20240531Final_Order_No_36207.pdf

Office of the Secretary
Service Date
May 31,2024
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF ROCKY MOUNTAIN ) CASE NO. PAC-E-24-05
POWER'S APPLICATION FOR APPROVAL )
OF $62.4 MILLION ECAM DEFERRAL ) ORDER NO. 36207
On April 1, 2024, PacifiCorp dba Rocky Mountain Power ("Company") applied for
authorization to adjust its rates under the Energy Cost Adjustment Mechanism ("ECAM"). The
Company seeks an order approving approximately $62.4 million in ECAM deferred costs and a
10.5 percent increase to Electric Service Schedule No. 94, Energy Cost Adjustment ("Schedule
94"). If the adjustment is approved, the monthly bill of an average residential customer using 783
kilowatt-hours of electricity would increase by about$7.39. The Company requested its proposed
adjustment be processed by Modified Procedure and become effective on June 1, 2024.
On April 13,2024,the Commission issued a Notice of Application and Notice of Modified
Procedure, establishing public comment and Company reply deadlines. Order No. 36153. P4
Production LLC., an affiliate of Bayer Corporation ("P4"), and PacifiCorp Idaho Industrial
Customers ("PIIC"), intervened. Order Nos. 36161 and 36176.
Commission Staff("Staff'), P4, PIIC, (collectively the "Parties"), and one member of the
public filed comments. The Company responded to Staffs, P4's, and PIIC's comments.
Having reviewed the record,the Commission approves the Company's Application in part.
Specifically,we disallow recovery of costs the Company incurred to comply with the Washington
Climate Commitment Act and authorize a revised ECAM deferral amount of$60,093,960.
BACKGROUND
The ECAM allows the Company to increase or decrease its rates each year to reflect
changes in the Company's power supply costs. These costs vary by year with changes in the
Company's fuel (gas and coal) costs, surplus power sales, power purchases, and associated
transmission costs. Each month, the Company tracks the difference between the actual net power
costs ("NPC") it incurred to serve customers, and the embedded (or base) NPC it collected from
customers through base rates. The Company defers the difference between actual NPC and base
NPC into a balancing account for later disposition at the end of the yearly deferral period. At that
time, the ECAM allows the Company to credit or collect the difference between actual NPC and
ORDER NO. 36207 1

base NPC through a decrease or increase in customer rates. Neither the Company nor its
shareholders will receive any financial return because of this filing.
THE APPLICATION
Besides the NPC difference described above, this year's ECAM includes: (1) the Load
Change Adjustment Revenues ("LCAR"); (2) an adjustment for coal stripping costs;' (3) a true-
up of 100% of the incremental Renewable Energy Credit ("REC") revenues; (4) Production Tax
Credits ("PTC"); (5) reasonable energy price ("REP") qualifying facility ("QF") adjustment;2 (6)
wind availability liquidation damages; and(7) interest on the deferral.
With its Application, the Company seeks an order approving the Company's: (1) request
for a$62.4 million ECAM deferral; and(2)a 10.5 percent increase for Schedule 94. The Company
states that if its proposal is approved,prices for customer classes would increase as follows:
• Residential Schedule 1 —(7.6%)
• Residential Schedule 36, Optional Time-of-Day Service—(8.7%)
• General Service Schedule 6—(10.7%)
• General Service Schedule 9—(13.1%)
• Irrigation Customers—(9.5%)
• General Service Schedule 23 —(9.0%)
• General Service Schedule 35 —(10.3%)
• Public Street Lighting—(5.2%)
• Tariff Contract, Schedule 400—(13.5%)
STAFF COMMENTS
1. ECAM Analysis and Calculation
Staff recommended the Commission authorize a lower 2023 ECAM deferral than the
Company proposed. Staff noted that the Company included additional costs incurred to comply
with Washington's Climate Commitment Act ("WCCA") in its proposed ECAM deferral. Staff
believed inclusion of these costs was not fair,just, or reasonable because it effectively imposes a
unilateral tax on Idaho customers. Accordingly, Staff recommended removing the WCCA costs
' The ECAM includes a"90/10 sharing band"in which customers pay/receive 90 percent of the increase/decrease in
the difference between actual NPC and base NPC,LCAR,and the coal stripping costs;and the Company incurs/retains
the remaining 10 percent.Application at 3.
z The REP QF adjustment flows from the 2020 Inter-Jurisdictional Allocation Protocol where, during the Interim
Period,"energy output of New QF PPAs will be dynamically allocated. . .using the SG Factor,priced at a forecasted
[REP] . . .and any cost of a New QF PPA above the forecasted[REP]will be situs assigned and allocated to the State
of Origin."Direct Testimony of Jack Painter at 10 ("Painter Direct");Order No.34640.
ORDER NO. 36207 2

from the proposed ECAM deferral, reducing it by approximately $2.3 million for a total revised
deferral amount of about $60.1 million.
Staff reviewed the other aspects of the Company's calculation of the 2023 ECAM for
compliance with previous Commission orders and accuracy in reported actual loads, prudence in
incurred actual costs and revenues, and correct application of loads, costs,and revenues embedded
in base rates. Staff also reviewed the Company's hedge contracts to ensure they safeguard price
and fuel stability.
The NPC to serve Idaho customers in 2023 was $149 million but the revenue collected
through base rates was only$85.7 million—leaving a$63.3 million under collected balance.3 After
accounting for the 90/10 band, customers are responsible for$57.2 million through the ECAM.
The Emerging Issues Taskforce ("EITF") an adjustment measuring the difference
between coal stripping costs incurred and recorded—increased the deferral by $60,594.
The LCAR adjusts for the over- or under-recovery of"fixed energy-classified production
cost (excluding NPC) resulting from the difference between Idaho sales used to determine base
rates and the sales from the deferral year." Staff Comments at 4. A LCAR of$8.74/MWh was set
in Case No. PAC-E-21-07 and the Company collected approximately $30.5 million through the
LCAR. The difference between this amount and the $30.8 million embedded in base rates
increased the ECAM deferral by $268,994.
Under Order No. 35277, the PTC true-up is $4.16/MWh. In 2023, a $13.6 million PTC
benefit from the ECAM fell short of the $14.6 million allocation to Idaho customers. The
difference between embedded PTCs and actual PTCs results in a$907,177 surcharge to customers
collected through the ECAM.
A rate of$0.07/MWh in REC revenues was set in Order No. 35277. In 2023, base rates
included$239,273 in benefits,but Idaho's actual share of REC revenues was $357,308 higher than
included in rates. This amount will offset the deferral balance.
s The NPC embedded in rates is set at $24.54 per megawatt-hour ("MWh"). To calculate the amount of revenue
collected through base rates the Company multiples the embedded per MWh cost by total MWhs sold. $24.54 x
3,495,580 MWh=$85.7 million.
ORDER NO. 36207 3

Per the 2020 protocol, all QF contracts approved in 2020 and thereafter became subject to
a REP adjustment.4 Idaho has 11 QF contracts that fall under the REP adjustment which resulted
in a $1.5 million increase to the Idaho deferral in 2023.
The ECAM also included a $310,085 credit for a wind availability liquidated damages
credit. This credit represents Idaho's share of the liquidated damages the Company receives from
suppliers of repowered wind facilities failure to meet required specifications.
2. Analysis of Actual NPC
Staff reported that, on a system wide basis, actual NPC was 85.2 percent higher than base
NPC in 2023. Focusing specifically on Idaho, actual NPC was 75.3 percent above base rate
recovery. Despite these increases, Staff believed the Company generally operated prudently in the
face of a difficult deferral period. Staff based this conclusion on its analysis of (1) the actual
amounts of energy delivered and costs incurred relative to base amounts embedded in rates for the
deferral period; and (2) the reasonableness of the unit downtime for Company's generation
resources.
Staff s analysis led it to believe that the high NPC in 2023 arose largely from lower than
forecast generation from the Company's lowest cost energy resources(i.e.,hydro,coal, and wind),
resulting in heavier reliance on gas generation and market purchases to meet customer's demand
for energy. Staff believed a lack of available wind and hydro resources during the deferral period
caused the reduction in zero-fuel cost hydro and wind generation.Regarding coal generation, Staff
believed coal supply issues and transmission constraints between the Bridger coal plant and loads
to the west diminished generation.
The Company's reliance on gas generation and market purchases exacerbated matters as
the actual prices for this energy were 47 percent and 64.1 percent higher than that forecasted in
base rates. Furthermore, the shortfall in hydro, wind, and coal generation also resulted in
diminished Company sales into the wholesale market—a traditional means of offsetting actual
NPC to customers. However, Staff noted that some of the discrepancy between forecast and actual
sales arose from inaccuracies in the modeling used for base rates, which the Company intends to
improve during its next general rate case.
4"The amount the Company paid for energy under each QF contract over a reasonable energy price would be SITUS
(state)allocated to the state that approved the QF contract."Staff Comments at 5;citing Painter Direct at 10.
ORDER NO. 36207 4

According to Staff,the Company made prudent decisions in taking resources out of service
for various reasons. Despite noting significant downtime for the "Prospect 3"hydro unit and five
Swift hydro units, Staff believed the Company had legitimate reasons for the downtime its
resources experienced and that they were out of service for a reasonable period.
3. Proposed Rates
The Company proposed raising Schedule 94 rates by approximately 101.1 percent,
increasing base rate revenue by 10.5 percent. Staff verified that the Company's underlying
calculations for these rates are accurate and comply with prior Commission orders. However, Staff
recommended a lower proposed rate increase that reflects the removal of the costs for complying
with the WCCA. Specifically, Staff proposed a 93.7 percent increase in Schedule 94 rates, which
would raise base rate revenue by 9.7 percent. Under Staff s proposed rate, a typical Schedule 1
customer's monthly bill would increase by $6.85.
P41S COMMENTS
P4 focused its comments on two costs the Company proposed for inclusion in the ECAM
deferral and subsequent recovery from customers. First, like Staff, P4 opposed the recovery of
costs for complying with the WCCA. Second, P4 also opposed the recovery of costs for
compliance with the Ozone Transport Rule ("OTR").
1. WCCA Costs
P4 presented essentially the same rationale as Staff for opposing recovery of costs
associated with WCCA. That is, WCCA compliance costs arose from the actions of a single state
(i.e., Washington) and, therefore, that state should bear them. However, P4 cited some additional
persuasive authority supporting this argument.
P4 noted that the Wyoming Public Service Commission ("WPSC") recently denied the
Company's request to recover from Wyoming customers the cost of purchasing Greenhouse Gas
allowances to comply with the WCCA.S In doing so, the WPSC rejected an argument that the cost
of complying with the WCCA were analogous to Wyoming's wind tax and, therefore, subject to
allocation to all states under the 2020 PacifiCorp Inter-Jurisdictional Allocation Protocol ("2020
Protocol"). The WPSC determined that the WCCA is a state-specific initiative that was akin to a
5 See 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 21.6Percent and to Revise the Energy Cost Adjustment Mechanism. WPSC
Docket No.20000-63 3-ER-23,Memorandum Opinion,Finding,and Order¶211 (Jan.2,2024).
ORDER NO. 36207 5

renewable portfolio standard("RPS")as the legislative intent behind the WCCA is to reduce fossil
fuel generation. Because such portfolio standards are undisputedly situs under the 2020 protocol,
the WPSC reasoned that the WCCA should be also.6
2. The OTR
P4 described the OTR as the final plan of the Environmental Protection Agency ("EPA")
to limit emissions of nitrogen oxides in 23 states, including Utah and Wyoming. However,
according to P4, the Utah Attorney General sued the EPA, seeking to overturn the OTR, and the
Tenth Circuit stayed the federal plan. Accordingly, P4 opposed recovery of what it considered
unnecessary expenses to comply with the OTR, describing the costs as unrelated to any operating
condition the Company had to satisfy addressing emissions of nitrogen oxides.7
PIIC'S COMMENTS
PIIC similarly focused its comments on two issues. First, like Staff and P4, PIIC opposed
the recovery of costs for complying with the WCCA. Second, PIIC recommended amortizing the
proposed rate increase over three years to mitigate any overlap between that increase and the
Company's next general rate case.
1. WCCA Costs
PIIC opposed the Company recovering costs it incurred to comply with the WCCA.
However, according to PIIC, the WCCA resulted in more costs to the Company than the $42
million spent to purchase greenhouse gas allowances. Specifically, PIIC asserted that the cost of
the allowances affected the dispatch of energy from the Chehalis power plant, resulting in an
inefficient dispatch of generation. Due to the time constraints of this case, PIIC could not perform
the analysis necessary to estimate the effect of this inefficiency. However, PIIC noted that this
dispatch cost was estimated to be $9,559,205 on a company-wide basis in the Company's 2023
general rate case in Wyoming.
In addition to the dispatch efficiency issue, PIIC also opposed the Company's recovery of
the cost of WCCA allowances, arguing that the Company included the expenses in the ECAM by
improperly recording them in Federal Energy Regulatory Commission ("FERC") Account 555,
6 P4 also noted that the Oregon Public Utility Commission denied recovery of WCCA costs from Oregon customers,
reasoning that such costs are part of a state-specific initiative properly allocated to Washington.See In re PacifiCorp,
dba Pacific Power, 2024 Transition Adjustment Mechanism,OPUC Docket No.UE 420,Order No.23-404(Oct.27,
2023).
7 P4 indicated the Company is seeking recovery of approximately$17 million for the OTR on a system basis.
ORDER NO. 36207 6

Purchased Power. PIIC argued that the costs for the allowances have nothing to do with purchased
power and should, therefore, be recorded in FERC Account 509, Allowances, which are not
included in the ECAM. Thus, PIIC reasoned that, regardless of the reasonableness of purchasing
the allowances, they cannot be included in the ECAM because the Company did not request
inclusion of FERC Account 509 in the ECAM and any change to the mechanism can only be
prospective.
Respecting the reasonableness of the allowances themselves, PIIC noted that the
Commission's prior decision to exclude WCCA costs from rates in Order No. 36015 is consistent
with other jurisdictions that have addressed the issue. The Oregon Public Utility Commission
("OPUC") did not allow the Company to include the cost of WCCA allowances in its 2024
Transition Adjustment Mechanism ("TAM") filing.$ As previously noted, the WPSC also denied
recovery of the WCCA allowances in the Company's 2023 general rate case.
PIIC also noted that, because of the separate allocation framework applicable to Chehalis
and no-cost allowances provided to Washington residents,the Company could potentially recover
allowance costs covering 112 percent of the cost of Chehalis from other states. For all the above
reasons, PIIC recommended that the Commission deny recovery of all costs incurred to comply
with the WCCA.
2. Amortization Period
PIIC also requested that the Commission amortize the rate increase proposed in this case
over three years. PIIC asserted that this will lead to more stable long-term rates by spreading the
increase over a three-year period, mitigating both the immediate impact of the increase and
diminishing any compounding rate effects from the Company's upcoming rate case. In support of
this proposal,PIIC noted that not only will the base NPC be reset in the Company's upcoming rate
case, but the price for natural gas has dropped and the issues the Company faced with its coal
operations have largely been resolved. Thus, PIIC indicated that it expects a significant decline in
the Company's ECAM deferrals going forward, reducing the likelihood of future rate pancaking
if the increase is amortized over three years.
Additionally,PIIC noted that it was not seeking to amortize the entire$62.4 million ECAM
deferral amount. Rather, it sought only to amortize the increase in the ECAM. Thus,under PIIC's
s PIIC describes the TAM as a docket that forecasts and establishes the NPC for the coming year.The OPUC's decision
to denying recovery of the allowances is currently on appeal to the Oregon Court of Appeals.
ORDER NO. 36207 7

proposal, the Company would recover $43,133,607 beginning on June 1, 2024, an approximate
3.5% rate increase. The Company would then recover an additional $10,886,666 in its next two
ECAM filings.
PUBLIC COMMENTS
One member of the public commented requesting the Commission deny the Company's
Application.
COMPANY REPLY COMMENTS
The Company disagreed with the other Parties' recommendation to disallow recovery of
costs it incurred to comply with the WCCA. The Company argued that disallowing recovery of
these costs would violate fundamental ratemaking and constitutional principles. Alternatively, the
Company argued that the Commission should remove the generation benefits of Chehalis from the
deferral balance if recovery of the WCCA compliance costs for operating the facility are
disallowed.
The Company contended that disallowing recovery of WCCA costs from Idaho customers
would violate the fundamental ratemaking principle of cost-causation. The Company reasoned
Chehalis benefits Idaho customers despite the additional WCCA compliance costs to operate it.
Because no party disputed the prudence of procuring WCCA allowances to operate Chehalis, the
Company reasoned Idaho customers should bear the actual costs of Chehalis generation from
which they benefit.
The Company also argued that the WCCA is like other taxes imposed by the federal and
other state governments on the Company. The Company warned that if policy shifts to Idaho
customers paying only for costs imposed by the state of Idaho, then it will become very difficult
for the Company to serve its Idaho customers with out-of-state resources. In support of this
argument, the Company cited the Wyoming wind tax, which is system allocated under the 2020
Protocol.
The Company further argued that denying recovery of the cost of complying with the
WCCA violates the dormant Commerce Clause by discriminating against the Company for
engaging in interstate commerce. Specifically, the Company contended that disallowing WCCA
costs would give Idaho customers an advantage and burden interstate commerce to the Company's
detriment.
ORDER NO. 36207 8

The Company also reasoned that the WCCA costs were properly allocated to Idaho under
the 2020 Protocol as a"System Resource." The Company observed that,under the 2020 Protocol,
generation resources are either"State Resources"or System Resources. Within the 2020 Protocol,
a Resource includes Company-owned generating units, like Chehalis.Under Section 3.1.2.1 of the
2020 Protocol,a Resource can be a State Resource when the resource was acquired to comply with
a"State-Specific Initiative."Because the Company did not acquire the physical Chehalis plant in
accordance with a State-specific initiative, the Company reasoned the subsequent acquisition of
greenhouse gas allowances to operate it under Washington state law did not convert it to a State
Resource.
The Company disagreed with PIIC's argument that WCCA costs should be recorded in
FERC Account 509. According to the Company, federal law currently in effect provides that only
allowances for sulfur dioxide emission should be recorded into FERC Account 509. Although a
recent change to federal regulations may require other allowances to be recorded into FERC
Account 509, that change will not be effective until January 1, 2025, and is not intended to impact
retail rates. See Accounting and Reporting Treatment of Certain Renewable Energy Assets, 183
FERC¶61,205, Order No. 898 (2023).
The Company also opposed P4's recommendation to disallow costs for complying with the
OTR. The Company noted that in preparing to comply with the OTR(which was to take effect on
August 4, 2023) it altered its thermal generating resources and dispatch through power purchases.
The Company represented that these efforts led to approximately$17 million in prudently incurred
costs. Although a stay from Tenth Circuit Court of Appeals one week before the implementation
date of the OTR relieved the Company the obligation to incur further compliance costs going
forward, the Company asserted that did not render imprudent the $17 million of costs already
incurred to prospectively comply with the OTR.
Finally, the Company opposed PIIC's three-year amortization proposal for two reasons.
First, amortizing incurred fuel expenses would impose regulatory lag on the Company's recovery
of those costs. The Company noted that the ECAM was designed for single-year recovery and,
despite the significant increase, that design should be honored. Second, extended recovery would
impose additional interest expenses and future price uncertainty on customers. Currently, the
ECAM imposes annual interest expenses on customers and, in the current environment, delaying
recovery could result in significant costs to customers in the form of higher interest costs.
ORDER NO. 36207 9

COMMISSION FINDINGS AND DECISION
The Commission has jurisdiction over the Company's Application and the issues in this
case under Title 61 of the Idaho Code including, Idaho Code §§ 61-501, -502, and -503. The
Commission is empowered to investigate rates, charges,rules,regulations,practices, and contracts
of all public utilities and to determine whether they are just, reasonable, preferential,
discriminatory, or in violation of any provisions of law, and to Ex the same by order. Idaho Code
§§ 61-501, -502, and-503.
Based upon a review of the record, we find it fair, just, and reasonable to approve the
Company's Application with some exceptions. First, the Commission is particularly concerned
with, and ultimately rejects, the Company's request to recover WCCA compliance costs and
hereby disallows the recovery of WCCA costs. Second, we also reject P4's and PIIC's
recommendations to disallow recovery of the costs the Company incurred to comply with the OTR
and to amortize recovery of the amount of the ECAM deferral exceeding that embedded in base
rates over three years, respectively. Each of these contested issues are discussed more thoroughly
below.
1. WCCA Compliance Costs
The WCCA establishes regulatory requirements reducing certain greenhouse gas ("GHG")
emissions from generating plants in Washington State. One component of the WCCA is a Cap and
Invest Program, which establishes an initial limit (or "cap") on GHG emissions in Washington
State. RCW §§ 70A.65.005 through 70A.65.901. The Washington Department of Ecology
("WDE") maintains and enforces the cap through the auctioning and subsequent retirement of a
limited number of"allowances." See RCW § 70A.65.090(7)(a) (requiring a compliance account
through which allowances are transferred to the WDE for retirement); RCW § 70A.65.100
(requiring the WDE to distribute allowances via auctions).Each allowance authorizes the emission
of one metric ton of carbon dioxide equivalent. See RCW § 70A.65.010(1). To ensure that certain
legislative emissions limits are met, the WDE will issue a steadily decreasing number of
allowances in coming years. See RCW § 70A.65.070.
Although the WDE must allow for secondary transfer of purchased allowances to the
greatest extent possible, see id., the auctions are considered the "linchpin" of the cap-and-invest
program that will generate "substantial revenue that must, by law be invested in critical climate
projects throughout" in Washington State. Dep't of Ecology State of Wash.,
ORDER NO. 36207 10

https:Hecology.wa.gov/air-climate/climate-commitmentact/auction-proceeds (last visited May 28,
2024); see also RCW §§ 70A.65.100, 70A.65.230, 70A.65.240, 70A.65.250, 70A.65.260,
70A.65.270, 70A.65.280.
The Company owns and operates a natural gas-fired generating facility in Chehalis,
Washington, that exports a portion of the electricity it generates there to Idaho customers. The
Chehalis facility emits carbon dioxide for which the Company must purchase and retire allowances
through the WDE.Although the WDE provides some allowances to the Company for the Chehalis
facility at no cost, these no-cost allowances must be allocated only to Washington State retail
customers. See RCW §§ 70A.65.110, 70A.65.120, 70A.65.130. The Company seeks authorization
to recover about $2.3 million from Idaho customers—an amount representing Idaho's
jurisdictional share of the cost to purchase the remaining allowances necessary to operate the
Chehalis facility and export electricity to customers outside of Washington.
We conclude that allowing recovery of costs incurred to comply with the WCCA from
Idaho customers would violate the 2020 Protocol, which governs the allocation of costs and
benefits of Company resources (including Company-owned generating facilities like the Chehalis
facility) across the jurisdictions in which the Company operates.9
We reject the Company's argument that the costs it incurred to comply with the WCCA
are like other taxes imposed on the Company, like the Wyoming Wind Tax. See Wyo. Stat. Ann. §
39-22-104 (imposing a tax of$1.00 on every MWh of wind energy generated in state). Rather,we
conclude the WCCA is more akin to an RPS as it is designed to reduce the use of fossil fuel
generation to serve load. The 2020 Protocol defines a"Portfolio Standard"as "a law or regulation
that requires [the Company] to acquire . . . [r]esources in a prescribed manner." 2020 Protocol,
Section 3.1.2.1. Although the Company owned the Chehalis generating facility before the WCCA
was enacted, it lost the right to operate it to generate electricity to serve customers outside of
Washington State without purchasing allowances when the legislation became effective. The
Company did not acquire that right again until after it obtained allowances as prescribed by the
Washington State legislature. The costs of resource procurement standards like this are situs-
assigned under the 2020 Protocol. Thus, costs the Company incurred to comply with the WCCA
are appropriately assigned to customers in Washington State.
9 The 2020 Protocol was approved in Order No. 34640.
ORDER NO. 36207 11

Other aspects of the WCCA buttress this conclusion. For example, the Washington State
legislature does not fix the cost of allowances like other taxes. Rather, that cost is determined at
an auction conducted by the WDE. Moreover,while isolated WCCA provisions might resemble a
tax or generation-dispatch costs,the complete statutory scheme goes beyond this by providing no-
cost allowances to Washington State retail customers alone.
The WDE discussed the rationale behind the provision of these no-cost allowances in
federal district court litigation concerning the WCCA. Specifically, the WDE indicated that the
no-cost allowances were linked to another Washington State climate initiative, stating:
[T]he Clean Energy Transformation Act (CETA), requires utilities serving
Washington customers to reduce their greenhouse gas emissions to neutral by 2030
and to zero by 2045. Critically, these requirements do not apply to generation for
out-of-state customers. Thus, the function of the no cost allowances in the Climate
Commitment Act is to avoid double-charging Washington customers for the costs
of the energy transition to non-emitting generation.10
The same year CETA requires the complete elimination of fossil-fuel generators from the
portfolios of electric utilities, the provision of cost-free allowances under the WCCA ends. Thus,
the CETA and WCCA work together to implement a state-specific initiative by creating portfolio
standards under CETA and then distributing no-cost allowances to CETA-obligated utilities
through the WCCA. The 2020 Protocol is designed and intended to isolate such state-specific
policy costs and recover those costs from customers in the states where the policies are created.
2. OTR Compliance Costs
We find it fair,just, and reasonable to allow the Company to recover from Idaho customers
Idaho's jurisdictional share of the costs incurred to comply with the OTR,a federal rule. Although
the Company did not ultimately have to comply with the OTR, that does not retroactively render
imprudent the costs it incurred preparing to comply.Nor does the record show that the Company's
preparations to comply with the OTR were otherwise imprudent.
3. Amortization of Recovery
We also find it fair,just, and reasonable to allow the Company to recover the 2023 ECAM
deferral in a single year.Although the deferral is substantial, amortizing its recovery is not without
additional costs or additional risks for customers. For example, interest would continue to accrue
"Invenergy Thermal LLC, and Grays Harbor Energy LLC v. Laura Watson, in her official capacity as Director of
the Washington State Department of Ecology,Defendant,("Invenergy v. Ecology")Defendant's Motion to Dismiss,
(Feb. 16,2023),Western District of Washington Case No. 3:22-cv-05967.
ORDER NO. 36207 12

on the uncollected deferral over the course of the amortization period, increasing the total amount
recovered from customers. Additionally, the Company could be faced with another substantial
ECAM deferral in the next two years, while it is still recovering part of the 2023 deferral. If this
hypothetical occurred, customers would incur additional interest costs only to obtain pancaking
rates. Moreover, the ECAM was designed for single-year recovery of deferred costs. Considering
the cost and risk a three-year amortization would entail,we find it reasonable to honor the original
design of the 2023 ECAM in this case and allow the Company to recover the ECAM deferral
allowed here in a single year.
In sum, we disallow recovery of the costs the Company incurred to comply with the
WCCA, approve$60,093,960 million in deferred costs from the deferral period beginning January
1, 2023, through December 31, 2023, and a corresponding increase to Electric Service Schedule
No. 94, Energy Cost Adjustment. Because these amounts differ from those proposed in the
Application, we direct the Company to submit as a compliance filing a revised Schedule No. 94
tariff reflecting the amounts approved in this Order within 15 days.
ORDER
IT IS HEREBY ORDERED that the Company's Application for deferred costs from the
deferral period beginning January 1, 2023, through December 31, 2023, in a revised amount of
$60,093,960 (which excludes costs incurred to comply with the WCCA) is approved, effective
June 1, 2024.
IT IS FURTHER ORDERED that the Company submit within 15 days of the issuance of
this order a revised Schedule No. 94 tariff reflecting the amounts approved in this Order as a
compliance filing.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date upon this Order regarding any
matter decided in this Order. Within seven (7) days after any person has petitioned for
reconsideration, any other person may cross-petition for reconsideration. See Idaho Code §§ 61-
626.
ORDER NO. 36207 13

DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 31St day of
May 2024.
ERIC ANDERSON, PRESIDENT
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J R. HAMMOND JR., COMMISSIONER
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Commission Secretary
I:\Legal\ELECTRIC\PAC-E-24-05_ECAM\orders\PACE2405_final_at.docx
ORDER NO. 36207 14