20240125IPC to Staff 67-84.pdf

LISA D. NORDSTROM
Lead Counsel
[e-mail]

January 25, 2024

VIA ELECTRONIC EMAIL

Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg 8,
Suite 201-A (83714)
PO Box 83720
Boise, Idaho 83720-0074

Re: Case No. IPC-E-23-23
Idaho Power Company’s 2023 Integrated Resource Plan

Dear Commission Secretary:

Enclosed for electronic filing, please find Idaho Power Company’s Response to the
Third Production Request of Commission Staff.

The attachments to DR 76, 80, and 81 can be found in the non-confidential FTP
Site. Confidential attachment to DR No. 82 will be uploaded to the confidential FTP Site
which will be provided to the parties who sign the Protective Agreement.

If you have any questions about the attached filing, please do not hesitate to
contact me.

Very truly yours,

Lisa D. Nordstrom
LDN:cd
Attachments
RECEIVED
Wednesday, January 25, 2024 4:33PM
IDAHO PUBLIC
UTILITIES COMMISSION

CERTIFICATE OF ATTORNEY

ASSERTION THAT INFORMATION CONTAINED IN AN IDAHO PUBLIC UTILITIES
COMMISSION FILING IS PROTECTED FROM PUBLIC INSPECTION

Idaho Power Company’s 2023 Integrated Resource Plan

Case No. IPC-E-23-23

The undersigned attorney, in accordance with Commission Rules of Procedure 67,
believes that the Attachment No(s). 82 to Idaho Power Company’s Response to the Third
Production Request of the Commission Staff, dated January 25, 2024, may contain
information that Idaho Power Company claims is a confidential trade secret as described
in Idaho Code § 74-101, et seq., and/or § 48-801, et seq. As such, it is protected from
public disclosure and exempt from public inspection, examination, or copying.

DATED this Thursday, January 25, 2024,

Lisa Nordstrom
Counsel for Idaho Power Company

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 1

LISA D. NORDSTROM (ISB No. 5733)
MEGAN GOICOECHEA ALLEN (ISB No. 7623)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
[e-mail]
[e-mail]

Attorneys for Idaho Power Company

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF IDAHO POWER
COMPANY’S 2023 INTEGRATED
RESOURCE PLAN.
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CASE NO. IPC-E-23-23

IDAHO POWER COMPANY’S
RESPONSE TO THE THIRD
PRODUCTION REQUEST OF THE
COMMISSION STAFF

COMES NOW, Idaho Power Company (“Idaho Power” or “Company”), and in response
to the Third Production Request of the Commission Staff (“Commission” or “Staff”) dated
January 17, 2024, herewith submits the following information:

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 2
STAFF REQUEST FOR PRODUCTION NO. 67: In response to Production Request No.
59, the Company states that Schedule 33 would experience a rate change related to changes in
energy load forecast percentile because the special contract relies on Demand-Side Management
("DSM") avoided cost averages. Please answer the following:
a. Please describe the relationship between the load forecast percentile and DSM
avoided cost averages;
b. Please explain the effect that moving from a 50th percentile load forecast to a 70th
percentile load forecast has had on each avoided cost component (e.g., avoided
cost of energy, avoided cost of capacity, etc.); and
c. Please explain the effect that moving from a 50th percentile load forecast to a 70th
percentile load forecast has had on demand response and energy efficiency
selections.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 67:
a. Demand-Side Management (“DSM”) avoided energy cost averages are determined by
simulating the dispatch of the Company’s resources based on the load and resource
assumptions used in each Integrated Resource Plan. Any change to load or resource
assumptions would have a corresponding change to the avoided cost output. However,
the Company has not performed such a comparative analysis to quantify the referenced
relationship.
b. As the Company has not performed a comparative analysis of DSM avoided cost averages
based on different load forecast percentiles, it cannot comment on the effect different load
forecasts have on this metric. However, it should be noted that Idaho Power’s use of a
P70 load forecast only applies to Idaho Power’s zone in AURORA. The remainder of the
Western Electricity Coordinating Council (“WECC”) (and zones within the WECC) was not
adjusted. Idaho Power’s transactions account for approximately 2 percent of the total
WECC, meaning that avoided cost averages for DSM, which are based on the simulated

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 3
zonal market price will not change in a significant way if the Company were to use P50
compared to the P70 load forecast. Because the avoided cost of capacity is based on the
cost of a Simple Cycle Combustion Turbine (“SCCT”), changes to the load forecast
percentile do not affect this value.
c. As the Company has not performed a comparative analysis of resource selections based
on different load forecast percentiles, it cannot speculate on the relationship between
them.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 4
STAFF REQUEST FOR PRODUCTION NO. 68: Please explain if the Company
conducted analysis to verify that the use of the top 90% of total risk hours captures all critical
timeframes for defining seasons while also minimizing computational load.
a. If yes, please provide the results of the analysis; and
b. If not, why not?
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 68:
Yes, the Company conducted analysis to verify that the top 90 percent of total risk hours
captures all critical timeframes for defining seasons while also minimizing computational load.
The top 90 percent of total risk hours was originally derived as a representation of the
capacity contribution of a Simple Cycle Combustion Turbine (“SCCT”) 𝐶𝑜𝑛𝑡𝑟𝑖𝑏𝑢𝑡𝑖𝑜𝑛 𝑡𝑜 𝑃𝑒𝑎𝑘𝑆𝐶𝐶𝑇=𝑁𝑎𝑚𝑒𝑝𝑙𝑎𝑡𝑒𝑆𝐶𝐶𝑇∗(1 −𝐸𝐹𝑂𝑅𝑑𝑆𝐶𝐶𝑇)
where the Equivalent Forced Outage Rate during Demand (“EFORd”) for an SCCT was
approximately 10 percent. To verify that the timing of highest risk captured all critical timeframes
for defining seasons and hours, Idaho Power calculated the Loss of Load Expectation (“LOLE”)
utilizing only the hours within the identified timing of highest risk instead of all hours in the calendar
year, which resulted in an average captured risk of 96.1 percent of the LOLE 0.1 event-days per
year threshold.
In addition, a 90 percent risk threshold has been utilized in previous Idaho Power
analyses, first introduced in Case No. IPC-E-21-37 (Speculative High-Density Load), and further
used in Case No. IPC-E-23-11 (Idaho Power’s General Rate Case) and Case No. IPC-E-23-14
(On-site Generation).
The response to this Request is sponsored by Andrés Valdepeña Delgado, System
Consulting Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 5
STAFF REQUEST FOR PRODUCTION NO. 69: Please explain if the Company evaluated
other levels (i.e., 70-80%) of total risk hours for this analysis. If so, please provide any associated
analysis.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 69:
Idaho Power did not evaluate other levels of total risk hours for the 2023 Integrated
Resource Plan (“IRP”) analysis. As an industry standard does not currently exist for determining
the season and hours of highest risk, Idaho Power utilized the 90 percent threshold to align with
previously filed methodologies as described in the Company’s Response to Staff’s Request for
Production No. 68.
The response to this Request is sponsored by Andrés Valdepeña Delgado, System
Consulting Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 6
STAFF REQUEST FOR PRODUCTION NO. 70: Please explain if the Company
conducted analysis to verify that the use of the top 50% of total risk hours in a month captures all
critical timeframes for hours of highest risk while also minimizing computational load.
a. If yes, please provide the results of the analysis; and
b. If not, why not?
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 70:
Yes, the Company did verify the use of the top 50 percent threshold. As described in the
Company’s Response to Staff’s Request for Production No. 68, to verify that the timing of highest
risk captured all critical timeframes for defining seasons and hours, Idaho Power calculated the
Loss of Load Expectation (“LOLE”) utilizing only the hours within the identified timing of highest
risk instead of all hours in the calendar year, which resulted in an average captured risk of 96.1
percent of the LOLE 0.1 event-days per year threshold.
The Company originally developed the top 50 percent of total risk hours threshold in
collaboration with Staff for Case No. IPC-E-22-06 (the replacement Special Contract for Micron)
to determine the critical hours for measuring the expected performance of non-dispatchable Clean
Energy Your Way (“CEYW”) resources; the hours of need are further described in Attachment 1
of the Company’s December 23, 2022, Compliance Filing for the specified case. The top 50
percent of total risk hours threshold was again utilized in Case No. IPC-E-21-42 (Brisbie, LLC
Special Contract), Case No. IPC-E-23-11 (Idaho Power’s General Rate Case), and Case No. IPC-
E-23-14 (On-Site Generation).
The response to this Request is sponsored by Andrés Valdepeña Delgado, System
Consulting Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 7
STAFF REQUEST FOR PRODUCTION NO. 71: Please explain if the Company evaluated
other levels (i.e., 40% or 60%) of total risk hours for this analysis. If so, please provide any
associated analysis.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 71:
Idaho Power did not evaluate other levels of total risk hours for the 2023 Integrated
Resource Plan (“IRP”) analysis. As an industry standard does not currently exist for determining
the season and hours of highest risk, Idaho Power utilized the 50 percent threshold that was jointly
developed with Staff to align with previously filed methodologies as described in the Company’s
Response to Staff’s Request for Production No. 70.
The response to this Request is sponsored by Andrés Valdepeña Delgado, System
Consulting Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 8
STAFF REQUEST FOR PRODUCTION NO. 72: In its response to Production Request
No. 3, the Company provided workpapers similar to those provided in response to Production
Request No. 96 in Case No. IPC-E-23-11. Please explain what factors changed between the
submission of these two requests that are driving the increase in Loss of Load Expectation for the
2025 forecast year, excluding Battery Energy Storage Systems ("BESS") projects.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 72:
As described in the Portfolio Reliability Analysis presentation given at the August 15, 2023,
Integrated Resource Plan Advisory Council (“IRPAC”) meeting, the Company’s Reliability and
Capacity Assessment Tool (“RCAT”) is capable of calculating two primary outputs: perfect
generator size and Loss of Load Expectation (“LOLE”). For the data attached to the Company’s
Response to Staff’s Request for Production No. 3, the provided 2025 No Battery Energy Storage
Systems (“BESS”) LOLE results were determined by setting the RCAT perfect generator size to
0 megawatts (“MW”) and calculating the resulting LOLE of the system; this is why the average
annual LOLE is greater than the Company’s 2023 Integrated Resource Plan (“IRP”) LOLE
threshold of 0.1 event-days per year. For the data attached to the Company’s Response to
Request No. 96 in Case No. IPC-E-23-11, the provided 2025 No BESS LOLE results were
determined by setting the LOLE threshold in the RCAT to 0.1 event-days per year and calculating
the resulting perfect generator size needed to make the system reliable; this is why each test year
and the average annual results all round to a value of 0.1.
The response to this Request is sponsored by Andrés Valdepeña Delgado, System
Consulting Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 9
STAFF REQUEST FOR PRODUCTION NO. 73: Please describe the differences between
Demand Response ("DR") selections and BESS selections within the Long-Term Capacity
Expansion ("LTCE") model and what metrics influence the selection of BESS systems over DR
programs.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 73:
The different selections of demand response (“DR”) and battery energy storage systems
(“BESS”) by the Long-Term Capacity Expansion (“LTCE”) model in the Preferred Portfolio can be
found on page 42 of the 2023 Integrated Resource Plan (“IRP”) Appendix C. For a more detailed
breakout of the DR bundles selected in the Preferred Portfolio, please see the Company’s
Response to Staff’s Request for Production No. 55.
Consistent with the Company’s Response to Staff’s Request for Production No. 37, the
metrics that influence the selection of DR and BESS are the same metrics that influence the
selection of any resource within the LTCE model. The metrics most applicable to the comparison
between BESS and DR include fixed costs (based on capital costs, program costs, and fixed
operations and maintenance), variable costs (non-fuel-related costs that are variable, and which
are different for each energy resource), and fuel costs (zonal prices when the batteries are
charging and discharging). Based on these cost inputs and the defined operating characteristics,
the model will select resources that can reliably serve load for every hour of the planning horizon
while minimizing the cost of those resources.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 10
STAFF REQUEST FOR PRODUCTION NO. 74: Please provide the Company analysis
supporting the selection of November 1 through February 28, and June 1 through September 15,
described on page 93 of Appendix C, as seasons of highest risk, in Excel format with equations
enabled and intact.
a. Please indicate the forecast year used to inform these selections; and
b. Please indicate if the analysis excludes any Energy Limited Resources ("ELR")
(i.e., DR, BESS, or hybrid resources) and if so, please provide a similar analysis
with the inclusion of the excluded resource(s).
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 74:
Idaho Power and Staff agreed to an extension for Staff’s Request for Production No. 74,
to ensure the Company would be able to provide information consistent with Staff’s expectations.
The Company will provide its response to this request by January 31, 2024.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 11
STAFF REQUEST FOR PRODUCTION NO. 75: Please provide Company analysis
supporting the selection of the Summer and Winter risk hours shown on page 93 and 94 of
Appendix C as the hours for highest risk in Excel format with equations enabled and intact.
a. Please indicate the forecast year used to inform these selections; and
b. Please indicate if the analysis excludes any ELRs (i.e., DR, BESS, or hybrid
resources). If so, please provide a similar analysis with the inclusion of the
excluded resource(s).
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 75:
Idaho Power and Staff agreed to an extension for Staff’s Request for Production No. 75,
to ensure the Company would be able to provide information consistent with Staff’s expectations.
The Company will provide its response to this request by January 31, 2024.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 12
STAFF REQUEST FOR PRODUCTION NO. 76: Please provide all workpapers
associated with calculating Net Present Values ("NPV") for the preferred portfolio along with
explanations for any assumptions made. Please provide all workpapers with formulas enabled.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 76:
Please see attached Excel spreadsheet for the requested information. In the attachment,
the Preferred Portfolio is named as the “Valmy 1 & 2” portfolio or “P3”. The base data this
workbook uses to calculate the net present value (“NPV”) costs are derived from the AURORA
model outputs. Additional assumptions include the transmission costs, which are added once the
lines are added/necessitated by the resource build, and the discount rate, which is the Weighted
Average Cost of Capital (“WACC”).
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 13
STAFF REQUEST FOR PRODUCTION NO. 77: In its response to Production Request
No. 32(c), the Company asserted that its planned shutdown of Bridger Units 3 and 4 or converting
them to natural gas in 2030 is due to "alignment with the co-owner and operator, PacifiCorp."
Given the Company's 2022 experience of high natural gas prices and low, and stable coal prices
in 2022, please provide the Company's economic justification for shutting down or converting the
coal plants in 2030. Please provide supporting evidence.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 77:
It is important to note that both natural gas and coal prices fluctuate year to year. Gas
prices during 2022 were higher than normal, while prices in 2023 were more consistent with the
lower prices experienced over the past decade with the shale gas revolution beginning around
2009.
Idaho Power coordinates with PacifiCorp on operating and cost assumptions for Bridger
to include in the Integrated Resource Plan (“IRP”). PacifiCorp is both the operator and majority
owner of the Bridger plant, and Idaho Power coordinates with PacifiCorp on their operating plans.
However, Idaho Power’s inclusion of the coal to gas conversion of Units 3 and 4 at Bridger in the
Preferred Portfolio was informed by the units’ identification as cost-effective resources when
compared to other alternatives in the AURORA Long-Term Capacity Expansion (“LTCE”). The
conversions were analyzed alongside other resource options for selection by the AURORA LTCE
model in the 2023 IRP. The conversion of Bridger Units 3 and 4 was selected by the AURORA
LTCE model in the Preferred Portfolio (and nearly every portfolio analyzed), which was the least-
cost, least-risk portfolio, as shown in Table 10.2 of the 2023 IRP Report. Not only was the
Preferred Portfolio (including the conversion of Bridger Units 3 and 4 to natural gas) the least-cost
portfolio under planning conditions, it was also consistently the lowest-cost portfolio in the
stochastic risk analysis (as discussed in the 2023 IRP Appendix C starting on page 84).
In addition, as part of the validation and verification plan for the 2023 IRP, a validation run
was performed to test if the shutdown of Bridger Units 3 and 4 in 2030 (and not converting to

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 14
natural gas) would create a lower-cost portfolio. This validation run showed that not converting
Bridger Units 3 and 4 to natural gas in 2030 would increase portfolio costs (see the 2023 IRP
Report Table 10.4).
Lastly, converting Units 3 and 4 to gas decreases the overall emissions profile at Bridger,
particularly carbon and NOx emissions, which provides additional operating flexibility and
economic benefits. Carbon and NOx emission levels are estimated to decline up to 47 percent
and 64 percent, respectively, with the conversion of Bridger Units 3 and 4 from coal to gas.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 15
STAFF REQUEST FOR PRODUCTION NO. 78: In its response to Production Request
No. 32 (b) and (d), the Company asserted that it would extend the useful life of Bridger Units 1
through 4 through 2037 because this "aligns with the assumptions made by the co-owner and
operator, PacifiCorp." Given that the two companies are converting Bridger Units 1 and 2 to gas
in 2024, and Units 3 and 4 in 2030, please provide the Company's economic justification for
closing them in 2037. Please provide supporting evidence.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 78:
The update from a 2034 to 2037 end-of-life date for the Bridger units was an alignment of
assumptions with the co-owner and operator, PacifiCorp, and is based on the assessment of
useful life for those units. Given the timing of a 2037 exit, the Company plans to continue to review
this assumption in subsequent Integrated Resource Plans (“IRP”).
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 16
STAFF REQUEST FOR PRODUCTION NO. 79: In its response to Production Request
No. 32(e), the Company asserted that "the converted Valmy units are assumed to have an end
of life that occurs after the planning horizon, in 2045." Please explain the Company's economic
justification for closing them in 2045. Please provide supporting evidence.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 79:
The year 2045 was stated as the assumed end of life (not economic end of life), because
it is outside of the 2023 Integrated Resource Plan (“IRP”) 20-year planning horizon, which means
it does not impact the outcome of the 2023 IRP. In subsequent IRPs, an economic end date for
converted Valmy units will be evaluated. It is important to note that as part of the validation and
verification plan for the 2023 IRP, earlier exit dates for the converted Valmy units were evaluated
and were found to be less economic than running the converted Valmy units for the whole
planning horizon (see Table 10.4 of the 2023 IRP report for cost comparisons).
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 17
STAFF REQUEST FOR PRODUCTION NO. 80: As part of its response to Production
Request No. 36, the Company submitted Attachment 1, which provides additional details
regarding interconnection cost assumptions. Please answer the following questions concerning
this information:
a. Please explain why the Company estimated the interconnection cost for a new 100
MW solar resource in Mountain Home to be $6,500,000, while it estimated the
interconnection cost for a 90 MW upgrade to Danskin 1 (also in Mountain Home,
with existing interconnection infrastructure) to be $9,370,000, nearly 45 percent
higher. Please provide the underlying worksheets for both estimates;
b. The cost estimate to connect 50 and 170 MW thermal resources to the 230-kV Bus
at the Langley Gulch location (where interconnection infrastructure already exists)
is $8,054,000. The cost estimate to connect a 100 MW wind or solar resource to a
230-kV or 345-kV Bus (where interconnection infrastructure does not exist) is
$6,500,000. Please explain why the wind and solar resource interconnections are
20 percent less costly. Please provide the underlying worksheets for the thermal
and variable resource estimates;
c. Please explain why the Company assumes additional expenses for a feeder
connection are appropriate for Geothermal and Biomass resources, but additional
feeder expenses are not appropriate for wind and solar resources;
d. Staff is unable to recreate the Attachment 1 normalized results (per kW) by dividing
the Cost Estimate by the Capacity. Please provide Attachment 1 with formulas
enabled; and
e. Staff believes the normalized (per kW) cost estimate for a natural gas reciprocating
engine is erroneous because it shares the same full interconnection cost estimate
as the hydrogen combustion turbine and the simple cycle combustion turbine

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 18
("SCCT"), yet it has only 29 percent of the nominal capacity. Please verify and
provide the underlying calculations.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 80:
a. The interconnection costs provided in the 2023 Integrated Resource Plan (“IRP”)
were based on actual projects in the Company’s Generation Interconnection (“GI”)
Queue. For example, the interconnection cost for a 90-megawatt (“MW”) increase
at the Danskin substation was modeled after GI Queue #604 assumptions, and the
100 MW solar resource in Mountain Home was modeled after GI Queue #607
assumptions. In explanation of the cost differences, the existing Danskin
substation is already built out and would require further modifications to adjust
existing infrastructure to add a breaker position, while a new solar plant in the
Mountain Home area is assumed to be a new build site without any costs
associated with modifying existing equipment. The redacted system impact studies
for the specified GI Queue projects are publicly available on Idaho Power’s
website.1
b. Please see the response to part (a) of this request.
c. Idaho Power did not assume that additional expenses for a feeder connection were
appropriate for geothermal and biomass resources. Rather, the Company
assumed that the projects were connected to a lower voltage level and utilized the
typical interconnection cost for a project at the distribution level.
d. Please see the attached Excel spreadsheet.
e. Please see the attached Excel spreadsheet.
The response to this Request is sponsored by Andrés Valdepeña Delgado, System
Consulting Engineer, Idaho Power Company.

1 https://www.idahopower.com/about-us/doing-business-with-us/generator-interconnection/generator-
interconnection-study-reports/

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 19
STAFF REQUEST FOR PRODUCTION NO. 81: Pages 22 and 23 of Appendix C list the
Company's Supply Side Resource Escalation Factors for the 20-year planning horizon. Please
answer the following questions about this list:
a. Please explain if the Company based its cost escalation forecasts on independent
outside sources, or if it internally generated them. If the former, please list the
sources, and provide a copy of each source; If the latter, please explain the
Company's rationale and basis for each resource's escalation over the 20-year
period;
b. Given the recent national news about the cancellation of several large wind
projects due to rising costs, please explain the Company's justification for
forecasting wind resources to decrease in price for the next seven years; and
c. Please explain why in each of the 20 years, the escalation factors for wind, solar,
and battery storage are significantly lower than for all the other resources. Please
provide data to support these assumptions.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 81:
a. The Company based its cost escalation forecasts on the National Renewable Energy
Laboratory’s (“NREL”) 2022 Annual Technology Baseline (“ATB”) data, which is
provided in the attached Excel spreadsheet.
b. Please see the answer to part (a) for the data source for wind related cost escalation
forecasts. Idaho Power would like to clarify that the Integrated Resource Plan (“IRP”)
uses data as of a given point in time. As such, recent national news would not be
captured, nor should it be expected to be explicitly captured by the 2023 IRP
assumptions. If the recent national news that is being referenced is related to offshore
wind projects, then it is an inappropriate extrapolation to onshore wind costs. Offshore
wind (in its infancy in the United States) has many different cost factors compared to
onshore wind, which is a mature technology.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 20
c. Please see answer to part (a).
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 21
STAFF REQUEST FOR PRODUCTION NO. 82: Page 21 of Appendix C lists the Cost
Inputs and Operating Assumptions that the AURORA LTCE model uses to select resources.
Please answer the following questions about this list:
a. Please explain if the Company reduced any of the Plant Capital estimates to
account for federal clean energy tax credits. If so, please list which resources
received the reduction and provide a worksheet (with formulas enabled) showing
the nature and amount of the reduction(s);
b. Please provide the underlying data the Company used to determine the plant
capital estimates for the following resources. Please provide any supporting
worksheets with formulas enabled;
a) 100 MW Wind — Idaho;
b) 100 MW Solar PV;
c) 300 MW Baseload Gas; and
d) 100 MW Nuclear — Small Modular Reactor.
c. Please provide the underlying data the Company used to determine the fixed
operation and maintenance costs for wind resources ($4.10/kW-month). Please
provide any supporting worksheets with formulas enabled;
d. Please provide supporting evidence for a 30-year economic life for wind resources;
e. Please provide supporting evidence for a 30-year economic life for solar resources;
and
f. Please provide supporting evidence for a 20-year economic life for battery storage
resources.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 82:
a) The Table on Page 21 of the 2023 IRP Appendix C shows cost inputs that have not
been reduced due to any federal clean energy tax credits. The clean energy tax credits
are reflected in the Levelized Cost of Energy (“LCOE”) and Levelized Cost of Capacity

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 22
(“LCOC”) (see Appendix C pages 24 and 25). The clean energy tax credits are
assumed at 30 percent Investment Tax Credit (“ITC”) or the full Production Tax Credit
(“PTC”) for the following resources:
 Hydrogen – Simple Cycle Combustion Turbine (“SCCT”):
PTC
 Small Modular Nuclear Reactor: PTC
 Geothermal: PTC
 Biomass: PTC
 Solar: PTC
 Wind (Idaho/Wyoming): PTC
 All Storage Types: ITC
b) Please see the attached confidential Excel spreadsheet.
c) For wind resource cost assumptions, please see the National Renewable Energy
Laboratory (“NREL”) 2022 Annual Technology Baseline (“ATB”) data that was
provided in the Company’s response to Staff’s Request for Production No. 81 and the
associated attachment.
d) For information on the life of wind projects, please see the NREL 2022 ATB data that
was provided in the Company’s response to Request No. 81 and the associated
attachment.
e) For information on the life of solar projects, please see the NREL 2022 ATB data that
was provided in the Company’s response to Request No. 81 and the associated
attachment.
f) A 20-year life for battery storage resources is consistent with battery storage bids from
Idaho Power’s recent Requests for Proposals.

The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 23
STAFF REQUEST FOR PRODUCTION NO. 83: In its response to Production Request
No. 38, the Company provided Attachment 1. Please answer the following questions about
Attachment 1.
a. Please explain how the Company determined the Effective Load Carrying
Capability ("ELCC") values for the Variable Energy Resources ("VER") and ELRs.
If the Company obtained the values from an external source, please list the source,
and provide a copy. If the Company calculated the values internally, please provide
the supporting worksheets with formulas enabled;
b. Please explain why the Levelized Cost of Energy ("LCOE") capacity factors differ
from the Levelized Cost of Capacity ("LCOC") peaking capacity factors for each
VER; and
c. The LCOC for each resource changes significantly after the Company adjusts for
that resource's ELCC. Please explain whether the AURORA LTCE model uses
adjusted or unadjusted LCOC values when it selects new resources. If it uses
adjusted values, please explain why the Company does not list the adjusted values
in the Integrated Resource Plan. If it uses unadjusted values, please explain why
this is economically accurate.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 83:
a. The Effective Load Carrying Capability (“ELCC”) values of variable and energy-limited
resources utilized in Attachment 1 of the Company’s Response to Staff’s Request for
Production No. 38 were calculated with Idaho Power’s Reliability and Capacity
Assessment Tool (“RCAT”) and were provided on page 92 of the 2023 Integrated
Resource Plan (“IRP”) Appendix C: Technical Report. For further explanation on how
ELCC values are calculated by the internally developed RCAT, please refer to the
following sources:

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 24
 Loss of Load Expectation section of the 2023 IRP Appendix C: Technical Report2
 The December 8th, 2022, Integrated Resource Plan Advisory Council (“IRPAC”)
meeting, Reliability & Capacity Assessment presentation3
 The March 9th, 2023, IRPAC meeting, Loss of Load Analysis & ELCC Update
presentation4
 The Idaho Power pre-recorded IRP Educational Resource video on Reliability &
Capacity Assessment5
All MATLAB scripts and input files required to perform the ELCC calculation in the
Company’s RCAT were provided as attachments to the Company’s Response to Request
Nos. 1 and 2.
b. Capacity factor is a metric used to determine how frequently a power plant operates for a
given amount of time. It is computed by dividing the actual unit electricity output by the
maximum output (nameplate) multiplied by the number of hours in that same time, and it
is expressed as a percentage. As defined in the Company’s Response to Staff’s Request
for Production No. 38, peaking capacity (factor), or contribution to peak, can be defined
as a resource’s ELCC; ELCC is not a function of energy or time like the capacity factor.
For further information on ELCC please see the 2023 Integrated Resource Plan (“IRP”)
Report, starting on page 56.
c. The Company would like to clarify that the 'ELCC adjusted' Levelized Cost of Capacity
(“LCOC”) value was intended to be illustrative and is not a common industry metric, like
“unadjusted” LCOC. The “unadjusted” LCOC of a resource, along with its unique
characteristics, such as ELCC, output shape, and ramp rates are all input into the

2 https://docs.idahopower.com/pdfs/AboutUs/PlanningForFuture/irp/2023/2023-appendix-c-final.pdf
3
https://docs.idahopower.com/pdfs/AboutUs/PlanningForFuture/irp/2023/2023IRP_ReliabilityCapacityAssessment.pdf
4 https://docs.idahopower.com/pdfs/AboutUs/PlanningForFuture/irp/2023/2023_03_07_PRM_ELCC_WRAP.pdf
5 https://youtu.be/Ds968-NI3wc?si=i62PQPYN2GpYYb2T

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 25
AURORA Long-Term Capacity Expansion (“LTCE”) model (as has been historically done
in past IRPs). AURORA optimizes to meet peak demand, as well as demand in every
hour, while meeting reliability constraints and minimizing cost. As shown through the
portfolio analysis, stochastic analysis, and validation/verification process, the AURORA
LTCE model produced a Preferred Portfolio that was least-cost and least-risk.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 26
STAFF REQUEST FOR PRODUCTION NO. 84: The 2023 IRP load forecast shows that
the average system load will grow by 975 MW, and the peak load by 1,507 MW, by 2043. To
satisfy this load increase, the preferred portfolio recommends adding 5,125 MW of wind and solar
and 1,453 MW of battery storage. Using the cost inputs on page 21 of Appendix C, Staff estimates
the simple cost to build these resources and operate them for 10 years to be approximately $11.7
billion.
Using the Baseload Gas cost input data, Staff calculates that a single 1,073 MW
combined-cycle combustion turbine (90.9 percent capacity factor), and a single 585 MW SCCT
for peaking capacity, could provide the same 10 years of power for approximately $2.9 billion.
Using the Small Modular Reactor data, Staff calculates that a 994 MW nuclear reactor
(98.1 percent capacity factor), and a 585 MW SCCT for peaking capacity, could provide the same
power for $10.5 billion, along with a 60-year life expectancy.
These simple alternative scenarios don't account for diversification risks, the timing of
need, and the time value of money; however, they do highlight a much higher cost of a solar,
wind, and battery portfolio relative to a baseload thermal resource portfolio. Please explain why
none of the scenario portfolios include significant baseload thermal resource additions, but
invariably add solar, wind, and batteries, instead.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 84:
Although the Company was not provided with the derivation of the numbers listed in this
request, the Company believes it was able to replicate the Staff’s approximated $11.7 billion
Preferred Portfolio case, the $2.9 billion baseload gas cost, and the $10.5 billion small modular
reactor (“SMR”) and Simple Cycle Combustion Turbine (“SCCT”) combination costs. Based on
the Company’s replication of these values, the simplifications used in the values’ construction are
missing some key considerations:
a. As stated in the request, the values here do not account for the time value of money and
the resource selections do not account for diversification risks.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 27
b. The portfolios presented by Staff have not been tested to determine if they provide
adequate capacity and energy to create reliable resource portfolios. By comparison, the
Preferred Portfolio was tested for reliability and accounts for diversification risk.
c. Based on the Company’s replication of the numbers provided in this request, the values
presented do not include:
i. The reduction in costs associated with wind and solar energy production related to
the selling of Renewable Energy Credits.
ii. The reduction in costs associated with Production Tax Credits (“PTC”) that have
now been extended for renewable resources and battery storage.
iii. The cost of fuel. For the baseload gas scenario, it’s reasonable to expect the
substantial addition of gas resources to need fuel to provide the energy and
capacity expected. Likewise, in the SMR case, the cost of uranium fuel is also
missing from the calculations.
iv. The environmental regulations that make it difficult to construct natural gas
generation quickly.
v. The cost of Carbon used in the 2023 Integrated Resource Plan (“IRP”). Although
more a concern in the baseload gas numbers, even the SMR case includes an
SCCT that will need to run during peak periods.
vi. The cost of a gas pipeline expansion necessitated by the addition of more than
600 megawatts (“MW”) of new gas resources6.
d. Based on the Company’s replication of the numbers provided in this request, the values
presented do not account for dispatch of resources. Specifically:
i. The Baseload gas and SMR cases generate all their energy from the baseload
resource with the SCCT providing only capacity. This is not a feasible dispatch

6 2023 IRP Report at page 112.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 28
solution because, during the peak hour, the SCCT must be both incurring its fixed
and variable cost. Indeed, there are many hours when the SCCT would need to
operate.
ii. The simplified use of 975 MW in all hours does not account for the reality that there
would be many hours below the average 975 MW of load. Likewise, there would
be many hours where load was above the average of 975 MW. Without accounting
for the load variability and using only the 975 MW, both the Baseload gas and SMR
cases underestimate the cost of serving variable load.
iii. The lack of dispatch modeling doesn’t capture the ancillary benefits of storage
resources (such as arbitrage) in the Preferred Portfolio.
e. The capacity factors used in this calculation are high. According to the Energy Information
Administration (“EIA”), a typical modern high efficiency Combined Cycle Combustion
Turbine (“CCCT”) plant capacity factor is about 65 percent while a nuclear plant operates
closer to 92 percent. The CCCT value of 90.9 percent and the SMR value of 98.1 percent
likely represent the theoretical maximum in a perfect year of operations and do not
reasonably incorporate maintenance time, economic operations, and refueling cycles.
The Company’s analysis in the 2023 IRP accounted for the time value of money, resource
diversification and the need to build reliable portfolios, a full accounting of costs including
Renewable Energy Credits, PTCs, fuel, and environmental, reasonable operations of plants and
their capacity factors, actual modeling of resource dispatch to match load, and the necessity of a
pipeline expansion after 600 MW of new gas. Once the full accounting of costs and operating
characteristics is included in an analysis, as was done in the 2023 IRP, then the addition of solar,
wind, and batteries are a lower-cost and lower-risk alternative to baseload thermal resources.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 29
DATED at Boise, Idaho, this 25th day of January 2024.

Lisa Nordstrom
Attorney for Idaho Power Company

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF- 30
CERTIFICATE OF SERVICE

I HEREBY CERTIFY that on the 25th day of January 2024, I served a true and correct
copy of Idaho Power Company’s Response to the Third Production Request of the Commission
Staff upon the following named parties by the method indicated below, and addressed to the
following:

Commission Staff
Chris Burdin
Deputy Attorney General
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg No. 8
Suite 201-A (83714)
PO Box 83720
Boise, ID 83720-0074

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Micron Technology, Inc.
Austin Rueschhoff
Thorvald A. Nelson
Austin W. Jensen
Holland & Hart, LLP
555 Seventeenth Street, Suite 3200
Denver, Colorado 80202

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Jim Swier
Micron Technology, Inc.
8000 South Federal Way
Boise, Idaho 83707
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________________________________
Christy Davenport
Legal Administrative Assistant