20240521Reply Comments.pdf

_ ROCKY MOUNTAIN 1407 W.North Temple,Suite 330
POWER. Salt Lake City,UT 84116
A DIVISION OF PACIFICORP
RECEIVED
2024 May 21, 4:02PM
May 21, 2024 IDAHO PUBLIC
VIA ELECTRONIC DELIVERY UTILITIES COMMISSION
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 MILLON ECAM DEFERRAL
Attention: Commission Secretary
Pursuant to Commission Order No. 36153 providing public notice of the Company's Application,
authorizing the processing of the Application by Modified Procedure, and establishing the
procedural schedule 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,
Joe Steward
Senior Vice President, Regulation and Customer& Community Solutions

Joe Dallas (ISB# 10330)
PacifiCorp, Senior Attorney
825 NE Multnomah Street, Suite 2000
Portland, OR 97232
Email:joseph.dallas(a)pacificorp.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
MILLON ECAM DEFERRAL ) ROCKY MOUNTAIN POWER
Pursuant to Rule 202.01(d) of the Rules of Procedure of the Idaho Public Utilities
Commission ("Commission") and the Commission's April 13, 2023,Notice of Application and of
Modified Procedure, Rocky Mountain Power a division of PacifiCorp (the "Company") hereby
submits reply comments in the above-referenced case.
I. BACKGROUND
1. On April 1, 2024, the Company applied for Commission authorization to adjust its
rates under the Energy Cost Adjustment Mechanism (`SCAM") and requested approval of
approximately $62.4 million in deferred costs 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").
2. On April 23, 2024, Commission Order No. 36153 provided public notice of the
Company's Application, authorized processing of the Application by Modified Procedure, and
established the procedural schedule allowing persons who would like to file written comments to
have until May 14, 2024, and the Company having until May 21, 2024, to file reply comments.
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3. In addition to the Commission Staff, P4 Production, L.L.C., an affiliate of Bayer
Corporation ("Bayer"), and PacifiCorp's Idaho Industrial Customers ("PIIC") filed a petition to
intervene and was granted intervener status in the case.
4. On May 14, 2024, Staff, Bayer, and PIIC filed comments (collectively "parties").
All the comments submitted recommend that the Company not be able to recover the costs it
incurred in 2023 associated with procuring Washington Climate Commitment Act ("CCA")
allowances that were necessary for the operation of the Chehalis natural gas facility("Chehalis").
PIIC also provides that the Company should receive an additional disallowance associated with
the Company's decision to consider costs associated with the CCA in its dispatch decisions of
Chehalis.' PIIC further provides a recommendation that the amortization of the 2023 ECAM
deferral balance should occur over a period of three years to mitigate rate impact.2 Bayer further
recommends that the Company should not be able to recover costs associated with compliance
with the Ozone Transport Rule ("OTR") because the U.S. Court Appeals for the Tenth Circuit
("10t'' Circuit") granted a stay the Environmental Protection Agency's ("EPA") final disapproval
of Utah's state implementation plan pending further disposition of the appeal.' Staff also provides
comments that the Company's operation of its coal plants during the deferral period and its coal
supply management activities were prudent.'
'PIIC Comments at 7, 14-14.
2 PIIC Comments at 3-4.
s Bayer Comments at 3.("[T]he U.S. Court of Appeals for the Tenth Circuit granted a stay of the EPA federal
plan.").On July 27,2023,the loth Circuit granted the Petitioner's stay pertaining to the EPA's final disapproval of
Oklahoma's and Utah's respective statement implementation plan regarding obligations under the OTR. Utah v.
EPA, Docket No.23-9509(loth Cir.July 27,2023)available at loth-Stay-Order.pdf(utah.gov).
4 Staff Comments 10-11 ("Staff believes the Company operated the plants prudently and sought alternative coal
supplies in a manner that mitigated costs while setting up its Utah plants to be a useful hedge against high prices in
the future.").
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II. REPLY COMMENTS
5. The Commission should deny the proposed disallowances of costs associated with
the CCA, OTR, and the request to extend the amortization period of the deferral balance for the
reasons set forth below.
A. The Commission should deny the proposed disallowance of CCA allowances costs
because they were prudently incurred by the Company to operate Chehalis in order
to serve Idaho customers.
6. It is crucial for this Commission to recognize that no party alleges the Company
acted imprudently in procuring CCA allowances, as securing these allowances was essential for
the operation of Chehalis during the deferral period. Indeed, if the Company were to operate in
accordance with the disallowance recommendation proposed by the parties it would not have been
able to operate Chehalis for the benefit of its Idaho customers. Moreover, no party suggests the
Company should have shut down Chehalis to avoid the need to procure CCA allowances. This is
likely because net power costs("NPC")would have increased in the deferral period, even with the
cost associated with the CCA allowances, if the generation from Chehalis were removed from
NPC. There also appears to be no recommendation that the Company should have willfully
violated state law and operated Chehalis without procuring CCA allowances.
7. Rather, it appears the parties' recommendation is that the Company should be
required to continue the 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. Essentially, the recommendation is to establish a disallowance on the premise that the
Company operated in compliance with applicable state law while engaging in interstate commerce
to provide electric service to its Idaho customers.
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8. The Commission should reject the recommendation to disallow the recovery of
CCA allowance costs because it violates fundamental ratemaking and constitutional principles. In
the alternative, if the Commission determines that the Company cannot recover its prudently
incurred costs associated with the operation of Chehalis, it should also remove the generation
benefits of Chehalis from the deferral balance as well.
i. Background of the CCA and the requirement to obtain allowances.
9. The CCA establishes regulatory requirements to reduce greenhouse gas ("GHG")
emissions from generating plants located in Washington.' One component of the CCA attempts to
reduce GHG emissions by establishing a market incentive for covered entities to reduce
emissions.' Generally, the CCA establishes a"cap" on the amount of emissions that are permitted
in the state,'which will decrease annually to meet GHG emission reduction goals.'An allowance
is required for each metric ton of carbon dioxide equivalent that the covered entity emits.9 The
Washington Department of Ecology ("Ecology") then distributes emission allowances to covered
s See RCW 70A.65.060(1)("In order to ensure that greenhouse gas emissions are reduced by covered entities
consistent with the limits established in RCW 70A.45.020,the department must implement a cap on greenhouse gas
emissions from covered entities and a program to track,verify,and enforce compliance through the use of
compliance instruments.").
6 RCW 70A.65.060(2)(h)("The program must consist of. . . [p]roviding for the transfer of allowances and
recognition of compliance instruments,including those issued by jurisdictions with which Washington has linkage
agreements[.]").
7 RCW 70A.65.070(2)("The annual allowance budgets must be set to achieve the share of reductions by covered
entities necessary to achieve the 2030,2040,and 2050 statewide emissions limits established in RCW
70A.45.020[.]").
8 RCW 70A.65.060(1)("In order to ensure that greenhouse gas emissions are reduced by covered entities consistent
with the limits established in RCW 70A.45.020,the department must implement a cap on greenhouse gas emissions
from covered entities and a program to track,verify,and enforce compliance through the use of compliance
instruments.");RCW 70A.45.020(1)(a),(a)(iv)("The state shall limit anthropogenic emissions of greenhouse gases
to achieve the following emission reductions for Washington state. . .By 2050,reduce overall emissions of
greenhouse gases in the state to five million metric tons,or ninety-five percent below 1990 levels.").
9 See RCW 70A.65.010(1)("`Allowance'means an authorization to emit up to one metric ton of carbon dioxide
equivalent.").
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entities, which function as financial instruments that the covered entities may trade to meet their
own emission needs.10
10. PacifiCorp is a "covered entity" subject to the CCA because it owns and operates
Chehalis." The CCA requires that the Company demonstrate compliance by retiring GHG
allowances for any GHG emissions from Chehalis—even if the Company exports the energy
outside the state of Washington.12 Accordingly, the Company had to procure CCA allowances
during the deferral period in order to operate Chehalis for the benefit of its Idaho customers. The
NPC for the 2023 deferral period includes approximately $42 million, on a total company basis,
in costs associated with CCA allowance associated with the generation from the Chehalis. Staff,
Bayer, and PIIC oppose the recovery of these costs,while seeking to retain the generation benefits
from Chehalis in Idaho rates.
ii. The Commission should allow the recovery of CCA allowances as consistent with
the fundamental rate making principal of cost causation and the requirement to
set just, reasonable, and sufficient rates.
11. The recommendation to disallow the recovery of CCA allowances contradicts
fundamental ratemaking principles. Through ratemaking, state utility commissions strive to
allocate costs according to causation. The cost-causation principle compares "the costs assessed
against a party to ... benefits drawn by that party." 13 The Commission has recognized cost
10 RCW 70A.65.060(2)(c),(h)("The program must consist of. . .Distribution of emission allowances,as provided
in RCW 70A.65.100,and through the allowance price containment provisions under RCW 70A.65.140 and
70A.65.150; . . . [and]Providing for the transfer of allowances and recognition of compliance instruments,including
those issued by jurisdictions with which Washington has linkage agreements[.]").
11 RCW 70A.65.080(1)(b),(c).The CCA covers Chehalis because it is an electricity-generating facility in
Washington state with associated emissions of at least$25,000 metric tons of carbon dioxide equivalent.
12 RCW 70A.65.080(1)(b).
13 S.C.Pub. Serv.Auth. v.Fed.Energy Regul. Conan n,762 F.3d 41,87-88(D.C.Cir.2014);see also Jonathan A.
Lesser,Ph.D.&Leonardo R.Giacchino,Ph.D.,FUNDAMENTALS OF ENERGY REGULATION at 183 (2d ed.,
Public Utilities Reports,Inc.2013)("One fundamental regulatory principle is to allocate costs to those who cause
them.").
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causation as a "fundamental ratemaking principle,"whereby, to the extent practical, "utility costs
should be paid by those entities that cause the utility to incur those costs." 14 Additionally, the
Commission has emphasized that the principle of cost causation is necessary for "just and
reasonable"rates under Idaho Code 61-502, 61-503, and 61-507.15
12. In this case, the generation from Chehalis provides significant benefits to Idaho
customers, even with the additional CCA compliance cost. No parry contests that the Company
procuring CCA allowances to operate Chehalis was imprudent. Accordingly, Idaho customers
should bear the actual costs of Chehalis generation because they are receiving the corresponding
benefit. Chehalis generation decreased the deferral balance by approximately$23.6 million during
the deferral period, on a total-Company basis.16 This net benefit accounts for the increased
generation dispatch cost resulting from the purchase of CCA allowances. Therefore, even
considering the costs associated with the CCA,the generation from Chehalis results in substantial
net benefits to Idaho customers.
13. Neither Staff, Bayer, nor PIIC dispute the benefits of Chehalis or present any
evidence that Idaho customers are better off without Chehalis. Rather, these parties imply that
Idaho customers should continue to receive the generation benefits of Chehalis but not be required
to pay for the prudently incurred compliance costs necessary for its operation. The Company
operates in compliance with applicable law, including Idaho law, and cannot willfully violate any
state or federal law in its operations. Accordingly, the Commission should reject this
recommendation as it would have Idaho customers enjoying the significant benefits of a plant
"In the Matter of the Application of Idaho Power Co.for Auth. to Modify Its Rule H Line Extension Tariff Related
to New Serv.Attachments&Distribution Line Installations.Order No. 30955(Nov. 30,2009).
15 Id. Importantly,the cost-causation principle also aligns with the limitations outlined in the Fifth and Fourteenth
Amendments to the United States Constitution,which prohibit a state regulatory commission from setting
confiscatory rates that amount to an unconstitutional taking. Duquesne Light Co. v.Barasch,488 U.S.299(1989).
16 Direct testimony of Jack Painter at 24.
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without bearing the attendant and prudent costs for its operation, in violation of well-established
cost causation principles.This approach would ensure that rates are just,reasonable,and sufficient
under Idaho Code 61-502.
14. In the alternative, should the Commission decide to disallow the CCA allowance
costs, it should also remove all other costs and benefits from Chehalis from Idaho rates. If Idaho
customers do not want to pay compliance costs for Chehalis, then it is reasonable for Idaho
customers to not receive the benefits of Chehalis' generation. Otherwise, the Company will be
required to subsidize Idaho rates in a manner that is contrary to established ratemaking principles,
and results in rates that are not just,reasonable and sufficient.
iii. Customers in all the Company's jurisdictions regularly pay environmental
compliance costs imposed by the federal government and other states under the
2020 Protocol and the CCA allowances are no different.
15. PacifiCorp operates in compliance with applicable state and federal in providing
electrical service for its Idaho customers. Instead of acknowledging this reality,the parties instead
present various arguments that on how they disagree with the CCA.For instance,each parry argues
that the Company should not be able to recover these costs because the Washington legislature
decided to provide no cost CCA allowances to in-state Washington retail utility customers.
PacifiCorp also has concerns with certain portions of the CCA and has filed a complaint in federal
district court raising concerns regarding the constitutionality of certain provisions under that law.17
Nevertheless, these arguments miss the point. The issue before the Commission is not to debate if
parties agree with how the Washington Legislature designed the CCA. Rather, the question in this
PacifiCorp v. Watson,Case No.3:23-cv-6155(W.D.Wash.),filed December 15,2023.
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ECAM proceeding is whether Company acted as a prudent and reasonable utility in procuring
CCA allowances in serving its Idaho customers during the deferral period."
16. PacifiCorp is subject to numerous state and federal taxes and compliance
obligations that various parties may subjectively disagree with from a policy perspective,but that
is not a valid or principled reason to disallow the recovery of prudently incurred costs in this
proceeding. For instance, the Company must comply with numerous upgrades at generation
facilities that are necessary to comply with environmental requirements like fish passages at
hydroelectric plants, avian curtailment at wind facilities, and emissions controls at thermal plants.
Furthermore,the Company also pays production taxes to various state governments,either directly
or indirectly through the cost of fuel, in order to extract natural resources used for thermal plant
generation. These compliance costs directly impact the cost of generation at certain thermal units,
similar to the CCA.
17. Indeed, the proposed disallowance seeks to deny recovery of costs that are
functionally the same as other state assessments that PacifiCorp is currently authorized to recover
in its rates. For instance,the Wyoming wind tax provides a comparable example of how generation
taxes imposed by one state are paid for by customers in other states, including customers in Idaho.
Wyoming imposes this tax on every megawatt hour of electricity produced from wind resources
within the state,but this dispatch cost is system-allocated to customers throughout the Company's
service territories who receive the benefits of the wind generation.19 This law is almost identical
to the CCA, in that it provides a cost directly correlated to generation. Hypothetically, if Wyoming
18 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-1702,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.").
19 Wyo. Stat. §39-22-103.
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decided not to not impose its wind tax on in-state retail utility service, the facts remain the
same—the Company had to incur these costs to operate the wind facilities in Wyoming for the
benefit of its Idaho customers.
18. The Wyoming wind tax costs directly affect associated generation and are system
allocated under the 2020 Protocol. Under the 2020 Protocol adopted by the Commission,the costs
of CCA allowances are allocated on a system-wide basis, in the same manner and proportion to
the allocation of Chehalis generation that the allowances enable.20 In particular, generation-related
dispatch costs and fuel-related taxes are allocated to customers as system costs—meaning that
Idaho pays its share of the costs commensurate with its share of all other generation-related costs,
consistent with basic principles of cost-causation.21 This makes sense because, among other
reasons, it is difficult to quantify and situs assign the impact that incremental generation costs,
such as taxes or environmental compliance costs, have on system plant dispatch. Here, the CCA
requires the Company to secure an allowance for each metric ton of carbon dioxide equivalent
emitted from Chehalis and therefore the allowance costs are directly tied to the level of generation
at the plant. Therefore, for purposes of cost allocation under the 2020 Protocol, the costs of these
allowances required under the CCA are generation-related dispatch costs or generation
taxes—which are allocated to Idaho customers.
19. If Idaho policy becomes one where Idaho customers only pay for costs imposed by
the state of Idaho, then it will become very difficult for the Company to engage in interstate
commerce and serve its Idaho customers with resources located in other states. Other states could
20 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);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).
21 Section 3.1.7 of the 2020 Protocol states that both"[g]eneration-related dispatch costs and associated plant"and
"[g]eneration and fuel-related taxes"will be allocated using the System Generation(SG)Factor."
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similarly respond in-kind, and situs assign any costs the Company incurs in Idaho. Accordingly,
the Commission should act in a consistent manner and treat the costs associated with CCA similar
to any other state or federal tax or compliance costs the Company is already authorized to recover
to provide interstate electrical service to its Idaho customers.
iv. The proposed disallowance of CCA costs discriminates against the Company for
engaging in interstate commerce.
20. The proposed disallowance seeks to protect Idaho customers by discriminating
against the Company as an interstate electric utility, leaving it unable to recover unavoidable
compliance costs when engaging in interstate commerce. The basis for this disparate treatment
appears to be dissatisfaction with the CCA,leading to parties'recommending that certain interstate
power transmitted from Washington be treated differently than power generated from other
sources. This disparate treatment grants Idaho consumers an advantage and deters the generation
and sale of certain interstate electricity from Washington.
21. 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."22 A
decision in 2023 summarized interstate commerce discrimination, overturning a Kentucky law
favoring locally produced coal, noting that "[t]he real question . . . is not whether [the state law]
differentiates between in-state and out-of-state coal but whether it impermissibly discriminates, as
that term is used in the Commerce Clause. That is, does the law benefit in-staters and burden
22 Or. Waste Sys.,Inc. v.Dep't ofEnv't Quality of Or.,511 U.S. 93,99(1994).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 U.S. 331 (1982).
(overturning an order of the New Hampshire Public Utilities Commission);W.Lynn Creamery,Inc.v.Healy,512
U.S. 186(1994)(invalidating a pricing order issued by the Massachusetts Department of Food and Agriculture).
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outsiders?"23 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."24
22. This antidiscrimination principle lies at the"very core of activities forbidden by the
dormant Commerce Clause. ,25 Even if a state law,regulation, or order does not discriminate on its
face, its "practical effect" may also disclose the presence of a discriminatory purpose.26 In
examining state actions impacting interstate commerce, U.S. Supreme Court cases often find
discriminatory practical effects in the cases of"state laws that impose burdens on the arteries of
commerce, on trucks, trains, and the like."27 Indeed, the "interstate grid [is] much closer to the
heartland of interstate commerce than the wine stores, dairies, or waste processing facilities that
have faced dormant Commerce Clause scrutiny. ,21
23. Here, the proposed disallowance of CCA allowances gives Idaho customers an
advantage, burdening the "arteries of commerce" to the detriment of the provisions of interstate
electricity by the Company.This results in discriminatory practical effects—allocating the benefits
but not the costs of Chehalis power to Idaho customers. The proposed disallowance also has a
discriminatory purpose, or effect, that seeks to punish, tax and deter the Company for generating
and selling certain electricity from Washington, even when this is the least cost/risk option for
customers in Idaho. It is essential to emphasize that the Company is legally bound to comply with
"Foresight Coal Sales,LLC v. Chandler,60 FAth 288,297-98(6th Cir.2023),cent. denied sub nom., Chandler v.
Foresight Coal Sales,LLC, 144 S.Ct. 80(Oct.2,2023).
24 Camps Newfound/Owatonna,Inc. v. Town of Harrison,520 U.S. 564,577-78(1997)(quoting Brown-Forman
Distillers Corp. v.New York State LiquorAuth.,476 U.S.573,580(1986)).
25 Camps Newfound/Owatonna,Inc. v. Town of Harrison,Me.,520 U.S. 564,581 (1997)(internal brackets and
quotations removed).
26 Maine v. Taylor,477 U.S. 131, 138(1986).
27 Nat'l Pork Producers Council v. Ross,598 U.S. 356,392,(2023)(Sotomayor,concurring)(internal quotations
omitted).(Sotomayor,concurring)(internal quotations omitted).
26 See NextEra Cap.Holdings,Inc. v.Lake,48 FAth 306,321-22(5th Cir.2022),cert.denied,_U.S.
(December 11,2023).
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all applicable laws, including both Idaho and Washington law. If the Commission were to issue an
order contradicting these legal obligations, it would place the Company in an untenable situation
as an interstate utility. Consequently, the Commission should reject the proposed disallowance as
it seeks to punish and deter PacifiCorp as an interstate utility when it sells Chehalis power in
interstate commerce to Idaho customers—sales that require the Company to incur the costs of
procuring CCA allowances.
V. Chehalis is a System Resource and its costs and benefits are properly allocated to
Idaho under the 2020 Protocol.
24. Bayer and PIIC seem to imply that Chehalis is a "State Resource" because it is a
"State-Specific Initiative" under the 2020 Protocol.29 Under the 2020 Protocol, Company
"Resources [are] allocated to one of two categories for inter jurisdictional allocation purposes:
State Resources or System Resources."30 If a "Resource" is not "State Resource" then it is a
"System Resource."31 System Resources "constitute the substantial majority of PacifiCorp
resources."32 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. ,33 In this case, the Resource in question, Chehalis, is a
"Company-owned generating unit."
29 PIIC Comments at 8-9;Bayer Comments at 2-3.
112020 Protocol,Section 3.1.2.
31 2020 Protocol,Section 3.1.2.
32 2020 Protocol,Section 3.1.2.
312020 Protocol,Appendix A.
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25. Under Section 3.1.2.1 of the 2020 Protocol,a"Resource"can be a"State Resource"
if it was acquired to comply with a "State-Specific Initiative."34 The 2020 Protocol speaks to
acquisition of the Resource whose costs and benefits are being allocated. It is only when the
Company acquires the Resource as part of a state policy initiative that Section 3.1.2.1 and its"State
Resources" category (with its attendant cost and benefit allocation and situs assignment criteria)
come into play. Specifically, to qualify as a State Resource, the Company must have acquired the
Resource because of a state-imposed requirement to procure specific types of resources. For
example, this could include renewable generation procured by the Company to comply with a
state's capacity standard or incentive program. In this case, all the costs and benefits associated
with this Resource would have a situs allocation.35
26. There is no evidence that Chehalis was "acquired in accordance with" a
State-Specific Initiative program. New state-imposed compliance costs for the operation of an
existing resource do not convert that resource into a "State Resource."Using the same logic, any
state-imposed compliance cost on a generating unit, like Wyoming wind tax discussed above,
would covert a "Company-owned generating unit" into a "State Resource." The criteria for
designating a Resource as part of a State-Specific Initiative category focuses on specifically
resources acquired in accordance with the initiative. There is no evidence that Chehalis, a thermal
sa 2020 Protocol,Section 3.1.2.1 "State-Specific Initiatives"include"Resource[s] acquired in accordance with a
State-specific initiative,"which may include,but are not limited to,Resources acquired to comply with"incentive
programs,net-metering tariffs,feed-in tariffs,capacity standard programs,solar subscription programs,electric
vehicle programs,and the acquisition of renewable energy certificates."The 2020 Protocol notes that"[h]istorically,
[State-Specific Initiatives] . . .have not included local fees or taxes related to the ongoing operation of existing
transmission and generation facilities within a State."The allocation and assignment rule for these Resources is
clear: "Costs and benefits associated with Interim Period Resources acquired in accordance with a State-specific
initiative will be allocated and assigned on a situs basis to the State adopting the initiative."
112020 Protocol,Section 3.1.2.1 ("Costs and benefits associated with Interim Period Resources acquired in
accordance with a State-specific initiative will be allocated and assigned on a situs basis to the State adopting the
initiative.").
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resource subject to the 2020 Protocol, was acquired to satisfy any state policies identified in the
definition of a State-Specific Initiatives.
27. Indeed, Chehalis was acquired by the Company well before the passage of the
CCA; it was introduced into Idaho rates in a 2008 rate case, while the CCA was passed in 2021.36
In particular, Chehalis started commercial operations in October 2003, and the Company acquired
the plant in 2008.37 Furthermore, the CCA does not mandate the procurement of any natural gas
resource and instead discourages the construction of new natural gas plants in the state 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 that neither Staff, Bayer, nor PIIC recommend. 38 Instead Chehalis is a
"System Resource,"and as stated above,the CCA allowance costs should instead be treated similar
to the Wyoming wind tax and system allocated as a generation-related dispatch costs pursuant to
Section 3.1.7 of the 2020 Protocol.39
28. PIIC also attempts to advance an argument that the Company is inappropriately
seeking to recover 112 percent of the CCA allowance costs it incurred in 2023.40 This is simply
factually incorrect. PIIC states, "PacifiCorp's allocation assumes that it will need to acquire
allowances on behalf of other states based on approximately 93 percent of the output of Chehalis,
36 In the Matter of the Application of PacifiCorp DBA Rocky Mountain Power for Approval of Changes to Its Elec.
Serv. Schedules,Docket No.PAC-E-08-07,Order No. 30783 (Apr. 16,2009);Washington Senate Bill 5126(2021
Regular Session).
37 State of Washington Energy Facility Site Evaluation Council,"Chehalis Generation Facility,"available at,
https://www.efsec.wa.gov/energy-facilities/chehalis-generation-facility(last visited May 20,2024).
38 2020 Protocol,Section 3.1.2.1 ("Costs and benefits associated with Interim Period Resources acquired in
accordance with a State-specific initiative will be allocated and assigned on a situs basis to the State adopting the
initiative.").
39 Section 3.1.7 of the 2020 Protocol states that both"[g]eneration-related dispatch costs and associated plant"and
"[g]eneration and fuel-related taxes"will be allocated using the System Generation(SG)Factor."
40 PIIC Comments at 13.
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resulting in allowance costs covering 112 percent of Chehalis."41 This assumption is inaccurate
because the $42 million of total-Company Washington CCA costs are calculated using only 79.19
percent of the total Chehalis generation. If Washington's 20.81 percent share of the Chehalis
generation was not deducted the Company would have calculated$52.5 million of CCA allowance
costs. By removing Washington's 20.81 percent share of the CCA costs PacifiCorp is seeking to
recover only 100 percent of its cost incurred and not the 112 percent inaccurately assumed by PIIC.
vi. CCA allowances incurred in the deferral period should not be booked under
FERC Account 509.
29. PacifiCorp disagrees with PIIC's positions that costs associated with CCA
allowances should be recorded in FERC Account 509.42 The Federal Energy Regulatory
Commission ("FERC") created account 509 with Order No. 552 issued November 17, 1997.
FERC defines account 509 as follows:
509 Allowances.
This account shall include the cost of allowances expensed concurrent with the monthly
emission of sulfur dioxide. (See General Instruction No. 21)
30. As noted in the FERC definition this account as currently published in the Federal
Code of Regulations ("CFR") only includes "sulfur dioxide" allowances under the federal Clean
Air Act. Therefore, this current account does not provide for the inclusion of GHG allowances.
FERC only recently adopted a rule that may require the Company to expense other allowances,
such as allowances required under the CCA, to FERC Account 509.43 Importantly, that rule will
41 PIIC Comments at 13.
41 PIIC Comments at 7-8.
41 See Accounting and Reporting Treatment of Certain Renewable Energy Assets, 183 FERC¶61,205,Order No.
898(2023).
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not take effect until January 1, 2025, and the FERC order explicitly provided "the accounting in
this rulemaking [Order No. 898] is not intended to impact retail rates."44 Accordingly,the currently
published CFR only allows FERC Account 509 to book costs associated with allowances for sulfur
dioxide allowances under the federal Clean Air Act. Therefore, the CCA allowance costs incurred
during calendar year 2023 should not be booked to FERC account 509. FERC Account 555 is an
acceptable account for recording costs directly correlated to energy production and generation for
the 2023 deferral period.
vii. The Commission should make its decision based on the argument and evidence
raised in this proceeding.
31. The parties contend that PacifiCorp should not be able to recover the costs incurred
for the operation of Chehalis because the Commission denied an application filed by Avista
Corporation ("Avista") in Case No. AVE-E-23-04. However, that case was different from the
present one. In Case No. AVE-E-23-04,Avista was seeking to modify its power cost adjustment
("PCA")mechanism to include an additional FERC account, and not seeking the recovery of NPC
during its PCA annual filing. Indeed, the Commission did not order any disallowance of actual
NPC in that proceeding. Furthermore, many of the arguments made by PacifiCorp in this
proceeding were not made by Avista. Accordingly, it is reasonable that the Commission could
come to a different determination in this proceeding given the difference in procedural posture and
arguments raised.This is important because in any appeal,this Commission would be judged based
on the arguments raised in comments and any subsequent petition for reconsideration in this
proceeding.45
44 Id.
45 See generally Whitted v. Canyon Cnty.Bd. of Commis, 137 Idaho 118, 121 (2002)(["I[n order for an issue to be
raised on appeal,the record must reveal an adverse ruling which forms the basis for an assignment of error.").
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32. Furthermore, PIIC claims that the Company should be disallowed these costs
because Oregon Public Utility Commission and Wyoming Public Service Commission denied
allowing the costs of the CCA allowances to be included in forecasts of NPC.46 Neither of these
decisions are final as the Company is currently pursuing appeals of these decisions. Furthermore,
these cases involved forecasting of NPC and not the recovery of actual NPC in a power cost
adjustment mechanism like in this case.47 In other words, these two cases did not order a
disallowance of actual NPC. If this Commission adopts the proposed disallowance of CCA
allowances against the Company, Idaho would be the first jurisdiction to do so in the context of a
power cost adjustment mechanism by disallowing actual NPC. Accordingly, the Company
requests that this Commission make its determination based on the evidence and arguments
presented in this proceeding.
B. The Commission should deny the proposed disallowance of Chehalis dispatch costs
because the Company operated the plant in a least/cost risk manner.
33. PIIC proposes that the Company be assessed a disallowance based on the argument
that the Company acted imprudently by considering the costs of CCA allowances when dispatching
Chehalis during calendar year 2023.48 PIIC does not calculate a disallowance amount but suggests
that Staff could later calculate an amount based on a hypothetical counterfactual where the CCA
does not exist or that the Company could calculate a disallowance amount in the next ECAM
filing.49 The allowances required under the CCA increase the dispatch cost of Chehalis,which can
affect the frequency with which the Company dispatches Chehalis. In other words,because of the
"PIIC Comments at 8-9.In re the Application of Rocky Mountain Power for Authority to Increase Its Retail
Electric Service Rates by Approximately$140.2 Million Per Year or 21.6 Percent and to Revise the Energy Cost
Adjustment Mechanism.Wy.PSC Docket No.20000-633-ER-23;In re PacifiCorp, dba Pacific Power, 2024
Transition Adjustment Mechanism,Or.PUC Docket No.UE 420.
47 Id.
46 PIIC comments 13-14.
49 PIIC comments 13-14.
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increased dispatch costs for Chehalis, there are certain circumstances in which other resources are
more cost-effective to operate than Chehalis when accounting for CCA allowances. However, the
Company has observed that these circumstances are limited and, as a result, including this
generation adder results in only a very small decrease of Chehalis's output.
34. It is important to recognize that including the Washington CCA costs into the
dispatch prices ensures that the CAISO will compensate PacifiCorp at a higher level in the EIM
market to reimbursement for WA GHG costs. To the extent Chehalis was incrementally dispatched
in the EIM during 2023 PacifiCorp received higher revenues due to the higher bid prices resulting
from the inclusion of CCA Costs. Thus, the higher dispatch costs may result in less dispatch but
when dispatched the revenues will be higher. This consideration needs to be factored into any type
of counterfactual analysis and it points out that net power costs are already factoring in revenues
for CCA CAISO reimbursements due to higher dispatch prices so it would be inappropriate to
remove the incremental dispatch costs or CCA purchases without also calculating how much of
the EIM revenues would need to be removed as well resulting from the higher dispatch prices. It
is not appropriate to include the CAISO reimbursements for CCA costs but remove the costs
themselves.
35. The issue with this proposed disallowance by PIIC is that the Company does not
operate in a hypothetical counterfactual—but rather actual reality where the CCA does exist.
Fundamentally, these costs do not disappear simply if the Commission chooses to deny recovery
in an ECAM proceeding, unless the Company chooses to shut down Chehalis for its interstate
operation or the CCA is repealed.
36. The Company dispatches its system on a least-cost/risk basis. The proposed
disallowance sets a precedent where the Company must ignore reality and not operate in a
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least-cost/risk manner, further punishing the Company for engaging in interstate commerce to
serve its Idaho customers and limiting its ability to earn a reasonable rate of return in Idaho. The
Company is not aware of any precedent from this Commission requiring it to not operate in a
least-cost/risk manner or to consciously ignore prudently incurred costs in its dispatch
decisions—nor should the Commission choose to establish such a precedent in this case.Adopting
such a precedent would not result in just,reasonable,and sufficient rates under Idaho Code 61-502.
Adopting such precedent would also violate the dormant Commence Clause by further deterring
the interstate generation and sale of certain electricity from Washington to Idaho.
37. Furthermore, the proposed PIIC adjustment would violate due process. As stated
by the United States Supreme Court: "The fundamental principle [is] that laws regulating persons
or entities must give fair notice of what conduct is required or proscribed."50 The Company has
not received prior notice from this Commission that it must dispatch its system in a manner that
does not consider all costs and risks. Accordingly, to disallow costs without prior notice that the
Company must dispatch its system in a manner that ignores least/cost principals violates
fundamental due process.
38. Lastly, a counterfactual like PIIC proposes would be extremely burdensome to
produce and its results would be of limited use because of the sheer number of speculative
assumptions that would be built into such a model. The Company cannot record actual data for
events that did not occur and would instead have to produce a completely new hypothetical model.
This would not only require substantial input from the Company but also from other stakeholders
to try to reduce controversy of the selected modeling inputs. Even with stakeholder input, it would
be difficult to get all parties to agree on a reasonable set of assumptions and modeling parameters
5'F.C.C. v.Fox Television Stations,Inc., 567 U.S.239(2012).
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for the counterfactual. Moreover, given the hypothetical nature of such a model and likely
disagreement over the reasonableness of assumed inputs, the results of the counterfactual model
would provide limited insight into the real-world applications of what market purchases would
have occurred absent other states'policies.
C. The Commission should deny the proposed disallowance associated with OTR
compliance because they were prudent incurred at the time they were incurred.
39. The Commission should disregard Bayer's argument to disallow compliance costs
associated with the Ozone Transport Rule ("OTR"). Bayer contends because compliance costs for
the OTR are no longer required, the Company's prudently incurred costs in 2023 should not be
recoverable.
40. The Company faced compliance costs for NPC in 2023 in the form of market
purchases to comply with the OTR. The federal plan for interstate transport of the 2015 ozone
National Ambient Air Quality Standards, known as the OTR, was planned to become effective on
August 4, 2023. To comply with the impending implementation of the OTR,the Company needed
to ensure it met requirements under the OTR to eliminate significant contributions of ozone or
ozone precursors, specifically nitrogen oxides ("NOx") in neighboring states. To ensure the
Company had sufficient NOx allowances to cover its generation,the Company altered its dispatch
through market power purchases and its thermal generating resources.
41. Altering the Company's dispatch resulted in approximately $17 million
total-Company, prudently incurred compliance costs for the OTR. Prudency evaluations require
that decisions should demonstrate reasonable behavior by the utility, given what was known, or
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should have been known, at the time of the execution of the decision.51 At the time of incurring
the costs, the Company reasonably believed the OTR would require the Company to alter its
dispatch. Therefore, the Company prudently incurred just and reasonable costs to comply with
OTR.
42. On July 27, 2023, one week before OTR's implementation date, the loth Circuit
Court of Appeals granted a motion to stay the EPA's final disapproval of Utah's OTR state
implementation plan ("SIP"), which impacted the OTR's application to the Utah thermal
generating units.52 Due to the Stay,the Company was no longer required to incur compliance costs
for the OTR because the Company no longer needed to replace thermal generating resources with
market power purchases to cover NOx allowances. Despite the Stay's impact on further
compliance costs,the Company still accrued approximately$17 million in prudently incurred costs
prior to the Stay.
43. Bayer opposes recovery of expenses relating to the OTR by incorrectly relying on
hindsight review. Specifically,Bayer argues the Company cannot recover compliance costs for the
OTR because the Company should have known in hindsight to not comply with impending
implementation of the OTR. Bayer's argument to disallow these costs relies on an incorrect theory
that the Company should have known the OTR would be stayed. The Commission will not make
a prudency determination in hindsight.53 Additionally, the Company could not have known prior
51 When"assessing the reasonableness of the Company's deferred costs we consider whether the Company's
decisions based on the information available at the time were reasonable when made and whether the utility's
attempt to control the costs were prudent."In the Matter of the Submission of the Status Report of Avista
Corporation and Application for a Continuation of Power Cost Adjustment Surcharge,Case No.AVU-E-02-6,
Order No.29130 at 14(October 15,2002).
52 Utah v.EPA, Docket No.23-9509(101 Cir.July 27,2023)available at 1Oth-Stay-Order.pdf(utah.gov).
53"[The Commission]will not examine the evidence using hindsight,but rather make our findings based upon the
circumstances at the time [the expenditure was made].In the Matter of Idaho Power Company Application for a
Refundable Emergency Energy Charge for the Recovery of Extraordinary Power Supply Expenses, Case No.IPC-E-
01-7,Order No.28852 at 8(September 8,2001).
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to July 27, 2023,that the Court of Appeals would Stay the OTR one week before implementation.
When the Company adjusted its dispatch to prepare for OTR's implementation, it prudently
incurred compliance costs because the Company was making reasonable decisions with what the
Company knew, or should have known, at the time.
44. Furthermore, the Commission should disregard Bayer's justification for
disallowing the OTR costs by comparing this proceeding with proceedings in Utah and Wyoming.
Bayer argues that because the Company voluntarily removed costs associated with the OTR from
its NPC forecast adjustment in Wyoming and Utah, the Company should remove previously
incurred compliance costs from this current proceeding in Idaho. Prior to the OTR's Stay, the
Company prudently incurred costs to prepare for OTR's implementation. The Company seeks to
recover those prudently incurred costs across its service territory, including this proceeding.When
the OTR was Stayed, the Company removed costs from the NPC forecast in proceedings in Utah
and Wyoming.54 The NPC forecast is forward looking.This proceeding does not involve the OTR's
impact on a forward-looking NPC forecast. Thus,Bayer's argument is misled. Bayer's proposal to
voluntarily remove OTR costs from the forward-looking NPC forecast, as the Company did in
Utah and Wyoming, is inapplicable and incomparable to the Company's request to recover
approximately $17 million dollars of prudently incurred compliance costs in this proceeding.
D. The Commission should not change the amortization period of the 2023 ECAM
deferral balance.
45. PIIC recommends the Company be required to amortize the rate increase over a
three-year period to mitigate the overlapping impacts from the rate case. The Company disagrees
54 In the Matter of the Application of Rocky Mountain Power for Authority to Increase its Retail Electric Service
Rates by Approximately$140.2 Million Per Year or 21.6 percent and to Revise the Energy Cost Adjustment
Mechanism, Docket No.20000-633-ER-23 (Record No. 17252),Rebuttal Testimony of Ramon J.Mitchell(RMP
Exhibit 10.7)at 42(Sept.26,2023). ("Based on[the Stay]and the continuing uncertainty around Wyoming,the
Company proposes to remove the OTR from the NPC forecast for both Utah and Wyoming.").
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with the recommendation to delay already-incurred fuel expenses for two main reasons: (1)
delaying the recovery of these costs would create regulatory lag for the Company; and (2)
extending the recovery timeline adds additional interest expenses for customers as well as
continued price uncertainty under unpredictable markets.
46. The Commission has previously agreed that extending recovery over a longer time
period, despite significant increases in rates, is not in the best interest of customers. In a previous
Idaho Power Company case, the Commission found that despite the price increase, Idaho Power
Company's mechanism "was designed for single-year recovery" and they decided to honor the
mechanism's original design.55 Likewise, the ECAM approved by the Commission for PacifiCorp
is designed for single-year recovery.56 In Case No. PAC-E-08-08, when approving the original
ECAM stipulation the Commission found that the ECAM,as it was designed,will send better price
signals to the Company's customers than irregular rate cases.57
47. In addition to providing for timely recovery of power costs, the annual recovery
period also limits additional interest expenses that customers could accrue on unrecovered ECAM
balances.As the ECAM is currently designed, customers incur an annual interest expense on the
deferral balance. In a higher interest rate environment, the interest rate on the deferral balance is
increasing. The interest rate has increased 250 percent year-over-year from 2 percent for calendar
year 2023 to 5 percent for calendar year 2024.58 Delaying recovery of the ECAM deferral, could
55 In the Matter of the Application of Idaho Power Company for an Energy Cost Financing Order and Authority to
Institute an Energy Cost Bond Charge. Case No.IPC-E-02-02;In the Matter of the Application of Idaho Power
Company for Authority to Implement a Power Cost Adjustment(PCA)Rate for Electric Service from May 16, 2002,
through May 15, 20023. Case No.IPC-E-02-03,Order No.29026(May 13,2002).
56 In the Matter of the Application of Rocky Mountain Power for Approval of an Energy Cost Adjustment
Mechanism (ECAM). Case No.PAC-E-08-08,¶6 of stipulation approved in Order No.30904(Sept.29,2009).
57 Id at p. 13.
58 In the Matter of the Interest Rate on Deposits Collected from Customers of Gas,Electric, Telephone, and water
Public Utilities for Calendar Year 2024. Case No.GNR-U-23-01,Order No. 36000(Nov. 15,2023).
Page 23

significantly increase the interest rate costs to customers which accounts for $1.2 million of the
deferral in the current case.
III. REQUEST FOR RELIEF
48. The ECAM deferral of$62.4 million, including interest, for calendar year 2023,
was accurately calculated in compliance with previous Commission orders. Based on the
foregoing, the Company respectfully requests that the Commission approve this application as
filed with rates effective June 1, 2024.
DATED this 21st day of May 2024.
Respectfully submitted,
ROCKY MOUNTAIN POWER
z
Joe Dallas (ISB# 10330)
PacifiCorp, Senior Attorney
825 NE Multnomah Street, Suite 2000
Portland, OR 97232
Email: joseph.dallas(&,pacificorp.com
Attorney for Rocky Mountain Power
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