20240920Reply Comments (Redacted).pdf

RECEIVED
Friday, September 20, 2024
IDAHO PUBLIC
UTILITIES COMMISSION
_ ROCKY MOUNTAIN 1407 W.North Temple,Suite 330
POWER. Salt Lake City,UT 84116
A DIVISION OF PACIFICORP
September 20, 2024
VIA ELECTRONIC DELIVERY
Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd
Building 8 Suite 201A
Boise, ID 83714
RE: CASE NO. PAC-E-24-05
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL OF $62.4 MILLION ECAM DEFERRAL
Attention: Commission Secretary
Pursuant to Commission Interlocutory Order No. 36274 dated July 19, 2024, please find Rocky
Mountain Power's Reply Comments in the above referenced matter.
Informal inquiries may be directed to Mark Alder, Idaho Regulatory Manager at(801) 220-2313.
Very truly yours,
q��a-�D
Joe Steward
Senior Vice President, Regulation
Cc: Service List Case No. PAC-E-24-05

CERTIFICATE OF SERVICE
I hereby certify that on this day, I caused to be served, via email, a true and correct copy
of Reply Comments in Case No. PAC-E-24-05 to the following:
Service List
Commission Staff
Adam Triplett
Deputy Attorney General
Idaho Public Utilities Commission
11331 W. Chinden Blvd.,Bldg No. 8,
Suite 201-A
Boise, ID 83720-0074
adam&jplett(cr)�puc.Idaho.gov
Bayer Corporation
Thomas J. Budge Brian C. Collins
Racine, Olson PLLP Greg Meyer
201 E. Center Brubaker&Associates
Pocatello, ID 83204-1391 16690 Swingley Ridge Rd., #140
tj&racineolson.com Chesterfield, MO 63017
bcollins&consultbai.com
rg_ne er&consultbai.com
PacifiCorp Idaho Industrial Customers
Ronald L. Williams Bradley Mullins
Brandon Helgeson MW Analytics
Hawley Troxell Ennis &Hawley LLP Teitotie 2, Suite 208
PO Box 1617 Oulunsalo Finland, FI 90460
Boise, ID 83701 brmullins(a_),mwanaltyics.com
rwilliams ghawle_ytroxell.com
bhel eg songhawleytroxell.com
Val Steiner Kyle Williams
Itafos Conda LLC BYU Idaho
val.steiner(a)itafos.com williamskgbyui.edu
PacifiCor , dba Rocky Mountain Power
Mark Alder Joe Dallas
PacifiCorp/dba Rocky Mountain Power PacifiCorp/dba Rocky Mountain Power
1407 West North Temple, Suite 330 825 NE Multnomah Street, Suite 2000
Salt Lake City,UT 84116 Portland, OR 97232
mark.alder(&,pacificorp.com joseph.dallas&pacificorp.com
Data Request Response Center
PacifiCorp
datare uest acifico .com
Page 1 of 2

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Joe Dallas (ISB# 10330)
PacifiCorp, Senior Attorney
825 NE Multnomah Street, Suite 2000
Portland, OR 97232
Telephone: [phone]
Email:joseph.dallaskpacificorp.com
Attorney for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-24-05
OF ROCKY MOUNTAIN POWER )
REQUESTING APPROVAL OF$62.4 ) REPLY COMMENTS OF
MILLION ECAM DEFERRAL ) ROCKY MOUNTAIN POWER
I. INTRODUCTION
1. Pursuant to Idaho Code § 61-626 and Rule 331 of the Rules of Procedure of the
Idaho Public Utilities Commission (the "Commission"), Rocky Mountain Power, a division of
PacifiCorp (the "Company"), hereby submits its reply comments, consistent with the procedural
schedule set forth in Interlocutory Order No. 36274 issued by the Commission in this proceeding
on July 19, 2024 (the "Interlocutory Order"). For the reasons stated herein, the Company
respectfully requests the Commission reverse its decision to disallow from the Company's 2023
Energy Cost Adjustment Mechanism ("ECAM") rate adjustment approximately $2.3 million,
representing the costs incurred by the Company to comply with the Washington Climate
Commitment Act("WCCA").1
II. BACKGROUND
2. On April 1, 2024, the Company applied for Commission authorization to adjust its
rates under the ECAM and requested approval of approximately $62.4 million in deferred costs
'RCW§ 70A.65.005-70A.65-901 (2024).
Rocky Mountain Power's Reply Comments Page 1

from the deferral period beginning January 1, 2023, through December 31, 2023, with a 10.5
percent overall increase to Electric Service Schedule No. 94, Energy Cost Adjustment("Schedule
94").
3. On May 14, 2024, Staff, Bayer, and PIIC filed comments (collectively "parties").
All the comments submitted recommended that the Company not be able to recover the costs it
incurred in 2023 associated with procuring WCCA allowances that were necessary for the
operation of the Chehalis natural gas facility ("Chehalis").
4. On May 24, 2024, the Commission issued Order No. 36207 approving the
Company's application for recovery of the 2023 deferred costs with the exception of costs incurred
to comply with the WCCA. On June 21, 2024, the Company submitted a Petition for
Reconsideration(the "Petition")requesting the Commission reconsider its decision to situs assign
WCCA compliance costs to Washington State and instead, apply the 2020 Protocol provisions as
written, and find that Chehalis remains a "System Resource" for cost allocation purposes. The
Company requested that if the Commission maintains that Chehalis is a "State Resource" under
the 2020 Protocol, the Commission should revise Order No. 36207 to remove both the costs and
benefits of Chehalis generation from Idaho Net Power Costs (`NPC").
5. The Commission granted the Company's Petition in Order No. 36274, and ordered
the parties to provide additional evidence and written comments regarding the disallowance from
the Company's 2023 ECAM rate adjustment of approximately$2.3 million,representing the costs
incurred by the Company to comply with the WCCA. In Order No. 36274, the Commission
required written responses from the Company to questions included in the Order, which the
Company timely provided on July 26, 2024. The Commission established a deadline for Staff and
intervenors to filed"written comments, associated documents, affidavits, and relevant evidence if
Rocky Mountain Power's Reply Comments Page 2

necessary."2 The Commission's order also afforded the Company an opportunity to reply to Staff
or other intervenor submissions by September 20, 2024. The Staff Comments were filed on
September 6, 2024, and this filing constitutes the Company's reply to the Staff Comments.3
6. On September 6, 2024, Commission Staff submitted comments on the Company's
Petition. In their comments, Staff contends that the Commission correctly determined that WCCA
costs arise from a "Portfolio Standard" and are properly situs assigned to Washington under the
2020 Protocol. Staff also argues that even if the Commission erred in this decision,the Commission
should not authorize recovery of WCCA compliance costs because it would not be fair,just, and
reasonable to include them in Idaho rates. Staff further presents arguments that disallowing
recovery of WCCA compliance costs does not violate the dormant Commerce Clause of the U.S.
Constitution ("dormant Commerce Clause"). Finally, Staff asserts the Company overstated the
impact of removing Chehalis from Idaho rates.
III. REPLY COMMENTS
7. The Company appreciates the opportunity to respond to Commission Staff
comments and the Commission's willingness to reconsider its decision regarding the Chehalis
WCCA costs. The Company also acknowledges Staff's consideration of its Petition and
submission of comments. In the following pages, the Company will respond to the comments
submitted by Staff on September 6, 2024.
2 Order No.46274 at 6.
3 Staff is the only party that filed comments on the reconsideration issue.
Rocky Mountain Power's Reply Comments Page 3

A. The WCCA never deprived the Company of the right to operate Chehalis, so
the Company never"reacquired" Chehalis as a generation resource.
8. Staff interprets the Commission's order to indicate "that the Commission reasoned
that the WCCA deprived the Company of the right to lawfully operate Chehalis to generate
electricity without obtaining and retiring allowances," and that the Chehalis gas generating plant
"effectively was inoperable as an electric generation facility unless the Company obtained
allowances."4 The claim that the Company "lost" and had to "reacquire" the right to operate
Chehalis is central to Staff's contention (discussed in the following section) that "the Company
`reacquired'the right to lawfully operate Chehalis to generate electricity in the manner prescribed
in the WCCA (i.e., obtaining WCCA allowances) and that the WCCA was a Portfolio Standard
under the 2020 Protocol."5
9. Staff s arguments, while well-intentioned, do not reference specific provisions of
the WCCA to support their position and appear to overlook the plain text of the statute. There is
nothing in the WCCA that supports Staff's claim that Chehalis was "effectively inoperable" if the
Company did not obtain WCCA allowances.As the Company detailed in the Petition, the WCCA
specifies how entities subject to the law demonstrate compliance.6 WCCA enforcement includes
imposition of "penalty allowances" the offending entity must purchase, and financial penalties
ranging from $10,000 to $50,000 per day for various types of violations.7 The WCCA does not,
however, say that power generators subject to the law must stop generating power if they do not
obtain WCCA allowances.
a Staff Comments at 3 (Sept. 6,2024). (emphasis in original).
5Id.
6 See RCW§ 70A.65.200(1):"All covered and opt-in entities are required to submit compliance instruments in a
timely manner to meet the entities' compliance obligations and shall comply with all requirements for monitoring,
reporting,holding,and transferring emission allowances ...."
7 See RCW 70A.65.200(2)—(5);Washington Administrative Code 173.446-610(2)—(6).
Rocky Mountain Power's Reply Comments Page 4

10. The Washington enforcement program is similar to that established in Idaho for
violations of the Idaho Environmental Protection and Health Act.8 Idaho law provides that when
the director of the Idaho Department of Environmental Quality "determines that any person is in
violation of any provision of [the Environmental and Health Act] or any rule, permit or order"
issued pursuant to it,the director"may commence [a]dministrative enforcement action... or[c]ivil
enforcement action."'Administrative and civil enforcement of state air emissions limits may result
in "monetary penalties" or liability "for any expense incurred by the state in enforcing" the
Environment and Health Act.
11. Idaho air emissions limits may be enforced by injunctive orders that stop operations
of the emitting entity only "in circumstances of emergency creating conditions of imminent and
substantial danger to the public health or environment."10 Washington law may offer a similar
injunctive enforcement tool in emergency conditions, but it does not authorize injunctive relief as
a remedy for WCCA violations.The enforcement provisions that apply to the WCCA are explicitly
set forth in Washington statutell and rule,12 and neither authorize the state to shut down the
operation of a power generator if it does not obtain WCCA allowances.
12. The Commission must act in a consistent manner and carefully consider the
precedent that would be set if it adopts Staff's reasoning. Staff does not appear to draw a clear
distinction between the WCCA and other taxes or compliance costs that the Company incurs. For
instance, if a county imposed a new property tax or compliance cost (such as a fish passage
requirement) on a generating unit,would PacifiCorp also lose a property right to operate the plant
8 Idaho Code§§ 39-101—39-130.
9Id. § 39-108(3).
10 Idaho Code§ 39-108(8).
"See RCW 70A.65.200(Enforcement—Penalty);RCW 65.310(Covered or opt-in entity compliance obligation).
12 WAC 173-446-610(Enforcement).
Rocky Mountain Power's Reply Comments Page 5

and only regain that right once the cost is paid?How factually is the plant"effectively inoperable"
if it still generating power—even assuming if the Company did not pay the cost and only incurred
penalties?What legal basis exists to conclude that PacifiCorp lost a property right in the generating
unit under such circumstances?What are the implications of this precedent in future proceedings?
Moreover, if this approach is valid, why is the Commission adopting it for the first time here, and
applying it solely to WCCA costs? These are just a few of the many questions that would arise if
other costs incurred by regulated utilities were treated similarly under Staff s recommendation.
PacifiCorp strongly urges the Commission to consider the reasoning and precedent it would set in
making its final determination.
13. Staff's arguments that "the WCCA deprived the Company of the right to operate
Chehalis" or that Chehalis "effectively was inoperable as an electric generation facility unless the
Company obtained allowances"13 have no basis in the text of the WCCA or the regulations
implementing it. The Commission should not adopt a disallowance based on legal argument that
provides no persuasive citation to the WCCA and is inconsistent with the plain text of the law.
Furthermore, there is simply no evidence in the administrative record that PacifiCorp lost any
property right that it had to "reacquire" or that Chehalis was "effectively inoperable" due to the
WCCA.
B. The WCCA is not a "Portfolio Standard" as defined in the 2020 Protocol.
14. Staff s misunderstanding that the WCCA required the Company to "reacquire"
Chehalis seems to support their position that the"WCCA is a Portfolio Standard"14 as that term is
defined in the interjurisdictional allocation standard adopted by the Commission and known as the
13 Staff Comments at 3 (Sept.6,2024)(emphasis in original).
14 Id. at 2.
Rocky Mountain Power's Reply Comments Page 6

"2020 Protocol."15 Staff's position goes well beyond what the Commission concluded in the Order,
where the Commission found the WCCA was "more akin to a" a Portfolio Standard than to a state
tax because the WCCA"is designed to reduce the use of fossil fuel generation to serve load."16
15. For purposes of assigning costs and benefits of resources, a"Portfolio Standard"is,
as Staff correctly states in its comments, "a law or regulation that requires [the Company] to
acquire ... Resources in a prescribed manner."17 It is important for the Commission to understand
that"Resource" is a defined term." There is no dispute that Chehalis is a "Resource" (it is a gas-
fired generation plant). The Order acknowledges that the Company "owned the Chehalis
generating facility before the WCCA was enacted."19 Staff also appears to agree with the Company
that WCCA allowances do not "constitute discrete `Resources'under the 2020 Protocol."20 Thus,
if the WCCA is to qualify as a Portfolio Standard for 2020 Protocol purposes, the WCCA would
have to require that the Company to "acquire"Chehalis, in order for Chehalis to be situs-assigned
to Washington (both costs and benefits)21 as a resource acquired pursuant to a Portfolio Standard.
There is no set of facts in the record that supports that conclusion.
is See Attachment A to these comments;see also 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
(April 22,2020). The references to the 2020 Protocol are to 2020 Protocol as submitted by the Company as Exhibit
No. 1 to the testimony of Joelle R. Steward in Case No.PAC-E-19-20.In 2023,the Commission approved a
"modification of Order No.34640 to approve the 2020 Protocol as amended through December 31,2025."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 (November 2,2023).
16 Order No. 36207,at 11.
17 Staff Comments at 3;see also 2020 Protocol,Appendix A("Portfolio Standard"means a law or regulation that
requires PacifiCorp to acquire: (a)a particular type of Resource,(b)a particular quantity of Resources,(c)
Resources in a prescribed manner or(d)Resources located in a particular geographic area.").
18 The 2020 Protocol defines a"Resource"as including"a Company-owned generating unit,plant,mine,long-term
Wholesale Contract, Short-Term Purchase and Sale,Non-firm Purchase and Sale,or QF contract."2020 Protocol,
Appendix A.
19 Order No. 36207 at 11.
21 Staff Comments at 3 (Sept.6,2024)(rejecting what Staff viewed as Company arguments"implying that"Order
No. 36207 held that WCCA allowances are"Resources.")
21 2020 Protocol,Section 3.1.2.1 (emphasis supplied).
Rocky Mountain Power's Reply Comments Page 7

16. Staff suggests that the"legislative intent"of the WCCA supports declaring Chehalis
as a Resource acquired to satisfy a Portfolio Standard. As discussed in the Petition, the 2020
Protocol includes detailed definitions of terms and applies those terms in specific ways. The
Commission need not look to legislative intent when the terms of the WCCA are unambiguous:
the words of the statute do not require the Company to obtain any Resource.22 Similarly,while the
2020 Protocol is not a legislative enactment,its text as written does not support qualifying Chehalis
costs for situs assignment to Washington.
17. There is simply no evidence in the record that Chehalis was "acquire[d]" in
accordance with a"Portfolio Standard."There is also no evidence that PacifiCorp lost any property
right in Chehalis that it had to "reacquire"because of the WCCA. Indeed, Chehalis was acquired
by the Company well before the passage of the WCCA; it was introduced into Idaho rates in a
2008 rate case,while the WCCA was passed in 2021.23 In particular, Chehalis started commercial
operations in October 2003, and the Company acquired the plant in 2008.24 Furthermore, the
WCCA does not mandate the procurement of any Resource and instead discourages the
construction of new thermal plants in Washington by introducing additional costs. Even if the
Company had somehow acquired Chehalis in 2008 to comply with a Washington law that would
not be passed until 2021,it would be consistent with the 2020 Protocol that all benefits of Chehalis,
as a Resource, should be situs-assigned to Washington—something no party or the Commission
has recommended or adopted.
22 See Blasch v.HP,Inc. (In re Certification of Question of L),545 P.3d 581,584(Supreme Court of Idaho,March
24,2024)("The basic rule of statutory construction is that the courts must first look to the language of the statute to
determine the legislature's intent. ... Only if the statute is ambiguous—or capable of more than one reasonable
construction—will this Court engage in statutory construction to ascertain legislative intent.")
23 In the Matter of the Application of PacifiCorp DBA Rocky Mountain Power for Approval of Changes to Its Elec.
Serv. Schedules,Case No.PAC-E-08-07,Order No.30783 (Apr. 16,2009);Washington Senate Bill 5126(2021
Regular Session).
21 State of Washington Energy Facility Site Evaluation Council,"Chehalis Generation Facility,"available at,
hiips://www.efsec.wa. ovg /energy-facilities/chehalis-generation-facility (last visited May 20,2024).
Rocky Mountain Power's Reply Comments Page 8

18. The Commission must carefully consider the precedent it would set by adopting
Staff s recommendation. For example, if a state imposed an avian curtailment requirement at a
wind facility for environmental purposes, would this requirement now qualify as a "Portfolio
Standard" that mandates PacifiCorp to "acquire . . . Resources in a prescribed manner"? The
answer is clearly no. The requirement to install avian curtailment does not mandate the Company
to acquire any new Resource, as defined in the 2020 Protocol. Hypothetically, if the Company
never acquired a new Resource again—it would not be in violation of this requirement. This logic
applies to most compliance costs or taxes the Company incurs, including WCCA allowances.
These costs simply represent expenses the Company must bear to operate its existing generating
facilities—they do not create a separate obligation to acquire a new Resource in the way a Portfolio
Standard would.
19. The 2020 Protocol recognizes that various states the Company operates in have
disparate laws and policies that impact the Company's costs of generating power. Those costs are
reflected in various regulatory requirements,taxes,fees,or other costs of doing business.The 2020
Protocol designates specific types of policies for situs assignment to a particular state. If the policy
is not implemented in a way that meets the terms of the 2020 Protocol governing situs assignment
(regardless of states' varying policy differences), Resources that serve the Company's customers
in a state should be paid for in accordance with the cost causation principle historically observed
by the Commission: "the cost causing customer is responsible for the costs associated with its
service."zs
21 In the Matter of the Application of Intermountain Gas Company to Change its Rates and Charges for Natural Gas
Service in the State ofldaho,Case No.INT-G-16-02,Order No. 33757 at 35 (April 28,2017)("We continue to
adhere to the principle of cost causation,namely that the cost causing customer is responsible for the costs
associated with its service.").
Rocky Mountain Power's Reply Comments Page 9

C. Providing Idaho customers with the full benefits of Chehalis power without
paying the full prudent costs of that power is not fair,just and reasonable.
20. The principle referenced above, that "the cost causing customer is responsible for
the costs associated with its service,"is fundamental to establishing fair,just and reasonable rates.
When a Resource is subject to situs assignment as a"State-Specific Initiative"Resource,including
a"Portfolio Standard,"the 2020 Protocol requires that both the"costs and benefits associated with
Interim Period Resources acquired in accordance with a State-specific initiative"be "assigned on
a situs basis to the State adopting the initiative."26 While the Company disagrees with situs
assignment of Chehalis, it notes that even if it was so assigned, Idaho customers receiving the
benefits of Chehalis power should contribute to paying the prudent costs of producing the power
they consume.
21. Staff comments argue the opposite: that applying the 2020 Protocol as written
would result in rates that are not fair,just and reasonable.27 Staff contends that"even if the WCCA
is not a Portfolio Standard, the Commission should disallow recovery of the costs the Company
incurred to comply with the legislation."28 Staff points to the provisions of the 2020 Protocol that
explicitly preserve state commissions' authority to determine rates in accordance with state law,
and to consider the effect of changing laws and regulations.
22. The Company has no quarrel with those provisions. For the WCCA disallowance
at issue here, however, the Commission does not claim the disallowance of Chehalis costs is
required by state law.Nor does it claim that the WCCA is a new type of law that is not covered by
the cost allocation treatments detailed in the 2020 Protocol. Moreover, the disallowance of costs
without an accompanying removal of benefits is inconsistent with the 2020 Protocol and with
212020 Protocol,Section 3.1.2.1 (emphasis supplied).
21 Staff Comments at 3-5(Sept.6,2024).
28 Id. at 3-4.
Rocky Mountain Power's Reply Comments Page 10

fundamental ratemaking principles that long pre-date the 2020 Protocol. Staff claims the basis for
disregarding the 2020 Protocol is that (1) "WCCA compliance costs are not taxes;" and (2) "QF
rates have a method for addressing situations when one state raises energy costs."29
23. The Company understands that the Commission is not persuaded that the WCCA
compliance costs the Company is legally required to pay are not analogous to the generation related
wind tax in Wyoming referenced in previous comments.30 Regardless, this does not diminish the
fact that WCCA costs are part of what the Company must incur to provide Chehalis power to Idaho
customers. It is important to note that the 2020 Protocol provides that both generation related taxes
and costs are system allocated for System Resources—like Chehalis.The fact that the WCCA costs
are not set at a flat rate like the Wyoming wind tax, can vary based on the WCCA's price-setting
mechanism,or are not paid at the same rate by all states,makes them no less compliance costs that
the Company does not control but is legally obliged to pay. Taxes may be based on flat rates,
percentages of sales, or levels of business income; they may include exemptions or credits
established by state legislatures. Staff does not provide any citation to support the claim that a tax
must be a "flat rate."31 Under Staff's logic, the federal income tax would not be a tax because it
not "flat rate." Regardless, those features do not affect whether they are legitimate costs that a
utility prudently incurred to provide energy to its customers. Whether the WCCA constitutes a
"tax"does not determine whether it is a"cost"for ratemaking purposes. Indeed,the 2020 Protocol
provides that for System Resources both "[g]eneration-related dispatch costs and associated plant"
29 Id. at 5. Staff cites these as the two reasons why"including WCCA compliance costs would not be fair,just and
reasonable."
30 Wyo. Stat. §39-22-103.
31 Staff comments at 4(Sept.6,2024).
Rocky Mountain Power's Reply Comments Page 11

and "[g]eneration and fuel-related taxes" will be allocated using the System Generation (SG)
Factor. ,32
24. Furthermore, the contention that certain Washington customers are given free
WCCA allowances has no bearing on whether procuring WCCA allowance to serve Idaho load
was a prudent action by the Company.Hypothetically,if the Wyoming legislature exempted certain
customers from the referenced Wyoming wind tax,33 the fact would remain the same—the
Company had to incur these costs to provide power to its Idaho customers.Because of this structure
should PacifiCorp cease operating these facilities in a cost-effective manner for the benefit of its
Idaho customers? The answer is obviously no. The fact that one set a customer is exempt has no
bearing on whether the Company had to prudently incur the costs to provide service for another
set of customers. Adopting this precedent would transform a historically prudent cost into an
imprudent cost due solely to legislative action completely outside the Company's control.
25. The nature of whether a cost is prudent and recoverable should not be dependent
on how a state legislature designed the costs—but rather, measured by whether, given all the
circumstances, a regulated utility's actions in incurring the cost was reasonable and cost-effective
in providing service to its customers in Idaho. Although PacifiCorp is challenging the WCCA in
federal court, the Company has no control over sovereign jurisdictions, and it would not be fair,
just, or reasonable to order a disallowance on this basis.
26. Staff's second argument for overriding the specific terms of the 2020 Protocol
applicable to Chehalis (the issue in this case) is to point to other terms of the 2020 Protocol that
apply to rates paid to Qualifying Facilities ("QFs") (which is not the issue in this case). The 2020
Protocol includes provisions that apply to state laws like the WCCA and it also includes provisions
32 2020 Protocol,Section 3.1.7.
33 Wyo. Stat. §39-22-103.
Rocky Mountain Power's Reply Comments Page 12

governing how various state QF compensation rates should be allocated among the states.The fact
that the 2020 Protocol includes language on a different topic is no justification for applying the
inapposite language to an entirely different situation.Rather,the QF treatment in the 2020 Protocol
is more evidence that the 2020 Protocol includes specific, well-considered treatment of how the
costs of various state policy initiatives should be allocated among the states. For the reasons
discussed above, the WCCA is not an initiative that justifies situs assignment under the 2020
Protocol provisions applicable to it.
27. Implicit in a power cost mechanism is an examination of whether costs were
prudently incurred by a company.34 In particular,the question in this ECAM proceeding should be
whether PacifiCorp acted as a prudent and reasonable utility in procuring WCCA allowances in
serving its Idaho customers during the deferral period. Whether or not a parry subjectively
disagrees with a compliance costs is not a valid basis for disallowance. For instance, if a party
subjectively disagrees with the substantive merits of a requirement to install an avian curtailment,
it does not remove inquiry as to whether a regulated utility had to prudently incur such costs for
operations. The Commission must recognize that:
1. No party alleges PacifiCorp acted imprudently in procuring WCCA
allowances;
2. No party alleges that PacifiCorp should have not procured the WCCA
allowances and instead incurred penalties; and
3. No party suggests PacifiCorp should have shut down Chehalis to avoid the
need to procure CCA allowance.
sa See, e.g_In the Matter of PacifiCorp DBA Rocky Mountain Powers Application for Approval of Its$16.7 Million
Deferral of Net Power Costs, &Auth. to Decrease Rates by$9.0 Million,Case No.PAC-E-17-02,Order(May 31,
2017)("Based on our review of the record,we find that the Company's proposed deferral of the 2016 energy-related
costs of$7.5 million,and decrease of$7 million in revenues collected is prudent and reasonable.").
Rocky Mountain Power's Reply Comments Page 13

28. Indeed, no party recommends that the Company should have taken a different
course of action in 2023 nor has the Commission found that the PacifiCorp did not operate in a
least cost/risk manner. Rather, it appears the recommendation is that the Company should be
required to continue operation of Chehalis for the benefit of its Idaho customers, but nevertheless
should still be denied recovery of the prudently incurred costs necessary for plant operation. This
recommendation is not due to any action by the Company—but rather by parties' dissatisfaction
that the Company is an interstate utility and incurred certain costs for generating power in
Washington and selling it in Idaho. Accordingly, because no parry has claimed that PacifiCorp
acted imprudently in incurring these costs it is fair,just, and reasonable to include them in rates.
Otherwise, the only rational basis for the disallowance is to punish and deter PacifiCorp for
engaging in interstate commerce in violation of the dormant Commerce Clause.
D. Staff's interpretation of the Commerce Clause lacks proper legal support and
should not be adopted.
29. The Staff comments do not address the central point of the Company's concern, as
stated in the Petition—that the Order is contrary to the dormant Commerce Clause of the U.S.
Constitution. The central issue is that the Commission's Order applies the neutral, non-
discriminatory terms of the 2020 Protocol to create an outcome that, in practical effect, results in
"purposeful discrimination against out-of-state economic interests."35
30. The Order prevents the Company from recovering$2.3 million because it disallows
costs mandated by the law of another state that is binding on the Company as an interstate utility.
From the analysis provided above, the only rational reason the Company is being penalized is
35 Nat'l Pork Producers Council v.Ross,598 US 356,369, 143 S.Ct. 1142, 1153 (2023).The U.S. Supreme Court
has overturned state administrative agency decisions,as well as state statutes and regulations,based on violations of
the dormant Commerce Clause.See, e.g.,New England Power Co. v.New Hampshire,455 US 331 (1982)
(overturning an order of the New Hampshire Public Utilities Commission); West Lynn Creamery,Inc. v.Healy,512
US 186(1994)(invalidating a pricing order issued by the Massachusetts Department of Food and Agriculture).
Rocky Mountain Power's Reply Comments Page 14

because Chehalis power is produced in Washington and the Company is complying with that state's
law. As explained in the Petition, this in turn has the "practical effect" of discriminating against
PacifiCorp for engaging in interstate operations, "imposes burdens on the arteries of commerce,"
and provides benefits to Idaho customers to the detriment of PacifiCorp—solely due to the nature
of its interstate operations.36 Neither the Commission nor any party has articulated a way the
Company could have avoided the proposed disallowance. It appears the only way to have done so
would have been to abstain from engaging in provisions of interstate service.
31. Without providing any legal citation, Staff concludes that "any [d]ormant
Commerce Clause violation associated with WCCA compliance costs occurred when the Company
initially incurred the costs—not when the Commission subsequently denied their recovery from
Idaho ratepayers."37 It is important to note that the dormant Commerce Clause is a constitutional
provision that applies only to state actions—such as actions by this Commission.38 Staff s
argument implies that the Commission is completely immune to any dormant Commerce Clause
violation unless it disallows costs at the time they are incurred. This interpretation should be given
no weight for the following reasons.
32. First, as noted, Staff provides no legal citation to support this interpretation. There
is a disconnect between Staff s analysis and its final legal conclusion. The Commission should not
adopt this unsupported interpretation by Staff. Second, this interpretation overlooks the actual
regulatory mechanics of the ECAM. Under the ECAM, the Company defers costs throughout the
calendar year and either seeks recovery or refund in the following year—subject to a regulatory
36 Petition at 10-12.
37 Staff Comment at 6(Sept.6,2024).
36 The dormant Commerce Clause"prohibits the enforcement of state laws ... [and]regulatory measures."Nat'l
Pork Producers Council v.Ross, 598 US 356, 369, 143 S. Ct. 1142, 1153(2023).
Rocky Mountain Power's Reply Comments Page 15

and prudence review.39 The ECAM does not allow for the immediate recovery of costs when they
are incurred.40 This is due to practical reasons; if the Company were required to seek recovery of
every power costs immediately upon incurring it, there could potentially be thousands of filings
each year. Staff understands this concept, as they were a signatory to the stipulation that created
the SCAM, and also regularly participate in these proceedings.41 Therefore, Staff s position41
overlooks the actual mechanics of the SCAM, which doesn't allow for the immediate recovery of
costs when incurred.
33. Next, Staff claims that the Company has paid Washington State more than $42
million of total WCCA compliance costs and $336,219 of Clean Energy Transformation Act
("CETA") compliance costs in 2023.43 The discrepancy in compliance costs is simply a reflection
that CETA and the WCCA are two separate laws with two separate requirements. Staff implies that
because the compliance costs of these two separate laws, at this particular point in time, are not
identical, that this somehow advances their dormant Commerce Clause interpretation. Staff
provides no analysis of the requirements of CETA, nor the timeline in which PacifiCorp must
comply with the requirements. PacifiCorp has not even reached its first relevant statutory deadline
under CETA. In relevant part, CETA requires the following:
1. Eliminate Coal by 2025: Coal fired resources must be eliminated from the
allocation of electricity by December 31, 2025. This does not include
decommission and remediation costs. Washington does not use the 2020 Protocol,
but rather the Washington Inter jurisdictional Allocation Methodology("WIJAM")
as its allocation method. In accordance with the WIJAM, PacifiCorp currently has
39 In the Matter of the Application of Rocky Mountain Power for Approval of an Energy Cost Adjustment
Mechanism (SCAM),Case No.PAC-E-08-08,Order No.30904(Sept.29,2009)(approving settlement that
implementing the ECAM).
40 Id.
41 See Id.
42 Staff Comment at 6(Sept.6,2024).
43 Id.
Rocky Mountain Power's Reply Comments Page 16

costs associated with two coal generating facilities in Washington rates that must
be removed by the aforementioned date.44
2. Carbon Neutral by 2030: Retail sales of electricity to Washington customer must
be greenhouse gas neutral by January 1, 2030.45
3. 100 Percent Clean Energy by 2045: All sales of electricity in Washington must
come from either non-emitting generation and/or renewable resources by
January 1, 2045.46
34. In order to comply with CETA, PacifiCorp files a Clean Energy Implementation
Plan ("CEIP") every four years.47 The CEIP outlines the actions the Company should take to
comply with CETA. To the extent CETA requires the Company to procure a resource that it would
not otherwise add to its system, such resource is situs assigned to Washington. For instance,
PacifiCorp's currently approved CEIP required it to procure three separate demand response
resources.4' These types of resources help allow Washington to meet peak demand once it loses
certain thermal dispatchable generation. Thereafter,PacifiCorp procured these three resources and
included them in Washington rates on a situs allocation.49 Contrary to representations made,these
CEIP situs-resources alone increased the annual tariffed Washington rate by$2.2 million.50 As the
CETA compliance deadlines approach, to the extent incremental resources are needed for
compliance that deviate from a least cost/risk portfolio, those costs will also be situs assigned to
Washington.Accordingly, Staff's observation is simply a reflection that CETA and the WCCA are
two separate laws, with two sperate requirements, and two separate compliance timelines—which
44 RCW 19.404.030.
45 RCW 19.405.040.
46 RCW 19.405.050
47 RCW 19.405.060.
48 WUTC v.PacifiCorp d/b/a Pacific Power&Light Company,Docket No.UE-210829,Order 06(Oct.25,2023)
(approving via settlement PacifiCorp CEIP).
49 In the Matter of PacifiCorp d/b/a Pacific Power&Light Company Accepting Tariff Revisions to WN U-76,
Schedule 191.1 System Benefits Charge Increase, Subject to Conditions,Docket No.UE-240393,Order 01 (August
30,2024)(increasing tariff rate by$2.2 million for CEIP demand response resources).
50 Id.
Rocky Mountain Power's Reply Comments Page 17

does nothing to further their interpretation of the Commerce Clause and the issue before the
Commission.
35. Staff's argument generally addresses the dormant Commerce Clause concerns
about the WCCA itself; these are similar to the concerns the Company has expressed in its federal
court challenge to the law. However, Staff has not addressed the issue before the Commission.
That is, while the WCCA remains in effect, the Company is required to pay for allowances that
raise the cost of power produced at Chehalis. When the Company sought recovery of those costs,
the Commission denied them based its view that Idaho customers should not pay for a cost imposed
by another state's law. In this way, the Order gives Idaho consumers an impermissible advantage,
discriminating against the Company's economic interests based solely on its provision of interstate
service.51 In other words, if the Company generated all its electricity in Idaho, it would not be
subject to this proposed disallowance. By adopting the proposed disallowance, the Commission
would be establishing a precedent that deters regulated utilities from procuring certain interstate
electric power, even in circumstances where such power is the most cost-effective and reliable
means to serve load in Idaho.
36. The Company cannot legally recover from its Washington customers the WCCA
costs for Chehalis power used to serve Idaho. Nevertheless, the Order disallows the Company's
51 In the Commerce Clause context,"discrimination"means"differential treatment of in-state and out-of-state
economic interests that benefits the former and burdens the latter."Or. Waste Systems,Inc. v.Dep't of Env't Quality
of Or.,511 US 93,99(1994).In considering this issue,"[t]he real question. . .is not whether[the state law]
differentiates between in-state and out-of-state coal but whether it impermissibly discriminates. . . .That is,does the
law benefit in-staters and burden outsiders?"Foresight Coal Sales,LLC v. Chandler,60 174th 288,297-98(6th Cir
2023),cert den sub nom Chandler v.Foresight Coal Sales,LLC, 144 S.Ct. 80(Oct.2,2023)(emphases in original).
Impermissible discrimination"is not limited to attempts to convey advantages on local merchants;it may include
attempts to give local consumers an advantage over consumers in other States." Camps Newfound/Owatonna,Inc. v.
Town of Harrison,520 US 564,577-78(1997)(quoting Brown-Forman Distillers Corp. v.New York State Liquor
Auth.,476 US 573,580(1986)).
Rocky Mountain Power's Reply Comments Page 18

WCCA costs when it sells Chehalis power in interstate commerce to Idaho customers—sales that
require the Company to incur the cost of securing WCCA allowances or incur penalties.
37. This discrimination in the application of the 2020 Protocol is the reason the
Company continues to urge the Commission to reconsider the Order to ensure it does not conflict
with the dormant Commerce Clause. The Commission could achieve this by: (a) applying the
neutral and non-discriminatory 2020 Protocol provisions as written and finding that Chehalis
remains a "System Resource"; or (b) maintaining the Commission's position that Chehalis is a
"State Resource" and apply the 2020 Protocol accordingly and remove the benefits of Chehalis
from Idaho NPC. The Commission simply cannot reasonably classify Chehalis as a "State
Resource" and continue to receive all the benefits without paying the attendant prudent costs.
E. Company Review of Staff's Analysis of the Impact of Removing Chehalis.
i. Clarification to Staff's Comments
38. Staff asserts that according to Company calculations,removing Chehalis generation
and its costs from Idaho rates would increase Idaho's NPC by$23.6 million.52 However, it appears
that Staff has made an error in its calculations. According to Company calculations, the energy
cost of removing Chehalis from Idaho rates would increase Idaho's NPC by $1.3 million ($23.6
million total-company),53 and the capacity cost of removing Chehalis from Idaho rates would
increase Idaho's NPC by$6.6 million. This is a total increase to Idaho NPC of$7.9 million.54 For
the reasons set forth below, the Company recommends that if the Commission orders the removal
of Chehalis from Idaho rates then the Company's calculation, as presented in its response to the
July 26 response to Order No. 36274, should be used to determine the rate impact on NPC.
12 Staff Comments at 6(Sept.6,2024).
ss PacifiCorp Response to Interlocutory Order Questions,page 2.
"PacifiCorp Response to Interlocutory Order Questions,page 3.
Rocky Mountain Power's Reply Comments Page 19

ii. Staff's Analysis
39. As an initial matter, Staff calculates that removing Chehalis from Idaho rates, all
other things equal,would reduce Idaho's revenue requirement.55 This is counter intuitive.Chehalis
is a 520 megawatt ("MW") natural gas power plant56 with full dispatch capability (i.e., the
Company can increase or decrease the generation from the plant at will).57 Dispatchable capacity
within the Western Interconnection has become increasingly scarce58 and remaining dispatchable
resources command a system/market premium.59 Furthermore, Chehalis' average dispatch price,
inclusive of the WCCA dispatch adder, is still lower than average market prices at trading hubs
across the West.60 Yet, Staff calculates millions of dollars in benefit simply from replacing the
energy produced from Chehalis with market purchases.Again,this is counter intuitive. Below, the
conceptual errors in Staff's analysis are discussed:
iii. Replacement Capacity
40. Staff asserts that it is not appropriate to use the capacity replacement costs from the
Western Resource Adequacy Program ("WRAP')61 to value Chehalis' capacity because the
Company is not capacity deficient. However, the premise of the valuation is that, from the
perspective of Idaho, Chehalis no longer exists within the Company's system. In other words, if
55 Staff Comments at 6 Confidential Attachment A,line 19,column I and column Q(Sept.6,2024).
56 State of Washington,Energy Facility Site Evaluation Council,Chehalis Generation Facility,available at:
https://www.efsec.wa.gov/sites/default/files/180303/00020/20001205 752.pdf(last visited Sept. 18,2024).
https://www.efsec.wa.gov/energy-facilities/chehalis-generation-facility.
57 See Id.
58 North American Electric Reliability Corporation,2023 Long-Term Reliability Assessment at page 14(Dec.2023),
available at:https://www.nerc.coM/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2023.pdf(last
visited Sept. 18,2024).
59 Climate Portal,Intermittent Versus Dispatchable Power Sources(Sept. 10,2021),available at:
hops://climate.mit.edu/posts/intermittent-versus-dispatchable-power-sources(last visited Sept. 18,2024).
6o See Confidential Attachment B to these comments.
6i Western PowerPool, Western Resource Adequacy Program,available at:
https://www.westempowerpool.or./abboout/pro,grams/western-resource-adequacy program(last visited Sept. 18,
2024).
Rocky Mountain Power's Reply Comments Page 20

the Commission affirms its decision that Chehalis is a "State Resource" rather than a "System
Resource" under the 2020 Protocol, then all the costs and benefits (including both capacity and
energy) should no longer be reflected in Idaho NPC. Since PacifiCorp's system is designed and
planned for using least risk/cost principles to accommodate the customer demand (load) from all
six states,62 it is therefore designed with an adequate amount of dispatchable capacity. From this
context, absent Chehalis—all else equal—the system would be capacity deficient. Otherwise, the
capacity would already have been sold in the bilateral market to reduce NPC. Therefore, and
contrary to Staff's claim, there is no existing excess generator capacity to reallocate to Idaho
ratepayers because such excess would not exist.63
41. Staff asserts that the WRAP capacity replacement costs include a penalty amount
to incentive participants to be capacity sufficient.64 However, while it is true that the capacity
replacement costs would incentivize participants to be capacity sufficient, the amount that Staff
identifies as a penalty amount is a functional representation of the premium(discussed above)that
the capacity deficient participant must pay to the capacity sufficient participant. In this valuation,
PacifiCorp is the capacity deficient participant given the aforementioned discussion, which
identifies that the Company would be capacity deficient without Chehalis. To be clear, in actual
operations, PacifiCorp would have to utilize the WRAP for replacement capacity if the capacity
associated with Chehalis was removed from the system without being replaced.65 Therefore, in the
context of removing Chehalis from Idaho rates (while the real power plant (Chehalis) still exists),
use of the WRAP capacity replacement costs are appropriate in the Company's calculation.
62 PacifiCorp,Integrated Resource Plan,available at:hlWs://www.pacificorp.com/energy/integrated-resource-
plan.html(last visited Sept. 18,2024).
63 Staff Comments at 7(Sept.6,2024).
64 Western PowerPool, Western Resource Adequacy Program CONE Penalty Task Force-Proposal, available at:
https://www.westeEnpowerpool.org/private-media/documents/2022-02-10_CONE_Penaliy Proposal.pdf(last
visited Sept. 18,2024).
61 Id. (last visited Sept. 18,2024).
Rocky Mountain Power's Reply Comments Page 21

42. Staff noted that the Company omitted capacity costs in April, May and October,
and Staff claims that the Company increased the capacity costs in August.66 However, the
Company's calculation is appropriate because this is how WRAP capacity replacement costs are
calculated. On a monthly basis, the month with the greatest deficit is assessed a first stage
premium, and additionally deficient months are assessed an incremental premium. The premiums
only apply to the summer and winter seasons, wherein the summer season is identified as June to
September and the winter season is identified as November to March.April, May and October are
not within those seasons and August is the peak load month where the first stage premium would
be incurred.67
iv. Replacement Energy
43. Staff disagrees with the Company's use of Mid-Columbia (Mid-C) power market
prices to replace the energy supplied by Chehalis, reasoning that the WRAP capacity replacement
costs are based on a replacement gas plant, therefore the Company's energy replacement costs
should be based on the price of gas generation.6' This is a logical fallacy, because the WRAP
capacity replacement costs are based on a hypothetical natural gas plant 6'but the Company would
not actually build the gas plant; Chehalis would still physically exist and continue to serve the
system.However,if Idaho chooses to no longer pay for Chehalis in rates it would no longer receive
the corresponding capacity and energy benefits. Therefore, although the Company incurs the
capacity replacement costs, it is still required to replace the energy in this counterfactual scenario.
66 Staff Comment at 7(Sept.6,2024).
67 Western PowerPool, Western Resource Adequacy Program CONE Penalty Task Force -Proposal, available at:
https://www.westelnpowerpool.ora/private-media/documents/2022-02-10 CONE Penalty Proposal.pdf(last
visited Sept. 18,2024).
68 Staff Comment at 7(Sept.6,2024).
69 Western PowerPool, Western Resource Adequacy Program CONE Penalty Task Force -Proposal, available at:
https://www.westeinpowerpool.org/private-media/documents/2022-02-10_CONE_Penalty Proposa1.pdf(last
visited Sept. 18,2024).
Rocky Mountain Power's Reply Comments Page 22

As mentioned above, the gas plant will not actually be built, therefore, the energy has to be
acquired from the wholesale electricity markets. In other words,in this scenario, it makes no sense
to replace energy lost from Chehalis by purchasing the commodity natural gas to fuel a plant no
longer in Idaho rates.Accordingly, the Company's monthly average gas cost is not relevant to the
calculation.
44. Staff argues that if the cost of gas generation is considered inappropriate (as
discussed above, it is inappropriate), then the calculation should use prices from the Western
Energy Imbalance Market ("WEIM") since Staff believes that the Company would be purchasing
replacement energy from the WEIM.70 This is also a logical fallacy. To participate in the WEIM,
entities must demonstrate resource sufficiency prior to the start of each hour.This requires showing
sufficient energy to meet forecasted load before being allowed to participate in and buy energy in
the WEIM.71 Absent Chehalis, to demonstrate resource sufficiency the Company would need to
purchase the replacement energy prior to participating in the WEIM.This involves bilateral market
purchases, which are valued in the Company's calculation of energy replacement costs, with day-
ahead prices from the Mid-C power market.
45. Accordingly, if the Commission orders the removal of Chehalis from Idaho rates
then the Company's calculation as presented in its July 26 response to Order No. 36274, should be
used to determine the rate impact on NPC.
70 Staff Comment at 7(Sept.6,2024).
71 California ISO,Business Practice Manual for the Western Energy Imbalance Market at Section 11.3.2, available
at:
https://bpmcm.caiso.com/BPM%20Document%20Library/Energy%20Imbalance%20Market/BPM_for_Energ °/y o201
mbalance%20Market V31 Clean.docx.
Rocky Mountain Power's Reply Comments Page 23

V. Use of 2020 rate base versus 2023 rate base.
46. In its July 26 response to Order No. 36274, the Company provided an illustrative
example of the impact of removing both the costs and benefits of generation from NPC. The
example included both the NPC component and the rate base component in the proposed
calculation. However, for the revenue requirement portion, the Company used the 2020 rate base
consistent with the rate base used for setting customers'rates in the most recently approved general
rate case. Since there is an ongoing rate case, Staff believes it would have been more appropriate
to use the 2023 rate base and expenses,rather than relying on 2020 figures. Those rates, however,
have yet to be approved by the Commission.For these reasons,the Company disagrees with Staff's
$242,000 adjustment to the revenue requirement, and it should be rejected by the Commission at
this time. If the Commission so orders, it can consider any impact associated with removing non-
NPC Chehalis costs in a future applicable rate proceeding.
IV. CONFIDENTIAL INFORMATION
47. This filing contains information that is Confidential and/or constitutes Trade
Secrets as defined by Idaho Code Section 74-101, et seq. and 48-801 and protected under IDAPA
31.01.01.067 and 31.01.01.233. Specifically, Confidential Attachment B contains Company
proprietary information that could be used to its commercial disadvantage.
V. CONCLUSION
48. The Commission should reconsider its decision to situs assign WCCA compliance
costs to Washington State, apply the 2020 Protocol provisions as written, and find that Chehalis
remains a "System Resource" for cost allocation purposes. Alternatively, if the Commission
maintains its position that Chehalis is a"State Resource"under the 2020 Protocol, it should revise
Rocky Mountain Power's Reply Comments Page 24

the Order in accordance with the mechanics of the 2020 Protocol to remove both the costs and
benefits of Chehalis generation from Idaho NPC.
DATED this 20st day of September, 2024
Respectfully submitted,
ROCKY MOUNTAIN POWER
Joe Dallas (ISB# 10330)
825 NE Multnomah St., Suite 2000
Portland, OR 97232
Telephone: [phone]
Email: Joseph.dallas&pacificorp.com
Attorney for Rocky Mountain Power
Rocky Mountain Power's Reply Comments Page 25

ATTACHMENT A

Case No. PAC-E-19-20
Exhibit No. 1
Witness: Joelle R. Steward
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
•
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Joelle R. Steward
December 2019

Rocky Mountain Power
Exhibit No. 1 Page 1 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R. Steward
•
2020 Pacif 'orI' Inter n-Jurisdictioal .111ocation Protocol

Rocky Mountain Power
Exhibit No. 1 Page 2 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
V1litness:Joelle R. Steward
Contents
l. Introduction...........................................................................................................................................................1
2. Timeframes and Effective Periods........................................................................................................................5
2.1. Effective Period of the 2020 Protocol..........................................................................................................5
2.2. Post-Interim Period......................................................................................................................................5
2.2.1. Commission Approvals for Post-Interim Period Method Obtained Prior to December 31,2023............5
2.2.2. Commission Approval Not Granted.........................................................................................................5
2.2.3. Post-Interim Period Method Agreement Not Reached.............................................................................6
2.2.4. Early Commission Approvals of Post-Interim Period Method................................................................6
2.2.5. Regulatory Filings to Implement Post-Interim Period Method................................................................6
3. Interim Period Allocation Method........................................................................................................................6
3.1. Continuing Terms of the 2017 Protocol for the Five States Interim Period Allocation Methodology.........7
3.1.1. Classification of Interim Period Resources..............................................................................................7
3.1.2. Allocation of Interim Period Resource Costs and Wholesale Revenues..................................................7
3.1.3. Re-functionalization and Allocation of Transmission Costs and Revenues.............................................9
3.1.4. Allocation of Distribution Costs............................................................................................................10
3.1.5. Allocation of Administrative and General Costs...................................................................................10
3.1.6. Allocation of Special Contracts.............................................................................................................10
. 3.1.7 Miscellaneous Costs and Taxes..............................................................................................................10
3.1.8. State Programs Regarding Access to Alternative Electricity Suppliers.................................................11
3.1.9. Loss or Increase in Load........................................................................................................................13
3.1.10. Commission Regulation of Interim Period Resources.......................................................................13
3.2. Modifications to the 2017 Protocol During the Interim Period..................................................................13
3.2.1. Net Power Costs Filings........................................................................................................................13
3.3.2. Embedded Cost Differential(`ECD")and Equalization Adjustment....................................................14
3.3.3. Costs and Benefits of Qualifying Facilities...........................................................................................15
3.3.4. Allocation of Gain or Loss from Sale of Assets.....................................................................................15
3.3.5. Interpretation and Governance...............................................................................................................15
4. Implemented Issues.............................................................................................................................................15
4.1. States'Decisions to Exit Coal-Fucled Interim Period Resources...............................................................16
4.1.1. Allocation of Costs at Closure...............................................................................................................16
4.1.2 Exit Orders.............................................................................................................................................17
4.L 3 Oregon Exit Dates..................................................................................................................................19
4.1.4. Washington Exit Orders.........................................................................................................................22
4.1.5. Establishment of Exit Dates for Hayden Units 1 and 2..........................................................................23
4.2. Reassignment of Coal-Fucled Interim Period Resources...........................................................................23
4.2.1 Company Proposals for Reassignment..................................................................................................23
4.2.2 Process and Timing................................................................................................................................24
4.2.3 Effects of Commission Decisions Regarding Assignment.....................................................................25

Rocky Mountain Power
Exhibit No 1 Page 3 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
. 4.3. Decommissioning Costs.............................................................................................................................26
4.3.1. Process for Determining Decommissioning Cost Allocation.................................................................26
4.3.2. Accounting for Decommissioning Costs Reserve Balances when All States Do Not Exit a Unit.........28
4.3.3. Accounting for Interim and Final Retirements......................................................................................29
4.3.4. Individual State Review Process............................................................................................................29
4.4. Qualifying Facilities...................................................................................................................................29
4.4.1. Existing QF PPAs..................................................................................................................................30
4.4.2. New QF PPAs........................................................................................................................................30
5. Resolved Issues-Post-Interim Period Implementation......................................................................................32
5.1. Generation Costs........................................................................................................................................32
5.1.1. Interim Period Resources Fixed Allocation...........................................................................................32
5.1.2. New Resources Fixed Assignment.........................................................................................................34
5.2. Transmission Costs......................................................... .....................34
......................................................
5.3. Distribution Costs......................................................................................................................................35
5.4. Svstem Overhead Costs..............................................................................................................................35
5.5. Administrative and General Costs..............................................................................................................35
5.6. Other Allocation Issues..............................................................................................................................35
5.7. Demand-Side Management Programs........................................................................................................37
5.8. State-Specific Initiatives............................................................................................................................37
6. Framework Issues...............................................................................................................................................38
6.1. Resource Planning and New Resource Assignment...................................................................................38
6.2. Net Power Costs/Nodal Pricing Model("NPM")............................................................................I.......39
• 6.3. Special Contracts........................................................................................................................................40
6.4. Limited Realignment..................................................................................................................................40
6.5. Post-Interim Period Capital Additions—Coal-Fueled Interim Period Resources......................................40
6.5.1. PacifiCorp Straw Proposal-Post-Interim Period Capital Investment Allocation Exceptions...............41
6.5.2. PacifiCorp Straw Proposal-Incremental Capital Investments Made Between 2024 and the Exit Date
Where Exit Date is On or Before December 31.2027.........................................................................................41
6.5.3. PacifiCorp Straw Proposal-Incremental Capital Investments Made in 2024 and 2025 Where Exit Date
isAfter 2027........................................................................................................................................................42
6.5.4. PacifiCorp Straw Proposal-Incremental Capital Investments Made Between 2026 and the Exit Date
Where the Exit Date is After 2027.......................................................................................................................43
7. Allocation of Gain or Loss from Sale of Assets..................................................................................................43
8. Interpretation and Governance............................................................................................................................43
8.1. Issues of Interpretation...............................................................................................................................43
8.2. Workgroups................................................................................................................................................44
8.2.1. Framework Issues Workgroup...............................................................................................................44
8.2.2. Multi-State Process Workgroup.............................................................................................................44
8.3. Commissioner Forum.................................................................................................................................44
8.4. Proposals to Change the 2020 Protocol during the Interim Period............................................................44
8.5. Replacement of the 2020 Protocol.............................................................................................................45
8.6. Interdependency Among Commission Approvals......................................................................................45
9. Compliance with Resource Laws........................................................................................................................46
• 10. Signatures of Parties to the 2020 Protocol..........................................................................................................46

Rocky Mountain Power
Exhibit No. 1 Page 4 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness Joelle R. Steward
1 1. I ntroduction
2 This 2020 PacifiCorp Inter-Jurisdictional Allocation Protocol Agreement (the "2020
3 Protocol" or this "Agreement") reflects the agreement among PacifiCorp (or the "Company"),
-t certain Commission' staff members, State regulatory agencies, customers, consumer advocates,
5 conservation organizations, and other interested parties from California, Idaho, Oregon, Utah,
6 Washington, and Wyoming (collectively referred to as the "States" or individually as a "State")
7 who have executed this Agreement (collectively referred to as the "Parties" or individually as a
s ` Party") on an interim allocation and assignment method and a process for determining a long-
9 term replacement of existing inter jurisdictional allocation and assignment methodologies.2 The
10 2020 Protocol is intended to: (1) supersede the 2017 PacifiCorp Inter-Jurisdictional Allocation
I l Protocol (the "2017 Protocol")for California, Idaho, Oregon, Utah, and Wyoming; and (2)modify
• 12 the West Control Area Inter jurisdictional Allocation Methodology ("WCA") for Washington.
13 However, as part of the 2020 Protocol, the 2017 Protocol and the WCA allocation methodologies
1.1 will continue to be used, with modifications explained herein, during an Interim Period, as defined
15 below. Subject to the provisions set forth below, and with the acknowledgment that only the
16 appropriate state body charged with issuing orders to establish rates can approve its use, the Parties
17 agree that the 2020 Protocol can be used to set just and reasonable rates and agree to support its
is use in rate filings in California, Idaho,Oregon,Utah,Washington,and Wyoming during the Interim
19 Period. The 2020 Protocol includes:
20 The allocation and assignment policies, procedures, and methods to be used during
21 the Interim Period (i.e., January 1, 2020 through December 31, 2023, as specified
' Capitalized terms in the 2020 Protocol are defined herein in Appendix A,or in Appendix C.
For purposes of this Agreement,use of the terms assign.assignment,and assigned generally refer to the generation.
capacity,benefits,and risks associated with certain assets and use of the terms allocate,allocated,allocation
generally refer to the treatment of costs associated with certain assets.
1

Rocky Mountain Power
Exhibit No 1 Page 5 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
• " in Section 2). The 2020 Protocol describes the way all components of PacifiCorp's
regulated service, including costs, revenues, and benefits associated with
'4 generation, transmission, distribution, and wholesale transactions, should be
allocated and assigned among the six States during the Interim Period. During the
Interim Period, these inter jurisdictional allocation policies, procedures, or
methods, if applied by each State as stated herein for rate proceedings filed during
the Interim Period, can provide PacifiCorp a reasonable opportunity to recover its
prudently incurred cost of service.
An agreement on certain issues that are intended to be implemented during the
Interim Period and,assuming final resolution of all outstanding issues, incorporated
into a Post-Interim Period Method agreement ("Implemented Issues").
>; A conditional agreement on certain issues intended to be implemented following
• .,4 the Interim Period, subject to final resolution of all outstanding issues ("Resolved
Issues").
36 A process and timeframe to address and attempt to resolve all outstanding issues
7 that the Parties intend to resolve after this 2020 Protocol has been filed with the
�g Commissions and during the Interim Period ("Framework"), including the
implementation or resolution of issues associated with a Nodal Pricing Model,
40 Resource planning and new Resource Assignment, Limited Realignment, Special
41 Contracts, post-Interim Period capital additions on coal-fueled Interim Period
42 Resources and other items ("Framework Issues"). The future resolution of
4; Framework Issues,combined with the Implemented Issues and the Resolved Issues,
44 would result in a new allocation methodology for PacifiCorp's six States ("Post-
2

Rocky Mountain Power
Exhibit No. 1 Page 6 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
• 45 Interim Period Method").
46 The proposed allocation of a particular expense or investment to a State under the 2020
47 Protocol is not intended to and will not prejudge the prudence of that cost or the extent to which
48 any particular cost may be reflected in rates. Nothing in the 2020 Protocol is intended to abrogate
49 any Commission's right or obligation to: (1) determine fair,just, and reasonable rates based upon
50 applicable laws and the record established in rate proceedings conducted by that Commission; (2)
51 consider the effect of changes in laws, regulations, or circumstances on inter jurisdictional
52 allocation policies and procedures when determining fair,just,and reasonable rates; or(3)establish
53 different allocation policies and procedures for purposes of allocating costs and revenues within
54 that State to different customers or customer classes.
55 Parties support the 2020 Protocol,but their support will not,in any manner, affect or negate
56 their right to address changed or unforeseen circumstances, including changes in laws or
57 regulations. A Part 's support of the 2020 Protocol will not bind or be used against that Pa if a
� Y PP g Party
58 Party concludes that the 2020 Protocol no longer produces results that are just, reasonable, or in
59 the public interest, or does not provide the Company with a reasonable opportunity to recover its
60 prudently incurred cost of service; provided, however, that in raising an objection to the 2020
61 Protocol the Parties agree to first raise any such objection by following the provisions of Section
62 8.4,
63 Support of the 2020 Protocol does not constitute an acknowledgment by any Party of the
64 validity or invalidity of any particular method, theory, or principle of regulation, cost recovery,
65 cost of service, or rate design. No Party will be deemed to have agreed that any particular method,
66 theory, or principle of regulation, Resource acquisition or Reassignment, cost recovery, cost of
67 service, or rate design employed in or implied by the 2020 Protocol is appropriate for resolving
•
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Rocky Mountain Power
Exhibit No. 1 Page 7 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
68 any issues other than the inter jurisdictional allocation of PacifiCorp's cost of service. The Parties
69 have made no effort to address or consider infra-state cost allocation issues and agree that using
70 the 2020 Protocol for inter jurisdictional cost allocation purposes does not suggest or require
71 similar treatment be applied to intra-state cost allocations for class cost-of-service purposes for
72 any State. Parties may propose such methods of intra-state class cost-of-service allocations as they
7; deem appropriate.
74 The 2020 Protocol includes the following appendices described briefly below:
75 Terms that are capitalized in the 2020 Protocol are defined herein, in Appendix A,
�> or in Appendix C.
77 Appendix B includes tables identifying the allocation factor to be applied to each
78 component of PacifiCorp's revenue requirement calculation.
79 :appendix C includes the definition and algebraic derivation of each allocation
s factor, alongwith the FERC accounts to which the allocation factor will be applied.
PP
I Appendix D is a Memorandum of Understanding among the Parties supporting the
S' Company's acquisition and implementation of a Nodal Pricing Model.
83 • Appendix E includes a table reflecting Commission-approved depreciable lives in
84 effect October 1, 2019, and the Company's proposed depreciable lives for coal-
85 fueled Interim Period Resources in pending depreciation dockets as filed in
86 September 2018.
87 • Appendix F is the Washington Inter-Jurisdictional Allocation Methodology
88 Memorandum of Understand]n�o between the Company and the Washington Parties,
which modifies the WCA.
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Rocky Mountain Power
Exhibit No. 1 Page 8 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
1090
Appendix G includes a description and numeric example of how Special Contracts
91 and related Issues will be treated dun i­ the Interim Period.
92 2. Timeframes and Effective Periods
93 2.1. Effective Period of the 2020 Protocol
94 For the Interim Period, January 1, 2020 through December 31, 2023, subject to Section
95 2.2.4,the Parties agree to support before their respective Commissions the use of the 2020 Protocol
96 in PacifiCorp regulatory proceedings or filings, subject to exceptions for deferred amounts
97 including, but not limited to, Net Power Costs as set forth in this Agreement. The 2020 Protocol
98 includes an agreed-upon approach for cost allocations to each State that will be used by PacifiCorp
99 in proceedings or filings commenced during the Interim Period, except as provided in Section
100 2.2.5.
101 2.2. Post-Interim Period
102 2.2.1. Commission Approvals for Post-Interim Period _lthod Obtained
103 Prior to December 31, 2023
104 If each State's Commission approves a Post-Interim Period Method agreement on or before
105 December 31,2023,or in the first general rate case after the Post-Interim Period Method agreement
106 is reached,' the Interim Period will terminate on December 31, 2023, and the Post-Interim Period
107 Method will take effect, subject to Section 2.2.2.
108 2.2.2. Commission Approval Not Granted
109 If any Commission denies PacifiCorp's request for approval of the Post-Interim Period
110 Method agreement, PacifiCorp will propose an alternative allocation method for the Post-Interim
III Period for consideration by all the Commissions. Parties are free to take any position regarding
. 'The Parties understand the California and Washington Commissions will likely consider the Post-Interim Period
Method in the first general rate case filed in either State after an agreement has been reached on the Post-Interim
Period Method.and approval may occur after December 31,2023.
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Rocky Mountain Power
Exhibit No. 1 Page 9 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness Joelle R Steward
• �? PacifiCorp's proposal, including proposing alternative allocation methodologies, filing a
1 complaint, or requesting an investigation of PacifiCorp's proposal.
114 2.2.3. Post-Interim Period Method Agreement Not Reached
115 If the Company determines that it is unlikely that a Post-Interim Period Method agreement
116 will be reached before the end of the Interim Period,then the Company will propose an allocation
117 method for the Post-Interim Period for consideration by the Commissions. Parties are free to take
118 any position regarding PacifiCorp's proposal, including proposing alternative allocation
119 methodologies, or initiating a complaint or investigation of PacifiCorp's proposal.
120 2.2.4. Early Commission Approvals of Post-Interim Period Method
121 If a Post-Interim Period Method agreement is reached on or before December 31, 2022,
122 any Post-Interim Period Method agreement will address whether and the degree to which the
123 Company will use the Post-Interim Period Method in regulatory proceedings or filings commenced
0124 after December 31, 2022.
125 2.2.5. Regulatory Filings to Implement Post-Interim Period Method
126 Any Post-Interim Period Method agreement will address whether and the degree to which
127 the Company may use the Post-Interim Period Method in regulatory proceedings or filings
129 commenced during the Interim Period while Commission approvals of the Post-Interim Period
129 Method agreement are pending but to be effective after the end of the Interim Period.
13o 3. Interim Period Allocation Method
131 The 2017 Protocol expires December 31, 2019.4 The Parties representing interests in the
132 States of California, Idaho, Oregon, Utah,and Wyoming(collectively referred to as the"Five State
133 Parties" and the "Five States") agree that the methodology outlined in the 2017 Protocol being
'As proposed in PacifiCorp's 2019 California general rate case filing,the 2017 Protocol does not expire in
California on December 31,2019.
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Rocky Mountain Power
Exhibit No. 1 Page 10 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
,e134 used by the Company in 2019 should continue, as outlined and modified in Section 3, during the
135 Interim Period while the Parties continue to negotiate the Framework Issues necessary to develop
136 the Post-Interim Period Method. The Washington Parties agree that the methodology outlined in
137 the WCA being used in 2019 should, subject to the terms included in Appendix F, continue during
138 the Interim Period while the Parties continue to negotiate the Framework Issues necessary to
139 develop the Post-Interim Period Method.
140 For the Five States, the terms of the 2017 Protocol that will be used during the Interim
141 Period under the 2020 Protocol are provided in Section 3.1. The 2017 Protocol terms that are
142 being modified by this Agreement are provided in Section 3.2.
143 3.1. Continuing Terms of the 2017 Protocol for the Five States Interim
144 Period Allocation Methodology'
145 Items included in the Company's results of operations will be allocated on the factors set
• 146 forth below. The FERC account and allocation factor combinations are included in Appendix B.
147 The algebraic derivation and factor definitions are included in Appendix C.
148 3.1.1. Classification of Interim Period Resources
149 All Fixed Costs of Interim Period Resources will be classified as 75 percent Demand-
150 Related and 25 percent Energy-Related. All Non-Firm Purchases and Sales will be classified as
151 100 percent Energy-Related.
152 3.1.2. Allocation of Interim Period Resource Costs and Wholesale Revenues
153 Interim Period Resources will be allocated to one of two categories for inter jurisdictional
154 allocation purposes: State Resources or System Resources. A complete description of allocation
155 factors to be used is set forth in Appendix B.
Terminology in Section 3.1 has been modified from the language in the 2017 Protocol to maintain consistency in
the use of terms within the 2020 Protocol.
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Rocky Mountain Power
Exhibit No.1 Page 11 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
0156 There are three types of State Resources. The remaining types of Interim Period Resources
157 are System Resources, which constitute the substantial majority of PacifiCorp's Resources.
158 Benefits and costs associated with each category and type of Interim Period Resource will be
159 assigned or allocated to States on the following basis.
160 3.1.2.1. Interim Period State Resources
161 Benefits and costs associated with the three types of State Resources will be assigned or
162 allocated as follows:
163 • Demand-Side Manaaement ("DSM') Programs: Costs associated with DSM
164 Programs, including Class I DSM Programs, will be allocated on a situs basis to
165 the State in which the investment is made. Benefits from these programs, in the
166 form of reduced consumption and contribution to Coincident Peak,will be reflected
167 in the Load-Based Dynamic Allocation Factors.
•168 • Portfolio Standards: The portion of costs associated with Interim Period Resources
169 acquired to comply with a State's Portfolio Standard adopted, either through
170 legislative enactment or by a State's Commission, that exceed the costs PacifiCorp
171 would have otherwise incurred, will be allocated on a situs basis to the Jurisdiction
172) adopting the Portfolio Standard.
1, State-Specific Initiatives: Costs and benefits associated with Interim Period
174 Resources acquired in accordance with a State-specific initiative will be allocated
175 and assigned on a situs basis to the State adopting the initiative. State-specific
176 initiatives include, but are not limited to, the costs and benefits of incentive
177 programs, net-metering tariffs, feed-in tariffs, capacity standard programs, solar
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Rocky Mountain Power
Exhibit No. 1 Page 12 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R Steward
0118 subscription programs, electric vehicle programs, and the acquisition of renewable
179 energy certificates.
180 3.1.2.2. Interim Period System Resources
181 All Interim Period Resources that are not State Resources are System Resources and will
182 be allocated as follows:
183 • Generally, all Fixed Costs associated with System Resources and all costs incurred
184 under Wholesale Contracts will be allocated based upon the System Generation
185 ("SG") Factor.
186 . Generally, all Variable Costs associated with System Resources will be allocated
187 based upon the System Energy("SE")Factor.
188 • Revenues received by PacifiCorp under Wholesale Contracts will be allocated
189 based upon the SG Factor.
�190 3.1.3. Re-functionalization and Allocation of Transmission Costs and
191 Revenues
192 Before filing any request to approve a reclassification of facilities as transmission or
193 distribution with FERC, PacifiCorp will submit filings seeking review and authorization of any
194 such reclassification with the Commissions. The cost responsibility for any assets reclassified
195 under FERC policy will be assigned or allocated consistent with other assets in the relevant
196 function.
197 Costs associated with transmission assets, and firm wheeling expenses and revenues, will
198 be classified as 75 percent Demand-Related, 25 percent Energy-Related, and allocated based upon
199 the SG Factor, Non-firm wheeling expenses and revenues will be allocated based upon the SE
200 Factor. In the event that PacifiCorp joins a regional independent system operator, the allocation
�201 of transmission costs and revenues may be reevaluated and revised as provided for in Section 8.4.
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Rocky Mountain Power
Exhibit No 1 Page 13 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R. Steward
• 202 3.1.4. Allocation of Distribution Costs
203 All distribution-related expenses and investment that can be directly allocated will be
204 directly allocated to the State where they are located. Those costs that cannot be directly allocated
205 will be allocated consistent with the factors set forth in Appendix B.
206 3.1.5. Allocation of Administrative and General Costs
207 Administrative and General Costs, General Plant costs, and Intangible Plant costs will be
208 allocated consistent with the factors set forth in Appendix B.
209 3.1.6. Allocation of Special Contracts
210 Revenues associated with Special Contracts will be included in State revenues, and loads
211 of Special Contract customers will be included in Load-Based Dynamic Allocation Factors as
212 appropriate (see Appendix G). Special Contracts may or may not include Customer Ancillary
213 Service Contract attributes. Load curtailments and buy-through arrangements will be handled as
10214 appropriate (see Appendix G).
215 3.1.7 Miscellaneous Costs and Taxes
216 Miscellaneous costs described below will be allocated as follows:
217 • Generation-related dispatch costs and associated plant will be allocated on the SG
218 Factor.
219 • Miscellaneous regulatory assets and liabilities, and miscellaneous deferred debits
220 will be allocated with the appropriate allocation factor depending on the related
221 assets or underlying costs.
222 Taxes and fees will be allocated as follows:
223 • Income taxes will be calculated using the federal tax rate and PacifiCorp's
224 combined State effective tax rate. State-specific Schedule M and deferred income
225 tax amounts will be allocated using the Company's tax software system. Consistent
10

Rocky Mountain Power
Exhibit No. 1 Page 14 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
with prior system allocation methods, the Washington Public Utility Tax is
• ,,, allocated using the SO Factor in lieu of a Washington income tax.
- g �
• Franchise taxes, revenue related taxes, Commission assessments and fees, and
" > usage related taxes are situs or a pass through_
• Property taxes are system allocated based on gross plant and allocated on a Gross
i Plant System ("GPS")Factor.
22 • Generation and fuel-related taxes will be allocated using the SG Factor.
233 • Other taxes such as payroll taxes are embedded in expenses or capital costs.
234 Balances associated with the Trojan Decommissioning will be allocated using the Trojan
235 Decommissioning("TROJD") Factor. This will not impact State-specific treatment of this item.
236 3.1.8. State Programs Regarding Access to Alternative Electricity Suppliers
9237 3.1.8.1. Treatment of Oregon Direct Access Programs
238 This Section describes treatment of loads lost to Oregon Direct Access Programs during
239 the term of the 2020 Protocol.
240 3.1.8.1.1. Customers Electing PacifiCorp's One- and
241 Three-Year Oregon Direct Access Programs
242 Customer loads electing to be served on PacifiCorp's one- and three-year Oregon Direct
243 Access Programs will be included in the Load-Based Dynamic Allocation Factors for all Interim
244 Period Resources, and the transition cost payments from these customers will be situs assigned
245 and allocated to Oregon.
246 3.1.8.1.2. Customers Electing PacifiCorp's Five Year Opt-
247 Out Program Under the Oregon Direct Access
248 Program
249 The treatment will be consistent with Order No. 15-060, as clarified through Order No. 15-
250 067,of the Oregon Public Utility Commission in Docket UE 267, and Oregon Schedule 296,which
11

Rocky Mountain Power
Exhibit No.1 Page 15 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
0251 allow Oregon Direct Access Consumers to permanently opt-out of cost-of-service rates after
252 payment often years of transition costs in Oregon. If an Oregon Direct Access Consumer is paying
253 transition costs during the Interim Period, the Oregon Direct Access Consumer's load(s) will be
254 included in Load-Based Dynamic Allocation Factors, and the transition cost payments from these
255 consumers will be situs-assigned to Oregon. If any Oregon Direct Access Consumer reaches the
256 end of the 10-year period covered by the transition cost payments during the Interim Period, the
257 load(s) for that Oregon Direct Access Consumer will be excluded from Load-Based Dynamic
258 Allocation Factors. Thereafter, if an Oregon Direct Access Consumer elects to return to Oregon
259 cost-of-service rates by providing four-years notice under Schedule 296, its load will be treated as
260 new load and incorporated in PacifiCorp's Resource planning process.
261 3.1.8.1.3. New Laws or Regulations
262 To the extent Oregon adopts new laws or regulations regarding Oregon Direct Access
0263 Programs, Oregon's treatment of loads lost to Oregon Direct Access Programs may be re-
264 determined in a manner consistent with the new laws and regulations. In the event Oregon adopts
265 such new laws or regulations, the Company will inform the Commissions and the Parties of the
266 same.
267 3.1.8.2. Utah Eligible Customer Program
268 If,pursuant to Utah Code Annotated Section 54-3-32,an eligible customer in Utah transfers
269 service to a non-utility energy supplier, the Public Service Commission of Utah will make
270 determinations under Utah law as contemplated therein. The Company will inform the
271 Commissions and the Parties of the Public Service Commission of Utah's determinations.
272 3.1.8.3. Other State Actions
273 In the event any State adopts laws or regulations governing customer access to alternative
0274 electricity suppliers, the Company will infomi the Commissions and the Parties of the same.
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Rocky Mountain Power
Exhibit No 1 Page 16 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
0271 3.1.9. Loss or Increase in Load
276 Any loss or increase in retail load occurring as a result of condemnation or
277 municipalization, sale or acquisition of new service territory that involves less than five percent of
278 system load, realignment of service territories, changes in economic conditions, or gain or loss of
279 large customers will be reflected in changes in the Load-Based Dynamic Allocation Factors. The
280 allocation or assignment of costs and benefits arising from merger, sale, or acquisition transaction
281 proposed by the Company involving more than five percent of system load will be considered on
282 a case-by-case basis in the course of Commission approval proceedings.
283 3.1.10. Commission Regulation of Interim Period Resources
284 PacifiCorp will plan and acquire new Interim Period Resources on a system-wide risk-
285 adjusted, least-cost basis. Prudently incurred investments in Interim Period Resources will be
286 reflected in rates consistent with the laws and regulations in each State, as approved by individual
0287 Commissions.
288 3.2. Modifications to the 2017 Protocol During the Interim Period
289 3.2.1. Net Power Costs Filings
290 For Net Power Costs ("NPC") filings, Parties agree to support use of the allocation
291 methodology in place when the NPC were or will be incurred, to align the timing of the actual
292 costs incurred with the applicable allocation method for cost recovery for that period. The table
293 below summarizes the transition from the 2017 Protocol to the 2020 Protocol for NPC filings. If
294 a Post-Interim Period Method agreement is reached between the Parties, a similar table will be
295 included to summarize the transition for NPC filings from the 2020 Protocol to the subsequent
296 agreement.
•
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Rocky Mountain Power
Exhibit No. 1 Page 17 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R Steward
Allocation Methodology Used for NPC Filings
Filing 2017 Protocol 2020 Protocol Notes
California ECAC 2021 ECAC for the 2022 ECAC for the
(Balancing Rate CY2020 Deferral Period CY2021 Deferral Period
California ECAC 2020 ECAC for the 2021 ECAC for the
(Offset Rate) CY2020 Forecast Period CY2021 Forecast Period 1
2020 ECAM for the 2021 ECAM for the
Idaho ECAM CY2019 Deferral Period CY2020 Deferral Period
2020 TAM for the CY2019 2021 TAM for the CY2020
c)rcon TAM Forecast Period Forecast Period
2020 PCAM for the 2021 PCAM for the
Oregon PCAM CY2019 Deferral Period CY2020 Deferral Period
2020 EBA for the CY2019 2021 EBA for the CY2020
Utah EBA Deferral Period Deferral Period
2019 PCAM for the 2020 PCAM for the
Washington PCAM CY2019 Deferral Period CY2020 Deferral Period 2
2020 ECAM for the 2021 ECAM for the
Wyoming ECAM CY2019 Deferral Period CY2020 Deferral Period
Net Power Costs included GRC with rate effective
in General Rate Cases date on or after January 1.
(GRC)-All States 2020
Notes:
1.The 2020 Protocol will not be implemented in California until approved by the Commission in a
general rate case. The dates included in the table are subject to change based on the California general
rate case schedule,the next general rate case is currently-scheduled to use a 2022 test period.
2. Washington will use the modified WCA allocation methodology per Appendix F of the 2020
Protocol.
3.This also applies to any other NPC filing that resets base NPC rates.
297 3.3.2. Embedded Cost Differential ("ECD") and Equalization Adjustment
298 3.3.2.1. ECD
299 The Fixed ECD will continue for Idaho through the end of the Interim Period. The
300 Dynamic ECD for Oregon will continue through the end of the Interim Period, capped at
301 $11,000,000. No ECD adjustment exists for Utah or California.
302 The Wyoming ECD will terminate December 31, 2020. Beginning January 1, 2021, for
303 purposes of the Wyoming energy cost adjustment mechanism("ECAM"), actual ECD will be zero
.304 and the true-up of the Wyoming ECD will not be subject to sharing bands in the Wyoming ECAM.
9_305 This treatment will continue until the ECD is removed from base rates.
14

Rocky Mountain Power
Exhibit No 1 Page 18 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
0106 3.3.2.2. Equalization Adjustment
307 The Equalization Adjustment addressed in Section XIV of the 2017 Protocol will terminate
308 on December 31, 2019, and no additional Equalization Adjustment amounts will be deferred after
309 that date. The method PacifiCorp will use to collect deferred Equalization Adjustment balances
310 and any related carrying charges has been or will be addressed in appropriate State regulatory
311 proceedings.
1312 3.3.3. Costs and Benefits of Qualifying Facilities
313 Costs and benefits of Qualifying Facilities will be treated consistent with the provisions
,14 specified in Section 4.4.
315 3.3.4. Allocation of Gain or Loss from Sale of Assets
316 The allocation of any gain or loss from the Company's sale of assets will be treated
317 consistent with the provisions specified in Section 7.
01118 3.3.5. Interpretation and Governance
319 This Agreement will be interpreted and PacifiCorp's Multi-State Process ("MSP") will be
320 governed by the provisions specified in Section 8.
321 4. Implemented Issues
322 The Parties agree that the following items, described later in this Section 4, will be
323 implemented and effective during the Interim Period:
324 • The process and timing for States' decisions to exit coal-fueled Interim Period
325 Resources;
326 • The process for potential Reassignment of coal-fueled Interim Period Resources
327 among States without Exit Orders;
328 • The process for the allocation of Decommissioning Costs; and
•329 • The allocation and assignment of Qualifying Facility Power Purchase Agreements
15

Rocky Mountain Power
Exhibit No. 1 Page 19 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness: Joelle R. Steward
330 ("QF PPAs").
10
331 These issues are more thoroughly explained below.
332 4.1. States' Decisions to Exit Coal-Fueled Interim Period Resources
333 PacifiCorp will continue to conduct operational and economic analyses in accordance with
334 applicable regulatory requirements and good utility practice to maintain reliable service on a risk-
335 adjusted,least-cost basis for its customers. PacifiCorp anticipates continuing to conduct integrated
336 resource planning, at least biennially. PacifiCorp also anticipates continuing to undertake
337 depreciation studies on a five-year cycle. If these analyses affect the depreciable lives or
338 operational lives of Interim Period Resources in the future, Parties may address such effects
339 through appropriate regulatory proceedings before the Commissions. Nothing in this Agreement
340 affects PacifiCorp's rights and obligations to make prudent decisions regarding operation of its
•341 assets and system in accordance with applicable law. The Parties further agree that PacifiCorp's
342 coal-fueled Interim Period Resource Closure dates may be informed by new information that
343 becomes available as a result of other regulatory filings or actions, including integrated resource
344 plans or State and federal energy policies. Nothing in this Agreement affects or limits any Party's
345 ability to raise any prudence issues with regards to PacifiCorp's decisions regarding Closure of an
346 Interim Period Resource.
347 Subject to the possible effects of Limited Realignment, the Parties agree to the following
348 procedures for the Company's coal-fueled Interim Period Resources.
349 4.1.1. Allocation of Costs at Closure
350 Upon Closure of a coal-fueled Interim Period Resource,each State that is receiving benefits
351 and is allocated costs associated with the coal-fueled Interim Period Resource at the time of
�352 Closure shall continue to be allocated its share of the remaining costs of the coal-fueled Interim
16

Rocky Mountain Power
Exhibit No. 1 Page 20 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
Period Resource in accordance with this 2020 Protocol,which may include the remaining net book
,54 value and Commission-approved Decommissioning Costs. The existence of an Exit Order does
»� not change this allocation, and all States assigned benefits and allocated costs from the coal-fueled
356 Interim Period Resource at the time of Closure will be allocated actual costs. Therefore, if every
357 State is being assigned benefits and allocated costs from a coal-fueled Interim Period Resource at
358 the time of Closure, every State will be allocated, in accordance with the method set forth in this
359 Agreement, all the actual costs associated with that coal-fueled Interim Period Resource and its
360 Closure. This can occur,for example,if every State(excepting Washington as discussed in Section
361 4.1.4) issues an Exit Order with the same Exit Date for a particular coal-fueled Interim Period
362 Resource. This can also occur,for example,if PacifiCorp pursues Closure of a coal-fueled Interim
363 Period Resource prior to a State Exit Date. No Party,by virtue of this Agreement, waives its right
0364 to investigate and analyze whether the Company's decision to continue operation or continue an
365 ownershipinterest is prudent, regardless of the anticipated Closure dates in the tables in Section
p g P
366 4.1.3.
367 4.1.2 Exit Orders
368 The Parties, representing diverse and varied interests, have worked in good faith to create
369 a process that allows for States to pursue differing resource portfolios in the future, including
370 decisions to transition out of coal-fueled Interim Period Resources while mitigating resulting
371 effects to the Company and other States. A Commission may issue an Exit Order specifying an
372 Exit Date in a proceeding for approval of this Agreement, a depreciation docket, a rate case, or any
373 other appropriate proceeding. A Commission Order or other determination that a coal-fueled
374 Interim Period Resource will reach the end of its depreciable life without a specific determination
• 6 An Exit Order is not required from a Commission if a coal-fueled Interim Pcriod Resource is not included in
PacifiCorp's rates in that State.
17

Rocky Mountain Power
Exhibit No. 1 Page 21 of 134 EXECUTION VERSION
Case No PAC-E-19-20
Witness Joelle R. Steward
•375 that the State will exit the Interim Period Resource shall not constitute an Exit Order. Provided
376 PaciftCorp secures all applicable approvals, a Company decision to close a coal-fueled Interim
377 Period Resource earlier than previously anticipated does not require the issuance of an Exit Order.
378 An Exit Order does not, by itself, result in Reassignment of shares of a coal-fueled Interim Period
379 Resource to other States or affect an Exiting State's responsibility for its share of the then-
380 remaining net book value of the Interim Period Resource that is being exited.
381 To provide the Company and States without Exit Orders time to consider the options and
382 address the potential Reassignment of the coal-fueled Interim Period Resource, as set forth in
383 Section 4.2, under this Agreement an Exit Order should provide at least four-years of notice'from
384 the date of the Exit Order to the Exit Date. After an Exit Date, the Exiting State will no longer be
385 allocated any new costs' and will no longer be assigned any benefits associated with that coal-
386 fueled Interim Period Resource, and no other State will be allocated the Exiting State's share of
�387 costs nor receive the Exiting s State' assigned benefits associated with that coal-fueled Interim
388 Period Resource, unless the costs and benefits are accepted through a Commission Order on
389 Reassignment. Until the Exit Date, an Exiting State shall continue to be assigned the benefits of
390 that coal-fueled Interim Period Resource and shall be allocated costs associated with that coal-
391 fueled Interim Period Resource in accordance with this 2020 Protocol or as determined through
392 the Framework process, which may include costs associated with any remaining net book value,
393 prudently incurred capital additions, prudently incurred Operations and Maintenance ("O&M")
394 expense, and prudently incurred or reasonably estimated Decommissioning Costs.
Subject to the provisions in Sections 4.1.3 and 4.1.4.
e New costs are costs incurred after the Exit Date to maintain or operate the coal-fueled Interim Period Resource
beyond that date. Amv costs associated with the operation of a coal-fueled Interim Period Resource and incurred
prior to the Exit Date that are allocated to the Exiting State as determined through the 2020 Protocol and that have
not yet been collected from customers in that State are still that State's responsibility.
18

Rocky Mountain Power
Exhibit No.1 Page 22 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
0315 An Exit Order establishes the Exit Date that PacifiCorp will use to propose the allocation
396 of DecommissioningCosts allocation of capital additions costs and an other associated costs
p Y
397 related to the exit from a coal-fueled Interim Period Resource as outlined in the 2020 Protocol.
398 PacifiCorp will timely propose to Parties from an Exiting State a method to address the treatment
399 of these costs for ratemaking, such that costs and benefits remain matched in customer rates.
400 Following receipt of an Exit Order, the Company will file in accordance with Section 4.2
401 to allow States without Exit Orders the opportunity to evaluate the potential Reassignment of the
402 coal-fueled Interim Period Resource. For regulatory efficiency, Section 4.1.3 establishes
403 timeframes for addressing Exit Orders from coal-fueled Interim Period Resources by Oregon and
404 the potential Reassignment of those resources to other States.
405 4.1.3 Oregon Exit Dates
406 The Oregon Parties and the Company a�,ree to recommend that the dates shown in the
0407 tables in this Section 4.1.3 be used in Oregon for service and depreciable lives, and for establishing
408 Oregon's Exit Dates for all coal-fueled Interim Period Resources.
409 4.1.3.1 Coal-Fueled Interim Period Resources Not Operated by
410 PacifiCorp Subject to Common Closure Dates, Oregon
411 Exit 2023-2027
412 PacifiCorp anticipates that Cholla Unit 4, Craig Unit 1, Craig Unit 2, Colstrip Unit 3, and
413 Colstrip Unit 4 will have common Closure dates for all States. If PacifiCorp effectuates Closure
414 at Cholla Unit 4, Craig Unit 1, Craig Unit 2, Colstrip Unit 3, or Colstrip Unit 4 on or before the
415 applicable dates identified in the table below, each State will be allocated its share of the costs and
416 benefits of that coal-fueled Interim Period Resource with no transfer of cost responsibility or
417 decommissioning liability among States, in accordance with Section 4.1.1.
418 PacifiCorp and the Oregon Parties agree to recommend to the Oregon Commission that the
0419 dates shown in the table below be used for establishing Oregon's Exit Dates and Oregon
19

Rocky Mountain Power
Exhibit No. 1 Page 23 of 134 EXECUTION VERSION
Case No. PAC-E-19-2D
VVitness:Joelle R. Steward
.42o depreciable lives for Cholla Unit 4, Craig Unit 1, Craig Unit 2, Colstrip Unit 3, and Colstrip Unit
421 4.
Coal-Fueled Interim
Period Resource Anticipated Closure
Name Date
Cholla Unit 4 January 1,2023
Craig Unit 1 December 31,2025
Craig Unit 2 December 31,2026
Colstrip Unit 3 December 31.2027
Colstrip Unit 4 December 31,2027
422 PacifiCorp and the Oregon Parties agree that PacifiCorp will make best efforts to effectuate
423 Closure of the units identified above by the anticipated Closure dates, but the Company may need
424 additional time for Closure of Craig Units 1 and 2 and Colstrip Units 3 and 4 due to its joint-owner
425 agreements, and Cholla Unit 4 due to other contractual requirements.
•426 If PacifiCorp has received an Exit Order from Oregon for Craig Unit 1, Craig Unit 2,
427Colstrip Unit 3, or Colstrip Unit 4 with the same Exit Date as the date set forth in the table above
428 and PacifiCorp does not effectuate Closure by such date, Oregon may elect, at its option, to:
42)9 • Continue to take an allocation and assignment of the costs and benefits of such unit
430 for one additional year following the specified Exit Date, or
431 • Discontinue taking an allocation and assignment of the costs and benefits of such
12 unit as of the specified Exit Date.
1;, Under either election, Oregon will continue to be subject to an allocation of actual
434 Decommissioning Costs if Closure of the unit is effectuated within such one-year period. If
435 Closure of the unit is not effectuated within such one-year period, Oregon will be allocated
436 Decommissioning Costs based on the estimates established pursuant to Section 4.3.
20

Rocky Mountain Power
Exhibit No. 1 Page 24 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
V1litness Joelle R. Steward
43, Oregon will be allocated actual Decommissioning Costs if Closure of Cholla Unit 4 occurs
0
438 on or before January 1, 2023. If Cholla Unit 4 operates beyond January 1, 2023, Oregon will be
4.39 allocated only estimated Decommissioning Costs as of January 1, 2023.
440 4.1.3.2. Coal-Fueled Interim Period Resources Operated by
441 PacifiCorp, Oregon Exit Through 2027
442 The Oregon Parties and the Company agree to recommend to the Oregon Commission that
4433 the Exit Date for each coal-fueled Interim Period Resource shown in the following table should be
444 used in Oregon for establishing Oregon's Exit Dates and Oregon depreciable lives for these coal-
445 fueled Interim Period Resources, subject to the other provisions of this Section 4.1.
Coal-Fueled Interim Recommended
Period Resource Oregon Exit Date
Jim Bridger 1 December 31,2023
Jim Bridger 2 December 31,2025
Jim Bridger 3 December 31,2025
• Jim Bridger 4 December 31,2025
Naughton l December 31,2025
Naughton 2 December 31.2025
Dave Johnston l December'31.2027
Dave Johnston 2 December 31.2027
Dave Johnston 3 December 31. 2027
Dave Johnston 4 December 31.2027
446 Oregon Parties and the Company will strive to have Exit Orders issued on or before
447 December 15, 2020, for the coal-fueled Interim Period Resources reflected in the table above to
448 allow the Company to make filings in the other States in accordance with Section 4.2. If
449 PacifiCorp effectuates Closure for any of the units no later than the dates in the table above, then
450 the provisions of 4.1.1 will apply.
21

Rocky Mountain Power
Exhibit No 1 Page 25 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness Joelle R. Steward
10451 4.1.3.3. Coal-Fueled Interim Period Resources, Oregon Exit
452 Date 2028- 2029
453 The Oregon Parties and the Company agree that the recommended Exit Dates for the coal-
454 fueled Interim Period Resources shown in the following table should be used in Oregon for
455 establishing Oregon's Exit Dates and Oregon depreciable lives for these coal-fueled Interim Period
456 Resources for purposes of this Agreement, subject to the other provisions of this Section 4.1.
Coal-Fueled Interim
Period Resource Recommended
Name Oregon Exit Date
Hunter 1 December 31,2029
Hunter 2 December 31,2029
Hunter 3 December 31,2029
Huntington 1 December 31,2029
Huntington 2 December 31, 2029
Wvodak December 31,2029
457 Oregon Parties and the Company will strive to have Exit Orders issued by the Oregon
458 Commission issued by December 31, 2023, for the coal-fueled Interim Period Resources reflected
459 in the table above to allow the Company to make the necessary filings in other States in accordance
460 with Section 4.2. If PacifiCorp effectuates Closure for any of the units no later than the dates in
461 the table above, then the provisions of 4.1.1 will apply.
462 4.1.4. Washington Exit Orders
463 The Washington Clean Energy Transformation Act ("CETA") requires coal-fueled Interim
464 Period Resources to be out of Washington rates by December 31, 2025. Section 6.4 of the
465 Framework Issues addressing Limited Realignment is intended to facilitate the removal of coal-
466 fueled Interim Period Resources from Washington rates and address the Washington-allocated
467 share, per the System Generation-Fixed ("SGF") Factor, as defined in Appendix C, of all coal-
468 fueled Interim Period Resources whether or not those resources are included in Washington rates.
�469 Washington Commission approval of the 2020 Protocol will constitute an Exit Order for
22

Rocky Mountain Power
Exhibit No. 1 Page 26 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
•470 Washington, unless modified by Reassignment or Limited Realignment, with an Exit Date of
471 December 31, 2023, for Jim Bndger Unit 1, and December 31, 2025, for Jim Bridger Units 2-4
472 and Colstrip Unit 4. PacifiCorp and the Washington Parties agree that an Exit Order is not required
473 from the Washington Utilities and Transportation Commission for any coal-fueled Interim Period
474 Resources not currently in Washington rates, and PacifiCorp can evaluate seeking Reassignment
475 upon approval of the 2020 Protocol by the Washington Commission.
476 4.1.5. Establishment of Exit Dates for Hayden Units 1 and 2
477 On or before February 1, 2021, the Company will make State-specific recommendations
478 to Commissions for the treatment of Hayden Units 1 and 2. If PacifiCorp effectuates Closure for
479 Hayden Units 1 and 2, then the provisions of 4.1.1 will apply, subject to applicable legal
4so requirements.
0491 4.2. Reassignment of Coal-Fueled Interim Period Resources
482 4.2.1 Company Proposals for Reassignment
483 After receipt of any Exit Order, PacifiCorp shall analyze whether it is reasonable to
484 continue to operate the affected coal-fueled Interim Period Resource for customers in one or more
485 of the States without Exit Orders. PacifiCorp may propose Reassignment of a greater share of the
486 coal-fueled Interim Period Resource to such State(s) to match State load and resource balance, or
487 request issuance of an Exit Order.9 PacifiCorp shall provide its analysis to Parties in each
488 applicable State and may make a filing with the Commission in each State that, as yet, has not
489 entered an Exit Order for such coal-fueled Interim Period Resource consistent with the timeframes
490 set forth in Sections 4.1 and this Section. If PacifiCorp seeks Reassignment, the analysis shall be
491 accompanied by recommendations as to an anticipated Closure date if Reassignment is accepted
• 9 Provided PacifiCorp secures all applicable approvals,PacifiCorp may effectuate Closure of a Resource without
requesting issuance of any Exit Order.
23

Rocky Mountain Power
Exhibit No.1 Page 27 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
0492 for such coal-fueled Interim Period Resource. Recommended Reassignments, if proposed, should
491 include a range of options, including fallback options based on the potential that one Commission
494 may reject PaciftCotp's recommendation while another Commission may accept the primary
495 recommendation. Notwithstanding this Section 4.2.1, realignment of certain Interim Period
496 Resources serving Washington will be determined subject to resolution of the Limited Realignment
497 Framework Issue or Section 4.1.4 as applicable.
498 4.2.2 Process and Timing
499 Consistent with Section 4.1, for those coal-fueled Interim Period Resources, with an Exit
500 Date on or before December 31, 2027, the filings including the Company's analysis and
50► recommendations are targeted to occur by February 1, 2021. For those coal-fueled Interim Period
502 Resources with an Exit Date after December 31, 2027, and on or before December 31, 2029, the
503 filings including the Company's analysis and recommendations are targeted to occur by June 30,
0504 2024, for Exit Orders that are received by December 31, 2023. Where possible, PacifiCorp will
505 make such filings concurrently in each State without an Exit Order so that each unit or plant can
506 be analyzed as a whole. To the extent a delay to these targeted filing dates is necessary, the
507 Company will provide notice to the Parties and Commissions explaining the reason and expected
508 filing dates. For coal-fueled Interim Period Resources with Exit Orders with different Exit Dates,
509 the Company will provide its analysis to the States without Exit Orders within six months after the
510 date any Exit Order is issued by any Commission, subject to the provisions of Section 4.1.4 for the
511 Washington Exit Orders.
512 If PacifiCorp makes filings pursuant to this Section in multiple States without Exit Orders,
513 then within 60 days from the date the last Commission issues an order pertaining to such filings,
514 PacifiCorp will submit a supplemental filing with each Commission in the State(s) without Exit
24

Rocky Mountain Power
Exhibit No.1 Page 28 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
0515 Orders summarizing the decisions made by each Commission and PaciliCorp's recommendati011s
516 regarding the implications.
517 4.2.3 Effects of Commission Decisions Regarding Assignment
518 If one or more Commissions have entered orders accepting, collectively, one-hundred
519 percent 10 of the cost allocation of a coal-fueled Interi m Period Resource beyond any Exit Date,the
520 costs and benefits of the coal-fueled Interim Period Resource after such Exit Date shall be
521 Reassigned to the States in accordance with the approved Reassignment as specified in the
522 applicable Commission Orders. Supplemental filings will reflect the final Reassignment of each
523 coal-fueled Interim Period Resource as a result of the Reassignment process and Commission
524 Orders.
525 If two or more Commissions have entered orders requesting, collectively, more than one-
526 hundred percent'1 of the cost allocation and associated benefits of a coal-fueled Interim Period
•527 Resource beyond an Exit Date,the Company will recommend a pro-rata Reassignment u to one
Y Y p Y P � P
528 hundred percent in accordance with the approved Reassignment as specified in the applicable
529 Commission Orders. Supplemental filings will reflect this pro-rata treatment of each coal-fueled
510 Interim Period Resource as a result of the pro-rata Reassignment process for further review and
t approval by the Commissions.
532 If Commissions do not agree to accept one-hundred percent cost allocation, collectively, of
533 a coal-fueled Interim Period Resource beyond an Exit Date, as part of its supplemental filings, the
534 Company will provide its recommendations on the treatment of any shortfall in the Reassignment
10 Based on PacifiCorp's ownership interest in the coal-fueled Interim Resource, whether wholly-owned or jointly-
owned.
• '` Based on PacifiCorp's ownership interest in the coal-fueled Interim Resource. whether wholly-owned or jointly-
owned.
25

Rocky Mountain Power
Exhibit No. 1 Page 29 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R Steward
0511 of a coal-fueled Interim Period Resource or recommendations on capacity reductions throu-h
536 Closures for further Commission consideration.
537 In the event of either common Exit Dates for all States or Closure as a result of the
538 Reassignment process or other appropriate regulatory proceedings,the provisions of Section 4.1.1
539 will apply.
540 4.3. Decommissioning Costs
541 4.3.1. Process for Determining Decommissioning Cost Allocation
542 4.3.1.1. Decommissioning Studies
543 The Company intends to undertake a contractor-assisted engineering study of
544 decommissioning costs and to make best efforts to complete the study by January 15, 2020, to
545 estimate appropriate Decommissioning Cost reserve requirements for the Jim Bridger, Dave
546 Johnston, Hunter, Huntington, Naughton, Wyodak, and Hayden coal-fueled Interim Period
10 547 Resources. Colstrip will also be included in the contractor-assisted engineering study of
548 decommissioning costs, and the Company will make best efforts to complete that portion of the
549 study by March 15, 2020. The Company will provide the information from the study to the States
550 as a supplemental filing in all applicable depreciation dockets. The study results will be used to
551 inform the Company's recommendation on the amount of Decommissioning Cost responsibility
552 to be allocated to States for coal-fueled Interim Period Resources that States exit at different times.
553 The Company will retain and make available the Decommissioning Studies in future regulatory
554 proceedings.
555 4.3.1.2. Decommissioning Studies Update
556 The Company intends to undertake the same process to complete an update to the
557 Decommissioning Studies by no later than June 30, 2024, to estimate appropriate
0558 Decommissioning Cost reserve requirements for the Craig, Hunter,Huntington, and Wyodak coal-
26

Rocky Mountain Power
Exhibit No. 1 Page 30 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
0559 fueled Interim Period Resources (collectively with the studies discussed in the paragraph above
560 constitutingthe Decommissioning Studies which will be incorporated into a Company-sponsored
g ), rp
561 depreciation study. The Company will retain and make available the Decommissioning Studies
562 update in future regulatory proceedings.
563 4.3.1.3. Commission Determination of Decommissioning Costs
564 No Party will be bound by the Decommissioning Cost estimates in the Decommissioning
565 Studies undertaken pursuant to Paragraphs 4.3.1.1 and 4.3.1.2, and final determination of each
566 State's just and reasonable Decommissioning Cost allocation for each coal-fueled Interim Period
567 Resource will remain exclusively with each Commission and will be determined in the
568 depreciation dockets in which the Decommissioning Costs are included.''
569 4.3.1.4. Decommissioning Costs Allocation
570 For coal-fueled Interim Period Resources having a common operating life across all States,
0571 each State shall be allocated its share of actual Decommissioning Costs based on either- an SG
572 Factor(if closed during the Interim Period)or an Assigned Production ("AP")Factor, adjusted for
573 any Reassignment or Limited Realignment effects (if closed after the Interim Period). For coal-
574 fueled Interim Period Resources that do not have a common operating life across all States, each
575 Exiting State shall be allocated, using either an SG Factor(if closed during the Interim Period)or
576 an AP Factor, adjusted for any Reassignment or Limited Realignment effects (if closed after the
577 Interim Period), that State's share of estimated Decommissioning Costs based on the
578 Decommissioning Studies described in Sections 4.3.1.1 and 4.3.1.2. If the Decommissioning
579 Costs ordered to be included in the reserve balance established for an Exiting State are less than
580 the estimated Decommissioning Costs allocated to that Exiting State as specified above, such
• For California.Decommissioning Costs will be addressed in PacifrCorp's next general rate case.
27

Rocky Mountain Power
Exhibit No. 1 Page 31 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
10581 difference sliall not be allocated to any other State under any circumstance. If PacifiCorp
582 effectuates Closure of a coal-fueled lntenm Period Resource after one or more States have exited
583 from the Resource, the Company may, with the burden of proof and subject to PacifiCorp
584 supporting its proposal in testimony,13 propose to allocate to and collect from each State that is
585 participating in that Resource at the time of Closure that State's share,based on either an SG Factor
586 (if closed during the Interim Period) or an AP Factor, adjusted for any Reassignment or Limited
587 Realignment effects(if closed after the Interim Period), of actual Decommissioning Costs less the
588 regulatory liabilities for Exiting States including interest as described in Section 4.3.2 and less any
589 difference between the reserve balance established for each Exiting State and the estimated costs
590 allocated to each Exiting State as described above. Parties in such State(s) may take any position
591 regarding a Company request to recover Decommissioning Costs.
10592 4.3.2. Accounting for Decommissioning Costs Reserve Balances when All
593 States Do Not Exit a Unit
594 After an Exit Date by some but not all States, the estimated Decommissioning Costs
595 reserves allocated to the Exiting State(s) associated with a coal-fueled Interim Period Resource
596 utlit, from which that State is exiting,will be accounted for as a regulatory liability that is excluded
597 from rate base. Interest will be accrued on that regulatory liability at the Company's then-
598 authorized weighted average cost of capital" for each State that continues to participate in that
599 coal-fueled Interim Period Resource after an Exit Date until the decommissioning work on that
600 unit is completed.
i3 PacifiCorp's testimony will identify and explain the variances between estimated and actual Decommissioning
Costs.
Not to exceed the mammum carrying charge allowed by applicable law or Commission Order.
28

Rocky Mountain Power
Exhibit No. 1 Page 32 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
601 4.3.3. Accounting for Interim and Final Retirements
1*602 Before any State exits a coal-fueled Interim Period Resource, but no later than December
603 31, 2021,the Company shall propose to the Parties a process for separately accounting for removal
604 costs associated with interim retirements and final Decommissioning Costs in its accounting
605 system. Each State may determine the regulatory treatment for such removal costs in appropriate
606 proceedings.
607 4.3.4. Individual State Review, Process
box Any Party, at its discretion and cost, may pursue actions it deems necessary or appropriate
609 to review and evaluate the Decommissioning Studies or Decommissioning Costs and may take any
610 positions based on its review and findings. If a Commission issues an order identifying an
611 independent evaluator for the Decommission Studies, and the Commission Order provides for the
612 deferral and later recovery in rates of the cost of the independent evaluator, the Company agrees
0613 to initially pay for this independent evaluation.
614 4.4. Qualifying Facilities
615 The allocation of QF PPAs shall be treated in accordance with Sections 4.4.1 and 4.4.2 of
616 this 2020 Protocol, superseding Section (IV)(A)(3) of the 2017 Protocol. For Washington, QF
617 PPAs will be assigned and allocated consistent with the terms of Appendix F during the Interim
618 Period. Other than addressing the allocation of the costs and assignment of benefits of QF PPAs
619 among the States, this 2020 Protocol does not restrict or affect any Commission's jurisdiction over
620 any agreement or interaction between QFs and the Company. QF PPAs shall be treated in the
621 following manner for allocation and assignment purposes.
29

Rocky Mountain Power
Exhibit No.1 Page 33 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
•622 4.4.1. Existing QF PPAs
623 QF PPAs fully executed15 or as to which a legally enforceable obligation exists16 on or
624 before December 31, 2019 ("Existing QF PPAs") will remain system assigned and allocated,
625 subject to any Limited Realignment in Section 6.4, until the end of 2029, after which time they
626 will be situs assigned and allocated to the State having jurisdiction over the QF PPA for avoided
627 cost pricing("State of Origin").
628 4.4.1.1. NN'yoming QFAdjustnrent
629 The Company agrees to include: (1)a$5 million adjustment,annually,to reduce Net Power
630 Costs in Wyoming customer rates" beginning January 1, 2021, until December 31, 2022; and (2)
631 a$7.175 million adjustment, annually,to reduce Net Power Costs in Wyoming customer rates from
632 January 1, 2023, until December 31, 2029.1s This adjustment will terminate on or before
633 December 31, 2029, or upon issuance of any order by the Wyoming Commission that changes
0634 Wyoming's treatment of the Implemented Issues or the Resolved Issues from the terms of the 2020
635 Protocol. The adjustment shall be made solely at the Company's expense and not allocated to any
636 other States.
637 4.4.2. New QF PPAs
638 QF PPAs fully executed or as to which a legally enforceable obligation exists after
639 December 31, 2019, ("New QF PPAs") will be situs assigned and allocated for ratemaking
640 proceedings pertaining to periods beginning on or after January 1, 2020, to the State of Origin.
15 Fully executed means executed and delivered by each party to the other party.
16 Any such legally enforceable obligation date must be confirmed by an order from the applicable Commission
issued prior to the end of the Interim Period.
"The Wyoming QF adjustment will be included in the base ECAM costs forecasted in a general rate case with rates
effectivc on or after January 1. 2021. The Wyoming QF adjustment will be trued up in the ECAM at 100%(sharing-
bands do not apply).
to The Wyoming QF adjustment shall be removed from base ECAM costs on December 31.2029,or as otherwise
. specified in Section 4.4.1.1.so that no adjustment flows through to customers in rates after that date unless it was
deferred in the ECAM prior to December 31,2029.
30

Rocky Mountain Power
Exhibit No. 1 Page 34 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
4.4.2.1. Interim Period Treatment - Pre-Nodal Pricing Model
• 642 For the Interim Period, the ener�g out Llt of New F PPAs will bed dynamically allocated
�) P Q Y Y
643 per this agreement using the SG Factor, priced at a forecasted reasonable energy price defined
644 below, and any cost of a New QF PPA above the forecasted reasonable energy price will be situs
645 assigned and allocated to the State of Origin. The forecasted reasonable energy price is a single
646 blended market price derived from the Company's Official Forward Price Curve("OFPC"), scaled
647 for hourly prices, that was used for setting QF pricing for the New QF PPA. The single blended
648 market price is calculated by applying the appropriate weighting to the hourly scaled prices from
649 the OFPC for each market hub. The weightings per market hub are identified in the table below.
650 The weighting will be applied by month and by heavy load hours ("HLH") and light load hours
651 ("LLIf). The forecasted reasonable energy price, used for allocation purposes, shall be
652 established at the time a QF PPA is fully executed.
• Market Hub Weighting by Month-HLH
Market Jan Feb Mar I Apr may I Jun Jul AugSep 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% 70.84% 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 Comers 1 64.72% 58.68% 35.94% 27.40% 16.15% 5.75% 4.12% 2.17% 3.82% 45.79% 52.88% 44.470%
Mead 0.18% 0.13% 1.23% 1.46% 1.52% 1.74% 1.95%1 3.30%1 6.64%1 0.33%1 0.12%1 0.57%
Mona 9.16% 7.90%1 2.94%1 2.03%1 1.79%1 0.74% 0.01% 0.18% 1.82% 7.82% 7.46% 2.18%
NOB 0.00% 0.00% 1.75% 4.40% 5.72% 0.33% 3.70% 4.92% 1.41% 0.27% 0.00% 10.54%
Total 100.00°A 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 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% 5.17% 3.53% 15.501/6 15.16% 5.97% 1.21% 0.31% 2.43% 3.44% 1.16%
Mid Columbia 58.74% 60.1096 76.58% 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% 2.71% 3.04% 0.001A 0.92% 1.91% 2.30%
Four Comers 33.45% 34.66% 13.63% 26.49% 10.44% 3.30% 5.35% 2.39% 11.60% 27.69% 26.36% 29.65%
Mead 1 0.00%1 0.06%1 0.94%1 0.44% 0.93% 0.47% 0.25% 0.00% 0.00% 0.57%1 0.00% 0.00%
Mona 7.81% 3.07% 1.54% 2.41% 0.92% 0.271A 0.00% 1.11% 4.82%1 5.61%1 1.99% 7.80%
NOB 0.00% 0.00%1 1.71% 0.73% 0.00% 0.00% 0.20% 0.00% 0.00% 0.00% 0.00% 0.009A
Total 100.00% 100.00%1 100.00% 100.00% 10O.M1 100.00% loo.00%1 100.00% 100.00%1 100.0a%j 100.00% 100.
653 4.4.2.2. Post-Interim Period Treatment
654 After the conclusion of the Interim Period, assuming resolution and Commission approval
•655 of all Framework Issues, the Parties agree that New QF PPAs will be situs assigned and the costs
31

Rocky Mountain Power
Exhibit No. 1 Page 35 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R. Steward
9656 and benefits will be allocated and assigned per the methodology developed throu�1111 the 1'ralnework
657 process in Section 6.2.
658 5. Resolved Issues - Post-Interim Period Implementation
659 The Parties agree, conditioned upon reaching agreement on a Post-Interim Period Method
660 on the future allocation treatment described in this Section 5 for certain benefits, revenues, costs,
661 and investments. As stated in Section 2, these Resolved Issues of the 2020 Protocol are intended
602 to take effect with the implementation of the Post-Interim Period Method. Parties acknowledge
66, that conditions may change materially in unforeseen ways during the Interim Period and that it
664 may be necessary to re-evaluate Resolved Issues as part of the Post-Interim Period Method. The
665 Resolved Issues are identified below.
666 5.1. Generation Costs
�667 Following the Interim Period, a fixed share of the Interim Period Resources will be
608 assigned to serve load to each State. The costs and benefits, including environmental attributes,
669 associated with each Interim Period Resource will be allocated and assigned in accordance with
670 the Interim Period Resources fixed allocation provisions (Section 5.1.1), Reassignment of coal-
671 fueled Interim Period Resources (Section 4.2), and Limited Realignment(Section 6.4).
672 5.1.1. Interim Period Resources Fixed Allocation
673 Interim Period Resources will be assigned and allocated to States based on the SGF Factor
674 for each State as defined in Appendix C. The load information used to determine the SGF Factor
675 is subject to modification for the inclusion or exclusion of Special Contract loads as determined
676 through the Framework process for resolution of issues addressed in Section 6.3. The SGF Factor
677 is used to develop the AP Factor for each unit. Additionally, Interim Period Resources will be
678 subject to the Limited Realignment as outlined in Section 6.4 and the Reassignment of Interim
32

Rocky Mountain Power
Exhibit No. 1 Page 36 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
�679 Period Resources as outlined in Section 4.2. Any such Assignment of lnterlin Period Resources,
680 along with the Limited Realignment and the Reassignment of Interim Period Resources, will be
681 subject to the following:
682 • Accumulated depreciation for Interim Period Resources will be allocated per the
683 AP Factor. State-specific accumulated depreciation that has been tracked by the
684 Company due to increased depreciation expenses will be treated as situs to the State
685 and offset its Resource costs until that State exits from an Interim Period Resource.
686 • Accumulated deferred income taxes and excess deferred income taxes will be
687 allocated per the Company's tax software system, using the AP Factor. State-
688 specific accumulated deferred income taxes and excess deferred income taxes that
689 have been tracked by the Company due to increased depreciation expense will be
10610 treated as situs to the State and offset that State's Resource costs until that State
691 exits from an Interim Period Resource.
692 • All O&M expenses that are associated with a specific Interim Period Resource will
693 be allocated per the AP Factor.
694 • All generation-related O&M expenses that cannot be allocated to a specific Interim
695 Period Resource through an AP Factor, such as general office generation
696 management expenses, will be allocated to States based on an Assigned Production
697 Operations and Maintenance ("APOM") Factor, calculated as each States' relative
698 share of direct-allocated generation O&M expenses. There will be three separate
699 APOM factors based on FERC classifications, with the APOMS used for steam
700 generation (FERC accounts 500 - 514),APOMH used for hydro generation (FERC
0701 accounts 535-545) and APOMO used for other generation (FERC accounts 546 -
33

Rocky Mountain Power
Exhibit No. 1 Page 37 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
10702 554). The APOM factor calculations are shown in Appendix C and also included
703 in Appendix B, Column 5.
704 • Property tax will continue to be allocated based on gross plant using the GPS Factor
705 as calculated in Appendix C and included in Appendix B, Column 5.
706 • All other rate-base items associated with Interim Period Resources will be allocated
707 consistent with the Interim Period Resource allocations using the AP Factor.
log 5.1.2. New Resources Fixed Assignment
Toy New Resources include any Resources that are not in commercial operation before the end
710 of the Interim Period. All costs and benefits associated with new Resources, subject to the
711 qualification below, will be allocated and assigned to States based on a fixed assignment under the
712 process to be determined in Section 6.1 —Resource Planning and New Resource Assignment. The
0713 Parties agree that a transitional period is necessary to change the cost allocation for future new
'14 Resources that are planned for b the Company, and that an new Resource reaching commercial
P YY g
715 operation before the end of the Interim Period will be treated the same as Interim Period Resources
716 for allocation purposes under the terms of this Agreement.
717 5.2. Transmission Costs
718 The costs associated with transmission assets, except as addressed in Section 6.1, will be
719 dynamically allocated among States on the System Transmission ("ST") Factor, generally
720 calculated based on a classification of costs as 75 percent Demand-Related and 25 percent Energy-
721 Related, and based on twelve monthly Coincident Peaks,using weather-normalized retail peak and
,22 energy data, as more thoroughly defined in Appendix C.
723 All revenues recovered through PacifiCorp's Open Access Transmission Tariff or other
724 transmission rate schedules approved by the FERC will be allocated based on the ST Factor.
s
34

Rocky Mountain Power
Exhibit No 1 Page 38 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
•725 The 2020 Protocol does not preclude PacifiCorp from participating in any independent
726 transmission organization, regional transmission organization, or other similar wholesale
727 transmission market subject to the jurisdiction and oversight of the FERC.
728 5.3. Distribution Costs
729 All distribution-related expenses and capital costs that can be directly allocated will be
730 directly allocated to the States where the related distribution facilities are located. Those
731 distribution expenses that cannot be directly allocated will be allocated among States on a System
732 Net Plant Distribution("SNPD")factor, as shown in Appendix B.
733 5.4. System Overhead Costs
734 Costs that support more than one function, such as generation, transmission, or distribution
735 plant,will continue to be allocated on the System Overhead("SO")Factor after the Interim Period
10736 but will be calculated based on an equal one-third weighting of the System Capacity("SC")Factor,
737 System Energy Factor, and System Gross Plant Distribution "SGPU" Factor, as shown in
Y gY � Y �
738 Appendix B.
739 5.5. Administrative and General Costs
740 Administrative and General Costs, General Plant costs, and Intangible Plant costs, both
741 expenses and investments, which can be directly allocated will be directly allocated to the
742 appropriate State(s). Those costs that cannot be directly allocated will be allocated among States
743 consistent with the factors set forth in Appendix B.
744 5.6. Other Allocation Issues
745 Items included in the Company's results of operations, other than those that are specifically
746 called out herein, will continue to be allocated on the same factors used in the 2017 Protocol. The
i
35

Rocky Mountain Power
Exhibit No.1 Page 39 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
�747 FERC account and allocation factor combinations are included in Appendix B. The algebraic
7.18 derivation and factor definitions are included in Appendix C.
749 The following miscellaneous changes will be made to be consistent with the other
750 allocation changes:
751 • Communication equipment allocated on the System Generation Factor during the
752 Interim Period will change to either the SE Factor(generation-related)or ST Factor
753 (transmission-related) depending on the nature of the equipment for which the
754 communication equipment is utilized.
755 • Contributions In Aid of Construction ("CIAC") currently allocated on the SG
756 Factor will change to either the AP factor for generation-related CIAC or the ST
757 Factor for transmission related CIAC.
0758 • Generation-related dispatch costs and associated plant be allocated on the SE
759 Factor.
760 • Miscellaneous regulatory assets and liabilities, and miscellaneous deferred debits
761 will be allocated with the appropriate allocation factor depending on the related
762 assets or underlying costs. Miscellaneous regulatory assets and liabilities, and
763 miscellaneous deferred debits currently allocated on the SG Factor, will change to
764 the AP Factor for generation-related and ST Factor for transmission-related items.
765 Taxes and fees will be allocated as follows:
766 • Income taxes will be calculated using the federal tax rate and PacifiCorp's
767 combined State effective tax rate. State specific Schedule M and deferred income
768 tax amounts will be allocated using the Company's tax software system. Consistent
•
36

Rocky Mountain Power
Exhibit No.1 Page 40 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
10769 with prior system allocation methods, the Washington Public Utility Tax is
770 allocated using the SO Factor in lieu of a Washington inconie tax.
771 • Franchise taxes, revenue related taxes, Commission assessments and fees, and
772 usage related taxes are situs or a pass through.
773 • Property taxes are system allocated based on gross plant and allocated on the GPS
774 Factor.
775 • Generation and fuel related taxes will follow the assignment of the Resource.
776 • Other taxes such as payroll taxes are embedded in the cost of expense or capital.
777 Balances associated with the Trojan Decommissioning will be allocated using the Trojan
778 Decommissioning Fixed ("TROJDF") Factor. This will not affect State-specific treatment of this
779 item.
0780 5.7. Demand-Side Management Programs
781 Costs associated with DSM Programs, including Class 1 DS>t-'I Programs, will continue to
782 be allocated on a situs basis to the State in which the investment is made. The benefits from these
783 programs will flow back to the State through Net Power Costs or through reduced or delayed future
784 capacity needs that will be addressed in the development and implementation of the process
785 identified in Section 6.1.
786 5.8. State-Specific Initiatives
797 Costs and benefits resulting from a State-specific initiative will continue to be allocated
788 and assigned on a situs basis to the State adopting the initiative. Historically, these have included,
789 but are not limited to, programs such as incentive programs and customer and community energy
790 generation programs, but have not included local fees or taxes related to the ongoing operation of
0791 existing transmission and generation facilities within a State. As new issues arise, PacifiCorp will
37

Rocky Mountain Power
Exhibit No. 1 Page 41 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
�792 bring each issue to the MSP Workgroup to discuss whether each issue is a State-specific initiative,
793 and, if not, whether a different allocation method is appropriate.
794 6. Framework Issues
795 The Parties acknowledge that certain components of the Post-Interim Period Method are
796 not resolved by this Agreement, including Resource Planning and new Resource Assignment,Net
797 Power Costs/Nodal Pricing Model,the treatment of Special Contracts, post-Interim Period capital
798 additions,and other issues related to the transition from a dynamically-allocated system generation
799 portfolio to fixed generation portfolios. As part of the 2020 Protocol, the Parties agree to the
800 following processes and timeframes to address remaining, unresolved Framework Issues and to
801 request approval of a new Post-Interim Period Method agreement by the Commissions. The
802 Company will file for Commission consideration and approval of a new Post-Interim Period
•803 Method in accordance with Section 2. The general understanding reached by the Parties as to
804 process and timelines for Framework Issues is as follows.
805 6.1. Resource Planning and New Resource Assignment
806 Continued operation, planning, and dispatch of the Company's system as an integrated six-
807 State system, to the greatest extent practicable, will likely be beneficial to PacifiCorp's customers.
808 However, because of differing State policies requiring or excluding certain generation resources,
809 it appears infeasible to continue serving customers with a common generation portfolio and
810 dynamically allocating system costs. Continued dynamic allocation of all system costs in this
811 environment could result in increased costs for some States, if not all. Accordingly, allocating
812 costs and assigning benefits associated with generation capacity will require assignment of specific
813 Resources, and potentially certain transmission assets, to a specific State or States. The goal is to
38

Rocky Mountain Power
Exhibit No. 1 Page 42 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
91114 allow PacifiCorp to meet its legal requirements as a public utility in each State in a risk-adjusted,
sti least-cost manner, while striving to mitigate cost impacts to other States.
816 PacifiCorp will continue to plan for capacity and operating needs, both for the entire
817 interstate system and for each State. PacifiCorp will work with Parties to develop:
818 • A planning process that optimizes risk-adjusted, least-cost resource portfolios on a
819 system basis to the extent practicable, while meeting individual State requirements
820 and maintaining system reliability; and
821 • A process that assigns benefits and allocates costs of specific new Resources added
822 in order to meet an individual State's needs.
823 Parties will evaluate these processes in light of existing or new Commission regulatory
824 processes governing Resource planning, procurement, and investment approval.
825 6.2. Net Power Costs / Nodal Pricing Model ("NPM")
826 A method to track the costs and benefits of Resource portfolios which may differ for each
827 State will be necessary in the future to maintain the benefits of system dispatch as much as
828 practicable. Specifically, after the Interim Period when States may no longer participate in a
829 common Resource portfolio, a NPM may be used to track cost causation and receipt of benefits by
830 each State for rate-making purposes.
831 Consistent with and in consideration of the Nodal Pricing Model Memorandum of
832 Understanding in Appendix D, the Company agreed to begin the development of an NPM with a
833 third-party vendor and will use best efforts to implement the NPM by the end of January 2021,for
834 purposes of total-Company day-ahead scheduling. Parties intend for this to provide some time and
39

Rocky Mountain Power
Exhibit No. 1 Page 43 of 134 EXECUTION VERSION
Case No PAC-E-19-20
Witness: Joelle R. Steward
0135 experience with the NPM before it may be used for rate making as part of the Post-Interim Period
836 Method.19
837 The Company will also use best efforts to implement a model that can forecast NPC based
838 on the NPM concept. During the Interim Period, this model may be used by the Company for
839 forecast analysis of NPC. After the Interim Period, the Company intends to propose the use of this
840 model for NPC forecasts in applicable rate-making proceedings.
841 6.3. Special Contracts
842 The Company will continue to work in good faith with the Special Contract customers to
843 develop one or more proposals for consideration by the Parties on the treatment of Special
844 Contracts'loads, costs, and benefits as part of the Framework Issues and will make best efforts to
845 present a proposal to Parties by September 1, 2021, with the intention of incorporating such
•846 proposal into the Post-Interim Period Method.
847 6.4. Limited Realignment
848 The Parties agree to investigate during the Interim Period the potential Limited
849 Realignment of Interim Period Resources among the States. Limited Realignment is intended to
850 address, among other potential issues, the transition of Washington retail customers away from
851 coal-fueled Interim Period Resource in compliance with the Washington CETA by realigning
852 Interim Period Resources, including natural gas-fueled Interim Period Resources.
853 6.5. Post-Interim Period Capital Additions — Coal-Fueled Interim
854 Period Resources
855 For a coal-fueled Interim Period Resource for which one or more States have an Exit Date
856 that differs from the depreciable life or Exit Date ordered in any other State, a process is needed
. 19 NPM is intended to be used for total Company system dispatch when it is fully functional and operational and will
impact system Net Power Costs that flow through State NPC balancing accounts.
40

Rocky Mountain Power
Exhibit No. 1 Page 44 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
��% for determining the cost allocation for capital investments made in the Resources subsequent to
i�
sib the Interim Period and prior to the Exit Date for each State. The Parties have agreed to evaluate,
859 but have not accepted, the following Company straw proposal for post-Interim Period capital
860 investments, information about which is provided here not for Commission approval but to inform
861 future discussions.
862 6.5.1. PacifiCorp Straw Proposal - Post-Interim Period Capital Investment
863 Allocation Exceptions
864 For post-Interim Period incremental capital investments that are made primarily for the
865 purpose of extending the life of a coal-fueled Interim Period Resource beyond a State's Exit Date
866 for that Resource, including but not limited to those associated with achieving compliance with
867 environmental requirements or those necessitated by catastrophic failure, such investments would
868 not be allocated to States that have issued such Exit Orders and would be allocated based on the
•869 percentage shares of the coal unit Reassignment process addressed in Section 4.2 or as otherwise
870 determined for States that continue to participate in the coal-fueled Interim Period Resource.
871 For these incremental capital investments made primarily for the purpose of repairing a
872 coal-fueled Interim Period Resource following a catastrophic failure of the Interim Period
873 Resource, such investments would not be allocated to and no generation or benefits will be
874 assigned to States that have issued Exit Orders for that Resource. Parties in States not allocated
875 costs for such investments would support recovery of any remaining net book value and
876 Decommissioning Costs.
877 6.5.2. PacifiCorp Straw Proposal - Incremental Capital Investments Made
878 Between 2024 and the Exit Date Where Exit Date is On or Before
879 December 31,2027
880 For States with Exit Orders for a coal-fueled Interim Period Resource specifying an Exit
0 mi Date on or before December 31, 2027, capital investments made in such Interim Period Resource
41

Rocky Mountain Power
Exhibit No.1 Page 45 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
Ig 882 after the Interim Period and prior to the Exit Date, would be allocated to an Exiting State based on
883 the AP Factor, adjusted for any Limited Realignment impacts agreed to, and pro-rated for the
884 number of years remaining based on the longest life ordered in any State's depreciation docket or
885 rate case by December 31, 2020, for such Interim Period Resource. States without Exit Orders in
886 such Interim Period Resource would be allocated the remaining amount of capital investment
887 based on proportional shares of the AP factor for the States that will be participating in the coal-
888 fueled Interim Period Resource after an Exit Date. For example, if a State's Exit Order establishes
889 an Exit Date four years from the date the capital investment is in-service, and the Interim Period
890 Resource has the longest remaining life in another State of ten years, the State with the Exit Order
891 would be allocated four-tenths of that State's share of the cost of the qualifying capital investment.
892 F_,ach State's allocation of such capital investments would be subject to a prudence review based
49, on the cost to be allocated to each State consistent with this Section.
•894 6.5.3. PacifiCor Straw Proposal - Incremental Capital Investments Made
P P A
895 in 2024 and 2025 Where Exit Date is After 2027
896 For States with Exit Orders for a coal-fueled Interim Period Resource specifying an Exit
897 Date after 2027, capital investments made in such Interim Period Resource after the Interim Period
898 and through December 3) 1, 2025, would be allocated to all States based on the AP Factor, adjusted
899 for any Limited Realignment impacts agreed to, and prudence of such capital investments for
900 States with Exit Orders would be determined based on the life established for such Interim Period
901 Resource in the Exit Order. This would allow for the reasonable allocation of capital and operating
902 costs for the Interim Period Resource during a period of time while PacifiCorp pursues the process
903 established in Section 42.
•
42

Rocky Mountain Power
Exhibit No. 1 Page 46 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
904 6.5.4. PacifiCorp Straw Proposal -Incremental Capital Investments Made
905 Between 2026 and the Exit Date Where the Exit Date is After 2027
906 For States with Exit Orders for a coal-fueled Interim Period Resource specifying an Exit
907 Date after 2027, capital investments made in such Interim Period Resource after December 31,
908 2025, and until the Exit Date, would be allocated to an Exiting State based on the AP Factor,
909 adjusted for any Limited Realignment impacts agreed to, and pro-rated for the number of years
910 remaining based on the longest life ordered in any State's depreciation docket, Reassignment
911 proceeding, or rate case as of December 31, 2025. States that will be participating in the coal-
912 fueled Interim Period Resource after an Exit Date would be allocated the remaining amount of any
913 capital investment based on the AP Factor calculated for that coal-fueled Interim Period Resource.
914 7. Allocation of Gain or Loss from Sale of Assets
915 Any gain or loss from the sale of Company-owned assets will be allocated among or to
•916 States based upon the proportional allocation or assignment of the asset at the time of the execution
917 date of the sale agreement. Each Commission will determine the appropriate allocation of the gain
918 or loss allocated to that State as between PacifiCorp's customers and shareholders. For assets that
919 have been Reassigned for less than one calendar year as of the execution date of the sale agreement,
920 States will be allocated the gain or loss as if the asset had remained a System Resource.
921 8. Interpretation and Governance
922 8.1. Issues of Interpretation
923 Parties will attempt, consistent with their legal obligations, to resolve questions of
924 interpretation of the 2020 Protocol, in good faith in light of the language of the 2020 Protocol and
925 the intent of the Parties.
43

Rocky Mountain Power
Exhibit No. 1 Page 47 of 134 EXECUTION VERSION
Case No PAC-E-19-20
Witness: Joelle R. Steward
�926 8.2. Workgroups
927 8.2.1. Framework Issues Workgroup
928 PacifiCorp will schedule and convene meetings with Parties to continue negotiations of the
929 Framework Issues, which may occur in person or remotely.
930 8.2.2. Multi-State Process Workgroup
931 Consistent with Sections 8.4 or 8.5 of this Agreement,the Company will notify Parties and
932 other MSP participants if it determines a need exists to convene the MSP Workgroup to address
933 general allocation issues or complaints related to the 2020 Protocol. Any Party to this Agreement,
934 State utility regulatory agency, or other stakeholder can participate in the MSP Workgroup. The
935 MSP Workgroup may create sub-committees to investigate or evaluate or make recommendations
936 as to specified issues. MSP Workgroup meetings may be held in person or remotely.
937 8.3. Commissioner Forum
40938 The 2017 Protocol included a mandatory requirement to hold an annual Commissioner
939 Forum each January during the pendency of that agreement. Under this 2020 Protocol,
940 Commission Forums are not required. A Commission or the MSP Workgroup may request such a
941 meeting of Commissioners. If a Commissioner Forum is requested, all seated commissioners from
942 each State will be invited to participate. Commissioner Forums will be public meetings, and all
943 interested parties will be allowed to attend. Before attending a Commissioner Forum, each
944 Commission can take such steps and provide such process for public input as the Commission
945 determines is necessary or appropriate under applicable State laws.
946 8.4. Proposals to Change the 2020 Protocol during the Interim Period
947 The Parties agree not to propose or support changes to the 2020 Protocol applicable to the
948 Interim Period based on a Party's dissatisfaction with a reasonably foreseeable outcome from
0949 implementation of the 2020 Protocol. Before proposing an alternative or modification to the 2020
44

Rocky Mountain Power
Exhibit No. 1 Page 48 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
10 950 Protocol based primarily on changed or tinforeseen circumstances, each Party agrees to first make
951 the proposal to the Parties and attempt to good faith to resolve the concern before asking a
952 Commission to change the 2020 Protocol. The provisions of this Section 8.4 will apply to any
953 State agency only to the extent consistent with the State agency's statutory obligations.
954 Proposals for modifications to the 2020 Protocol may be submitted to the Company by any
955 Party. Proposals received by the Company shall be circulated in a timely manner to the other
956 Parties and the Company shall initiate discussions to attempt to address and resolve specific
957 concerns.
958 8.5. Replacement of the 2020 Protocol
959 If any stakeholder that is not a Party to this Agreement objects to the use of the 2020
960 Protocol after approval by the Commissions or proposes a new inter jurisdictional allocation
•961 procedure, PacifiCorp may convene the MSP Workgroup and hold discussions to attempt to
962 address and resolve the concerns at an MSP Work group meetin .
g p g�s)
963 8.6. Interdependency Among Commission Approvals
%4 The 2020 Protocol has been developed and negotiated by the Parties as an integrated,
965 interdependent whole. Support by any Party of the 2020 Protocol is expressly conditioned upon
966 approval without material alteration of the 2020 Protocol by all Commissions in the States that
967 PacifiCorp has sought approval.20 If any Commission disapproves, alters, or conditions approval
968 of the 2020 Protocol,Parties shall promptly meet and discuss the implications of that Commission's
969 action. PacifiCorp shall report to the Parties any Commission Order of another State concerning
970 the 2020 Protocol. Parties agree to recommend to each Commission that approval of the 2020
971 Protocol be conditioned on other Commissions approving the 2020 Protocol without change.
. 20 California has historically reviewed allocation methodologies in conjunction with a general rate case.
PacifiCorp's next regulatory-mandated general rate case will not be filed until 2021 at the earliest.
45

Rocky Mountain Power
Exhibit No 1 Page 49 of 134 'F�C.;r C111C'�O �r°li,R*toIN
Case No. PAC-E-19-20
Witness-Joelle R. Steward
9.3 9. Compliance witb esource Lars
974 PacifiCorp eLf 3C €.> _ltslf the. 2020 Protocol caoniplies with the tegtdrements of current
935 r )urc;e laws of all of fbe States and YM riot shift risk of oompliance among PacifiCorp°s States.
976 If a future clian a in. ILAv, court dmisi.on, or Commission deg-isiort results in the Company's
97.7 reasonable belief that Compliance with all applicable laws cannot b7: achieves., the Company Will
978 raise its concerns with the Parties and/or convene an MSP Workgnoup meeting to addremss the issue.
979 10. Signatures of Parties to the 2020 Protocol
98D This 2020 Protocol i;; cn€c;cd it)t<? bra- eacl€ Party an the date eutcrod below such Panv's
981 signature,
PACIFICORP
a ,,�•,, Y�Y•w^ ALLIANCE OF WFS tRN ENERGY
CONS1uERS�jj� �fpY'• -++ ..`,��...+.�r `...yam..
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i
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46

Rocky Mountain Power
Exhibit No. 1 Page 50 of 134
Case No. PAC-E-19-20 EXEC r.10K VEWSION
Witness:Joelle R. Steward
. 973 9. Compliance With Resource Laws
974 Pacifit)r? asses that the 2020 Protocol complies with the mquirvnneiats of current
975 reKiurce lams of all of the Sties and will not shift risk of compliance among,PacifiCorp°s Mates.
976 If a futwe change in lair, wW day.siori, or Commission decision results in the Compazlys
1;77 rewmable belief that compl arice writh all applicable laws cwnot be acs`tiev4 the CompRny-Ml
978 wise its conoems with the Parties an,1 oe convcme an MSPWork-Woup meefing to ad dross the issue.
Q79 10. Signatures of Parties to the 2020 Protocol
9N `ais 2020 Protocol is enter into by Inch Pam on the date entered below such Pa€y's
981 signature,
X.e CONS LA.I RS
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i
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Date: .gate:
46

Rocky Mountain Power
Exhibit No.1 Page 51 of 134EXECUTION VERSION
Case No.PAC-E-19-20
Vliitness:Joelle R.Steward
973 9. Compliance with Resource Laws
974 PaciftCorp asserts, that the 2020 Protocol complies with the requirements of current
975 resource laws of ail of the States and will not Shift risk of compliance among PacifiCorp's States.
976 If a fixture change in la-vv, court. &6sion, or C oratnission decision results in the C4)tr3.pHiryrs
977 reasonable belief that compliance v6th all applicable laws cannot he aebievc41,the Ompany will
978 raise its concemis with die Parties atid'or convene an MSP Workgpup rn.eeting to address the issue.
979 10. Signatures of Parties to the 2020 Protocol
910 This 2020 Protocol is entered into by each Party on the date entered below such Party's
951 signature,
........................................_........................__.......................
j PAC-'IPICfJ.RP ALLIANCE OF W STI"RNt ENERGY"
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46

Rocky Mountain Power
Exhibit No.1 Page 52 of 134
Case No. PAC-E-19-20
Witness,Joelle R. Steward FIXECUMON V EWSIO'N
<,.3 9. Compliance with Resource Laws
9774 PacifiC atp asses that type 2020 i'3raw—ol complies with the regwrrmaits of c•li7Tent
(,r 5 resoame laves of a=1 of the State-,, and will not shift.rill,of comp iancc.aunong PacifiC:orp's Stage:
970 if a futwv c:•hunp in law, court de6sion, or Commission dmi`ion results in the C:'oalpai3d`s
977! reasionable belief that conipliance ;vith all applicable laws cannot be achieved.., the Company zv Il
978 raise its conccros w3ith the.Part.t iind!Or CI)T;a•cne sin MSS Work goup minting to address the i$8'M.
10
i ; -es € f 11ar es to the 202 rococo
,I,10 11is 2020 Pwstocof is cnun'W into by etch Pwly on the Mate entered fac;low such 11w-tys
981 signature.
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Title° Stiatc i"iustnes i'latu�ln;» 7i#Ie:
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Date: titan r 22,20 9................. Date: _. .
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46

Rocky Mountain Power
Exhibit No. 1 Page 53 of 134
Case No.PAC-E-19-20
Witness:Joelle R.Stewan:EXECUTFION VERSION
............................
IDAHO IRRIGATION PUMPERS INTERNVEST ENERGY ALLIANCE
ASSOCIM'
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POWER PR.ODtJCER,S
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STA F I
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Date: Date:
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47

Rocky Mountain Power
Exhibit No. 1 Page 54 of 134
Case No. PAC-E-19-20
Witness:Joelle R.StewarEXECUTION VERSION
• IDAHO IRRIGATION PUMPERS INTERWES RGY ALLIANCE
ASSOCIATION
y•
fIw
B By: CICLC)f fil ti,
Title: Title:
o r o :c �
Date: Date: /i _ /
MONSANTO COMPANY NORTHWEST& INTERMOUNTAIN
POWER PRODUCERS
By: By:
Title: Title:
Date:. Date:
NORTHWEST ENERGY COALITION
• By: By:
Title: Title:
Date: Date:
OREGON CITIZENS'UTILITY BOARD OREGON PUBLIC UTILITY COMMISSION
STAFF
By: By:
Title: Title:
Date: Date:
• 47

Rocky Mountain Power
Exhibit No.1 Page 55 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
• IDAHO IRRIGATION PUMPERS INTERWEST ENERGY ALLIANCE
ASSOCIATION
Bv: By:
Title: Title:
Date: Date:
MONSANTO COMPANY NORTHWEST& INTERMOUNTAIN
POWER PRODUCERS
y.
Title: Attorney for Monsanto Title:
Date: 11/26/2019 Date:
NORTHWEST ENERGY COALITION
By: By:
Title: Title:
Date: Date:
OREGON CITIZENS' UTILITY BOARD OREGON PUBLIC UTILITY COMMISSION
STAFF
By: By:
Title: Title:
Date: Date
47

Rocky Mountain Power
Exhibit No.1 Page 56 of 134 H'XECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R. Steward
..........................................................................................
€:D: iC)litRICiATiL� T PUMPERS :I:NTERWEST ENERGY ALLIANCE
• i ASSOCIg110
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47

Rocky Mountain Power
Exhibit No.1 Page 57 of 134
Case No.PAC-E-19-20 EXECUTION VERSION
Witness:Joelle R.Steward
._ . ..... .........................................................
PUMPERS IRRIGATIOPUMPERS INTLRNVEST ENERGY ALLIANCE
.ASSOCIATION
€ By: By,
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47

Rocky Mountain Power
Exhibit No.1 Page 58 of 134
Case No.PAC-E-19-20
Witness:Joelle R.Steward 1,�1XFXJTION VERSION
11ACIVICORP IDA.110 IND1.1STRIAL P,.-NCKAGING CORPOR.XHON OF
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........... ----—---

Rocky Mount "TION VERSION
Exhibit No.1 Page 59 of 134
Case No.PAC-E-19-20
Witness:Joelle R.Steward
PACIFICORP IDAHO INDUSTRIAL PACKAGING CORPORATION OF
CUSTOMERS AMERICA
By: By:
Title: Title:
Date: Date:
POWDER RIVER BASIN RESOURCE RENEWABLE NORTHWEST
COUNCIL
By: By:
Title: Staff Attorney Title:
Date: November 26, 2019 Date:
SIERRA CLUB UTAH ASSOCIATION OF ENERGY USERS
•
By: By:
Title: Title:
Date: Date:
UTAH CLEAN ENERGY UTAH DIVISION OF PUBLIC UTILITIES
By: By:
Title: Title:
Date: Date:
•
48

Rocky Mountain Power
Exhibit No. 1 Page 60 of 134
Case No.PAC-E-19-20
1n/tness:Joelle R.Steward EXECUTION VERSION
F'AC: FCORI' AHC7 NDS PAC:kAGI':G C ORP ORA TI ON{JF
' lI . . ...ID. _ .. -I- . LTRIAL -. ---
CUSTOMERS ME'RIC'A �
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• 48

Rocky Mountain Power
Exhibit No.I Page 61 of 134
Case No.PAC-E-1 9-20 EXECI.-VION VE16.10N
Witness:Joelle R.Steward
FP,—ACAFI ORP IDAHO lNl.-XJS-l-R1Al- w PA- CKAGING CORPORAFION OF
CUISIT'Affillks AMERICA
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POWDER RIVER BASIN RESOURCE s RENEWNBLE NOKI'HWEST
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4a

Rocky Mountain Power
Exhibit No.1 Page 62 of 134
Case No.PAC-E-19-20
Witness:Joelle R. StewarEXECUTION VERSION
13ACIFICORP IDAHO INDUSTRIAL PACKAGING CORPORATION OF
CUSTOMERS AMERICA
By: By:
Title: Title:
Date: Date:
POWDER RIVER BASIN RESOURCE RENEWABLE NORTHWEST
COUNCIL
By: By:
Title: Title:
Date: Date:
SIERRA CLUB UTAH ASSOCIATION OF ENERGY USERS
By: ! By:
Title: Title:
Date: Date:
UTAH CLEAN ENERGY 1JTAI-1 DIVISION OF PUBLIC UTILITIES
By: By:
Title: Title: P414-20—
Date: Date: 4 ZS 1
48

Rocky Mountain Power
Exhibit No. 1 Page 63 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
VVdness:Joelle R. Steward
UTAH INDUSTRIAL ENERGY UTAH OFFICE OF CONSUMER SERVICES
CONSUMERS
By: By:
Title: Title:
Date: Date:
VOTE SOLAR WASHINGTON PUBLIC COUNSEL
By: By:
Title: Title:
Date: Date:
WASHINGTON UTILITIES & WESTERN RESOURCE ADVOCATES
TRANSPORTATION COMMISSION STAFF
By: By:
Title: Title:
Date: Date:
WOLVERINE FUELS WYOMING INDUSTRIAL ENERGY
CONSUMERS
By: By:
Title: Title:
Date: Date:
•
49

Rocky Mountain Power
Exhibit No.1 Page 64 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
• UTAH INDUSTRIAL ENERGY UTAH OFFICE OF CONSUMER SERVICES
CONSUMERS
By: By:
Title: Title:
Date: Date:
VOTE SOLAR WASHINGTON PUBLIC COUNSEL
By: By:
Title: Title.
Date: Date:
WASHINGTON UTILITIES & WESTERN RESOURCE ADVOCATES
TRANSPORTATION COMMISSION STAFF
•
By: By: —
*4�7
Title: Title: Senior Staff Attorney
Date: Date: November 27, 2019
WOLVERINE FUELS WYOMING INDUSTRIAL ENERGY
CONSUMERS
By: B_v:
Title: Title:
Date: Date:
49

Rocky Mountain Power
Exhibit No.1 Page 65 of 134
Case No.PAC-E-19-20
Witness:Joelle R. Steward EXECUTION VERSION
• UTAH INDUSTRIAL ENERGY UTAH OFFICE OF CONSUMER SERVTC.ES
CONSUMERS
By: By:
Title: Title:
.Date: Date,
VOTE SOLAR WASRINGTON PUBLIC COUNSEL,
Ley: � By: — — .......
Title: Title:
Date: Date:
VJASHINGTUN UT11�T PIES VbTSTERN R-ESOURCE ADVOCATES
TRANSPORTATION COMMISSION STAFF
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Title: --- Title:
Date: Date:
I
................._.._
WOLVERINE FIJELS WYOMING INDIJSTRIAI-,ENERGY
CONSI.WERS
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"Title: Title:
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f
•
49

Rocky Mountain Power
Exhibit No.1 Page 66 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
UTAH INDUSTRIAL ENERGY UTAH OFFICE OF CONSUMER SERVICES
CONSUMERS
By: By:
Title: Title:
Date: Date:
VOTE SOLAR WASHINGTON PUBLIC COUNSEL
By: BY
Title: Title:
Date: Date:
WASHINGTON UTILITIES& WESTERN RESOURCE ADVOCATES
TRANSPORTATION COMMISSION STAFF
•
By: By:
Title: Title:
Date: Date:
WOLVERINE FUELS WYOMING INDUSTRIAL ENERGY
CONSUMERS
By: By: ✓ � ✓-`> �
Title: Title: Attorney for WIEC
Date: Date: November 25, 2019
•
49

Rocky Mountain Power
Exhibit No. 1 Page 67 of 134FX
� ECUTION VERSION
Case No PAC-E-1 9-20
Witness:Joelle R. Steward
WYOMJNIG OFFICE OF CONSUMER WYOMING PUBLIC SERVICE
ADVOCATE COMMISSION STAFF
By: By:
A,
"Q'm
'Title: ,4L Title: --2n
Date: s
Date:
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Title: Title:
Date- Date:
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Date: Date:
----------------------—----- .........
By: By.,
Title: Title:
Date: Date:
------------------------

Rocky Mountain Power
Exhibit No.1 Page 68 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
APPENDIX A
Definitions
1 For purposes of this Agreement, the following terms wi It have the following meanings:
2 • "2017 Protocol" refers to the 2017 PacifiCorp Inter-Jurisdictional Allocation Protocol.
3 • 112020 Protocol" refers to the 2020 PacifiCorp Inter-Jurisdictional Allocation Protocol.
4 "Administrative and General Costs" means costs included in FERC accounts 920 through 935.
• "Assigned Production Factor"or"AP"means States'assigned share of a Resource(see Appendix
6 C for more details).
7 "Assigned Production - Operations and Maintenance Factor" or "APOM Factor" means the
8 State allocated share of all generation related operating and maintenance expenses that cannot be
9 associated with a specific Resource, such as general office generation management expenses, that
will be allocated to States calculated as each State's relative share of directly allocated generation
I operating and maintenance expenses for steam, hydro, and other generation functions (see Section
12 5.1.1 and .Appendix C for more details).
I, "Class 1 Demand-Side Management" or "Class 1 DSM" means dispatchable or scheduled firm
1.4 DSM resources, sometimes referred to as direct load control programs.
I; • "Closure" means either PacifiCorp's termination of ownership interest in a Resource, permanent
16 cessation of operations of a Resource, permanent cessation of receipt of energy from a Resource, or
17 otherwise retirement of a Resource.
18 0 "Coincident Peak" means the hour each month that the combined demand of all PacifiCorp retail
19 customers is greatest, adjusted for normal weather conditions. The hour of coincident peak is
20 calculated assuming weather normalized retail load, and as it relates to generation allocation factors,
it includes adjustments for Class 1 DSM and Special Contract curtailments. In calculating the
2020 Protocol-Appendix A 1

Rocky Mountain Power
Exhibit No.1 Page 69 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
22 coincident peak for the System Transmission Factor, the only adjustment will be for weather
. normalization.
2.3 "Commission" means a utility regulatory commission in a State.
2- "Commissioner Forum" means the meeting of Commissioners from all States, the goal of which
26 is to provide an update from the MSP Workgroup. Such a forum is not required by the 2020 Protocol.
27 "Commission Order" means a formal determination issued by a State Commission consistent with
28 its authority as provided by a State's statutes or administrative rules.
29 "Company"means PacifiCorp.
30 "Contributions in Aid of Construction" or"CIAC" means contributions from customers to pay
.31 their share of a capital construction project above the amount their retail rates justify. CIAC is a
32 reduction to rate base, (see Appendix C for more detail).
33 "Customer Ancillary Services"means products or services that may be provided by a customer to
0 the Company, such as in which the Company has the right to curtail electric service to the customer
35 so as to lower the costs of operating the Company's system.
16 • "Customer Ancillary Service Contracts" means contracts between the Company and a retail
37 customer pursuant to which the Company pays the customer for Customer Ancillary Services
• "Decommissioning Costs" means the costs of removal and environmental remediation or
reclamation - net of any salvage value realized - required at the time a generation resource is
40 physically retired.
41 "Decommissioning Studies" means the engineering studies carried out in advance of planned coal-
42 fueled Interim Period Resource Reassignment filings in February of 2021 and June of 2024, in order
I: to identify the final Decommissioning Cost liabilities of Exiting States, as specifically identified in
44 Section 4.3.1.
16- • "Demand-Related" describes capital and other fixed costs incurred by the Company in order to be
46 prepared to meet the maximum demand imposed upon its system.
2020 Protocol-Appendix A 2

Rocky Mountain Power
Exhibit No.1 Page 70 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
4- "Demand-Side Management Programs" or "DSM Programs" means programs intended to
• reduce electricity use through activities or programs that promote electric energy efficiency or
49 conservation, more efficient management of electric energy loads, or reductions in peak demand.
50 "Embedded Cost Differential" or"ECD" means the sum of PacifiCocp's production costs of pre-
51 2005 resources as defined in the 2010 Protocol,excluding west side hydro,Mid-Columbia Contracts,
52 and Qualified Facility contracts, referred to as "all other generation resources" expressed in dollars
53 per megawatt-hour compared to west hydro-electric resources production costs expressed in dollars
54 per megawatt-hour with the difference multiplied by the hydro-electric resources megawatt-hours
55 of production, and the differential between the all other generation resources dollars per megawatt-
56 hour compared to Mid-Columbia Contracts costs dollars per megawatt-hour multiplied by the Mid-
57 Columbia Contracts megawatt-hours.
58 "Dynamic Embedded Cost Differential"or"Dynamic ECD"means the ECD components
are updated to the test period utilized in the filing.
60 0 "Fixed Embedded Cost Differential"or"Fixed ECD" means the ECD amount for a State
61 is set at a point of time and not updated.
62 • "Energy Imbalance Market" or "EIM" means the multi-Balancing Authority Area (BAA) real-
63 time market operated by the California Independent System Operator (CAISO) that balances
64 electricity supply and demand every five minutes by choosing the least-cost resource to serve system
65 load.
66 • "Energy-Related" means variable costs incurred by the Company in order to deliver the energy
67 required to serve customers.
68 • "Existing QF PPAs" is defined in Section 4.4.l of the agreement.
69
1
2020 Protocol-Appendix A 3

Rocky Mountain Power
Exhibit No. 1 Page 71 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
-() • "Exit Date" means the date, established in an Exit Order entered by a Commission, on which
is
PacifiCorp intends to discontinue the allocation of costs and assignment of benefits of a coal-fueled
72 Interim Period Resource to the State issuing the Exit Order.
73 • "Exiting State" means a State with a final order from a State Commission approving the exit from
74 a coal-fueled Interim Period Resource on a date certain.
75 • "Exit Order" means an order entered by a Commission establishing an Exit Date consistent with
76 the 2020 Protocol.
77 "Extended Day-Ahead Market" or "EDAM" means a market currently still in development that
7s will address ramping needs between intervals and uncertainty that can occur between the day-ahead
79 and real-time markets.
80 • "FERC" means the Federal Energy Regulatory Commission.
81 • "Five States" means the States of California, Idaho, Oregon, Utah, and Wyoming.
0 "Fixed Costs" means costs incurred by the Company that do not vary with the arnount of energy
8.1 delivered by the Company to its customers during any hour.
84 "Frames ork" is defined in Section 1 of the Agreement.
85 "Framework Issue" is defined in Section 1 of the Agreement.
86 "General Plant" means capital investment included in FERC accounts 389 through 399.
87 "Implemented Issues" is defined in Section 1 of the Agreement.
88 "Intangible Plant" means capital investment included in FERC accounts 301 through 303.
89 "Interim Period" is defined in Section 2 of the Agreement.
90 "Interim Period Resource" means Resource in commercial operation, or with a contract delivery
91 date, as applicable, during the Interim Period.
92 "Limited Realignment" means the assignment of Interim Period Resources among PacifiCorl)
States that differ from assignment using the SGF Factor.
2020 Protocol-Appcndix A 4

Rocky Mountain Power
Exhibit No. 1 Page 72 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R. Steward
94 "Load-Based Dynamic Allocation Factor" means an allocation factor that is calculated using
0 States'monthly energy usage and/or States' contribution to monthly system Coincident Peak.
90 "Mid-Columbia Contracts" means the various power sales agreements between PacifiCorp and
97 Public Utility District No. 2 of Grant County,PacifiCorp and Douglas County Public Utility District,
98 and PacifiCorp and Chelan County Public Utility District, specifically: the Power Sales Contract
99 with Public Utility District No. 2 of Grant County dated May 22, 1956; the Power Sales Contract
100 with Public Utility District No. 2 of Grant County dated June 22, 1959; the Priest Rapids Project
101 Product Sales Contract with Public Utility District No. 2 of Grant County dated December 31, 2001;
102 the Additional Products Sales Agreement with Public Utility District No. 2 of Grant County dated
103 December 31, 2001; the Priest Rapids Project Reasonable Portion Power Sales Contract with Public
104 Utility District No. 2 of Grant County dated December 31, 2001; the Power Sales Contract with
105 Douglas County Public Utility District dated September 18, 1963; the Power Sales Contract with
0 Chelan County Public Utility District dated November 14, 1957, and all successor contracts thereto.
107 "MSP Workgroup" means a group of re`ulators, the Company, and other interested stakeholders
IN that convenes to discuss the assignment or allocation of PacifiCorp revenues, costs, and investments
109 among the States.
1 10 • "Multi-State Process" or"MSP" means the ongoing Company-led convening of Parties from all
111 six States in which it operates to consider issues related to fair cost allocations among the States.
111 • "Net Power Costs" or "NPC" means PacifiCorp's fuel and wheeling expenses and costs and
113 revenues associated with long-term Wholesale Contracts, Short-Term Purchases and Sales and Non-
114 Firm Purchases and Sales.
115 "New QF PPA" is defined in Section 4.4.2 of the Agreement.
116 • "'Nodal Pricing Model" or "NPM" means a method for pricing electricity proposed by the
Company that is based on the marginal cost ($/MWh) of serving the next increment of demand at a
2020 Protocol-Appendix A 5

Rocky Mountain Power
Exhibit No. 1 Page 73 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
VVitness:Joelle R.Steward
t 18 given pricing node consistent with existing transmission constraints and the performance
• characteristics of resources.
120 • "Nodal Pricing Model Memorandum of Understanding" or"NPM MOU"means the agreement
121 among the Parties on the prudence of the Company's proceeding to implement the Nodal Pricing
122 Model that may be adopted for the calculation of net power costs (NPC) through a new inter-
123 jurisdictional cost-allocation methodology.
1-4 • "Non-Firm Purchases and Sales"means transactions at wholesale that are not Wholesale Contracts
125 or Short-Term Purchases and Sales.
126 • "Open Access Transmission Tariff' means PacifiCorp's Open Access Transmission Tariff on file
127 with FERC.
128 "Operations and Maintenance" or"O&M"means costs incurred by the Company to maintain its
129 assets that are expensed as defined by FERC.
is • "Oregon Direct Access Consumer" means Oregon retail electricity consumers that procure
131 electricity from a supplier other than PacifiCorp under an Oregon Direct Access Program.
132 • "Oregon Direct Access Program" means Oregon laws, regulations, and orders that permit
133 PacifiCorp's Oregon retail consumers to purchase electricity directly from a supplier other than
134 PacifiCorp.
135 • "Party" or "Parties" means certain State Commission staff members, regulatory agencies,
136 customers, consumer advocates, conservation organizations, and other interested parties from
137 California, Idaho, Oregon, Utah, Washington, and Wyoming who have executed this Agreement.
138 • "Portfolio Standard"means a law or regulation that requires PacifiCorp to acquire: (a)a particular
139 type of Resource, (b)a particular quantity of Resources, (c)Resources in a prescribed manner or(d)
140 Resources located in a particular geographic area.
•
2020 Protocol-Appendix A 6

Rocky Mountain Power
Exhibit No.1 Page 74 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
141 • "Post-Interim Period Method" means the resolution of the Framework Issues combined with the
0 Implemented Issues and the Resolved Issues are all intended to result in the new allocation
143 methodology for PacifiCorp's six States.
114 • "Post-Interim Period Resources" means Resources that begin commercial operation, or with a
145 contract or delivery date, as applicable, after the end of the Interim Period.
146 • "Qualifying Facility" or"QF"means small power production or cogeneration facilities developed
147 under the Public Utility Regulatory Policies Act of 1978 (PURPA) and related State laws and
148 regulations.
149 • "Qualifying Facility Power Purchase.Agreement" or"QF PPA" means contracts to purchase the
150 output of a Qualifying Facility by the Company.
151 "Reassignment", "Reassign", or "Reassigned" means assigning benefits from an Exiting State's
152 share of a coal-fueled Interim Period Resource to those States with Commission orders to accept the
0 cost responsibility allocation for the Exiting State's portion of the coal-fueled Resource.
1;4 "Resolved Issues"is defined in Section 1 of the Agreement.
155 "Resource"means a Company-owned generating unit, plant, mine, long-term Wholesale Contract,
156 Short-Term Purchase and Sale, Non-firm Purchase and Sale, or QF contract.
157 "Short-Term Firm Purchases and Firm Sales" means physical or financial contracts pursuant to
158 which PacifiCorp purchases, sells, or exchanges firm power at wholesale and Customer Ancillary
159 Service Contracts that are less than one year in duration.
160 "Short-Term Purchases and Sales" means physical or financial contracts pursuant to which
161 PacifiCorp purchases, sells, or exchanges firm power at wholesale and Customer Ancillary Service
162 Contracts that are less than one year in duration.
163 "Special Contract"means a contract entered into between PacifiCorp and one of its retail customers
with prices, terms, and conditions different from otherwise-applicable tariff rates. Special Contracts
2020 Protocol-Appendix A 7

Rocky Mountain Power
Exhibit No.1 Page 75 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
165 may provide for a value consideration to the customer to reflect attributes of Customer Ancillary
40 Service Contracts.
167 • "State" means California, Oregon, Idaho, Utah, Washington, or Wyoming.
168 • "State Resources" means Interim Period Resources whose costs are assigned to a single
169 jurisdiction to accommodate jurisdiction-specific policy preferences.
170 • "System Energy Factor" or"SE Factor" is defined in Appendix C.
171 • "System Generation-Fixed Factor" or"SGF Factor" is defined in Appendix C.
172 • "System Gross Plant Distribution Factor" or"SGPD Factor"is defined in Appendix C.
173 • "System Net Plant-Distribution Factor" or"SNPD Factor"is defined in Appendix C.
174 • "System Overhead Factor" or"SO Factor" is defined in Appendix C.
175 • "System Resources"means Interim Period Resources that are not State Resources and whose
176 associated costs and revenues are allocated among all States on a dynamic basis.
• "System Transmission Factor" or"ST Factor" is defined in Appendix C.
178 • "Trojan Decommissioning"means costs associated with decommissioning the Trojan Plant.
179 • "Trojan Decommissioning Fixed Factor" or("TROJDF") is defined in Appendix C.
180 • "Trojan Plant" means the now-decommissioned nuclear plant for which the Company is still
IINII recovering costs.
1`20 "Variable Costs" means costs incurred by the Company that vary with the amount of energy
183 delivered by the Company to its customers during any hour.
I�4 • "Washington Public Utility Tax" means a Washington tax on public service businesses, including
185 businesses that engage in transportation,communications,and the supply of energy, natural gas, and
186 water. The tax is in lieu of the business and occupation (B&O)tax.
187 "West Control .area Inter jurisdictional Allocation Methodology" or "WCA" means the
6 allocation protocol methodology used by Washington to allocate costs consistent with its Balancing
189 Area Authority-based principles governing the assets deemed to serve Washington.
2020 Protocol-Appendix A 8

Rocky Mountain Power
Exhibit No.1 Page 76 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
190 "Wholesale Contracts" means physical or financial contracts pursuant to which PacifiCorp
purchases, sells, or exchanges firm power at wholesale and Customer Ancillary Service Contracts.
2020 Protocol -Appcndix A 9

Rocky Mountain Power
Exhibit No. 1 Page 77 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
APPENDIX B
Allocation Factors by Account by Revenue Requirement Components

Rocky Mountain Power
Exhibit No. 1 Page 78 of 134
Case No. PAC-E-19-20
Witness:Joelle R. Steward
2020 Protocol -Appendix B
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
FERC ACC T 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
Non-Firm SE AP,NP
Firm SG AP,NP
449 Provision for Rate Refund
Direct assigned-Jurisdiction S S
• Transmission SG ST
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 Wale(Sales
Retail Revenues Direct assigned-Jurisdiction SG AP
454 Rend of Electric Properly
Retail Revenues Direct assigned-Jurisdiction S S
Common SG ST
Other-Common so So
456 Other Electric Revenue
Retail Revenues Direct assigned-Jurisdiction S S
Wheeling Non-firm,Other SE ST
Common so SO
Wheeling-Firm,Other SG ST
Customer Related CN CN
•
2020 Protocol-Appendix B

Rocky Mountain Power
Exhibd No 1 Page 79 of 134
Case No. PAC-E-19-20
Witness Joelle R Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
• INTERIM PERIOD POST INTERIM PERIOD
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
Miscellaneous Revenues
41 l6o Gain on Sale of Utility Plant-CR
Distribution S
Production SG All
Transmission 5 61
General Office Sv SO
41170 Loss on Sale of Utility Plant
Distribution S S
Production SG AP
Transmission SG ST
General Office so So
4118 Gain from Emission Allowances
S02 Emission Allowance sales SE AP
41181 Gam from Disposition of NOX Credits
NOX Emission Allowance sales SE AP
421 (Gain)f Loss on Sale of Utility Plant
Distribution S S
Production SG AP
Transmission SG ST
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
Steam Plants O&M SG AP APOMS
501 Fuel Related
Steam plants Fuel SE AP,APOMS
503 Steam From Other Sources
Steam Royalties SE AP,APOMS
Nuclear Power Generation
517-532 Nuclear Power O&M
Nuclear Plants O&M SG AP
Hydraulic Power Generation
5"5 545 Hydro O&M
Pacfic Hydro O&M SG AP,APOMH
East Hydro O&M SG AP,APOMH
Other Power Generation
• 545,148.554 Operation Super&Engineering
Other Production Plant SG AP,APOMO
547 Fuel
Other Fuel Expense SE AP,APOMO
2020 Protocol-Appcndix B Z

Rocky Mountain Power
Exhibit No. 1 Page 80 of 134
Case No. PAC-E-19-20
Vlfrtness Joelle R Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
• INTERIM PERIOD POST INTERIM PERIOD
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
Other Power Supply
Purchased Power
Tracking Mechanisms S S
Firm SG AP,NP
Non-firm SE AP.NP
555 System Control&Load Dispatch
Other Expenses SG SE
557 Other Expenses
Direct assigned-Jurisdiction S S
Other Expenses SE SE
Other Expenses SG APOMS,APOMM.APOMO
Cholla Transaction SGCT AP
TRANSMISSION EXPENSE
560 564 555 573 Transmission O&M
Transmission Plant O&M SG ST
565 Transmission of Electricity by Others
Firth Wheeling SG ST
Non-Firm Wheeling SE ST
GRID Management Charge SG SE
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 AP
FERC Regulatory Expense SG ST
• General SO SO
2020 Protocol -Appendix B 3

Rocky Mountain Power
Exhibit No. 1 Page 81 of 134
Case No, PAC-E-19-20
Witness'Joelle R Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
• INTERIM PERIOD POST INTERIM PERIOD
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
DEPRECIATION EXPENSE
403GP Steam Depreciation
Steam Plant, SG AP
403NP Nuclear Depreciation
Nuclear Plant SG AP
403HP Hydro Depredation
Pacific Hydro SG i•P
East Hydro SG AP
4030P Other Production Depreciation
Other Production Plant SG AP
403TP Transmission Depreciation
Transmission Plant SG ST
Distribution Depreciation Direct assigned-Jurisdiction
Land&Land Rights S S
Structures S S
Station Equipment S S
Storage Battery Equipment S S
Poles 6 Towers S S
OH Conductors S S
UG Conduct 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
Distribution S S
Steam Plants SG AP
Mining SE AP
Pacific Hydro SG AP
East Hydro SG AP
Transmission SG ST
Customer Related CN CN
General SO SO
n i;r,ll' Mining Depreciation
Mining Plant SE AP
�Il�u Ploto'.ul - Appcndu R q

Rocky Mountain Power
Exhibit No. 1 Page 82 of 134
Case No. PAC-E-19-20
Witness:Joelle R Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
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 AP
4041P Amort of LT Plant-Intangible Plant
Distribution S S
Production SG AP
Transmission SG ST
General SO SO
Mining Plant SE AP
Customer Related CN CN
404MP Amort of LT Plant-Mining Plant
Mining Plant SE AP
404HP Amortization of Other Electric Plant
Pacific Hydro SG AP
East Hydro SG AP
405 Amortization of Other Electric Plant
Direct assigned-Jurisdiction S S
406 Amortization of Plant Acquisition Adj
Direct assigned-Jurisdiction S S
Production Plant SG AP
407 Amort of Prop Losses,Unrec Plant,etc.
Direct assigned-Jurisdiction S S
Production, SG AP
Transmission SG ST
Taxes Other Than Income
408 Taxes Other Than Income
Direct assigned-Jurisdiction S S
Properly GPS GPS
System Taxes SO s0
Misc Energy SE AP
Misc Production SG AP
DEFERRED ITC
41 140 Deferred Investment Tax Credit-Fed
ITC DGU DGUF
41141 Deferred Investment Tax Credit-Idaho
ITC DGU DGUF
•
2020 Protocol-Appendix B 5

Rocky Mountain Power
Exhibit No. 1 Page 83 of 134
Case No. PAC-E-19-20
Vlliness Joelle R. Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
• INTERIM PERIOD POST INTERIM PERIOD
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
Interest Expense
427 Interest on Long-Term Debt
Direct assigned-Jurisdiction S
Interest Expense SNP SNP
428 Amortization of Debt Disc&Exp
Interest Expense SNP SNP
429 Amortization of Premium on Debt
Interest Expense SNP SNI'
431 Other Interest Expense
Interest Expense SNP SNI'
432 AFUDC-Borrowed
AFUDC SNP SNP
Interest&Dividends
4 t 9 Interest&Dividends
Interest&Dividends SNP SNP
DEFERRED INCOME TAXES
4101G Deferred Income Tax-DR
Direct assigned-Jurisdiction S S
Non-Coal and Gas Production SG AP
• Coal and Gas Production SG AP
Transmission SG ST
Customer Related CN CN
General SO SO
Property Tax related GPS GPS
Miscellaneous SNP SNP
Trojan TROJID TROJDF
Distribution SNPD SNPD
Mining Plant SE AP
Bad Debt BADDEBT BADDEBT
Tax Depreciation TAXDEPR TAXDEPR
2020 Protocol -Appendix B 6

Rocky Mountain Power
Exhibit No. 1 Page 84 of 134
Case No. PAC-E-19-20
Witness: Joelle R Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
• INTERIM PERIOD POST INTERIM PERIOD
FERC ACCT ACCTNAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
41110 Deferred Income Tax-CH
Direct assigned-Jurisdiction S S
Non-Coal and Gas Production SG AP
Coal and Gas Production SG AP
Transmission SG ST
Customer Related CN CN
General So So
Property Tax related GPS GPS
Miscellaneous SNP SNP
Trojan TROJD TROJDF
Distribution SNPD SNPD
Mining Plant SE AP
Contributions in Aid of Construction CIAC CIAC
Production,Other SGCT AP
Book Depreciation SCHMDEXP SCHMDEXP
SCHEDULE-M ADDITIONS
SCh-MAIh Additions-Flow Through
Direct assigned-Jurisdiction S S
SCHMAP Additions-Permanent
Direct assigned-Jurisdiction S S
Mining related SE AP
General SO So
Non-Coal and Gas Production SG AP
Coal and Gas Production SG AP
Transmission SG ST
Depreciation SCHMDEXP SCHMDEXP
SCHMAT Additions-Temporary
Direct assigned-Jurisdiction S S
Bad Debt BADDEBT BADDEBT
Contributions in Aid of Construction CIAC CIAC
Miscellaneous SNP SNP
Trojan TROJD TROJDF
Non-Coal and Gas Production SG AP
Mining Plant SE AP
Coal and Gas Production SG AP
Transmission SG ST
Property Tax GPS GPS
General SO SO
Depreciation SCHMDEXP SCHMDEXP
Distribution SNPD SNPD
Production,Other SGCT AP
•
2020 Protocol -Appendix B 7

Rocky Mountain Power
Exhibit No. 1 Page 85 of 134
Case No. PAC-E-19-20
V\Mness Joelle R Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
• INTERIM PERIOD POST INTERIM PERIOD
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
SCHEDULE-M DEDUCTIONS
SCHMDF Deductions-Flow Through
Direct Assigned-Jurisdiction S S
Coal and Gas Production SG AP
Transmission SG ST
Non-Coal and Gas Production SG AP
SCHMOP Deductions-Permanent
Direct Assigned-Jurisdiction S S
Mining Related SE AP
Depreciation SCHMDEXP SCHMDEXP
Miscellaneous SNP SNP
General SO so
SCHMDT Deductions-Temporary
Direct Assigned-Junsdiclion S S
Bad Debt BADDEBT BADDEBT
Miscellaneous SNP SNP
Non-Coal and Gas Production SG AP
Mining related SE AP
Coal and Gas Production SG AP
Transmission SG ST
Property Tax GPS GPS
General so SO
Depreciation TAXDEPR TAXDEPR
• Distribution SNPD SNPD
Customer Related CN CN
State Income Taxes
40911 State Income Taxes
40911 Income Before Taxes CALCULATED CALCULATED
40911 Renewable Energy Tax Credit SG AP
40910 FIT True-up S S
40910 Renewable Energy/Production Tax Credit SG AP
40911 PacfiCorp Minerals Inc. SE AP
40911 Foreign Tax Credit SO SO
Steam Production Plant
310-316 Steam Plants
Steam Plants SG AP
Nuclear Production Plant
320-325 Nuclear Plant
Nuclear Plant SG AP
Hydraulic Plant
330-336 Hydro Plant
Pacific Hydro SG AP
East Hydro SG AP
i
2020 Protocol -Appendix B 8

Rocky Mountain Power
Exhibit No. 1 Page 86 of 134
Case No. PAC-E-19-20
Witness: Joelle R Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
Other Production Plant
340-346 Other Production Plant
Other Production Plant-Situs S
Other Production Plant SG All
TRANSMISSION PLANT
350-359 Transmission Plant
Transmission Plant ST
DISTRIBUTION PLANT
360373 Distribution Plant
Direct assigned-Jurisdiction S S
GENERALPLANT
3E9 398 General Plant
Distribution S S
Pacific Hydro SG AP
East Hydro SG AP
Production SG AP,SE
Transmission SG ST
Customer Related CN CN
General SO SO
Mining SE AP
399 Coal Mine
Mining Plant SE AP
1011346 General Gas Line Capital Leases
Capital Lease SG AP
1011390 General Capital Leases
Direct assigned-Jurisdiction S S
General SO SO
Generation SG AP
Transmission SG ST
INTANGIBLE PLANT
301 Organization
Direct assigned-Jurisdiction S S
302 Franchise 6 Consent
Direct assigned-Jurisdiction S S
Production SG AP
Transmission SG ST
303 Miscellaneous Intangible Plant
Distribution S S
Pacific Hydro SG AP
East Hydro SG AP
Production SG AP
Transmission SG ST
• Customer Related CN CN
General SO s0
Mining SE AP
Other SG SGF
2020 Protocol -Appendix B 9

Rocky Mountain Power
Exhibit No. 1 Page 87 of 134
Case No.PAC-E-19-20
Witness:Joelle R.Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
303 Less Non-Utdity Plant
Direct assigned-Jurisdiction S S
Rate Base Additions
105 Plant Held For Future Use
Direct assigned-Jurisdiction S s
Production SG AP
Transmission SG ST
Mining Plant SE AP
114 Electric Plana Acquisition Adjustments
Direct assigned-Jurisdiction S S
Production Plant SG AP
Transmission SG ST
115 Accum Provision for Asset Acquisition Adjustments
Direct assigned-Jurisdiction S S
Production Plant SG AP
Transmission SG ST
124 Weatherization
Direct assigned-Jurisdiction S S
General So SO
128 Pensions
General SO SO
182 W Weatherization
Direct assigned-Jurisdiction S S
185W Wealherization
Direct assigned-Jurisdiction S S
151 Fuel Stock
Steam Production Plant SE AP
152 Fuel Stock-Undistributed
Steam Production Plant SE AP
25316 LAMPS Working Capital Deposit
Mining Plant SE AP
25317 UG&T Working Capital Deposit
Mining Plant SE AP
25319 Provo Working Capital Deposit
Mining Plant SE AP
2020 Protocol-Appendix B 10

Rocky Mountain Power
Exhibit No. 1 Page 88 of 134
Case No. PAC-E-19-20
Witness:Joelle R Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
. INTERIM PERIOD POST INTERIM PERIOD
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
154 Matenals and Supplies
Direct assigned-Jurisdiction S S
Production, SG AP
Transmission SG ST
Mining SE AP
Production-Common SG AP
General SO SO
Distribution SNPD SNPD
Production,Other SG AP
153 Stores Expense Undistributed
General SO SO
25318 Provo Working Capital Deposit
Provo Working Capital Deposit SG AP
165 Prepayments
Direct assigned-Jurisdiction s S
Property Tax GPS GPS
Production SG AP
Transmission SG ST
Mining SE AP
General So so
• 182M Misc Regulatory Assets
Direct assigned-Jurisdiction S S
Production SG AP
Transmission SG ST
Mining SE AP
General so so
Production,Other SGCT AP
Other SG SGF
Misc Deferred Debits
Direct assigned-Jurisdiction S S
Production SG AP
Transmission SG ST
General SO SO
Mining SE AP
Production- Common SG AP
Other SG SGF
Working Capital
CWC Cash Working Capital
Direct assigned-Jurisdiction S S
OWc Other Working Capital
131 Cash SNP SNP
135 Working Funds SG AP
141 Notes Receivable so So
143 Other Accounts Receivable so SO
•
2020 Protocol -Appendix B

Rocky Mountain Power
Exhibit No.1 Page 89 of 134
Case No.PAC-E-19-20
Witness:Joelle R. Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
• INTERIM PERIOD POST INTERIM PERIOD
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
232 Accounts Payable SO SO
232 Accounts Payable SE AP
232 Accounts Payable SG ST,AP SGF
25330 Other Deferred Credits-Misc SE AP
230 Other Deferred Credits-Misc SE AP
254105 ARC,Reg Liability SE AP
Rate Base Deductions
235 Customer Service Deposits
Direct assigned-Jurisdiction S S
2281 Prov for Property Insurance
Prov for Property Insurance SO So
2282 Prov for Injuries 8 Damages
Prov,for Injuries&Damages So SO
2283 Prov for Pensions and Benefits
Prov for Pensions and Benefits SO SO
22841 Accum Misc Oper Prov-Black Lung
Other Production SG AP
254105 FAS 143 ARO Regulatory Liability
ARO S S
• Trojan Plant TROJD TROJDF
Asset Retirement Obligation
Trojan Plant TROJD TROJDF
252 Customer Advances for Construction
Direct assigned-Jurisdiction S S
Production SG AP
Transmission SG ST
Customer Related CN CN
25398 S02 Emissions
S02 Emissions SE AP
25399 Other Deferred Credits
Direct assigned-Jurisdiction S S
Production SG AP
Transmission SG ST
General SO SO
Mining SE AP
Regulatory Liabilities
Insurance Provision SO So
i
2020 Protocol -Appendix B 12

Rocky Mountain Power
Exhibit No. 1 Page 90 of 134
Case No. PAC-E-19-20
Witness:Joelle R Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
• INTERIM PERIOD POST INTERIM PERIOD
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
150 Accumulated Deferred Income Taxes
Direct assigned-Jurisdiction S S
Bad Debt BADDEBT BADDEBT
Non-Coal and Gas Production SG AP
Coal and Gas Production SG AP
Transmission SG ST
Customer Related CN CN
General SO SO
Miscellaneous SNP SNP
Trojan TROJD TROJDF
Distribution SNPD SNPD
Mining Plant SE AP
<<,I Accumulated Deferred Income Taxes
Non-Coal and Gas Production SG AP
Coal and Gas Production SG AP
Transmission SG ST
282 Accumulated Deferred Income Taxes
Direct assigned-Jurisdiction S S
Depredation DITBAL DITBAL
Non-Coal and Gas Production SG AP
Coal and Gas Production SG AP
Transmission SG ST
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 AP
283 Accumulated Deferred Income Taxes
Direct assigned-Jurisdiction S S
Depreciation DITBAL DITBAL
Non-Coal and Gas Production SG AP
Coal and Gas Production SG AP
Transmission SG ST
Customer Related CN CN
General So SO
Miscellaneous SNP SNP
Trojan TROJD TROJDF
Production,Other SGCT AP
Property Tax GPS GPS
Mining Plant SE AP
255 Accumulated Investment Tax Credit
Direct assigned-Jurisdiction S S
Investment Tax Credits TC84 ITC84
Investment Tax Credits ITC85 ITC85
• Investment Tax Credits ITC88 ITC86
Investmenl Tax Credits ITC88 ITC88
Investment Tax Credits ITC89 ITC89
Investment Tax Credits ITC90 ITC90
Investment Tax Credits SG SGF
2020 Protocol-Appendix B 13

Rocky Mountain Power
Exhibit No. 1 Page 91 of 134
Case No. PAC-E-19-20
Witness:Joelle R. Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
• INTERIM PERIOD POST INTERIM PERIOD
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
PRODUCTION PLANT ACCUM DEPRECIATION
108SP Steam Prod Plant Accumulated Depr
Steam Plants G ;P
108NP Nuclear Prod Plant Accumulated Depr
Nuclear Plant SG AP
108HP Hydraulic Prod Plant Accum Depr
Pacific Hydro SG AP
East Hydro SG AP
108OP Other Production Plant-Accum Depr
Other Production Plant SG AP
TRANS PLANT ACCUM DEPR
108TP transmission Plant Accumulated Depr
Transmission Plant SG ST
DISTRIBUTION PLANTACCUM DEPR
108360 108373 Distribution Plant Accumulated Depr
Direct assigned-Jurisdiction S S
108D00 Unclassified Dist Plant-Acd 300
Direct assigned-Jurisdiction S S
• 108DS Unclassified Dist Sub Plant-Acd 300
Direct assigned-Jurisdiction S S
108UI 1 Unclassified Dist Sub Plant-Acd 300
Direct assigned-Jurisdiction S S
GENERAL PLANT ACCUM DEPR
1 oBGP General Plant Accumulated Depr.
Distribution S S
Pacific Hydro SG AP
East Hydro SG AP
Production SG AP
Transmission SG ST
Customer Related CN CN
General SO so so
Mining Plant SE AP
108MP Mining Plant Accumulated Depr.
Mining Plant SE AP
1081390 Accum Depr-Capital Lease
General So SO
1081399 Accum Depr-Capital Lease
Direct assigned-Jurisdiction S S
2020 Protocol -Appendix B 14

Rocky Mountain Power
Exhibit No.1 Page 92 of 134
Case No. PAC-E-19-20
Witness: Joelle R Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
INTERIM PERIOD POST INTERIM PERIOD
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
ACCUM PROVISION FOR AMORTIZATION
I I I SP Accum Prov for Amor1-Steam
Steam Plants SG AP
111GP Accum Prov for Amort-General
Distribution S S
Pacific Hydro SG AP
East Hydro SG AP
Production SG AP
Transmission SG ST
Customer Related CN CN
General SO SO so
111HP Accum Prov for Amorl-Hydro
Pacific Hydro SG AP
East Hydro SG AP
111 IP Accum Prov for Amon-Intangible Plant
Distribution S S
Pacific H ydro SG AP
Production SG AP
Transmission SG ST
General SO SO
Mining SE AP
Customer Related CN CN
• 1111P Less Non-Utildy Plant
Direct assigned-Jurisdiction S S
111390 Accum Prov Amor1-Capital Leases
Distribution S S
Production SG AP
General SO SO
i
2020 Protocol-Appendix B 15

Rocky Mountain Power
Exhibit No. 1 Page 93 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
APPENDIX C
. Definitions of Allocation Factors
Factors without an effective period will be used during and after the Interim Period.
i denotes count of jurisdictions. j denotes count of month in a year. N is the number of'regulatory
jurisdictions that the Company operates in and allocates costs to.
Assigned Production Factor ("AP")—Effective after Interim Period
A Pt
SGFi
= X
Z;F SGFi
where:
APi = Assigned Production Factor for jurisdiction i.
SGFi = System Generation —Fixed Factor for jurisdiction i.
x = Number of jurisdictions that are assigned the unit.
The AP factor may be calculated by unit of Resources, group of Resources, or for specific periods of
capital investments. The AP factor may changeover time as allocations change due to jurisdictions
accepting a larger or smaller assignment in units that lead to the change in the value of x.
For example,
1. Assuming a unit is assigned to States A, Band C out of six jurisdictions in year 1, and their
SGF factors are
SGFA= 25%, SGFB =45%, and SGFc= 15%, respectively, then
_ 25% _
_ _ o
`4PA 25% + 45% + 15% °
45% _
0
APB = 25% + 45% + 1S% — 2.9/o
15%
_ o
APB _ 25% + 45% + 1S% 1 /o
2. Assuming the unit is later assigned to States B and C only, then the AP factors will change to
APA = 0%
45% _
0
APB = 45% + 15% - 7 %
15% _
o
%
APB _ _45% + 15% 25%
2020 Protocol-Appendix C 1

Rocky Mountain Power
Exhibit No.1 Page 94 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle_R.Steward
3. Assuming the unit is later assigned to C only, then the AP factors will change to
. APA = 0%
APB = 0%
15%APC = 15% = 100%
Accounts using AP factor: Sales for Resale(447), Water Sales (453), Miscellaneous Revenue (41160,
41170, 4118, 41181, 421), Generation (500-555, 557),Administrative and General Expense(920-935),
Depreciation Expense(403SP, 403NP, 403HP, 4030P, 403GP, 403MP) Amortization Expense(404SP,
4041P, 404HP, 404W 406-407), Taxes Other Than Income(408), Deferred Income Tax Expense (41010,
41110), Schedule M, Income Taxes (40910, 40911), Generation Plant(310-346), General Plant (389-399),
Intangible Plant (302-303), Plant Held for Future Use(105), Electric Plant Acquisition Adjustments (114-
115), Fuel Stock (151-152), Materials and Supplies (154), Mining Working Capital Deposits(25316-
25319), Prepayments(165),Misc. Regulatory Assets(182M), Misc. Deferred Debits (186M),Working
Capital (135, 232, 25330, 230, 245105), Accum Misc Oper Prov-Black Lung(22841), Customer
Advances for Construction(252), S02 Emissions(25398), Other Deferred Credits (25399), Regulatory
Liabilities ARO Regulatory Liability (254105),Accumulated Deferred Income Taxes (190, 281-283),
Accumulated Depreciation (108SP, 108NP, 108HP, 1080P, 108GP, 108MP),Accumulated Provision for
Amortization (IIISP, I IIGP, I I IHP, I I IIP, 111390)
Assigned Production Factor of New Resources -Effective after Interim Period
Initial values of AP factors for all new resources will be addressed as part of the Framework discussions
on Resource Planning.
.Assi-ned Production Hvdro - O&M Factor, (".WOMH")-Effective after- Interim Period
PPOMHi
APOMH� _ PPOMIIi
where:
APOMH, = Assigned Production Hydro O&M Factor for jurisdiction i.
PPOMH, = Sum of all hydro production plant O&M costs allocated to
jurisdiction i using the AP factors.
N = Number of jurisdictions.
The APOMH factor is used to allocate hydro generation related O&M costs that cannot be allocated to a
specific hydro resource through an AP factor, calculated as each States'relative share of direct-allocated
hydro generation and maintenance expenses.
Accounts using APOMH factor: Hydro (535-545, 557)
Assigned Production Other-O&M Factor("APOMO")- Effective after Interim Period
APOMOi
PPOMOi
=• where: Z1=N
1 PPOMOi
APOMO, = Assigned Production Other O&NI Factor for jurisdiction i.
2020 Protocol-Appendix C

Rocky Mountain Power
Exhibit No.1 Page 95 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
PPOMO, = Sum of all other production plant O&M costs allocated to
jurisdiction i using the AP factors.
• N = Number of jurisdictions.
The APOMO factor is used to allocate other generation related O&M costs that cannot be allocated to
specific other production Resource through an AP factor, calculated as each States' relative share of
directly-allocated other production generation and maintenance expenses.
Accounts using APOMO factor: Other Generation (546-554, 557)
.kssiugned Production Steam — O&M Factor("APOMS")—Effective after Interim Period
PPOMSi
APOMSi = v 1 PPOMSi
where:
APOMS, = Assigned Production Steam O&M Factor for jurisdiction i.
PPOMS, = Sum of all steam production plant O&M costs allocated to
jurisdiction i using the AP factors.
N = Number of jurisdictions.
The APOMS factor is used to allocate steam generation related O&M costs that cannot be allocated to
specific steam resource through an AP factor, calculated as each States' relative share of direct-allocated
steam generation and maintenance expenses.
• Accounts using APOMS factor: Generation (500-514, 557)
Bad Debt Expense Factor("BADDEBT")
ACCT 904i
RADDL''BTi = N
2:Y1 ACCT904i
where:
BADDEBT, = Bad Debt Expense Factor for jurisdiction i.
ACC7904i = 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 forbad
debt related expenses.
Accounts using BADDEBT factor: Deferred Income Tax Expense(41010), Schedule M, Accumulated
Deferred Income Taxes(190)
Contributions in Aid of Construction Factor("CIAC")
CI ACNAi
CIACi = ,v CIACNA
Yi=1 i
where:
CIAO; = Contributions in Aid of Construction Factor for jurisdiction i.
CIACNA; = Contributions in aid of construction—net additions for jurisdiction i.
2020 Protocol-Appendix C 3

Rocky Mountain Power
Exhibit No. 1 Page 96 of 134 EXECUTION VERSION
Case No PAC-E-19-20
Witness:Joelle R. Steward
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.
Accounts using CIAC factor: Deferred Income Tax Expense(41110), Schedule M, Accumulated Deferred
Income Taxes (282)
Customer Number Factor ("(-N'')
CUS'"l-i
CNi = y N I CUS"1'i
where:
CNt - Customer Number Factor for jurisdiction i.
CUST, - Total electric customers for jurisdiction i.
N = Number of jurisdictions.
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.
Accounts using CN factor: Gain/Loss on Sale of Utility Plant(421), Customer Service Deposits (4311),
Other Electric Revenue(456), Customer Account Expense (901-905), Customer Service Expense(907-
i910), Sales Expense(911-916),Administrative and General Expense(920-935), General Plant
Depreciation (403GP), Amortization Intangible Plant (4041P), Deferred Income Tax Expense(41010,
41110), Schedule M, General Plant(389-398), Intangible Plant(303), Customer Advances for
Construction (252),Accumulated Deferred Income Taxes(190, 282-283), General Plant Accumulated
Depreciation (I08GP), Accumulated Provision for Amortization (I I l IP)
Deferred Tax Balance Factor ("DITBAL")
DITBAI,Ai
DITBAL- =
ZN DITBALA
t-1
where:
DITBAL; = Deferred Tax Balance Factor for jurisdiction i.
DITBALA; = 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.
Accounts using DITBAL factor: Accumulated Deferred Income Taxes(282, 283)
•
2020 Protocol-Appendix C 4

Rocky Mountain Power
Exhibit No. 1 Page 97 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
Division Generation— Pacific Factor("DGP")
SG'i
DGPi =
E"r SG'i
where:
DGP, = Division Generation— Pacific Factor for jurisdiction i.
.SG*, = SG,if i is a pre-merger Pacific Power jurisdiction, otherwise 0.
SG, = System Generation Factor for jurisdiction i.
N = Number of jurisdictions.
The DGP Factor is calculated as the ratio of the pre-merger Pacific Division's SG factor for a jurisdiction
divided by the sum of the pre-merger Pacific Division's SG factors.
The DGP factor is only used in calculating the dynamic ECD
Division Generation — Ulih Factor ("DGU")
DGUi
SG'i
=
E"1SG'i
where:
DGU; = Division Generation—Utah Factor for jurisdiction i.
SG", = SG,if i is a pre-merger Utah Power jurisdiction, otherwise 0.
SG, = System Generation Factor for jurisdiction i.
N = Number of jurisdictions.
After the Interim Period, the factor is determined by the average of the four-year historical
value from 2018 to 2021, or 2019 to 2022 if the Interim Period is extended.
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 only accounts using DGU factor are Deferred Investment Tax Credits (41140, 41141)
Gross Plant System Factor("GPS")
GPSi
PPi + PTi + PDi + PGi + PIi
= N
Ei=1(PPi + PTi + PDi + PGi + PIi)
where:
GPS, = Gross Plant System Factor for jurisdiction i.
PP, = Production plant for jurisdiction i.
PT, = Transmission plant for jurisdiction i.
PA = Distribution plant for jurisdiction i.
PG, = General plant for jurisdiction i.
Pl, = 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.
2020 Protocol-Appendix C i

Rocky Mountain Power
Exhibit No.1 Page 98 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
The accounts using GPS factor: Taxes Other Than Income Taxes(408), Deferred Income Tax Expense
(41010, 41110), Schedule M, Prepayments(165),Accumulated Deferred Income Taxes (282, 283)
• Nodal Pricing Assignment of Net Power Costs ("NP")
Costs listed as allocated by NP in Appendix B are costs that will be allocated through the Nodal Pricing
Model.
Accounts using NP factor: Sales for Resale (447), Purchased Power(555)
Schedule .N7 — Depreciation Expense Factor ("SCHMDEXP")
DEPRCi
SCHMUL = Zi_nr
1 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.
The SCHMDEXP factor is used to allocate Schedule M items related to depreciation expense.
The accounts using SCHMDEXP factor: Deferred Income Tax Expense(41110), Schedule M,
Accumulated Deferred Income Taxes (282)
System Capacity Factor("SC")
• SC — -Jz
` 1 TAPii
— ZN 12 TAP��(-1 Ei=1
where:
SCi = System Capacity Factor for jurisdiction i.
TAP,1 = Weather-normalized peak load of jurisdiction i at the time of the
system peak in month j. During the Interim Period, the peak load is
further adjusted to exclude the peak load of Class 1 Demand Side
Management programs and interruptible peak load of the special
contracts as defined in the 2017 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 that is used to calculate the System Generation and System Transmission
factors
System Energy Factor("SE")
SE —_ "f z 1 TAEii
` 2i 1�JZ1 TAEii
where:
SE; = System Energy Factor for jurisdiction i.
My = Weather-normalized energy at input of jurisdiction i in month j.
• N = Number of jurisdictions.
2020 Protocol-Appendix C 6

Rocky Mountain Power
Exhibit No.1 Page 99 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
The SE factor is used to allocate energy-related costs and 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.
Accounts using SE factor for Interim period: Sales for Resale(447), Other Electric Revenue(456),
Miscellaneous Revenue (4118, 41181), Steam Plants Fuel (501), Steam from Other Sources(503), Other
Fuel Expense (547), Purchased Power(555), Transmission of Electricity by Others (565),Administrative
and General Expense(920-935), Depreciation Expense(403MP),Amortization Expense (4041P,
404MP),Taxes Other Than Income(408), Deferred Income Tax Expense(41010, 41110), Schedule M,
Federal Income Tax True-Up (40910), General Plant (389-399), Intangible Plant(303), Plant Held for
Future Use (105), Fuel Stock(151, 152), Working Capital -Mining related (25316, 25317, 25319),
Materials and Supplies(154), Prepayments-Mining related (165), Misc. Regulatory Assets-Mining
Related (182M), Misc. Deferred Debits-Mining related (186M),Accounts Payable(232), Other
Deferred Credits Misc. (25330, 230, 25399),ARO Regulatory Liability (254105), SO Emissions (25398),
Regulatory Liabilities (254),Accumulated Deferred Income Taxes(190, 282-283), General Plant
Accumulated Depreciation 108GP,Accumulated Provision for Amortization (1 111P, I I IMP)
Accounts using SE factor after Interim period: System Control & Load Dispatch(556), Other Expenses
(557), Transmission of Electricity by Others - GRID Management Charge(565)
System Generation Factor("SG").-Effective during the Interim Period
SGi = 0.75 * SCi + 0.25 *SEi
where:
SQ - System Generation Factor for jurisdiction i.
SC; System Capacity Factor for jurisdiction i.
.SF,'i = System Energy Factor for jurisdiction i.
The SG factor is used to allocate generation and transmission costs. It is calculated using a weighting of
75% of the SC factor and 25%of the SE factor for a jurisdiction.
Accounts using the SG factor: Sales for Resale(447), Provision for Rate Refund (449), Other Electric
Operating Revenue(453, 454 ,456), Miscellaneous Revenue(41160, 41170, 421), Generation Expense
(500, 502, 504-514, 517-532, 535-545, 546, 548-554, 555, 556, 557), Transmission Expense(560-564,
566-573, 565), Administrative and General Expense(920-935), Depreciation Expense(403SP, 403NP,
403HP, 403OP, 403TP, 403GP),Amortization Expense(404SP, 404HP, 4041P 406, 407), Taxes Other
Than Income(408), Deferred Income Tax Expense, (41010, 41110), Schedule M, Renewable Energy Tax
Credit(40911), Federal Income Tax True-Up (40910), Generation Plant (310-316, 320-325, 330-336, 340-
346), Transmission Plant(350-359), General Plant (389-398, 1011390), Intangible Plant (302-303), Plant
Held for Future Use(105), Electric Plant Acquisition Adjustments(114-115), Materials and Supplies
(154), Working Capital Deposit(25318), Prepayments (165), Misc. Regulatory Assets (182M), Misc.
Deferred Debits (186M), Working Capital (135, 232),Accumulated Misc. Operating Provision Other
(22841), Customer Advances for Construction (252), Other Deferred Debits(25399), Accumulated
Deferred Income Taxes (190, 281-283), Accumulated Investment Tax Credit(255),Accumulated
Depreciation (108SP, 108HP, 1080P, 108TP, 108GP),Accumulated Provision for Amortization (I IISP,
111GP, 111HP, 1111P, 111390)
2020 Protocol-Appendix C 7

Rocky Mountain Power
Exhibit No. 1 Page 100 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R. Steward
System Generation Factor— Fixed ("SGF")—Effective after Interim Period
• Based on actual SG allocation factors for the most recent four calendar years available prior to the end of
the Interim Period. The SGi factor is as defined above.)
PY1SGi + PY2 SG + PY3SCi + PY4SGi
SGFi = 4
where:
SGFi = System Generation—Fixed Factor for jurisdiction i.
Prior Year(PY) 1 SGi = PY1 System Generation Factor for jurisdiction i.
Prior Year(PY)2 SGi = PY2 System Generation Factor for jurisdiction i.
Prior Year(PY) 3 SGi = PY3 System Generation Factor for jurisdiction i.
Prior Year(PY)4 SG, = PY4 System Generation Factor for jurisdiction i.
For Example: If the Interim Period ends December 31, 2023, then(PY) l = calendar year 2022, (PY)2 =
calendar year 2021, (PY) 3 = calendar year 2020, and (PY)4 = calendar year 2019.
Accounts using SGF factor: Intangible Plant (303), Misc. Regulatory Assets(182M), Misc. Deferred
Debits(186M), Working Capital (232),Accumulated Investment Tax Credit(255)
System Gross Plant Distribution Factor("SGPD")— Effective after Interim Period
GPDi
SGPllj = N
where: GPD
i � _� i
SGPD; = 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.
There are no accounts allocated using the SGPD factor. This factor is used to calculate the SO factor after
the Interim period.
System Net Plant- Distribution Factor("SNPD")
PDi + ADPDi
SNPDi = ZN 1(PDi + ADPDi)
where:
.SNPD, = System Net Plant—Distribution Factor for jurisdiction i.
PA = Distribution plant—for jurisdiction i.
ADPD, = 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.
2020 Protocol-Appendix C 8

Rocky Mountain Power
Exhibit No.1 Page 101 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
Accounts using the SNPD factor: Distribution O&M (580-598), Deferred Income Tax Expenses(41010,
41110), Schedule M, Materials and Supplies-Distribution (154),Accumulated Deferred Income Taxes
(190)
System Net Plant Factor("SNP")
PPi + PT, + PDi + PGi + Pli + ADPPi + ADPTi + ADPDi + ADPGi + ADPPi
SNPi = ,j=1(PPi + PTi + PDi + PGi + Pli + ADPPi + ADPTi + ADPDi + ADPGi + ADPID
where:
SNP, = System Net Plant Factor for jurisdiction i.
PPi = Production plant for jurisdiction i.
PT,' = Transmission plant for jurisdiction i.
PD, = Distribution plant for jurisdiction i.
PGi = General plant for jurisdiction i.
PL = Intangible plant for jurisdiction i.
ADPP, = Accumulated depreciation production plant for jurisdiction i.
ADPTi = Accumulated depreciation transmission plant for jurisdiction 1.
ADPD, = Accumulated depreciation distribution plant for jurisdiction i.
ADPG, = 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.
Accounts using SNP factor: Interest Expense(427-429, 431, 432), Deferred Income Tax Expenses (41010,
41110), Schedule M, Working Capital -Cash (131),Accumulated Deferred Income Taxes (190, 282, 283)
System Overhead Factor("SO")-Effective after Interim Period
SCi + SEi +SGPDi
SOi = 3
where:
SOi = System Overhead Factor for jurisdiction i.
SCi = System Capacity Factor for jurisdiction i.
SEi = System Energy Factor for jurisdiction i.
SGPDi = System Gross Plant Distribution for jurisdiction i.
The SO factor is used to allocate system overhead costs. The SO factor used after the Interim period is
calculated by taking the sum of the SC, SE and SGPD factor for a jurisdiction and dividing by three.
Accounts using SO factor after Interim period: Other Electric Operating Revenue (451, 454, 456),
Miscellaneous Revenue(41160, 41170, 421),Administrative and General Expense(920-935),
Depreciation Expense(403GP), Amortization Expense(404GP, 404IP), Deferred Income Tax Expenses
(41010, 41110), Schedule M, Federal Income Tax True-Up (40910), General Plant (389-398, 1011390),
Intangible Plant (303), Materials and Supplies(154), Stores Expense Undistributed (163), Prepayments
(165), Misc. Regulatory Assets (182M), Misc. Deferred Debits (186M), Working Capital (141, 232), Rate
Base Deduction Provisions(2281-2283), Other Deferred Credits (25399), Regulatory Liabilities(254),
2020 Protocol-Appendix C 9

Rocky Mountain Power
Exhibit No. 1 Page 102 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
Accumulated Deferred Income Taxes (190, 282, 283),Accumulated Depreciation(108GP, 1081390),
Accumulated Provision for Amortization (I I IGP, 11 IIP)
System Overhead Factor ("SO")- Effective during the Interim Period
PPi + PT, + PDi + PGi + Pli - PPoi - PToi - PDoi - PGoi - Plai
SO, = hr
yt_1(PPt + P"1'i + PDi + PGi + Pli - PPoi - PToi - PDoi - PGoi - P10i)
where:
SOi = System Overhead Factor for jurisdiction i.
PPi = Gross production plant for jurisdiction i.
PTi = Gross transmission plant for jurisdiction i.
PDi - Gross distribution plant for jurisdiction i.
PGi - Gross general plant for jurisdiction i.
P4 Gross intangible plant for jurisdiction i.
PPoi Gross production plant for jurisdiction i allocated on a SO factor.
PToi - Gross transmission plant for jurisdiction i allocated on a SO factor.
PI)w = Gross distribution plant for jurisdiction i allocated on a SO factor.
PGoi Gross general plant for jurisdiction i allocated on a SO factor.
P& - Gross intangible plant for jurisdiction i allocated on a SO factor.
N = Number of jurisdictions.
The SO factor is used to allocate system overhead costs. The SO factor used during the Interim period is
calculated by taking the gross plant allocated to a jurisdiction, excluding the plant amounts allocated on
SO, and dividing it by the total gross plant for all jurisdictions, excluding plant amounts allocated on SO,
for all jurisdictions.
Accounts using SO factor during the Interim period: Other Electric Operating Revenue(451, 454, 456),
Miscellaneous Revenue(41160, 41170, 421), Administrative and General Expense(920-935),
Depreciation Expense (403GP),Amortization Expense (404GP, 404IP), Deferred Income Tax Expenses
(41010, 41110), Schedule M, Federal Income Tax True-Up (40910), General Plant(389-398, 1011390),
Intangible Plant (303), Materials and Supplies(154), Stores Expense Undistributed (163), Prepayments
(165), Misc. Regulatory Assets(182M), Misc. Deferred Debits (186M), Working Capital (141, 232), Rate
Base Deduction Provisions(2281-2283), Other Deferred Credits(25399), Regulatory Liabilities(254),
Accumulated Deferred Income Taxes(190, 282, 283), Accumulated Depreciation (108GP, 1081390),
Accumulated Provision for Amortization(I IIGP, 11 IIP)
System Transmission Factor ("ST")- Effective after Interim Period
STi = 75% * SCi, + 25% * SEi
where:
STi = System Transmission Factor for jurisdiction i.
SCi = System Capacity Factor for jurisdiction i.
SEi = System Energy Factor for jurisdiction i.
The ST factor is used to allocate transmission related costs after the Interim period. It is calculated using a
weighting of 75%of the SC factor and 25% of the SE factor for a jurisdiction.
Accounts using ST factor: Provision for Rate Refund (449), Operating Revenue (454), Other Electric
Revenue (456), Miscellaneous Revenue (41160, 41170, 421), Transmission Expense(560-564, 566-573),
2020 Protocol-Appendix C 10

Rocky Mountain Power
Exhibit No. 1 Page 103 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
VWness:Joelle R.Steward
Transmission of Electricity by Others (565),Administrative& General Expense (920-935), Depreciation
Expense(403TP, 403GP), Amortization Expense(4041P, 407), Deferred Income Tax Expenses (41010,
• 41110), Schedule M, Transmission Plant(350-359), General Plant(389-398, 1011390), Intangible Plant
(302, 303), Plant Held for Future Use(105), Electric Plant Acquisition Adjustments (114-115), Material
and Supplies(154), Prepayments(165), Misc. Regulatory Assets(182M), Misc. Deferred Debits (186M),
Working Capital (232), Customer Advances for Construction (252), Other Deferred Credits (25399),
Accumulated Deferred Income Taxes(190, 281-283),Accumulated Depreciation (108TP, 108GP),
Accumulated Provision for Amortization (111TP, 111GP, 111IP)
Tax Depreciation Factor("TAXDEPR")
TAXDF,PRAi
7'AXDF,PRi = N
Zivi TAXDFPRAi
where:
TAXDEPR; = Tax Depreciation Factor for jurisdiction i.
TAXDEPRA; = 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 total allocated ratio of these
functional pre- and post-merger splits to the total Company tax
depreciation.)
N - Number of jurisdictions.
• The TAXDEPR factor allocates depreciation related tax costs.
Accounts using TAXDEPR: Deferred Income Tax Expense(41010) Schedule M,Accumulated Deferred
Income Taxes (282)
Trojan Decommissioning Factor ("TROJD")
TRDJDt
ACCT 22842i
= N
EN ACCT22842i
where:
7ROJA = Trojan Decommissioning Factor for jurisdiction i.
ACCT22842; = 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.
Accounts using TROJD: Deferred Income Tax Expenses(41010, 41110), Schedule M, FAS 143 ARO
Regulatory Liability-Trojan Plant(254105),Asset Retirement Obligation-Trojan Plant (230),
Accumulated Deferred Income Taxes(190, 283)
Trojan Decommissionine Fixed Factor("TROJDF")
• Effective after Interim Period Based on actual TROJD allocation factors for the most recent four calendar
years available prior to the end of the Interim Period. (The TROJDi factor is as defined above.)
2020 Protocol-Appendix C 11

Rocky Mountain Power
Exhibit No. 1 Page 104 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
PYITROJDi + PUTROJDi + PY3TRM5i+�'e��1'�tU
TROJDFi = 4
• where:
TROJDFi = Trojan Decommissioning—Fixed Factor for jurisdiction i.
Prior Year(PY) 1 TROJDi = PYI Trojan Decommissioning Factor for jurisdiction i.
Prior Year(PY) 2 TROJDi = PY2 Trojan Decommissioning Factor for jurisdiction i.
Prior Year(PY) 3 TROJDi = PY3 Trojan Decommissioning Factor for jurisdiction i.
Prior Year(PY)4 TROJDi = PY4 Trojan Decommissioning Factor for jurisdiction i.
For Example: If the Interim Period ends December 31, 2023, then (PY) I = calendar year 2022, (PY) 2 =
calendar year 2021, (PY) 3 = calendar year 2020, and (PY) 4 = calendar year 2019.The TROJDF factor is
used to allocate decommissioning related costs associated with the Trojan plant.
Accounts using TROJDF: Deferred Income Tax Expenses (41010, 41110), Schedule M, FAS 143 ARO
Regtalatory Liability — Trojan Plant (254105), Asset Retirement Obligation — Trojan Plant (230),
Accumulated Deferred Income Taxes (190, 283)
•
2020 Protocol -Appendix C 12

Rocky Mountain Power
Exhibit No. 1 Page 105 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R.Steward
APPENDIX D
• Nodal Pricing Model Memorandum of Understanding
•
•

Rocky Mountain Power
Exhibit No, 1 Page 106 of 134
Case No. PAC-E-19-20
Witness:Joelle R :*A", 1.14 ,,VERSION
• PacifiC'or 's Nodal Pricing Model Memorandum of L"aderstandfng.
Intrt;<rluction
1. Paciti.C;c rp and the undersigned parties (Partizs) enter into this Memorandum of
Undemanding (MOLD to acknowledge their ;support, as describvd bolo-,., of l'acifiCorp's
in c imrnent in the development WW implementation of a'nodal Pricing MoJef(NP.M9)that r aky be
adopted for the calculation of net-power costs(NPQ.
Background
?. PaciliCorp is a multi jurisdictional electric utility that is serving custom en in
C'alifomia,Idaho,Oregon,€.'lath, Washington.and Wyoming..
• 3. Generally, Pacific orp has allocated costs among those states using an intcr-
uri.W—Ictllonal cost allocation methc?dolagy..
4. PaCifICarp's Wrm-nt inter-jurisdictional cast allocation methodology, the 2017
PacifiCorp Inter-Jurisdictional Allocation Protocol(2017 Protocol),was adopter by the applicable
rogtrlatory commissions in Idaho, Oregon, Lhah, and Wyoming in 2016, and set a process for
& efoping a nc��- inter-jurisdictional cost allt ation niethctdology through a -work-in; group of
stakeholders consisting of utility regulatory agencies, customers, and certain others potentially
alTocted by Inter-jurisdictional al location procedures.known as the Multi-State.Process%korkgrc.,up
(NOSP W`orkgroup).r U`asshingwn has used the West Control Area Inter-Jurisdictional.Allocation
Pacili(74,rp anticipates dw California i4i1i adopt dw 201' Protocol in 2019.
1
2020 Prolocul-pp-eudia 1) t

Rocky Mountain Power
Exhibit No. 1 Page 107 of 134
Case No.PAC-E-19-20
Witness:Joelle R.St"T(J TIO?IY VERStOv
Methodology for the purposes of cost allocations sinct:.2007.0aliforni<a current€y uses the Revised
Protocol,but a decision on adoption of the 2017 Protocol is pending before the commission.
S- Discussions arnong the 'VISP Work—group for the potential extension of the 2017
Protoctd andlor a tic", inter-iurisdictional cost allocation methodology are h6ne heft.
6. In 1atc;-2017, PacitiC.°orp presented the MI:t' Wtirkgroiip with a proposal. o tme•1
NPC through a NIII t 4t?f1i:ept designed to facilitate each states energy policies and unique resource
portfolios %Abile still seeking to maintain the henefits of system dispatch and optimi-7,ation.
Pacif-iC orp also indicated a pcitential for the NPM to provide increased dispatch efficiencies,
7. PacifiC orp's NPM propcfsal is to use a third-party day-ahead digmtch model to
detennine the schedules for each of its generation resources to serve state toads can a least-cost
basis, while tracking costs and benefits associated with the different resource portfolios used to
Serve Pac:ificorp's load En each st;atc. I'ac;iliC orp has 1a esi in discussions with the California
Independent System Operator(C'AISO)to provide the clay--ahead dispatch modet.
8- To allow for tfteanticipated implernctltatiOn Of NPM fOr IVteriti21 ratCMal:itlg by
2023, .t'acit3C orp has determined that it must now invest related capital, incur related operations
and maintenance expenses. and pay related ongoing grid martageinent charges. Attached as
l~xhibit A to thN MOO is a description of the vvpe of v-sork that PacitiC:cirp arltisipates undertaking.
The I'arlies understand that the list is preliminary-and is not intended to he a complete List.
2020 Protmol-Appendix D 2

Rocky Mountain Power
Exhibit No. 1 Page 108 of 134
Case No.PAC-E-19-20
Witness:Joelle R vFIC1.11ION VERSION
• Agreement
9, As described in this the Parties affirm support for llacif c.orp's reasclna€bica
and prudent investment of related capital funds,related operations and maintenance expenses.and
the; related ongoing grid management charges to develop and implentent an NP%-,I. Exhibit 8 to
this ,NIOU is art estimate of the investment,, and ongoing-c:ogs PaciftCurp anticipates it will make.
or incur through this of oft and an explanation of the anticipated hene.fity, including coast-savings
and compltancc: with state policy directives impacting resource portfoliodecisions. The.Parties
agree that.,based on the information provided by PacifiCotp,Pac itiC.:otp's decision to invest eapital
funds and pay ongoing grid management charges to develop and implement an NPM is Msonable
mid prudent. Ho-we't er, the Parties dot not ne-.e:ssarily agree that any specific investment or
• expenditure is reasonable or prudent and the Parties reserve all rights to audit, review, and
challenge any specific investment or expenditure: as unremonable or imprudent in appropriate
regulatory commission proceedings.
ilf. They Parties agree the associated grid management costs will be hoc)l e d in Federal
Ettergy Regulatory Commission (FERC) Account 565, which is included in PacifiC.~orp�s bi:PC.
NPM related costs will he allocated among the Pactf€Corp states as follows=:
Rcferc oam to"S6 t=actm-atul"SE Factor`in the MkIwinga tsthlc are to the Systcnt Generation Factor and the
System I'.mry}'actor,r",poctively.&&tkied in the eurreitly-applicable cost tl Ima Lion protmof in each state,or any
wccesaor t'ao;,r`- Ft;.3erettees to-Fixed SQ Faclor"am to a tnopsad N-%ed SO Ftt;;t w than�hc Parties cunvaitly
anticip to rtaa.Y he cstablishe-A as pan of a f-tare intern,ante cilia altm—ation prol�-ol.
3
210.20.Pre.imol-Appendix D

Rocky Mountain Power
Exhibit No. 1 Page 109 of 134
Case No.PAC-E-19-20
Witness:Joelle R.StMCUTION VERSION
Time Period
NPM Associated January 1.2020 Through the
Costs E tft.ctive Date or a.New Beginning upon the Ett'ectiv
lnterlurisdictioful Cost Elate of it New Interstate Cost E
_ Allocation Protocol' Allocation Protocol !
4t;F Factor SE r Factor
Mai t fneat Ch me
CapitalizedStartdrp .-.,._... ..........�..-.�....�...... ._....�........,.�..........�......V..y.
CesL4 for PacafiC.orp SG Factor Fixed SO Factor
ESW
_......... ...........................................................
Capitalized CA(SO SO F uc:tor Fixed SO ra►,tir
I Implementation l ee _......_.............
i:)ng;rind Operations and Maintc:.namee. SG Pactot SE liactor
oMn e
Otherwise,this lw OU shall not limit the positions any Party may take regarding how nodal pricing
may be used to allocate casts amongst the states before any applicable state reoulator�cc�mmi. icrn.
11. The Company shall use: its list O Torts to provide adequate training and
dcscumentation regarding the NFM such that Parties may understand, review,iew, and audit NPM-
derived'14K. The v-P M,however.is bmd on C AISO F RC jurisdictional market model to which
PactfiCo p doo.4 not have and cannot, PA)Vide access. For re-g alatot), purposes, the Company will
retrain C AISO advisory schedules and documentation of any decision to materially deviate f -)m
those advisory schedules. The Company further agrees to provide training and facilitate access to
the Company's forecasting model for any appropriate party for regulatory purposes.
The Partiesare iad£°r4:ntly nep! iiwing towards a possible extension<,f the 21017 fmtrruraAi..tional Allocation
toil 3iylr, y"(Sukicrct to,%-mce posi ible changes),uptil a future inerstate cost allimati iri tirt?tt+of bet;t m-5 emctivT,
which the:Parties curr:ritly expect matt•kJanuary 1,20201 or.larisary 1,21024.
. `Piici#cC't�rp's F::tier y"Suppty Management(ESA'i)is the business unit responsible for scheduling and dispatching
PacitfCorp`s generation resources to ,crve tetail load and buy'sell iri wholesale encrgy snit capacity rila£l a-5,
2020 Protocol.-Apj-- tcwlix 1) 4

Rocky Mountain Power
Exhibit No. 1 Page 110 of 134
Case No. PAC-E-19-20
Witness Joelle R f..lYl ION VERSION
1.2. The Parties acknowledge that this MOU does not address any other aspect of the
on-going negotiations regarding an extension of the 2017 Protocol or anew inter-juri0-ictional
cast allocation methodology. By executing this MOO.no Party is agreeing to any other issue not
agreed to in this MOU.
13. 'This INIOU may lsc executed in counterparts and each signed counterpart constitutes
an original ducumcni,
14. The obligations of arty state age ttcy thw is a party to this MOU shalt b,., iawrpretcd
in a manner consistent with its statutoq :tttthority and responsibilities, and arty explanation and
suppot-t provided 1.n this MOU:or to any regulatory 1voceeding shall be consistent wide its statutory
authorio and responsibility.
15. This MOU is entorc:d into by each Puny on the date entered below such Party's
signature.
r �
.... .................. .................................
Organization
.... . _w.
i

Rocky Mountain Power
E)diibit No. 1 Page 111 of 134
Case No PAC-E-19-20
Witness:Joelle R. StEMPT ;- ION XTRSION
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2020 Pmtocot-Appimidie U f�

Rocky Mountain Power
Exhibit No. 1 Page 112 of 134
Case No.PAC-E-1 9-20
VVitness:Joelle R.IeVft-UTION VERSION
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2020 Pmtcov)l-Appeiidix D

Rocky Mountain Power
Exhibit No. 1 Page 113 of 134
Case No. PAC-E-19-20
Witness:Joelle R. Steward
EXECUTION VERSION
WXanzzatt«n Crquniatinn
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2020 Flvitmal-Appendix Ul ;e

Rocky Mountain Power
Exhibit No. 1 Page 114 of 134
Case No.PAC-E-1 9-20
Witness:Joelle R.Steward
F,I,M.CMO,',.4 VKMON
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24020 F.'rolocol--Appendix D

Rocky Mountain Power
Exhibit No 1 Page 115 of 134
Case No. PAC-E-19-20
Witness:Joelle R. Steward
CXECUTION VERSION
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2020 Pmwof-Appendix D €t;

Rocky Mountain Power
Exhibit No. 1 Page 116 of 134
Case No.PAC-E-19-20
Witness:Joelle R.Steward
EXECUTION VERSION
EXHIBIT A
NcAlal Pricing,ltude>l Statement of Work
Introduction
PacifiCorp bass requested the CANO provide a design proposal flor a MINI that can be used to clear
energy supply and demand bids for the PacifiCorp Balancing.Authority Areas (BAA)1 one day.
ahead. Mile CAISO proposes to leverage its existing Day-Ahead Market (DAM) technology
platfrirrn, the: market full network model, and data interfaces available in the reakinie Energy
Imbalance Marl-et (EIM) to pRwide they `NPX-1 solution. PacifiCorp is currently an El-M Entity
participating in the EIM and has already developed systems and data interfaces with the: EIM in
submitting data and receiving settlement statements. Consequently, the proposed solution would
require an expansion of PacifiC:orp's bidding, scheduling, and settlement systems for flit: tiPM,
while gaining full access to the,most advanced security constrained unit c ommitrmen(tool currently
used in the CAISO's DAk-t.
Nodal Pricing Model
Currently, the: CAISO's DAM footprint is limited to the CAISO BAA (CISO). Although supply
and demand schedules in the external BAAs ate not optimized, they are modeled :ts fixed in the
DAM to produce: an accurate market and power flow solution. 7be: CAISO, as the Reliability
CiLwordinator, receives the demmid forecast and generation schedul.c.s for the next day 1h-mi EIM
BAAs and external BAAs,as well as the Area-`I o-Ama.Net Schedule Interchanges between HAAs.
For the l-PM solution,the CAISO proposes to include in the DAM footprint the PacifiCorp BAAs.
i.e. PACW and FACE,which arc modeled as individual BAAs in the EIM. Using similar market
features and technology optimization algorithm approaches employed in the EIM,the DAM Akil.l
produce optimal unit commitment and hourly energy schedules forsupply,resources in PACW and
PACE, subject to a power balance constraint for each of die w BAAs. in addition to the power
balance constraint for CISO arsd active transmission network constraints to CISE3. FACE. and
PACW. Energy transfers between PACW and FACE will be optimally scheduled. subject to
applicable scheduling limits,whereas the net energy transfer to or from CISO will be fixed at zero,
to prevent energy exchange be3tvveen ClSO and PacifiCorp that may impact the CAISO's DAM
solution.
As an intended standard l at.ure of the DAN-1, the CAISO%vill ako b,,- able to optimally schedule
ancillary services to nicet the c:>rrespt�nding requirements it) PACW and PACE. by designating
these BAAs as separate ancillary services regions with distinct requirements.
The ancillary- services are the following:
« Regulation up and dawn.
+ Spinning Resenec and
• Nuri-Spinning Keserve
Pac:itiCurp upirc ws txzt BAAs,11aiciff'orp Fast.H AA(t'AC E)and Patc if iCcwp West.BAA(PAt:'W
20210 Protoct)l-ApI nudix D 9 4

Rocky Mountain Power
Exhibit No. 1 Page 117 of 134
Case No. PAC-E-19-20
Witness:Joelle R Steward
EXECUTIONVERSION
• All ancillary services have a 10-minute ramping requimment,which is shared a a"Ing the upward
anc:illany services. Both Spinning Reserves and Iron-Spinning Reserves are contingency reserves,
but Non-Spinning Reseme can also be provided by o#flinc; resources that can start up within 10
minutes. The upward ancillary services procurement is cascaded so that spin can meet-non-spin
requirements, and regulation up can meet both spin and Yvon-spin requirementti< to minimize the
overall procurcrnent cost.
Advisory Pricing
The day ahead settlement for the NPM is advisory,i.e.no4 financially binding between l'acifiCorp
and C:AISO. Day-ahead energy and ancillary service prices for )PacifiCbrp resources will be
published in CAtSO Market Results Interface for PacifiCorp, but they will not he published- in
Open ,Access Same-time Information System (OASIS) in the public domain. Similarly, the
publication of i..ocational Mdrginal Prices at KACW and PACE:pricing nodes (generally referred
to as Pl'odes)will Ix-,suppressed in OASIS.
Q? Protocol-.A+penciix 1.) 1.

Rocky Mountain Power
Exhibit No. 1 Page 118 of 134
Case No.PAC-E-19-20
Witness:Joelle R.Steward
EXECUTION'VERSION
EXHIBIT B
PacifiC orp's Estimated Costs of the Nodal Pricing Model
CAISO Grid Management Charge or Sete ices lee -$IB to 10 milli:313 per year
Capitalized PacifiCorp Start-Up Costs for Energy Supply Management and Settlement
Processing - $3 to$S million with 100%applicable to a.Future Extended Day-Ahead Market
(EDAM)
Capitalized CAISO Implementation Fee—SI to S?million(termed on Energy In3halarwe Nfarket.
or EIM, implementation fee)cane-time cost
Ongoing Operations and Maintenance Expense-- $500,000-$700,000 per year
Benefits of the modal Pricing Model
The NPM is lacing developed to allocate actual NTC as states move to unique generation
portfolio,".111 NP1t is intendW to hclp preserve the sy=stem benefit of operating,as a single
systetrt.
CA]Ws cxisting tec-hriology platform is intended to reduce both schedule and budget risk to
quickly implement the NIT allocation methodology that Pacif Corp is seeking to implemcat
based can the N41 lei solution.
• In addition to providing a method to allocate NfxC, the NJIM potentially of'lers the follo,�Ning
best:fits from cuing the CAISO market optimization tool:
• It provides more granular dispatch information resulting in anticipated operational cost
savings.
• It allcat PaeifiCorp to leverage('AlWs independence as a t` itt3 part4 nutrket provider.
* It guar tees that the.solution i3utcorne is consistent with die€.ALSO EIM iratkzt
solution since it is using the same exact tool and input data.
• 1t leverages the effort and money used to guild and maintain a complex and granular
heal-dine network model thatt is used in the actual market nin.
• It util izes the satrts schcdule data for in(croa.l and external resources infonning the
potential for unscheduled loop flows aid is informative-.vhen p..rffortning congestion.
management and potentially enforcing physical floNv transmission constraints.
Lastly,if'the CAISO ofTers a Day-Ahead Market to external entities for optional participation,
the NI)M solution development would allow Pac.ifCorp to seamlessly participate in the CAISO
ED IVI,if and when Pac;ifiCorp decides to join that market.
2020 Protocol-Appendix 13 13

Rocky Mountain Power
Exhibit No. 1 Page 119 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Wtness Joelle R. Steward
APPENDIX E
Coal-Fueled Interim Period Resource Depreciation Lives
------ ----.............._._..........._........-.........._............................................................................. ..........................................................................
2012 2018
Depreciation Depreciation
In . ..Stud:Life__ Study Life
Unit Other .. .......i.................. Capacity Physical
Service PP RMP (NM Location
I
OR States States States
A B C D E F i G H 1
Lives Addressed by Section 4.1.3.1
Apr- Apr-
Cholla 4 1981 2028 2042 25 25 387 Arizona
Colstrip 3 1984 2032 2046 2027 2027 74 Montana
Colstrip 4 1986 2032 2046 2027 2027 74 Montana
Craig 1 1980 2026 2034 2025 2025 82 Colorado
Craig 2 1979 2026 2034 2026 2026 82 Colorado
Lives Addressed by Sections 4.1.3.2 and 4.1.3.3
Dave Johnston 1 1959 2023 2027 2023 2027 99 Wyoming
Dave Johnston 2 1960 2023 2027 2023 2027 106 Wyoming
• Dave Johnston 3 1964 2023 2027 2023 2027 220 Wyoming
Dave Johnston 4 1972 2023 2027 2023 2027 330 Wyoming
Hunter 1 1978 2029 2042 2029 2042 418 Utah
Hunter 2 1980 2029 2042 2029 2042 269 Utah
Hunter 3 1983 2029 2042 2029 2042 471 Utah
Huntington 1 1977 2030 2036 2029 2036 459 Utah
Huntington 2 1974 2030 2036 2029 2036 450 Utah
Jim Bridger 1 1974 2025 2037 2025 2028 354 Wyoming
Jim Bridger 2 1975 2025 2037 2025 2032 359 Wyoming
Jim Bridger 3 1976 2025 2037 2025 2037 349 Wyoming
Jim Briidger 4 1979 2025 2037 2025 2037 353 Wyoming
Naughton 1 1963 2028 2029 2028 2029 156 Wyoming
Naughton 2 1968 2028 2029 2028 2029 201 Wyoming
Wyodak 1978 2026 2039 2026 2039 268 Wyoming
Lives Addressed by Section 4.1.5
Hayden 1 1965 2023 2030 2023 2030 44 Colorado
Hayden 2 1976 2023 2030 2023 2030 33 Colorado
(1)The life of coal plants for Washington is addressed in Section 4.1.4.
2020 Protocol-Appendix E 1

Rocky Mountain Power
Exhibit No. 1 Page 120 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R. Steward
APPENDIX F
Washington Inter-Jurisdictional Allocation Methodology
Memorandum of Understanding
•
•

Rocky Mountain Power
Exhibit No. 1 Page 121 of 134
Case No. PAC-E-19-20
Witness:Joelle R. Steward
The Washington Inter-Jurisdictional Allocation Methodology
0 Memorandum of Understanding
Introduction
PacifiCorp d/b/a Pacific Power and Light Company (PacifiCorp or Company), Staff of the
Washington and Utilities and Transportation Commission (Staff), Public Counsel Unit of the
Washington State Attorney General's Office (Public Counsel)and Packaging Corporation of
America(PCA), have executed this agreement(the Parties or, individually, a Party) enter into
this Memorandum of Understanding(Agreement)to acknowledge their support for certain
adjustments to the West Control Area Inter-Jurisdictional Allocation Methodology (WCA).
Background
PacifiCorp is a multi jurisdictional electric utility that provides services in six states (California,
Idaho, Oregon, Utah, Wyoming, and Washington). Staff is participating in PacifiCorp's Multi-
State Process(MSP), working towards the Company's goal of developing a common cost
allocation methodology amongst these six states. Currently, Washington uses the WCA for
determining which costs are eligible for recovery in rates from customers in Washington.'
As approved by the Washington Utilities and Transportation Commission (Commission), the
WCA isolates the costs and revenues associated with assets located in the Company's west
• "control area" or"PacifiCorp West Balancing Authority Area" (PACW), and allocates to
Washington a proportionate share of the costs and revenues based primarily on Washington's
relative contribution to demand and energy requirements. The WCA includes loads, generation
and transmission assets, and wholesale contracts for facilities located in California, Oregon, and
Washington. It also includes transmission and generation assets located outside of California,
Oregon, and Washington that are electrically located in PACW. The WCA excludes all loads and
assets located within PacifiCorp's East Balancing Authority Area(PACE).
In the context of inter jurisdictional cost allocation, the Commission will consider a resource to
be used and usefid to Washington customers' if the resource"provides quantifiable direct or
indirect benefmv to Washington[ratepayers]commensurate with its costs.,,3 To modify the WCA
methodology, "any changes should be considered in the context of an overall review of that
methodology."' 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 a persuasive showing demonstrating that the proposed change is
appropriate."'
1 Prior to the WCA methodology being approved in Docket UE-061546.PacifiCorp proposed the Revised Protocol
as its cost allocation methodology in Docket UE-050684.The Revised Protocol presented costs as an integrated six-
state system.The Commission rejected the Revised Protocol because there was not sufficient evidence in the record
that the methodology complied with the legal requirements in RCW 80.04.250.See generally UE-050684.Order 04.
'See RCW 80.04.250
3 Docket UE-050684,Order 04 ¶ 68.
'Docket UE-130043,Order 05¶92-94.
Id.
61d.
2020 Protocol-Appendix F 1

Rocky Mountain Power
Exhibit No. 1 Page 122 of 134
Case No.PA E-19-20
The Washington Inter-Jurisdictional Allocation MethodolOMn 131�I t nderstanding,
Page 2 of 7
Foundation for this Agreement
In this memorandum of understanding, the Parties agree to support certain modifications to the
WCA in the Company's forthcoming rate case provided the Company can demonstrate that the
modifications within this agreement provide beneficial resources to Washington customers that
are used and nsefiil. In particular, the Parties agree to support these modifications if PacifiCorp
can demonstrate these modifications provide quantifiable direct or indirect benefits to
Washington customers, and that these benefits are commensurate with their costs.' The Parties
agree to work collaboratively with PacifiCorp as they make this demonstration. However, as the
party advocating for these changes, PacifiCorp bears the legal and factual burden to sufficiently
demonstrate that these modifications better align the cost allocation methodology with the
principles described above in its forthcoming general rate case.
This demonstration may include the following benefits:
• A diverse generation portfolio, including an increase in high capacity renewable
generation.
• Over 170 interconnections with other BAAs and transmission operators providing access
to market hubs for wholesale energy transactions (e.g., Mid-C, COB, Mona, Four-
Corners and Palo Verde).
• Greater Energy Imbalance Market(EIN4)benefits.
• Efficiencies, such as retail load characteristics and variable resource diversity, which
40 minimize operational costs and reduce the need to build for reserves and blackstart
capability for each state.
• Washington recently enacted Senate Bill -5116, the Clean Energy Transformation Act
(CETA)which, among other things, requires the elimination of coal-fired resources from
PacifiCorp's electric rates by December 31, 2025. PacifiCorp's proposed modification to
the WCA will facilitate a reasonable path towards PacifiCorp's compliance with CETA.'
Based on this understanding, the Parties agree to the following:
Agreement
1. Implementation. This Agreement includes modifications to the � CA subject to
approval by the Commission.
The Commission has stated that one way the Company can demonstrate this is"through historical system operation
or modeling of the system shoeing that Eastside plant costs added to Washington rates would be offset by
reductions to other cost categories(e.g..power costs),such that overall costs to Washington ratepayers would be no
more than without the Eastside resources."Docket UE-050684,Order 04 ¶ 69(emphasis added).
a CETA also sets a policy of 100 percent clean energy by 2045.RCW 19.405.050. Additionally. CETA establishes
an interim target of 100 percent greenhouse gas(GHG)neutral by 2030,and allows utilities to meet this requirement
through 80 percent non-emitting energy and an alternative compliance option,including up to 20 percent unbundled
renewable energy credits. RCW 19.405.040.
2020 Protocol-Appendix F 2

Rocky Mountain Power
Exhibit No. 1 Page 123 of 134
Qa5e No.PA 9-zq Washington Intcr-Jurisdictional Allocation MethodoloA7.4 wwwAwnderstanding,
Page 3 of 7
1.1. PacifiCorp will file a rate case that allows for rates to go into effect(after
suspension)on or before January 1, 2021. This rate case will use this MOU as the
basis for any proposed modifications to the WCA.
2. Prudence. The proposed allocation of a particular expense or investment under this
Agreement 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 this Agreement 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. Quantification and Analytical Support. The Parties agree to work collaboratively and
in good faith to agree on the quantification and analytical support necessary for the
Company to meet its legal and factual burden.
3.1. This analysis should be substantially completed before the filing of the general rate
case referenced in section 1.1 and with enough time to reasonably allow parties to
review the analysis.
• 3.2. Before the general rate case referenced in section 1.1 is filed, if a Party determines
that the Company's quantification and analytical support does not demonstrate that
the Company can meet its legal and factual burden, Parties have the option to
withdraw their support from this agreement.
3.3. After the general rate case referenced in section 1.1 is filed, if a Party determines that
this agreement does not result in fair,just and reasonable rates for Washington
customers, a party may withdraw from this agreement. The withdrawing Party must
provide testimony in the general rate case explaining why this agreement does not
result in fair,just and reasonable rates for Washington Customers.
3.4. In the event of a Party's withdrawal, the remaining Parties may continue to support
this Agreement for approval in any proceeding before the Commission.
4. System Transmission. The Parties agree that all existing system transmission' costs and
benefits will be allocated using the System Generation(SG) factor as specified in
Attachment 1.
4.1. Rate Impacts: To mitigate the immediate overall rate impact to Washin�oton
customers in the rate case referenced in Section 1.1, Parties agree to support the
framework of the following phase-in approach:
• °Existing transmission includes any transmission asset that is in service as of December 31,2019.
2020 Protocol-Appendix F 3

Rocky Mountain Power
Exhibit No. 1 Page 124 of 134
Qa5e No. PA
c�i, -E-19-
The Washington Inter-Jurisdictional Allocation Methodol ;g� t nderstanding,
Page 4 of 7
4.1.1. An incremental allocation of one-third of existing transmission costs and
benefits, which are not currently allocated to Washington under the current
WCA methodology, will be included in the rate case referenced in Section 1.1.
4.1.2. An incremental allocation of an additional one-third of existing transmission
costs and benefits, which are not currently allocated to Washington, will be
included in a separate tariff rider with a rate effective date on or before
January 1, 2022.
4.1.3. An incremental allocation of an additional one-third of existing transmission
costs and benefits, which are not currently allocated to Washington, will be
included in a general rate case or through an amendment to the separate tariff
rider set forth in Section 4.1.2 with a rate effective date on or before January 1,
2023.
4.1.3.1. The incremental allocation in 4.1.3 will exclude the costs and benefits of
all transmission-voltage, radial lines connecting resources not otherwise
included in Washington rates to PacifiCorp's interconnected, network
transmission system. If PaciftCorp is required to include a portion of a
transmission line in its interconnected, network transmission system for
open access transmission service due to a subsequent generation or load
• interconnection, PacifiCorp may request to include such portion of the
assets in a subsequent rate case.
4.1.4. The separate tariff rider described above will remain in place until the fully
allocated cost of transmission costs as described in Section 4 is included in
rates through a general rate case.
4.2. New Transmission. Any new transmission10 incremental to the existing
transmission described and included in Section 3, will be system-allocated using the
SG factor as specified in Attachment 1.
4.2.1. Similar to the methodology outlined in 4.1.3.1, Transmission which can be
demonstrated to be used primarily for the transmission of power from
generation assets which are not assigned to Washington under the WCA, as
modified by this Agreement, will be excluded from this and any other
allocation to Washington.
4.3. Analytical Support. As a part of the analytical support in Section 4, the Company
will quantify the differences between total depreciation and ADIT balances using a
WCA Allocation of transmission and the system allocation above.
• 10"New"shall constitute assets used and useful for Washington customers after December 31,2019.
2020 Protocol-Appendix F 4

Rocky Mountain Power
Exhibit No. 1 Page 125 of 134
The Washington Inter-Jurisdictional Allocation Methodok ,� understanding,
Page 5 of 7
5. Non-Emitting Resources. The Parties agree that all existing and new non-emitting
resources will be dynamically allocated using the SG Factor specified in Attachment 1.
5.1. Assignment. If by December 31, 2023, none of the Parties to this agreement have
signed a new cost allocation methodology with the Company, then the Company
agrees to engage in collaborative conversations with the Parties and other interested
Washington stakeholders to explore the following:
5.1.1. An Assignment method for new resources for the purposes of the WCA; and,
5.1.2. A methodology to allocate fixed shares of existing non-emitting resources.
6. Net Power Costs (NPC). Forecasted NPC for ratemaking purposes will be consistent
with Sections 1,4,5,6, and 7 of this agreement. Additionally, Washington customers will
receive all direct and indirect benefits associated with their proportional system-allocated
share of existing transmission, including Energy Imbalance Market benefits.
6.1. Actual NPC. Actual NPC for ratemaking purposes will include only the generation
resources included in Washington rates and will be calculated using a spreadsheet.
6.2. Qualifying Facilities. The costs and benefits of Power Purchase Agreements for
Qualifying Facilities(QF PPAs)will continue to be situs assigned to the state having
jurisdiction over the QF PPA for cost responsibility, renewable energy credit
assignment and resource planning.
7. Accelerated Depreciation. PacifiCorp and Staff agree to support a final depreciation
date of December 31, 2023, for Bridger Units 1-4, Colstrip 4 and any transmission assets
associated solely with the interconnection of these units to the transmission network. This
date does not represent a date of estimated closure, changes in operations, or the end of
the assignment to Washington of either benefits or costs associated with these plants.
Public Counsel and PCA reserve the right to make a recommendation on the depreciation
for Bridger Units 14, Colstrip, and any transmission assets associated solely with the
interconnection of these units to the transmission network in PacifiCorp's forthcoming
general rate case.
7.1. Capital Investments. Washington will continue to be allocated a WCA share of
ongoing capital investments expenses for these plants, excluding incremental capital
investments that are made primarily for the purpose of extending the life of these
plants. Incremental capital investments that are made primarily for the purpose of
extending the life of these plants includes, but is not limited to, those associated with
achieving compliance with environmental requirements or those necessitated by
catastrophic failure.
7.2. Deadline for Removal. Consistent with RCW 19.405.030, PacifiCorp will remove
from Washington rates all costs and benefits associated with Bridger units 1-4 and
Colstrip unit 4 no later than December 31, 2025.
2020 Protocol-Appendix F 5

Rocky Mountain Power
Exhibit No. 1 Page 126 of 134
a c No PA -E-19
The Washington Inter-Jurisdictional Allocation Methodolcm, I p �Jnderstanding,
Page 6 of 7
• 7.3. Resource Flexibility. The dates articulated in this section are agreed upon by parties
to facilitate the removal of coal from Washington Rates by 2025, and provide the
flexibility that may allow for early compliance with CETA.
8. Decommissioning Cost. Washington will continue to be allocated ongoing and expected
decommissioning expenses for a WCA share of Jim Bridger Units 14 and Colstrip Unit
4.
8.1. Colstrip Engineering Study. The Company will provide by March 30, 2020, an
independent engineering study of estimated decommissioning costs for Colstrip.
8.2. Jim Bridger Engineering Study. The Company will provide by January 15, 2020,
an independent engineering study of estimated decommissioning costs for Jim
Bridger.
8.3. Cost Assignment. To facilitate the allocation of decommissioning costs, Parties
agree to support a system allocation of the costs associated with an independent
engineering study in 8.1 and 8.2.
9. This agreement proposes modifications to the WCA, which serves as the basis for
allocating costs in Washington. PacifiCorp will allocate costs based on the WCA
consistent with the modifications in this Agreement for ratemaking purposes in
Washington unless a different cost allocation method is approved by the Commission.
10. Each Party to this Agreement represents that they are signing this Agreement in good
faith and that they intend to abide by the terms of this Agreement.
11. This Agreement may be executed in counterparts and each signed counterpart constitutes
an original document.
12. Attachment 1 contains updated allocation factors consistent with this Agreement.
13. This Agreement is entered into by each Party on the date entered below such Party's
signature.
2020 Protocol-Appcndix F 6

Rocky Mountain Power
Exhibit No. 1 Page 127 of 134
9-20
The Washington Inter-Jurisdictional Allocation Methodolq -nr ►j understanding,
Page 7 of 7
PACIFICORP STAFF OF THE WASHINGTON
UTILITIES AND TRANSPORTATION
COMMISSION
By: By:
Title: Title:
Date: Date:
PUBLIC COUNSEL PACKAGING CORPORATION OF
AMERICA
By: By:
Title: Title:
Date: Date:
2020 Protocol-Appendix F 7

Rocky Mountain Power
Exhibit No. 1 Page 128 of 134
Case No. PAC-E-19-20
Witness:Joelle R. Steward
The Washington Inter-Jurisdictional Allocation.Methodology Memorandum of Understanding,
Page 7 of 7
•
PACIFICORP STAFF OF THE WASHINGTON
UTILITIES AND TRANSPORTATION
COMMISSION
Title: V<t 'i=-1%`7 �s 1- � '� Title:_......................_ _.........._._............._..........
_ ....
Date: No v�e rat i tff:- i fj Date:
PUBLIC COUNSEL PACKAGING CORPORATION OF
AMERICA _—
:.
Title: Title: r)*1P1 ,,R......
. e o..r
Date: Date: t ° Z, !
•
2020 Protocol-Appendix F 8

Rocky Mountain Power
Exhibit No. 1 Page 129 of 134
Case No.PAC-E-19-20
Witness:Joelle R.Steward
The Washington Inter-Jurisdictional Allocation Methodology Memorandum of Understanding,
• Page 7 of 7
PACIFICORP STAFF OF THE WASHINGTON
UTILITIES AND TRANSPORTATION
COMMISSION
By: By: A
Title: Title: ,U 41c 41, "/0/1-1 .5;4w lel 7
Date: Date: A4y
PUBLIC COUNSEL PACKAGING CORPORATION OF
AMERICA
By: By:
Title: Title:
Date: Date:
2020 Protocol-Appendix F 9

Rocky Mountain Power
Exhibit No. 1 Page 130 of 134
a e No. PA 9-ZQ
The Washington Inter.-Jurisdictional Allocation Methodolrm„ '13�ii�trt. ?nderctandine,
Page 7 of 7
PACIFICORP STAFF OF THE WASHINGTON
UTILITIES AND TRANSPORTATION
COMMISSION
By: Bv:
Title: Title: .-.-- ---
Date: Date:
PUBLIC COUNSEL PACKAGING CORPORATION OF
AMERICA
By: By:
Title: Assistant Attorney General
Y� Title.: ___-
Date: 11/21/2019 Date:
•

Rocky Mountain Power
Exhibit No. 1 Page 131 of 134 EXECUTION VERSION
Case No.PAC-E-19-20
Witness:Joelle R.Steward
APPENDIX G
Special Contracts
Special Contracts without Ancillary Service Contract Attributes
For allocation purposes, Special Contracts without identifiable Customer Ancillary Service
attributes are viewed as one transaction.
Loads of Special Contract customers will be included in all Load-Based Dynamic
Allocation Factors.
When interruptions of a Special Contract customer's service occur, the reduction in load
will be reflected in the host jurisdiction's Load-Based Dynamic Allocation Factors.
Actual revenues received from Special Contract customer will be assigned to the State
where the Special Contract customer is located.
See example in Table 1.
Special Contracts with Customer Ancillary Service Attributes
• For allocation purposes, Special 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 Customer
Ancillary Service Contract's rate.
Loads of Special Contract customers will be included in all Load-Based Dynamic
Allocation Factors.
When interruptions of a Special 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 Special Contract customer, before any discounts for Customer
Ancillary Services attributes of the Special Contract, will be assigned to the State where
the Special Contract customer is located.
Discounts from tariff prices provided for in Special Contracts that recognize the Customer
Ancillary Services attributes of the Contract, and payments to retail customers for
Customer Ancillary Services will be allocated among States on the same basis as System
Resources.
See example in Table 2.
2020 Protocol -Appendix G 1

Rocky Mountain Power
Exhibit No. 1 Page 132 of 134 EXECUTION VERSION
Case No. PAC-E-19-20
Witness:Joelle R. Steward
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 Special Contract
customer load associated with the buy-through will be not be included in the calculation of
Load-Based Dynamic Allocation Factors, and the revenue associated with the buy-through
will not be included in State revenues.
2020 Protocol -Appcndix G 2

Rocky Mountain Power
Exhibit No. 1 Page 133 of 134
Case No.PAC-E-19-20
Witness:Joelle R.Steward
c3ib�G•
Interruptible Contract Without Ancillary Servtcf? Contract Attributes
Effect on Revenue Requirement
L:x.rry Tout s��enn 3rai�rtiitirsrr 1 Jtrri�•i!c£:•or.i furfsdiciicra 3
2.i;tryr!ictieae,H irsaets-;to t:�lere::�ik'�te�isx
r.turi4docnai 8cetr at 12 nr-6r"} CP•?emarsd(t51'vk) 72.003 ;4.000 3b,i333 12•rD3C
4 Er s bcfiaruzi Annnm*Fmwgy(?e5 kh) a 00).cm 14,iD3+3.(tAu' 2I'-;?£,rf.`r(t 7,m":Lz ffi:0
5
i J:x wkdmna!Loa-ft-i Y&.Inmmm rf:5fe Se:ice- R*aCtmq Achaa!ircterrurs"r.
T,tS f.ckbo:at Sivn a'12 monthf f CY defftand OAWi 11.700 24,0W 145,7w 12,iD3tf
R Jrrrst sttiarat t-.fmw. E:rerr2S(Ak':) 4I.W.500 14.,1,r..fft- 14),36J, it 7,Of Qf,1ti0
9
10 Smciat Cottba:t C;rsb me Reis-ue old Umd-Non intemipMe aet\•:ce
11 Saaai t oni act(;rOMOr}ti WVWe S 29.0W.000 S 2(I.Y-X.=,lr O
12*toaa!(:ct*ad Cats amw Gain of 52 CPs(t W1 lm-. dec in titre 2) NO Rk -
13 tivaaaf Cu:et xi Amstntf Energy(t/14S#;(Inctude8 is sae 3} 50-U-00 5,)C.m)0
S4(
t 5 Soma! Gv*act Cksb;mec River ue w d Load-14tW-3niemjpfitae Sere¢--(75 IN"Y 53G t)o=of bdam"hart;
16 Via!Contad Cusww Rr;"e:x e S i?i 0(}S).Gfi3 5 tCs;)3t;rJf3(i
17 Cir-coum.W Are fty Services
I£vei Cost to Spetsse!fisrAnkcaCt,stcenrtx' 3 ia.f)1k3 t103 5 1t,Jir0;33:r
19 Special Crnnttact stun t f 12 GP- Reft c§gg.Actua!tntcrtup6ons im's';(tnrbdtxt in fi<a 71 (430 tx3 i
20??Tecaat Cm(,ad.4 mutt nesgr-Rei sar:fi:rg Ac-.K;d s isr of+iicttts 0MVV:'(IfwAKkA Ri!tee 8) 462.540 45 c,rfrir
21
w?Sygwr S 4vL'iC6 fi_e2r Lmer2ptm $4.6V3,000
23
24 Mocat(vn Factoty
25 No tm.-rFWhbk,`se;oce
25 SE fantm-((;ak..n`aiad f+nm!i:e 4) SE 1 i fdr 00% 33.33% W.M. , 14S.67%
2?SC taclw(Ca3cu4ted fmm,7ne 3y SiC 1 '(10.00% 3a.33% Y6.00% 16 v7%
28 SG fnrtor One 27175%a iirre:tS'2'3 S; SG I 3(30.PU% 3,133% 15.61%
29
30 S^frtix FxstrruN4:tdr+ rs arCe Relit 3mg kctu ri?)ryw.ai urtytrrt s!%ts;
31 SE factor(Cak".ec imm line y) SE2 10 00% ?:3.3eG% 49,963% 16-62%
32 SC fat for(Calculated from kv 7) SC2 i00.QQ'% 33.419'9 49.7914 16.74%
es SG€eclat(Erne n2'Is4a s:kw M'25%) SG2 %X).(3(t°% 3'.S 45;i, 4S.83% 16.72 0
36 No Interruptible Service
37
38 Cost of Setvit:e
35 Erremy C*,%t SE 1 5 533.0%000 c 166,E.66 W, S 250,000,333 S 83,3?,3,333
40 Lnc t. l-wid Rbu-d Costa V4 I S 1.fKk'3.W.MG S 333,333.333 S 5U0:XYi,(f9v S 166,n6-6,6F7
41 Stenof?s%t 3 t.5 s300.0 O S R)PI.O (f.(10:1 $ 7%.000,0W. S 25 ,f3e"£;'3Csr
42
43 RovmIls
44 Spe i!C.uvnfratl Rw,r n.ire &-,Ws S 2:3 002.006 20;M,006
45 Revt�me%fitrtt aftsxfw cusumnem C:tt:s $ 1.48030000 S W),O:'Xt 0,^ £ F3t3,t3ffEfsnw S i*'i0,0w.0m
46
e7
as 'Aft frAerruptible Service
49
. f cast.C4 Cetvfce
51 ErnerT/Co% SE2 S 49310W.04M S 166,148,347 $ 248,717,433 $ 0,074,173
52 Gamar:d RetaRe?L:ssts SG? S 99 0ftn.Of3f3 S 334,05f3,571 S 496,912,134 $ IFT.029,289
63 Sum of:�bf $ 1 C36.it(33,iCti? $ 500,2061924 $ 745.s1'.S,514 5 —KC,10,46 2
54
S5 Rrireturea
.A sper6ai C.rmFacl Re"m t:e `itrts S 1 0m.m. $ 3�i:3(Qi,JCSL
57 Revenues from aft caller customers Sdus S 1:48000,000 S W,2W.424 S T4,1in,614 S M.103:462
2020 Protocol-Appendix G i

Rocky Mountain Power
Exhibit No. 1 Page 134 of 134
Case No. PAC-E-19-20
Witness: Joelle R. Steward
• Table 2ContractInterrupt€biContractWithWith Ancillary Service CQlitir-c'3Ct Attributes
Effect on Revenue Requirement
i:i:tet 1 cis£*v,�teni ,tr_visrlit*ixt 1 Jun e# f, i5 Z ,M6SdictiGn 3
£
2 3:.sive!tctkwai kfrae?s-:4n In4w:up"Setvice
3 Jiz;sdiidionai Sitar of 12 nxa mMy CP demaws{Wsh+ - 72,000 24,3W KWO iZ&M.
4 AR--,sf(icsrsai Amnia:Eiwruy if.Kl-.) 14,006.9M 21;3 if,(Kiif 7,E):1 X?e
5
6 Juti�t>iLfionai£-e3ds-Y'itft£sites•c>fpftJEk.Serrtcs- Re^sctii;6 Acltzzi ifeti:rr�rst!tiir,
7.fsR'Sckc6 rat S m:of)2 rront"A CP demand(WW, 711.71313 240X, -,6,7w 12,9;iti
£3.f ndf.iorca)Awua`•Fiwrg t?L"c?3 41.962,560 14JIM.GM, i33.#i2.rstw i,3Y?.iKst
9
10 Sc*cia£Cont~ad Cusif mef Reiwwe and Load-Wo.biiemaptikde Senvc¢
l)002i i:•aWact f,assA7atier Rkevvviue S 202000.M) 5 20.00C.DJt7
12 Ssetaai Coii3.• Ctr>tomv-Sum of 12 CPs(MVj ti:x:Wud in Wte 21 9W RW
13:4xaa c£C,-NWuL1.fvinuz£Etwg ; VV1s (3nc£uded in 4m 3, 509.Ca 5xgx,
14
15 Speaai Contact Cusifsnw Revemm and LoM-♦Vif),internipWo Service(75 bNrr*X 5r3E3 Naurs of tsSfeTsjafoat;
16 TwOf UquivaMM Afrwvxm S 23,6.%10,00 5 2fY'(W.,(lN
17 T"Okaiy SOMO-'Discau--*foc lf�rAV X 5W Hour c4 Economise OjfWrnstiE S ;4,frC.Ov,)
IS Net Cv,A to Spac£at Cfsf my Custcsrrzx' 3 ?S.slilt3 tSG� S 1&, ;33f]
i9 Special Cumract Swit rf Q CP- Re£kcl;ng.Adaxai lnicjctt,,4ms?kw,d (111c3:sded o 1s 71 &W
20 Silmaai Cant:ad?im"Enwg f-Refiscii,s3 Act W i P-ffufAMs (fMitKW- a;lins F.) Sti2. 60 462,C436
21
22 3011em Cost Swop Fans InterruplAvi S4.f3L39,isfX3
23
24 A111n mi-0ti Factoyy
25 tit;lronitiiribW S.;W-e
.n+SF far3ua'{E;aicufaw;innii$ie 4) RE? t(i(i t3 % 13-M% 54.40% M67%
27 SC factor(,;alw-tated tram aye 3i Jc r 100.00% 33.33% 16 tit%
29SGtactoc Om27'7§%+i i(i'2394; Sal 1W.M'% 33.33% 1667%
29
30 With irisPrrprt*Semte-RM"stiy At,,,jal Ptfyw.al iris rsrsSoirr)
31 SE factor(Cak".ed imm fine°) SE2 :00 t)0% 13.3% 49.96% 1ri.GM
32 SC faa for(C.A:utated from)fsc 71, Sr-2 :00 00% 33-47% 49.9% 16.74%
SGfacfx(fine 12'15%+ime 31*25%l SG.' ?til00% 33.45% 49.113% 116.r2%
3S No fntefruptible Service
37
39 tot Yfca
Mi Energt Cost NE: S 3.Gi(lis,t)a?l3 S 166;W.W, S 250,(67U;3%-1 S 83,333.333
40 .CW,3 SGI S 1.:fift'1.t21?'3.M1 S 333.133.333 $ C4;1flf.:f3Cs S t6fs;5fi6,fi$T
4 i S er of?>ast S f::,t£Ct f3M.M S iI,flf)C,50iA $ 7z;0,013C.'ClCiCi S 2,C.W ,O)O
42
43 Rey--nijis
44 dal Q.nUact tiiY-mt.a S'tit9 S 2 U L`tN3.000 S 20"VC-,33(r
45 Revesm j from ail oldies custcsnets `itus $ 1,4,90 M3#3,M) $ 0),i)£lnbOt S ru)3 3t1(1,w S 250.0•3fi,(t:xi
:6
47
49 With Intesruptlble Service&Ancillary Service Contract
43
So Cow C9 feivlt:e
51 Enermf Cost SE i S 49U.11Q OOD S 1fiE,tILH1,13iJ:) S 249,4 ).0-3u $ 83,Cani,i33�
62 t•ema^td R49aW NASA SG£ S M.L'(liK-00 S 332.W.66T S 499.4Y)@,IM $
53Ani1£asy&-4vifzCantra:f-E:LMcrssicCurtta ifrree.(L martai SG1 S 2.M,WO S 6€6:6v S t,O"WOV, $ 333,33?
64 AwAvy Sw,&x(ArArac:t-L.t fmurk Qviagmant( nti yY) 3E 1 S 2.Ms."0 S &%,667 S •,kX,i>S?£ S 333,33.3
55 SUR)tit cos: i 1:h3f3.f1(lif,a`tX3 S 5(3G,(i(R;,i3fli3 S 750,t-R)s;J G S 25E,O0O,O3C
56
57 eve
SS Specaz!Cont adRevenue Stirs $ 20.600:•ii£(i S -,V Ow,On-^
59 Revenues from ail o@iar customms 3:tus S 1.41!10,0 iti,9 V S SWIM OM S 73?),34r'U" S M,ti,^•c�p51:
•
2020 Protocol-Appendix G 4.

REDACTED
CONFIDENTIAL ATTACHMENT B

Attachment B
REDACTED Page 1 of 2
Mid-C Market Price($/MWh) PV Market Price($/MWh)
- 76.18 64.89

Attachment B
Page 2 of 2
Start Date End Date Number of Days HLH LLH Palo Verde HLH Palo Verde LLH Palo Verde Flat Mid-Columbia HLH Mid-Columbia LLH Mid-Columbia Flat Chehalis
1/1/2023 1/31/2023 31 400 344 141.44 128.70 135.55 146.06 145.07 145.60 15.91
2/1/2023 2/28/2023 28 384 288 69.32 63.75 66.93 91.57 72.67 83.47 7.53
3/1/2023 3/31/2023 31 432 312 61.37 66.22 63.40 87.31 83.67 85.78 5.66
4/1/2023 4/30/2023 30 400 320 63.37 67.59 65.24 104.77 82.49 94.87 8.03
5/1/2023 5/31/2023 31 416 328 28.01 21.34 25.07 19.97 6.80 14.16 2.42
6/1/2023 6/30/2023 30 416 304 34.94 29.79 32.77 49.38 37.08 44.19 2.93
7/1/2023 7/31/2023 31 400 344 111.49 76.17 95.16 98.15 63.29 82.03 3.45
8/1/2023 8/31/2023 31 432 312 134.33 60.77 103.48 129.23 53.93 97.65 3.73
9/1/2023 9/30/2023 30 400 320 45.04 37.19 41.55 63.39 39.91 52.95 2.40
10/1/2023 10/31/2023 31 416 328 59.89 50.96 55.95 104.51 70.37 89.46 2.99
11/1/2023 11/30/2023 30 400 320 52.30 51.65 52.01 75.43 63.70 70.21 4.49
12/1/2023 12/31/2023 31 400 344 39.95 39.09 39.55 56.40 49.37 53.15 2.85