20251113Staff Comments.pdf

RECEIVED
November 13, 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 IDAHO POWER )
COMPANY'S 2025 INTEGRATED ) CASE NO. IPC-E-25-23
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 June 27, 2025, Idaho Power Company("Company") applied to the Commission
requesting that the Commission issue an order acknowledging the Company's 2025 Integrated
Resource Plan("IRP") ("Application").
On August 11, 2025, the Commission issued a Notice of Application and Notice of
Intervention Deadline. Order No. 36706. The Commission granted intervention to Micron
Technology, Inc., Idaho Irrigation Pumpers Association,Northwest Energy Coalition and
STAFF COMMENTS 1 NOVEMBER 13, 2025

Renewable Northwest, and Renewable Energy Coalition. Order Nos. 36717, 36740, 36751, and
36758. On September 15, 2025, a Notice of Parties was issued.
STAFF ANALYSIS
Staff recommends acknowledgement of the Company's 2025 IRP. This recommendation
is based on the Company's compliance with the minimum requirements and with the
Commission's prior orders.
Order No. 22299 requires the Company to submit a biennial IRP that considers existing
resources, load forecasts, and future resources (supply-side and demand-side)necessary to
reliably serve the future load. Order No. 25260 requires public participation in development of
the plan. Staff believes the 2025 IRP complied with the procedural and substantive requirements
of the Orders and recommends that the Commission affirm this through its acknowledgement.
Staff recognizes the significant time and effort the Company invested in developing this
IRP and appreciates the vast amount of information compiled within it. The report has become
increasingly complex and increasingly important as the results from the report inform resource
investments.
It is important to reiterate that the Commission's acknowledgement of the IRP does not
imply that prudence is conferred to the resources included in the Preferred Portfolio. Staff
considers that the resources included in the Company's Preferred Portfolio are proxies that the
Company selected based on assumptions at that moment in time. Staff expects that the Company
will select each resource at the time of acquisition by evaluating it against the range of
alternatives that are available at that time and at current prices to obtain a determination of
prudence.
Additionally, Staff comments and recommendations are organized in the following
sections:
L Inputs, Assumptions and Model Constraints;
II. The Preferred Portfolio;
II1. The Near-Term Action Plan;
IV. The Load and Resource Big Picture;
V. The Demand-Side Management Program;
VI. PURPA: New Development and Replacement Rates;
STAFF COMMENTS 2 NOVEMBER 13, 2025

VII. Other Modeling Issues; and
VIIL Staff s Recommendations.
I. Inputs,Assumptions and Model Constraints
The foundation of the IRP is the collection of cost inputs, assumptions and model
constraints used by the Company. The quality of the IRP results depends on them. After a
careful examination of the source data, Staff believes that the inputs, assumptions and model
constraints are reasonable. However, Staff suggests a few changes for the Company to consider
for its next IRP.
1. Levelized Cost of Capacity
The levelized cost of capacity ("LCOC") is one of the most fundamental inputs for each
resource, and it plays a significant role in which resources the Aurora Long Term Capacity
Expansion("LTCE")model selects. Staff examined the Company's LCOC worksheets carefully
and believes that the Company's assumptions are reasonable. However, Staff offers observations
about three sub-factors that feed into the LCOC calculations: overnight plant capital ("OPC"),
interconnection capital ("IC"), and the capacity factors ("CF").
To determine the OPC for each resource, the Company collected cost estimates from a
variety of sources such as the National Renewable Energy Laboratory ("NREL"), the Energy
Information Administration, and the IRP estimates from other utility companies.' The Company
then selected one of these estimates to use as the basis for its own LCOC calculations. In
reviewing the Company's selections, Staff could not discern a consistent pattern for which values
were selected. Sometimes an estimate near the low end of the range was selected, and
sometimes near the high end. For two resources, the Company selected the highest priced
estimate, and for one of those, the value was an outlier by a significant margin. Staff
recommends the Company provide rationale for its choices in the next IRP.
Regarding the IC estimates, Staff commends the Company for its new approach of
assigning a standard value that is solely determined by a geographic cluster area, the actual cost
of recent similar projects in those areas, and the interconnection voltage.2 This is less arbitrary
and more equitable than the approach used in the prior IRP.
'Response to Staff Request No. 1 —Confidential Attachment 1.
2 Response to Staff Request No. 1 —Attachment 2.
STAFF COMMENTS 3 NOVEMBER 13, 2025

Regarding annual CFs, Staff believes that they are a significant sub-factor of LCOC
calculations for some resources. Staff recommends that the Company conceptually discuss them
in its next IRP and explain which resources require that a CF be applied to the LCOC (and why),
and report each value selected by the Company.
2. Escalation Factors
The Company must assume an annual escalation rate for a wide range of factors in its
cost models. For most of them, such as the property tax escalation rate and the insurance
escalation rate, the Company assumes a single rate and applies it uniformly to every resource in
each modeled year.3
However, for the LCOC values, the Company applies different escalation rates for each
resource, and it changes the rates seemingly arbitrarily from one year to the next. For example,
the escalation rate for a geothermal resource is near zero for the first five years, while all other
resources are set to escalate at 2.40 percent or 3.40 percent for those same years. Also, the
escalation rates drop significantly for all resources between 2030 and 2031.4 In Response to
Staff Production Request No. 3, the Company explains that it expects recent technological
advancements to reduce the cost of geothermal resources in the near term, thus setting the rates
to fluctuate around zero percent. The Company's explanation for the abrupt rate changes in 2031
is that there is more uncertainty that far in the future, so they switched to NREL Annual
Technology Baseline cost curves.
Staff agrees with the Company's justification for the near-term geothermal cost
efficiencies,but recommends that a single, simple value be chosen such as 0.0 percent or 0.5
percent. The micro-adjustments around a value of zero percent only obfuscate the underlying
premise (cost stability due to technological advances). Also, displaying values with precision to
a hundredth of a percent implies that the values are based on detailed calculations rather than
educated guesses.
Staff disagrees with the Company's justification for shifting to NREL's estimates in 2031
and beyond. By the Company's own words,5 there is more uncertainty that far in the future.
s 2025 IRP,Table 10.1 at 112.
4 2025 IRP Appendix C at 23.
5 Response to Staff Production Request No.3
STAFF COMMENTS 4 NOVEMBER 13, 2025

Therefore, Staff believes the Company should apply a uniform value to every resource for all
remaining years. Staff believes assigning different values to different resources more than five
years in the future is arbitrary without a factual basis.
3. Forecasts
The IRP identifies five factors that can vary widely in quantity and value over time and
affect the final cost of a resource portfolio. These include gas prices, carbon prices, hydro-
electric generation, renewable energy certificate ("REC")prices, and the system load. The
Company develops a range of forecasts for each of these factors. Staff reviewed the Company's
basis for each of these and believes that each one is reasonable.
4. Model Constraints— Thermal Plants
In its 2023 IRP comments, Staff expressed concern about the Company predetermining
when its gas and coal resources would convert or shut down, as opposed to letting the LTCE
model choose the most economical course of action.
The conversion of North Valmy from coal to gas in 2026 was recently determined by a
separate case, IPC-E-25-03, so the model constraints for Valmy were settled for the 2025 IRP.
Regarding Jim Bridger Units 3 and 4 (`Bridger" or`Bridger 3&4"), Staff commends the
Company for its open-minded and thorough investigation of the most economic course of action.
The Company's analysis was complicated by many factors, including the depletion of Bridger
Mine coal and the uncertainty of repealing Rule I I I(d) of the Clean Air Act ("Rule I I I(d)").
However, the Company devised multiple scenarios and developed models for converting to gas,
shutting down, continuing coal, and adding carbon capture and storage technology.6 This is a
positive example of the Company pursuing the least-cost least-risk("LC-LR") solution,
wherever the results led.
5. Model Constraints - Transmission
Staff also reviewed the Company's model constraints for three new transmission lines:
Boardman to Hemingway(`B2H"), Southwest Intertie Project—North ("SWIP-N"), and
6 2025 IRP at 50.
STAFF COMMENTS 5 NOVEMBER 13, 2025

Gateway West segment eight ("GWW8"). For all three, the Company used the most current
target commercial operation date ("COD") for each project. Although Staff accepts that this is a
reasonable course of action by the Company, Staff recommends that the Company consider
either adding up to 12 months to the modeled COD for any transmission project that does not
have all its permitting and right-of-way issues resolved, or model delays as a risk variable to
determine how portfolios would need to change so that least-cost contingencies can be
developed.
Staff proposes this because the construction of new transmission lines is more vulnerable
to legal delays than other types of construction projects. Legal battles over permitting and right-
of-way can easily extend a transmission project by months or years. For example, the Company
assumed a B2H COD of June 2026 in the 2023 IRP. Due to ongoing legal delays, the Company
revised the B2H COD to December 2027 for this IRP.' Furthermore, the legal battles to build
B2H are still not fully resolved, and additional delays are possible. The current 18-month delay
has forced the Company to significantly adjust its near-term resource acquisition plan.
Similar legal and regulatory delays are beginning to materialize for SWIP-N and GWW8.
In the current high-growth environment, it is far easier to adjust to a transmission resource
coming online earlier than planned than it is to adjust to a delayed resource.
II. The Preferred Portfolio
The Preferred Portfolio is one of the primary results of the IRP process. It is the list of
supply and demand-side resources the Company believes will reliably meet the forecasted load
over the next 20 years at the least cost. Because the Company uses the IRP portfolio results and
methods of analysis as part of its justification for new resource projects, Staff examined the
portfolio development process carefully and believes the Company's results are reasonable.
Staff believes that the Preferred Portfolio is likely the LC-LR portfolio.
1. The Main Planning Cases
Staff reviewed the main planning cases pictured in Figure 9.2 of the 2025 IRP and
believes them to be reasonable. Each case revolves around the various courses of action for
7 2025 IRP,Table 9.1 at 101.
STAFF COMMENTS 6 NOVEMBER 13, 2025

Bridger 3&4, the status of Rule 111(d), and the addition of future large loads. Staff commends
the Company for developing the main planning cases in consultation with the IRP Action
Committee ("IRPAC") in the months prior to the report.
2. The Sensitivity and Validation Scenarios
The sensitivity scenarios are designed to change some of the baseline modeling
assumptions to see how the future resource mix changes. The Company, working with the
IRPAC, developed nine scenarios. Three examples are "High Gas & Carbon Prices",
"Constrained Markets", and"100% Clean by 2045". Staff believes the spectrum of scenario
variation is adequate.
Staff commends the Company for including side-by-side comparisons of each sensitivity
portfolio with the Preferred Portfolio in Tables 11.4 to 11.12. This feature allows helpful insight
into resource differences that might occur under different planning conditions.
The Company also designed validation scenarios to test the validity of the Preferred
Portfolio results. By forcing the model to select different resources at different times, the
Company can examine the net present value ("NPV") results to confirm that the Preferred
Portfolio is truly the optimal cost portfolio. Staff examined the eight validation cases and agrees
they cover an adequate range of tests. Furthermore, the results confirmed that the Preferred
Portfolio is likely the optimal cost portfolio. Staff commends the Company for its well-designed
model validation process.
3. The Preferred Portfolio is Least Cost
The Company presented its NPV results for each of the 2025 IRP main cases in Table
10.2. The table shows that the `Bridger 3&4 converted to natural gas' portfolio ("Bridger 3&4
NG") was the least-cost portfolio if Rule 111(d) remains in effect, and it was within one percent
of the least-cost portfolio if Rule 111(d) is repealed. In the latter scenario, the least-cost portfolio
is the `Bridger 3&4 converted to Powder River Basin coal' scenario (`Bridger 3&4 PRB").
When the two portfolios are compared in the `300 megawatts ("MW") of new load' scenario and
the `500 MW of new load scenario', the NPV results are similarly close.
The Company asserts that the most realistic least-cost option is Bridger 3&4 NG, even
though the Bridger 3&4 PRB portfolio is slightly less costly, because it only becomes an option
STAFF COMMENTS 7 NOVEMBER 13, 2025

if Rule I I I(d) is repealed. It also carries additional barriers to implementation and risks if
national environmental policy swings against coal in the future. Lastly, the Company asserts that
at least one more IRP cycle remains before this decision must be made; thus, there is time to
gather additional information to better assess the risks and cost savings.
Staff carefully considered the above justifications and reviewed the Company's
underlying NPV calculations. Staff agrees that the Bridger 3&4 NG portfolio is the realistic
least-cost portfolio for the current IRP cycle.
4. The Preferred Portfolio is Least Risk
Assessments of the qualitative risk and the stochastic risk are the final two steps to
confirm that the Preferred Portfolio is least risk.
The qualitative risk analysis identifies seven categories of risk such as `State/Federal
Policy' risk and `Supply Chain' risk. The Company then subjectively assesses the risk for each
portfolio, assigning a risk level of low, medium, or high for each risk category. Staff believes
that the Company identified a comprehensive range of risk categories and determined reasonable
risk levels for each portfolio in each category. The results summary is displayed in Table 10.5 of
the 2025 IRP.
However, Staff believes there are limited situations where the qualitative risk analysis
can be practically useful. For example, which portfolio is lower risk: a portfolio that has six low-
risk factors and one high-risk factor, or a portfolio that has five low-risk factors and two medium-
risk factors? How would the Company rate the risk if two portfolios have the same number of
low and medium-risk factors, but align to different risk categories that may not have equivalent
weight? Staff believes the qualitative analysis is only useful in situations where one portfolio
has a clear preponderance of high-risk factors and is being compared against a portfolio with
mostly low-risk factors.
In Table 10.5, the Preferred Portfolio has one of the better qualitative risk profiles,but
there are at least two other portfolios with comparable profiles. Therefore, Staff can only
conclude that the Preferred Portfolio is one of several portfolios with lower qualitative risk.
Staff believes the stochastic risk is more objective. The Company's stochastic analysis is
summarized in Figure 10.2 of the 2025 IRP. It shows the Preferred Portfolio is one of three
portfolios with the most leftward-shifted probability profiles. This means that under a wide
STAFF COMMENTS 8 NOVEMBER 13, 2025

variety of variations of gas price, carbon price, hydro-generation, REC prices, and load, the
Preferred Portfolio has the highest probability of being a least-cost portfolio, which makes it a
least-risk portfolio.
Staff believes that both the qualitative analysis and stochastic risk analysis support the
Company's assertion that the Preferred Portfolio is least risk.
S. The Preferred Portfolio is Least Cost, Least Risk
Based on Staff s analysis and conclusions, Staff supports the Company's decision to
make the Bridger 3&4 NG portfolio as the Preferred Portfolio because it is likely LC-LR across a
reasonable range of alternative futures. However, Staff qualifies its support of the Company's
final results, which are based on assumptions and inputs into its models and methods of analysis.
Significant shifts in inputs and assumptions could change the final conclusions and should be
considered when resource prudence determinations are made.
III. The Near-Term Action Plan
In addition to the Preferred Portfolio, the other primary product of the 2025 IRP is the
Near-Term Action Plan("NTAP"). 2025 IRP at 140-141. Staff believes the NTAP is reasonable
and does not object to any of the Company's proposed actions in principle, but each action
remains subject to detailed review in future cases when prudence of each resource will be
determined.
The Company chose to divide the NTAP into two sub-lists: 1)Actions Committed to
before the 2025 IRP; and 2) 2025 IRP Decisions for Acknowledgement. Staff agrees that all the
actions on the first list have already been approved or are in review in separately filed cases.
Regarding the second list, Staff believes that Commission acknowledgement is not appropriate
or necessary. Commission acknowledgement is not necessary for the reasons listed below:
1. The SWIP-N case has been filed(IPC-E-25-08), and a final order is imminent;
2. A separate process exists for approving the expansion of the Demand Response
("DR")program;
3. The Company is always free to coordinate with PacifiCorp on the future of Bridger;
and
STAFF COMMENTS 9 NOVEMBER 13, 2025

4. The Company has already issued its 2028 All-Source Request for Proposals, which is
requesting resources in 2028 and 2029. Individual cases for potential acquisitions are
filed and being reviewed.
IV. The Load and Resource Big Picture
Stepping back from the 2025 IRP results, and to consider the load and resource big
picture, Staff notes that exceptionally large load growth commences in 2026 and continues until
at least 2031.8 Also, two of the main case scenarios assume additional large growth because the
Company believes that additional new large load growth may come to its service territory.9
On the resource side, Staff notes that several elements of the Near-Term Action Plan are
at risk and one element is pending cancelation. Staff believes the three new transmission
projects are at risk of further delay, and the 600 MW wind resource planned for 2027 is
potentially cancelled.10
These two trends suggest that the Company is approaching a situation where it must
choose between the following:
1. Putting system reliability at risk by accepting large new loads without sufficient
resources; or
2. Delaying the acceptance of large new loads; or
3. Paying a premium to accelerate projects or to purchase scarce firm market energy.
Should this situation materialize where there are tradeoffs between the Company's
obligation to serve customers in its service territory, and meeting its obligation to provide service
at fair,just, and reasonable rates, Staff recommends that the Company engage the Commission
prior to making decisions that could limit potential options. For example, additional possibilities
include assigning cost premiums to new large loads, coordinating with the new large load
customers to curtail load whenever system reliability is at risk, or delay service dates or load
ramps to ensure incremental resources can be acquired economically.
$2025 IRP,Figures 8.1 and 8.2,and Tables 8.1 and 8.2.
9 Application at 11.
10 IPC-E-25-28.
STAFF COMMENTS 10 NOVEMBER 13, 2025

V. The Demand-Side Management Program
The Company's NTAP calls for incremental cost-effective acquisition of Energy
Efficiency ("EE") and Demand Response ("DR") resources that provide annual system capacity
and energy selections. 2025 IRP at 4. The Company contracted with a third-party to conduct an
Energy Efficiency Potential Study(`BE Potential Study") for the 2025 IRP. Id. at 53-54. The
assessment provided a broad estimate of demand-side resource characteristics to inform
modeling of these resources. Id. at 172. In the EE Potential Study, individual measures are
screened for cost-effectiveness. Cost-effective EE measures are included in the IRP as a
decrement to the load forecast. Id. at 53. Staff has reviewed the Preferred Portfolio's EE and
DR selections and supporting methodology and generally believes they are reasonable.
1. Energy Efficiency Selections
EE remains an important resource to offset future energy loads on the Company's system.
Id. The Company's 2025 Preferred Portfolio included 344 MW of incremental EE. Id. at 3. The
Company's Near-Term Action Plan includes 80 MW identified by the EE Potential Study. Id. at
7.
In addition to the cost-effective potential identified by the EE Potential Study,bundles of
EE measures that were not cost-effective were selected by the Aurora model. Id. at 53-54. Staff
is concerned with these selections. The 2025 IRP explains that EE potential measures that did
not pass cost-effectiveness screening were bundled according to price and season where most
savings occur. Id. In its response to Staff Production Request No. 12, the Company indicated
that selection of EE bundles begins in 2031 and that the Aurora model has only selected the
lowest cost bundles. Across the forecast horizon these bundles total 57 MW of incremental EE
measures, mostly in the winter season. Response to Staff Production Request No. 12. Staff
believes that due to the relatively small magnitude and the timing of the selections, there is no
immediate issue for this IRP. Theoretically, the pursuit of not cost-effective EE measures could
cause complications with the Company's existing EE programs. Staff recommends the
Company provide additional details in future IRPs that will allow increased transparency
regarding how these selections are made and how they should be considered.
STAFF COMMENTS 11 NOVEMBER 13, 2025

2. DR Selections
Like EE, DR remains an important resource to offset future energy loads on the
Company's system. 2025 IRP at 53. The Company's 2025 Preferred Portfolio includes 20 MW
of incremental DR. Id. at 3. A 10 MW selection is part of the Company's NTAP. Id. at 7. In
response to Staff Production Request No. 11, the Company explains that the selections are
proxies for expansion of the Company's existing DR programs. Staff believes that the
incremental DR aligns with the Company's recent expansion of the Air Conditioner Cool Credit
program.
3. Avoided Cost
To select potential EE programs, the Company uses avoided costs to estimate the value of
program savings. Avoided costs are determined by value streams that represent the estimated
energy, capacity, and transmission and distribution upgrade costs that the Company defers or
otherwise avoids through implementing Demand-Side Management("DSM")measures. The
values are important as each defines the EE measures selected for DSM planning and to evaluate
the cost-effectiveness of those programs'performance. The 2025 IRP avoided costs are similar
to the 2023 IRP forecasts in the near term. However, the avoided costs in later years decrease in
value. Staff has reviewed the avoided costs and believes that the Company's avoided costs are a
reasonable forecast for DSM program planning.
VI. PURPA: New Development and Replacement Rates
As part of its baseline assumptions, the Company used the Public Utility Regulatory
Policies Act("PURPA") new development rates and replacement rates based on the most recent
five years of data available at the time the analysis was conducted(August 1, 2019, to July 31,
2024; analysis began in August 2024), regardless of where the projects are located. Response to
Staff Production Request No. 9. For wind and solar replacement rates, the Company did not
have empirical data to determine the baseline rates, as none of the wind and solar contracts had
expired yet, nor had any entered into replacement contracts. Therefore, the Company assumed a
75 percent replacement rate, which was mandated by Oregon Public Utility Commission's Order
No. 24-285. Staff recommends that the Company:
STAFF COMMENTS 12 NOVEMBER 13, 2025

1. Develop Oregon's rates and Idaho's rates separately and use Idaho-specific data to
develop Idaho's PURPA new development and replacement rates;
2. Separately develop Idaho's PURPA new development and replacement rates for
projects that use the Surrogate Avoided Resource ("SAR") method and for projects
that use the Incremental Cost IRP ("ICIRP") method; and
3. Contact the projects in Idaho that will expire soon to gain understanding of their
project renewal intentions, when the empirical data for determining Idaho's
replacement rates is insufficient or not available.
First, Staff believes that baseline assumptions should reflect actual circumstances as
closely as possible, even though scenario cases may test more extreme assumptions such as no
new developments and no replacements. Because Oregon and Idaho have different policy
environments, Staff recommends that the Company develop Oregon's rates and Idaho's rates
separately. For Idaho's rates, Staff recommends that the Company use Idaho-specific data to
develop Idaho's PURPA new development rates and replacement rates.
Second, Staff also believes that the Company should separately develop Idaho's PURPA
new development and replacement rates for projects that use the SAR method and for projects
that use the ICIRP method, because these two types of projects have different maximum contract
terms in Idaho (i.e., 20 years for SAR-based projects and two years for ICIRP-based projects),
resulting in different development trends. For example, since the maximum contract length for
ICIRP-based projects was reduced to two years in 2015, the development of such projects has
been reduced significantly.
Lastly, for the determination of Idaho's replacement rates where empirical data is
insufficient or not available, Staff recommends that the Company contact the projects in Idaho
that will expire in the near future to gain understanding of their intents to renew the projects,
instead of borrowing Oregon's replacement rate,because Staff believes that those expiring
projects in Idaho can serve as a reasonable indicator of renewal trends in the state.
VI I. Other Modeling Issues
Calibration between Aurora LTCE and RCAT
After developing a portfolio through the Aurora LTCE functionality, the Company then
uses the Reliability and Capacity Assessment Tool ("RCAT")model to calculate the annual
STAFF COMMENTS 13 NOVEMBER 13, 2025

capacity positions of the Aurora-produced portfolio to ensure that the 20-year load and resource
buildouts will result in a positive capacity position sufficient to achieve the pre-determined
reliability threshold of 0.1 event-days per year loss of load expectation. If the portfolio results in
a capacity shortfall, the Company will recalibrate the seasonal Planning Reserve Margin
("PRM") and the Effective Load Carrying Capability("ELCC") curve to re-run the LTCE model
for a new portfolio. 2025 IRP at 120. The calibration process continues until both the LTCE
model and the RCAT model converge on a similar capacity position. Id. at 100.
Although the Company described the calibration process conceptually in the 2025 IRP,
Staff believes more transparency should be provided on the process, especially how the seasonal
PRM and the ELCC curve are adjusted for the calibration. Therefore, Staff recommends that the
Company illustrate the calibration process between the LTCE model and the RCAT model in a
more transparent way in the next IRP with a focus on the adjustments of the seasonal PRM and
the ELCC curves.
Flexible Ramping Requirements of WEIM
As a market participant in the Western Energy Imbalance Market ("WEIM"), the
Company is tested every 15 minutes on its ability to ramp up or down in response to forecast
errors to see if it meets the Flexible Ramping Requirement of WEIM. Response to Staff
Production Request No. 47. However, the Aurora model is an hourly model that does not
capture sub-hourly inputs. Therefore, the Flexible Ramping Requirement is not reflected in the
IRP. Staff recommends that the Company explore the possibility of incorporating the Flexible
Ramping Requirement in the next IRP to ensure the Company has sufficient reserve to meet
various reserve needs including WEIM's requirement.
STAFF RECOMMENDATION
Staff recommends that the Commission acknowledge the 2025 IRP, and that the 2025
IRP meets the requirements of Order Nos. 22299 and 25260. Staff also supports the Company's
decision to designate the Bridger 3&4 NG portfolio as the Preferred Portfolio. Staff summarizes
its other recommendations below:
1. Provide rationale for the overnight plant capital selected for each resource;
2. Publish the annual capacity factor values selected for each resource that requires one;
STAFF COMMENTS 14 NOVEMBER 13, 2025

3. Simplify and standardize the escalation factors applied to LCOC calculations;
4. Build delay into the modeled COD for new transmission resources;
5. Engage the Commission when there are tradeoffs between the Company's obligation
to serve new large loads and provide fair,just, and reasonable rates;
6. Provide additional EE details;
7. Develop Oregon's rates and Idaho's rates separately and use Idaho-specific data to
develop Idaho's PURPA new development and replacement rates;
8. Separately develop Idaho's PURPA new development and replacement rates for
projects that use the SAR method and for projects that use the ICIRP method;
9. Contact the projects in Idaho that will expire soon to gain understanding of their
project renewal intentions, when the empirical data for determining Idaho's
replacement rates is insufficient or not available;
10. Illustrate the calibration process between the LTCE and RCAT models; and
11. Explore incorporation of the flexible ramping requirement.
Respectfully submitted this 13th day of November 2025.
Jeffrev R. Loll
Deputy Attorney General
Technical Staff. Matt Suess, Jason Talford, Yao Yin
I:\Utility\UMISC\COMMENTS\IPC-E-25-23 Comments.docx
STAFF COMMENTS 15 NOVEMBER 13, 2025

CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 131h DAY OF NOVEMBER 2025,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. IPC-E-25-23, BY E-MAILING A COPY THEREOF TO THE FOLLOWING:
Idaho Power Company: Idaho Power Company:
MEGAN GOICOECHEA ALLEN TIM TATUM
DONOVAN E. WALKER RILEY MALONEY
IPC DOCKETS MICAH BABBITT
IDAHO POWER COMPANY IDAHO POWER COMPANY
1221 WEST IDAHO STREET (83702) 1221 WEST IDAHO STREET (83702)
PO BOX 70 PO BOX 70
BOISE ID 83707-0070 BOISE ID 83707-0070
E-MAIL: E-MAIL:
mgoicoecheaallen&idahopower.com ttatum&idahopower.com
dwalkergidahopower.com rmaloney&idahopower.com
dockets(cr�,idahopower.com mbabbitt&idahopower.com
Idaho Irrigation Pumpers Association,Inc
Micron: (IIPA):
Austin Rueschhoff Attorneys for IIPA:
Thorvald A. Nelson Eric L. Olsen
Austin W. Jensen ECHO HAWK& OLSEN, PLLC
Kristine A.K. Roach E-MAIL:
Holland& Hart, LLP elo(cr�,echohawk.com
555 17th St., Ste. 3200 tayshagechohawk.com
Denver, CO 80202
E-MAIL: Lance Kaufman, Ph.D.
darueschhoff(cr�,hollandhart.com E-MAIL: lancegae_isi�nsi_ht�com
tnelson(d,hollandhart.com
awj ensenghollandhart.com
karoach(d),hollandhart.com
aclee&hollandhart.com
tlfriel(d),hollandhart.com
Attorney for Northwest Energy Coalition
and Renewable Northwest:
Benjamin J. Otto
1407 W. Cottonwood Ct.
Boise, ID 83702
E-MAIL:
ben&nwenergy.org
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Northwest Energy Coalition: Renewable Northwest:
Lauren McCloy Mike Goetz
Utility Regulatory Director Regulatory Affairs Director
lauren(a,nwenergy org mike(krenewablenw.org
Derek Goldman Katie Chamberlain
Policy Associate Regulatory Manager
derek(knwenergy org katherine c(+�renewablenw.org
Kyle Unruh
Director, MT and ID
kyle(a,renewablenw.org
Renewable Energy Coalition (REC)
Irion Sanger
Sanger Greene, P.C.
4031 SE Hawthorne Blvd.
Portland, OR 97214
irion(a),sanger-law.com
diego ,sanger-law.com
dustin(a),sanger-law.com
j ohnikrecoalition.com
PATRICIA JORDA9, SECRETARY
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