20230531Final_Order_No_35801.pdf

ORDER NO. 35801 1

Office of the Secretary
Service Date
May 31, 2023
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF ROCKY MOUNTAIN
POWER’S APPLICATION REQUESTING
APPROVAL OF $32.5 MILLION ECAM
DEFERRAL
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CASE NO. PAC-E-23-09

ORDER NO. 35801

On March 30, 2023, 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 $32.5 million in ECAM deferred costs and a
2.3 percent increase to Electric Service Schedule No. 94, Energy Cost Adjustment (“Schedule
94”). The monthly bill of an average residential customer using 783 kilowatt-hours of electricity
would increase by about $1.57. The Company requests its proposed adjustment be processed by
Modified Procedure and become effective on June 1, 2023.
On April 13, 2023, the Commission issued a Notice of Application and Notice of Modified
Procedure establishing public comment and Company reply deadlines.
P4 Production LLC., an affiliate of Bayer Corporation (“P4”) intervened in the case. Order
No. 35768.
Staff and P4 and one member of the public filed comments. The Company responded to
Staff’s and P4’s comments.
Having reviewed the record, the Commission approves the Company’s Application as
discussed below.
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. 35801 2

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, this year’s ECAM includes: (1) the Load Change Adjustment
Revenues (“LCAR”); (2) an adjustment for coal stripping costs;1 (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 deferral. Application at 3.
With its Application, the Company seeks an order approving the Company’s: (1) request
for a $32.5 million ECAM deferral; and (2) a 2.3 percent increase for Schedule 94. Id. at 1. The
Company states that if its proposal is approved, prices for customer classes would increase as
follows:
• Residential Schedule 1 – (1.6%)
• Residential Schedule 36, Optional Time-of-Day Service – (1.9%)
• General Service Schedule 6 – (2.3%)
• General Service Schedule 9 – (2.9%)
• Irrigation Customers – (2.1%)
• General Service Schedule 23 – (2.0%)
• General Service Schedule 35 – (2.2%)
• Public Street Lighting – (1.1%)
• Tariff Contract, Schedule 400 – (3.0%)

See Customer Notices attached to Application.

COMMENTS

Staff, P4, one member of the public, and the Company submitted comments.
Staff Comments
1. ECAM Analysis and Calculation
Staff recommended the Commission authorize the 2022 ECAM deferral. Staff verified the
Company's calculation of the 2022 ECAM complied with previous Commission orders and that

1 The ECAM 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 coal stripping costs; and the Company incurs/retains
the remaining 10%. Application at 3.
2 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; Order No. 34640.
ORDER NO. 35801 3

the Company accurately reported actual loads, prudently incurred actual costs and revenues, and
applied the correct loads, costs, and revenues embedded in base rates. Staff also reviewed the
Company's hedge contracts, believing they safeguard price and fuel stability.
The NPC to serve Idaho customers in 2022 was $126.3 million but the revenue collected
through base rates was only $90.9 million—leaving a $35.3 million under collected balance.3
After accounting for the 90/10 band, customers are responsible for $30.5 million through the
ECAM.
The Emerging Issues Taskforce (“EITF”)—an adjustment measuring the difference
between coal stripping costs incurred and recorded—decreased the deferral by $190,656.
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 5. A LCAR of $8.74/ megawatt-hour
(“MWh”) was set in the Company’s last general rate case and the Company collected $32.4 million
through the LCAR. This resulted in a $1.5 million offset to the deferral.
Also set in the last general rate case, the PTC true-up is $4.16/MWh. In 2022, a $15.5
million PTC benefit from the ECAM exceeded the $14.1 million allocation to Idaho customers.
The $1.4 million difference between base rate PTCs and actual PTCs will be a surcharge to
customers.
A rate of $0.07/MWh in REC revenues was set in the last general rate case. In 2022, base
rates included $153,744 in benefits, but Idaho’s actual share of REC revenues was $130,679 higher
than included in rates. This amount will offset the deferral balance.
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 $634,305 increase to the Idaho deferral in 2022.
The ECAM also included a $295,039 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 not meeting required specifications.

3 The NPC embedded in rates is set at $24.54 per 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 3,706,984 MWh = $90.9
million. 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.” Id. at 6; citing Painter Direct at 10.

ORDER NO. 35801 4

2. Analysis of Actual NPC
Staff reported that actual NPC increased 47.5 percent system wide in 2022, including by
45.9 percent above base rate recovery in Idaho. Staff recommended withholding a decision on
whether actual NPC included in the 2022 ECAM deferral was prudent, but still allow the actual
NPC used to calculate the 2022 ECAM deferral and Schedule 94 rates in this case. Staff also
recommended “the Company provide . . . a full accounting of the issues causing the extraordinarily
high NPC, with a focus on the lack of coal generation and coal supplies, by directing the Company
to perform a full investigation starting with a comprehensive report from the Company within six
months of the Commission’s final order.” Id. at 7. At the conclusion of the assessment, Staff
proposed it make a recommendation to the Commission regarding any adjustments that should be
made to the balancing account in the 2023 ECAM, if the Commission finds adjustments necessary.
Staff proposed the Company’s investigatory report would include:
1. Provide past details of the Company’s forecasted 2022 load and how the
Company planned to meet this load requirement at a least-cost to customers
prior to the 2022 ECAM year;

2. For each coal plant, if shortages occurred, provide an analysis and a timeline
of events such as decisions and actions taken by the Company relative to
coal supply contracts or investments in coal mines to maintain coal supply
leading up to shortages in coal supply and the inability to dispatch coal
plants that occurred during the ECAM year;

3. List issues that occurred during the ECAM year (high natural gas cost, lack
of hydro generation, high market prices, etc.) which caused the significant
increase to NPC and for each, provide:

a. A full explanation of the issue and how lack of coal generation factored
into the issue; and
b. The cost impact of the issue and how much of the impact could have
been mitigated if coal generation was available.

4. For each coal plant, if shortages occurred, provide an analysis that traces
and compares the Company’s coal generation forecasts and the
corresponding coal supply orders and deliveries starting in January 2021 to
the present documenting who was aware of any shortfall between the two,
and when;

5. For each coal plant, if shortages occurred, discuss alternatives the Company
considered, decisions made, and action plans taken (with dates and action
ORDER NO. 35801 5

owners) to either acquire additional coal supply, or mitigate the impact of a
lack of coal supply;

6. For each coal plant, if shortages occurred, discuss, and fully explain what
the Company will be doing differently in the future to maintain operation of
its coal plants needed to meet delivery of electricity at least cost to
customers; and

7. Provide an appendix to the report with documents that supports the
Company’s analysis and provides evidence showing what the Company
knew, when they knew it.
Id. at 7-8.
Staff performed several analyses which lead it to believe the root cause of the high NPC in
2022 “was due to the Company’s inability to dispatch its coal plants, while required to dispatch its
higher cost natural gas plants and purchase higher cost market power in order to meet its load
obligations.” Id. at 8. Staff cited lower wholesale sales, increase purchased power costs, decreased
coal costs (for generation), and increased gas costs (for generation) among several factors that
contributed to the increased NPC.
Staff believed the reduction in coal power generation form the assumption in base rates, a
resource that had a low average unit cost per MWh, caused the Company to make fewer sales on
the market, buy more gas (which was generally more expensive in 2022), and make more market
purchases. Staff believed the reduction in generation compared to the amount assumed in base
rates occurred because “the Company’s coal plants were not fully utilized in the Company’s model
used to determine base rate NPC.” Id. at 11.
According to Staff there did not appear to be a significant amount of forced or unforced
downtime that would have required the Company to dispatch its coal generators less. Staff noted
the “Company did provide information about coal supply issues affecting coal generation in Utah
that would have forced the Company to obtain supply from higher cost sources. However, the
Company did not identify or disclose any coal supply issues at the Bridger coal plant located in
Wyoming.” Id. at 12.
Staff discussed the Company’s total natural gas fuel expense, which contributed to a $382
million increase in NPC over base NPC. Average gas generation costs increased $17.66/MWh over
base rates in 2022. The higher cost is primarily due to increased commodity prices experienced in
ORDER NO. 35801 6

2022. Staff noted the “Company increased natural gas fueled generation by 5,198 GWh or 61%.”5
Id.
P4 Comments
P4, like Staff, focused its comments on the fact that the Company relied less on coal
generation in the 2022 ECAM, with little explanation as to why. P4 noted the Company generated
about 1.5 gigawatt-hours (“GWh”) less in 2022 than its base rates included. Further, the
Company’s coal generation decreased by about 3.2 GWh from 2021 to 2022. All this occurred
when the market forces would suggest the Company should generate more electricity from coal,
not less.
P4 pointed out the cost of short-term market purchases were four times greater than the
cost of coal generation from the Company’s plants (as included in rates). P4 requested the
Company be directed to provide an “explanation of why coal generation was significantly
depressed during the 2022 ECAM period.” P4 Comments at 2. P4 specifically asked that the
explanation include information on the following conditions: “forced outages, scheduled
maintenance, operating constraints, coal supply constraints, market factors, political factors, etc.”
Id. P4 also requested that for each condition the Company be required to submit an estimate of lost
MWh generation. Finally, P4 sought the right to conduct discovery and potentially request a
hearing based on the Company’s response.
Public Comments
One member of the public commented requesting the Commission deny the Company’s
Application and offering their own hypothesis on the reasons for the increased market prices for
electricity.
Company Reply Comments
The Company noted that Staff recommended the Commission “approve the 2022 ECAM
deferral balance and approve the proposed Schedule 94 rate.” Company Reply Comments at 2.
The Company also noted Staff’s recommendation to defer a prudence determination on 2022 NPC
costs included in the ECAM “until an investigation into the Company’s ability to economically
dispatch its coal plants” was completed. Id. The Company requested denial of Staff’s proposal for
additional process.

5 “The Company asserts that natural gas prices, at the Opal natural gas trading hub, one of the Company’s natural gas
delivery points, were over 424% higher in December 2022 than in December 2021.” Id. at 12; citing Painter direct at
13.
ORDER NO. 35801 7

The Company disagreed with Staff’s proposed investigation and ensuing report stating that
the record contains an explanation of the coal supply challenges faced by the Company in 2022.
The Company maintained that it dispatched its coal fleet per prudent utility practices, which
dictates that the Company maintains an adequate stockpile of coal to be consistent with least-cost
economic dispatch.
The Company provided explanations of the coal acquisition process, its Jim Bridger coal
supply, and its Utah plants’ coal supply.
The Company stated its “goal in fuel supply planning it securing the least-cost and least-
risk fuel supply for customers” which requires it to follow a comprehensive process for fuel supply
planning. Id. at 4. The fuel supply planning process according to the Company first requires the
Company to estimate annual and future generation forecasts for each plant. The estimations include
“historical usage patterns, sales and load forecasts, market prices, changes in available generation,
operating lives, and reliability requirements.” Id. After the generation forecasts have been
developed “the Company then develops fuel volume, pricing, and sourcing assumptions, as well
as transportation costs.” Id.
Using its planning assumptions, the Company stated, it then enters into contracts of various
lengths with third-party suppliers to meet the needs of individual plants. The Company “considers
term, price, volume, and coal quality when negotiating third-party coal supply agreements and
seeks to strike the optimum balance among these factors. Negotiations for bilateral coal supply
agreements are specific to the individual plant, mine or mines that can serve the plant,
transportation requirements, and overall coal market.” Id. at 5. These contracts ensure reliable,
uninterrupted coal supply for its plants at predictable terms, prices, and conditions. The Company
claimed it provided Staff all the documents for an assessment of whether the Company’s coal
procurement decisions were prudent when contracts were signed to prepare for the 2022 fuel year.
The Company argued that Staff incorrectly correlated the problems Idaho Power had with
coal supply at Bridger with the Company’s decreased generation in 2022. The Company explained
that it did not reduce generation at Bridger due to lack of supply and it in fact maintained an
inventory that exceeded its 45-day minimum stockpile reliability target during the year. Therefore,
the Company noted there was no need, nor did it curtail generation at Bridger in 2022. The
Company stated that it took the following steps to ensure adequate stockpiles at Bridger:
ORDER NO. 35801 8

• In August 2022, PacifiCorp directed the plant to begin using coal permitted for
long-term storage. A total of 407,395 tons (shared between PacifiCorp and Idaho
Power) were consumed from the long-term storage pile in 2022.

• In September 2022, PacifiCorp issued a request for proposals (RFP) to Powder
River Basin (PRB) coal suppliers for future deliveries to the plant, specifically
targeting deliveries for the fourth quarter of 2022 and 2023.

• In September 2022, PacifiCorp initiated discussions with Union Pacific railroad
regarding the delivery of PRB coal to the plant. These discussions aimed to ensure
reliable transportation and delivery of the required coal to Jim Bridger.

• PacifiCorp also embarked on a search to lease 120 coal railcars, further
demonstrating its commitment to securing adequate transportation resources for
coal deliveries.

Id. at 8-9.
The Company added that the combined capacity of its coal and wind resources in Wyoming
exceeds the available transmission capacity to move the generation from the region. The reduction
in coal generation can be partially attributed to times when coal competes with wind for
transmission and the zero-cost fuel resource is selected. The Company explained that “for calendar
year 2021 to calendar year 2022” wind generation increased by about 760,000 MWh while coal
generation decreased by about 740,000 MWh.6 This represents a $13.5 million reduction in
Bridger fuel costs from 2021 to 2022 and an increase in PTC of $25.2 million for the same period.
The Company discussed its coal supply issues in Utah. During 2022, a mine that produced
25 percent of Utah’s coal closed because of a fire and the Company received force majeure claims
from two other mines that supply Hunter and Huntington plants. When the Company learned of
the supply constraints, it began transporting coal from its safety pile at Rock Garden and working
with other suppliers to secure additional coal. Because of the supply disruptions, the Company
began curtailing generation at Hunter in September 2022 and at Huntington in November 2022.
This, according to the Company, was to maintain minimum stockpile reliability targets.
In response to the efforts to maintain minimum stockpile reliability, the Company
recalculated its dispatch prices for Hunter and Huntington to between $50-$70MWh in September
and again in November 2022 eventually rising to $90/MWh by the end of 2022. At the higher

6 The Company did not explain why it chose to use the phrase “for calendar year 2021 to calendar year 2022” instead
of “in 2022” or for the 2022 ECAM year.”
ORDER NO. 35801 9

dispatch prices, the Company’s models do not run the plants, which ensures the Company can
maintain its minimum stockpile. The Company maintained that it practiced prudent utility
operations to ensure reliability as directed by industry standards.
The Company indicated P4’s concerns were like Staff’s and the production responses
which are relevant to P4’s concerns are available to P4 for review.
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 record in this case and based on that review, we find it
fair, just, and reasonable to approve the Company’s Application with some exceptions. The
Commission is concerned with the Company’s deployment of its coal fleet during the 2022 ECAM
year as described in both Staff’s and P4’s comments. We understand that 2022 was a difficult year
for power supply across the west, both summer and winter. Regardless, we always expect the
utilities we regulate will work to ensure the power supply costs, which will ultimately end up in
customer rates, will be as low as reasonably possible. Notably, the Company, according to P4’s
comments, generated 1.5 GWh less from coal in 2022 than was included in its base rates. Had the
Company generated all the electricity from coal that was included in base rates, it could have
impacted the ECAM greatly. During that time the Company could have deployed its coal fleet to
maximize market transactions differently and also impacted the ECAM.
In order to ensure the Company was maximizing its coal fleet to customers’ benefit, we
direct the Company to investigate and report on the issues causing the extraordinarily high NPC,
with a focus on the lack of coal generation and coal supplies, and the Company’s management of
those issues, as described in Staff’s and P4’s comments. This report should be completed before
the end of the 2023 ECAM year.
Accordingly, the Commission approves the $32.5 million in deferred costs from the
deferral period beginning January 1, 2022, through December 31, 2022, and a corresponding 2.3
percent increase to Electric Service Schedule No. 94, Energy Cost Adjustment. However, we
ORDER NO. 35801 10

withhold a prudency determination on the NPC pending the results of the report as discussed
above. Any necessary adjustments to the 2022 NPC will occur in the 2023 ECAM.
ORDER
IT IS HEREBY ORDERED that the Company’s Application for $32.5 million in deferred
costs from the deferral period beginning January 1, 2022, through December 31, 2022, is approved.
The Company’s Application for a 2.3 percent increase to Electric Service Schedule No. 94 Energy
Cost Adjustment, with new rates effective June 1, 2023, is approved. However, the prudency of
2022 NPC will not be determined until after an investigation and report on the Company’s dispatch
of its coal fleet.
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.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 31st day of
May 2023.

ERIC ANDERSON, PRESIDENT

JOHN R. HAMMOND JR., COMMISSIONER

EDWARD LODGE, COMMISSIONER

ATTEST:

Jan Noriyuki
Commission Secretary

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