20260508Staff Comments.pdf

RECEIVED
May 08, 2026
KELSEA E. ROSS IDAHO PUBLIC
DEPUTY ATTORNEY GENERAL UTILITIES COMMISSION
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83702
[phone]
IDAHO STATE BAR NO. 12050
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF ROCKY MOUNTAIN )
POWER'S APPLICATION REQUESTING ) CASE NO. PAC-E-26-05
APPROVAL TO RECOVER$4.1 MILLION )
ASSOCIATED WITH THE ECAM )
DEFERRAL AND REFUND $1.4 MILLION ) COMMENTS OF THE
ASSOCIATED WITH THE RRA ) COMMISSION STAFF
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission
("Commission"),by and through its attorney of record,Kelsea E. Ross,Deputy Attorney General,
submits the following comments.
BACKGROUND
On April 1, 2026, Rocky Mountain Power, a division of PacifiCorp ("Company"), applied
to the Commission requesting authorization to adjust its rates under the Energy Cost Adjustment
Mechanism ("ECAM"). Specifically, the Company requests that the Commission approve: (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 $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 ("Application"). Application at 1.
The Company requests that this matter be processed by Modified Procedure and become effective
on June 1, 2026. Id. at 10.
On April 20,2026,the Commission issued a Notice of Application and Notice of Modified
Procedure establishing deadlines for written comments. Order No. 37006.
STAFF COMMENTS 1 MAY 8, 2026

The ECAM allows the Company to adjust 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 established in the most recent general rate case. The Company defers the difference
between actual NPC and base NPC 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 the difference
between actual NPC and base NPC through a temporary decrease or increase in customer rates.
Besides the NPC difference, the Company's proposed ECAM adjustment under Schedule
94 for January 1, 2025 through December 31, 2025 includes: (1) Load Change Adjustment
Revenues; (2) coal stripping costs under Emerging Issues Task Force 04-6; (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 proposes 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,
and represents that those 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 represents its proposed rates for Schedule 98 would result in 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 ANALYSIS
Staff reviewed the Company's calculation for the ECAM deferral and determined it is
consistent with prior Commission orders. Staff verified the accuracy of actual loads, costs, and
revenues received by the Company, as well as the correct application of the loads, costs, and
revenues embedded in base rates. Based on its review, Staff believes the Company's ECAM
deferral balance appropriately reflects the variance between the energy costs and revenues
included in base rates and the actual costs and revenues realized during 2025 and recommends that
the Commission approve the 2025 ECAM deferral as detailed below in Table No. 1:
STAFF COMMENTS 2 MAY 8, 2026

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 $ 49,3311797
Staff performed an audit of the Company's reported energy costs and revenues, including
an examination of external audit reports, journal entries, invoices, and contracts to verify the
accuracy of recorded transactions. To ensure accuracy, Staff evaluated the Company's
adjustments to actual NPC costs to ensure they were appropriately calculated and supported. In
addition, Staff reconciled general ledger amounts to the NPC to confirm consistency and accuracy.
A detailed assessment of hedge contracts and the Company's hedging policies was performed to
determine compliance with approved risk management practices. Finally, Staff reviewed
transactions and supporting invoices related to Energy Imbalance Market revenues to validate the
amounts included in the ECAM calculation. A summary of Staff s evaluations and analysis is
provided below.
Net Power Cost Deferral
In the ECAM, the NPC adjustment allows the Company to recover from, or credit to,
customers the difference between the actual NPC incurred to serve Idaho customers and the
amount recovered through base rates during the yearly deferral period. Application at 2. The
Company's base rates reflect an NPC of$36.91 per MWh for February 2025 through December
2025, which is consistent with Order No. 36452. Painter Direct Exhibit No. 1 at Line No. 4. The
STAFF COMMENTS 3 MAY 8, 2026

January 2025 NPC remained at $24.54 per MWh, consistent with Order No. 35277. Id. The
Company represented that Idaho's actual 2025 billed energy consumption was 3,802,242 MWh.
Painter Direct Exhibit No. 1 at Line No. 5.
By applying the Company's embedded NPC rates—$24.54 for January 2025 (Order No.
35277), and $36.91 for February 2025 through December—to Idaho's actual 2025 billed energy
consumption of 3,802,242 MWh, Staff calculated that the Company's base rate revenue for 2025
was approximately $136.4 million. The Company represented that Idaho's share of actual NPC
for 2025 totaled $139.0 million. Painter Direct Exhibit No. 1 at Line No. 11. The difference
between 2025 base rate revenues collected and Idaho's share of actual NPC resulted in an under-
collected balance of$2.63 million. The Company absorbs ten percent of the NPC balance from
this under-collected balance subject to the ECAM's 90/10 sharing mechanism. After applying the
sharing mechanism, Staff calculated that the remaining balance of$544,166(the 90%), as outlined
in Table No. 1,represented the amount to be recovered from customers through Schedule 94 rates.
Emerging Issues Task Force
The Emerging Issues Task Force ("EITF") 04-6 Adjustment represents the difference
between the coal stripping costs incurred and recorded by the Company in accordance with
accounting guidance under EITF 04-6, and the amortization methodology approved in Order No.
30987, issued in Case No. PAC-E-09-08. Under EITF 04-6 Adjustment,the Company is required
to expense coal stripping costs as incurred, rather than amortize them over the volume of coal
produced from a specific section of open-pit mines. As described in Exhibit No. 1, Line 13, the
adjustment reflects the difference between coal stripping costs recorded pursuant to EITF 04-6 and
the Commission-approved amortization of those costs approved in Order No. 30987, Case No.
PAC-E-09-08. For the 2025 deferral period, Staff calculated that the EITF 04-6 Adjustment
increased the ECAM deferral balance by approximately$84,392 before applying the 90/10 sharing
mechanism.
Load Change Adjustment Revenues
The LCAR captures the under- or over-recovery of fixed, energy-classified production
costs (excluding NPC) resulting from differences between Idaho sales used to establish base rates
and actual sales during the deferral year. Application at 6. In Case No. PAC-E-24-04, the
Company's LCAR rate was set at $6.29 per MWh for February 2025 through December 2025,
STAFF COMMENTS 4 MAY 8, 2026

while the January 2025 rate remained at $8.74 per MWh pursuant to what was required in Order
No. 35277. By applying these rates to the 2025 actual Idaho sales of 3,802,242 MWh, Staff
calculated that approximately $25.4 million in energy-classified fixed production costs was
recovered through base rates. By comparing the $25.4 million in energy-classified fixed
production costs to the$23.2 million embedded in base rates detailed in Painter Direct Exhibit No.
1 at Line No. 14, Staff determined there was a $2.15 million decrease to the ECAM deferral.
Wheeling Revenues
Beginning February 1, 2025, the Company included wheeling revenues in the ECAM
deferral. Application at 5. In Order No. 36452 issued in Case No. PAC-E-24-04,the Commission
approved the settlement in which an Idaho-allocated wheeling revenue rate of$2.97 per MWh was
established. The Company represented that Idaho's 2025 actual billed energy consumption was
3,486,720 MWh. Painter Direct Exhibit No. 1 at Line No. 20. Staff applied this rate to 2025 actual
Idaho billed energy consumption of 3,486,720 MWh during February 2025 through December
2025 and calculated that $10.36 million was recovered through base rates. Staff calculated that
the Company's actual Idaho-allocated wheeling revenues totaled$10.33 million. Staff calculated
that the difference between actual Idaho allocated wheeling revenues and revenues collected in
base rates increased the ECAM deferral by $34,954.
Production Tax Credits
In Order No. 33668, the Commission approved a settlement wherein the parties agreed to
move the PTC true-up into the ECAM. PTCs are federal tax credits associated with qualifying
renewable generation that reduce net power costs for customers. In Order No. 36452, the
Commission set the PTC rate at$4.31 per MWh for February 2025 through December 2025,while
the January 2025 rate remained at$4.16 per MWh under Order No. 35277. Painter Direct Exhibit
No. 1 at Line No. 27. In 2025, base rates included a $16.3 million PTC benefit Painter Direct
Exhibit No. 1 at Line No. 29., while actual PTCs allocated to Idaho customers totaled $17.3
million. Painter Direct Exhibit No. 1 at Line No. 30. Staff calculated that the difference between
the $16.3 million PTC benefit and $17.3 million of actual PTCs allocated to Idaho customers
reduced the ECAM deferral by approximately $1.0 million.
In Case No. PAC-E-25-04 the Company discovered an error in its calculation of PTC
credits which would reduce the overall recovery. Order No. 36621 at 2. In Order No. 36621, the
STAFF COMMENTS 5 MAY 8, 2026

Commission ordered the Company to adjust the balancing account to address the $52,243 error in
the PTC calculation and credit customers in the next ECAM filing. Based on Staff s review, Staff
believes that the credit was applied to the 2025 ECAM filing.
Reasonable Energy Price OF Adiustment
The "2020 Protocol," approved by the Commission in Order No. 34640, included a
provision that all qualifying facilities("QF")contracts approved in 2020 and after would be subject
to a reasonable price adjustment. The amount the Company paid for energy under each QF
contract over a reasonable energy price would be directly allocated to the state that approved the
QF contract. Painter Direct at 11-12.
Staff reviewed the Company's process for determining both the reasonable energy price
and the contract energy price for the applicable QF contracts and believes it complies with the
2020 Protocol. The reasonable energy price QF adjustment results in a$1.3 million increase to the
Idaho ECAM deferral. Painter Direct at 12.
Wind Availability Liquidated Damages
Under the stipulation approved in Order No. 33954 issued in Case No. PAC-E-17-06, the
Company agreed to pass through all liquidated damages received from wind facility suppliers in
the event that repowered equipment failed to meet specified performance standards. In this case,
the Company represented it allocated the liquidated damages using the system generation factor
and applied the resulting credit to customers. Painter Direct at 12. In this ECAM filing, the
Company included a$265,256 credit to customers related to wind availability liquidated damages.
Painter Direct Exhibit No. 1 at Line No. 34. Staff reviewed the Company's supporting
documentation and agrees with including the credit to NPC.
Renewable Energy Credits
In Order No. 36452,the Commission approved a settlement that discontinued the inclusion
of REC revenues in the ECAM beginning February 1, 2025. Prior to that change, the ECAM
tracked the difference between actual REC revenues recorded during the deferral period and the
amount of REC revenues credited to customers in base rates. In Order No. 35277,the Commission
approved a REC revenue credit of$0.07 per MWh to be included in the Company's base rates.
STAFF COMMENTS 6 MAY 8, 2026

The 2025 ECAM includes a true-up for actual REC revenues for January only, which Staff
calculated results in a $21,598 increase to the ECAM deferral balance.
REC Revenue Adjustment
In Case No. PAC-E-24-04, the Company proposed removing REC revenues from the
ECAM and establishing a new mechanism to track REC revenues. In Order No. 36452, the
Commission approved a settlement establishing the REC Revenue Adjustment ("RRA"), or
Schedule 98. The RRA deferral balance reflects the difference between the Company's actual
REC revenues recorded during a calendar year and the amount of REC revenues included in base
rates, which is zero in this filing. Highsmith Direct at 4. In addition, the RRA applies a carrying
charge on deferred RRA balance equal to the customer deposit rate of 5% for 2025. Order No.
36390.
During calendar year 2025,the Company allocated $1.3 million in REC revenues to Idaho
and applied approximately $32,401 in carrying charges. Highsmith Direct Exhibit No. 2 (See
Highsmith Direct at 6). The Company represented that together these amounts produce a total
RRA deferral balance of$1.4 million, which the Company proposes to refund to customers over
the period June 1, 2026, through May 31, 2027. Application at 8-9. Staff reviewed the RRA
mechanism and the Company's exhibits supporting its calculations and verified that the
Company's RRA calculations were accurate.
Accrued Interest
The Company accrued $3.5 million in interest on the uncollected ECAM balance during
the deferral period. Id. at 7. Staff reviewed the Company's interest calculation and verified that
it applied the customer deposit rate of 5%approved by the Commission in Order No. 36390. Staff
confirmed that the Company's calculation and application of the interest rate were reasonable and
consistent with Commission practice.
Analysis of Actual NPC
The decrease in the ECAM deferral is reflected by the lower $34.37 per MWh overall
actual unit cost of energy when compared to the $36.91 per MWh unit cost of energy embedded
in the Company's base rates. Painter Direct at 13 and Exhibit No. 1 at Line No. 3. To determine
whether the Company generally incurred NPC in a prudent manner, Staff compared the amount
STAFF COMMENTS 7 MAY 8, 2026

and cost of energy embedded in its base rates to the actual amount and cost of energy incurred
during the 2025 deferral period for the Company's different types of resources as illustrated in
Table No. 2,below. The amount and cost of energy embedded in base rates for January 2025 were
set in Case No. PAC-E-21-07 and provided in Case No. PAC-E-25-04 Exhibit No. 1 workpapers
provided. Base rates for the 2025 deferral period were set in Case No. PAC-E-24-04 and provided
by the Company in response to Staff s Audit Request at No. 20 in this case. Actual amount and
cost of energy incurred during the 2025 deferral period were provided by the Company in Exhibit
1 workpaper provided with the Application. Through this analysis, Staff believes the lower unit
costs of NPC were primarily caused by lower purchased power prices and producing more energy
from lower cost coal and gas resources.
Table No. 2: Comparison of Base and Actual NPC
Source Amt of Energy Amt of Unit Cost Unit Cost
million MWh Ener $/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%
The Company's base rates for January 2025 were established by Order No. 35277 and the
base rates for February 2025 to December 2025 were established by Order No. 36452. When Staff
compared the amounts reflected in the base rates, it calculated that the actual amount of energy
from market purchases and hydro generation were lower by 9.6% and 15.5%, respectively, while
the amount of energy from coal and gas generation were higher by 5.3% and 28.7%, respectively.
Staff believes that the major drivers affecting NPC were: (1) lower purchased power and
natural gas prices; and (2) a stable and consistently available coal fuel supply. Staff calculated
STAFF COMMENTS 8 MAY 8, 2026

that the Company's actual purchased power unit cost was lower than the base by 9.0% and actual
natural gas unit cost was lower by 17.1% (See Table No. 2). Lower gas prices decreased the
Company's cost of natural gas generation allowing the Company to dispatch its gas units more and
reduce the amount of market purchases needed to meet load by 9.6% when compared to the
amounts assumed in base rates.
From 2022 to 2024,the Company experienced coal supply constraint issues. Painter Direct
at 4. In 2025, the coal fuel supply has stabilized relative to supply uncertainties occurring from
2022 through 2024. Id. Staff believes that by counting on coal generation availability, the
Company can again use coal generation as a hedge against more volatile purchased power and
natural gas prices, further reducing the need for purchased power to meet load. Although actual
electricity market prices were lower than market prices embedded in base rates, which also
contributed to lower NPC, Staff believes the ability to dispatch larger amounts of lower cost coal
and gas generation during the deferral period contributed more overall to lower cost NPC for Idaho
customers.
However, Staff believes that as the Company moves towards reliance on gas generation
and market purchases due to coal-to-gas conversions, it is likely the Company's NPC will become
increasingly subject to the volatility of the natural gas and wholesale electricity markets. Staff
believes this will place more importance on the ability of the Company to hedge its price risk
within those markets. Staff notes that in 2025, the Company increased the amount of long-term
market purchases by 13.1%, as shown in Table No. 2, at a lower cost compared to the base, which
hedges its price risk for market purchases of natural gas and electricity.
Thermal Plant Downtime
It is Staff s position that excessive thermal plant downtime can have a major impact on the
Company's actual NPC passed through the ECAM. Staff reviewed the amount of planned and
forced outages that occurred for each of the Company's thermal generating units. Response to
Staffs Audit Request at No. 6. Staff reviewed the data and believes: (1)the amount and causes of
downtime due to forced outages were reasonable when compared to downtime that occurred during
the previous year; and (2)the Company was able to conduct its planned maintenance on most of
its generating units in about the same amount of time it planned for them to be down. However,
when the actual amount of time was greater than the amount planned, Staff believes the Company
STAFF COMMENTS 9 MAY 8, 2026

was able to show it acted prudently and had sound justification for the additional amount of
downtime.
Line Loss
Staff reviews the line losses in each ECAM filing to ensure the amount of load at input is
correct. The load at input is a critical component of the Company's ECAM calculation
methodology and must be correct to calculate an accurate deferral. The load at input is the net
amount of MWhs that is metered into and out of Idaho at its borders and should be equal to Idaho's
customer load including its share of line losses. By taking the difference between the load at input
and the amount of load at the customers' meter, the amount of line losses can be calculated,which
should remain reasonably stable each year. Staff believes that the Company's line loss calculation
in the 2025 deferral period is reasonable and is within an acceptable range.
Staff calculated the line loss percentage by calculating the percentage difference between
Idaho load at input and Idaho load at customer meter and compared it to the line loss percentage
from the previous year as shown in Table No. 3 below. The 3.06%line loss in 2025 is lower than
the line loss in 2024 calculated in last year's ECAM (See Table No. 3). This year's line loss
amount was also less than the overall transmission line loss of 3.5% that was identified in the
Company's last line loss study conducted in 2018. Staff believes that the line loss in the deferral
period from January 2025 through December 2025 is reasonable.
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%
Proposed Schedule 94 Rates
Staff verified that the rates in the Company's proposed Schedule 94 were calculated using
the methodology approved in Order No. 33440 and comply with the settlement stipulation
approved through Order No. 36452. Staff believes the proposed rates in Schedule 94, which were
included with the Application as Exhibit No. 3 of Elder's testimony and is included as Attachment
STAFF COMMENTS 10 MAY 8, 2026

A, are line-loss adjusted depending on service type or voltage level that each customer receives
service. Table No. 4 below summarizes the Company's proposed rates for each type of customer.
Table No. 4: Comparison of Current and Proposed Schedule 94 Rates
Current Rates Proposed Rates Decrease
Service Type
(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%
Staff calculated that the Company's proposed revision to Schedule 94 decreases Company
revenue by 0.7%. However, Staff believes the revenue decrease to specific classes will vary
because of differences in rate design among the classes. If approved, Staff believes the Company's
proposed revision will result in an overall revenue decrease for residential customers of 0.5%. A
typical residential customer using an average of 836 kWh per month would pay $0.61 less per
month under the proposed rates. Application Customer Notices.
Proposed Schedule 98 Rates
Staff verified that the rates in the Company's proposed Schedule 98are consistent with the
RRA proposal presented in Case No. PAC-E-24-04 and approved through Order No. 36452. The
proposed rates are designed to refund $1.4 million to customers. Application at 1. The average
decrease to customer classes will be 0.6 percent, if approved. Id. The Company's proposed rates
are included with the Application as Exhibit No. 4 of Elder's testimony. Tariff Contract 400's
rates do not change because the Company represents the REC revenues are being excluded from
Schedule 400. Elder Direct at 4. In addition, customers in the voluntary REC Option Program,
Schedule 74,will not receive rate changes related to Schedule 98 because customers who enroll in
the program do not receive any credits for sales of RECs in their rates. Application at 8.
CUSTOMER COMMENTS
The Company's press release and customer notice were included in the Application. Staff
reviewed the documents and determined that both met the requirements of Rule 125 of the
Commission's Rules of Procedure. Rule 125, IDAPA 31.01.01.125. The Company represented
STAFF COMMENTS 11 MAY 8, 2026

that customer notice was included with billing statements mailed to customers from April 3
through May 4, 2026. Application at 10. The Company also represented that for customers
enrolled with paperless billing, an email was sent during the same period that included a link to
the digital version of the customer notice. Id.
As of May 8, 2026, the Commission set public comment deadline (Order No. 37006), no
customer comments have been filed. Staff believes that some customers in the last billing cycle
may not have received their notices or had adequate time to submit comments before the comment
deadline. Staff believes that customers should have the opportunity to file comments and have
those comments considered by the Commission and recommends that the Commission consider
late filed comments by customers.
STAFF RECOMMENDATION
Staff recommends that the Commission:
1. Approve recovery of the $4.1 million ECAM deferral balance;
2. Approve the return of$1.4 million in REC revenues through the RRA;
3. Approve Schedules 94 and 98 rates as filed, with an effective date of June 1, 2026;
and
4. Accept the late-filed customer comments.
Respectfully submitted this 8th day of May 2026.
X'1ZVt/?A_ 9'e-1-Y
Kelsea E. Ross
Deputy Attorney General
Technical Staff: Ty Johnson, Ray McArthur, Michael Eldred, Curtis Thaden
I:\Utility\UMISC\COMMENTS\PAC-E-26-05 Comments.docx
STAFF COMMENTS 12 MAY 8, 2026

EXHIBIT NO.3
ROCKY MOUNTAIN POWER
ESTIMATED IMPACT OF PROPOSED ECAM ADJUSTMENT
FROM ELECTRIC SALES TO ULTIMATE CONSUMERS
DISTRIBUTED BY RATE SCHEDULES IN IDAHO
ADJUSTED HISTORICAL 12 MONTHS ENDED DECEMBER 2023
Present At Meter At Sch 94 ECAM Proposal Present
Line Average Base MWh by Voltage Generation Rev Rate 0/kWh ECAM Rev Net Change
No. Description Sch. Customers MWH ($000) S P T MWh ($000) S P T ($000) ($000) %
(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16)
Residential
1 Residential Service 1 61,756 619,659 $79,827 619,659 675,807 $6,590 1.064 1.044 1.009 $7,046 ($455) -0.5%
2 Residential Optional TOD 36 10,176 172,088 $19,704 172,088 187,681 $1,830 1.064 1.044 1.009 $1,957 ($126) -0.6%
3 AGA Revenue $1
4 Total Residential 71,933 791,748 $99,532 791,748 0 0 863,488 $8,421 $9,002 ($581) -0.5%
5 Commercial&Industrial
6 General Service-Large Power 6 1,120 305,548 $28,816 279,600 25,948 332,720 $3,245 1.064 1.044 1.009 $3,469 ($224) -0.7%
7 General Svc.-Lg.Power(R&F) 6A 186 22,162 $2,242 22,103 59 24,169 $236 1.064 1.044 1.009 $252 ($16) -0.7%
8 Subtotal-Schedule 6 1,306 327,711 $31,058 301,703 26,007 0 356,890 $3,480 $3,721 ($240) -0.7%
9 General Service-High Voltage 9 17 221,839 $15,539 0 0 222,699 230,500 $2,248 1.064 1.044 1.009 $2,403 ($155) -0.9%
10 Irrigation 10 5,726 551,496 $59,052 551,496 601,467 $5,866 1.064 1.044 1.009 $6,271 ($405) -0.6%
11 General Service 23 8,666 217,574 $23,810 182,662 353 0 199,592 $1,946 1.064 1.044 1.009 $2,081 ($134) -0.5%
12 General Service(R&F) 23A 2,565 42,247 $4,797 42,246 1 46,075 $449 1.064 1.044 1.009 $480 ($31) -0.6%
13 Subtotal-Schedule 23 11,230 259,822 28,608 224,909 354 0 245,667 2,396 2,561 (165) -0.5%
14 General Service Optional TOD 35 3 323 $33 323 352 $3 1.064 1.044 1.009 $4 ($0) -0.6%
15 General Service Optional TOD(R&F) 35A 1 56 $9 56 61 $1 1.064 1.044 1.009 $1 ($0)
16 Subtotal-Schedule 35 4 379 42 379 0 0 413 4 1.064 1.044 1.009 4 (0) -0.6%
17 Special Contract 400 1 1,314,200 $91,220 1,314,200 1,360,236 $13,265 1.009 $14,404 ($1,139) -1.1%
18 AGA Revenue $520
19 Total Commercial&Industrial 18,284 2,675,446 $226,038 1,078,487 26,362 1,536,899 2,795,174 $27,259 $29,363 ($2,105) -0.8%
20 Public Street Lighting
21 Security Area Lighting 7 174 230 $46 230 251 $2 1.064 1.044 1.009 $3 ($0) -0.4%
22 Security Area Lighting(R&F) 7A 119 93 $22 93 102 $1 1.064 1.044 1.009 $1 ($0) -0.3%
23 Street Lighting-Company 11 61 182 $81 182 198 $2 1.064 1.044 1.009 $2 ($0) -0.2%
24 Street Lighting-Customer 12 266 2,360 $356 2,360 2,574 $25 1.064 1.044 1.009 $27 ($2) -0.5%
25 AGA Revenue $0
26 Total Public Street Lighting 620 2,866 $506 2,866 0 0 3,125 $30 $33 ($2) -0.4%
27 Total Sales to Ultimate Customers 90,837 3,470,059 $326,076 1,873,100 26,362 1,536,899 3,661,787 $35,710 $38,398 $2,688 -0.7%
28 Total Excluding Special Contract 400 90,836 2,155,859 $234,856 1,873,100 26,362 222,699 2,301,550 $22,445 $23,994 $1,550 -0.6%
Rev.Rqmt Unallocated Allocated Proposed Rates Current Rates
29 Voltage Line Loss Factors applied to rates(2018 Study): 1.09061 1.07082 1.03503 S P_ T S P T
30 Tariff Customer ECAM deferral and Rate(cents/kWh): $22,445 0.975 1.064 1.044 1.009 Tariff Customer Rate F1.064 1.044 1.009 1.137 1.116 1.079
31 REC Adjustment and Rate(cents/kWh): $0 0.000 0.000 0.000 0.000 Schedule 400 Rate 1.009 1.096
32 Total Idaho ECAM Rate(cents/kWh): $35,710 0.975 1.064 1.044 1.009 REC Adj $0
ATTACHMENT A
Case No. PAC-E-26-05
Staff Comments
May 8, 2026

CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 81h DAY OF MAY 2026, SERVED
THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE NO.
PAC-E-26-05, BY E-MAILING A COPY THEREOF, TO THE FOLLOWING:
Rocky Mountain Power:
JANA SABA
JOE DALLAS, ASSISTANT GENERAL COUNSEL
ROCKY MOUNTAIN POWER
E-MAIL: jana.saba@,pacificorp.com
joseph.dallas(crpacificorp.com
datarequestkpacificorp.com
PATRICIA JORDA9, SECRETARY
CERTIFICATE OF SERVICE