20250513Staff Comments.pdf

RECEIVED
Tuesday, May 13, 2025
ADAM TRIPLETT IDAHO PUBLIC
DEPUTY ATTORNEY GENERAL UTILITIES COMMISSION
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 10221
Street Address for Express Mail:
11331 W CHINDEN BLVD, BLDG 8, SUITE 201-A
BOISE, ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF ROCKY MOUNTAIN )
POWER'S APPLICATION FOR APPROVAL ) CASE NO. PAC-E-25-04
OF $66.7 MILLION ECAM DEFERRAL )
COMMENTS OF THE
COMMISSION STAFF
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission
("Commission"), by and through its Attorney of record, Adam Triplett, Deputy Attorney
General, submits the following comments.
BACKGROUND
On March 27, 2025, Rocky Mountain Power, a division of PacifiCorp ("Company"),
applied for Commission authorization to adjust its rates under the Energy Cost Adjustment
Mechanism("ECAM"). Specifically, the Company seeks approval of approximately $66.7
million in ECAM deferral and a 2.2 percent increase to Electric Service Schedule No. 94, Energy
Cost Adjustment. The Company requests that this matter be processed by Modified Procedure
and become effective on June 1, 2025.
STAFF COMMENTS 1 MAY 13, 2024

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 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 decrease or increase in customer rates. Neither the Company nor its
shareholders will receive any financial return because of this filing.
Besides the NPC difference, this year's ECAM includes: (1) the Load Change
Adjustment Revenues; (2) coal stripping costs under Emerging Issues Task Force 04-6; (3)
Renewable Energy Credit revenues; (4) Production Tax Credits; (5) the reasonable energy price,
as defined in the 2020 Protocol; (6) qualified facility costs; and (7) wind availability liquidated
damages.
The Company seeks an order approving its request for$66.7 million ECAM deferral; and
(2) a 2.2 percent increase to Electric Service schedule No. 94. The Company represents that, if
its proposal is approved, prices for customer classes would increase as follows:
• Residential Schedule 1 —(1.7%)
• Residential Schedule 36 —(1.9%)
• General Service Schedule 6 —(2.2%)
• General Service Schedule 9—(2.8%)
• Irrigation Customers—(2.0%)
• General Service Schedule 23 —(1.7%)
• General Service Schedule 35 —(2.1%)
• Public Street Lighting—(1.2%)
• Tariff Contract, Schedule 400—(2.9%)
The Application and Attachments are available for public inspection during regular
business hours at the Commission's office. These documents are also available on the
Commission's website at www.puc.idaho.gov. Click on the "ELECTRIC" icon, select "Open
Cases," then click on the case number as shown on the front of this document.
STAFF COMMENTS 2 MAY 13, 2024

STAFF ANALYSIS
Staff reviewed the Company's calculation for the ECAM deferral and determined that it
is consistent with prior Commission orders. Staff verified the accuracy of the actual loads, costs
incurred, and revenues received by the Company, as well as the correct application of the loads,
costs, and revenues embedded in base rates. After filing its Application, the Company
discovered an error in its calculation of PTC credits which reduced the overall recovery by
$52,243 —or 1 hundredth of a percent from 2.22 to 2.21 percent. Staff considers the error to be
immaterial and recommends maintaining the proposed schedule 94 rates, as filed, with an
adjustment made in the balancing account to be trued up in next year's ECAM.
With consideration to PTC error, 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 2024. Staff recommends that the Commission
approve the 2024 ECAM deferral as detailed below:
Table No. 1: Deferred ECAM Balance
NPC Differential for Deferral $ 70,481,775
EITF 04-6 Adjustment (546,980)
LCAR (1,757,888)
Total Deferral Before Sharing 68,176,907
Sharing Band 90%
Customer Responsibility 61,359,217
Production Tax Credits 363,786
REP QF Adjustment 1,512,726
Wind Liquidated Damages (100,045)
REC Deferral (791,134)
Interest on Deferral 4,314,352
Annual Deferral (Jan - Dec 2024) 66,658,903
Unamortized Previous Balance 73,082,282
ECAM Rider Revenues (51,121,109)
Total Company Recovery $ 88,620,076
tt
Staff conducted a comprehensive review of the Company's reported energy costs and
revenues. This review included an examination of external audit reports,journal entries,
invoices, and contracts to verify the accuracy of recorded transactions. Staff also evaluated the
STAFF COMMENTS 3 MAY 13, 2024

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.
Net Power Cost Deferral
The NPC adjustment within the ECAM enables the Company to either 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 deferral period. Pursuant to Commission
Order No. 35277, the NPC embedded in base rates was established at $24.54 per megawatt-hour
("MWh").
To determine base rate revenue, the embedded NPC rate of$24.54 is multiplied by
Idaho's actual 2024 sales of 3,727,500 MWh, resulting in approximately $91.5 million. Idaho's
share of actual NPC for 2024 totaled $161.9 million. The difference between base rate revenue
collected and Idaho's share of actual 2024 NPC leaves an under-collected balance of$70.5
million. This under-collected balance is subject to the 90/10 customer sharing mechanism, in
which the Company absorbs 10% of the NPC balance. After removing the Company's share, the
remaining $61.4 million is the amount customers are responsible to pay through Schedule 94
rates.
Emerginy-Issues Task Force ("EITF")
The 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, the Company is required to expense stripping costs as incurred, rather
than amortize them over the volume of coal produced from a specific section of open-pit mines.
The Company uses this adjustment to reverse the accounting effects of EITF 04-6. For the
deferral period, the adjustment reduces the ECAM deferral balance by $546,980. Staff reviewed
the calculation and determined that it was accurate and appropriate.
STAFF COMMENTS 4 MAY 13, 2024

Load Change Adiustment Revenues
Staff verified that the Company's LCAR adjustment is consistent with Order No. 35277.
The LCAR accounts for the under- or over-recovery of fixed energy-classified production costs
(excluding NPQ due to differences between Idaho sales used to establish base rates and actual
sales during the deferral year. In Case No. PAC-E-21-07, the LCAR rate was established at
$8.74 per MWh. When applied to actual Idaho sales of 3,727,500 MWh, the result is recovery of
approximately $32.6 million in energy-classified fixed production costs through base rates. The
difference between the actual fixed energy-classified production costs collected and the $30.8
million embedded in base rates decreases the ECAM deferral by $1.76 million.
Production Tax Credits
In Order No. 33668, the Commission approved a settlement wherein the parties to the
case agreed to move the PTC true-up into the ECAM, reflecting a $1.99 per MWh benefit to
customers within base rates. Subsequently, in Order No. 35277, the Commission approved a
settlement increasing the PTC to $4.16 per MWh. In 2024, base rates reflected a$15.5 million
benefit from PTCs; however, the actual PTCs allocated to Idaho customers during the year
totaled $15.1 million. The difference between the PTCs embedded in base rates and the actual
amount realized results in a$363,786 customer surcharge.
As previously mentioned, the Company discovered a$52,243 error in its calculation of PTCs
which has an immaterial impact on the calculation of the rates. Staff recommends the amount be
adjusted in the balancing account and credited to customers in next year's ECAM.
Reasonable Energy Price OF Adiustment
The 2020 Protocol, approved by Order No. 34640, included a provision that all 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 SITUS allocated to the state that approved the QF contract. Painter Direct at 10.
In this case, there are 11 contracts requiring comparison for the reasonable energy price QF
adjustment with four incurring a SITUS allocation adjustment to Idaho. Staff reviewed the
process for creating the reasonable energy price and the energy price for those contracts and
STAFF COMMENTS 5 MAY 13, 2024

Staff believes it complies with the 2020 Protocol. The reasonable energy price QF adjustment
results in a$ 1.5 million increase to the Idaho ECAM deferral.
Wind Availability Liquidated Damages
The Company included $100,045 credit to customers related to wind availability
liquidated damages. Pursuant to the stipulation approved in Order No. 33954, Case No. PAC-E-
17-06, the Company agreed to pass through all liquidated damages received from suppliers in the
event that repowered equipment fails to meet specified performance standards. The Company
allocated the liquidated damages using the system generation factor and applied the resulting
credit to customers. Staff reviewed the supporting documentation provided by the Company and
agrees with the inclusion of this reduction to NPC.
Renewable Energy Credits
In Order No. 35277, the Commission approved $0.07 per MWh in REC revenues to be
included in base rates. The difference between the embedded amount and actual REC revenue is
trued-up in the ECAM. In 2024, base rates included $255,148 in benefits from REC revenues.
Idaho's share of the Company's actual REC revenues was $1,046,282. The difference of
$791,134 reduces the deferral balance.
Accrued Interest
In the Application, the Company included forecasted interest of approximately $3.6
million on the deferred ECAM balance from June 1, 2025, through May 31, 2027. This interest
is associated with the recovery of approved ECAM costs, as outlined in the settlement stipulation
approved in Order No. 36452.
The ECAM rates on Schedule 94 for recovery of the 2023 deferred costs Case No. PAC-
E- 24- 05), will be reduced by 50 percent, effective January 1, 2025 (or rate effective date
of this proceeding)with the remaining balance as of June 1,2025,to be recovered over two
years with the costs deferred in 2024.
Staff reviewed the Company's interest calculation, methodology, and rate assumptions.
This included the use of a 5% interest rate, which aligns with the Commission-approved
customer deposit rate for 2025.1 While the settlement stipulation did not explicitly authorize the
recovery of interest, Staff determined the proposal was appropriate because it is consistent with
i Customer Deposit Rate Approved in Order No. 36390.
STAFF COMMENTS 6 MAY 13, 2024

regulatory treatment and ensures that the Company is fairly compensated for the delay in cost
recovery.
Analysis of Actual NPC
The increase in the ECAM deferral is reflected by the higher$40.86 per MY h overall
actual unit cost of energy when compared to the $23.41 per MWh unit cost of energy embedded
in base rates. To determine whether the Company generally incurred NPC in a prudent manner,
Staff compared the amount and cost of energy embedded in base rates to the actual amount and
cost of energy incurred during the 2024 deferral period for the different types of resources as
illustrated in Table No. 1, below. Through this analysis, Staff believes the higher unit costs of
NPC were primarily caused by being constrained from producing more energy from the
Company's lower cost resources (Coal, Gas and Other) while needing to source more of its
energy from relatively higher cost market purchases and the Company's gas-generating units.
Table No. l: Comparison of Base and the Proposed NPC
Source Expense Amt of Energy Unit Cost
(million $) (million MWh) ($/MWh)
Actual Base Actual Base Actual Base
NPC NPC NPC NPC NPC NPC
Wholesale Sales (106.72) (463.69) 1.96 10.76 54.35 43.09
Total Purchased Power 1,422.34 844.45 20.59 18.28 69.06 46.19
- Other Purchases 1,215.57 654.03 14.57 13.90 83.40 47.06
- Long-term Purchase 206.77 190.42 6.02 4.38 34.35 43.44
Coal Resource 527.48 599.88 18.22 29.88 28.94 20.08
Gas Resource 571.86 228.73 16.94 8.49 33.75 26.95
Hydro Resource - - 2.59 4.44 - -
STAFF COMMENTS 7 MAY 13, 2024

Other Resource(wind, 6.13 4.42 7.20 8.12 0.85 0.54
solar, etc.)
Total System 2,598.57 1,367.92 63.59 58.44 40.86 23.41
The Company's base rates were established by Commission Order No. 35277 with an
effective date of January 1, 2022. When compared to the amounts reflected in the base, the
actual amount of generation in coal, hydro, and other resources decreased by 39.0%, 41.7%, and
11.3%, respectively, while the amount of energy from the market and from the Company's gas
plants increased by 13% and 100%, respectively.
In large part due to the coal-to-gas conversion of Bridger units 1 and 2 that occurred in
2024, the Company dispatched 12 million MWhs less coal generation, much of which was made
up by(1) natural gas generation from the Company's gas plants, double the amount assumed in
the base, and (2) through market purchases, 13% higher than the amount assumed in the base.
Because coal generation cost has typically remained relatively stable, it has acted as a hedge to
keep NPC costs low. However, as the Company moves towards gas generation and market
purchases, the Company's NPC will become increasingly subject to the volatility of the natural
gas and wholesale electricity markets. This will place more importance on the ability of the
Company to hedge its price risk within those markets. It may also require the Company to make
increasingly more long-term market purchases as evidenced by the $34.35 per MWh cost of
long-term purchases when compared to the $69.06 per MWh overall cost of market purchases.
Another major cause of the Company's higher NPC is the reduction in the amount of
wholesale sales, an amount which is 5 times lower than the amount reflected in the base.
Although the Company was able to sell its power for$54.35 per MWh instead of the $43.09 per
MWh price assumed in the base, the higher price is likely an indication that the increased overall
cost of energy from the Company's portfolio of resources has risen to the level to be priced out
of the market.
Thermal Plant Downtime
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 Audit Request No. 6.
STAFF COMMENTS 8 MAY 13, 2024

Staff reviewed the data and came to the following two conclusions: (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 amount of planned downtime and actual downtime that was
greater than the amount planned had sound justification and was reasonable.
Line Loss
Staff reviews the line losses in each ECAM to ensure the amount of load at input is
correct. The load at input is the metered amount of MWhs that moves into the Company's Idaho
jurisdiction needed to serve Idaho's customer load. The load at input is a critical component of
the Company's ECAM calculation methodology and must be correct to calculate an accurate
deferral. Staff believes that the line loss calculated in the 2024 deferral period is reasonable and
is within an acceptable range.
Staff calculated the line loss percentage by calculating the percentage difference between
the Idaho load at input and the Idaho load at customer meter and compared it to the line loss
percentage from the previous year as shown in Table No. 2 below. Even though the 3.11% line
loss in 2024 is greater than the line loss in 2023, the line loss is less than the transmission line
loss of 3.5% that was identified in the Company's last line loss study. Based on the results, Staff
concludes that the line loss in the deferral period from January 2024 through December 2024 is
acceptable.
Table No. 2: Comparison of Line Loss
Category 2023 2024
ID Load at Input (MWh) 3,587,417 3,847,108
ID Sales (MWh) 3,495,580 3,727,500
Line Loss 2.56% 3.11%
Proposed Rates
Staff verified that the rates in the Company's proposed Schedule 94, Energy Cost
Adjustment, are calculated using the methodology approved in Order No. 33440 and comply
with the Settlement Stipulation approved through Order No. 36452, which directed the Company
STAFF COMMENTS 9 MAY 13, 2024

to collect the ECAM balance over two years. The proposed rates in Schedule 94 are line-loss
adjusted depending on service type or voltage level that each customer receives service. Table
No. 3 below summarizes the rates for each type of customer.
Table No. 3: Comparison of Current and Proposed Rates
Service Type Current Rates Proposed Rates Increase
(cents/kWh) (cents/kWh) (%)
Secondary Distribution 0.905 1.137 25.64%
Primary Distribution 0.888 1.116 25.68%
Transmission 0.859 1.079 25.61%
The Company's revised rates are included with the Application as Exhibit 2 of
Meredith's testimony. The Company's proposed revision to Schedule 94 increases Company
revenue by approximately 2.2%. However, revenue increases to specific classes will vary
because of differences in rate design among the classes. The overall revenue increase for
residential customers is 1.7%. A typical residential customer using an average of 836 kWh per
month would pay $1.94 more per month under the proposed rates.
Customer Notice and Press Release
The Company's press release and customer notice were included with its Application.
Staff reviewed the documents and determined that both meet the requirements of Rule 125 of the
Commission's Rules of Procedure (IDAPA 31.01.01.125). The notice was included with bills
mailed to customers beginning April 8 and ending May 6, 2025.
The Commission set a comment deadline of May 13, 2025. Some customers in the last
billing cycle may not have received their notices or had adequate time to submit comments
before the comment deadline. Customers should have the opportunity to file comments and have
those comments considered by the Commission. Staff recommends that the Commission
consider late filed comments by customers. As of May 13, 2025, the Commission received three
customer comments in opposition to the proposed rate increase.
STAFF COMMENTS 10 MAY 13, 2024

STAFF RECOMMENDATION
Staff recommends the Commission:
1. Approve the ECAM deferral of approximately $66.6 million for the period of January
1, 2024 through December 31, 2024;
2. Allow actual NPC included in the filing to be used to calculate the ECAM deferral
and authorize Schedule 94 rates as filed;
3. Direct the Company to adjust the balancing account for the $52,243 error in the
calculation of PTCs to be credited to customers in next year's ECAM; and
4. Accept late-filed customer comments.
Respectfully submitted this 13th day of May 2025.
Adam Triplett
Deputy Attorney General
Technical Staff: Ty Johnson
Seungjae Lee
Curtis Thaden
I:\Utility\UMISC\COMMENTS\PAC-E-25-04 Comments.doex
STAFF COMMENTS 11 MAY 13, 2024

CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THISL3
DAY OF MAY 2025,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. PAC-E-25-04, BY E-MAILING A COPY THEREOF, TO THE
FOLLOWING:
MARK ALDER DATA REQUEST RESPONSE CENTER
ROCKY MOUNTAIN POWER E-MAIL ONLY:
1407 WEST NORTH TEMPLE STE 330 datarequest@,pacificorp.com
SALT LAKE CITY UT 84116
E-MAIL: mark.alderApacificorp.com
JOE DALLAS
ROCKY MOUNTAIN POWER
825 NE MULTNOMAH, SUITE 2000
PORTLAND, OR 97232
E-MAIL:[e-mail]
Bayer:
Thomas J. Budge Brian C. Collins
Racine Olson,PLLP Greg Meyer
P.O. Box 1391 Brubaker&Associates
Pocatello, ID 83204-1391 16690 Swingley Ridge Rd.,#140
tj(a-)racineolson.com Chesterfield,MO 63017
bcollinsAconsultbai.com
gmeyer(a)consultbai.com
IIPA:
Eric L.Olsen Lance Kaufman,Ph.D.
Echo Hawk&Olsen,PLLC 2623 NW Bluebell Place
P.O.Box 6119 Corvallis,OR 97330
Pocatello,ID 83205 lancegae ig'sinsi hg t.com
elo(&echohawk.com
PHC:
Ronald L.Williams Bradley Mullins
Brandon Helgeson MW Analytics
Hawley Troxell Ennis&Hawley LLP Teitotie 2, Suite 208
P.O.Box 1617 Oulunsalo Finland,FI-90460
Boise,ID 83701 brmullinspmwanalytics.com
[e-mail]
bhel eg sonAhawleytroxell.com Via E-Mail Only:
Val Steiner
Itafos Conda,LLC
[e-mail]
Kyle Williams
BYU Idaho
[e-mail]
C'� 'A' ` 14kz�
PATRICIA JORDAN, SECRETARY
CERTIFICATE OF SERVICE