20251112Comments.pdf

RECEIVED
November 12, 2025
Benjamin J. Otto, ISB No. 8292 IDAHO PUBLIC
1407 W Cottonwood Crt. UTILITIES COMMISSION
Boise, Idaho 83702
Tel: [phone]
[e-mail]
Attorney for the Renewable Northwest and the Northwest Energy Coalition
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER ) CASE NO. IPC-E-25-23
COMPANY'S 2025 INTEGRATED ) COMMENTS
RESOURCE PLAN. )
NORTHWEST ENERGY COALITION AND
RENEWABLE NORTHWEST
I. INTRODUCTION
Renewable Northwest("RNW") and NW Energy Coalition ("NWEC") submit this comment on
Idaho Power Company's ("Idaho Power" or"the Company") 2025 Integrated Resource Plan
("IRP"). Idaho Power's approach to resource planning adopts many best practices.' The
Company engages stakeholders to craft IRP modeling scenarios and solicits feedback. The
Company links resource adequacy assessments with resource planning to some extent. The
Company relies on recent data for the development of inputs, plans for large loads, and models
multiple storage candidate resources. The Company conducts scenario-based modeling with
additional sensitivities to better evaluate risk and uncertainty. And Idaho Power's assessment of
regional transmission opportunities presents new ways to achieve reliable and affordable energy
services. Still, there are areas in this IRP where Idaho Power's approach should be improved—
specifically in assumed resource costs; assessment of thermal reliability, fuel supply and price
risks; transparency and flexibility for new large loads; and a fulsome evaluation of the risks
presented by each portfolio.
In the comments that follow, RNW and NWEC reflect on the Company's significant change in
direction from their 2023 IRP, highlight some weaknesses in the 2025 IRP's input assumptions,
1 Bruce Biewald et al,Best Practices in Integrated Resource Planning, Synapse and LBNL(Dec 6,2024),
httas://www.svnaDse-energv.com/sites/default/files/IRP Best Practices 2024 Synapse LBNL 24-061 1.Ddf
IPC-E-25-23 NWEC and RNW Comments 1
November 12,2025

and offer suggestions to ensure the selection of the least-cost,least-risk plan for the Company's
customers. Overall,we are surprised to see Idaho Power turn away from the work presented in the 2023
IRP that put the Company on track to reach its internal goal of 100%clean energy by 2045.
II. COMMENTS
a. Resource cost assumptions stray from industry benchmarks and are fraught with
significant variability, creating unacceptable levels of uncertainty and risk in the
2025 IRP results.
Resource cost assumptions are one of the most critical inputs in long-term capacity expansion
("LTCE")modeling. Optimized LTCE modeling tools, such as Aurora, seek to minimize
portfolio costs while serving system load, meeting the planning reserve margin ("PRM"), and
satisfying model constraints. The LTCE model evaluates the relative costs and capabilities of
resources when selecting the best candidates to build in each year of the study. Because resource
assumptions are so fundamental to optimized resource planning, they garner significant attention.
The dynamic nature of the industry today can render input assumptions developed at the
beginning of the IRP process outdated by the time capacity expansion modeling is conducted.
This is particularly true for resource costs. As explained further below,we have four concerns
regarding the Company's resource cost assumptions: understated costs for gas-fired resources,
overstated costs for wind, understated costs for storage resources, and unrealistic escalation
factors for future costs.
Because the IRP is a forward-looking planning document, the Company and the Commission
must consider the most up-to-date resource costs when evaluating the trajectory laid out by the
Company's preferred portfolio. We acknowledge that recent policy decisions at the national level
have affected future resource costs. But that does not obviate the need for rigorous assessment of
forecasts that are prudently conservative and reflect the full range of recent,demonstrable market
uncertainty. We are not saying Idaho Power should have used resource cost estimates published
after the IRP process was largely competed. Rather, we provide this updated resource cost
information to guide the Commission's evaluation of the IRP process and assessment of the risks
posed by Idaho Power's preferred portfolio.
IPC-E-25-23 NWEC and RNW Comments 2
November 12,2025

1. Assumed costs for gas-fired resources are approximately 25%below benchmark data.
In the 2025 IRP, the Company adopted capital costs of$1,650/kW for a new CCCT and
$1,200/kW for a new SCCT.2 A recently published study found publicly available datasets
underestimate the costs for new CCCT and new simple SCCT resources as the datasets lag the
most current market conditions.' The study reviewed seven public IRPs and datasets with near-
term capital and fixed costs for combined cycle combustion turbine ("CCCT") and new simple
cycle combustion turbine ("SCCT")resources.4,1,6,1,8,9 Cost estimates varied significantly across
sources for combustion turbine-based resources reflecting the dynamic nature of the combustion
turbine market. The study levelized the capital and fixed cost assumptions for all resources
across these public benchmarks and inflated all dollars to a 2026-dollar year to achieve a fair
comparison. The median data point is used for each resource type to avoid unfair representations
from singular high or low references that can skew the average. Note, this analysis does not
consider the variable cost of dispatching these units.
Along with evidence in recent Certificates of Public Convenience and Necessity("CPCN")
docket in other states, this analysis indicates the Company should model capital costs of at least
$2,000/kW for CCCTs and $1,500/kW for SCCTs units coming online in 2030 or later. Further,
current industry trends show the lead-time to acquire new SCCT or CCCT turbines is five to
seven years.10 Idaho Power's resource cost estimates must match this future time. On this basis,
the Company's cost assumptions for new SCCTs and CCCTs reflect a 25% discount relative to
these latest published benchmarks which are known to lag behind and underestimate latest
market prices.
2 Idaho Power 2025 IRP,Appendix C at 22.(Note,while the Company's Preferred Portfolio builds reciprocating
internal combustion engine("RICE")resources,our cost review is focused on SCCT and CCCT resources.RICE
units were more difficult to fairly compare in our review of the publicly available datasets due to heterogeneity in
technology assumptions and a dearth of cost data compared to SCCT resources.)
s The New Reality of Power Generation,An Analysis of Increasing Gas Turbine Costs in the U.S.,Gridlab(Sept
2025).https:Hgfidlab.org/gas-turbine-cost-report/.
4 https:Hatb.nrel.gov/electricity/2024/about.
5 Assumptions to the Annual Energy Outlook 2025:Electricity Market Module.P 7- 8. (April 2025).
6 PacifiCorp 2025 IRP.Volume 1.P 149- 158&P167- 169.
Lazard Levelized Cost of Energy+.P34-39.(June 2025).
8 Portland General Electric 2023 CEP/IRP Update.P 96.
9 Avista 2025 IRP.P 190.
10 Mark Shenk,Rush for US gas plants drives up costs,lead times.Reuters(July 21,2025),
https://www.reuters.com/business/energy/rush-us-gas-plants-drives-up-costs-lead-times-2025-07-21/
IPC-E-25-23 NWEC and RNW Comments 3
November 12,2025

The dynamic nature of the industry today places significant uncertainty on both the cost of new
thermal generation and the lead time for procurement. Again, we offer this analysis to inform the
Commission about the trajectory in Idaho Power's preferred portfolio and to highlight the
significant risk gas resources will be far more expensive when the Company seeks to acquire
them than shown in the 2025 IRP. This creates significant risk for Idaho Power's ratepayers and
calls into question whether the Company's heavy reliance on thermal generation assets aligns
with a least-cost, least-risk outcome.
2. Assumed costs for wind generation are approximately 30%above benchmark data.
We also found cost estimates for new wind generation to vary considerably, with the Company
using the highest costs among sources reviewed. Based on Idaho Power's data, we calculated a
levelized cost of more than $240/kW-Yr, representing a 30%premium over the median of all
sources surveyed. While the Company anticipates the highest costs for wind generation, its
forecast is not totally alone. One other publicly available source projects costs above $225/kW-
yr. All other sources forecast levelized costs between $150 and$180/kW-Yr. Based on this mix
of data, we calculated a median levelized cost of approximately $185/kW-Yr for new wind
resources as a reasonable benchmark. For wind, Idaho Power's cost forecast is an outlier that
strongly depresses the LTCE model's selection of new wind capacity despite strong wind
resources in the upper mountain west. The Company's reliance on such a high-cost assumption
introduces a significant bias into its resource planning,ultimately undermining the goal of
achieving a least-cost outcome for ratepayers.
In the 2023 IRP, the Company included a candidate wind resource in Wyoming. This candidate
was a lower-cost, higher-capacity-factor resource than the local Idaho wind resource candidate.
The Preferred portfolio in the 2023 IRP built 1,800 MW of economic wind projects from 2027 to
2032 contingent upon the completion of Gateway West. Given the relative quality and cost of the
Wind-Wyoming candidate resource, we can assume that the Wyoming resource comprised much
of the Company's 2023 IRP wind capacity. The 2025 IRP does not address the removal of this
resource candidate, but does continue to pursue Gateway West and other transmission projects
IPC-E-25-23 NWEC and RNW Comments 4
November 12,2025

that are key enablers of clean energy imports to the system. The removal of the Wyoming wind
candidate serves to depress wind expansion realized by the 2025 IRP's LTCE portfolios. This
omission is an example of the Company's change in direction from a renewables-forward
portfolio in 2023 to a 2025 portfolio that leans more heavily on new thermal generation.
3. Assumed costs for storage resources are 1 S% to 45%above benchmark data.
Levelized cost forecasts for new 4-hour battery storage candidates provide a clearer picture
among the data sources we reviewed. All of the sources we reviewed expect new 4-hour battery
storage candidates to range from $160 to $180/kW-Yr. The Company's 2025 IRP forecast cost in
the upper end of the distribution,just shy of the 75th percentile. Further, for new 4-hour battery
storage resources built in 2030, Idaho Power's assumptions exceed the Company's own 2023
forecast by 15%, the 2023 Portland General Electric ("PGE") IRP forecast by 38%, the 2024
NREL Annual Technology Baseline ("ATB") by 21%, and NREL's 2025 Battery Storage
Update forecast by 45%.
Where the Company forecasts diverge from others is in technology maturity curves. Across all
clean energy resources, the Company's assumptions predict flat or limited cost reductions in the
near-term, followed by steady, linear reductions. Delays in cost reductions will have a significant
impact on least-cost resource selection in the critical years of the early 2030s. Barring a
generational pandemic and subsequent disruption of supply chains and manufacturing, lithium-
ion battery costs have fallen year-over-year.I I The National Renewable Energy Laboratory's
("NREL") latest 2025 battery storage cost update for storage resources anticipates a reduction in
overnight capital costs of 27%by 203512 while the escalation factors for the 2025 IRP forecast a
reduction of approximately 7%.
Forecasting resource costs is challenging, and no single forecast will likely be 100% correct.
Still, the Company's forecasts for resource cost declines reflect a very conservative view that
11 Lithium-Ion Battery Pack Prices See Largest Drop Since 2017,Falling to$115 per Kilowatt-Hour:Bloomberg
New Energy Finance,(Dec. 10,2024),
https://about.bnef.com/insights/commodities/lithium-ion-battery-hack-prices-see-largest-drop-since-2017-falling-to-
115-per-kilowatt-hour-bloombergnef/
12 Wesley Cole et al.,Cost Projections for Utility-Scale Battery Storage:2025 Update,NREL(June 2025),
https://docs.nrel.2ov/docs/fv25osti/93281.pdf
IPC-E-25-23 NWEC and RNW Comments 5
November 12,2025

diverges from other publicly available data sources, including industry reports and utility IRPs.
Significant cost declines in lithium-ion battery storage technologies, specifically, have been
reported in recent years as the industry recovers after COVID. The Company should avoid
relying on `delayed cost reduction' scenarios in its base capacity expansion analysis. These
delays have a material impact on the resulting portfolio. Anchoring base assumptions to
consensus trajectories will provide a better foundation for LTCE modeling and better ensure the
pursuit of least-cost, least-risk outcomes. Absent this analysis, it is unclear whether the preferred
is in the best interests of its customers.
b. Idaho Power's risk assessment misses key reliability and volatility concerns.
1. The Company assesses the reliability of variable energy resources and energy limited
resources, but omits key reliability considerations for thermal resources.
Along with least cost, the preferred portfolio should also expose customers to the least risk
feasibly possible. A key consideration here is whether selected resources will be available to
meet energy demands. Evaluating the Effective Load Carrying Capacity("ELCC") is critical to
capture the reliability contributions of variable energy resources ("VERs") and("ELRs") in
LTCE studies. As more of these resources are brought onto the system, their capacity
accreditation becomes more dynamic and fundamental to system reliability. For example,
ELCCs are known to decline for stand-alone solar installations as their contribution to the
afternoon peak load saturates. Alternatively, the combined effects of renewable and storage
resources elevate their combined ELCC.13 ELCCs, though more computationally intensive to
calculate, are necessary metrics because they define the reliable capacity for a portfolio of new,
clean resources that are poorly suited for classical reliability metrics developed for thermal
resources such as Unforced Capacity ("UCAP") and Equivalent Demand Forced Outage Rate
Demand("eFORd").
For thermal resources, assumptions around forced outage rates, derates, loss of fuel, and other
outage types can be adopted to calculate ELCCs and reflect the reality that their reliable capacity
will be less than nameplate. The Company's reliance on ELCC, Planning Reserve Margin
"Kevin Carden et al.,Effective Load Carrying Capability Study:Prepared for ERCOT,Astrape Consulting(Dec 7,
2022),httns://www.ercot.com/files/docs/2022/12/09/2022-ERCOT-ELCC-Study-Final-Report-12-9-2022.ndf
IPC-E-25-23 NWEC and RNW Comments 6
November 12,2025

("PRM") and eFORd is limited to assessing the physical reliability-this is important, but not
complete. For example, this metric does not consider operating with frequent daily cycling to
integrate variable energy resources that is more stressful than traditional baseload service and
can cause faster performance degradation than implied by historical Generating Availability Data
System("GADS") data. Moreover, this metric does not fully capture the fuel supply risks from
constrained or disrupted pipelines or competing uses during extreme cold weather events. And
the use of a reliability metric (EFORd)has no bearing on the financial risk to customers from
escalating gas prices. To ensure a least cost and least risk portfolio, the IRP must clearly and
comprehensively address the risks of fuel supply curtailments and price volatility.
This omission repeats a finding by RNW in the 2023 IRP. We are particularly concerned about
the risk assessment of thermal resources. Idaho Power's preferred portfolio continues to include
plans to convert coal units to gas-fired generation. It is important to note that the existing coal
assets are almost 50 years old. Even if converted to gas, as these aging units approach the end of
their design life, their risk of forced outages increases, making them less reliable.14 Determining
a least-cost, least-risk portfolio requires a balanced treatment of thermal resources, VERs, and
ELRs. We look forward to improving this balance in the next IRP cycle.
2. The Company's increased reliance on new thermal capacity exposes the system to
fuel price volatility and supply risk.
The preferred portfolio for the 2025 IRP builds 450 MW more new thermal resources than the
2023 IRP preferred portfolio between 2029 and 2032. The composition of the 2025 builds
suggests the LTCE built a 150 MW SCCT in 2029 and a 300 MW CCCT in 2030. Over the same
time period, the 2025 IRP reduced wind capacity by 900 MW, solar by 300 MW, and storage by
215 MW. The 2025 preferred portfolio will lean more heavily on thermal generation for both
capacity and energy. The system's reliance on gas will increase accordingly. The volatility of gas
prices will introduce additional risk to the preferred portfolio's ability to realize a lowest-cost,
lowest-risk future. For example, the Company's "Low Gas Price" and"High Gas & Carbon
Prices"portfolios result in the lowest($10.16B) and the highest ($14.16B) total costs,
14 2024 State of Reliability,NERC(June 2024),
httas://www.nerc.com/na/RAPA/PA/Performance%20Analysis%20DL/NERC SOR 2024 Technical Assessment.])
df
IPC-E-25-23 NWEC and RNW Comments 7
November 12,2025

respectively. The costs of these gas price sensitivities, relative to the preferred portfolio
($10.96B), suggest the Company's capacity to reduce costs under a low gas future
(-$0.80B) is significantly smaller than the increased cost risk(+$3.20B)that a high gas cost
future presents the system. Based on these portfolio results, a reduction in thermal generation is
likely to reduce system cost risks.
The Company will need expanded capacity at the Northwest Pipeline to support additional gas
generation resources. The 2025 IRP models this increased expense as an additional $0.50 to
$1.20/MMBtu on the gas fuel price. Gas prices for the 2025 IRP are based on the 2023 U.S.
Energy Information Administration ("EIA") Annual Energy Outlook("AEO") "Low Oil and Gas
Supply." If we adopt the average price over 2030-2039, $6.23/MMBtu($2024), the Northwest
Pipeline expansion cost adder is expected to increase fuel price by 8%to 19%. Over the study
horizon,the years in which new resources can be selected by the LTCE study (2029-2045), the
gas price is forecasted to increase by 24% in addition to this Northwest expansion cost adder.
RNW and NWEC are not convinced that adding additional gas to achieve "fuel risk diversity"
will reduce risks for customers. On the contrary, the Company's sensitivity analysis actually
highlights the disproportionate financial risk associated with the reliance on new thermal
capacity. The Company needs to justify why a "Reduced Gas" or "Gas Deferred" portfolio,
which minimizes or defers the 450 MW of capital-intensive, fuel price volatility exposed thermal
capacity is not the true optimal choice. This portfolio would capture nearly all of the operational
flexibility and transmission benefits cited by the Company,while simultaneously minimizing the
exposure to the $3.20 B downside risk identified in their own sensitivity analysis. The issue is
not diversity between gas supply sources, rather diversity of generation sources to mitigate the
overall risk of gas price volatility.
Beyond fuel price risk associated with Northwest Pipeline expansion and market volatility, the
fuel supply strategy is a work in progress. The feasibility and timeline for the expansion of the
Northwest Pipeline are not adequately addressed in the 2025 IRP. The Company states... the
"[fuel supply] expansion options are fluid and this is an area that the company is actively
IPC-E-25-23 NWEC and RNW Comments 8
November 12,2025

monitoring."15 Merely stating the Company is monitoring a fluid situation is not the same as
addressing the actual ability, timeline, and cost to increase gas delivery capacity to Idaho. On any
given day, the Company expects to procure additional transportation capacity via the short-term
capacity release market, further jeopardizing the certainty of the supply and delivered price.
Taken together, a portfolio that relies more heavily on thermal resources is likely to suffer higher
and more volatile fuel costs, greater supply and transportation uncertainty, and elevated
reliability and ratepayer risk. The interdependency between the electric and gas systems
increases reliability and ratepayer risk, demonstrating that the preferred portfolio is likely far
riskier and more volatile than the Company acknowledges.
c. NWEC support Idaho Power's use of the RCAT tool to validate the LTCE portfolio
reliability.
Utility resource planning too often relies on an"open loop"process for the development of input
assumptions, resource selection, reliability validation, and performance evaluation. Input
assumptions are often developed in collaboration with external consultants and passed along to
the resource planning process. Given all input assumptions, a utility will conduct LTCE studies
across various scenarios to arrive at an"optimal"portfolio. In this "open loop"process,
information moves in a single direction from inputs to outputs without feedback from proximate
steps. The long time-horizon and complex nature of integrated system planning studies make
them organizationally and computationally expensive to conduct. LTCE studies have to rely on
sampled chronologies, such as one week per month, to optimally and efficiently select new
resources over a long time horizon. This "open loop"process and sampled chronology can
misrepresent the reliability of an LTCE portfolio.
Idaho Power has recognized the limitations of using Aurora LTCE studies to ensure a reliable
system and introduced its RCAT tool: "[T]he Aurora LTCE model used in the 2025 IRP cannot
currently calculate the dynamic diversity benefit caused by a changing resource mix."16 We
applaud the Company's introduction of the RCAT tool into a feedback loop with the Aurora
15 Idaho Power 2025 IRP,Ch.8,page 94.
16 Idaho Power 2025 IRP,Appendix D,page 8.
IPC-E-25-23 NWEC and RNW Comments 9
November 12,2025

LTCE studies to ensure that the resulting portfolio's capability to meet the LTCE's planning
reserve margin aligns with RCAT's LOLE-derived capacity requirement. This iterative approach
also helps ensure that the ELCC assumptions provided to the LTCE model are tuned to the
portfolio composition. The RCAT to LTCE back-and-forth sharpens the portfolio's reliability
evaluation.
d. RNW and NWEC recommend the Company and Commission create more
transparency and rigor to future new large-loads forecasts and flexibility.
1. Idaho Power's preferred capacity expansion portfolio risks over procurement of capacity
for load growth that is unprecedented.
The Company forecasts total system peak load to increase by 1.1 GW from 2026 to 2032." Over
the same period, the Company expects to add 800 MW of additional firm load from its largest
customers",representing—72% of the total forecasted system peak load. Over this period, the
preferred portfolio builds 1.2 GW of dispatchable thermal generation and storage capacity. In the
Company's 300 MW large load sensitivity, the capacity expansion model adds a 300 MW CCCT
in 2032 on top of the preferred portfolio. In the Company's 500 MW large load sensitivity, the
capacity expansion model adds a 150 MW SCCT in 2032 and a 300 MW CCCT and a 155 MW
battery in 2033, 605 MW in total, on top of the preferred portfolio. These sensitivities suggest
that large-load growth will require significant firm capacity, nearly one-to-one, in the coming
years.
Significant growth of large-loads introduces risks and opportunities for the Company and its rate
payers. Thoughtful planning, interconnection processes, and novel rate design will be required to
balance the economic potential of large-loads against the reliability and cost-shifting risks they
exacerbate. The Company's modeling of additional large-load scenarios offers useful
benchmarks for stakeholders and regulators to evaluate the capacity needs and corresponding
costs for a system with even more load than is currently forecasted. There is a reliability risk
present if the Company under-plans for load growth. This reliability risk is most efficiently
mitigated when it is balanced against the risk of over-procurement and stranded assets. In its
17 Idaho Power 2025 IRP,Table 8.2,page 89.
18 Idaho Power 2025 IRP,Appendix A,page 44.
IPC-E-25-23 NWEC and RNW Comments 10
November 12,2025

current form, the IRP does not address this second risk.
These potential large-load customers, such as data centers, are expected to be a key part of the
Company's future plans. The Company has up-corrected its forecast for 2032 additional firm
sales by 200 - 300 MW in every IRP filed since 2019.19 This rapid change in large-load
forecasting reflects the volatility inherent in the still-nascent industry of building,
interconnecting, and operating very large data centers.2°,21 Large-load developers and utility
business development teams hold a shared incentive to locate a new project in the utility's
footprint. Speculative interconnection requests from new large-load developers inflate load
forecasts and weaken the reliability of planning assumptions. Beyond the uncertainty
surrounding the materialization of large-load projects, there exists load ramp uncertainty. An
interconnection request for 100 MW by 2030, with a 20 MW ramp over the first 5 years after
energization, may be delayed throughout construction. The prominence of the large-load forecast
in the Company's total system peak and the large size of individual interconnection requests,
greater than 20 MW, exacerbates the risks posed by the forecast uncertainty. If these large-loads
fail to materialize or ramp on schedule, Idaho Power and its ratepayers risk over-procurement,
stranded assets, and increased costs.
We credit the Company for recognizing the "inherently uncertain"nature of new industrial and
energy service agreement("ESA") customers. The 2025 IRP suggests that the Company is
working to address large-load materialization and ramp uncertainty by only including customers
that have made a"significant binding investment" or"interest indicating a commitment of the
highest probability."An accurate quantification of anticipated large loads and the resource
demand they drive is essential to creating a least-cost, least-risk resource portfolio. As Idaho
Power faces the most significant load growth forecasts in generations, it is imperative the
Company and the Commission provide more transparency and rigor to defining these terms for
the 2027 IRP cycle.
19 Idaho Power 2019 IRP,Idaho Power 2021 IRP,Idaho Power 2023 IRP,Idaho Power 2025 IRP
21 Ian Hitchcock and Merritt Cahoon,Hyperscaler Data Center Buildout:A Sustainability Bane,Boon,or Both?
Nicholas Institute for Energy,Environment&Sustainability,Duke University,(Aug.2025),
httas://nicholasinstitute.duke.edu/publications/hvaerscaler-data-center-buildout-sustainabilitv-bane-boon-or-both
21 Ryan Quint et al.Practice Guidance and Considerations for Large Load Interconnections,Elevate Energy
Consulting and GridLab,(May 2025),
httos:H2ridlab.ore/portfolio-item/practical-guidance-and-considerations-for-large-load-interconnections/
IPC-E-25-23 NWEC and RNW Comments 11
November 12,2025

2. Increased demand-side flexibility from large loads offers a significant opportunity to de-
risk the Company's load forecast and capacity expansion plans.
Recent studies demonstrate how limited, demand-side flexibility from large-loads during the
periods of highest stress can help to mitigate reliability and planning risks.22 Across the country,
98 GW of new load could be integrated on the power grid without additional generation capacity,
if that load is curtailed for just 0.50% of its annual energy demand.21 Among Western Electricity
Coordinating Council ("WECC")balancing authorities evaluated in this study, the average
curtailment-enabled headroom, at a 0.50%rate, was greater than 1 GW. We'll note, 1 GW is
approximately the forecast for additional firm sales in the 2025 IRP. Recent commitments to
enable large-load demand side management demonstrate how utilities, regulators, and large loads
can collaboratively and creatively develop new solutions to serve, and in fact utilize, these large-
load interconnection requests. In August of 2025, Google announced agreements with Indiana
Michigan Power("I&M") and Tennessee Valley Authority("TVA")to enable demand response
capabilities in its datacenters.24
Flexible loads place a smaller burden on system demand. They are less likely to trigger the need
for transmission and generation upgrades,which can allow for accelerated interconnection
processes and reduced pressure on electricity rates. Idaho Power's data showing the loss of load
expectations for each hour reveals substantial opportunities to shift loads to off-peak hours as
well as the limited number of hours where available capacity is highly stressed. The Company
has years of experience with demand response programs and can build on this knowledge.
Because the 2025 IRP shows drastically increasing loads and resource needs, the assessment of
Demand Response opportunities the Company used is stale. Now is the time to reassess the
potential for flexibility in new large loads.
The development of innovative large-load tariffs will be a key tool for utilities to benefit
22 Powering Intelligence:Analyzing Artificial Intelligence and Data Center Energy Consumption,EPRI(May 28,
2024),https://www.epri.com/research/nroducts/3002028905
23 Tyler Norris et al,Rethinking Load Growth:Assessing the Potential for Integration of Large Flexible Loads in US
Power Systems,Nicholas Institute for Energy,Environment&Sustainability,Duke University(2025),
httas://nicholasinstitute.duke.edu/sites/default/files/publications/rethinking-load-growth.odf
24 Michael Terrell,How we're making data centers more flexible to benefit power grids,Google(Aug.4 2025),
https://blo 2.Qoo2le/inside-eoo2le/infrastructure/how-were-makine-data-centers-more-flexible-to-benefit-Dower-grid
s/
IPC-E-25-23 NWEC and RNW Comments 12
November 12,2025

economically from the data center boom while efficiently managing cost and reliability risks.
Now is the time to increase the requirements for, and the support to achieve, more flexibility
from large customers. This will complement the Clean Energy Your Way program whereby large
customers can acquire new energy resources to be delivered over Idaho Power's system.
e. RNW and NWEC support the Company's continued commitment to regional and
inter-regional transmission development.
Idaho Power recognizes the critical role transmission expansion plays in building a reliable, low-
cost, and adaptable power system. Transmission expansion provides the Company with avoided-
capacity benefits from accessing regional load diversity, increased revenue from off-system
sales, improved integration of renewable resources, efficient market operations, and facilitates
new industry growth.
In the 2023 IRP, the Company highlighted Boardman to Hemingway's ("B2H") importance to its
100% clean energy by 2045 goals. Specifically, B2H plus the acquisition of capacity at Four will
provide the company access to high-quality solar generation and wind potential in the Desert
Southwest.25 B2H will allow clean hydroelectric generation in the Pacific Northwest to be shared
with the Mountain West, while the Upper Mountain West's wind generation can more easily
serve load in the Pacific Northwest.26 Further, Gateway West, will help to relieve on-system
transmission constraints and integrate additional wind and solar generation from the eastern
portion of the state and neighboring Wyoming. For the 2025 IRP, Idaho Power determined that
acquiring capacity to import power along the SWIP-North line will further benefit the system at
customers. In this way, transmission expansion supports Idaho Power's 100% Clean by 2045
goals and improves system reliability. RNW and NWEC urge Idaho Power to continue to
robustly analyze transmission development to unlock a broad pool of geographically and
technologically diverse resources across a broad footprint to meet customer needs in a least-cost,
least-risk manner.
25 Idaho Power 2023 IRP,Ch.7,page 86.
26 Idaho Power,Boardmen to Hemingway-Purpose and Need,
https://www.idahopower.com/enerev-environment/ener2v/planning-and-electrical-proi ects/current-nroi ects/boardma
n-to-heminLywav/purpose-and-need/
IPC-E-25-23 NWEC and RNW Comments 13
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f. RNW and NWEC recommend the Company update its approach to risk assessment
and documentation to enable a full assessment of portfolio options.
The 2025 IRP's evaluation of portfolios is overly reliant upon portfolio net present value
("NPV")to identify the least-cost, least-risk plan among the scenarios considered. Total system
NPV among the 2025 IRP Main cases differs only slightly. Among cases with the base load
forecast, the most expensive main case, "With I I I(d) Bridger 3&4 CCS" costs 5%more than the
preferred portfolio.2' The IRP process intended to determine a preferred portfolio that balances
costs and risks. With such a narrow range of NPV values among the options, the issue of risk
assessment rises importance. Our recommendation here are intended to help the Commission and
others gain more insight to the risk profiles presented by the portfolio.
Beyond the portfolio costs, the Company presents Stochastic and Qualitative Risk analyses as a
part of its portfolio evaluation.21 The Qualitative Risk Analysis lacks clear values and thresholds
to define what constitutes low, medium, or high risk. Clearly presenting these values and the
rationale behind them would greatly enhance the clarity and usefulness of the analysis. Further,
this analysis is limited to the preferred portfolio with constituent Bridger 3&4 conversion
sensitivities and no gas scenarios. An extension of the Qualitative analysis to other future
portfolio sensitivities would provide insight into the Company's view of these alternatives' risks.
The Stochastic Risk Analysis evaluates the sensitivity of each portfolio's system NPV to select
key inputs. The "Preferred- Bridger 3&4 NG"portfolio is among the scenarios with the highest
likelihood to result in the lowest portfolio cost despite stochastic inputs. The others are the "Low
Gas Price" and"Forced SCCT in 2030"with very similar system NPV distributions. It would be
prudent to balance evaluation of the likeliest results, the peak of the distribution, against the
range of possible results. The Company should provide the 5th and 95th percentile, or some
other measure of variance, of the costs in the stochastic analysis to better quantify the sensitivity,
and therefore uncertainty, of each portfolio to these key inputs.
Ultimately,we recommend that the Company develop a portfolio scorecard to holistically
compare each of the IRP's resource plans. Stakeholders' and regulators' evaluation of portfolios
21 Idaho Power 2025 IRP,Ch. 10,page 114.
28 Idaho Power 2025 IRP,Ch. 10,pages 118-120.
IPC-E-25-23 NWEC and RNW Comments 14
November 12,2025

would benefit from a scorecard that summarizes portfolio performance across key quantitative
(cost, emissions, dispatch), qualitative (regulatory risk, emerging technology), and composite
metrics (resource diversity, market reliance). These metrics should be developed in collaboration
with the IRP Advisory Council ("IRPAC")to identify the suite of metrics that are the most
important to the Company, stakeholders, and regulators. Certainly, cost is a core metric to
evaluate an IRP portfolio, but when total system NPV varies only slightly, it is important to
weigh costs against other important portfolio metrics. A scorecard can synthesize a large amount
of information into a format that is easy for stakeholders and regulators to review and consider.
This scorecard does not replace the content of the Company's risk evaluation,rather provides an
overview and synopsis to guide the Commission and others as they review the more granular
information.
The Company presents the results of its modeling studies across various tables in Chapter 10 of
the IRP. A reader seeking to understand the differences among portfolios across multiple
dimensions must flip back and forth or produce their own side-by-side comparison to understand
how the 5% cost savings realized by the preferred plan are reflected across other important
dimensions. Aspects of this multi-dimensional analysis are present in the IRP, but they are
disjointed. We applaud the Company for attempting to address qualitative risk, the probability
distribution of system NPV, and cumulative portfolio emissions,but there are better ways to
summarize these results. Interstate Power and Light (Alliant Energy)presented a strong example
for a portfolio scorecard in their 2024 Resource Evaluation Study("RES").21 Their portfolio
dashboards, or scorecards, summarize each portfolio along customer affordability, customer rate
stability, flexibility and resource diversity, sustainability, and reliability dimensions. We
recommend that the Company develop a portfolio performance scorecard that captures the
multidimensional nature of integrated resource planning. The scorecard should summarize
portfolio results side-by-side to support transparent decision-making and highlight the relative
strengths and weaknesses of alternatives.
CONCLUSION
RNW and NWEC offer appreciation to both the Commission and the Company for their
29 Interstate Power&Light Company,Resource Evaluation Study(Feb 13,2025).Docket No.RPU-2021-0003
IPC-E-25-23 NWEC and RNW Comments 15
November 12,2025

consideration of these comments. While we applaud Idaho Power's continued work in
developing regional and inter-regional transmission capacity, we are concerned by the
Company's resource cost assumptions, risks assessments, and lack of large load flexibility
considerations undercut the conclusion the preferred portfolio is the least-cost, least-risk future.
Respectfully submitted this 13th day of November, 2025.
A<,
Benjamin J. Otto
ISB No 8292
Attorney for NWEC/RNW
Developed and Supported by:
/s/Lauren McCloy /s/Kyle Unruh
/s/Derek Goldman /s/Mike Goetz
NW Energy Coalition 811 1 st Ave#305 /s/Katie Chamberlain
Seattle,WA 98104 /s/Aaron Menenberg
206-621-0094 Renewable Northwest
[e-mail] 421 SW 6th Ave., Suite 1400
[e-mail] Portland, OR 97204
503-223-4544
/s/Alejandro Palomino [e-mail]
/s/Keegan Moyer [e-mail]
Energy Strategies [e-mail]
111 E. Broadway Suite 1200 Salt Lake [e-mail]
City,Utah 84111
[e-mail]
[e-mail]
IPC-E-25-23 NWEC and RNW Comments 16
November 12,2025

CERTIFICATE OF SERVICE
I hereby certify that on this 12th day of November 2025,1 delivered true and correct copies of the
foregoing COMMENTS of NWEC and RNW in IPUC Docket No. IPC-E-25-23 to the following persons
according to Rule 61.03 via electronic mail only.
Benjamin J. Otto
Idaho Public Utilities Commission Idaho Power Company
Monica Barros-Sanchez Megan Goicoechea Allen
Commission Secretary Donovan E.Walker
[e-mail] Timothy Tatum
Riley Maloney
Jeff Loll [e-mail]
Deputy Attorney General dwalkerkidahopower.com
Idaho Public Utilities Commission [e-mail]
[e-mail] [e-mail]
[e-mail]
Idaho Irrigation Pumpers Association [e-mail]
Eric L. Olsen
Lance Kaufman Renewable Energy Coalition
[e-mail] Irion Sanger
[e-mail] Sanger Greene,P.C.
4031 SE Hawthorne Blvd.
Micron Technology,Inc Portland, OR 97214
Austin Rueschhoff [e-mail]
Thorvald A.Nelson [e-mail]
Austin W. Jensen [e-mail]
Kristine A.K. Roach [e-mail]
Holland&Hart,LLP
[e-mail]
[e-mail]
[e-mail]
[e-mail]
[e-mail]
[e-mail]
IPC-E-25-23 NWEC and RNW Comments 17
November 12,2025