202312222022 ECAM Investigative Report - Redacted.pdf

1407 W. North Temple, Suite 330
Salt Lake City, UT 84116

December 22, 2023

VIA ELECTRONIC DELIVERY

Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd
Building 8 Suite 201A
Boise, ID 83714

RE: 2022 ECAM INVESTIGATIVE REPORT IN CASE NO. PAC-E-23-09
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL OF $32.5 MILLON ECAM DEFERRAL

Attention: Commission Secretary

Pursuant to Order No. 35801 in the above referenced matter Rocky Mountain Power hereby
respectfully submits its 2022 Energy Cost Adjustment Mechanism (ECAM) Confidential
Investigative Report to the Idaho Public Utilities Commission. Included with this filing is the
attorney’s certificate claim of confidentiality relating to the 2022 ECAM Investigative Report, two
confidential exhibits, and confidential workpapers.

Informal inquiries may be directed to Mark Alder, Idaho Regulatory Manager at [phone].

Very truly yours,

Joelle Steward
Senior Vice President, Regulation and Customer & Community Solutions

Enclosures

CC: Terri Carlock
TJ Budge (C)
Brian Collins (C)
Greg Meyer (C)
Eric Olsen
Mike Veile (C)

RECEIVED
Friday, December 22, 2023 1:07:10 PM
IDAHO PUBLIC
UTILITIES COMMISSION
1
Joe Dallas (ISB #10330) 825 NE Multnomah, Suite 2000
Portland, OR 97232
Telephone No. [phone] Email: [e-mail] Attorney for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
EQUESTING APPROVAL OF $32.5

-E-23-09
THE 2022 ECAM

I, Joe Dallas, represent Rocky Mountain Power in the above captioned matter. I am an
attorney for Rocky Mountain Power.
I make this certification and claim of confidentiality regarding the response to the attached
Idaho Public Utilities Commission Staff discovery request pursuant to IDAPA 31.01.01 because
Rocky Mountain Power, through its response, is disclosing certain information that is Confidential
and/or constitutes Trade Secrets as defined by Idaho Code Section 74-101, et seq. and 48-801 and
protected under IDAPA 31.01.01.067 and 31.01.01.233. Specifically, the contracted coal amounts
contain Company proprietary information that could be used to its commercial disadvantage.
Rocky Mountain Power herein asserts that the aforementioned responses contain
confidential in that the information contains Company proprietary information.
2
I am of the opinion that this information is “Confidential,” as defined by Idaho Code
Section 74-101, et seq. and 48-801, and should therefore be protected from public inspection,
examination and copying, and should be utilized only in accordance with the terms of the
Protective Agreement in this proceeding.

DATED this 22nd day of December, 2023.

Respectfully submitted,

By__________________________
Joe Dallas Senior Attorney Rocky Mountain Power
December 2023
ROCKY MOUNTAIN POWER’S
2022 ENERGY COST ADJUSTMENT
MECHANISM CONFIDENTIAL
INVESTIGATIVE REPORT
Case No. PAC-E-23-09 / 2022 ECAM / IPUC Order No. 35801 
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Table of Contents
Table of Contents ............................................................................................................................ 1 
List of Tables .................................................................................................................................. 2 
List of Exhibits ................................................................................................................................ 2 
1.0 Executive Summary .................................................................................................................. 3 
2.0 Background ............................................................................................................................... 3 
3.0 2022 ECAM Summary ............................................................................................................. 5 
3.1 War in Ukraine ...................................................................................................................... 5 
3.2 Weather Events ..................................................................................................................... 7 
3.3 Force Majeure Events ........................................................................................................... 8 
4.0 Forecast Base Versus Actual Generation .................................................................................. 9 
5.0 Forecast Method and Optimization Models ............................................................................ 12 
6.0 PacifiCorp’s Coal Acquisition Process ................................................................................... 13 
7.0 Changes in Coal Market Conditions ....................................................................................... 14 
8.0 Coal Supply Agreements ........................................................................................................ 17 
8.1  Utah Plants ..................................................................................................................... 18 
8.2  Wyoming Plants ............................................................................................................. 19 
8.3  Joint-Owned Plants – Partner Operated ......................................................................... 22 
9.0 Conclusion .............................................................................................................................. 23 
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List of Tables
Name Location
Table 3.1 – 2022 ECAM Deferral Pa e 5
Confidential Table 3.2 – Natural Gas Generation Costs – Forecast Base to Actual 2022 Pa e 6
Confidential Table 3.3 – Power Pricin – Forecast Base to Actual 2022 Pa e 6
Confidential Table 3.4 – Coal Generation Costs – Forecast Base to Actual 2022 Pa e 6
Table 3.5 – H dro Generation – Forecast Base to Actual 2022 Pa e 8
Confidential Table 3.6 – Coal Expense – Forecast Base to Actual 2022 Pa e 8
Table 4.1 – Coal Generation – Forecast Base to Actual 2022 Pa e 10
Table 4.2 – Coal Generation – Forecast Base to Actual 2020-2022 Pa e 11
Table 4.3 – Gas Generation – Forecast Base to Actual 2022 Pa e 11
Table 4.4 – Natural Gas Generation – Forecast Base to Actual 2020-2022 Pa e 12
Confidential Table 7.1 – Force Ma eure Claims in 2022 Pa e 16
Confidential Table 7.2 – 2022 Utah Plants Coal Received and Consume Pa e 16
Table 7.3 – 2022 Utah Plants Coal Inventor Pa e 17
Table 8.1 – Existin , Amended, and New CSAs in 2022 Pa e 18
Table 8.2 – 2022 Jim Brid er Coal Inventor Pa e 20
Confidential Table 8.3 – 2022 Jim Brid er Coal Suppl (PacifiCorp Share) Pa e 21
List of Exhibits
Name
Confidential Exhibit No. 1 – 2022 Thermal Outa e Summar
Confidential Exhibit No. 2 – Force Ma eure Claims
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1.0 Executive Summary
As directed by the Idaho Public Utilities Commission (the “Commission”), Rocky Mountain
Power, a division of PacifiCorp (the “Company”) hereby submits its 2022 Energy Cost
Adjustment Mechanism (“ECAM”) investigative report (“Investigative Report”) in accordance
with Order No. 35801 in Case No. PAC-E-23-09 (“2022 ECAM”). The Investigative Report
focuses on the issues related to lower coal generation and coal supplies, the deployment of the
Company’s coal fleet during calendar year 2022, the impacts on net power costs (“NPC”) and the
Company’s management of these issues during calendar year 2022. The difference between
actual coal generation in the 2022 ECAM and the coal generation in the forecast base period
included in the 2021 general rate case (“2021 GRC”)1 was five percent. This variance was
reasonable given the inherent difficulty of forecasting variables that are dependent on weather
and market conditions. This was particularly true in calendar year 2022 where the war in Ukraine
and extreme weather events created unprecedented market conditions.
This Investigative Report begins with a background of the 2022 ECAM followed by a summary
of the 2022 ECAM components and the coal generation and deployment circumstances of
calendar year 2022 including the war in Ukraine, extreme weather and force majeure events from
the Company’s coal suppliers. Also provided is a summary of the Company’s optimization
models followed by a focus on the Company’s coal acquisition process, coal market conditions
in calendar year 2022 and the Company’s coal supply agreements (“CSA”) relevant to the 2022
ECAM.
2.0 Background
On March 30, 2023, the Company, under Case No. PAC-E-23-09, applied for Commission
authorization to adjust its rates under the 2022 ECAM and requested approval of approximately
$32.5 million in deferred costs for the period of January 1, 2022 through December 31, 2022,
with a 2.3 percent overall increase to Electric Service No. 94, Energy Cost Adjustment
(“Schedule 94”).2
Prior to the Company’s March 30, 2023, application, Commission Staff (“Staff”) conducted a
review and audit of the 2022 ECAM involving 26 production requests, an on-site visit to the
Company facilities in Salt Lake City, Utah to meet with representatives from the fuel resources
department, and an on-site visit to Portland, Oregon to meet with representatives from the
Company’s NPC department. Based on their findings and review of the Company’s application,
1 In the Matter of the Application of Rocky Mountain Power for Authority to Increase its Rates and Charges in Idaho
and Approval of Proposed Electric Service Schedules and Regulations, Case No. PAC-E-21-07. 
2 In the Matter of the Application of Rocky Mountain Power Requesting Approval of $32.5 Million ECAM Deferral,
Case No. PAC-E-23-09, Application at 7 (March 30, 2023).
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Staff submitted its comments on May 10, 2023, which recommended the Commission approve
the Company’s 2022 ECAM deferral balance along with the proposed Schedule 94 rate.
In addition, Staff recommended the Commission defer its decision on the prudence of the
Company’s 2022 NPC until an investigation was completed into the Company’s ability to
economically dispatch its coal plants in calendar year 2022. Staff requested the report to include
details of the Company’s forecasted load and its plan to meet this load requirement, a timeline of
events leading to coal shortages and the inability to dispatch its coal plants, a list of issues that
resulted in a significant increase in NPC, documentation of the Company’s awareness of the
shortfalls, alternative solutions considered, and the Company’s proposed actions for the future to
address these challenges effectively.
P4 Production, L.L.C. (“P4”), an affiliate of Bayer Corporation, also submitted comments noting
concerns similar to Staff about the Company’s coal generation levels in calendar year 2022. P4
requested a detailed discussion on the costs of short-term purchases in relation to the coal
expense. In addition, P4 requested an explanation of the Company’s ability to generate electricity
from its coal units considering factors such as forced outages, scheduled maintenance, and
operating constraints. The Company, through its discovery responses to both P4 and Staff,
addressed in detail the forced and maintenance outages with a duration of longer than 72 hours
and derates at 50 percent or more of net capacity.
On May 17, 2023, the Company submitted reply comments showing how it dispatched its coal
generation units in calendar year 2022 in accordance with prudent utility practice, ensuring the
maintenance of an adequate coal stockpile and consistent with least-cost economic dispatch
principles. The Company’s reply comments explained its coal acquisition process, its coal
inventory levels at the Jim Bridger, Hunter and Huntington plants in calendar year 2022, and the
process the Company followed to economically dispatch its coal generation units. The Company
demonstrated that coal generation units were dispatched economically on a system-wide least-
cost basis.
On May 31, 2023, the Commission issued Order No. 35801 approving the Company’s $32.5
million in deferred costs for the deferral period January 1, 2022 through December 31, 2022, and
approving a 2.3 percent increase to Schedule 94 with new rates effective June 1, 2023. The
prudency determination of NPC in the 2022 ECAM was withheld until the Company submitted
this Investigative Report before the end of the 2023 ECAM year.3 In particular, the Commission
directed the Company to submit a report focusing on any issues related to coal generation and
supplies, and the Company’s management of those issues, that occurred in calendar year 2022.4
3 In the Matter of the Application of Rocky Mountain Power Requesting Approval of $32.5 Million ECAM Deferral,
Case No. PAC-E-23-09, Order No. 35801 (May 31, 2023).
4 Id. at 9.
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3.0 2022 ECAM Summary
The Company’s 2022 ECAM Application was for the recovery of $32.5 million as shown in
Table 3.1 below:
Table 3.1 – 2022 ECAM Deferral
The recovery amount largely stemmed from the $35.3 million difference between the actual NPC
(“Actual NPC”) and the NPC collected from Idaho customers (“Base NPC”) through rates set in
the 2021 GRC. Three main drivers were responsible for the differential between Base NPC and
Actual NPC; (1) worldwide natural gas supply and demand pressure that significantly impacted
and increased power prices, as further explained in detail below; (2) extreme weather events that
caused temporary increases in power and natural gas market prices; and (3) coal supply
constraints due to force majeure claims. Despite facing numerous hurdles in calendar year 2022,
further elaborated below, the Company experienced only a five percent discrepancy between the
projected and actual coal generation. This variance is within the anticipated range as detailed in
Section 4.0 of this Investigative Report.
3.1 War in Ukraine
During calendar year 2022, the conflict between Russia and the Ukraine resulted in decreased
availability of natural gas in Europe, which was previously sourced from Russian imports. With
decreased European supply, a measure of European demand turned to United States domestic
supply to fill the gap. This resulted in increased competition over domestic supply, which drove
regional natural gas fuel prices upwards due to domestic production being unable to keep pace
with the increased demand. This increase in natural gas fuel prices correspondingly increased
regional natural gas market prices and regional power market prices. The average cost of natural
gas generation during the 2022 ECAM deferral period increased 66 percent from $26.95 per
Calendar Year 2022 ECAM Deferral
NPC Differential 35,322,826$
EITF 04-6 Adjustment 190,656
LCAR (1,578,588)
Total Deferral Before Sharing 33,934,894$
Sharing Band 90%
Customer Reponsibility 30,541,405$
Production Tax Credits 1,388,020$
REP QF Adjustment 634,305
Wind Liquidated Damages (295,039)
REC Deferral (130,679)
Interest on Deferral 326,544
Annual Deferral (Jan - Dec 2022)32,464,556$
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megawatt-hour (“MWh”) in Base NPC to $44.61/MWh in Actual NPC as shown in Confidential
Table 3.2 below:
Confidential Table 3.2 – Natural Gas Generation Costs – Forecast Base to Actual 2022
Because the Company operates its system on a least-cost economic dispatch model, even with
higher natural gas prices throughout calendar year 2022, the Company’s owned gas-generating
plants were still, on average, significantly more economical than market power purchases during
calendar year 2022, as shown in Confidential Table 3.3 below:
Confidential Table 3.3 – Power Pricing – Forecast Base to Actual 2022
During calendar year 2022, coal generation costs increased only moderately in comparison to
natural gas and power pricing with a slight increase of two percent as shown in Confidential
Table 3.4 below:
Confidential Table 3.4 – Coal Generation Costs – Forecast Base to Actual 2022
Actual 2022 coal generation costs, on a $/MWh basis, was within 2 percent of the forecasted cost
of coal. As shown in Sections 6.0, 7.0, and 8.0 of this Investigative Report, the Company acted
prudently by securing coal in advance of 2022 and utilized its coal fleet as prudently as possible
during 2022 while ensuring reliability, despite force majeure events from coal suppliers in Utah.
Plant Base $/MWh Actual $/MWh Variance Percent
Chehalis
Currant Creek
Gadsby
Hermiston
Lake Side 1
Lake Side 2
Naughton - Gas
Total Gas 26.95$ 44.61$ 17.66$ 66%
Type Base $/MWh Actual $/MWh Variance Percent
Long-term Firm
Qualifying Facilities
Short-term/Balancing
Total Purchases 46.19$ 66.13$ 19.93$ 43%
Plant Base $/MWh Actual $/MWh Variance Percent
Colstrip
Craig
Dave Johnston
Hayden
Hunter
Huntington
Jim Bridger
Naughton
Wyodak
Total Coal 20.08$ 20.47$ 0.39$ 2%
REDACTED
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3.2 Weather Events
In addition to the war in the Ukraine creating unique market conditions, several extreme and
unforeseeable weather events occurred during the 2022 ECAM deferral period, all with a
collective impact on Actual NPC throughout the year. Multiple heat waves across the Company’s
service territories throughout July 2022, August 2022 and September 2022 had a significant
effect on market power prices leading to an increase in Actual NPC.5 The NPC differential for
those months alone amounted to $16.5 million and is almost half of the entire $35.3 million NPC
variance in the 2022 ECAM.
In their comments filed on May 10, 2023, P4 suggests that during the extreme weather events
“one would expect an increase in coal generation from historic levels since customer demand
would be higher during such events.” As P4 notes, the Company often experiences a
corresponding increase in demand and load on its system during extreme weather events. To
illustrate, actual Company system load in 2022 was 3,735,471 MWh, or 6 percent, above
forecasted load. 42% of that increase (1,584,546 MWh), occurred in July, August, and
September, when there were multiple heat waves across the Company’s service area. However,
because PacifiCorp’s customer load demand peaks during the summer months of July, August,
and September the Company’s own coal and gas generating plants were already operating near
peak capacity during much of the summer, which required the Company to purchase additional
power to meet customers’ needs during the extreme weather events in the Company’s service
territory.
Ongoing drought in the Western United States, dating back to the summer of 2020, has
continued to impact Actual NPC through reduced availability of the Company’s hydro resources.
In calendar year 2022, actual generation from hydro resources was 1,505,231 MWh or 34
percent lower than forecasted base generation as shown in Table 3.5 below:
5 PacifiCorp operates on a least-cost basis and does not rely on a weather-normalized forecast such as the one
prepared to set Base NPC in the 2021 GRC. Each hour, day, or season presents unique conditions that differ from a
weather-normalized forecast. These differences arise due to changes in market conditions, including market prices,
load demand, hydroelectric generation, wind generation and solar generation. Consequently, the variance between
forecast and actual conditions largely accounts for the difference between Base NPC and Actual NPC. In the 2021
GRC, the calendar year 2021 load forecast was an input to determine the Base NPC. This load forecast was a
weather-normalized projection created in the spring of 2020 but was only one of many load forecasts across time
that the Company has used to forecast the overall system generation as well as coal plant generation in order to
acquire fuel in a manner that benefits customers.
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Table 3.5 – Hydro Generation – Forecast Base to Actual 2022
The estimated impact to the NPC differential in the 2022 ECAM due to drought is $8.9 million.
A historic winter cyclone event in December 2022 occurred across the majority of the United
States, impacting both market power prices and natural gas prices, along with an increase in
demand. Natural gas prices across the Company’s delivery points drastically increased. At the
Opal natural gas trading hub, average market prices were 424 percent higher in December 2022
as compared to December 2021, while market prices at the Mid-Columbia and Four Corners
trading hubs were, on average, 406 percent higher across all load hours. The NPC differential in
December alone is $6.7 million, or 19 percent, of the NPC variance in the 2022 ECAM.
Overall, total-company coal fuel expense decreased by $18.8 million in the 2022 ECAM as
shown in Confidential Table 3.6 primarily because coal generation volume decreased:
Confidential Table 3.6 – Coal Expense – Forecast Base to Actual 2022
3.3 Force Majeure Events
Toward the end of 2022, due to conditions outside of the Company’s control, coal supply issues
causing delivery shortages began to impact the dispatch at Utah’s Hunter and Huntington coal-
generating plants. The operating mines in Utah’s Book Cliffs and Wasatch Plateau coal fields
experienced production difficulties due to a variety of geological, logistical, and financial
challenges. Additionally, there was a mine fire at American Consolidated Natural Resources’
Lila Canyon mine in September 2022. In recent years, the Lila Canyon mine has accounted for
more than 25 percent of Utah’s coal production. Several of the Company’s coal suppliers issued
force majeure notices in 2022 per the contract terms, which limited deliveries. Because of the
coal supply constraints identified above, the Company had to take action to maintain the
minimum stockpile reliability target.
Plant Base MWh Actual MWh Variance Percent
West Hydro 4,137,648 2,745,774 (1,391,874) (34%)
East Hydro 303,342 189,984 (113,358) (37%)
Total Hydro 4,440,989 2,935,758 (1,505,231) (34%)
Plant Base Dollars Actual Dollars Variance Percent
Colstrip
Craig
Dave Johnston
Hayden
Hunter
Huntington
Jim Bridger
Naughton
Wyodak
Total Coal 599,876,421$ 581,031,513$ (18,844,907)$ (3%)
REDACTED
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Once informed of the force majeure claims, the Company proactively took actions to address
coal supply constraints for its Utah plants during calendar year 2022, as further explained in
Section 8.1 of this Investigative Report. Furthermore, based upon industry standard practice
regarding the dispatch of fuel-limited resources, such as hydro plants, the Company calculated
the dispatch price for the fuel-limited Hunter and Huntington units to maintain minimum coal
stockpile reliability targets and secure availability for the benefit of customers during critical
periods. The dispatch price for each of these units was calculated, to ensure an adequate coal
stockpile, at $50-$70/MWh at Hunter in September 2022 and later in November 2022 at
Huntington. By the end of 2022, the price was recalculated to approximately $90/MWh. The
higher dispatch prices reflected the true cost of dispatching these resources with limited fuel
supply and ensured that the Company’s optimization models did not reduce coal stockpiles at
Hunter and Huntington to unacceptable levels. It is important to note that despite the Hunter and
Huntington dispatch prices being raised, Hunter and Huntington were not idled; they continued
to operate to serve customers.
The Company’s decision to calculate the dispatch price based on the economics of fuel-limited
resources reflects its commitment to upholding reliability standards, and ensuring the availability
of coal units when they are most needed. Although this calculation rendered the Hunter and
Huntington plants less economically favorable to dispatch within the Company’s operational
optimization models in late 2022, it was necessary to maintain a prudent coal stockpile level in
the aftermath of the unprecedented force majeure claims made by two coal suppliers, and to
ensure reliability during high-demand periods.
4.0 Forecast Base Versus Actual Generation
As shown in Table 4.1 below, actual coal generation in the 2022 ECAM decreased by 1,484,137
MWh on a total-company basis, or five percent compared to the forecast base period (from the
2021 GRC). This five percent variance between forecast and actual is well within the expected
range given that the periods compared are one year apart and the difficulty in forecasting with
increasing variable renewable resources on the Company’s system.
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Table 4.1 – Coal Generation – Forecast Base to Actual 2022
The largest decrease of 1,392,385 MWh at Dave Johnston plant (28 percent) is primarily due to
the planned outage for the Dave Johnston Unit 4 boiler overhaul. Dave Johnston Unit 4 is the
largest unit at the Dave Johnston plant with a capacity of 330 megawatts (“MW”) versus 220
MW at Dave Johnston Unit 3, 106 MW at Dave Johnston Unit 2 and 99 MW at Dave Johnston
Unit 1. The generation in Base NPC is modeled using a four-year overhaul average. Typically,
each of the four units at the Dave Johnston plant undergoes a major overhaul every four years.
Therefore, in years when the largest unit – Dave Johnston Unit 4 – is overhauled, such as in
calendar year 2022, generation would be lower than the modeled average. Dave Johnston Unit 4
also experienced a number of forced outages during 2022 due to a variety of boiler tube leaks.
Naughton plant generation was down 631,479 MWh or 25 percent, compared to the base
forecast. Naughton Unit 2 experienced an unusually long outage period primarily due to
generator and exciter problems. A 2022 Thermal Outage Summary is attached to this
Investigative Report as Confidential Exhibit No. 1. Huntington generated 23 percent more than
the base forecast or 1,074,181 MWh, despite the coal supply issues facing the Utah plants during
the fourth quarter of 2022.
Coal generation variances in prior ECAMs were significantly larger than the 2022 ECAM
variance of five percent. In the 2020 ECAM6, actual coal generation decreased by 8,465,194
MWh on a total-company basis, or 22 percent compared to the forecast base period (calendar
year 2016). In the 2021 ECAM7 actual coal generation decreased by 7,509,751 MWh on a total-
company basis, or 19 percent compared to the forecast base period as shown below in Table 4.2:
6 In the Matter of Rocky Mountain Power’s Application Requesting Approval of $16.1 Million Net Power Cost
Deferral (ECAM), Case No. PAC-E-21-09. Base NPC for the 2020 ECAM were based on 2015 annual results of
operations report and established In the Matter of Rocky Mountain Power to Update the Base Net Power Costs and
Implement a Rate Stability Plan, Case No. PAC-E-16-12, Application at 5.
7 In the Matter of Rocky Mountain Power’s Application Requesting Approval of $28.4 Million ECAM Deferral, Case
No. PAC-E-22-05. Base NPC for the 2021 ECAM were based on 2015 annual results of operations report and
established In the Matter of Rocky Mountain Power to Update the Base Net Power Costs and Implement a Rate
Stability Plan, Case No. PAC-E-16-12, Application at 5. 
Plant Base MWh Actual MWh Variance Percent
Colstrip 965,999 1,080,477 114,478 12%
Craig 997,267 1,066,740 69,473 7%
Dave Johnston 4,974,304 3,581,919 (1,392,385) (28%)
Hayden 442,366 523,072 80,706 18%
Hunter 6,057,136 5,865,760 (191,376) (3%)
Huntington 4,598,934 5,673,115 1,074,181 23%
Jim Bridger 7,656,465 7,376,117 (280,348) (4%)
Naughton 2,511,449 1,879,970 (631,479) (25%)
Wyodak 1,671,199 1,343,811 (327,388) (20%)
Total Coal 29,875,118 28,390,981 (1,484,137) (5%)
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Table 4.2 – Coal Generation – Forecast Base to Actual 2020-2022
The large variances in the 2020 ECAM and the 2021 ECAM are also within the expected range
and reflect the fact that the periods being compared are four to five years apart as well as the fact
that Cholla Unit 4 was retired and Naughton Unit 3 was converted to gas after the 2016 forecast
base period.
As shown in Table 4.3 below, natural gas generation in the 2022 ECAM increased by 5,198,076
MWh on a total-company basis, or 61 percent compared to the forecast base period:
Table 4.3 – Gas Generation – Forecast Base to Actual 2022
When compared to prior ECAMs, the natural gas generation variance in the 2022 ECAM was
significantly larger. The 2020 ECAM actual natural gas generation decreased by 307,312 MWh
on a total-company basis, or two percent compared to the forecast base period. The 2021 ECAM
natural gas generation increased by 962,582 MWh on a total-company basis, or eight percent
compared to the forecast base period as shown below in Table 4.4. These variances are also
within the expected ranges.
Table 4.4 below also shows that actual natural gas generation from 2020 to 2022 increased by
1,643,774 MWh or about 14 percent. Given the coal supply limitations the Company endured in
calendar year 2022, along with the extreme weather events, ongoing drought, and increased load,
it would be expected that gas generation would increase in actual system operations. This is
especially true when natural gas generation is still a more economical resource compared to
market purchases, on average.
Year Base MWh Actual MWh Variance Percent
2020 ECAM 39,100,008 30,634,813 (8,465,194) (22%)
2021 ECAM 39,100,008 31,590,257 (7,509,751) (19%)
2022 ECAM 29,875,118 28,390,981 (1,484,137) (5%)
Plant Base MWh Actual MWh Variance Percent
Chehalis 2,182,201 2,171,994 (10,207) (0%)
Currant Creek 993,561 2,805,979 1,812,418 182%
Gadsby 123,088 118,821 (4,267) (3%)
Hermiston 1,049,262 1,433,878 384,616 37%
Lake Side 1 1,487,154 3,047,188 1,560,034 105%
Lake Side 2 2,143,135 3,531,485 1,388,350 65%
Naughton - Gas 509,100 576,231 67,131 13%
Total Gas 8,487,500 13,685,576 5,198,076 61%
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Table 4.4 – Natural Gas Generation – Forecast Base to Actual 2020-2022
5.0 Forecast Method and Optimization Models
The Base NPC from the 2021 GRC set the forecast for calendar year 2022 and the 2022 ECAM’s
NPC differential is the difference between that 2021 Base NPC and the 2022 Actual NPC. In
calendar year 2022:
1.Wholesale electricity market prices were approximately 82 percent higher than the
wholesale electricity market prices assumed in the 2021 Base NPC.
2.Natural gas market prices were approximately 151 percent higher than the natural gas
market prices assumed in the 2021 Base NPC.
3.Hydroelectric generation (water availability) was approximately 34 percent lower than
the hydroelectric generation assumed in the 2021 Base NPC.
NPC are sensitive to underlying commodity prices outside of the Company’s control, and these
commodity prices are wholesale electricity market prices, natural gas market prices and coal fuel
prices. Regional wholesale electricity market prices are driven by regional natural gas market
prices and calendar year 2022 natural gas market prices saw an unexpected increase due to
various regional and national events such as the conflict in the Ukraine. Furthermore,
unanticipated drought conditions in the Pacific Northwest decreased expected hydroelectric
generation which diminished local and regional energy supply. Coal fuel is discussed in detail in
Sections 6.0, 7.0, and 8.0 of this Investigative Report.
Additionally, global supply chain constraints delayed production and transportation of key
components and equipment necessary for renewable resource construction across the nation. In
the planning arena, at the regional level, renewable resource construction/acquisition is assumed
to partially offset the impact of thermal plant retirements on an energy basis. In the short term,
while the construction of these renewable resources are delayed, the thermal plant retirements
are, however, proceeding as scheduled. The resulting energy shortfall decreases supply without
any associated decrease in demand (load). Consequently, this triggers an incremental energy
price rise across the competitive regional wholesale electricity markets which is additive to the
exacerbation caused by natural gas market price increases.
Year Base MWh Actual MWh Variance Percent
2020 ECAM 12,349,114 12,041,802 (307,312) (2%)
2021 ECAM 12,349,114 13,311,696 962,582 8%
2022 ECAM 8,487,500 13,685,576 5,198,076 61%
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PacifiCorp relies on a least-cost optimization model to ensure the cost-effective fulfillment of its
system obligations. This optimization model takes into consideration various factors such as load
resource balance, generator characteristics, system obligations, fuel supply, and transmission
limits to determine the most efficient unit dispatch schedule. Due to expected variations between
input forecasts and actual real-time operating conditions, market traders use the modeled results
as a guide when making decisions on how to best economically serve the system obligations.
This approach enables PacifiCorp to economically meet its obligations through coal generation,
other resources, or market purchases.
Regarding the economic dispatch of coal units in calendar year 2022, PacifiCorp's least-cost
optimization model and the California Independent System Operator’s Western Energy
Imbalance Market optimization model both accounted for the challenges related to coal supply.
2022 witnessed historically low coal inventories and surging natural gas prices, necessitating
additional purchases of coal to meet immediate consumption needs and replenish depleted
inventories.
6.0 PacifiCorp’s Coal Acquisition Process
PacifiCorp’s goal in acquiring fuel supply for the coal generating plants is to secure the least-cost
and least-risk fuel for customers. To achieve this, the Company follows a comprehensive fuel
supply planning process. It begins with estimating the annual and future generation forecast for
each coal plant, considering many factors including historical usage patterns, the Company’s
sales and load forecasts, coal, power, and gas market price forecasts, changes in available
generation throughout the Company’s system and neighboring areas, operating lives of coal
plants and other generating plants, and operational and regulatory reliability requirements.
Subsequently, the Company then develops fuel volume, pricing, and sourcing assumptions, as
well as transportation costs. If applicable, operating and capital costs for the plant are considered.
In cases where a coal generating plant is supplied by a dedicated, jointly-owned mine, PacifiCorp
collaborates with other owners to develop a mine plan to support the long-term fueling forecast.
All costs from all sources are combined and evaluated to establish a fueling plan that is least-cost
and least-risk.
The Company negotiates with third-party suppliers to secure fuel contracts to meet its generation
forecasts in a manner that is least-cost and least-risk. PacifiCorp’s process for developing and
negotiating these contracts considers a range of important factors, including contract term, price,
volume, supplier credit worthiness, plant location or coal region, coal supply options, coal
transportation options, and coal quality. It is important to note that coal contracts can vary in
length and are often renewed or replaced on a rolling basis. The forecasts used for one contract
may differ from those used for another contract executed on a different date. Furthermore,
subsequent contracts are often negotiated during different market conditions, given the ever-
changing nature of the coal market.
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It is also important to recognize that coal quality specifications vary across different regions, and
transportation costs play a significant role in the overall fuel procurement process. Moreover,
PacifiCorp’s coal plants are situated in diverse geographic locations throughout the Western
United States in strategic locations, typically adjacent to or near coal sources to minimize
transportation costs. This diversity serves to reduce overall system risk since there may be
locations where transportation, labor, or supplies may be limited for a given time, yet other
locations may not have those same limitations. Given these factors, PacifiCorp considers term,
price, volume, and coal quality when negotiating third-party CSAs and seeks to strike the
optimum balance among these factors. Negotiations for bilateral CSAs are specific to the
individual plant, mine or mines that can serve the plant, transportation requirements, and overall
coal market.
CSAs play a vital role in ensuring reliable, uninterrupted supply of coal that will be available to
fuel the Company’s plants at known and predictable prices, terms, and conditions. In contrast,
relying solely on spot market purchases to supply its plants poses significant risks. Relying
exclusively on the spot market is an extremely risky strategy because it would expose customers
to substantial and unreasonable price and supply risk, especially in the illiquid markets in which
most of PacifiCorp’s coal plants are located. On the other hand, multi-year contracts significantly
reduce the risk to customers associated with market price volatility or fluctuations. It is also
critical to emphasize that without the security of fuel supply contracts, there may be an elevated
risk of fuel shortages during certain times of the year.
7.0 Changes in Coal Market Conditions
The coal market has experienced unprecedented price increases and significant fluctuation since
2021 including but not limited to: increased coal demand due to high domestic natural gas prices;
nationwide low inventories at coal-fired power plants; increased demand abroad for coal exports;
international and domestic supply chain constraints; labor and material shortages; and general
market inflation.
Due to the record-high coal prices in export markets, many United States coal mines, including
coal mines in Utah, rushed to take advantage of record high coal prices by exporting coal, or by
leveraging increased prices in the domestic market. Additionally, the Lila Canyon mine fire that
occurred in September 2022 compounded the supply and demand imbalance in the Utah coal
market. The Lila Canyon mine accounted for more than 25 percent of Utah’s total coal
production in recent years. In November 2023, PacifiCorp was informed that the Lila Canyon
mine will not be resuming coal production.
Also in calendar year 2022, the Company received force majeure claims from its two major Utah
coal suppliers: (1) Bronco Utah Operations, LLC (“Bronco”) on June 22, 2022, and (2)
Wolverine Fuels, LLC (“Wolverine”) on September 22, 2022. These two force majeure claims
are attached to this Investigative Report as Confidential Exhibit No. 2. To manage the shortfalls
in coal deliveries caused by the force majeure claims, PacifiCorp evaluated the merits of the
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claims and considered the legal options available to it under its CSAs. In July 2022, the
Company began transporting coal from the Rock Garden safety pile for consumption at the
Huntington plant to compensate for reduced coal deliveries. The Company also began working
with current suppliers on potential solutions and new potential Utah coal suppliers to secure
additional coal and began exploring alternative coal sources.
Therefore, to acquire additional coal, PacifiCorp issued a request for proposals (“2022 RFP”) on
August 31, 2022. The 2022 RFP was provided to all of the logical mine suppliers, a total of
seven entities. After analyzing the proposals received, PacifiCorp accepted two proposals and
negotiated agreements with Gentry Mountain Mining, LLC (“Gentry”) and Wolverine for
deliveries during 2023 through 2025. The 2022 RFP results demonstrate both the limited
availability of coal in 2022 and the significant price increases in the current coal market for the
shorter-term CSAs. The Company also initiated evaluations for (and continues to evaluate)
potential acquisition of coal sourced from outside of Utah.
The Hunter and Huntington plants lack rail infrastructure for receiving out-of-state coal by rail.
This lack of adequate off-loading rail infrastructure limits PacifiCorp’s ability to procure and
receive coal from outside of the state of Utah. Notwithstanding this limitation, the Company
invited coal and transportation suppliers both inside and outside of Utah to participate in the
2022 RFP to explore the feasibility of alternative coal supply options.
The Company also explored the possibility of using the Company’s own mines – Bridger mine in
Wyoming and Trapper mine in Colorado – to cost-effectively supply the Hunter plant. However,
due to coal supply needs at the Jim Bridger and Craig plants, additional coal was not available to
ship to Utah. Furthermore, the Company is working with several non-conventional coal sources,
including coal previously categorized as refuse, to supplement the fuel supply and continues to
look for innovative ways to increase fuel supply at both the Hunter and Huntington plants.
Confidential Table 7.1 below provides the details of the force majeure claims by the Utah coal
suppliers:
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Confidential Table 7.1 – Force Majeure Claims in 2022
The coal supply constraints discussed above resulted in lower than forecasted coal deliveries at
both the Huntington and Hunter plants in 2022. PacifiCorp’s stockpiled inventories in Utah were
significantly depleted. The Company anticipates there will be a continuation of coal supply
shortages and market instability in the foreseeable future. Moreover, received and consumed coal
quantities at the Utah plants will likely remain approximately the same in upcoming years until
additional coal can be secured. Confidential Table 7.2 below provides a comparison of 2022
actuals, consumed and contracted coal quantities for both Hunter and Huntington plants:
Confidential Table 7.2 – 2022 Utah Plants Coal Delivered and Consumed
As illustrated in Table 7.3 below, PacifiCorp began the year 2022 with 132 days of coal
inventory and ended with 65 days of inventory at the Utah plants based upon expected
consumption of 7.0 million tons:
Plant
Contracted
Tons
Delivered
Tons
Consumed
Tons
Inventory
Tons Used
Hunter 2,573,711 3,303,195 729,484
Huntington 1,966,980 2,520,067 553,087
Total 4,540,691 5,823,262 1,282,571
REDACTED
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Table 7.3 – 2022 Utah Plants Coal Inventory
PacifiCorp began reducing generation at the Hunter plant in September 2022 and at the
Huntington plant in November 2022 to maintain stockpile reliability targets. Based upon industry
standard practice regarding the dispatch of fuel-limited resources, such as hydro plants,
PacifiCorp calculated the dispatch price for the fuel-limited Hunter and Huntington units to
maintain prudent and reliable coal stockpile inventories and secure plant availability for the
benefit of customers during critical periods when the plants were most needed. This calculation
rendered the Hunter and Huntington plants less economically favorable to dispatch within the
operational optimization model. However, these actions were necessary and the Hunter and
Huntington plants were dispatched appropriately in comparison to other generating resources.
8.0 Coal Supply Agreements
PacifiCorp purchased coal for its nine coal-fueled plants under 14 different CSAs during
calendar year 2022. The Company entered into one new CSA, and one amendment of a
previously executed CSA, for 2022. Prior to entering into a CSA, the Company conducts a
detailed internal economic analysis to determine whether the CSA is a reasonable and prudent
business decision and in the best interest of its customers. Generally, these economic analyses
include background on each plant, key contracting provisions, discussion of modeling inputs and
assumptions, and analyses of various scenarios ran under current and forecasted conditions.
These analyses are consistent with the Company’s integrated resource planning (“IRP”)
processes and rely on software to estimate the expected cost or benefit of each new CSA
compared to relevant alternatives. The 14 CSAs are listed in Table 8.1 below:
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Table 8.1 – Existing, Amended, and New CSAs in 2022
The Company is focused on achieving its target coal supply at a reasonable price, along with
contract terms that provide flexibility. PacifiCorp continuously re-evaluates the practice of
maintaining flexibility in its fuel’s supply options and generation planning strategies, with each
new CSA to determine whether a longer or shorter term would benefit its customers and
maintain generation. Each CSA typically has a minimum-take or similar contracting provision
which is a fundamental component of most CSAs and constitutes the consideration required to
obtain a supplier’s commitment to provide coal.
8.1 Utah Plants
8.1.1 Hunter Plant
The Hunter plant is located near Castle Dale, Utah, in Emery County. The plant is supplied with
coal from Wolverine, Bronco and Gentry. The coal is delivered to the plant by trucks. It has
operated three coal units since opening in 1978. The combined rated capacity for the three units
is 1,363 MW. PacifiCorp owns 93.75 percent of Hunter Unit 1, 60.31 percent of Hunter Unit 2,
and 100 percent of Hunter Unit 3, for a combined 84.97 percent or 1,158 MW. Deseret
Generation & Transmission, Utah Association of Municipal Power Systems and Utah Municipal
Power Agency are the Hunter plants’ co-owners. Historically, PacifiCorp has purchased 100
percent of Hunter’s coal requirements from local mines. The co-owners then purchase their coal
requirements from PacifiCorp based on their actual coal consumption. PacifiCorp’s 2023 IRP
calls for Hunter Unit 1 to cease burning coal on December 31, 2031, and for Hunter Unit 2 and
Hunter Unit 3 to cease burning coal on December 31, 2032.
The total amount of coal under contract for the Hunter plant in 2022 was [Begin Confidential]
[End Confidential] tons. However, PacifiCorp did not receive the full amount of
coal supply under its existing CSAs for the Hunter plant due to the force majeure claims,
Plant Supplier/Mine Contract Type Executed Term
Naughton Kemmerer Operations/Kemmerer Existing CSA 12/29/21 Jan 2022 - Dec 2025
Wyodak Wyodak Resources / Wyodak Existing CSA 01/01/01 Jan 2001 - Dec 2022
Dave Johnston Arch / Coal Creek Existing CSA 08/20/19 Jan 2020 - Dec 2022
Dave Johnston Peabody / Caballo Existing CSA 09/17/19 Jan 2020 - Dec 2022
Dave Johnston Peabody / NARM Existing CSA 11/12/20 Jan 2021 - Dec 2024
Dave Johnston Peabody / Caballo Existing CSA 12/08/20 Jan 2021 - Dec 2024
Hunter Bronco / Emery 2nd Amendment 08/03/22 Aug 2022 - Dec 2022
Hunter Wolverine Fuels Existing CSA 12/11/20 Jan 2021 - Dec 2023
Huntington Wolverine / Sufco & Skyline Existing CSA 12/12/14 Jun 2015 - Dec 2029
Jim Bridger Lighthouse Resources / Black Butte Existing CSA 02/28/18 Jan 2018 - Jun 2022
Jim Bridger Lighthouse Resources / Black Butte New 06/17/22 Jun 2022 - Dec 2023
Colstrip Westmoreland/Rosebud Existing CSA 12/05/19 Dec 2019 - Dec 2024
Craig Trapper Mining/Trapper Existing CSA 01/01/21 Jan 2021 - Dec 2025
Hayden Peabody/Twentymile Existing CSA 12/12/11 Jan 2012 - Dec 2027
REDACTED
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transportation issues, mine geologic difficulties and other challenges in the Utah coal market.
The contracted volume was also more than the actual coal consumed at Hunter in 2022, which
included a significant portion of the available stockpiled inventory.
8.1.2 Huntington Plant
The Huntington power plant is located near Huntington, in Emery County, Utah. As part of the
closure of the Deer Creek Mine in 2014, which was the primary source of coal for the
Huntington power plant, the Company executed a 15-year agreement with Wolverine to supply
the Company’s coal requirements for Huntington plant through December 2029. The expected
annual quantity has a minimum purchase obligation of [Begin Confidential][End
Confidential] tons of coal per year and a maximum supply obligation of [Begin Confidential]
[End Confidential] tons per year. The CSA has fixed pricing for the entire term of
the contract and the CSA includes a minimum take provision.
Similar to the Hunter plant, PacifiCorp did not receive the full amount of coal supply under the
existing CSA for the Huntington plant due to multiple factors such as: a force majeure claim,
transportation issues, mine geologic difficulties and other challenges in the Utah coal market.
Coal stockpiled at the Rock Garden safety pile was used to supplement the consumption at the
Huntington plant.
8.2 Wyoming Plants
8.2.1 Jim Bridger Plant
The Jim Bridger plant is located approximately 24 miles east of Rock Springs, Wyoming. The
Jim Bridger plant is the largest power plant on the PacifiCorp system (2,120 MW) and is jointly
owned by PacifiCorp (66.7 percent) and Idaho Power Company (“IPC”) (33.3 percent). The Jim
Bridger plant consists of four almost identical units, each with a nominal 530 net MW capacity.
Over the four-year period of 2019-2022, the Jim Bridger plant consumed 24 million tons of coal,
an average of six million tons per year. The plant is designed to consume coal sourced from
southwest Wyoming. PacifiCorp’s 2023 IRP calls for Jim Bridger Unit 1 and Jim Bridger Unit 2
to cease burning coal on December 31, 2023, and convert to natural gas consumption. Jim
Bridger Unit 3 and Jim Bridger Unit 4 are planned to cease burning coal on December 31, 2029,
and convert to gas as well. The remaining useful life for all four Bridger units is forecasted to be
December 31, 2037.
Ownership in the Bridger Coal Company allows PacifiCorp to flex coal deliveries up or down,
within certain constraints, to better align Jim Bridger plant delivered and consumed coal
quantities. Mine ownership also reduces coal supply delivery risk, mitigates unfavorable impacts
of unexpected coal delivery changes, and has historically improved contract price terms with the
third-party coal supplier.
PacifiCorp did not reduce generation at the Jim Bridger plant during calendar year 2022 due to a
lack of coal supply. PacifiCorp’s minimum stockpile reliability target for 2022 was deemed to be
REDACTED
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530,000 tons or 45 days of expected consumption of 4.3 million tons. As illustrated in Table 8.2
below, PacifiCorp’s inventory stockpile at Jim Bridger exceeded that target throughout 2022:
Table 8.2: 2022 Jim Bridger Coal Inventory
Being the 67 percent owner of the Jim Bridger plant, PacifiCorp is responsible for supplying its
ownership portion of the coal directly to the plant. PacifiCorp prudently managed its coal
inventory in 2022 by beginning the year with just over one million tons of coal which equated to
78 percent of the coal at the plant. PacifiCorp ended the calendar year 2022 with a supply of
approximately 719,000 tons which equated to 90 percent of the coal inventory. The Company
entered 2022 with enough coal to be able to draw from its coal stockpile without placing
inventory at a level that could have jeopardized reliability for its customers.
PacifiCorp’s coal inventory exceeded its minimum stockpile reliability target of 45 days of
inventory throughout 2022. There was no need for PacifiCorp to reduce generation at the Jim
Bridger plant in 2022 to conserve coal. Thus, PacifiCorp did not reduce generation in 2022 to
conserve coal inventory at the Jim Bridger plant. As shown in Confidential Table 8.3 below, the
coal supply shortfall experienced at Jim Bridger did not reach a level critical enough for
PacifiCorp to take measures to reduce generation in 2022:
2022 Tons
Consumed
Beginning
Inventory as
Expected
Days Burn
Ending
Inventory as
Expected
Days Burn
Tons %Tons %
PacifiCorp 1,008,008 78% 718,623 90% 4,215,793 86 61
Idaho Power 276,559 22% 79,160 10% 1,885,327 54 15
Total Plant 1,284,567 100% 797,783 100% 6,101,120 76 47
Jim Bridger Plant Inventory
12/31/2021 12/31/2022
Note: PacifiCorp's Days Burn is calculated using Expected 2022 Consumption of 4.3
million tons. Idaho Power's Days Burn is calculated using actual 2022 consumption.
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Confidential Table 8.3: 2022 Jim Bridger Coal Supply (PacifiCorp Share)
It is important to recognize the distinction between the situations faced by PacifiCorp and IPC in
2022 concerning coal supply issues and the resulting generation curtailment at the Jim Bridger
plant. Through proactively managing its coal supply, PacifiCorp successfully avoided the need to
reduce generation to ensure an adequate coal stockpile availability to meet reliability standards.
Specifically, PacifiCorp took the following actions to ensure an adequate coal supply at Jim
Bridger for the relevant time-period:
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 IPC) were consumed
from the long-term storage pile in 2022.
In September 2022, PacifiCorp issued an 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 plant.
PacifiCorp also embarked on a search to lease 120 coal railcars, further demonstrating its
commitment to securing adequate transportation resources for coal deliveries.
These proactive actions ultimately led to the successful delivery of PRB coal to the Jim Bridger
plant, commencing in April 2023. By taking these steps, PacifiCorp effectively managed its coal
supply and ensured the availability of coal for the Jim Bridger plant, ensuring benefit to its
customers. These measures highlight PacifiCorp's continuous proactive approach to addressing
the unprecedented coal supply challenges that occurred in 2022 while maintaining reliable
generation.
Plant Supplier
Budgeted
Tons
Delivered
Tons Variance Explanation
Bridger Bridger Coal Company 2,653,333 2,648,039 (5,294)
Black Butte Coal Company 1,278,948
3,926,987
REDACTED
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8.2.2 Naughton Plant
The Naughton plant is located in Kemmerer, Wyoming, and is wholly owned by PacifiCorp.
Naughton is supplied by the adjacent Kemmerer mine with Naughton Unit 1 and Naughton Unit
2, rated at 156 and 201 MW, operated on coal and Naughton Unit 3 operates on natural gas.
PacifiCorp’s 2023 IRP identifies that Naughton Unit 1 and Naughton Unit 2 will cease burning
coal on December 31, 2025, and convert to gas in 2026. PacifiCorp’s prior agreement for
Naughton’s coal supply ended on December 31, 2021. PacifiCorp executed a new CSA with the
Kemmerer Mine for the purchase of Naughton’s coal supply from January 1, 2022 through
December 31, 2025. 
8.2.3 Dave Johnston Plant
The Dave Johnston plant is located in Glenrock, Wyoming. PacifiCorp owns 100 percent of the
plant and operates all four units. The output capacity at the plant is as follows: Dave Johnston
Unit 1 – 99 MW; Dave Johnston Unit 2 – 106 MW; Dave Johnston Unit 3 – 220 MW; and Dave
Johnston Unit 4 – 330 MW. The plant receives coal from mines in the PRB which is the largest
coal production region in the U.S. Due to the abundance of coal in the PRB, along with the
number of operating mines in this region, PacifiCorp is able to take advantage of favorable coal
market pricing that exists in the liquid PRB market. The coal is delivered by Burlington Northern
Santa Fe Railway. During 2022 there were four CSAs; one with Arch Coal’s Coal Creek Mine
and three with Peabody Energy for deliveries from the Caballo mine and North Antelope
Rochelle mine.
8.2.4 Wyodak Plant
The Wyodak plant is located in Campbell County, Wyoming, and is jointly owned with Black
Hills Energy (“Black Hills”), which has a 20 percent ownership interest in the plant. There is one
coal unit at the Wyodak plant with an output capacity of 335 MW. The Wyodak plant is a mine-
mouth operation and receives its coal from the adjacent Wyodak Mine by conveyor. This
eliminates the need to store coal inventory at the plant. Wyodak Resources Development Corp.
(a subsidiary of Black Hills) owns and operates the mine. PacifiCorp’s agreement for the
Wyodak plant’s coal supply was from January 1, 2001, to December 31, 2022. A new CSA for
Wyodak was signed in 2022 for coal supply beginning in 2023.
8.3 Joint-Owned Plants – Partner Operated
8.3.1 Colstrip Plant
The Colstrip plant is a 1,480 MW two-unit coal plant located in Colstrip, Montana. Colstrip Unit
3 and Colstrip Unit 4 are jointly owned by Avista Corporation, NorthWestern Energy,
PacifiCorp, Portland General Electric Company, Talen Energy, and Puget Sound Energy.
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Colstrip Unit 1 and Colstrip Unit 2 were retired in 2020 and were owned by Talen Energy and
PSE. The plant is a mine-mouth operation and receives its coal from the adjacent Rosebud Mine
by conveyor. Westmoreland Rosebud Mining, LLC owns and operates the mine. PacifiCorp’s
agreement for the Colstrip plant coal supply is from January 1, 2020, through December 31,
2024, with an option for PacifiCorp to extend it through December 31, 2025.
8.3.2 Craig Plant
The Craig plant is a 1,427 MW, three-unit coal plant located in Moffat County, Colorado. Craig
Unit 1 and Craig Unit 2 are jointly owned by Tri-State Generation and Transmission Association
(“Tri-State”), Salt River Project Agricultural Improvement and Power District (“SRP”), Platte
River Power Authority (“Platte”), PacifiCorp and Public Service Company of Colorado
(“PSCo”). Craig Unit 3 is owned exclusively by Tri-State. Craig Unit 1 and Craig Unit 2 are
supplied by the Trapper mine, which is an affiliate captive mine owned by three entities with the
ownership percentages as follows: SRP – 43.72 percent, PacifiCorp – 29.14 percent, and Platte –
27.14 percent. The recent CSA between Trapper mine and PacifiCorp, SRP and Platte was for a
term of 10 years, from January 1, 2010, through December 31, 2020, which was later extended
for another five years through December 31, 2025.
8.3.3 Hayden Plant
The Hayden plant is a 441 MW, two-unit coal plant located in Routt County, Colorado. Hayden
Unit 1 is jointly owned by PSCo and PacifiCorp. The Company owns 24.5 percent of Hayden
Unit 1. Hayden Unit 2 is jointly owned by PSCo, SRP, and PacifiCorp. The Company owns
12.6 percent of Hayden Unit 2. PSCo operates the plant. PacifiCorp negotiated the Hayden CSA
in collaboration with PSCo and SRP in order to secure future fuel requirements for Hayden from
the nearby Twentymile mine owned and operated by Peabody Energy. The Hayden CSA was
executed on December 12, 2011, and runs through December 31, 2027. Hayden Unit 2 is
scheduled for closure in 2027 and Hayden Unit 1 is scheduled for closure in 2028.
9.0 Conclusion
In compliance with Order No. 35801, the Company respectfully submits this Investigative
Report focused on the issues related to lower coal generation and coal supplies, the deployment
of its coal fleet, and the Company’s management of these issues during 2022.
As shown in this Investigative Report in detail, the actual coal generation in the 2022 ECAM
was reasonable and in best interest of its customers, and the Company operated prudently based
on market conditions that were influenced by multiple factors including but not limited to, the
war in the Ukraine and extreme weather events. The Company was also challenged by force
majeure events outside of its control, but the Company was properly prepared for these events
with sufficient stockpile supplies at both the Hunter and Huntington plants as well as the Rock
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Garden safety pile. Faced with force majeure events, the Company took proactive measures to
deploy its coal fleet prudently by working to secure additional coal while prudently managing its
coal supply to ensure its coal fleet reliability was maintained. Despite facing numerous
challenges in 2022 as detailed in this Investigative Report, the difference between actual and the
forecast coal generation was only five percent.
The Company respectfully request that the Commission issue an order finding that the Company
complied with the requirements in Order No. 35801 and costs within the 2022 ECAM deferral
were prudently incurred.
Confidential Exhibit No. 1
2022 Thermal Outage Summary
THIS EXHIBIT IS CONFIDENTIAL IN ITS
ENTIRETY AND IS PROVIDED UNDER SEPARATE
COVER
Confidential Exhibit No. 2
Force Majeure Claims
THIS EXHIBIT IS CONFIDENTIAL IN ITS
ENTIRETY AND IS PROVIDED UNDER SEPARATE
COVER