20251007Staff Comments.pdf

RECEIVED
October 07, 2025
JEFFREY R. LOLL IDAHO PUBLIC
DEPUTY ATTORNEY GENERAL UTILITIES COMMISSION
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 11675
Street Address for Express Mail:
11331 W CHINDEN BLVD, BLDG 8, SUITE 201-A
BOISE, ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF PACIFICORP'S )
APPLICATION FOR ACKNOWLEDGEMENT ) CASE NO. PAC-E-25-12
OF THE 2025 INTEGRATED RESOURCE )
PLAN )
COMMENTS OF THE
COMMISSION STAFF
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission
("Commission"), by and through its attorney of record, Jeffrey R. Loll, Deputy Attorney
General, submits the following comments.
BACKGROUND
On December 31, 2024, Rocky Mountain Power, a division of PacifiCorp ("Company"),
filed a draft version of its 2025 Integrated Resource Plan("Draft IRP")with the Commission in
Case No. PAC-E-24-13. The Company indicated that it would file the final version of the 2025
IRP on March 31, 2025. On March 31, 2025, the Company applied to the Commission
requesting acknowledgment of the final version of its 2025 IRP ("Application" or"2025
IRP"). On May 22, 2025, the Commission issued Order No. 36605, closing PAC-E-24-13, and
opening this docket to consider the Company's 2025 IRP. The Commission issued Order No.
STAFF COMMENTS 1 OCTOBER 7, 2025

36620 on June 3, 2025, giving notice of the Company's Application and setting deadlines for
interested persons to petition to intervene in the case. No third parties sought to intervene in the
case prior to the June 24, 2025, deadline.
STAFF ANALYSIS
Staff recommends the Commission acknowledge the Company's 2025 IRP. Staff s
recommendation is based on the Company meeting the minimum requirements set forth in
Commission Orders, its review of the filed 2025 IRP, and responses to production requests, in
addition to the participation by Staff in the series of 2025 IRP Public Input Meetings. However,
Staff has several conclusions and recommendations summarized below. Staff believes the
Company should:
1. Justify the selection of the Company's PP when other portfolios perform consistently
better across potential alternative futures;
2. Perform additional analysis by applying "end effects" or similar conditions under
each Price-Policy Scenario (PPS) for all competing portfolios in the future IRPs;
3. Review its practices for hedging natural gas fuel supply to mitigate fuel supply risks
and dependence on natural gas for dispatchable generation;
4. Meet with Staff to explore the possibility of developing Idaho-specific portfolios
prior to the next IRP;
5. Meet with Staff to explore how to balance between meeting the Western Resource
Adequacy Program ("WRAP")resource adequacy compliance and avoiding
overbuilding resources;
6. Provide more specific information to the Commission before the next IRP regarding
removal of new large customer loads, how the customers plan to serve their own
loads, and the impact on the Company's system and on its Idaho customers;
7. Provide the Commission with its re-evaluation study before the next IRP regarding
the need and timing of the Boardman-to-Hemingway (`B21­1") transmission line;
8. Provide an incremental analysis showing how the types of resources would change as
a result of some of the most recent federal policies under the new presidential
administration; and
STAFF COMMENTS 2 OCTOBER 7, 2025

9. Provide greater clarity whether the defined reliability target is achieved by the
developed integrated preferred portfolios in future IRPs.
Compliance with the Commission Orders
Staff believes the 2025 IRP meets the minimum requirements set forth in Order Nos.
22299 and 25260. Staff reviewed the Company's IRP to confirm that it complies with
requirements as specified by Commission Orders and contains the required information. Staff
examined the Company's 2025 IRP Methodology, generation resource evaluations, load forecast,
transmission planning, demand side resources, market assumptions, and action plan. Each of
these subjects are addressed in greater depth in the sections below.
Issues Identified from Past IRP(s)
In the 2023 IRP, Staff recommended the Company begin forecasting the benefits of
WRAP when it is projected to become a binding participant in the next IRP. The Company's
reply comments in that case (Case No. PAC-E-23-10) indicated that the Company expected to
include discussion of the impacts of WRAP compliance and appropriate modeling of planning
reserve margin and resource requirements. This is discussed further within the Analysis of
Reliability section below.
Overview of the 2025 IRP
The 2025 IRP describes the Company's proposed plan to deliver continuous, reliable
electric service to its customers over the next 21 years (from January 1, 2025, to December 31,
2045)using an approach that can identify a least-cost, least-risk resource portfolio. In
developing this plan, the Company considers a load forecast with varying levels of load growth,
future capability and capacity of existing resources, and a range of potential future resources
before determining the preferred portfolio. The Company incorporates several risk variables and
constraints in its evaluation to arrive at a preferred portfolio it believes is least-cost and least-risk
that can meet future customer load while performing well across a range of PPSs throughout the
IRP planning horizon.
STAFF COMMENTS 3 OCTOBER 7, 2025

In developing the 2025 preferred portfolio, the Company demonstrated high reliance on
receiving Inflation Reduction Act("IRA") tax credits for renewables and non-emitting green
energy resources, such as wind, solar, and battery storage. However, due to the active executive
orders and certain restrictions from the new presidential administration regarding the withdrawal
of leases and permits for wind projects on federal lands,1 ending of subsidies for wind and solar
or green energy resources,2 and application of reciprocal tariffs on internationally imported
goods and materials,3 these may disrupt implementation of such resources in the future and could
potentially invalidate some of the IRP results. Although the Company acknowledged the
potential impact of these new federal policies, it did not provide any guidance on its plan moving
forward. 2025 IRP—Volume I at 23. Staff outlined some concerns regarding these specific
issues in the Supply-Side Resources section of these comments.
Analysis of the IRP Methodology
Generally, the Company's process involves two steps to determine the Preferred Portfolio
("PP"):
1. Development of optimized portfolios under different PPSs that can reliably meet the
Company's load; and
2. Selection of a PP through an evaluation of how well each of these optimized
portfolios can perform under alternative futures using a wide range of risk variables
and different combinations of PPSs.
Staff believes the end result of these two steps can enable the Company to identify a PP,
which is the set of resources that can be implemented over the 21-year planning horizon that
meets the reliability needs of its customers, while balancing cost with risk. However, as will be
' Temporary Withdrawal of All Areas on the Outer Continental Shelf from Offshore Wind Leasing and Review of
the Federal Government's Leasing and Permitting Practices for Wind Projects.URL:
https://www.whitehouse.goy/presidential-actions/2025/01/temporary-withdrawal-of-all-areas-on-the-outer-
continental-shelf-from-offshore-wind-leasing-and-review-of--the-federal-governments-leasing-and-permitting=
practices-for-wind-projects/.
2 Ending market distorting subsidies for unreliable,foreign controlled energy sources.URL:
https://www.whitehouse.aoy/presidential-actions/2025/07/ending-market-distorting-sub sidies-for-unreliable-
foreien%e2%80%91 controlled-energy-sources/.
3 Modifying the scope of reciprocal tariffs and establishing procedures for implementing trade and security
agreements.URL:https://www.whitchouse.goy/presidential-actions/2025/09/modifying-the-scope-of-reciprocal-
tariffs-and-establishing=procedures-for-implementing-trade-and-security-agreements/.
STAFF COMMENTS 4 OCTOBER 7, 2025

discussed in The 2025 IRP Preferred Portfolio section, Staff has concerns whether the most
robust portfolio was selected based on the results of the Company's analysis.
As part of its analysis, Staff identified the following key changes in the Company's 2025
IRP methodology compared to the 2023 IRP:
• The IRP planning horizon was extended to 21 years instead of the typical 20-year
cycle to accommodate a requirement from the State of Washington. 2025 IRP—
Volume I at 181;
• The portfolios must achieve regional and system WRAP compliance. The IRP
modeling captures the WRAP compliance requirements starting in 2028 and
continues through the study horizon. Id.;
• No federal carbon-dioxide ("CO2") adder is assumed in the PP, and as a result, the
existing thermal units can operate indefinitely with ongoing maintenance;
• IRA tax credits are extended through the 21-year study period, but the value of
production tax credits is reduced in the last five years of the study horizon to better
represent the value of resource additions in the latter half of the planning horizon; and
• The stochastic analysis of the portfolios incorporates volatility with renewables,
thermal outages, load, market prices, and hydro availability using 18 years of actual
historical data, from 2006 to 2023.
Step 1: Development of Optimized Portfolios that Meet Reliability Requirements
The objective of the first step is to identify a diverse set of resource portfolios that can
meet the reliability needs of its customers, which can be evaluated for cost and risk in the second
step. A resource portfolio is a set of demand and supply-side resources, retirements, and
transmission options, that all meet the reliability needs of the Company's customers over the
planning horizon. To ensure a diverse set of reliable portfolios, the Company has identified
several PPSs. A PPS is a combination of different federal policies (carbon prices, environmental
policies, etc.) and natural gas price forecasts (high, medium, and low). By using the Company's
PLEXOS modeling software, the Company can then generate a different resource portfolio for a
given PPS. For example, a high gas price and no carbon price scenario will drive more
renewables and less gas-fueled resources into a portfolio, while a low gas price and high carbon
price scenario will drive in less renewables and more gas-fueled resources.
STAFF COMMENTS 5 OCTOBER 7, 2025

The Company utilizes two models developed in PLEXOS to generate the portfolios: (1)
the Long-Term model ("LT"), which simultaneously optimizes the set of resources for the
planning horizon using an optimization algorithm to generate a cost-optimum portfolio for a
given PPS; and(2) the Short-Term model ("ST"), which is a time-step simulation model that
simulates how the Company would operationally and optimally dispatch the resources included
in a resource portfolio by stepping through each hour across the 21-year planning horizon.
Because the LT is less granular, the portfolios it generates may not completely meet
reliability constraints. By modeling the portfolio in the ST, any amount of unserved energy is
identified, and the resources are adjusted and fed back into the LT model. These steps are
repeated until all instances of unserved energy are resolved for a given portfolio. The Company
utilizes seasonal loads, operating reserves, and regulation reserves with minimum monthly
planning reserve margin ("PRM") requirements based on the WRAP as the primary constraints
related to reliability.
The result of this process is a diverse set of resource portfolios which should be reliable
and least-cost for the Company's system for each PPS.
Step 2: Cost Analysis of Portfolios Over Multiple Alternative Futures
The objective of Step 2 is to evaluate the cost and risk for each of the portfolios generated
in Step 1 across each of the PPSs. The portfolio that is the most robust by performing
consistently with the lowest costs across the set of most likely PPSs should be identified as the
least-cost, least-risk portfolio and recommended as the PP.
To determine how each of the resource portfolios perform relative to cost and risk for
each of the portfolios produced in Step 1, the Company uses the ST model described above. In
addition to measuring unserved energy when simulating the operation of a given portfolio, the
ST model collects the variable costs of every resource dispatch over the 21-year planning
horizon and produces a Net Present Value Revenue Requirement ("PVRR") for the simulation
run so they can be compared in present day dollars. The Company modeled 13 different PPSs.
Staff included a short description of each in Attachment No. A. Staff believes the Company
explored a reasonable range of alternative futures.
The Company also performed stochastic risk modeling of resource portfolios using actual
historical conditions from 18 distinct years (from 2006 to 2023)to account for volatility and real-
STAFF COMMENTS 6 OCTOBER 7, 2025

world conditions, such as weather patterns, outages, fuel and market prices, hydro generation,
wind and solar generation profiles, etc. Staff believes using the approach of relying on actual
historical data provides reasonable correlation between load forecast, extreme weather events,
and renewable resource (wind and solar)performances. The results of this additional step
provides a risk-adjusted PVRR for each portfolio used in selecting the PP.
The resulting rankings based on PVRRs for each of the portfolios in various alternative
future PPSs are summarized in Attachment No. B —Table No. 3. The information provided in
Table No. 3 is extracted from the data provided in the 2025 IRP—Volume I: Table Nos. 9.34—
9.37.
The 2025 IRP Preferred Portfolio
The Company selected the "Integrated Base MN"portfolio for its 2025 IRP PP.
According to the Company's analysis, it is the least-cost and lease-risk portfolio when comparing
the PVRRs for each of the 13 portfolios when run using the PPSs most likely to occur in the
future. The PP was developed under the medium gas price and zero carbon-dioxide PPS.
Company's Response to Staff Production Request No. 11. In selecting the preferred portfolio,
the Company considered the performances of all portfolios including "end effects,"where the
overall portfolio costs are evaluated and ranked for five additional years (up to year 2050)
beyond the 2025 IRP horizon. 2025 IRP—Volume I at 260: Table No. 9.34, and Company's
Response to Staff Production Request No. 12.
From the rankings provided in the Attachment No. B —Table No. 3, it appears the
"Integrated Base MN"portfolio only ranks as the top performing portfolio when the future PPS
is considered as "Medium Gas/Zero CO2"with end effects being applied. However, when future
PPS assumptions change, the Company's selected PP does not perform as well as other
portfolios. As a result, Staff is concerned that if assumed conditions change in the future (e.g.
natural gas prices deviate significantly from the medium gas forecast, or federal CO2 policies
become more restrictive to carbon-emitting sources), the "Integrated Base MN"may not be the
most cost-effective portfolio compared to other portfolios. In this regard, Staff believes that
between each of the 13 considered portfolios, "Integrated Hunter Retire MN,""Integrated Base
HH," or"Integrated Base MR"portfolios demonstrate more robust performance across the range
of future PPSs based on the Company's rankings and when compared to the Company's selected
STAFF COMMENTS 7 OCTOBER 7, 2025

PP. Staff believes the Company should address these concerns and provide further justification
for its selected PP.
Additionally, the Company only applied end effects to one PPS. Staff believes it does
not provide fair comparison among all integrated portfolios for different scenarios. Thus, Staff
recommends the Company perform additional analysis by applying end effects or similar
conditions under each PPS for all competing portfolios in the future IRPs to ensure they are
comparable on a relative basis.
Major Resource Additions in 2025 IRP
The following items represent major capital additions identified within the Company's
selected PP.
New Generation Resources:
• 3,782 MW of new wind resources;
• 5,912 MW of new solar resources, including utility-scale and small-scale resources;
• 7,524 MW of storage resources, including four-hour, and 100-hour(iron-air
technology) durations; and
• 500 MW of advanced nuclear(Natrium reactor demonstration project), which is
projected to be online by Fall 2031.
Customer Programs:
• 5,255 MW of capacity saved through energy efficiency(`BE")programs; and 769
MW of capacity saved through direct load control programs.
Key Thermal Outcomes:
• Exit from the Colstrip project in Montana by 2030;
• Coal-to-gas conversion of Naughton Units 1 and 2 in Kemmerer, WY,by 2026;
• Initiate coal-to-gas conversion of Dave Johnston Units 1 and 2 in Glenrock, WY,by
2029; and
• Carbon Capture and Sequestration ("CCS") options for Jim Bridger Units 3 and 4 in
Rock Springs, WY, for completion by 2030.
New Transmission and Upgrades:
• New transmission from Walla Walla, Washington to Yakima, Washington;
STAFF COMMENTS 8 OCTOBER 7, 2025

• New transmission, including a 10-mile line from Summer Lake to Burns, Oregon, and
an 88-mile line from Summer Lake to Full Circle in Central Oregon;
• Various upgrades to increase the transfer capability from southern Utah to the major
load center in the Wasatch Front;
• Various upgrades that increase transfer capability between the Summer Lake, Oregon
and Hemingway, Idaho substations;
• These near-term upgrades connect with a later upgrade a new transmission line
connecting Walla Walla to the Full Circle substation, expected in 2039; and
• Additional local transmission upgrades to connect clean resources to the transmission
system in southern Utah, southern and central Oregon, the Willamette Valley in
Oregon, and in Yakima and Walla Walla, Washington.
In terms of transmission resources, compared to the 2023 IRP, the Company excluded
B2H transmission line from its resource list. This issue is discussed in further detail in the
Planning of Transmission Resources section.
Coal Unit Retirements and Gas Conversions
In the 2025 IRP, some of the Company's coal-fired units do not have any enforceable
environmental compliance requirement and continue coal-fired operation throughout the IRP
planning horizon, as opposed to the retirements assumed in 2023 IRP. 2025 IRP—Volume I at
233. Several other coal units are either planned to be converted to gas or outfitted with CCS
technology based on the natural gas supply to each unit. 2025 IRP—Volume I at 9. This is
similar to what the Company planned in the 2023 IRP. Staff believes the transition to increased
dependency on natural gas increases the risk of customers being exposed to price volatility tied
to markets for natural gas supply compared to relatively lower cost coal. Staff recommends the
Company review its practices for hedging natural gas-fuel supply to reduce exposure to natural
gas price volatility as it continues to gradually step away from coal and increases its natural gas
capacity for dispatchable generation in the following IRPs.
Table No. 1 below summarizes the differences between 2025 and 2023 IRP regarding the
existing majority and minority-owned coal units.
STAFF COMMENTS 9 OCTOBER 7, 2025

Table No. 1: Comparison of Thermal Unit Retirements and Gas Conversion between 2025
and 2023 IRP.
Year Coal Unit 2025 IRP Retirement/ 2023 IRP Retirement
Conversion as Input Conversion as Input
(No EPA 111(d) Regulation)
2024 Jim Bridger 1, 2 Not retired(Gas conversion 2024) 2037 (Gas conversion 2024)
2025 Colstrip 3 Transfer Capacity to Unit 4 Same
Craig 1 End of life assumed Same
2026 Naughton 2 Not retired(Gas conversion 2026) 2036 (Gas conversion 2026)
Naughton 1 2042 (Gas conversion 2026) Retirement 2036 (Gas
conversion 2026)
2027 Hayden 2 End of life assumed Same
Dave Johnston 3 Clean air compliance Same
2028 Craig 2 End of life assumed Same
Hayden I End of life assumed Same
2029 Colstrip 4 PacifiCorp exit Same
Dave Johnston Not retired(Gas conversion 2029) Retirement 2028
1, 2
2030 Jim Bridger 3, 4 2042 (CCS conversion 2030) 2037 (Gas conversion 2030)
2032 Wyodak Retirement 2032 Retirement 2039
Dave Johnston 4 Not retired Retirement 2039
Huntington 1, 2 Not retired Retirement 2032
Hunter 1 Not retired Retirement 2031
Load Forecast
Staff reviewed the methodology used to derive the load forecast and believes it is sound
and has resulted in a load forecast that is reasonable for purposes of planning the Company's
resources. Staff also compared the 2023 IRP and 2025 IRP load forecasts and has determined
the largest impact has been the removal of new large customers' loads from the forecast due to
STAFF COMMENTS 10 OCTOBER 7, 2025

these customers supplying their own power. Based on its analysis, Staff has several concerns
and recommends the Company provide the Commission with more specific information
regarding these customers' loads, how they plan to serve their own loads, and the impacts it will
have on the Company's system and on Idaho customers.
The 2025 IRP peak load forecast increased from 11,318 MW in 2025 to 15,518 MW in
2044, as shown in Figure A.1 of Appendix A—Load Forecast. As stated in Appendix A, the
peak load forecast is used in portfolio development and is the maximum load required on the
system. Staff ensured that jurisdictional peak load forecasts are reasonably developed using
historical actual data, such as load and weather, and economic data, including employment and
population, to fit with each customer class's characteristic. Additionally, Staff verified that the
peak load forecast in 2025 IRP—Volume II: Figure A.1 of Appendix A is identical to the load in
2025 IRP—Volume I: Table Nos. 9.12 and 9.13 - Preferred Portfolio Summer Capacity Load
and Resource Balance and proved that the peak load forecast is incorporated with portfolio
development.
For the annual load, the 2025 IRP energy-load forecast is about 12% less than the energy-
load forecast in the 2023 IRP. Specifically, the average decreased amount of energy from 2025
through 2027 is expected to be 6,117 gigawatt-hours ("GWh"), and 10,973 GWh less from 2028
through 2044. The Company stated that the primary driver for this decrease is the exclusion of
specific new large-load customers who are expected to acquire their own resources. See 2025
IRP, Appendix A - Load Forecast. However, the 2025 IRP didn't include detailed information
regarding these large-load customers and how they plan to serve their own load. Without more
detailed information, Staff has concerns regarding the size of these customers' loads, their load
factors, and the types of resources they plan to acquire. Depending on these details, this may
require the Company to continue to provide these customers with reserves, raising questions
regarding how those additional costs will be allocated between States. In addition, the location
of these resources could drive changes in the transmission system, which is discussed in more
detail in the Planning of Transmission Resources section of these comments. Thus, Staff
recommends the Commission direct the Company to provide the Commission with more specific
information regarding these customers and how they plan to serve their own loads.
STAFF COMMENTS 11 OCTOBER 7, 2025

Planning of Transmission Resources
Based on the Company's methods, Staff believes that the Company planned for
transmission for its system that will provide sufficient delivery of power to its load throughout its
service territory. However, Staff has two concerns, both related to large load customers: (1)the
elimination of need for the Boardman-to-Hemmingway transmission line in the Company's
preferred portfolio, and(2) how these customers will obtain the necessary power to serve their
own load and its effect on the Company's transmission system. In addition to the
recommendation included in the Load Forecast section, Staff recommends that the Company
provide the Commission with its re-evaluation study regarding the need and timing of the B2H
transmission line.
The Commission issued a certificate of public convenience and necessity ("CPCN") for
the B2H transmission line. Order No. 35839. Additionally, it was modeled in the 2023 IRP as a
resource providing a capacity increase of approximately 818 MW from east to west and 300 MW
from west to east. However, the Company excluded the B2H transmission from the preferred
portfolio in the 2025 IRP because the Company is re-evaluating the need and timing of the
transmission line due to conditions that have changed since the 2023 IRP was acknowledged.
Application at 84. According to the Company, B2H was needed to facilitate load service for
specific new large-load customers. 2025 IRP—Volume II• Appendix M— Stakeholder
Feedback. However, several of the large-load customers are located in Oregon, accounting for
nearly 70% of the total decreased loads and driving the need for the B2H transmission line. See
2025 IRP, Appendix A - Table A.3. After removing these large-load customers from the load
forecast in the 2025 IRP, the associated transmission line was no longer needed.
Staff believes the Company's re-evaluation may trigger actions that may need to be taken
regarding the CPCN. The re-evaluation may also affect the commitments the Company has
made to Idaho Power Company for its portion of the transmission line's capacity. Therefore,
Staff recommends that the Commission direct the Company to submit its re-evaluation for the
B2H transmission line when the Company finalizes the re-evaluation study before its next IRP.
Staff s second concern with new large-load customers is how each will obtain the
necessary power to serve its own load and the effect on the transmission system. The lack of
information creates concerns, especially if the way these large customers plan to acquire their
power is from the market or from resources that are not located at the customer's site, requiring
STAFF COMMENTS 12 OCTOBER 7, 2025

additional transmission infrastructure. This is especially a concern given the typical practice for
the Company to allocate the cost of transmission between the states. Therefore, if these large-
load customers require new transmission or transmission upgrades and are located outside of
Idaho, it will be important for the incremental costs not to be jurisdictionally allocated to Idaho.
Supply-Side Resources
Although Staff believes the Company properly updated the assumptions for supply-side
resources, reflecting the advanced technology, environmental factors, and costs under the
previous Biden administration, several recent changes to federal policies may have invalidated
some of the results. Staff recommends that the Company provide an incremental analysis
showing how the types of resources would change as a result of some of the most recent federal
policies.
Staff reviewed the supply-side resources in the 2025 IRP and compared them to resources
in the 2023 IRP. As stated in the 2025 IRP on page 142 in Chapter 7—Resource Options, the list
of the supply-side resources was modified to reflect stakeholder input, new technology
developments, environmental factors, cost dynamics, and anticipated permitting requirements.
The Company used the Annual Technology Baseline by the National Renewable Energy
Laboratory, as much as possible, for consistency, unlike what occurred in the 2023 IRP. The
Company also included the addition of hydrogen-fueled resources for selection into portfolios in
this IRP. Staff believes the addition of hydrogen resources resulted from an assessment of new
technological development.
However, the Company didn't reflect the new federal policies under the current
administration. Staff believes that the extent of the changes may have invalidated much of the
2025 IRP results due to the changing costs of resources as a result of the elimination of
production tax credits, investment tax credits, and the inclusion of reciprocal tariffs. Staff
recommends that the Company provide an incremental analysis to show how the Company's
resource plan would change under the more recent federal policies.
Nuclear Resource—Natrium Demonstration Project
Staff believes the Company should provide the Commission with regular updates on its
progress toward implementing the advanced Natrium Nuclear plants. The 2025 IRP Preferred
STAFF COMMENTS 13 OCTOBER 7, 2025

Portfolio selected 500 MW of capacity through advanced Natrium Nuclear demonstration project
(commercially name as Kemmerer Power Station Unit 1 or"KU1") starting January 1, 2032.
In response to Staff Production Request No. 15, the Company stated that it recently
executed a power purchase agreement("PPA") with US SFR Owner, LLC, a subsidiary of
TerraPower, LLC, for the KUl project. The Company acknowledged that similar to adopting
any new or forward technology, the KU1 nuclear project comes with first-of-a-kind("FOAK")
technology risk and associated FOAK program and construction costs. 2025 IRP—Volume I at
147.
Although, the structure of this specific PPA shields customers from these costs, Staff is
concerned that if these associated risks and costs exceed the benefits, and if the Company does
not have any suitable cost-effective alternatives to replace the equivalent generation amount(500
MW, as assumed through KU1 project), then customers could be highly impacted. 2025 IRP—
Volume I at 147 and Company's Response to Staff Production Request No. 15. One of the
variants (No Nuclear Variant) of the PP, as outlined in 2025 IRP—Volume I at 263 states that if
no nuclear project was selected through the IRP horizon, it adds a total $1.794 billion of
incremental costs to the system.
Additionally, in the 2023 IRP PP, the Company indicated that a Natrium project would be
in place by 2030. However, in this IRP, the Company extended the timeline by two years.
Given the importance for this type of resource in the Company's portfolios, Staff is concerned
this nuclear resource may not be available when expected. The delay could shift resource
selections in future IRPs and could inflate the cost of future resources due to the uncertainty.
Staff believes the Company should take necessary efforts to determine the actual timing of this
resource, so the Company does not get locked into short-term alternatives that are not least-cost
and least-risk over the long-term.
Front Office Transactions ("FOTs')
In developing the integrated PP, the Company did not count FOTs towards the WRAP
resource adequacy compliance requirements because WRAP only allows specified sources to
count towards its compliance, and most of the standard market purchases come from unspecified
sources. Staff Comments in Case No. PAC-E-25-08 at 3. However, the Company stated that
"[w]hile 2025 IRP does not allow FOTs to meet WRAP compliance requirements, PacifiCorp
STAFF COMMENTS 14 OCTOBER 7, 2025

expects to continue pursuing economic short-term and intermediate-term market opportunities
that assist with WRAP compliance and/or balancing." 2025 IRP at 178.
The Company agreed to include FOTs in the Load and Resource Balance ("L&R") in
Case No. PAC-E-25-08 and stated that"some short-term resource opportunities are likely to
exist in the future as various utilities and market participants are likely to have excess supply in
some periods and insufficient supply in others." Company's Reply Comments in Case No. PAC-
E-25-08 at 3. Staff believes that not counting FOTs in the integrated PP could result in
overbuilding resources. Therefore, Staff recommends that the Commission direct the Company
to meet with Staff to explore how to balance between meeting the WRAP resource adequacy
compliance and avoiding overbuilding resources.
Demand-Side Management("DSM")
The Company's near-term action plan calls for cost-effective acquisition of EE and
Demand Response ("DR")resources that provide annual system capacity and energy selections.
2025 IRP at 17. A portion of these selections are provided by Idaho EE selections. The
Company explains that because DSM resources compete with supply side resources,
optimization of DSM resources results in selection of all cost-effective options. 2025 IRP at 8.
The Company contracted with a third party to conduct a Conservation Potential Assessment
("CPA") for the 2025 IRP. 2025 IRP at 171. This assessment provided a broad estimate of
demand-side resource characteristics to inform modeling of these resources in competition with
supply-side alternatives. Id. at 172.
EE Programs
In its near-term action plan, the Company identifies system-level EE selections totaling
2,413 GWh of energy and 610 MW of capacity by 2028. 2025 IRP Vol I at 3. Idaho
contribution to this total is 89.7 GWh and 21.6 MW. 2025 IRP Appendix D supporting
workpapers. EE selections are made by selecting groups of measures bundled by the
temperature dependence and timing of savings. In the Company's model, Idaho had 25 measure
bundles with 12 related to measures that save the most during the summer. 2025 IRP—Volume
II: Appendix D at 96. The Company's IRP indicates that all Idaho bundles were selected. Id.
Staff believes that this methodology is reasonable.
STAFF COMMENTS 15 OCTOBER 7, 2025

DR Programs
In its near-term action plan, the Company identifies system-level DR selections totaling
83 MW of capacity by 2028. 2025 IRP—Volume I at 3. Idaho contribution to this total is
negligible, showing no Idaho DR capacity selected until 2030. 2025 IRP Appendix D at 94. In
the 2023 IRP, the cumulative Idaho DR selection was 55.6 MW by the end of the forecast
horizon. 2023 IRP Appendix D at 108. In 2025, Idaho DR potential across the 2025 forecast
horizon totaled 27 MW. CPA at 60-61. The overwhelming majority of this new potential is
related to irrigation load control programs with 16.2 MW. Id. The next highest potential is in
heating ventilation and air conditioning direct load control programs with 3.2 MW. Id. The
CPA Explains that expansions to the existing irrigation load control programs after the 2023
CPA have reduced the availability of incremental potential. Id. Staff believes that these
assumptions are reasonable.
Analysis of Reliability
Staff believes the Company should include an additional verification step to confirm that
the selected PP meets the defined loss of load expectation("LOLE")target. The 2025 IRP
modeling steps incorporate WRAP compliance requirements for the PRMs starting from 2028
and continues through the study horizon. WRAP defined a PRM of 14.4% for summer months
(based on July 2025 projections) and 16.8% for winter months (based on December 2025
projections) of additional capacity the Company needs to ensure a LOLE target of 1-event-day in
10 years, or 2.4 event hours per year. 2025 IRP—Volume I at 131. Staff believes that WRAP-
defined PRMs vary significantly from month to month and year to year, and using a fixed
amount of PRM for the full IRP period of 21 years can potentially alter the cost and risk factors
of the PP.
The defined PRMs act as adjustment factors to increase the amount of load that the
resource plan must meet; however, without a process to mathematically verify whether the
portfolios meet the LOLE target is not outlined in the 2025 IRP. Staff believes that once the
portfolios are developed, the Company should be able to verify whether the resulting portfolios
met the original target as a feedback loop. This feedback loop and final verification step is
important because portfolios with a significant number of variable resources may require a
higher PRM than a portfolio with a higher concentration of dispatchable resources for a given
STAFF COMMENTS 16 OCTOBER 7, 2025

reliability target. Therefore, Staff recommends that the Company provide greater clarity relative
to these expectations in future IRPs.
Idaho-Specific Portfolio
The Company started with three jurisdictional portfolios (i.e. the Oregon jurisdiction, the
Washington jurisdiction, and the Utah/Idaho/Wyoming/California jurisdiction) in the 2025 IRP
process to arrive at the system integrated PP. Staff would like to explore the possibility of
developing an Idaho-specific portfolio for the next IRP. Therefore, Staff recommends that the
Commission direct the Company to meet with Staff to explore such a possibility before the next
IRP. This recommendation is aligned with Staff s recommendation in Case No. PAC-E-25-08,
the Company's capacity deficiency period case.4
First, the Company creates each jurisdictional portfolio by excluding the constraints and
requirements of other jurisdictions (except for load requirements). Response to Staff Production
Request No. 4 (a). Second, the Company integrates jurisdictional portfolios into an integrated
PP by adopting the largest quantity of each resource across all jurisdictional portfolios by year as
the cumulative amounts of resources to be built for the system. Response to Staff Production
Request No. 5 (a). Third, resources selected from the Eastern jurisdictional portfolio (i.e. the
Utah/Idaho/Wyoming/California jurisdiction) are assigned to Utah/Idaho/Wyoming/California in
the integrated PP; and resources selected from the Western jurisdictional portfolios (i.e. the
Oregon jurisdiction or the Washington jurisdiction) are allocated as 75 percent to Oregon and 25
percent to Washington customers. Response to Staff Production Request No. 5 (d). Lastly, since
Idaho is combined with Utah, Wyoming, and California, it is difficult to know the amounts of
resources that need to be planned for, from the perspective of Idaho. Therefore, Staff
recommends that the Commission direct the Company to meet with Staff to explore the
possibility of developing an Idaho-specific portfolio before the next IRP.
Action Plan
The IRP contains an action plan section that provides a status update of action items from
the Company's 2023 IRP as well as 2025 IRP action plan which"identifies the steps the
4 In Case No.PAC-E-25-08,capacity deficiency was determined based on a L&R before new resources were added.
In the IRP,the preferred portfolio included new resources selected to meet the Company's capacity needs.
STAFF COMMENTS 17 OCTOBER 7, 2025

company will take over the next two-to-four years to deliver a least-cost, least-risk portfolio for
customers, based on the resources and requirements identified in its preferred portfolio, with a
focus on the front five years of the planning horizon." 2025 IRP at 303.
The Company's 2023 IRP action plan status update includes items spanning its service
territory. Staff believes the Company is continuing to move forward with, or has reasonably
accomplished, many of its Idaho-specific action items. The 2023 IRP action plan items related
to Idaho includes the following:
• EPA requirements and the planned path forward to maintain compliance;
• Boardman to Hemingway, Energy Gateway South, and Energy Gateway West
transmission lines;
• Energy Efficiency and Demand Response targets; and
• Renewable Energy Credit Sales.
The Company's 2025 IRP action plan includes items spanning its service territory. The
2025 IRP action plan items related to Idaho include the following:
• EPA requirements and the planned path forward to maintain compliance;
• Gateway West segments D.3 and E:
o Note, B2H is being reevaluated and is absent from the 2025 IRP action plan.
• Energy Efficiency and Demand Response targets:
o Identifying a decrease in EE annual capacity forecast of 64% in 2025 and 55% in
2026; and
o Identifying a decrease in DR annual incremental capacity forecast of 88% in 2025
and 98% in 2026.
These items are discussed in greater detail within the EE Programs and DR Programs
sections above.
STAFF RECOMMENDATION
Staff recommends that the Commission acknowledge the Company's 2025 IRP,
submitted on March 31, 2025. Further, Staff recommends the Commission direct the Company
to:
1. Justify the selection of the Company's PP when other portfolios perform consistently
better across potential alternative futures;
STAFF COMMENTS 18 OCTOBER 7, 2025

2. Perform additional analysis by applying "end effects" or similar conditions under
each PPS for all competing portfolios in the future IRPs;
3. Review its practices for hedging natural gas-fuel supply to mitigate
fuel supply risks and dependence on natural gas for dispatchable generation;
4. Meet with Staff to explore the possibility of developing Idaho-specific portfolios
prior to the next IRP;
5. Meet with Staff to explore how to balance between meeting the WRAP resource
adequacy compliance and avoiding overbuilding resources;
6. Provide more specific information to the Commission before the next IRP regarding
removal of new large customer loads, how these customers plan to serve their own
loads, and the impact on the Company's system and on Idaho customers;
7. Provide the Commission with its re-evaluation study before the next IRP regarding
the need and timing of the 132H transmission line;
8. Provide an incremental analysis showing how the types of resources would change as
a result of some of the most recent federal policies under the new presidential
administration; and
9. Provide greater clarity whether the LOLE reliability target of 2.4 event hours per year
is achieved by the developed integrated preferred portfolios in future IRPs.
Respectfully submitted this 7th day of October 2025.
7
Jeffrev R. Loll
Depury Attorney General
Technical Staff. Shubhra Deb Paul
Seungjae Lee
Yao Yin
Jason Talford
Vicki Stephens
I:\Utility\UMISC\COMMENTS\PAC-E-25-12 Comments.docx
STAFF COMMENTS 19 OCTOBER 7, 2025

Attachment No. A
2025 IRP Portfolios
Table No. 2: A List of All Integrated Jurisdictional Portfolios of the 2025 IRP and Their
Descriptions
Portfolio Name Description
Integrated Base MN* Medium gas price, zero CO2 costs.
Integrated Base LN Low gas price, zero CO2 costs.
Integrated Base HH High gas price, high CO2 costs.
Integrated Base MR Medium gas price, with at-risk federal regulations.
Integrated No CCS MN MN policy, with no coal units are able to select CCS technology.
Integrated No Nuclear MN MN policy, with no nuclear resources are eligible for selection.
Integrated No Coal Post MN policy, with all coal resources must retire or convert by
2032 MN January 1, 2032.
Integrated Offshore Wind MN policy, with high-capacity factor offshore wind resources.
MN
Integrated No Future Tech MN policy, with no nuclear, hydrogen or 100- hour storage, or
MN biodiesel peaking.
Integrated Geothermal MN MN policy, with high-capacity factor geothermal resources.
Integrated Hunter Retire MN policy, with all Hunter units to retire no later than January 1,
MN 2030.
Integrated No CCS MR MR policy, with no coal units are able to select CCS technology.
Integrated Base SC SCGHG Price-Policy Scenario.
*Company selected Preferred Portfolio
ATTACHMENT NO. A
CASE NO. PAC-E-25-12
STAFF COMMENTS 20 OCTOBER 7, 2025

Attachment No. B
2025 IRP Portfolio Rankings
Table No. 3: Summary of the 2025 IRP Portfolio Rankings in Various Alternative Future
PPSs
Portfolio Ranks in Various Alternative Future Price-Policy Scenarios
Medium Gas/ Medium Gas/ Low High Gas, Medium Gas/
Zero CO2 Zero CO2 Gas/Zero Coal/High Social Cost
(ST) w/End CO2 CO2 of CO2
Portfolio Name: Effects (ST) (ST) (ST)
Integrated Base MN* 4 1 5 8 8
Integrated No CCS MN 6 6 8 11 11
Integrated No Nuclear
9 7 12 10 4
MN
Integrated No Coal Post
7 8 6 4 5
2032 MN
Integrated Offshore
13 13 13 13 13
Wind MN
Integrated No Future
10 10 9 12 10
Tech MN
Integrated Geothermal
11 11 10 9 9
MN
Integrated Hunter
1 3 2 3 2
Retire MN
Integrated Base MR 3 5 1 2 3
Integrated No CCS MR 8 9 7 5 6
Integrated Base LN 5 4 4 6 12
Integrated Base HH 2 2 3 1 1
Integrated Base SC 12 12 11 7 7
*Company's selected Preferred Portfolio
ATTACHMENT NO. B
CASE NO. PAC-E-25-12
STAFF COMMENTS 21 OCTOBER 7, 2025

CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 7TH DAY OF OCTOBER 2025,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. PAC-E-25-12, BY E-MAILING A COPY THEREOF, TO THE
FOLLOWING:
MARK ALDER DATA REQUEST RESPONSE CENTER
JOE DALLAS PacifiCorp
ROCKY MOUNTAIN POWER 825 NE MULTNOMAH, SUITE 2000
1407 WEST NORTH TEMPLE STE 330 PORTLAND, OR 97232
SALT LAKE CITY UT 84116 E-MAIL ONLY:
E-MAIL: mark.alderkpacificorp.com datarequest(kpacificorp.com
joseph.dallas(&,pacificorp.com irp(a,pacificorp.com
PATRICIA JORIAN, SECRETARY
CERTIFICATE OF SERVICE