20260528Final_Order_No_37051.pdf

Office of the Secretary
Service Date
May 28,2026
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF ROCKY MOUNTAIN ) CASE NO. PAC-E-26-05
POWER'S APPLICATION REQUESTING )
APPROVAL TO RECOVER$4.1 MILLION )
ASSOCIATED WITH THE ECAM ) ORDER NO. 37051
DEFERRAL AND REFUND $1.4 MILLION )
ASSOCIATED WITH THE RRA )
On April 1, 2026, Rocky Mountain Power, a division of PacifiCorp ("Company") applied
to the Idaho Public Utilities Commission ("Commission") requesting authorization to adjust its
rates under the Energy Cost Adjustment Mechanism ("ECAM"), effective June 1, 2026
("Application"). Application at 1. The Company requested approval of. (1) approximately $4.1
million in ECAM deferral—and a corresponding 0.7% decrease to Schedule No. 94, Energy Cost
Adjustment ("Schedule 94"); and (2) returning approximately $1.4 million in renewable energy
credit ("REC") revenue to customers under Schedule No. 98, REC Revenue Adjustment
("Schedule 98")—and a corresponding 0.4% decrease in rates.' Id.
On April 20, 2026, the Commission issued a Notice of Application and a Notice of
Modified Procedure, establishing public comment and Company reply deadlines. Order No.
37006. Commission Staff("Staff') filed comments to which the Company replied briefly asking
the Commission to adopt the recommendations outlined in Staff's comments.
Based on our review of the record, we issue this Final Order approving the Company's
ECAM deferral balance, the return of REC revenues through the REC Revenue Adjustment, and
Schedules 94 and 98 as filed, effective June 1, 2026.
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
' Prior to 2024, the Company's REC revenues were included in the ECAM. In its 2024 rate case, the Company
proposed returning REC revenues in a separate schedule,which was approved by the Commission in Order No.36452.
ORDER NO. 37051 1

costs ("NPC") it incurred to serve customers, and the embedded (or base) NPC it collected from
customers through base rates established in the most recent general rate case. The Company defers
the difference between actual NPC and base NPC—higher or lower—into a balancing account for
treatment at the end of the yearly deferral period.At that time, the ECAM allows the Company to
credit or collect through a surcharge the difference between actual NPC and base NPC through a
temporary decrease or increase in customer rates in Schedule 94.
THE APPLICATION
The Company represented that in addition to the NPC difference,the Company's proposed
ECAM adjustment under Schedule 94 for January 1, 2025 through December 31, 2025, included:
(1)Load Change Adjustment Revenues ("LCAR"); (2) coal stripping costs under Emerging Issues
Task Force 04-6 ("EITF"); (3) Production Tax Credits ("PTC"); (4) the reasonable energy price,
as defined in the 2020 Protocol; (5) qualified facility costs; and (6) wind availability liquidated
damages.Application at 3.
The Company requested approval to implement its proposed Schedule 94 rates of 1.064,
1.044, and 1.009 cents per kilowatt-hour ("kWh") for secondary, primary, and transmission
delivery service voltages, respectively. Id. at 7. Under its proposal, the Company would return
approximately $1.4 million to customers. Id. at 8. The Company represented that if approved, the
proposed Schedule 94 rates would result in a 0.6% decrease for standard tariff customers, a 1.1%
decrease for Schedule 400 customers, and an overall 0.7% decrease for Idaho customers.Id. at 7.
The Company also requested approval to implement its proposed rates for Schedule 98.Id.
at 8. The Company stated that if the proposed Schedule 98 rates were approved, there would be a
0.6%decrease for standard tariff customers,no change for Schedule 400 customers,and an overall
0.4% decrease for Idaho customers. Id. at 8-9.
STAFF COMMENTS
1. ECAM Analysis and Calculation.
Staff recommended the Commission approve the Company's $49,331,797 ECAM deferral
for 2025. Staff Comments at 2. To develop these recommendations, Staff reviewed the Company's
ECAM deferral calculation, confirming it accurately reflected actual loads, costs, and revenues,
and was consistent with prior Commission orders. Id. Staff also verified that the application of
base rate components was correct.Id. To ensure accuracy, Staff: (1)reviewed audit reports,journal
ORDER NO. 37051 2

entries, invoices, and contracts; (2) reviewed evaluation adjustments to NPC costs; and (3)
reconciled ledger amounts, assessed hedge contracts for compliance, and verified Energy
Imbalance Market revenues included in the Company's ECAM calculation.Id. at 3. Staff outlined
the Company's 2025 ECAM deferral in the following table:
Table No. 1:Deferred ECAM Balance
NPC Differential for Deferral $ 2,631,661
EITF 04-6 Adjustment 84,392
LCAR (2,146,378)
Wheeling Revenues 34,954
Total Deferral Before Sharing 604,629
Sharing Band 90%
Customer Responsibility 544,166
Production Tax Credits (1,047,075)
REP QF Adjustment 1,308,827
Wind Liquidated Damages (265,256)
REC Deferral 21,598
Interest on Deferral 3.522,536
Annual Deferral(Jan- Dec 2025) 4,084,796
Unamortized Previous Balance 88,620,076
ECAM Rider Revenues 43,373,074
Total Company Recovery $ 49,331,797
Id.
Staff calculated the NPC to serve Idaho customers was $139.0 million but the revenue
collected through base rates was only $136.4 million. Id. at 4. After applying the 90/10 sharing
band, Staff calculated the Company's customers are responsible for$544,166 through the ECAM.
Id. Regarding the EITF adjustment, Staff calculated that the EITF increased the ECAM deferral
by $84,392 before applying the 90/10 sharing band. Id. Regarding the LCAR, Staff stated that
Order No. 36452 set the Company's LCAR rate at$6.29 per megawatt hour("MWh")for February
2025 through December 2025. Id. at 5. Staff calculated that the Company collected $25.4 million
through the LCAR. Id. Staff determined that the difference between the collected $25.4 million
and the $23.2 million embedded in base rates decreased the ECAM deferral by $2.15 million.Id.
Regarding wheeling revenues, Staff explained that Order No. 36452 established an Idaho-
allocated wheeling revenue rate of$2.97 per MWh. Id. After applying the rate to billed energy
consumption for Idaho during February 2025 to December 2025, Staff determined that the
ORDER NO. 37051 3

difference between what was recovered through base rates, and the actual Idaho-allocated
wheeling revenues, increased the ECAM deferral by $34,954.Id.
Staff confirmed the PTC true-up rate was set at$4.31 per MWh for February 2025 through
December 2025 in accordance with Order No. 36452. Id. Staff also confirmed that the PTC true-
up rate remained at $4.16 per MWh for January 2025 in accordance with Order No. 35277. Id.
Staff calculated in 2025 there was a$16.3 million PTC benefit.Id. Actual PTCs allocated to Idaho
customers were $17.3 million. Id. Staff determined the difference between the PTC benefit, and
what was allocated to Idaho customers, reduced the ECAM deferral by $1.0 million. Id. Staff
believed the Company applied the $52,243 balancing account error credit (required by the
Commission in Order No. 3 662 1) to the 2025 ECAM filing.Id. at 6.
Staff reviewed the Company's process for determining "the reasonable energy price and
the contract energy price" for relevant qualifying facilities ("QF") contracts and believed that the
Company complied with the 2020 Protocol that was approved by the Commission in Order No.
34640. Id. Staff also confirmed the ECAM also included $265,256 for the wind availability
liquidated damages credit as required by Order No. 33954.Id. Staff believed that the ECAM only
included a true-up for actual REC revenues for January 2025, which was consistent with Order
No. 36452.Id. at 6-7.
Staff reviewed the Company's interest calculation,method,and rate assumptions,including
the Company's use of a 5% interest rate, which matched the Commission approved customer
deposit rate from Order No. 36390,and determined the calculation and application of the rate were
reasonable. Staff Comments at 7.
2. Analysis of Actual NPC.
Staff asserted that the ECAM deferral decreased due to a lower actual unit cost of energy
at $34.37 per MWh, compared to the $36.91 per MWh cost included in base rates. Id. To assess
the prudency of the Company's NPC, Staff compared the energy amounts and costs in base rates
to the actual energy use and costs in 2025 across various resource types, as illustrated in Table No.
2 below:
ORDER NO. 37051 4

Table No.2: Comparison of Base and Actual NPC
Source Amt of Energy Amt of Unit Cost Unit Cost
million MWh) Energy $/MWh
Actual Base %Change Actual Base %Change
NPC NPC NPC NPC
Wholesale Sales 4.04 4.39 -8.0% 44.81 61.10 -26.7%
Total Purchased Power 18.74 20.74 -9.6% 51.55 56.67 -9.0%
-Other Purchases 9.48 12.54 -24.5% 72.61 72.36 0.3%
-Long-term Purchase 9.27 8.20 13.1% 30.00 32.65 -8.1%
Coal Resource 23.29 22.11 5.3% 30.35 30.53 -0.6%
Gas Resource 15.38 11.95 28.7% 34.38 41.47 -17.1%
Hydro Resource 2.57 3.04 -15.5% - - -
Other Resource (wind, 8.28 7.07 17.0% 0.70 0.79 -11.1%
solar,etc.
Total System 64.22 60.53 6.1% 34.37 37.50 -8.3%
Id. at 7-8. Staff found the lower NPC unit costs were mainly due to purchased power prices being
lower and because more energy was produced from lower cost coal and gas resources.Id. at 8.
According to Staff's analysis, the cost of energy from market purchases was 9.6% lower
and the cost of energy from hydro generation was 15.5% lower. Id. Staff also determined that
energy from coal and gas generation was 5.3% and 28.7% higher, respectively. Id. Staff believed
NPC was mainly affected by: (1)the fact that purchased power and natural gas prices were lower;
and(2)that there was a stable and consistent coal fuel supply.Id. Staff found that actual purchased
power unit cost was 9.0% lower than the base and that actual natural gas unit cost was 17.1%
lower.Id. at 8-9. Staff believed the lower gas prices decreased the costs for natural gas generation,
which allowed the Company to use its gas units more, and reduced by 9.6%the amount of market
purchases needed to meet load.Id. at 9.
Staff believed that the stabilization of coal fuel supply could reduce the Company's need
for purchased power to meet load because the Company could count on coal generation being
available. Id. Staff believed the Company's ability to use additional lower cost coal and gas
generation in the deferral period helped lower the NPC cost. Id. Staff noted that as the Company
relies more on gas generation and market purchases,the Company's NPC will likely become more
subject to the unpredictability of the markets for natural gas and wholesale electricity. Id. Staff
ORDER NO. 37051 5

highlighted that the Company increased its long-term market purchases by 13.1% at a lower cost
which hedged the Company's "price risk for market purchases of natural gas and electricity."Id.
Staff reviewed Company planned and forced outages for each of the Company's thermal
generating units that were provided in the Company's Response to Staff's Audit Request at No. 6.
Id. Based on this review, Staff reached two conclusions: (1)the amount and causes of forced outage
downtime were reasonable when compared to the previous year; and(2)both the planned and any
additional unplanned downtime had clear justification and were deemed reasonable.Id. at 9-10.
Staff calculated line loss by comparing the Idaho load at input to the load at customer
meters, as illustrated in Table No. 3 below, and found a 3.06% loss in 2025:
Table No.3:Comparison of Line Loss
Category 2024 2025
ID Load at Input(MWh) 3,847,108 3,922,255
ID Sales(MWh) 3,727,500 3,802,242
Line Loss 3.11% 3.06%
Id. at 10. Staff noted the loss is lower than the line loss in 2024 and is below the 3.5%loss identified
in the Company's last line loss study completed in 2018.Id. Staff believed the result indicated that
the Company's line loss during 2025 was reasonable.Id.
3. Proposed Rates.
Staff confirmed that the Company's proposed Schedule 94 rates complied with Order No.
33440 and the settlement stipulation approved in Order No. 36452, the Company's most recent
general rate case. Id. Table No. 4 below illustrates Staff's summary of the Company's proposed
rates for each customer type:
Table No.4:Comparison of Current and Proposed Schedule 94 Rates
Service Type Current Rates Proposed Rates Decrease
(cents/kWh) (cents/kWh) (%)
Secondary Distribution 1.137 1.064 -6.42%
Primary Distribution 1.116 1.044 -6.45%
Transmission 1.079 1.009 -6.49%
Id. Staff determined that the Company's proposed Schedule 94 rates would decrease overall
revenue by 0.7%, though the impact would vary by customer class due to rate design differences.
ORDER NO. 37051 6

Id. at 11. For residential customers, Staff believed the average overall revenue decrease would be
0.5%.Id. Staff calculated that under the proposed rates, a residential customer using 836 kWh per
month "would pay $0.61 less per month." Id. Regarding the proposed Schedule 98 rates, Staff
confirmed that the Company's proposed rates complied with the REC Revenue Adjustment
approved by the Commission in Order No. 36452.Id.
4. Customer Notice and Press Release.
Staff believed the press release and customer notice provided with the Application satisfied
Rule 125 of the Commission's Rules of Procedure (IDAPA 31.01.01.125). Id. Because the
Commission set a comment deadline of May 8, 2026, Staff believed that some customers may not
have had enough time to respond and thus recommended the Commission consider any late filed
comments by customers.Id. at 12.
COMMISSION FINDINGS AND DECISION
The Commission has jurisdiction over the Company's Filing 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 record in this case. Based on our review,we find it fair,
just, and reasonable to approve the Company's Application. Specifically, we approve of the
Company recovering $4,084,796 in deferred costs from the deferral period beginning January 1,
2025, through December 31, 2025, and a corresponding 0.7% decrease to Schedule 94.
Additionally, we approve of the Company returning $1,381,352 in REC revenue to customers
under Schedule No. 98 and a corresponding 0.4% decrease in rates for Idaho customers.
ORDER
IT IS HEREBY ORDERED that the Company's Application for Schedule 94 deferred
costs from the deferral period beginning January 1, 2025, through December 31, 2025, in the
amount of$4,084,796 is approved, effective June 1, 2026.
IT IS FURTHER ORDERED that the Company's Application for a 0.7% decrease to
Schedule 94 is approved, effective June 1, 2026.
ORDER NO. 37051 7

IT IS FURTHER ORDERED that the Company's Application to return$1,381,352 in REC
Revenues through Schedule 98 to customers is approved, effective June 1, 2026.
IT IS FURTHER ORDERED that the Company's Application for a 0.4% decrease in
Schedule 98 rates for Idaho customers is approved, effective June 1, 2026.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within 21 days of the service date of this Order regarding any matter decided in
this Order.Within seven days after any person has petitioned for reconsideration, any other person
may cross-petition for reconsideration.Idaho Code § 61-626.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 281h day of
May 2026.
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ORDER NO. 37051 8