20220315Joint Comments and Attachments-Redacted.pdf

Rose Monahan (CA 329861) (Pro Hac Vice) Sierra Club Environmental Law Program 2101 Webster Street, Suite 1300
Oakland, CA 94612 (415) [e-mail]
Attorney for Sierra Club
Benjamin J. Otto (ISB No. 8292) 710 N 6th Street Boise, ID 83701 Ph: [phone] x 12
Fax: [phone] [e-mail]
Attorney for the Idaho Conservation League
BEFORE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF ROCKY MOUNTAIN POWER’S FILING FOR
ACKNOWLEDGEMENT OF ITS 2021
INTEGRATED RESOURCE PLAN
CASE NO. PAC-E-21-19
JOINT COMMENTS OF SIERRA
CLUB AND IDAHO
Public Version
March 15, 2022
RECEIVED
2022 MAR 15 PM 4:24
IDAHO PUBLIC
UTILITIES COMMISSION

i
TABLE OF CONTENTS

I. Introduction and Recommendations 1
A. Key Conclusions and Observations of PacifiCorp’s 2021 IRP 5
B. Summary of Recommendations 7
II. PacifiCorp’s Methodological Choices for Reliability and Resource Adequacy Raise
Significant Concern. 11
A. There Are Inconsistencies Between PacifiCorp’s Capacity Contribution Study and the
Preferred Portfolio with Respect to the Capacity Value of Solar Plus Storage,
Potentially Leading to Overbuild of Coal Replacement Resources. 11
B. PacifiCorp’s Application of a 13 Percent Hourly Reserve Margin to Individual Load
Areas Is Not Fully Justified. 14
1. Reliability metrics 15
2. Binding transmission limits 16
C. PacifiCorp’s Portfolio Development Process Included a Non-Transparent Post-
Modeling “Reliability Adjustment” that Lacked Adequate Supporting Data or
Analysis. 17
III. Coal Unit Economics and Plant Retirements 21
A. PacifiCorp Failed to Include a Unit-By-Unit Coal Analysis Consistent with the 2019
IRP. 21
B. PacifiCorp Inappropriately Assumes a Significant Share of Its Future Coal Fuel
Expenditures Are “Sunk Costs” in the Form of Future Take-Or-Pay Contracts. This
Assumption Significantly Constrains Any Coal Retirement Analysis Since These
Costs Would Never Materialize if the Plants Retired Early. 25
1. PacifiCorp Inappropriately Assumed that Jim Bridger and Huntington are Subject
to Minimum Take Requirements 26
2. PacifiCorp’s Coal Fuel Pricing Tier Assumptions Lack Any Clear Explanation or
Justification 30
C. A Sensitivity Model Run Removing Minimum Take Requirements at Jim Bridger
Yielded Significant Benefits and Should be Considered in Place of the Preferred
Portfolio 31
1. The No Minimum Scenario Indicates that Jim Bridger Could Potentially be
Fueled Exclusively by the Bridger Mine 32
2. The No Minimum Scenario Supports Retirement of Jim Bridger Units 3 and 4
Prior to 2037 34

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3. The No Minimum Scenario–If Selected–Would Impact the Near-Term Action
Plan and Upcoming All Source RFP 38
D. A Sensitivity Model Run Removing Huntington’s Minimum Take Assumptions Was
Not Preformed, but Should be Required in Future IRPs 39
E. The P02h Variant Case (Jim Bridger Units 3 and 4 Early Retirement) Is Lower in
Cost than PacifiCorp’s Preferred Portfolio (P02-MM-CETA). This Is True Despite
Questionable Assumptions that Needlessly Inflate the Cost of the P02h Variant Case.
41
F. PacifiCorp’s IRP Did Not Fully Assess the Risks Associated with the Early Exit of its
Coal Plant Co-Owners. 43
G. PacifiCorp’s IRP Failed to Evaluate a Feasible Scenario in Which EPA Requires SCR
Installations to Comply with the Clean Air Act. 45
H. PacifiCorp’s P03 Early Coal Retirement Case Is Misleading on Increased Costs
(Relative to the Preferred Portfolio), as These Increases Are Partly Driven by
Deficiencies and Subjective Choices in the Company’s Modeling Methodology. 47
IV. PacifiCorp’s Expectation that it Will Receive Power from the Natrium Plant, a Novel
Nuclear Technology, by 2028 Introduces Substantial Cost and Execution Risks that Were
Not Adequately Addressed in the IRP. 49
V. Risks Related to the Jim Bridger Gas Conversion 54
A. Overview of PacifiCorp’s Proposed Coal-to-Gas Conversion of Jim Bridger Units 1
and 2 54
B. PacifiCorp’s Proposed Gas Conversion Comes with Significant Price Risk. 54
C. The Risk of Fuel Cost Volatility Is Borne by Customers, Not Shareholders. 58
D. PacifiCorp’s IRP Contains Unresolved Questions about the Coal-to-Gas Conversion
Analysis. 59
E. PacifiCorp and Idaho Power Do Not Appear to be Aligned on the Gas Conversion
Proposal. 61
VI. Barriers to Clean Energy 62
A. PacifiCorp’s Long-Term Resource Cost Assumptions Are Not Fully Informed by the
Recent All-Source RFP Results. 62

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LIST OF TABLES
Table 1. Comparison of PacifiCorp’s Coal Unit Costs and Proposed Retirement Dates ............. 23
Table 2. System Optimizer Results from PacifiCorp’s 2019 IRP Coal Retirement Analysis ..... 25
Confidential Table 3. Take-or-Pay Volumes (in Millions of Tons) Assumed by PacifiCorp in
PLEXOS for Future Years at the Huntington and Jim Bridger Plants ......................................... 27
Confidential Table 4. Jim Bridger Generation Output from the LT Model ................................ 37
Table 5. Net Present Value for Coal Plants With and Without SCRs .......................................... 46

LIST OF FIGURES
Confidential Figure 1. Jim Bridger Units 3 and 4 Generation Under the Preferred Portfolio and
the No Minimum Scenario ............................................................................................................ 32
Figure 2. Historic Henry Hub Prices and PacifiCorp's IRP Natural Gas Price Forecast ............. 55
Figure 3. Henry Hub Prices Since January 2020, and PacifiCorp's Gas Price Forecast .............. 56
Figure 4. U.S. Natural Gas Production ........................................................................................ 57
Figure 5. Figure 7.5 from PacifiCorp 2021 IRP Volume I Compared to NREL Cost Assumptions
....................................................................................................................................................... 64

LIST OF ATTACHMENTS
Attachment 1 Selected PacifiCorp Public Data Responses in LC 77
Attachment 2 Confidential Attachment “3112 Capacity Requirements P02-MMR (CO)
Intl UTWY 2031 6-17-21” to PacifiCorp Response to SC 6.1
(Jan. 26, 2022)
Request 4.2 in LC 77 (included in “Attach 2-2 CONF”)
PacifiCorp (PAC/1200) (excerpt)
CONF" to PacifiCorp Response to ALJ Bench Request 1
CONF” to PacifiCorp Response to ALJ Bench Request 1
1
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF ROCKY MOUNTAIN POWER’S FILING FOR
ACKNOWLEDGEMENT OF ITS 2021
INTEGRATED RESOURCE PLAN
CASE NO. PAC-E-21-19
JOINT COMMENTS OF SIERRA
CLUB AND IDAHO
JOINT COMMENTS OF SIERRA CLUB AND IDAHO CONSERVATION LEAGUE [PUBLIC VERSION]
I.Introduction and Recommendations
Sierra Club and Idaho Conservation League (“ICL”) appreciate the opportunity to
comment on PacifiCorp’s 2021 Integrated Resource Plan (“IRP”).1 These comments were
prepared with the assistance of Strategen Consulting, and they are based on a review of
PacifiCorp’s input assumptions and analytical approach. These comments are further informed
by Sierra Club and Idaho Conservation League’s active participation in PacifiCorp’s 2021 IRP
public input meetings and all previous PacifiCorp IRP processes going back to 2011.
As a preliminary matter, it is PacifiCorp’s responsibility to demonstrate that its plans and
actions are in the public interest by balancing costs and risks to customers. Unfortunately, the
Company did not meet this requirement with the 2021 IRP. As our comments show, not only has
the Company modeled costs, such as the take-or-pay coal contracts, in a manner that unduly
favors its coal fleet, but the Company has also omitted critical information supporting its
assumptions and modeling choices that are essential for stakeholders and the Commission to
1 While Sierra Club is the primary author of these comments, ICL adopts and supports all of Sierra Club’s analysis and recommendations herein.
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adequately evaluate PacifiCorp’s analyses and the resulting portfolios. These process and
selection errors result in a resource plan that will cost customers more money and expose them to
more risk inevitable carbon regulations.
As our comments show that not only has the Company modeled costs, such as the take-
or-pay coal contracts, in a manner that unduly favors its coal fleet, but the Company has also
omitted critical information supporting its assumptions and modeling choices that are essential
for stakeholders and the Commission to adequately evaluate PacifiCorp’s analyses and the
resulting portfolios. These process and selection errors result in a resource plan that will cost
customers more money and expose them to more risk due to inevitable carbon regulations.
The omissions throughout the IRP are significant and represent an unacceptable risk for
Idaho customers. For example, (which is further described in Section II(C) below), the Company
included a second nuclear plant in the P02h variant case that examines early retirement of
Bridger units 3 and 4,2 thereby adding a significant cost to that portfolio. Despite touting its
“extensive public-input process,” Sierra Club only learned in November 2021, through informal
conversations with the Company, that the second nuclear plant was not economically selected
but rather was manually forced in to the variant case to meet a reliability need; yet, neither the
IRP nor any of the Company’s written analyses explain the number of hours, the time of year, or
the shortfall of this purported reliability need. This information was only disclosed as a result of
Sierra Club’s data requests. Compounding this lack of transparency, the IRP does not describe
which resources the Company considered when manually filling this unquantified reliability gap

2 Jim Bridger Units 3 and 4 Early Retirement Variant (P02h-JB3-4 Retire). PacifiCorp, 2021 Integrated Resource Plan, Vol. I at 287-289 (Sept. 1, 2021), available at https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-plan/2021-irp/Volume%20I%20-%209.15.2021%20Final.pdf [hereinafter “PacifiCorp 2021 IRP Vol. I”].
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or why it determined a second nuclear plant was the best fit. Sierra Club highlights this one
example to demonstrate the pervasive shortcomings of this IRP, particularly its lack of
transparency concerning critical assumptions and subjective decision-making that went into the
analysis and undoubtedly had significant implications for each portfolio, including the preferred
portfolio.
Furthermore, this IRP cannot be separated from the historic moment in which it was
developed. The Intergovernmental Panel on Climate Change (“IPCC”) has made clear that
humanity’s window to address and slow global climate change is rapidly closing. Within the next
decade, society must act aggressively and decisively to eliminate its reliance on fossil fuels, and
yet, PacifiCorp’s customers must pay for one of the most carbon-intensive energy mixes in the
country. The IPCC has stated that human-caused emissions of carbon dioxide need to fall by 45
percent from 2010 levels by 2030, reaching “net zero” emissions by 2050 in order to have a
realistic chance of limiting global warming to 1.5 degrees Celsius.3 Indeed, even PacifiCorp
implicitly recognizes this necessity by modeling nonexistent “non-emitting peaker” resources;
yet, the Company continues to unduly favor its coal fleet and undervalue clean, renewable
resources. Unlike utilities, such as Idaho Power Company, strategically transitioning away from
coal and committing to 100 percent clean energy,4 PacifiCorp continues to describe its coal fleet
as playing “a pivotal role”5 and is one of the only major utilities to lack a climate action plan. A
business-as-usual approach to electric sector energy planning will ultimately result in millions of

3 IPCC, Summary for Policymakers of IPCC Special Report on Global Warming of 1.5C approved by governments (Oct. 8, 2018), available at https://www.ipcc.ch/2018/10/08/summary-for-policymakers-of-ipcc-special-report-on-global-warming-of-1-5c-approved-by-governments/.
4 See, e.g., Idaho Power Company, Clean Today, Cleaner Tomorrow, available at https://www.idahopower.com/energy-environment/energy/clean-today-cleaner-tomorrow/ (last accessed Mar. 14, 2022) (Idaho Power Company initiative pledging to provide 100 percent clean energy no later than 2045). 5 PacifiCorp 2021 IRP Vol. I at 15, 299.
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Americans losing their homes and communities to what President Biden has described as a
“merciless march of ever-worsening droughts and floods, more intense fires and hurricanes,
longer heatwaves and rising seas.”6 In just the past few years, Idaho has experienced many of
these catastrophes, including droughts, heatwaves, and mega-fires. In 2021 alone, the wildfires in
the western U.S. burned an area larger than Delaware and Rhode Island combined, impacting air
quality in states as far away as Vermont and Maine.7 The recently completed Idaho Climate-
Economy Impacts Assessment by the University of Idaho McClure Center examined the
evidence and concluded that “[p]rojected changes to Idaho’s climate suggest very high
confidence in warming trends, limited changes in total annual precipitation albeit a significant
reduction in the proportion of precipitation falling as snow, and high potential for increased
frequency of certain types of droughts.”8 By failing to account for the impacts of coal pollution
to Idaho’s economy, and the availability of lower cost, cleaner options today, PacifiCorp’s 2021
IRP places undue risks that Idahoans will face ever rising electricity costs along with negative
climatic impacts.
The need and urgency for action cannot be overstated. The Commission can and must
require meaningful action from PacifiCorp to reduce emissions and transition Idaho to a clean,
sustainable energy future. Sierra Club urges the Commission to closely scrutinize PacifiCorp’s
2021 IRP and implement the recommendations below.

6 White House, Remarks by President Biden Before the 76th Session of the United Nations General Assembly (Sept. 21, 2021), available at https://www.whitehouse.gov/briefing-room/speeches-remarks/2021/09/21/remarks-by-president-biden-before-the-76th-session-of-the-united-nations-general-assembly/.
7 Aya Elamroussi, Wildfires have burned a combined area the size of Delaware and Rhode Island – and then some, CNN (July 28, 2021), available at https://www.cnn.com/2021/07/28/weather/western-wildfires-wednesday/index.html. 8 John T. Abatzoglou et al., Idaho Climate-Economy Impacts Assessment: Observed and Projected Changes in
Idaho’s Climate, University of Idaho, at 19 (Dec. 2021), available at https://www.uidaho.edu/president/direct-reports/mcclure-center/iceia/climate.
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A. Key Conclusions and Observations of PacifiCorp’s 2021 IRP
These comments are organized into the following five key subject matters:
1. PacifiCorp’s methodological choices related to reliability
2. Coal unit economics and plant retirements
3. The proposed Natrium nuclear power plant
4. The proposed conversion of Jim Bridger 1 and 2 to burn natural gas
5. Barriers to future clean energy deployment
Based on the analysis it has conducted to date on PacifiCorp’s IRP, Sierra Club has developed
the following set of key conclusions and observations:
Topic 1: Concerns over methodological choices related to reliability
● There are inconsistencies between PacifiCorp’s capacity contribution study and the
Preferred Portfolio with respect to the capacity value of solar plus storage. This
differential may be leading to overbuild of coal replacement resources.
● PacifiCorp’s application of a 13 percent hourly reserve margin was not fully justified
and may be overly conservative.
● PacifiCorp’s portfolio development process included a non-transparent post-modeling
“reliability adjustment.” This step lacked adequate supporting data or analysis.
Topic 2: Coal unit economics and plant retirements
● PacifiCorp failed to include a unit-by-unit coal analysis as it had done in 2019. This
essential step provides a check on the reasonableness of retirements included in its
portfolio-wide analysis.
● PacifiCorp inappropriately assumes a significant share of its future coal fuel
expenditures are “sunk costs” in the form of future take-or-pay contracts. This
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assumption significantly hampers any coal retirement analysis since these costs would
never materialize if the plants retired early.
● PacifiCorp’s coal fuel pricing tier assumptions lack any clear explanation or
justification.
● The P02h variant, which retires Jim Bridger Units 3 and 4 before 2030, is lower in
cost than PacifiCorp’s Preferred Portfolio. This is true despite questionable
assumptions that needlessly inflate the costs of the P02h case.
● The IRP did not fully assess the risks associated with Idaho Power’s early exit from
the Jim Bridger plant.
● PacifiCorp did not adequately assess the risk of a scenario in which selective catalytic
reduction (“SCR”) installations are required at coal units in both Utah and Wyoming.
● PacifiCorp’s P03 Early Coal Retirement Case paints a misleading picture of increased
costs (relative to the Preferred Portfolio), since these increases are partly driven by
deficiencies and subjective choices in the Company’s modeling methodology.
Topic 3: Risks related to the Natrium nuclear plant
● PacifiCorp’s expectation that it will receive power from a novel nuclear technology
by 2028 may be unrealistic and introduces substantial cost and execution risks that
are not adequately addressed in the IRP.
Topic 4: Risks related to the Jim Bridger gas conversion
● PacifiCorp’s planned coal-to-gas conversion of Jim Bridger Units 1 and 2 by 2024
carries significant fuel cost risk that is borne almost exclusively by ratepayers.
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● The recent rise in natural gas prices has already outpaced PacifiCorp’s forecast for
prices in 2034, further indicating that customers may be at significant risk of higher
fuel costs than what PacifiCorp has anticipated.
● If recent price trends continue, PacifiCorp’s plan to burn natural gas at Jim Bridger 1
and 2 (rather than retire the units) could subject customers to additional costs on the
order of $230 million present-value revenue requirement (“PVRR”).
● PacifiCorp does not discuss the lack of any contractual arrangements with co-owner
Idaho Power to allocate costs and liabilities arising from different exit dates from
both coal burning units and the gas conversion.
Topic 5: Barriers to clean energy development
● PacifiCorp’s long-term resource cost assumptions are not fully informed by the recent
all-source RFP results
B. Summary of Recommendations
Based on Sierra Club’s analysis of these five topics, we make the following
recommendations:
Topic 1: Concerns over methodological choices related to reliability
● Recommendation 1: The Commission should direct PacifiCorp to provide more detail
on the capacity value of solar plus storage assumed in each year of its model, and
justify the decline in capacity value after 2030. This detail and explanation should be
provided in all future IRPs.
● Recommendation 2: The Commission should direct PacifiCorp to define a specific
reliability metric for evaluating its resource portfolios along with a specific
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performance target as well as clearly identifying transmission constraints impacting
load area’s ability to meet planning reserve margins.
● Recommendation 3: The Commission should direct PacifiCorp to provide the hourly
results of its reliability analysis, prior to making any reliability-related cost
adjustments or other portfolio refinements. The Commission should also direct
PacifiCorp to identify which resources in each portfolio were added manually as part
of the “portfolio refinement” step and provide a detailed justification for why that
specific resource type was selected and what alternatives were considered.
Topic 2: Coal unit economics and plant retirements
● Recommendation 4: The Commission should direct PacifiCorp to continue
conducting a unit-by-unit coal retirement analysis as performed in 2019 (but not in
2021) for the 2021 IRP and in all future IRPs.
● Recommendation 5: “No Minimum Scenario,” where PacifiCorp removed minimum
take requirements at Jim Bridger, should be considered for the preferred portfolio, as
it reduced the PVRR by $156 million when compared to the top performing case P02-
MM.
o Recommendation 5(a): Replacement energy for Jim Bridger under the No
Minimum Scenario, estimated by Sierra Club to be on the order of 1,000 MW
of new wind, should be considered in the upcoming all-source request for
proposals (“RFP”).
o Recommendation 5(b): The Commission should provide guidance to
PacifiCorp that no additional investments in either the Black Butte or Bridger
Coal Company mines will be authorized prior to a thorough prudency review
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of an updated long-term fuel supply plan for Jim Bridger. The updated plan
should evaluate the feasibility of closing the Bridger mine in the 2026
timeframe (or sooner) and fueling the Jim Bridger plant from stockpiled coal
for the remainder of its life.
● Recommendation 6: The Commission should require that the dispatch of coal
resources modeled in future IRPs is based upon the total or “average” fuel costs over
a period of 1 or more years (rather than some lower incremental value within each
year).
● Recommendation 7: If the No Minimum Scenario is not considered for the preferred
portfolio, the Commission should direct PacifiCorp to evaluate whether the P02h
variant portfolio, where Bridger units 3 and 4 retire in 2026 and 2029 respectively, is
a superior replacement for the Preferred Portfolio, which is designed to comply with
the Washington Clean Energy Transition Act (“CETA”).
● Recommendation 8: The Commission should direct PacifiCorp to model a variant of
its Preferred Portfolio that includes PacifiCorp absorbing Idaho Power’s share of Jim
Bridger plant costs from 2028-2037. PacifiCorp should also be required to compare
this variant to retiring the plant by 2028.
● Recommendation 9: The Commission should direct PacifiCorp to model a variant of
the Preferred Portfolio with SCRs installed on all relevant facilities in Utah and
Wyoming. This variant should be compared to early retirement at these facilities
before 2030.
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Topic 3: Proposed Natrium nuclear power plant
● Recommendation 10: The Commission should require PacifiCorp to provide a
detailed risk assessment for Natrium to be completed on time and within budget. This
should include the nine items detailed in the bulleted list at the end of Section IV
below. The Commission should not acknowledge the Natrium plant as part of this
IRP until such an assessment is available and evaluated.
● Recommendation 11: The Commission should require PacifiCorp to reconcile why
the variant analysis with Natrium removed leads to higher costs, even though the
plant must be forced into the Preferred Portfolio.
Topic 4: Proposed conversion of Jim Bridger 1 and 2 to burn natural gas
● Recommendation 12: The Commission should require PacifiCorp to provide updated
risk assessment of gas fuel that reflects recent price trends. This assessment should be
provided before any further consideration of Jim Bridger conversions by this
Commission.
● Recommendation 13: The Commission should require PacifiCorp to reconcile the
allocation of costs and liabilities arising from the different exit date plans with co-
owner Idaho Power.
● Topic 5: Barriers to Clean Energy Deployment
● Recommendation 14: The Commission should require PacifiCorp to revise its long-
term resource cost assumptions, particularly for battery storage (standalone or paired
with other resources), to better reflect the results of its 2019 all-source RFP.
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II. PacifiCorp’s Methodological Choices for Reliability and Resource Adequacy Raise Significant Concern.
Specific methodological choices PacifiCorp made in all of its IRP analyses may
ultimately have led to a biased resource selection process and therefore raise significant concerns
regarding the accuracy of each portfolio.
Sierra Club understands that certain discretionary methodological choices were made by
PacifiCorp in an attempt to address purported reliability concerns. To be clear, Sierra Club
understands that maintaining grid reliability is paramount and, in many cases, it is important to
err on the side of caution. However, these choices are not transparent, lack supporting data and
analysis, and only receive cursory explanations in the IRP documentation. It is not clear that
these adjustments are necessary or the least-cost approach to meeting reliability needs.
This section details several of these reliability-related issues that warrant further
investigation in this IRP, including:
● The assumed capacity contribution of solar plus storage resources;
● The application of an hourly 13 percent reserve margin at the load area level; and
● The “reliability adjustments” made to initial resource cost assumptions (i.e., post-
modeling).
A. There Are Inconsistencies Between PacifiCorp’s Capacity Contribution Study and the Preferred Portfolio with Respect to the Capacity Value of Solar Plus Storage, Potentially Leading to Overbuild of Coal Replacement Resources.
PacifiCorp provided a detailed capacity contribution study in Appendix K, which
provided the percentage of a resource’s nameplate capacity that is considered reliable for
meeting system demand. This analysis relied upon the capacity factor approximation method,
which the National Renewable Energy Laboratory (“NREL”) determined to be the most
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dependable capacity contribution approximation technique. This method was applied to a
portfolio similar to the Preferred Portfolio in 2030, and thus contemplates a significant amount of
renewable resource penetration. The results of this study for solar plus storage are especially
noteworthy since they found the capacity contribution to be on the order of 79-82 percent in the
summer and 91-95 percent in the winter.9 These values are comparable to many traditional
thermal resources after accounting for forced outage rates.
PacifiCorp’s capacity contribution study shows, then, that solar plus storage is a perfectly
viable replacement option for retiring coal resources in lieu of proposed new thermal additions
such as the Jim Bridger gas conversions or higher-cost, unproven technologies like the Natrium
nuclear plant and non-emitting peaker plants. Both the speculative Natrium nuclear plant and the
hydrogen fueled non-emitting peakers suffer from the same flaws—lack of commercially
available examples, lack of known permitting timelines, and lack of available fuel sources.
However, PacifiCorp significantly discounted solar plus storage as a viable capacity resource
option in lieu of those thermal alternatives, particularly in the later years of the planning period.
For instance, in the P02a-JB 1-2 No GC variant case (i.e., no gas conversion at Jim Bridger), a
significant amount of costly non-emitting peakers are added starting in 2031 instead of simply
adding more solar plus storage, which is cost effective. A similar result is seen in the P02e-No
NUC variant case (i.e., removing the Natrium plant), which favored non-emitting peakers in the
later years, rather than solar plus storage additions. In the P02h-JB3-4 Retire variant case (i.e.,
retire Jim Bridger 3 and 4 by 2030), an additional nuclear unit is added in 2030 instead of
increasing solar plus storage deployment.

9 PacifiCorp, 2021 Integrated Resource Plan, Vol. II, App. K at 221 (Sept. 1, 2021), available at https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-plan/2021-irp/Volume%20II%20-%209.15.2021%20Final.pdf [hereinafter “PacifiCorp 2021 IRP Vol. II”]
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Given the relatively high cost, and vast uncertainty of the availability and performance of
the nuclear and non-emitting peakers, it is unclear why these would be deployed in lieu of solar
plus storage which has a relatively comparable capacity contribution according to PacifiCorp’s
own study. Sierra Club acknowledges that most resources tend to have a declining capacity
contribution at higher levels of penetration, which would also be true of solar plus storage.
However, PacifiCorp has provided no evidence on what those declines would be for specific
resources, or evidence that such declines would be large enough to erode the value of solar plus
storage as a viable alternative to thermal resources.
Finally, PacifiCorp may have used entirely different capacity contribution values than
those included in its own study in Appendix K. For example, Table 9.17 shows that the installed
capacity of the Preferred Portfolio includes 4,781 MW of battery storage collocated with solar by
2040.10 Meanwhile, Table 9.18 shows a solar plus storage summer capacity contribution of only
1,811 MW (1,228 MW east, 583 MW west),11 or a capacity contribution of approximately 38
percent as a percentage of nameplate. This is substantially lower than the 79-82 percent range
from PacifiCorp’s own study. Even for the year 2030, the total solar plus storage summer
capacity contribution is 1,125 MW (350 MW east, 775 MW west), or approximately 66 percent
of the 1696 MW of installed capacity. This capacity value of 66 percent is still far lower than the
79-82 percent range that PacifiCorp’s study would suggest.
To summarize, PacifiCorp’s analysis assumed capacity contributions from solar plus
storage that are much lower than their own study presented in Appendix K. Even accepting the
lower capacity contributions, there is a significant decline in the capacity value of this resource

10 PacifiCorp 2021 IRP Vol. I at 307. 11 Id. at 309-10.
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(i.e., from 66 percent to 38 percent) that it did not fully explain, nor did it provide any supporting
analysis in the IRP. Sierra Club understands that capacity values decline with increasing resource
penetration. However, it is not clear why such a large discrepancy exists between the values in
Appendix K and Tables 9.17 & 9.18, especially in light of the fact that the analysis in Appendix
K “was performed using a portfolio that is similar to the 2021 IRP preferred portfolio”12 and thus
should have already accounted for significant solar penetration.
The assumed decline in capacity value has a significant influence on the overall resource
selection process and warrants further documentation. If PacifiCorp is in fact undervaluing the
capacity contribution of solar plus storage, as the analysis presented above shows, then the
Company may be overbuilding capacity resources. This is especially relevant for the P03 early
coal retirement cases since they include a more acute capacity replacement need. As such, any
assumptions that underestimate the capacity value of solar plus storage (or any other resource)
will also exacerbate the cost differential between the P02 and P03 cases. Sierra Club
recommends that the Commission require PacifiCorp to provide much more detail on its
assumptions for capacity contribution in the resource selection process, including any assumed
decline in capacity value over time.
B. PacifiCorp’s Application of a 13 Percent Hourly Reserve Margin to Individual Load Areas Is Not Fully Justified.
The 2021 IRP employed a brand-new approach to resource adequacy that differs from
past practices and also differs substantially from what utilities have traditionally done. Rather
than set a planning reserve margin targeted towards ensuring sufficient resources are available on
the whole system during the highest peak load hour, PacifiCorp has established an hourly reserve

12 PacifiCorp 2021 IRP Vol. II, App. K at 218.
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margin of 13 percent that is applied to each of 15 load areas in its system topology. In addition to
resource additions driven by the 13 percent margin, PacifiCorp also adds other resources in
subsequent steps of its analysis to ensure resource adequacy (this is addressed in more detail in
Section II(C) below).
Moving towards an approach that examines a more granular timescale for the reserve
margin may be sensible; as more variable wind and solar resources are added to the system, it is
important to consider not only the peak load hour.
However, because this is still such a novel approach, Sierra Club believes there are many
outstanding questions related to PacifiCorp’s new method that were not adequately addressed in
PacifiCorp’s IRP. In particular, Sierra Club believes there are two main issues that should be
addressed on this subject, discussed below, and Sierra Club recommends that the Commission
require updated information prior to an acknowledgment decision:
1. Reliability metrics
First it is not clear what specific reliability criteria PacifiCorp is using to determine
whether the preferred portfolio (or any of the variants and sensitivities studied) are sufficiently
reliable.
Standard industry practice would use metrics such as loss of load expectation (“LOLE”),
loss of load probability (“LOLP”), or expected unserved energy (“EUE”) as benchmarks for
reliability performance. For example, one of the most common standards used is an LOLE of
0.1/yr, which equates to an expected loss of load of one day every ten years.
However, PacifiCorp’s IRP has not provided any information on how this resource
selection process, and the subsequent portfolios, perform with respect to the reliability metrics
mentioned above. For each portfolio, PacifiCorp did provide values for the Energy Not Served
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(“ENS”) expressed as “Average Annual ENS, 2021-2040 % of Average Load.” However,
PacifiCorp did not specify what threshold for the ENS values it considered acceptable or reliable.
Going forward, Sierra Club recommends that the Commission require PacifiCorp to
define a specific reliability metric for evaluating its resource portfolios along with a specific
performance target. For example, a reasonable approach could be to define any portfolio with a
LOLE value <0.1/yr as being reliable.
2. Binding transmission limits
Second, while it was not initially clear from PacifiCorp’s IRP, Sierra Club’s
understanding is that PacifiCorp allows for capacity resources in each of PacifiCorp’s 15 load
areas to contribute towards the 13 percent reserve margin in other load areas, if there is sufficient
transmission available. While Sierra Club supports this approach, PacifiCorp has not provided
much transparency around when and where these transmission limits may become binding when
attempting to meet the 13 percent reserve margin target. This information is important for several
reasons. First, disclosure of transmission limits would allow stakeholders to assess the
reasonableness of PacifiCorp’s assumptions within its own system. Second, this information
would assist project developers in identifying the locations with the greatest need and
opportunity for development. Going forward, Sierra Club recommends that PacifiCorp provide
greater detail on when and where transmission constraints become binding (or close to binding)
as the Long Term (“LT”) capacity expansion model selects resources to fulfill the 13 percent
reserve margin requirement.
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C. PacifiCorp’s Portfolio Development Process Included a Non-Transparent Post-Modeling “Reliability Adjustment” that Lacked Adequate Supporting Data or Analysis.
As part of its core resource selection process, PacifiCorp applied a pre-modeling
“granularity adjustment” and post-modeling “reliability adjustment.” In essence, these
adjustments were made to steer the resource selection process toward a certain outcome that
would not otherwise be captured by the LT model (i.e., capacity expansion) due to its inherent
limitations. The granularity adjustment approach may be necessary for the model to ensure the
full value of resources, such as battery storage, are appropriately captured. However, in the case
of the post-modeling reliability adjustment, the lack of transparency regarding what specific
resource adjustments were actually made and why should raise red flags.
During an informal meeting between PacifiCorp and Sierra Club on November 30, 2021
PacifiCorp expressed that it made changes to the initial resource cost inputs used in the LT
model based on reliability considerations. However, after reviewing subsequent discovery
responses from the Company, it is Sierra Club’s more recent understanding that PacifiCorp did
not actually adjust resource costs to account for reliability. Instead, PacifiCorp hand-picked
additional resources on an ad hoc basis in an attempt to address any remnant reliability issues
after the initial LT model run was conducted. One example of this occurs in the P02h variant
case where Jim Bridger was retired by 2030. There, PacifiCorp manually forced in a new nuclear
plant (after Natrium) in 2030 as a “portfolio refinement” step meant to address purported
reliability concerns that the Company has not substantiated. This is a fundamental and costly
change to the portfolio that PacifiCorp made outside of the core portfolio optimization step.
Moreover, according to a discussion with PacifiCorp representatives on November 30, 2021,
PacifiCorp did not reoptimize the portfolio after taking this step. Since this additional nuclear
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resource was not added in other portfolios, and there is no supporting analysis that it will be
needed or even available, PacifiCorp may be overstating the cost of early Jim Bridger retirement.
Sierra Club is concerned that these adjustments represent an opportunity for PacifiCorp to
“put its thumb on the scale” and steer resource selection towards a desired outcome. This risk is
further exacerbated by the fact that PacifiCorp did not reoptimize the portfolio in the LT model
after making these hand-picked reliability-based adjustments.
To Sierra Club’s knowledge, PacifiCorp did not provide any data or information on the
reliability-related resource additions or corresponding analysis of the hourly resource shortfalls
in its IRP filing. However, Sierra Club did receive some of this information through follow-up
data requests. Specifically, Sierra Club requested that PacifiCorp provide any LT and Short Term
(“ST”) model workpapers as well as supporting reliability assessment workpapers for any
preliminary resource portfolios that PacifiCorp developed for the 2021 IRP, prior to applying the
granularity and reliability adjustments or any other subsequent portfolio refinements.13 In
response, PacifiCorp provided two Long Term portfolios that were run without adjustments and
used to develop the granularity and reliability adjustments:
● PLEXOS study number 3112 (P02-MMR (CO,NG) Intentional)
● PLEXOS study number 2993 (P02-MMR (CO,NG) Intl UTWY)
These preliminary portfolios were primarily used to evaluate the difference in resource value
between the LT and ST models in order to understand which resource options could produce
reliable portfolios. Although the difference between the two studies is not clearly explained,

13 PacifiCorp Response to Sierra Club Data Request 6.1 in LC 77 (included in “Attach Sierra Club 2-1”) (all public responses to Idaho and Oregon data requests referenced in these comments are provided as Sierra Club/ICL Attach. 1).
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PacifiCorp produced a set of workpapers for both studies. Each set included a workpaper for
each year from 2025 to 2040,14 detailing the hourly data of unserved energy. For the PLEXOS
3112 study, unserved energy was for half of those years while for the rest it ranged from
MW on an annual basis. For example, in year 2031, there are two hours of projected
unserved energy:15
●
●
Both shortages occur in , It is
thus possible that additional energy could be available in the system, but may be constrained in
the model; however, such details are not available in the workpapers. Results for other years are
similar with being the highest amount of unserved energy experienced in one of the
system areas in the 3112 run up until 2032. The workpapers also reveal shortages in the system’s
regulation reserves during some summer days. Sierra Club subsequently confirmed with
PacifiCorp that the same hourly data files were relied upon for assessing reliability of the P02h
variant case.16
PacifiCorp stated that “the same hourly data files already provided in response SC 6.1 for
the P02-MM case were relied upon for assessing reliability of the P02h case.” However, given
the
, it is far from clear how PacifiCorp concluded that a 500 MW nuclear addition was

14 The Confidential Attachments to PacifiCorp Response to Sierra Club Data Request 6.1 (provided in “Attach 2-2 CONF”) include workpapers for years 2026-2040 for study 2993, and 2025-2040 for study 3112. 15 Confidential Attach. “3112 Capacity Requirements P02-MMR (CO) Intl UTWY 2031 6-17-21” to PacifiCorp Response to Sierra Club Data Request 6.1 (included in “Attach 2-2 CONF”) (provided as Sierra Club/ICL Attach. 2).
16 Email from Carla Scarcella, PacifiCorp Senior Regulatory Attorney to Rose Monahan, Sierra Club (Jan. 26, 2022) (provided as Sierra Club/ICL Attach. 3)
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needed in the P02h case. Sierra Club acknowledges that this level of unserved energy
could increase with the earlier retirement of Jim Bridger 3 and 4, as contemplated in the P02h
variant case. However, PacifiCorp has not produced sufficient hourly generation data to show
when Jim Bridger will be operating in 2031, nor has it provided evidence that the unserved
energy would reach such high levels that a nuclear plant was the only viable replacement
resource. Without having additional information on the unserved energy if Jim Bridger 3 and 4
retired in 2030, any resource additions seem subjective and not the result of proper analysis.
In sum, although PacifiCorp has indicated that the nuclear resources were the best fit for
replacing Jim Bridger, because they are long duration resources that can “run around the
clock[,]”17 PacifiCorp has not provided any evidence that an extremely high cost and unproven
resource was the best fit for replacing Jim Bridger in 2030, as compared to other options such as
longer-duration batteries (e.g. 6-8 hrs) paired with renewables. In fact, it appears that PacifiCorp
limited the model’s resource selection to just nuclear or non-emitting peakers once a reliability
gap reached a certain threshold. There is no evidence that longer or larger reliability gaps can
and should be filled with—and only with—nuclear or non-emitting peakers.
Therefore, without more details, these adjustments may simply amount to a tool for
PacifiCorp to “put its thumb on the scale” and steer resource selection towards its preferred
outcome. If this is not the case, it is unclear why PacifiCorp did not provide a more thorough and
detailed explanation of this critical step in its application and accompanying workpapers.
Specifically, PacifiCorp should have provided:

17 In the Matter of PacifiCorp, d/b/a Pacific Power, 2021 Integrated Resource Plan, Docket No. LC 77, PacifiCorp Reply Comments at 17 (Ore. P.U.C. Dec. 23, 2021), available at https://edocs.puc.state.or.us/efdocs/HAC/lc77hac144535.pdf [hereinafter “LC 77 PacifiCorp Reply Comments”].
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1. A characterization of the reliability risks these adjustments are attempting to address
(i.e. timing, duration, extent and frequency of reliability risks);
2. An evaluation of the ability of all resources under consideration to address these
reliability needs; and,
3. Data on the specific resource adjustments that were made in each portfolio as part of
this “reliability adjustment” step.
Sierra Club recommends that the Commission direct PacifiCorp to provide this information for
the 2021 IRP and all future IRPs.
III. Coal Unit Economics and Plant Retirements
A. PacifiCorp Failed to Include a Unit-By-Unit Coal Analysis Consistent with the 2019 IRP.
The economics of coal generation, relative to other options, has plunged in recent years.
PacifiCorp has analyzed and disclosed the economics of coal plant retirements in previous IRP
cycles, a practice which the Company somewhat continued in the 2021 IRP cycle; but
unfortunately, it omitted important useful analyses conducted in 2019 from the 2021 IRP,
particularly the unit-by-unit analysis included in Appendix R of the 2019 IRP.18 PacifiCorp was
required to pursue this unit-by-unit analysis in 2019, but absent a clear mandate, the Company
unilaterally chose not to perform a similar analysis in 2021.
That 2019 unit-by-unit analysis was not only informative, but was a necessary component
of a portfolio-wide approach to the modeling of coal retirements. The unit-by-unit approach
provides additional information on the relative value of certain retirement decisions and also can
help serve as a “check” on the soundness of the portfolio-wide results. Given the importance of a

18 PacifiCorp, 2019 Integrated Resource Plan, Vol. II, App. R (Oct. 18, 2019), available at https://www.pacificorp.com/energy/integrated-resource-plan html [hereinafter “PacifiCorp 2019 IRP”].
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unit-by-unit analysis, it is unclear why PacifiCorp chose not to continue with this practice in this
current IRP cycle, but the 2021 IRP is less informative as a result.
Instead, for the 2021 IRP, PacifiCorp’s analysis only identified the most economic coal
retirement dates through “endogenous” portfolio-wide modeling. The results of this endogenous
selection process are similar to those in the 2019 IRP with the retirement dates left the same, or
accelerated by a couple of years. The results also show that it is most economic to retire many of
the Company’s coal units prior to 2030, which is what PacifiCorp proposes in its Preferred
Portfolio. Importantly, however, there are a handful of coal units that do not follow this pattern
and instead remain in PacifiCorp’s Preferred Portfolio through the late 2030s and early 2040s.
These late retirements include the coal units at the Hunter, Huntington, Jim Bridger, and Wyodak
plants.
This result is both concerning and counter-intuitive because some of the units with post-
2030 retirement dates are among the costliest coal units on PacifiCorp’s system on a going-
forward basis. For example, the table below shows the estimated Levelized Cost of Electricity
(“LCOE”) to continue operating each of PacifiCorp’s coal units as estimated in the 2018 Coal
Valuation Study, conducted by Energy Strategies.19 The units are ranked from highest to lowest
cost and presented alongside the 2021 IRP proposed retirement dates, with the post-2030 dates
highlighted in red.

19 Energy Strategies, PacifiCorp Coal Unit Valuation Study: A Unit-by-Unit Cost Analysis of PacifiCorp’s Coal-Fired Generation Fleet, (Sierra Club June 20, 2018), available at https://www.sierraclub.org/sites/www.sierraclub.org/files/PacifiCorp-Coal-Valuation-Study.pdf [hereinafter “PacifiCorp Coal Unit Valuation Study”].
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Sierra Club recognizes that an optimal portfolio may not show a perfect correlation
between LCOE and retirement date due to the complexities of modeling a large power system
like PacifiCorp’s. However, even when PacifiCorp did undertake a more comprehensive
modeling approach to studying coal retirements, as it did in its 2019 IRP, the Company reached a
very clear conclusion that early retirement of the Jim Bridger units would be beneficial to
customers. In fact, the company found “there are potential customer benefits from accelerating
the retirement of certain coal units, where the greatest customer benefits are associated with the
potential accelerated retirement of units at the Naughton and Jim Bridger plants located in
Wyoming.”24 The four Jim Bridger units ranked 1, 2, 5, and 6 out of all 22 coal units in terms of
potential customer benefits were they to retire early.25 The results of PacifiCorp’s 2019 IRP coal
retirement analysis from System Optimizer are shown in the table copied below.26

24 PacifiCorp 2019 IRP, Vol. II, App. R at 613.
25 Id., Vol. II, App. R at 594. 26 Id., Vol. II, App. R at 598.
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Table 2. System Optimizer Results from PacifiCorp’s 2019 IRP Coal Retirement Analysis

Given the 2019 result, the prolonged retirement dates of Jim Bridger 3 and 4 (as well as
Huntington 1 and 2) in the 2021 IRP Preferred Portfolio may in fact be the result of certain
operating costs at these coal units not being accurately represented in the 2021 IRP modeling, as
well as other subjective choices in PacifiCorp’s portfolio selection process.
B. PacifiCorp Inappropriately Assumes a Significant Share of Its Future Coal Fuel Expenditures Are “Sunk Costs” in the Form of Future Take-Or-Pay Contracts. This Assumption Significantly Constrains Any Coal Retirement Analysis Since These Costs Would Never Materialize if the Plants Retired Early.
Several critical flaws are evident in the model input assumptions PacifiCorp developed
for future coal fuel supply at coal units and the associated pricing. Chief among these flaws is the
fact that PacifiCorp inappropriately assumed significant take-or-pay volumes associated with
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supplying coal to the Jim Bridger and Huntington units well into the future. Additionally,
PacifiCorp assumed incremental fuel pricing for some plants that further distorted their true cost.
1. PacifiCorp Inappropriately Assumed that Jim Bridger and Huntington are Subject to Minimum Take Requirements
PacifiCorp assumed in the PLEXOS model that a certain minimum volume of coal fuel
must be purchased in each year for each plant by either using the fuel or by paying a penalty
price for not using the fuel. This means that PacifiCorp treats the minimum take quantity as a
“sunk cost,” even though the cost would never be incurred if the plant retired. Take-or-pay
assumptions have a significant influence on both how often to run a plant and when to retire it
because the existence of a take-or -pay penalty would substantially reduce—if not eliminate—the
economic benefits of reducing fuel consumption (e.g., from retirement) at that plant.
The take or pay volumes for the Huntington and Jim Bridger plants are summarized in
the table below for years after 2022, which was developed based on the information contained in
the confidential data disk accompanying PacifiCorp’s 2021 IRP.27

27 PacifiCorp Confidential Master Assumptions BaseCase Workpaper PacifiCorp’s 2021 IRP “Scenario Master_BaseCase 20210519_CONF.xlsx,” tab “10 – Coal Cost Incrementl by Vol” (details of the take-or-pay quantities and prices) [hereinafter “Confidential Scenario Master_BaseCase Workpaper”].
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Confidential Table 3. Take-or-Pay Volumes (in Millions of Tons) Assumed by PacifiCorp in PLEXOS for Future Years at the Huntington and Jim Bridger Plants
The large amount of assumed take-or-pay quantities is particularly problematic for the
Jim Bridger fuel sources because there is currently no contract in effect that establishes any take-
or-pay volumes after .28 PacifiCorp has yet to sign a contract for the Black Butte coal
supply for 202229 and there is no take-or-pay penalty associated with coal from Bridger Coal
Company, which is PacifiCorp’s affiliate mine. PacifiCorp has inappropriately assumed that
future coal supply agreements to supply Jim Bridger would be required through and that
these agreements would contain provisions corresponding to its assumed minimum take
volumes, without providing any supporting information.

28 Confidential Attach. to PacifiCorp Response to Sierra Club Data Request 4.2 in LC 77 (included in “Attach 2-2 CONF”) (provided as Sierra Club/ICL Attach. 4).
29 In the Matter of the Application of PacifiCorp (U 901 E) for Approval of its 2022 Energy Cost Adjustment Clause and Greenhouse Gas-Related Forecast and Reconciliation of Costs and Revenue, Proceeding No. A.21-08-004, PacifiCorp (U 901 E) Brief Summary of Dates that Existing Coal Supply Agreements Are Scheduled for Renewal (Nov. 10, 2021), available at https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M425/K516/425516818.PDF.
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Sierra Club understands that for the Jim Bridger plant, PacifiCorp did not assume that it
would incur any take-or-pay penalties after the plant retired. In other words, if Jim Bridger was
retired in 2030, it would not incur take-or-pay penalties after that date. While this is an
appropriate assumption, PacifiCorp has provided no justification for nevertheless assuming that
it would have minimum take requirements for each year that Jim Bridger operates prior to
retirement. By assuming that Jim Bridger will be subject to minimum-take requirements in the
years before it is retired, PacifiCorp skewed the model toward (1) projecting artificially high
capacity factors at Jim Bridger and (2) potentially delaying the identified optimal retirement date.
PacifiCorp asserts that it is appropriate to assume that minimum take requirements will
apply if Jim Bridger is operating because the “IRP modeling is intended to reasonably represent
the constraints and operating parameters faced by each resource” and take-or-pay contracts are
“consistent with many of the Company’s existing obligations and comparable structures are
likely in future coal supply procurement.”30 PacifiCorp ignores, however, that as the owner and
operator of the Bridger mine, which primarily supplies the Jim Bridger plant, the Company has
complete control over production levels at the mine. Accordingly, any “minimum take” at the
Bridger mine is set by PacifiCorp itself. Even assuming that the Bridger mine requires some base
level of production to justify continued operations, PacifiCorp admitted during a public
workshop with the Oregon Public Utilities Commission that it did not evaluate an optimal supply
from the Bridger mine because the Company “didn’t have time to address all that.”31 Instead,
the Company used a single supply scenario from the Bridger mine without evaluating any lower
production.

30 LC 77 PacifiCorp Reply Comments at 22-23.
31 LC 77, Ore. Pub. Util. Comm’n, PAC 2021 IRP Commission workshop video recording at 2:43:51-2:44:26 (MacNeil, PacifiCorp) (Jan. 13, 2022), available at https://www.oregon.gov/puc/news-events/Pages/default.aspx.
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Not only are PacifiCorp’s assumptions entirely inappropriate, but they are also at odds
with its own position in recent fuel-cost recovery proceedings. For instance, in PacifiCorp’s most
recent fuel cost proceeding in Oregon, the Company said that the volume of coal can and should
be evaluated and adjusted over a multiyear period within the IRP process. Specifically,
“[c]hanges in BCC mine plans and staffing levels need to be evaluated in multiyear evaluations
such as PacifiCorp's IRP and not in a one-year filing like the [Oregon fuel proceeding].”32
Instead, PacifiCorp has taken the same approach in the IRP as its fuel proceeding modeling: the
Company assumes minimum coal consumption levels throughout the planning period.
Even if one were to presume that new Coal Supply Agreements (“CSA”) should be
executed in the future, the volumes PacifiCorp has assumed do not have any clear rationale or
justification in the IRP. For example, the Jim Bridger Black Butte take or pay volume is assumed
to increase from tons in 2023-2030 to tons in 2031-2037, even as Jim
Bridger’s coal-fired output will decline.
In sum, PacifiCorp treats a large share of the coal fuel costs at Jim Bridger as a “sunk
cost” in its modeling for all years the plant is online, even though these costs have not yet been
incurred and might never be incurred. This means that PacifiCorp’s analysis ignored a substantial
portion of the fuel cost savings that would arise from dispatching Jim Bridger at lower capacity
factors and may also have skewed the findings of the optimal plant retirement date. By skewing
the output of Jim Bridger to be higher than necessary, PacifiCorp is also reducing the model’s
selection of other resource additions that could provide energy at a lower cost. Importantly,
customers pay for PacifiCorp’s self-dealing with the mine it owns and controls.

32 In the Matter of PacifiCorp, dba Pacific Power, 2022 Transition Adjustment Mechanism, Dkt No. UE 390, Surrebuttal Testimony of Dana M. Ralston on Behalf of PacifiCorp (PAC/1200) at Ralston/32:15-16 (Ore. P.U.C. Aug. 2021) [hereinafter “PAC/1200”] (excerpt provided as Sierra Club/ICL Attach. 5).
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2. PacifiCorp’s Coal Fuel Pricing Tier Assumptions Lack Any Clear Explanation or Justification
In addition to assuming that a large volume of PacifiCorp’s coal fuel supply is subject to
take-or-pay agreements, PacifiCorp also makes additional assumptions regarding the incremental
pricing (i.e., marginal cost) for volumes of coal fuel above the take-or-pay minimum volumes. In
doing so, PacifiCorp developed a set of tiered coal prices at each plant. However, the tier
volumes and their corresponding prices are not explained or justified in the IRP.
In most instances, the incremental fuel costs at the Jim Bridger and Huntington plants
appear to be substantially lower than the average cost of the take-or-pay volume tier. For
example, at Jim Bridger from , any coal consumed just above the take-or-pay
minimum is assumed to cost percent less in $/MMBtu than the take-or-pay volume tier.33
The steep drop-off in the assumed price of coal for volumes above the take-or-pay
threshold (in conjunction with the take-or-pay penalties) is an inappropriate assumption that is
causing PacifiCorp’s model to overvalue coal at the expense of other resources. In other words,
if PacifiCorp set the incremental cost of coal fuel artificially low, and it set the cost substantially
lower than the average cost of coal fuel, then the planning model is likely to dispatch coal
excessively over time. This will have the consequence of crowding out other resource additions
which might otherwise be economically selected—particularly those with high energy value,
such as high-capacity factor wind resources.
In other proceedings, PacifiCorp has indicated that it would not use incremental pricing
in its IRP because the average cost of coal fuel should be used to govern long-term planning
decisions, rather than some lower incremental price assumptions. For instance, in the Company’s

33 Calculation based on Confidential Scenario Master_BaseCase Workpaper.
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2021 ECAC (which is the California fuel cost recovery proceeding), the Company testified that:
“The Company's IRP uses a 20-year planning horizon and considers the average coal fuel cost in
its dispatch commitment.”34 Based on that testimony, Sierra Club was surprised to learn that
PacifiCorp is using an incremental pricing approach in the 2021 IRP with incremental fuel costs
that are significantly lower than the average cost.
C. A Sensitivity Model Run Removing Minimum Take Requirements at Jim Bridger Yielded Significant Benefits and Should be Considered in Place of the Preferred Portfolio
In PacifiCorp’s 2021 IRP filing in Oregon, PacifiCorp agreed to produce a new
sensitivity model run on behalf of Oregon Staff removing minimum take requirements at Jim
Bridger and allowing PLEXOS to consider retirement dates for Jim Bridger every two years.35 In
anticipation of these modeling results, Oregon Administrative Law Judges (“ALJs”) issued
several bench requests.36 On March 3, 2022, PacifiCorp produced the results of this “No
Minimum Scenario” as well as its responses to the ALJs’ bench requests pertaining to that
modeling.37
The results are striking: compared to PacifiCorp’s preferred portfolio, annual generation
at Jim Bridger Units 3 and 4 is reduced by percent, on average, between 2022 and 2037. After
2030, there is output from the plant. If adopted, the No Minimum Scenario

34 In the Matter of the Application of PacifiCorp (U 901-E) for Approval of its 2021 Energy Cost Adjustment Clause and Greenhouse Gas-Related Forecast and Reconciliation of Costs and Revenue, Docket No. A.20-08-002, Rebuttal
Testimony of David G. Webb on Behalf of PacifiCorp (PAC/800) at Webb/9:16-17 (May 2021), available at https://docs.cpuc.ca.gov/PublishedDocs/SupDoc/A2008002/3651/385112433.pdf (emphasis added). 35 LC-77 PacifiCorp Reply Comments at 61-62. 36 In the Matter of PacifiCorp, d/b/a Pacific Power, 2021 Integrated Resource Plan, Docket. No. LC-77, Bench Request (Ore. P.U.C. Feb. 17, 2022), available at https://edocs.puc.state.or.us/efdocs/HDA/lc77hda13425.pdf. 37 In the Matter of PacifiCorp, d/b/a Pacific Power, 2021 Integrated Resource Plan, Docket. No. LC-77, PacifiCorp Response to ALJ Bench Requests 1 through 7 (Ore. P.U.C. Mar. 3, 2022), available at https://edocs.puc.state.or.us/efdocs/HAC/lc77hac15285.pdf.
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would be substantially better for PacifiCorp customers than the IRP preferred portfolio, reducing
the PVRR by $156 million.
The significant difference in generation between the No Minimum Scenario and
PacifiCorp’s IRP Preferred Portfolio are illustrated in the confidential chart below.
Confidential Figure 1. Jim Bridger Units 3 and 4 Generation Under the Preferred Portfolio and the No Minimum Scenario
1. The No Minimum Scenario Indicates that Jim Bridger Could Potentially be
Fueled Exclusively by the Bridger Mine
In its response to the Oregon ALJs’ Bench Request, PacifiCorp claims that the $156
million (PVRR) benefit would be offset by the need to retrofit the plant to process coal from the
Powder River Basin (“PBR”), to the tune of $ (PVRR).38 PacifiCorp’s claim that this
PRB coal processing facility is needed rests on the idea that PacifiCorp would need to resort to
PRB coal fuel in the event that take or pay provisions were not executed with its current
38 Confidential PacifiCorp Response to ALJ Bench Request 1 (included in “Attach Sierra Club 3-2 CONF”)
(provided as Sierra Club/ICL Attach. 6).
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suppliers (i.e., Black Butte, and BCC).39 The Company claims that it would be “unrealistic” for
its current suppliers to deliver significantly lower volumes of coal absent such take or pay
provision.40 The Commission should be highly skeptical of these claims for the reasons
explained below.
To begin, it is not evident that any long-term coal supply agreements with minimum take
obligations are actually necessary to meet the fueling requirements of Jim Bridger under the No
Minimum Scenario. Based on the results provided in the confidential attachment to ALJ Bench
Request 1-1, Sierra Club estimates that only MMBtu (or tons) of coal
are needed in total to supply Jim Bridger units 3 and 4 from 2022 through 2037. This is
approximately what PacifiCorp projected to mine from BCC alone over
.41 Thus, it is conceivable that PacifiCorp could continue BCC mine production for
at current production levels and produce enough coal to operate Jim Bridger through
2037 under the No Minimum Scenario. This would avoid the need to enter any long-term
contracts with minimum take obligations.
While Sierra Club has had insufficient time to fully probe PacifiCorp’s ability to
stockpile tons of coal between both the BCC and Jim Bridger facilities, in response to
a data request submitted in the Oregon 2021 IRP proceeding, PacifiCorp indicated that “BCC’s
maximum live stockpiled coal storage is 675,000 tons and the maximum seals stockpiled coal
39 In the Matter of PacifiCorp, d/b/a Pacific Power, 2021 Integrated Resource Plan, Docket. No. LC-77, PacifiCorp Response to ALJ Bench Requests 1 (Ore. P.U.C. Mar. 3, 2022), available at https://edocs.puc.state.or.us/efdocs/HAC/lc77hac15285.pdf. 40 Id. 41 PacifiCorp Will Close Jim Bridger Longwall Mine in November, Coal Age (Sept. 23, 2021), available at
https://www.coalage.com/breaking-news/pacificorp-will-close-jim-bridger-longwall-mine-in-november/ (noting that the BCC surface mine produced 1.5 million tons in 2020 and the underground mine produced 1.4 million within the first nine months of 2021).
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storage is 1,900,000 tons.”42 At the Jim Bridger plant, “coal stockpile inventory [is limited] to a
maximum of 1.5 million tons of coal at any one time.”43 This means total capacity between the
BCC mine and the Jim Bridger plant is currently just over four million tons. PacifiCorp further
indicated that, in principle, the stockpile capacity could be increased at both locations, although
PacifiCorp would need to seek modified air quality permits.44 Thus, it is possible that
PacifiCorp could mine coal from BCC for years, holding the coal in stockpile. Even if
the maximum storage capability is no higher than approximately four million tons, PacifiCorp
could conceivably stop BCC mining after and still have enough coal to meet the
fueling requirements of the No Minimum Scenario. Neither of these scenarios would rely upon
any future coal from Black Butte.
As is apparent, these findings also call into question the need for PacifiCorp to execute a
new contract with the Black Butte mine—particularly one with a minimum take provision.
Moreover, the ability for BCC alone to meet Jim Bridger’s needs through 2037 also suggests that
the PRB coal processing investment is not necessary and should not be viewed as an offsetting
factor in the $156 million PVRR benefit of the No Minimum Scenario.
2. The No Minimum Scenario Supports Retirement of Jim Bridger Units 3 and 4 Prior to 2037
The No Minimum Scenario supports retirement of Jim Bridger Units 3 and 4 no later than
, and potentially as early as .
First, it is readily apparent from the results provided in the confidential attachment to
ALJ Bench Request 1-1 that the Jim Bridger plant provides energy value in any year

42 Sierra Club/ICL Attach. 1 PacifiCorp Response to Sierra Club Data Request 9.1 in LC 77.
43 Id. 44 Id.
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after 2030. In fact, the hourly dispatch results provided in confidential attachment ALJ Bench
Request 1-4 show that Jim Bridger 3 is
Meanwhile, Jim Bridger 4

.45
Second, generation patterns for the two units as presented in the workpapers also raise
additional questions about the model results relative to the units’ technical constraints.46 For
example, the finding that Jim Bridger Unit 3 operates for only hours in 2037 does not seem
to match the PLEXOS inputs provided in the Company’s original filing which included a
minimum uptime significantly longer than hours.47 A similar mismatch occurs for Jim
Bridger 4. This suggests that perhaps different modeling assumptions were applied in the 2037
timeframe simply to justify PacifiCorp’s preferred plant retirement date.
Third, the results of the No Minimum Scenario show that the long-term (“LT”) model,
which PacifiCorp uses for making resource retirement decisions, assumed a level of
dispatch from Jim Bridger than did the more temporally granular short-term (“ST”) PLEXOS
model which includes hourly dispatch. In fact, the LT model for the No Minimum Scenario
assumes that Jim Bridger dispatch would actually
while the ST model shows
45 “Attach ALJ Bench Request 1-4 CONF.zip\JB34 Hourly Reserve Provision ST 48540 CONF” to PacifiCorp Response to ALJ Bench Request 1 (included in “Attach Sierra Club 3-2 CONF”) (the two confidential Bench Request Attachments 1-4 are provided as Sierra Club/ICL Attach. 7). 46 Sierra Club/ICL Attach. 7, “Attach ALJ Bench Request 1-4 CONF.zip\JB34 Hourly Generation ST 48540 CONF.” 47 Confidential Plexos Inputs Workpaper accompanying PacifiCorp’s 2021 IRP “Plexos Inputs - 2021 IRP
091021_CONF.xlsx.”
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.48 This suggests that the LT model is likely
in PacifiCorp’s portfolio. Because the LT model is where resource retirement
decisions are made, it is possible that this LT model run may contain systemic biases that inflate
Jim Bridger’s value thereby delaying Jim Bridger’s retirement relative to the value demonstrated
in the more granular ST model. Indeed, the No Minimum Scenario results suggest that the
minimum take constraints may not have been removed from the LT model, but rather only
removed from the ST model. Because of the limited time between receiving the modeling results
and submitting these comments, Sierra Club was unable to confirm this hypothesis; however, it
is supported by the fact that when comparing the annual generation output from the LT model of
the No Minimum Scenario to the LT model of PacifiCorp’s Preferred Portfolio, the two
scenarios are virtually identical as shown in the table below:
48 Confidential Attach. “OR LC-77 Attach ALJ Bench Request 1-1 CONF” to PacifiCorp Response to ALJ Bench
Request 1 (included in Attach Sierra Club 3-2 CONF) (provided as Sierra Club/ICL Attach. 8).
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Confidential Table 4. Jim Bridger Generation Output from the LT Model
No
Minimum MM-
CETA

If the minimum take constraints were not actually removed from the LT model, then the
Commission should be highly skeptical of PacifiCorp’s assertion that PLEXOS continues to
select Jim Bridger Units 3 and 4 to run on coal through 2037.49
49 PacifiCorp Response to ALJ Bench Request 1 (“PLEXOS LT optimization of the P02-MM study continues to select Jim Bridger Unit 3 and Jim Bridger Unit 4 to run on coal and generate energy through the existing end-of-life in 2037”).
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Sierra Club recommends that in future IRPs, the Company fully explain any
discrepancies between the LT and ST models, including potential implications for coal
retirement dates.
Finally, the fact that Jim Bridger raises significant
questions about the plant’s reliability value and the need to keep this resource online for
reliability purposes. PacifiCorp’s results suggest that Jim Bridger provides some incremental
reliability value in 2037. However, this is challenged by the fact that Jim Bridger Unit 3 is
projected to
. This finding also challenges the notion that a 500 MW nuclear resource would be needed
as a replacement, which is what PacifiCorp has recommended in both its preferred case and the
P02h variant, discussed below.
Accordingly, in contrast to PacifiCorp’s assertions that the No Minimum Scenario
supports operating Jim Bridger 3 and 4 through 2037, a more reasonable interpretation of the
sensitivity is that Jim Bridger 3 and 4 should retire no later than , and potentially as early as
.
3. The No Minimum Scenario–If Selected–Would Impact the Near-Term Action Plan and Upcoming All Source RFP
The No Minimum Scenario shows substantially reduced output at Units 3 and 4 in all
years beginning . As the chart above shows, the discrepancy between Jim Bridger
generation in the preferred portfolio and the No Minimum Scenario becomes most pronounced
beginning in , meaning that if the No Minimum Scenario were to become the preferred
portfolio, the near-term action plan and the upcoming All Source RFP would be significantly
impacted. While the Idaho Commission does not have a formal process for RFPs like some of
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PacifiCorp’s other jurisdictions, PacifiCorp’s RFP will impact available resources for Idaho in
the coming years.
PacifiCorp’s response to the Oregon ALJs’ Bench Request did not provide details on
specific resource additions in the No Minimum Scenario. However, Sierra Club estimates that
reducing Jim Bridger’s output under this scenario could equate to replacement energy on the
order of over MW of new wind in the 2025-2030 timeframe. Thus, a significant amount of
additional new renewable resources would likely be needed under the No Minimum Scenario but
would not otherwise be procured if PacifiCorp’s preferred portfolio is pursued instead. Sierra
Club recommends that such incremental resources be considered within the upcoming All Source
RFP.
D. A Sensitivity Model Run Removing Huntington’s Minimum Take Assumptions Was Not Preformed, but Should be Required in Future IRPs
Just as take-or-pay assumptions for the Jim Bridger plant have a significant impact on the
final portfolio, Huntington’s assumed minimum take (through 2029) is also likely to have a
significant impact. Using the information from PacifiCorp’s input data files, Sierra Club
estimates that the costs associated with the Huntington take-or-pay costs between 2023 and 2037
amount to $ (PVRR).50 In other words, there is a significant amount of fuel cost
savings PacifiCorp's model could potentially realize if these future take-or-pay provisions could
be avoided and output at Huntington was reduced, either due to early retirement or lower
dispatch.
Although PacifiCorp’s current CSA at Huntington extends through 2029, PacifiCorp’s
analysis presumes that no events have transpired, or will transpire, that could trigger a reopener
50 Calculation based on Confidential Scenario Master_BaseCase Workpaper.
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clause in the Huntington CSA. However, the Huntington CSA contains a “environmental
regulations” provision51 under which the Company can avoid minimum take requirements if
changes in environmental laws implicating the Huntington plant make continued operations
uneconomic.52 Stakeholders in Oregon, such as the Oregon Citizens Utility Board and the
Oregon Commission Staff, have already questioned whether current environmental laws and
regulations would be enough to trigger this provision, although PacifiCorp has disagreed.53
However, environmental controls required under the Clean Air Act’s Regional Haze
requirements would undoubtedly constitute the type of “environmental regulations”
contemplated by the Huntington coal contract. Currently, an SCR requirement at the Huntington
plant remains under Clean Air Act litigation and could foreseeably be reimposed. Huntington
may also be subject to additional environmental controls under the Regional Haze program’s
“Round 2” rulemaking, as the plant currently has no pollution controls whatsoever for nitrogen
oxide (“NOx”). Utah’s state implementation plan (“SIP”) for Regional Haze “Round 2” is
expected in July 2022, with EPA acting upon that SIP shortly thereafter. Environmental controls
required under the Regional Haze rulemaking are further discussed in Section III(E). Regardless
of any environmental regulatory changes, the Oregon Public Utilities Commission has already
directed PacifiCorp to “thoroughly explore the costs and benefits of contract termination or
renegotiation . . . .”54 Accordingly, PacifiCorp should have modeled a sensitivity case where the
current CSA at Huntington was either nullified or renegotiated.

51 Sierra Club/ICL Attach. 5, UE 390, PAC/1200 at Ralston/12:14-13:11 (describing Huntington CSA environmental regulations provision).
52 Id. 53 Id.
54 In the Matter of PacifiCorp, dba Pacific Power, 2022 Transition Adjustment Mechanism, Docket No. UE 390, Order No. 21-397 at 23 (Nov. 1, 2021), available at https://apps.puc.state.or.us/orders/2021ords/21-379.pdf.
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In conclusion, Sierra Club recommends that the Commission direct PacifiCorp to produce
the No Minimum Scenario sensitivity and provide an opportunity for stakeholder comment prior
to any acknowledgment decision. This modeling should become standard practice in all future
IRPs and further also remove minimum take requirements at Huntington after a certain date (e.g.,
2025).
E. The P02h Variant Case (Jim Bridger Units 3 and 4 Early Retirement) Is Lower in Cost than PacifiCorp’s Preferred Portfolio (P02-MM-CETA). This Is True Despite Questionable Assumptions that Needlessly Inflate the Cost of the P02h Variant Case.
As shown above, Sierra Club has significant concerns over the late retirement dates of
some of PacifiCorp’s coal units, particularly Jim Bridger. This concern is underscored by not
only the No Minimum Scenario discussed above but also PacifiCorp’s own analysis of the P02h
variant case, which shows a risk-adjusted PVRR of $26,240 million under the MM price-policy
scenario.55 This compares favorably to PacifiCorp’s Preferred Portfolio which has a PVRR of
$26,343 million,56 or about $103 million more costly than the P02h-MM case
Sierra Club recognizes that PacifiCorp made certain adjustments to the initial P02-MM-
MM portfolio to ensure that the final Preferred Portfolio (P02-MM-CETA) was compliant with
Washington’s CETA requirements. These changes added approximately $164 million in (PVRR)
costs relative to the initial P02-MM-MM portfolio.57 However, it is not clear whether the exact
same changes would also be necessary for the P02h variant to become CETA compliant. For
instance, the P02h portfolio already includes 200 MW of incremental solar plus storage relative
to P02-MM-MM, beginning in 2027.58 This is roughly equal to the 160 MW of renewable plus

55 PacifiCorp 2021 IRP Vol. I at 289, Table 9.14. 56 Id. at 291, Table 9.15.
57 Id. at 261, Table 9.1; 291, Table 9.15. 58 Id. at 287.
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storage resources that were added to create the P02-MM-CETA portfolio.59 Thus, the P02h
variant may already be largely, if not entirely, CETA compliant. Sierra Club recommends that
PacifiCorp determine what shortfall, if any, there may be in this regard. Furthermore, Sierra Club
recommends that PacifiCorp assess whether the P02h case should be considered preferable to its
Preferred Portfolio.
From a pure least-cost planning standpoint, early retirement of Jim Bridger would lead to
a more optimal portfolio and would be in PacifiCorp customers’ interest. This conclusion would
be bolstered were the take-or-pay provisions described above correctly modeled, thereby
allowing even greater fuel cost savings from an early retirement. Additionally, the P02h variant
includes a second nuclear unit (beyond Natrium) in the 2030 timeframe. According to a
discussion with PacifiCorp’s analytical team on November 30, 2021, this nuclear unit was not
economically selected in the initial stage of modeling, and was later added when PacifiCorp
decided it was necessary to address reliability issues. As discussed above, from the reliability
data provided to Sierra Club that led to its decision to add the second nuclear unit, it appears that
PacifiCorp evaluated an extremely narrow range of alternatives and it is far from clear that a
nuclear plant was the best fit to meet the identified reliability gap. If a less costly set of resources
could address the same reliability needs this nuclear addition was meant to cover, then it is
conceivable the early retirement of Jim Bridger would be even more cost effective, potentially on
the order of hundreds of millions of dollars (in PVRR terms), than what PacifiCorp reported in
the IRP. PacifiCorp’s ad hoc approach to addressing reliability concerns by adding resources
through post-modeling “portfolio refinements,” such as this nuclear unit addition, is discussed
more thoroughly above in Section II(C).

59 Id. at 290.
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F. PacifiCorp’s IRP Did Not Fully Assess the Risks Associated with the Early Exit of its Coal Plant Co-Owners.
One important consideration regarding PacifiCorp’s continued operation of certain coal
plants is how its actions align with the actions of facility co-owners. PacifiCorp has accelerated
its exit of Colstrip Units 3 and 4, which is consistent with Sierra Club’s understanding of the
intentions of other Pacific Northwest co-owners of the plant (e.g., Puget Sound Energy, Avista,
and Portland General Electric). However, PacifiCorp has not aligned itself with co-owners of
other plants. In particular, in an application before this Commission filed in June 2021, Idaho
Power stated its intention to exit its 33 percent share of the Jim Bridger plant by 2030 and adjust
the depreciation accounting accordingly.60 Importantly, Idaho Power’s depreciation application
did not contemplate the gas conversions PacifiCorp proposed in its IRP filing.
Since June, Idaho Power filed the 2021 IRP in which the Company plans to participate in
the gas conversions but will exit from the gas units by 2034, three years earlier than PacifiCorp’s
planned retirement in 2037.61 Additionally, Idaho Power now plans to exit Jim Bridger Units 3
and 4 earlier than previously stated: by 2025 and 2028.62 Whether Idaho Power’s interest in Jim
Bridger Units 1 and 2 continues past 2034 or in Units 3 and 4 continues past 2028 has significant
implications for PacifiCorp’s assumptions in the 2021 IRP regarding the cost to continue
operating the plant long term. Some of the considerations are:
1. PacifiCorp should be clear on who would ultimately take ownership of Idaho Power’s
share of the Jim Bridger Units 1 and 2 capacity and its associated output from 2034-

60 In the Matter of the Application of Idaho Power Company for Authority to Increase its Rates for Electric Service
Costs Associated with the Jim Bridger Power Plant, Docket No. IPC-E-21-17, Application at 5 (June 3, 2021), available at https://puc.idaho.gov/Fileroom/PublicFiles/ELEC/IPC/IPCE2117/CaseFiles/20210603Application.pdf [hereinafter “IPC Application”]. 61 Idaho Power Company, 2021 Integrated Resource Plan at 152-153 (December, 2021) available at https://puc.idaho.gov/Case/Details/6793 [hereinafter “Idaho Power 2021 IRP”]. 62 Id. (indicating that all gas will come off Idaho Power’s system by 2034 and all coal by 2028).
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2037 and Units 3 and 4 capacity and associated output from 2025-2037. If PacifiCorp
were to ultimately acquire or otherwise maintain control of Idaho Power’s portion of
the Jim Bridger plant, the Company should provide these acquisition costs and any
sensitivities around them in the IRP.
2. If there are no parties interested in acquiring Idaho Power’s ownership share, then
PacifiCorp would still need to find a way to cover the associated operating and
maintenance costs as well as incremental capital costs for major overhauls expected
in 2032, 2033, 2034, and 2035. These additional costs are not adequately assessed in
the IRP.
3. PacifiCorp would also be responsible for all decommissioning and remediation costs
incurred after Idaho Power’s exit in the 2028-2034 timeframe. PacifiCorp has not
included those additional costs in its analysis.
The IRP does not address these major developments with Idaho Power and what they
would mean for continued operation of Jim Bridger past 2028. In response to a discovery request
asking whether PacifiCorp expects a third-party to assume ownership of Idaho Power’s share, the
Company simply stated: “PacifiCorp has not made any assumptions regarding whether or how
Idaho Power Company (IPC) will handle its property.”63 At the very least, the Company could,
and should, have explored sensitivities regarding whether PacifiCorp or a third party would
assume ownership of Idaho Power’s share of the plant.

63 Sierra Club/ICL Attach.1, PacifiCorp Response to Sierra Club Data Request 3.2(a) in LC 77 (included in “Attach Sierra Club 2-1”).
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G. PacifiCorp’s IRP Failed to Evaluate a Feasible Scenario in Which EPA Requires SCR Installations to Comply with the Clean Air Act.
As PacifiCorp's 2021 IRP described in great detail, the Company’s coal plants must meet
certain requirements to comply with the EPA’s Regional Haze Rule. This matter is especially
relevant for PacifiCorp’s Utah coal plants, Hunter and Huntington.
In recent years the regional haze requirements in Utah have been hotly contested. In June
2016, EPA issued a final rule (“2016 FIP”) requiring PacifiCorp to retrofit Hunter Units 1 and 2
and Huntington Units 1 and 2 with SCRs by August 4, 2021. The Trump administration
withdrew the 2016 FIP and replaced it with a FIP that required no controls whatsoever at the four
BART units. In response, Sierra Club and other organizations filed a petition in the Court of
Appeals for the Tenth Circuit challenging the Trump FIP. That appeal is pending.
Outside of Utah, other plants are subject to SCR requirements to meet regional haze
requirements, including Jim Bridger Units 1 and 2 and Wyodak. SCR installation was required at
Jim Bridger Unit 2 by the end of 2021, and is required at Unit 1 by the end of 2022. Although
Wyoming’s Governor issued an emergency order to allow Unit 2 to operate in violation of the
Clean Air Act through April 2022, the federal EPA has recently announced that it intends to
maintain the SCR requirements on both units.64 Despite PacifiCorp having to comply with the
Clean Air Act’s regional haze rule at some point, it steadfastly refuses to take this risk seriously,
and chose to omit this very real possibility in its IRP analysis, even as a sensitivity case.
PacifiCorp’s malfeasance not only threatens significant harm to the reliability of the grid, to
workers at the Jim Bridger plant, and public health in Idaho and other states but violates this

64 87 Fed. Reg. 2571 (Jan. 18, 2022), available at https://www.govinfo.gov/content/pkg/FR-2022-01-18/pdf/2022-00777.pdf. Since the federal EPA issued this notice, PacifiCorp and the State of Wyoming entered into a consent decree which would allow PacifiCorp to avoid installation of SCRs at Jim Bridger units 1 and 2. However, the EPA was not a party to this consent decree and has not acquiesced to its terms. Accordingly, the private agreement between PacifiCorp and Wyoming has no impact on federal requirements.
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Commission’s IRP guidelines, which require consideration of the effects of “known or potential
changes to existing resources” and recognition of “contingencies for upgrading . . . resources . . .
as future events unfold”.65
To put the potential impact in perspective, Strategen considered the cost of installing
SCRs at each of the coal plants mentioned above. Based on the values reported in Energy
Strategies’ 2018 PacifiCorp Coal Unit Valuation Study,66 the incremental cost of these
environmental controls could be on the order of $753 million in NPV terms as shown in the
following table.
Table 5. Net Present Value for Coal Plants With and Without SCRs
Without SCR With SCR Difference
Hunter 1 $ 1,263 $ 1,402 $ 139
Hunter 2 $ 849 $ 913 $ 64
Huntington 1 $ 1,510 $ 1,470 $ 149
Huntington 2 $ 1,321 $ 1,386 $145
Jim Bridger 1 $ 1,241 $ 791 $ 80
Jim Bridger 2 $ 711 $ 912 $ 88
Wyodak $ 824 $ 910 $ 88
Total $ 753
For comparison, the difference between the P02-MM Preferred Portfolio and the P03-MM Early
Retirement Portfolio, which retired all of PacifiCorp’s coal plants by 2030, is $1,697 million
(risk adjusted),67 meaning that a $753 million increase in the PVRR equates to more than 44
percent of this difference. In other words, if SCR-related costs are ultimately required but
PacifiCorp could avoid these costs through early retirement, then the difference in costs between

65 See In the Matter of the Investigation by the Idaho Public Utilities Commission into Idaho Electric Utility Conservation Standards and Practices, Docket U-1500-165, Order No. 22299, (1989).
66 PacifiCorp Coal Unit Valuation Study. 67 PacifiCorp 2021 IRP Vol. I at 261, Table 9.1.
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the P02 and P03 cases becomes much smaller in magnitude. In fact, using PacifiCorp’s own IRP
analysis as a starting point, Sierra Club estimates the impact of early coal retirement in terms of
total PVRR increase could be as little as three percent (versus six percent if SCRs are not
considered). Under the high gas price scenario (HH), this difference declines even further and
could be as little as <1 percent, meaning the cost difference between the P02 case if SCRs are
required and the P03 case could be almost negligible. This is especially relevant in light of the
recent and dramatic increase in gas prices, which shows that the HH scenario may be closer to
reality than the MM scenario.
In summary, SCR requirements will at some point be required under the Clean Air Act.
At that time, the early retirement case becomes roughly equivalent from an economic standpoint
to the current preferred case, depending on the price-policy scenario.
H. PacifiCorp’s P03 Early Coal Retirement Case Is Misleading on Increased Costs (Relative to the Preferred Portfolio), as These Increases Are Partly Driven by Deficiencies and Subjective Choices in the Company’s Modeling Methodology.
To assess the potential for early retirement of the entire coal fleet, PacifiCorp created the
“P03” cases that optimize coal unit retirement by 2030.68 Overall, PacifiCorp’s IRP analysis
finds that the P03 early coal retirement cases are costlier than the P02 cases. One exception
occurs when the true social cost of carbon is applied. Under that price-policy assumption, the
P03 case is the least cost option from a PVRR perspective.69
Importantly, even when a social cost of carbon is not applied, PacifiCorp’s analysis could
be exaggerating or overestimating how early retirements under the P03 cases would drive higher
costs relative to the P02 cases. Instead of early retirements being the key driver of these costs, a

68 PacifiCorp 2021 IRP Vol. I at 248. 69 Id. at 262.
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large portion of the higher P03 costs may simply arise from methodological choices PacifiCorp
has made that bias replacement resource selection towards a costlier portfolio than necessary.
One such methodological choice was PacifiCorp’s overly restrictive decision on the types
of potential replacement resource options it considered in the IRP selection process. For
example, the main difference in incremental capacity between the P02-MM and P03-MM cases
through 2030 is two resources: 1) solar plus storage and 2) non-emitting peakers. It is evident
from the model assumptions and model results that the non-emitting peakers are a relatively
expensive resource to build and operate (i.e., ~$374/MWh levelized cost using PacifiCorp’s
assumptions)70 and their inclusion may be one of the driving factors of the higher P03 costs.
Since gas additions are excluded (aside from the Bridger conversions), it appears that the
primary options for resources with high capacity value are limited mainly to the non-emitting
peaker and nuclear additions, both of which are expensive. Indeed, both nuclear and non-
emitting peaker additions feature prominently in the variant analyses and are often the main
drivers of cost differences between the variants and the base case.
Through informal discussions, PacifiCorp indicated that it views resources like the non-
emitting peakers as “placeholders” for resources that will be needed far into the future. However,
they are still assigned a cost that is included in the PVRR calculation and is evaluated on an
equal footing with nearer term resource additions. Thus, inclusion of non-emitting peakers and
nuclear plants, even as indicative “placeholders” for the distant future, can still substantially
skew the PVRR results and lead to misleading conclusions about the relative cost of portfolios
like P03-MM.

70 Id. at 183, Table 7.2.
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If PacifiCorp had instead included more resource options with high capacity value
beyond those two choices, then the results would differ substantially, and the cost differential of
the P03 cases versus the P02 cases would not be as dramatic. Some of these additional resource
options might include: 1) advanced load response measures with fewer operating limits than
traditional demand response; 2) managed EV charging and Vehicle-to-Grid flexibility 3)
offshore wind; 4) longer duration storage resources; or 5) alternative configurations for hybrid
resources (e.g., solar plus battery storage with five- or six-hour durations, versus PacifiCorp’s
identified four-hour duration).
IV. PacifiCorp’s Expectation that it Will Receive Power from the Natrium Plant, a Novel Nuclear Technology, by 2028 Introduces Substantial Cost and Execution Risks that Were Not Adequately Addressed in the IRP.
PacifiCorp’s analysis of the Natrium advanced nuclear reactor raises numerous concerns.
First, and most significantly, PacifiCorp has stated on numerous occasions that the Natrium
nuclear plant was “exogenously” included in the model, a fancy way of saying that it was not
economically selected by the model. By definition, this means that removing the Natrium unit
should lead to a lower overall portfolio cost. However, the variant case where Natrium was
excluded (P02e) leads to an increase in portfolio costs. This presents a logical inconsistency that
would only make sense if PacifiCorp were applying other changes to the variant case. Given
these discrepancies, PacifiCorp should provide a more detailed explanation of how Natrium can
be both economic and non-economic.
Second, PacifiCorp has failed to meaningfully evaluate the various risks surrounding an
untested, highly controversial energy source, including Natrium’s permitting, regulatory,
financial, operational, environmental, and technical risks. PacifiCorp has either downplayed or
failed to acknowledge each of these. This lack of information and the absence of rigorous
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analysis for a new, untested technology should cause the Commission significant pause, and
ultimately result in a non-acknowledgement.
To begin, the Natrium project faces significant regulatory hurdles. The Company
acknowledged that Natrium is “a first of a kind sodium fast reactor” and that there may be
Nuclear Regulatory Review “challenges.”71 Yet, when asked about the project’s permitting
requirements, PacifiCorp implied that some portion of these risk factors would essentially be
outsourced to its partner (TerraPower), saying that the Company and TerraPower “will comply
with all federal, state and local permitting requirements[,]” but “it is premature to provide an
exhaustive list of permitting requirements or timelines at this time.”72 Additionally, PacifiCorp
does not appear to have a current plan for disposal of nuclear waste. When asked about the
construction or availability of federally licensed storage facilities for nuclear waste that would be
generated from Natrium, PacifiCorp responded that it “has no further information on this topic”
but expects some, unidentified independent storage to be federally approved at some
unidentified, later date.73 The IRP omitted any potential regulatory delay or denial; instead it
assumed the Natrium plant will smoothly proceed through the regulatory process. This
assumption imposes significant risk on the entire Preferred Portfolio, as certain resource
planning decisions in the 2020s appear to hinge upon Natrium’s completion.
Next, PacifiCorp’s modeling assumes that the federal government will ultimately fund a
significant portion of total costs. Sierra Club acknowledges that the U.S. Department of Energy
has already awarded TerraPower $80 million through its advanced reactor demonstration

71 Sierra Club/ICL Attach. 1 PacifiCorp Response to Oregon Citizens’ Utility Board (“CUB”) Data Request 3 in LC 77. 72 Sierra Club/ICL Attach.1, PacifiCorp Response to Sierra Club Data Request 4.5 (included in “Attach Sierra Club 2-1”). 73 Sierra Club/ICL Attach.1, PacifiCorp Response to CUB Data Request 6 in LC 77.
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program,74 and over the next seven years, the Department plans to invest a total of $3.2 billion in
this program, with industry partners providing matching funds.75 While these are significant
sums, neither PacifiCorp nor TerraPower can guarantee that additional federal funding, in any
amount, will materialize. Federal policy can change quickly, and it is difficult to forecast
whether the Biden administration’s (or future administrations’) support for nuclear power will
remain, particularly as Russia’s war on Ukraine has already created serious and dangerous
conditions at the Chernobyl nuclear plant76 and raised concerns about attacks on other nuclear
facilities. The IRP does not contain any analysis of potential cost overruns, despite the fact that
nearly all nuclear projects in the U.S. have been plagued by astronomical cost overruns,77 or any
contingency plan in the event that the federal funding is not awarded. While there have been
assurances that TerraPower will assume the risk of cost overruns and delays,78 to date,
PacifiCorp has not presented any agreements with TerraPower to this effect or otherwise
provided any evidence that customers will be protected.
Connected, Natrium’s technical design itself raises cost concerns. Unlike past nuclear
projects, Natrium requires a highly enriched uranium, known as “high-assay low-enriched
uranium” (“HALEU”). PacifiCorp is assuming it will obtain a domestic supply for HALEU;79

74 U.S. Department of Energy Awards TerraPower $80 Million to Demonstrate Advanced Nuclear Technology, TerraPower (Oct. 13, 2020), available at https://www.terrapower.com/doe-natrium-demonstration-award/. 75 Office of Nuclear Energy, U.S. Department of Energy Announces $160 Million in First Awards under Advanced
Reactor Demonstration Program, Energy (Oct. 13, 2020), available at https://www.energy.gov/ne/articles/us-department-energy-announces-160-million-first-awards-under-advanced-reactor.
76 Henry Fountain, How the loss of power at Chernobyl could affect the nuclear disaster site, New York Times (Mar. 9, 2022), available at https://www nytimes.com/live/2022/03/09/world/ukraine-russia-war#how-losing-power-at-chernobyl-affects-operations-at-the-former-plant. 77 See, e.g., Timothy Gardner and Nichola Groom, Some U.S. Cities Turn Against First Planned Small-Scale
Nuclear Plant, Reuters (Sept. 2, 2020), available at https://www.reuters.com/article/us-usa-nuclearpower-nuscale/some-u-s-cities-turn-against-first-planned-small-scale-nuclear-plant-idUSKBN25T30E (noting that the NuScale nuclear project’s projected cost of $6.1 billion has risen from $3.1 billion in 2017). 78 Project Details, Wyoming Advanced Energy, available at https://wyomingadvancedenergy.com/project-details/ (last visited Mar. 3, 2022). 79 Sierra Club/ICL Attach.1, PacifiCorp Response to CUB Data Request 4 in LC 77.
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however, such fuel is currently only produced for commercial purposes in Russia.80 In light of
the ongoing war and humanitarian crisis in the Ukraine, increasing the United States’ energy
reliance on Russia should raise obvious concerns. Some trade press estimate that it will take at
least seven years to develop a U.S. based market.81
Fuel availability further raises questions on impacts to local, fenceline communities. For
example, the White Mesa mine in southwestern Utah, which is the only operating conventional
uranium mine in the U.S., has caused documented environmental damage to the surrounding
indigenous communities. Further development of uranium production in the U.S. to fuel plants
such as Natrium could similarly result in harmful consequences for nearby, local communities.
Yet, PacifiCorp has not considered and disclosed these issues.
Finally, operating any nuclear plant comes with significant operational risks. In addition
to having minimal information on its waste management strategy, PacifiCorp does not appear to
have begun planning to operate the plant. For example, regarding training personnel, PacifiCorp
has only indicated that it is “currently evaluating the overall strategy for operations and
maintenance.”82 Notably, the IRP does not contain any analysis evaluating the risk that the
plant—a first of its kind demonstration project that has never operated on a commercial scale—
may suffer from operational difficulties during its early years.
Sierra Club recommends first that the Commission not acknowledge any IRP planning
assumptions that rely on PacifiCorp’s unsupported assertion and the timeline, cost, and
performance of the Natrium plant. Non-acknowledgement will make clear that PacifiCorp’s

80 Matthew Bandyk, Nuclear reactors of the future have a fuel problem, Utility Dive (Aug. 30, 2021), available at https://www.utilitydive.com/news/nuclear-reactors-of-the-future-have-a-fuel-problem/604707/.
81 Id. 82 Sierra Club/ICL Attach. 1, PacifiCorp Response to CUB Data Request 9 in LC 77.
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pursuit of this unproven, risky, and expensive technology is a risk to be borne by shareholders,
not ratepayers. Additionally, the Commission should require significantly more information from
PacifiCorp concerning its nuclear plant, including:
1. A detailed explanation of how Natrium can be both non-economic (and thus requiring
hardwiring into PLEXOS) and economic (removing the Natrium plant from the
model increasing costs to the system) is essential to understanding this resource;
2. A detailed explanation of anticipated radioactive waste storage options;
3. A detailed explanation of anticipated federal, state, and local permitting requirements,
with key milestones with anticipated dates; this should also explain who is
responsible (i.e., PacifiCorp or Terrapower) for achieving licensing and permitting
milestones;
4. A detailed accounting of estimated costs, including various scenarios forecasting
potential cost overruns and lack of federal funding support;
5. Greater explanation on the plant’s anticipated fuel supply, with contingency plans if a
domestic market is not available by 2028;
6. A detailed explanation of PacifiCorp’s operating plans, including safety, worker
training, and worker transition;
7. A clarification of whether this project would be a purchase power agreement (“PPA”)
arrangement or a PacifiCorp-owned resource. If it is a PPA, PacifiCorp should
provide a detailed explanation for what protections will be in place for its customers
regarding any project denials, delays or cost overruns;
8. A contingency plan for meeting resource needs if the plant is still in the planning or
construction phase in 2028; and,
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9. A detailed explanation, with documentation, on how PacifiCorp will protect itself and
ratepayers from unforeseen cost overruns and delays.
V. Risks Related to the Jim Bridger Gas Conversion
A. Overview of PacifiCorp’s Proposed Coal-to-Gas Conversion of Jim Bridger Units 1 and 2
PacifiCorp’s planned coal-to-gas conversion at Jim Bridger Units 1 and 2 by 202483
carries significant risk that is borne almost exclusively by ratepayers. Specifically, the
Company’s overly optimistic fuel cost forecasts combined with its artificial limitation on the
types of capacity resource alternatives explains why the Company found the conversion to be
economical. In reality, the Company has not adequately explained the details of the conversion.
The Company’s analysis of the conversion’s impact on the preferred portfolio is examined in its
variant run that excluded the gas conversion.84 In its analysis, the Company concluded that the
portfolio without the conversion is $305 million on a risk adjusted basis more than the preferred
portfolio.85 The Company claims that the project is cost-effective primarily because it has low
capital costs relative to the alternative resource. But this claim does not account for the increased
fuel price risk to be borne by customers nor the lack of any approval by state and federal
regulators of the gas supply lines and air quality permits.
B. PacifiCorp’s Proposed Gas Conversion Comes with Significant Price Risk.
Historically, the price of natural gas has been linked to crude oil prices, where both
commodities’ prices rose and fell together.86 However, beginning in 2011, gas prices dropped,

83 PacifiCorp 2021 IRP Vol. I at 24.
84 Id. at 269-270, Variant P02a-JB1-2 GC. 85 Id. at 270, Table 9.7 and 291, Table 9.15 (comparing the P02a-MM no conversion portfolio to P02-MM-CETA portfolio). 86 Peter Hartley et al., The Relationship Between Crude Oil and Natural Gas Prices, James A. Baker III Inst. for Pub. Policy at 8 (Nov. 2007), available at https://www.bakerinstitute.org/media/files/Research/c4d76454/ng relationship-nov07.pdf.
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primarily due to the domestic shale fracking, and became relatively stable. A low, stable gas
price was the norm for a decade. Consequently, we saw a dramatic shift in the electric sector as
generation shifted from coal to fracked gas and then renewables.
PacifiCorp’s IRP forecast expects these low prices to continue for the entire planning
horizon. As shown in Figure 1, PacifiCorp’s forecast for Henry Hub natural gas prices begins in
April 2021 at just under $3/MMBtu, slowly rise to $4 in 2029, $5 in 2034, and ultimately top off
at just under $7/MMBtu by 2041.87
Figure 2. Historic Henry Hub Prices and PacifiCorp's IRP Natural Gas Price Forecast

However, gas prices have nearly doubled in the past year alone.88 Prices rose sharply in
February 2021 after the Texas winter storm, dropped quickly, but then immediately started a
persistent climb in March 2021 until today. Because PacifiCorp had to lock in its gas price
forecast as an input for its IRP in early 2021, we can track the Company’s forecast to actual gas

87 The most likely natural gas hub for the Jim Bridger plant is Opal, which closely mirrors Henry Hub but is usually 5-10 percent cheaper.
88 Talmon Joseph Smith, Winter Heating Bills Loom as the Next Inflation Threat, The New York Times (Nov. 8, 2021), available at https://www nytimes.com/2021/11/08/business/economy/home-heating-prices-winter html?utm source=Sailthru&utm medium=email&utm campaign=Issue:%202021-11-08%20Utility%20Dive%20Newsletter%20%5Bissue:37856%5D&utm term=Utility%20Dive.
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prices. Since April 2021, actual gas prices have significantly increased relative to the Company’s
forecast. In October 2021, the Henry Hub price for gas was $5.51/MMBtu, nearly double the
Company’s forecast of $2.84/MMBtu.
Figure 3. Henry Hub Prices Since January 2020, and PacifiCorp's Gas Price Forecast

Despite this dramatic increase in gas prices in 2021 PacifiCorp is optimistic that prices will
revert to their historic low. According to the IRP, as of June 30, 2021, gas futures show a high
price of $3.17/MMBtu, which is a “signal-to-drill” and will incent drillers to chase production
efficiency and continue to drive down prices.89 PacifiCorp continued that “[t]he North American
natural gas supply curve continues to flatten as production efficiencies expose an ever-increasing
resilient, flexible, and low-cost resource base.”90
However, there is also a real chance high prices could persist as a “new normal.” Even as
gas prices reached and then exceeded $3.17/MMBtu in 2021, rather than incentivizing drillers to

89 PacifiCorp 2021 IRP Vol. I at 44. 90 Id. at 46.
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chase production as PacifiCorp predicted, domestic fracked gas production has remained
relatively flat since November 2020.91 While gas prices remain high, and demand responds to
seasonal needs, overall U.S. gas supply has remained flat through March 2022.92
Figure 4. U.S. Natural Gas Production

The domestic and international gas markets continue to evolve. European and Asian gas prices
are higher than normal as demand outpaces supplies.93 The United States is not immune to this
global dynamic and, in fact, has much more international exposure now due to LNG expansion.94
The cost of financing new fossil fuel projects, like fracked gas wells, and the distribution system
for carrying that gas, is increasingly costly relative to alternative opportunities, like renewable

91 Monthly Crude Oil and Natural Gas Production, U.S. Energy Info. Admin. (Nov. 30, 2021), available at https://www.eia.gov/petroleum/production/#ng-tab. The drop in February 2021 was caused by the Texas Winter Storm.
92 Natural Gas Weekly Update, U.S. Energy Info. Admin. (March 3, 2022), available at https://www.eia.gov/naturalgas/weekly/#tabs-supply-3.
93 Frederico Carita, LevelTen Energy, A Perfect Storm: Understanding the European Energy Crisis (Oct. 28, 2021), available at https://www.leveltenenergy.com/post/europe-energy-crisis.
94 Victoria Zaretskaya, U.S. liquefied natural gas exports grew to records highs in the first half of 2021, U.S. Energy Info. Admin., (July 27, 2021), available at https://www.eia.gov/todayinenergy/detail.php?id=48876.
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generation.95 Fossil fuel company shareholders are demanding higher returns after a decade of
relatively low growth of returns.96
Based on our initial analysis, if gas prices held at $5/MMBtu in 2021 and increased at 3
percent annually until 2037,97 PacifiCorp customers would spend an incremental $230 million on
fuel costs during the plant’s operation horizon from 2024-2037.
The purported economic benefits of the coal-to-gas conversion is further diminished upon
closer scrutiny of PacifiCorp’s other variant assumptions, as we will address in subsection (D).
Sierra Club does not purport to know future gas prices. However, we are well aware of
the risks associated with investing in a long-term resource with an unknown long-term fuel cost
relative to an alternative resource, such as renewables paired with storage, which has no fuel cost
risks whatsoever. If the recent prices become “the new normal” then we are currently
experiencing natural gas prices that PacifiCorp did not anticipate until 2034.
C. The Risk of Fuel Cost Volatility Is Borne by Customers, Not Shareholders.
As demonstrated above, there is significant risk associated with relying on a fossil fuel
resource with variable, uncertain fuel costs, and that risk falls squarely on customers. In Idaho,
fuel costs are initially set through rate cases, with “true-ups” approved through the Energy Cost
Adjustment Mechanism (“ECAM”). Idaho customers pay 90 percent of the difference between
base fuel costs set in the rate case and adjustments through the ECAM, meaning that PacifiCorp
has some, but a relatively small, incentive to ensure that projected fuel costs established in a rate

95 Tim Quinson, Cost of Capital Spikes for Fossil-Fuel Producers, Bloomberg Green (Nov. 9, 2021), available at https://www.bloomberg.com/news/articles/2021-11-09/cost-of-capital-widens-for-fossil-fuel-producers-green-insight.
96 Matt Egan, US oil companies are in no rush to solve Biden’s gas price problem, CNN Business (Nov. 10, 2021), available at https://www.cnn.com/2021/11/10/energy/oil-gas-prices-joe-biden/index html?.
97 PacifiCorp’s forecast for Opal, the most likely gas hub for the Jim Bridger plant, increases 3.89 percent on average between 2024-2037.
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case track actual fuel costs. In other words, PacifiCorp can largely adjust its forecast annually in
the ECAM, and thus can track the upward trajectory of costs, thereby limiting the Company’s
risk exposure when considering a long-term investment decision like the gas conversion.
Meanwhile, customers have no ability to mitigate this risk but must pay for higher than assumed
gas prices through the annual ECAM. It is unlikely that PacifiCorp would assume that type of
asymmetrical risk for its shareholders, and would rather insist on assigning that risk to its
customers. Meanwhile, there is an abundant choice of alternative, clean capacity resources that
do not carry this inherent fuel cost risk. For example, PacifiCorp modeled an alternative to the
gas conversions which revealed fixed-cost solar and storage would maintain reliability while
mitigating the price risk carried by customers.98.
D. PacifiCorp’s IRP Contains Unresolved Questions about the Coal-to-Gas Conversion Analysis.
In addition to the concerns raised above, the IRP does not provide a description of the
plant nor the capital projects that the Company plans to undertake in order to convert Jim Bridger
Units 1 and 2 to gas. The Company’s action item for the conversion consists of five, broad steps
that provide little meaningful detailed information.99 The Company does not provide any
explanation in the IRP on the expected fuel source, the type of permitting that must be
completed, or if the converted units would be classified as a new or existing source for purposes
of environmental compliance. Nor does the Company explain how they will address the fact that
Idaho Power’s plan would exit the gas converted units years before PacifiCorp intends.100

98 PacifiCorp 2021 IRP Vol. I at 269. 99 See Id. at 24.
100 See Idaho Power 2021 IRP at 152 (exiting the gas conversions in 2034 instead of PacifiCorp’s intended date of 2037).
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The Company also refers to the converted units as “peakers,” but does not explain if the
plant will operate as combustion turbines or will maintain and use the existing boilers. The
Company’s workpapers only compound the confusion by including multiple, disparate heat rates,
which suggests two very different technologies. In one confidential workpaper, the Company
appears to use heat rates of and Btu/kWh for Jim Bridger 1 and 2 respectively,101 and
in another workpaper the heat rates are listed as and .102 Which heat rate, or rates,
the Company uses as an input in its models has a tremendous impact on the outcome of the
model run. But the IRP fails to provide any of this critical information.
Finally, as discussed in Section III(F), the results of the No Gas Conversion variant, that
finds the conversion economical, may be a result of PacifiCorp’s overly restrictive number of
potential replacement options in its IRP selection process. The No Gas Conversion variant
includes over 600 MW of non-emitting peakers from 2031-2037, a future resource that is still
speculative. But the Company limited its IRP capacity resource options to non-emitting peakers
and nuclear additions, both of which are expensive, thus driving up the cost of replacing the gas
conversion. The Company then used the results of the variant, based on the speculative costs of
speculative resources, as justification for converting Jim Bridger Units 1 and 2 to gas. As
discussed in Section III(F), if PacifiCorp had included more resource options with high-capacity
value beyond nuclear and non-emitting peakers, then the variant results could differ
substantially.

101 Confidential Plexos Inputs Workpaper accompanying the PacifiCorp 2021 IRP Application “Plexos Inputs – 2021 IRP 091021_CONF.xlsx.”
102 Confidential Jim Bridger Gas Conversation Master Assumptions Workpaper accompanying the PacifiCorp 2021 IRP Application “JB1+2_NGCv20210519 CONF.xlsx” tab “15 - Refuel CapEx.”
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E. PacifiCorp and Idaho Power Do Not Appear to be Aligned on the Gas Conversion Proposal.
As noted above, PacifiCorp does not appear to be appropriately coordinating with its co-
owner of the Jim Bridger facility, Idaho Power. Idaho Power has publicly set a company goal to
be 100-percent clean energy by 2045, and, as noted, has taken steps to accelerate the Jim Bridger
depreciation schedule no later than December 31 2030.103 However, just a few months after
making its depreciation filing, Idaho Power and Idaho Commission Staff filed a joint motion
requesting a suspension of the procedural schedule and discovery “to allow Movants the
opportunity to assess this case in light of new developments that may impact the operation of the
Jim Bridger Power Plant.”104 Those “new developments” turned out to be (1) continued
regulatory uncertainty regarding Regional Haze requirements at the plant and (2) PacifiCorp’s
announced gas conversions for Units 1 and 2. Idaho Power’s filing indicates that PacifiCorp may
not be coordinating its plans with its co-owner.105 A prime example is Idaho Power’s testimony
that the “Co-owners have not yet developed contractual terms that would be necessary to allow
for the potential earlier exit of a Bridger unit by one Co-Owner, and not both Co-Owners.”106
Meanwhile Idaho Power plans to exit each of the Bridger units earlier than PacifiCorp. This

103 IPC Application at 1. 104 In the Matter of Idaho Power Company’s Application for Authority to Increase its Rates for Electric Service to
Recover Costs Associated with the Jim Bridger Power Plant, Case No. IPC-E-21-17, Joint Motion to Suspend Procedural Schedule at 1 (Oct. 1, 2021), available at https://puc.idaho.gov/Fileroom/PublicFiles/ELEC/IPC/IPCE2117/Company/20211001Joint%20Motion%20to%20Suspend%20Procedural%20Schedule.pdf.
105 In the Matter of Idaho Power Company’s Application for Authority to Increase its Rates for Electric Service to Recover Costs Associated with the Jim Bridger Power Plant, Case No. IPC-E-21-17, Amended Application and Motion to Set Schedule (Feb. 16, 2022), available at https://puc.idaho.gov/Fileroom/PublicFiles/ELEC/IPC/IPCE2117/CaseFiles/20220216Amended%20Application%20and%20Motion%20to%20Set%20Schedule.pdf. 106 In the Matter of Idaho Power Company’s Application for Authority to Increase its Rates for Electric Service to
Recover Costs Associated with the Jim Bridger Power Plant, Case No. IPC-E-21-17 Matt Larkin Supplemental Direct Testimony at 9:12-15 (Feb. 16, 2022), available at https://puc.idaho.gov/Fileroom/PublicFiles/ELEC/IPC/IPCE2117/Company/20220216Larkin%20Supplemental%20Direct.pdf.
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misalignment and lack of contractual arrangements highlights the uncertainty of the true cost and
viability of the gas conversions.
The questions raised above regarding cost and liability assumptions are especially
concerning as PacifiCorp’s conversion plan is fast-paced. The Company states that it intends to
initiate the conversion process by finalizing an employee transition plan by the end of Q2 2022
and finalize close-out existing permits, contracts, and other agreements by the end of 2023.107
However, PacifiCorp does not explain the timeline for permitting and building the gas supply
lines necessary to fuel the converted plants. These plans appear aggressive, incomplete, and
document PacifiCorp’s lack of transparent communications and coordination with Idaho Power.
VI. Barriers to Clean Energy
A. PacifiCorp’s Long-Term Resource Cost Assumptions Are Not Fully Informed by the Recent All-Source RFP Results.
PacifiCorp’s assumptions regarding the cost of new clean energy resources are a key
driver of its IRP portfolio results—particularly over the long term after it constructs the 2019
RFP finalist projects. While many of PacifiCorp’s cost and performance assumptions are
consistent with other recent public data, some assumptions, as described in this section, are
unsupported.
PacifiCorp retained Burns & McDonnell Engineering Company (“BMcD”) to evaluate
various renewable energy resources in support of the development of the 2021 IRP and
associated resource acquisition portfolios and/or products. According to the Company, the
resulting 2020 Renewable Resources Assessment and Summary Tables108 provide a high-level

107 PacifiCorp 2021 IRP Vol. I at 322. 108 PacifiCorp 2021 IRP Vol. II, App. M.
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comparison of technical capabilities, capital costs, and O&M costs that are representative of
renewable energy and storage technologies. PacifiCorp made additional adjustments on some of
the cost and performance parameters to reflect the Company’s own experience and assessment.
PacifiCorp’s assessment is fairly comparable with the most recent (2021) Annual
Technology Baseline (“ATB”) report by the National Renewable Energy Lab (“NREL”) with the
exception of battery storage cost estimates, which differ significantly. For example, PacifiCorp
assumed that a 4-hour Li-Ion battery, that is available in 2021 and has a commercial operation
year of 2023, has a capital cost of $1,820/kW, while NREL’s ATB predicts $1,281-1,351/kW for
2021 installations and $1,070-1,275/kW for 2023 installations.109 Similarly, PacifiCorp assumed
a capital cost of $4,622/kW for an 8-hour battery, while NREL’s ATB projects the cost to be
$2,318-2,444/kW in 2021 and $1,937-2,307/kW in 2023. The 2021 IRP’s Figure 7.5 (provided in
Volume I) shows the forecast of storage costs that informed the Company’s modeling. The
below figure provides the IRP’s cost curves with the NREL’s moderate and advanced cost
assumptions, identified by the orange and blue lines respectively.

109 NREL ATB estimates are expressed in $2019, but were adjusted to $2020 for a consistent comparison (using a 2.5% inflation assumption).
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Figure 5. Figure 7.5 from PacifiCorp 2021 IRP Volume I Compared to NREL Cost Assumptions

PacifiCorp’s higher cost assumption combined with other flawed assumptions and
modeling choices, such as the capacity contribution of hybrid solar plus storage assets (as
discussed above in Section II(A)) and the low gas prices (as discussed above in Section V),
caused underinvestment in clean energy and storage technologies in the Company’s optimized
portfolios.
Regardless of how PacifiCorp developed its technology cost assumptions, it is
problematic that these assumptions may not match the reality of actual project costs as informed
by the recent all-source RFP bids. When PacifiCorp delayed its IRP filing from April to
September, one of the justifications it provided was that the additional time would allow the
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Company to utilize the results of its all-source RFP for the modeling. That way, the most up-to-
date market data could be reflected in the supply side resource cost assumptions and modeling.
PacifiCorp included cost information for the specific projects resulting from the 2019 RFP to be
deployed in the 2021-2024 timeframe, but did not necessarily use that information to inform its
forecasts going further into the future, and instead reverted back to the BMcD forecast.
PacifiCorp confidentially provided some information on the 2019 project bids,110 but it is
still possible to develop a high-level comparison of the recent project cost data to PacifiCorp’s
future forecast. Focusing on the workpaper for the Dominguez I project (a 200MW/4hr battery
energy storage system with a projected commercial operation date of mid-2024), the estimate for
“All Fixed Costs With Network Upgrades” is /kW for the first full year of operation
(2025) escalating at per year. In contrast, in Table 7.2 Total Resource Cost for
Supply-Side Resource Options 21 IRP, PacifiCorp assumes a total fixed cost of $223.65/kW for
50MW/4hr Li-Ion battery.111 This confirms that there is a significant discrepancy between
PacifiCorp’s model assumptions going forward and real-world project cost data it has recently
received. Sierra Club recommends that PacifiCorp revise its long-term resource cost
assumptions, particularly for battery storage (stand alone or paired with other resources), to
better reflect the results of its RFP as it had promised in requesting a delay.
Dated: March 15, 2022
Respectfully submitted,

Rose Monahan (CA Bar No. 329861) Sierra Club

110 Unfortunately, values in the project-specific workpapers were hard coded and it is not fully transparent how their values were used to inform the final selection of resources.
111 PacifiCorp 2021 IRP Vol. I at 177 in reference to this workpaper “3_0003_Dominguez_BSA_200MW_200_4H_UT_15YR_2024_2_A_B+F_IRPDataFix CONF.xlsx”.
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Benjamin Otto (ID Bar No. 8292) Idaho Conservation League
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Attachment 1
Selected PacifiCorp Public Data Responses
Sierra Club/ICL Attachment 1
Selected Public Responses to Sierra Club Data Requests
1 LC 77 - PacifiCorp Response to Sierra Club Data Request 3.2
2 LC 77 - PacifiCorp Response to Sierra Club Data Request 4.5
3 LC 77 - PacifiCorp Response to Sierra Club Data Request 6.1
4 LC 77 - PacifiCorp Response to Sierra Club Data Request 9.1
5 LC 77 - PacifiCorp Response to CUB Data Request 3
6 LC 77 - PacifiCorp Response to CUB Data Request 4
7 LC 77 - PacifiCorp Response to CUB Data Request 6
8 LC 77 - PacifiCorp Response to CUB Data Request 9
Sierra Club/ICL Attachment 1
Page 1 of 9
LC 77 / PacifiCorp October 14, 2021 Sierra Club Data Request 3.2

Despite PacifiCorp's diligent efforts, certain information protected from disclosure by the attorney-client privilege or other applicable privileges or law may have been included in its responses to these data requests. PacifiCorp did not intend to waive any applicable privileges or rights by the inadvertent disclosure of protected information, and PacifiCorp reserves its right to request the return or destruction of any privileged or protected materials that may have been inadvertently disclosed. Please inform PacifiCorp immediately if you become aware of any inadvertently disclosed information.
Sierra Club Data Request 3.2
In response to SC 1.9, the Company responded that it does not include any incremental costs to operate the Jim Bridger plant after Idaho Power exits the plant in 2030.
PacifiCorp intends to run Units 3 & 4 until 2037.
(a) Does PacifiCorp anticipate a third-party will assume all of Idaho Power’s share and costs?

(b) Please provide all contracts and materials that describe how PacifiCorp and Idaho Power share common costs, O&M costs, and decommissioning and remediation costs of the joint units. (c) Please provide all contracts and other materials that describe any agreement between
PacifiCorp and Idaho Power regarding Idaho Power’s planned exit from Jim Bridger
in 2030. Response to Sierra Club Data Request 3.2

(a) PacifiCorp has not made any assumptions regarding whether or how Idaho Power Company (IPC) will handle its property. (b) Two agreements govern PacifiCorp and IPC’s relationship at the Jim Bridger plant. First, the Agreement for the Ownership and Operation of the Jim Bridger Project
between IPC and PacifiCorp Power and Light Company (PP&L), executed September
22, 1969, subsequently amended (O&O Agreement) and second, the Agreement for the Operation of the Jim Bridger Project between IPC and PP&L, executed September 22, 1969, subsequently amended. Please refer to Confidential Attachment
SC 3.2, which provides excerpts governing cost sharing.
(c) Please refer to the Company’s response to subpart (b) above. Confidential information is designated as Protected Information under the protective order in this proceeding and may only be disclosed to qualified persons as defined in that
order.
Sierra Club/ICL Attachment 1
Page 2 of 9
LC 77 / PacifiCorp November 12, 2021 Sierra Club Data Request 4.5

Despite PacifiCorp's diligent efforts, certain information protected from disclosure by the attorney-client privilege or other applicable privileges or law may have been included in its responses to these data requests. PacifiCorp did not intend to waive any applicable privileges or rights by the inadvertent disclosure of protected information, and PacifiCorp reserves its right to request the return or destruction of any privileged or protected materials that may have been inadvertently disclosed. Please inform PacifiCorp immediately if you become aware of any inadvertently disclosed information.
Sierra Club Data Request 4.5 Please identify all anticipated federal, state, and local permit approvals, including required waivers or exceptions to federal, state, and/or local law that will be required for
the proposed NatriumTM plant.

(a) For each permit requirement identified, indicate the current status of the permitting process (e.g., yet to apply, pending, permit received, etc.); (b) For each permit requirement identified, please indicate the anticipated timeframe for
obtaining said permit.

Response to Sierra Club Data Request 4.5
TerraPower and PacifiCorp will comply with all federal, state and local permitting
requirements. It is premature to provide an exhaustive list of permitting requirements or timelines at this time. Please refer to the Company’s response to CUB Data Request 5.
Sierra Club/ICL Attachment 1
Page 3 of 9
LC 77 / PacifiCorp December 22, 2021 Sierra Club Data Request 6.1

Despite PacifiCorp's diligent efforts, certain information protected from disclosure by the attorney-client privilege or other applicable privileges or law may have been included in its responses to these data requests. PacifiCorp did not intend to waive any applicable privileges or rights by the inadvertent disclosure of protected information, and PacifiCorp reserves its right to request the return or destruction of any privileged or protected materials that may have been inadvertently disclosed. Please inform PacifiCorp immediately if you become aware of any inadvertently disclosed information.
Sierra Club Data Request 6.1 Please provide any LT model work papers, ST model work papers and supporting reliability assessment work papers, for any preliminary resource portfolios PacifiCorp
developed for the 2021 IRP prior to applying the Granularity and Reliability Adjustments
or any subsequent portfolio refinements. Response to Sierra Club Data Request 6.1

PacifiCorp’s planning process must ensure that portfolios produced are reliable. The preliminary portfolios listed below were primarily used to evaluate the difference in resource value between the Long-Term (LT) model and the Short-Term (ST) model in order to understand which options could be counted on to produce reliable portfolios.
The following LT portfolios (with PLEXOS study numbers) were run without
adjustments and used to develop the Granularity and Reliability adjustments:
• PLEXOS study number 3112 (P02-MMR (CO,NG) Intentional)
• PLEXOS study number 2993 (P02-MMR (CO,NG) Intl UTWY)
Please refer to Confidential Attachment SC 6.1, which provides the LT work papers and the ST hourly capacity requirements.
Confidential information is designated as Protected Information under the protective
order in this proceeding and may only be disclosed to qualified persons as defined in that order.

Sierra Club/ICL Attachment 1
Page 4 of 9
LC 77 / PacifiCorp March 15, 2022 Sierra Club Data Request 9.1

Despite PacifiCorp's diligent efforts, certain information protected from disclosure by the attorney-client privilege or other applicable privileges or law may have been included in its responses to these data requests. PacifiCorp did not intend to waive any applicable privileges or rights by the inadvertent disclosure of protected information, and PacifiCorp reserves its right to request the return or destruction of any privileged or protected materials that may have been inadvertently disclosed. Please inform PacifiCorp immediately if you become aware of any inadvertently disclosed information.
Sierra Club Data Request 9.1 What is the maximum amount of coal that can be currently stockpiled at both the BCC mine and at the Jim Bridger plant?

(a) Could the maximum stockpile capacity identified in response to the question above be expanded? If not, why not?
Response to Sierra Club Data Request 9.1
Bridger Coal Company’s (BCC) existing air quality permit is changing and the new air quality permit has an effective date of April 1, 2022. The new permit has lower fugitive dust emissions than the existing permit and was adjusted to reflect changes associated with the underground mine closure. Effective April 1, 2022, BCC’s maximum live
stockpiled coal storage is 675,000 tons and the maximum sealed stockpiled coal storage
is 1,900,000 tons.
The Jim Bridger Plant’s existing air quality permit limits coal stockpile inventory to a maximum of 1.5 million tons of coal at any one time, with the plant annual average tonnage no more than 1.331 million tons.
(a) In principle, BCC could petition the Wyoming Department of Environmental Quality
(DEQ) to expand the stockpiled coal storage capacity via an air quality permit revision. An increase in capacity and/or emissions would be considered a “major revision”, requiring extensive modeling, studies, a public comment period and
ultimately Wyoming DEQ approval.
Like BCC, an increase of the Jim Bridger plant’s coal stockpile limits would trigger an air permitting action. An increase of the coal stockpile inventory would require an evaluation of air emission increases resulting from the project. If the emission increases were determined to be significant, air modeling would be required to
determine impacts to National Ambient Air Quality Standards (NAAQS). The project
would also require an evaluation of best available control technologies to control emissions from the Jim Bridger stockpiles.

Sierra Club/ICL Attachment 1
Page 5 of 9
LC 77 / PacifiCorp November 9, 2021 CUB Data Request 3

Despite PacifiCorp's diligent efforts, certain information protected from disclosure by the attorney-client privilege or other applicable privileges or law may have been included in its responses to these data requests. PacifiCorp did not intend to waive any applicable privileges or rights by the inadvertent disclosure of protected information, and PacifiCorp reserves its right to request the return or destruction of any privileged or protected materials that may have been inadvertently disclosed. Please inform PacifiCorp immediately if you become aware of any inadvertently disclosed information.
CUB Data Request 3 NatriumTM Advanced Nuclear Demonstration Project Please provide a narrative on the potential risks of this project as perceived by
PacifiCorp and explain how the Company plans to address these risks.
Response to CUB Data Request 3 Identified risks include:
• Fuel Supply – specifically high-assay low-enriched uranium (HALEU) supply.

• Regulatory – specifically this is a first of a kind sodium fast reactor (SFR). There is expected design and Nuclear Regulatory Commission (NRC) review challenges that will need to be addressed.
• Project Management - unforeseen delays related to the design, construction, and
commissioning of a “first of a kind” demonstration reactor. PacifiCorp will work closely with TerraPower to identify, minimize, address, and provide solutions to the risks that come up throughout the project. Further, PacifiCorp intends to negotiate terms and conditions in future definitive agreements with TerraPower to
minimize these risks for our retail customers.
Sierra Club/ICL Attachment 1
Page 6 of 9
LC 77 / PacifiCorp November 9, 2021 CUB Data Request 4

Despite PacifiCorp's diligent efforts, certain information protected from disclosure by the attorney-client privilege or other applicable privileges or law may have been included in its responses to these data requests. PacifiCorp did not intend to waive any applicable privileges or rights by the inadvertent disclosure of protected information, and PacifiCorp reserves its right to request the return or destruction of any privileged or protected materials that may have been inadvertently disclosed. Please inform PacifiCorp immediately if you become aware of any inadvertently disclosed information.
CUB Data Request 4 NatriumTM Advanced Nuclear Demonstration Project Please provide a narrative explanation of the fuel that the NatriumTM plant will use
and the status of supply sources of this fuel.
Response to CUB Data Request 4 The initial fuel for the demonstration program will be sodium bonded metallic uranium fuel encased lead. This extensively tested type of fuel is used at the Fast Flux Test Facility in Hanford, WA, and Experimental Breeder Reactor-2 at the Idaho National Laboratory in Idaho Falls, ID. The fuel is expected to be sourced domestically from U.S- based facilities. Additional information on NatriumTM fuel is available on the U.S.
Nuclear Regulatory Commission (NRC) website at the link provided below.
Natrium | NRC.gov
Sierra Club/ICL Attachment 1
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LC 77 / PacifiCorp November 9, 2021 CUB Data Request 6

Despite PacifiCorp's diligent efforts, certain information protected from disclosure by the attorney-client privilege or other applicable privileges or law may have been included in its responses to these data requests. PacifiCorp did not intend to waive any applicable privileges or rights by the inadvertent disclosure of protected information, and PacifiCorp reserves its right to request the return or destruction of any privileged or protected materials that may have been inadvertently disclosed. Please inform PacifiCorp immediately if you become aware of any inadvertently disclosed information.
CUB Data Request 6 NatriumTM Advanced Nuclear Demonstration Project Please provide an update on the construction or availability of federally licensed
storage facilities for nuclear wastes that would be generated from this plant.

Response to CUB Data Request 6

PacifiCorp currently has no further information on this topic. However, it is expected that independent storage of spent nuclear fuel and high-level radioactive waste will be licensed under Title 10 of the Code of Federal Regulations (CFR) Part 72.
Sierra Club/ICL Attachment 1
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LC 77 / PacifiCorp November 9, 2021 CUB Data Request 9
Despite PacifiCorp's diligent efforts, certain information protected from disclosure by the attorney-client privilege or other applicable privileges or law may have been included in its responses to these data requests. PacifiCorp did not intend to waive any applicable privileges or rights by the inadvertent disclosure of protected information, and PacifiCorp reserves its right to request the return or destruction of any privileged or protected materials that may have been inadvertently disclosed. Please inform PacifiCorp immediately if you become aware of any inadvertently disclosed information.
CUB Data Request 9
NatriumTM Advanced Nuclear Demonstration Project
Please describe the steps PacifiCorp is taking towards training its personnel to operate
the plant.
Response to CUB Data Request 9
PacifiCorp is currently evaluating the overall strategy for operations and maintenance,
including training requirements.
Sierra Club/ICL Attachment 1
Page 9 of 9

Attachment 2

Confidential Attachment “3112 Capacity Requirements P02-MMR (CO)
Intl UTWY 2031 6-17-21” to PacifiCorp Response to SC 6.1

Sierra Club/ICL Attachment 2 contains confidential information subject to the protective agreement in Case No. PAC-E-21-19 and has been served upon the Commission and parties on the service list eligible to receive confidential information.
Attachment 3
Email from Carla Scarcella, PacifiCorp to Rose Monahan, Sierra Club
(Jan. 26, 2022)
3/9/22, 10:22 AM Sierra Club Mail - LC-77 - Sierra Club's 6th Set of Data Requests
https://mail.google.com/mail/u/0/? k=6c37dda345&view=pt&search=all&permmsgid=msg-f%3A1723043414324104016&simpl=msg-f%3A1723043414…1/1
Rose Monahan <[e-mail]>
LC-77 - Sierra Club's 6th Set of Data Requests
Scarsella, Carla (PacifiCorp) <[e-mail]>Wed, Jan 26, 2022 at 10:37 AM
To: "Monahan, Rose" <[e-mail]>, Edward Burgess <[e-mail]>
Cc: Gloria Smith <[e-mail]>, "Baker, Randy (PacifiCorp)" <[e-mail]>
Rose-
You are correct that there are no additional hourly data files for the P02h variant case, and that the same hourly data files
already provided in response SC 6.1 for the P02-MM case were relied upon for assessing reliability of the P02h case.
[Quoted text hidden]
Sierra Club/ICL Attachment 3
Page 1 of 1

Attachment 4

Confidential Attachment to PacifiCorp Response to Sierra Club Data
Request 4.2 in LC 77

Sierra Club/ICL Attachment 4 contains confidential information subject to the protective agreement in Case No. PAC-E-21-19 and has been served upon the Commission and parties on
the service list eligible to receive confidential information.

Attachment 5

UE 390, Surrebuttal Testimony of Dana M. Ralston on Behalf of
PacifiCorp (PAC/1200) (excerpt)
REDACTED Docket No. UE 390
Exhibit PAC/1200
Witness: Dana M. Ralston BEFORE THE PUBLIC UTILITY COMMISSION OF OREGON

PACIFICORP ___________________________________________________________ REDACTED Surrebuttal Testimony of Dana M. Ralston

August 2021
Sierra Club/ICL Attachment 5
Page 1 of 4
PAC/1200 Ralston/12
Surrebuttal Testimony of Dana M. Ralston
unfairness of Staff’s recommendation to apply its newly articulated prudence standard 1
to CSAs that were executed last year. 2
Q. Did Staff provide any evidence specific to the new Hunter CSAs to suggest that 3
the minimum take levels are excessive? 4
A. No. 5
Huntington 6
Q. Has Staff modified its position on the Huntington CSA? 7
A. Yes. Staff no longer believes that the CSA is imprudent.15 But Staff agrees with 8
CUB’s recommendation that the Company “conduct analysis to determine whether 9
contract provisions in the CSA result in uneconomic dispatch of the plant, and if yes, 10
whether that uneconomic dispatch is related to environmental laws and 11
regulations.”16 12
Q. How do you respond to Staff’s new recommendation? 13
A. The Company agrees that it has an obligation to prudently manage the CSA, 14
including determining whether there are reasonable grounds to invoke the termination 15
provision in the agreement. But the Company does not agree that additional analysis 16
or reporting is required at this time. 17
The Company regularly assesses the economics of the plant. If it becomes 18
apparent that the plant is consistently unable to economically accept delivery of the 19
minimum volumes, then the Company will then proceed to determine whether the 20
consistent inability to economically accept coal deliveries at the plant is the result of 21
an environmental regulation(s), i.e., whether the plant would be economic but for the 22

15 Staff/1400, Anderson/12. 16 Staff/1400, Anderson/15.
Sierra Club/ICL Attachment 5
Page 2 of 4
PAC/1200 Ralston/13
Surrebuttal Testimony of Dana M. Ralston
environmental regulation(s). 1
Currently, even if the plant were to require alternate dispatch in order to reach 2
the minimum take level, there is no evidence that the alternate dispatch is caused by 3
environmental regulations. The examples cited by CUB, which are primarily state 4
renewable generation mandates,17 are too attenuated to justify invoking the 5
termination provision in the CSA. No party has identified, and the Company is 6
unaware of, any existing environmental regulation that is sufficiently tied to the 7
Huntington plant to allow the invocation of the CSA’s termination provision. It is 8
unclear what additional analysis Staff envisions, but from the Company’s perspective 9
it has already conducted the analysis that Staff requested and concluded that there is 10
no reasonable basis to terminate the CSA. 11
Q. Will the Company continue to monitor the plant to determine if there is a basis 12
to terminate the CSA? 13
A. Absolutely. The Company is always committed to prudently managing all its 14
contracts. The Company’s interests are firmly aligned with customers and the 15
Company has no incentive to continue to burn coal at Huntington if it is uneconomic. 16
As market conditions and the regulatory environment change, the Company will 17
continue to monitor Huntington to ensure that the Company reasonably exercises its 18
ability to terminate the contract if doing so is prudent. The Company’s annual TAM 19
filings provide a reasonable forum for the Commission and stakeholders to assess the 20
economics of the plant to ensure that the Company continues to prudently manage its 21
obligations under the CSA. 22

17 See, e.g., CUB/200, Jenks/19.
Sierra Club/ICL Attachment 5
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PAC/1200 Ralston/32
Surrebuttal Testimony of Dana M. Ralston
(1)management employee severance costs and union severance and benefit costs as 1
required in the working agreement with the International Brotherhood of Electrical 2
Workers triggered by his significant reduction in labor costs, (2) final reclamation 3
contributions ($) required to comply with federal and state legal 4
obligations, (3) depreciation expenses incurred for capital investments between 5
April 1, 2021 and December 31, 2022 ($), (4) additional coal inventory 6
and deferred longwall expenses incurred between April 1, 2021 and 7
December 31, 2022 ($), (5) embedded fixed costs in material and supply 8
costs as discussed in response to Sierra Club 2.5, and (6) federal and state royalties 9
associated with increased costs noted above. In summary, Mr. Burgess’ analysis 10
contains substantial flaws and should be rejected in its entirety. 11
Q As discussed above, Mr. Burgess reduced BCC labor and benefit costs in his 12
flawed analysis by in Confidential Table 3 and described those costs 13
as “variable”. Do you agree? 14
A. No. Changes in BCC mine plans and staffing levels need to be evaluated in multi-15
year evaluations such as PacifiCorp’s IRP and not in a one-year filing like the TAM. 16
A reduction in labor and benefit costs would result in an approximate 17
reduction of employees. Not only would it be imprudent to incur costs to 18
terminate and then later hire employees in one year, it is highly unlikely the skills 19
of those terminated employees could be replaced and would need to be developed 20
over an extended period of time. Additional costs would be incurred to train new 21
hires and offset the unfavorable impact of reduced productivity rates. 22
Sierra Club/ICL Attachment 5
Page 4 of 4
Attachment 6
Confidential PacifiCorp Response to ALJ Bench Request 1 in LC 77

Sierra Club/ICL Attachment 6 contains confidential information subject to the protective agreement in Case No. PAC-E-21-19 and has been served upon the Commission and parties on
the service list eligible to receive confidential information.

Attachment 7

Confidential Attachments “OR LC-77 Attach ALJ Bench Request 1-4
CONF” to PacifiCorp Response to ALJ Bench Request 1

Sierra Club/ICL Attachment 7 contains confidential information subject to the protective agreement in Case No. PAC-E-21-19 and has been served upon the Commission and parties on
the service list eligible to receive confidential information.
Attachment 8
Confidential Attachment “OR LC-77 Attach ALJ Bench Request 1-1
CONF” to PacifiCorp Response to ALJ Bench Request 1
Sierra Club/ICL Attachment 8 contains confidential information subject to the protective agreement in Case No. PAC-E-21-19 and has been served upon the Commission and parties on
the service list eligible to receive confidential information.
CERTIFICATE OF SERVICE
I hereby certify that on this 15th day of March 2022, I delivered true and correct copies
of the foregoing JOINT COMMENTS AND ATTACHMENTS OF SIERRA CLUB AND
IDAHO CONVERSATION LEAGUE to the following persons via the method of service
indicated below. The confidential version of these comments was served on eligible parties via
encrypted password protected.zip folders with the exception of Attachment 2 which is being
provided via Federal Express overnight mail.
/s/ Ana Boyd Ana Boyd
Sierra Club
Electronic mail only (see Order 35058) and FedEx
Idaho Public Utilities Commission Jan Noriyuki, Secretary
Idaho Public Utilities Commission 11331 W. Chinden Blvd. Building 8 Suite 201-A Boise, ID 83714 [e-mail]
Rocky Mountain Power Ted Weston Emily Wegener
PacifiCorp/ dba Rocky Mountain Power
1407 West North Temple, Suite 320 Salt Lake City, UT 84116 [e-mail] [e-mail]
[e-mail]
[e-mail]
Electronic mail only (see Order 35058)
Commission Staff
Riley Newton Deputy Attorney General Idaho Public Utilities Commission 11331 W. Chinden Blvd., Bldg No. 8
Suite 201-A
Boise, ID 83714 [e-mail]