20220526Final_Order_No_35419.pdf

ORDER NO. 35419 1

Office of the Secretary
Service Date
May 26, 2022
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF ROCKY MOUNTAIN
POWER’S APPLICATION REQUESTING
APPROVAL OF $28.4 MILLION ECAM
DEFERRAL
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CASE NO. PAC-E-22-05

ORDER NO. 35419

On March 30, 2022, PacifiCorp dba Rocky Mountain Power (“Company” or “Rocky
Mountain”) applied for Commission authorization to adjust its rates under the Energy Cost
Adjustment Mechanism (“ECAM”). The Company requested approval of approximately $28.4
million in deferred costs from the deferral period beginning January 1, 2021, through December
31, 2021, and a 4.5 percent increase to Electric Service Schedule No. 94, Energy Cost Adjustment.
The Company estimated that a residential customer using 783 kilowatt-hours (“kWh”) per month
would see an increase of approximately $2.97 a month on their electricity bill, and the Company
provided a summary of the estimated increased percentage impacts by customer class:
• Residential Customers – (3.2%)
• Residential Schedule 36 – (3.7%)
• General Service Schedule 6 – (4.6%)
• General Service Schedule 9 – (5.8%)
• Irrigation Service Schedule 10 – (4.1%)
• General Service Schedule 23 – (3.8%)
• General Service Schedule 35 – (4.4%)
• Public Street Lighting – (2.2%)
• Tariff Contract 400 – (6.0%)
The Company requested that its proposed adjustment to the Electric Service Schedule No.
94, Energy Cost Adjustment, become effective on June 1, 2022.
On April 20, 2022, the Commission issued a Notice of Application and Modified Procedure
setting comment deadlines. Order No. 35376. P4 Production, L.L.C. and PacifiCorp Idaho
Industrial Customers (“PIIC”) petitioned to intervene, and the Commission granted their petitions.
Order Nos. 35374 and 35393.
Having reviewed the record, the Commission approves the Company’s Application as
discussed below.
BACKGROUND
The Commission approved the use of the ECAM in 2009. Order No. 30904. Every month,
the Company tracks the difference between the actual net power costs (“NPC”) it incurred to serve
ORDER NO. 35419 2

customers, and the base NPC it collected from customers through previously established base rates.
Those costs vary by year with changes in the Company’s gas and coal fuel costs, surplus power
sales, power purchases, and associated transmission. 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. The ECAM allows the Company to credit or collect the difference between actual
NPC and base NPC through a decrease or increase in customer rates.
In addition to the NPC difference, the ECAM includes: (1) the Load Change Adjustment
Revenues (“LCAR”); (2) an adjustment for coal stripping costs under Emerging Issues Task Force
(“EITF”) 04-06; (3) a true-up of 100% of the incremental Renewable Energy Credit (“REC”)
revenues; (4) Production Tax Credits (“PTC”); (5) the Lake Side 2 generation resource adder; (6)
a resource tracking mechanism (“RTM”); and (6) the reasonable energy price (“REP”), as defined
in the 2020 Protocol, qualified facility (“QF”) and energy imbalance market (“EIM”) body of state
regulators (“BOSR”) costs. The ECAM also includes a “90/10 sharing band” in which customers
pay/receive 90% of the increase/decrease in the difference between actual NPC and base NPC,
LCAR, and the EITF 04-06 coal stripping costs; and the Company incurs/retains the remaining
10%.
COMMENTS
Commission Staff (“Staff”); the Company; and PIIC submitted comments.
A. Staff Comments
With respect to the ECAM calculation, Staff reviewed the Company’s external audit
reports, journal entries, invoices, contracts, and bills to customers. Staff also reviewed the
Company’s adjustment to actual costs, and the Company’s hedge contracts and policies. Staff
believed they reasonably safeguarded price and fuel stability. Staff also reviewed the transactions
and invoices for the EIM revenues, and the calculations of the RTM adjustment included in the
ECAM. Staff noted that the Company included three new items in this ECAM. The Company
included the REP, BOSR and the Western Resource Adequacy Program (“WRAP”) funding. Staff
believed that because the BOSR and WRAP funding were not net power cost items, those costs
should not be included in the ECAM. Staff believed that removal of the BOSR and WRAP funding
would reduce the ECAM deferral by approximately $15,000, and that the change would require
only a minor adjustment to the Schedule 94 rates.
ORDER NO. 35419 3

With respect to the rate adjustment, Staff verified that the rates in the Company’s proposed
Schedule 94, Energy Cost Adjustment, were calculated using the methodology approved in Order
No. 33440. However, Staff noted that with the changes in the deferral balances proposed by Staff,
the rates would be lower than what the Company proposed. Staff explained that the Company’s
proposed rates in Schedule 94 were voltage-level specific: 0.733 cents per kWh for secondary
service; 0.720 cents per kWh for primary service; and 0.696 cents per kWh for transmission
service. Staff’s proposed rates were 0.733 cents per kWh for secondary service; 0.719 cents per
kWh for primary service; and 0.695 cents per kWh for transmission service. Staff noted that both
the Company’s and Staff’s proposed revision to Schedule 94 increased Company revenue by
approximately 3.9%. However, Staff believed that revenue increases to specific classes would vary
because of differences in rate design among the classes. Staff concluded that the overall revenue
increase for residential Schedule 1 customers was 3.3%, and a typical residential customer using
an average of 783 kWh per month would still pay $2.97 more per month under Staff’s proposed
rates.
Staff recommended that the Commission: (1) approve the ECAM deferral balance without
the BOSR and WRAP expenses; (2) approve the rates in Attachment A to Staff’s comments, as
provided by Staff’s adjusted calculations; and (3); order the Company to provide revised tariffs for
the proposed rates.
B. PIIC Comments
PIIC commented on three issues: (1) a Utah customer’s load adjustment; (2) Navajo Tribal
Utility Authority (“NTUA”) partial requirements load; and (3) Lake Side II Outages.
With respect to the Utah customer, PIIC believed that when calculating total company load
used to calculate the ECAM surcharge, the Company removed the Utah Customer’s load, which
resulted in an increase in costs allocated to Idaho. PIIC believed that this appeared to be a new
adjustment that was not considered in the Company’s most recent rate case and raised several
important policy and allocation issues. Specifically, PIIC was concerned that the Company’s
treatment of the Utah Customer load was not consistent with the 2020 PacifiCorp Inter-
Jurisdictional Allocation Protocol (“2020 Protocol”).
With respect to NTUA, PIIC believed that the Company had not made an adjustment to
include the NTUA partial requirements loads in the adjusted total company load used to calculate
ORDER NO. 35419 4

the ECAM deferral. PIIC recommended that adjusted total company loads be increased by 258,726
MW to account for the NTUA partial requirements load.
With respect to Lake Side II outages, PIIC noted that it had not been able to fully investigate
the outages at Lakeside II, nor the impact of potential construction or other defects leading to its
poor availability in recent years. PIIC requested that Staff further investigate those outages,
including an evaluation of root cause analyses and other supporting information.
C. Rocky Mountain Reply Comments
With respect to the Utah customer issue, the Company explained that the customer at issue
entered into a contract under a Utah-specific tariff that allowed the customer to offset their load
with renewable resources. The Company reasoned that under the 2020 Protocol, the costs and
benefits resulting from a state-specific initiative were allocated and assigned on a situs basis to the
State adopting the initiative. The Company also noted that the customer contract was entered into
pursuant to Utah Electric Service Schedule No. 34 (“Schedule 34”), a tariff implementing Utah
Code section 54-17-806, and that the customer’s energy generation program had been in place
since 2016 and would not be considered a “new issue” under the 2020 Protocol. Further, the
Company noted that including the customer’s load as system load created a mismatch where all
costs were situs assigned to Utah and system load was increased reducing the overall dollar-per-
megawatt-hour cost in the Idaho ECAM. The Company believed that PIIC’s proposal was at odds
with the 2020 Protocol, was not symmetrical, and did not match costs with benefits.
With respect to the NTUA issue, the Company explained that for purposes of calculating
jurisdictional allocation factors, the Company begins with total metered load for each state, and
that Utah’s metered load was inclusive of all customers, Federal Energy Regulatory Commission
(“FERC”) and NTUA included, located in the state. The Company believed that no adjustment
was necessary to Utah load to include NTUA’s metered load, as that load was already included in
Utah’s metered load.
With respect to the Lake Side II outage issue, the Company believed that because PIIC did
not provide any factual basis for its conclusion, the Commission should disregard the issue.
Finally, with respect to Staff comments, the Company believed that the BOSR and WRAP
fees were directly associated with NPC and should be included in NPC. However, the Company
reasoned that even if the Commission decided to remove those expenses, the Company did not
believe it was necessary to revise rates or update Schedule 94. The Company explained that the
ORDER NO. 35419 5

ECAM deferral was a balancing account, and the difference in the load used to develop Schedule
94 rates and actual energy consumed during the collection period would have a much larger impact
on the balance than the approximate $15,000 associated with the two adjustments requested by
Staff.
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 fix the same by order. Idaho Code
§§ 61-501, -502, and -503.
The Commission has reviewed the Company’s Application including all submitted
testimony and exhibits, Staff’s comments, all Intervenor comments, and all Company reply
comments. Based on its review of the record, the Commission finds it fair, just, and reasonable to
approve the Company’s Application with some exceptions. Specifically, the Commission finds
that the BOSR and WRAP funding are not net power cost items, and those costs should not be
included in the ECAM. However, given the totality of the ECAM calculation relative to the BOSR
and WRAP funding, the Commission finds that the Company’s Application complies with the
Commission’s prior orders and directives concerning the recovery of deferred NPC incurred by
the Company during the deferral period.
Accordingly, the Commission approves the $28.4 million in deferred costs from the
deferral period beginning January 1, 2021, through December 31, 2021, and a 4.5 percent increase
to Electric Service Schedule No. 94, Energy Cost Adjustment.
ORDER
IT IS HEREBY ORDERED that the Company’s Application for $28.4 million in deferred
costs from the deferral period beginning January 1, 2021, through December 31, 2021, is approved,
less the amounts for BOSR and WRAP funding. The Company’s Application for a 4.5 percent
increase to Electric Service Schedule No. 94 Energy Cost Adjustment, with new rates effective
June 1, 2022, is approved.
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
ORDER NO. 35419 6

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 and 62-619.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 26th day of
May 2022.

ERIC ANDERSON, PRESIDENT

JOHN CHATBURN, COMMISSIONER

JOHN R. HAMMOND JR., COMMISSIONER

ATTEST:

Jan Noriyuki
Commission Secretary

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