20240104IPC to Staff 32-66.pdf

MEGAN GOICOECHEA ALLEN
Corporate Counsel
[e-mail]

January 4, 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
Second Production Request of Commission Staff.

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

Very truly yours,

Megan Goicoechea Allen
MGA:cd
Attachments
RECEIVED
Thursday, January 4, 2024 4:29PM
IDAHO PUBLIC
UTILITIES COMMISSION
IDAHO POWER COMPANY’S RESPONSE TO THE SECOND 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 SECOND
PRODUCTION REQUEST OF THE
COMMISSION STAFF

COMES NOW, Idaho Power Company (“Idaho Power” or “Company”), and in response
to the Second Production Request of the Commission Staff (“Commission” or “Staff”) dated
December 14, 2023, herewith submits the following information:

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 2
STAFF REQUEST FOR PRODUCTION NO. 32: Please explain why the Company built
the following constraints into its AURORA Long Term Capacity Expansion ("LTCE") model:
a. Please explain why the Company constrained the LTCE model to select between exiting
Valmy Unit 2 at the end of 2025 or converting to natural gas in 2026. IRP at 9;
b. Please explain why the Company required Bridger Units 1 and 2 (already converted to
natural gas in 2024) to shut down at the end of 2037. IRP at 10;
c. Please explain why the Company required Bridger Units 3 and 4 to shut down at the end
of 2029 or convert to natural gas in 2030;
d. Please explain why the Company required Bridger Units 3 and 4 (if converted to natural
gas in 2030) to shut down at the end of 2037; and
e. Please explain why the Company allowed Valmy Units 1 & 2 to operate indefinitely on
natural gas, if economically favorable.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 32:
a. The Valmy coal to gas conversion or exit date is based on alignment with the plant’s co-
owner and operator, NV Energy. As such, the modeling constraints discussed on page 9
of the 2023 Integrated Resource Plan (“IRP”) for the Valmy Unit Conversions match Idaho
Power’s options for participation in the plant.
b. The 2037 shutdown for Bridger Units 1 and 2 (provided there was not an early exit) was
an update from the assumed end of life for these units of 2034 used in the 2021 IRP. This
extension to 2037 aligns with the assumptions made by the co-owner and operator,
PacifiCorp.
c. The Company would like to clarify the language on page 10 of the 2023 IRP report about
Bridger Units 3 and 4. Rather than an end of year shut down in 2029 or a conversion to
gas being the only two options available to those units, the model was also allowed to exit
from those units in years 2026-2029 before the conversion occurs. The exit and
conversion timing are based on alignment with the co-owner and operator, PacifiCorp.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 3
d. The 2037 shutdown for Bridger Units 3 and 4 was an update from the 2034 assumed end
of life for these units used in the 2021 IRP. The extension to 2037 aligns with the
assumptions made by the co-owner and operator, PacifiCorp.
e. Based on alignment with the plant’s co-owner and operator, NV Energy, the converted
Valmy units are assumed to have an end of life that occurs after the planning horizon, in
2045.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 4
STAFF REQUEST FOR PRODUCTION NO. 33: The Company states that it will account
for the Federal Good Neighbor Plan by modeling a range of nitrogen oxide ("NOx") allowances
for Valmy and Bridger. IRP at 23. Please explain the following:
a. Please explain the Company's NOx model in detail;
b. Please explain if the model establishes an economic penalty, like the carbon adder, for
NOx emissions. If so, please provide the penalty tables used by the Company, and the
data that supports those tables;
c. Please explain if a plant's exceedance of one or more NOx allowances results in the
shutdown, restriction, or conversion of that plant in the AURORA model; and
d. Please explain any impacts that modeling NOx had on the selection of resources in the
portfolios.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 33:
a. The Company’s NOx model works like other emissions estimates in the model. For Valmy,
and any other NOx-emitting resource, a NOx emissions rate in pounds per million British
Thermal Units (“lbs/MMBtu”) is entered into the AURORA model. As the AURORA model
dispatches those units, it calculates the emissions associated with that dispatch based on
total fuel throughput.
b. The 2023 Integrated Resource Plan (“IRP”) assumed compliance with the Good Neighbor
Plan for operations at North Valmy. The model was not allowed to dispatch the North
Valmy units such that they would produce NOx emissions that exceed the NOx
allowances.
c. In the case of a NOx emissions limit, the AURORA model is allowed to dispatch that unit
up to the limit but will not exceed it. This can have the effect of reducing total energy
production that might otherwise be considered economic.
d. The 2023 IRP assumed compliance with the Good Neighbor Plan and did not test
assumptions without the expected NOx constraints. Thus, the following is a general

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 5
description of possible impacts. If the NOx constraint curtailed production that would have
otherwise been economical, energy would need to come from other resources. This may
result in either additional resource build or dispatch from existing but less economic
generation sources.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 6
STAFF REQUEST FOR PRODUCTION NO. 34: The Company states that it "treats
approximately 500 MW of B2H's summer capacity as equivalent to a summer resource." and "200
MW of winter import capacity as equivalent to a winter resource." IRP at 89. However, the IRP
does not list these values in any of the LTCE Results (IRP Appendix C, pp. 42-71). Please explain
how the Company incorporated transmission as a resource in the LTCE analysis.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 34:
The summer and winter import capacity associated with Boardman to Hemingway (“B2H”)
is incorporated in the Long-Term Capacity Expansion (“LTCE”) analysis through use of the ‘Firm
Import’ variable. The ‘Firm Import’ variable is counted toward the AURORA-calculated Planning
Reserve Margin (“PRM”) within the model, meaning the inclusion of the B2H capacity reduces the
need to add other generation or transmission resources in order to meet the required PRM.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 7
STAFF REQUEST FOR PRODUCTION NO. 35: Figures 7.4 and 7.5 of the IRP depict the
historical and forecast load data for multiple southwestern balancing authorities. The Company
asserts that the large gap between summer load and winter load ensures there will be a surplus
of winter power available for purchase on the market. However, a large percentage of the
southwest generation resources are solar, so the winter generation profile will diminish in
conjunction with the load profile. Please provide the Company's analysis that compares the winter
generation profile to the winter load profile.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 35:
Please see the attached Excel spreadsheet for the amount of non-coal-fired thermal
resource generation in Arizona and Southern Nevada within the Western Electricity Coordinating
Council (“WECC”) 2024 Heavy Winter power flow case. Focusing just on these dispatchable
thermal resources alone, the amount of generation within Arizona and Southern Nevada far
exceeds the amount of load. From the analysis, Arizona and Southern Nevada have 6,577
megawatts (“MW”) and 2,006 MW of net thermal resource capacity above peak winter load levels,
respectively. This gap between generation and load in the southern market area is indicative of
an opportunity to access the southern energy market for winter season imports. Please note that
this analysis conservatively focuses on dispatchable thermal resources and does not consider
energy storage projects and solar projects.
The response to this Request is sponsored by Curtis Westhoff, System Consulting
Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 8
STAFF REQUEST FOR PRODUCTION NO. 36: Table 7.8 lists the transmission
interconnection assumptions for each supply-side resource. Please answer the following
questions:
a. Please provide an expanded version of Table 7.8 that includes the following for each
resource:
i. The raw capital cost estimate for transmission interconnection;
ii. The normalized (per kW) capital cost estimate; and
iii. An explanation of the major assumptions that drive the normalized cost
differences.
b. Please explain why the Company assumes the "Wind-Wyoming" 100 MW resource will be
within 5 miles of Jim Bridger, even though the resource plan calls for 18 new 100 MW wind
resources.
c. Please explain why the Local Interconnection Assumption note for Solar PV Utility-Scale
is nearly identical to the notes for Natural Gas resources, but the Natural Gas resources
have a normalized interconnection cost seven times larger than Solar PV.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 36:
a. Please see the attached Excel spreadsheet for the requested cost estimates. The
difference in normalized costs is driven by the assumed location of the resource options
on the Idaho Power system and the associated required interconnection transmission
upgrades.
b. For wind resources, an 800-megawatt (“MW”) Wyoming wind limit is set at the upper end
of available transmission capacity for transmission resources from Wyoming (Jim Bridger
Plant) to Idaho. There is also a total wind cap of 1,800 MW, which accounts for wind from
Idaho and/or Wyoming.
c. The Local Interconnection Assumption notes for solar PV utility-scale and natural gas
resources are identical because both resource types are assumed to connect to a 230-kV

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 9
system. However, the natural gas resources were assumed to be connected on the west
side of the Treasure Valley area while the solar PV utility-scale was assumed to connect
in the Mountain Home area. Interconnection costs are location dependent and vary based
on the project’s required network upgrades. The natural gas resources’ location
assumptions were based on other requirements to interconnect a gas resource such as
water availability and proximity to a natural gas pipeline. The solar PV utility-scale was
assumed to be located in the Mountain Home area given the amount of interconnection
requests that the Company has received from developers in recent years.
The response to this Request is sponsored by Curtis Westhoff, System Consulting
Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 10
STAFF REQUEST FOR PRODUCTION NO. 37: The Company states that, Levelized
Cost of Energy ("LCOE") is not an input into the AURORA modeling performed for the IRP. IRP
at 115. Please explain the decision logic used by the AURORA LTCE model to select resources
that are least-cost. Please provide the data table that informs the model, and please provide an
explanation of each of the data fields.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 37:
At its simplest level, the decision logic used by the AURORA Long-Term Capacity
Expansion (“LTCE”) model is to select the optimal portfolio of resources (with their individual
operating characteristics and constraints) that will provide the generation capable of reliably
serving load while minimizing the cost.
On the other hand, and as more fully explained in the 2023 Integrated Resource Plan
(“IRP”) report, the calculation of a levelized cost of energy (“LCOE”) value requires several
assumptions and only reflects an approximation of cost competitiveness. It doesn’t consider
whether a particular resource could actually serve load every hour of the year, nor does it change
based on dispatch or technological cost curves. The LCOE values provide a simplistic way of
comparing resource costs that the Company has historically provided as a way to educate the
general public and the IRP Advisory Council about generic resource costs. The high-level nature
of LCOE, however, makes it an inappropriate measure to compare resource costs in actual
operational settings.
Instead of using the simplified LCOE metric, the AURORA LTCE model uses sophisticated
cost metrics that more precisely capture the cost of resources. Those metrics are: fixed costs
(based on capital costs and fixed operations and maintenance), variable costs (non-fuel-related
costs that vary by energy resource), fuel costs if applicable, and other secondary cost modifiers
like emissions costs or Renewable Energy Certificates. Based on these more nuanced cost inputs
and the defined operating characteristics, the model will select resources that can serve load for
every hour of the planning horizon while minimizing the cost of those resources.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 11
For the fixed and variable cost inputs, as well as the technological cost curves, please see
2023 IRP Appendix C, pages 21 through 23.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 12
STAFF REQUEST FOR PRODUCTION NO. 38: Table 8.3 is the Levelized Cost of
Capacity ("LCOC") for supply-side resources. The Company states that the values "are presented
in terms of dollars per kW of nameplate capacity per month." IRP at 114. However, the Company
also says that "expression of these costs in terms of kW of peaking capacity can have a significant
effect...." Id. Please provide the following information:
a. Please clarify the definition of peaking capacity;
b. If peaking capacity is different from a resource's Effective Load Carrying Capacity please
explain any differences and explain how peaking capacity is determined;
c. Please provide an expanded version of Table 8.3 that includes the following for each
resource:
i. The raw capital cost, without normalizing, and without adjusting for the tax credits;
ii. The raw capital cost, without normalizing, but adjusted for tax credits;
iii. The resource's assumed peaking capacity; and
iv. The resource's Total Cost per kW/mo., adjusted for peaking capacity.
d. Please provide the basis for each resource's assumed peaking capacity; and
e. Please provide the underlying worksheets that inform Table 8.3.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 38:
a. Peaking Capacity, or contribution to peak, can be defined as a resource’s Effective Load
Carrying Capability (“ELCC”) value multiplied by its nameplate capacity for Variable
Energy Resources (“VER”) and Energy Limited Resources (“ELR”). For flexible resources,
the peaking capacity is the nameplate multiplied by one, minus their Equivalent Forced
Outage Rate during Demand (“EFORd”).
b. Please see the response to part (a) of this request.
c. Please see the attached Excel spreadsheet.
d. Please see the response to part (a) of this request.
e. Please see the attached Excel spreadsheet.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 13
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 14
STAFF REQUEST FOR PRODUCTION NO. 39: Please explain the following regarding
Table 8.3:
a. Please explain why the Company opted to report the levelized cost per kW/month, instead
of per kW/year which has been the standard for previous IRPs;
b. Please explain why the normalized capital cost for Danskin 1 Retrofit is 60 percent higher
than the normalized capital cost to build a new Combined Cycle Combustion Turbine
("CCCT").
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 39:
a. The Company has not changed the units for levelized cost of capacity (“LCOC”) for the
2023 Integrated Resource Plan (“IRP”). Over the past four IRPs, starting in the 2015 IRP1,
the Company has reported LCOC units in dollars per kilowatt per month (“$ per
kW/Month”).
b. A retrofit of an existing Simple Cycle Combustion Turbine (“SCCT”) plant to operate as a
Combined Cycle Combustion Turbine (“CCCT”) plant involves the addition of a Heat
Recovery Steam Generator (“HRSG”). To do so on an existing SCCT requires substantial
modifications of the current unit that were not contemplated in the original design.
Construction would require not only the addition of the new HRSG but also dismantling of
the existing SCCT’s components. It is this extensive and custom engineering work (that
can’t be spread across multiple installations) and the double work of dismantling and
reconstructing the existing unit that increases the cost of the unit. Finally, generating
efficiency does not result from this kind of conversion, as the additional kilowatts (“kW”)
produced from an existing SCCT (with a retrofit) are fewer than the additional kWs
produced from a new CCCT; meaning, there are fewer kWs to divide the cost by in dollars
per kilowatt per month (“$ per kW/Month”) metric.

1 Idaho Power Company’s 2015 Integrated Resource Plan, p. 88.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 15
The response to this Request is sponsored by John Carstensen, Joint Projects Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 16
STAFF REQUEST FOR PRODUCTION NO. 40: Table 8.4 is the levelized cost of energy
("LCOE") for supply-side resources. Please explain the following:
a. Please provide the underlying worksheets that inform Table 8.4;
b. Please explain why the capital cost for converting Danskin 1 to CCCT is $56/kW, but the
capital cost to build a new CCCT is only $36/kW.
c. Please clarify if the LCOE capacity factor is the same or different than the LCOC peaking
factor;
d. Please provide the Company's basis for each resource's LCOE capacity factor.
e. Please clarify why variable wind and solar have capacity factors ranging from 31 percent
to 47 percent, while a gas CCCT has a capacity factor of only 55 percent.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 40:
a. Please see the attached Excel spreadsheet for the requested information.
b. As a point of clarification, the units (including Cost of Capital) for the Levelized Cost of
Energy table in Table 8.4 of the 2023 Integrated Resource Plan (“IRP”) report are in units
of dollars per megawatt-hour (“$/MWh”), except for the Capacity Factor which is given as
a percentage. The costs depend on the capital cost of the given resources, which differ
for Danskin 1 retrofit compared to a new Combined Cycle Combustion Turbine (“CCCT”).
Please also see the Company’s response to Request No. 39 for more information.
c. As a point of clarification, Idaho Power does not use the term or metric of “peaking factor.”
The Company presumes that Staff is inquiring whether there is a difference between
capacity factor and peaking capacity. If so, the answer is yes: capacity factor, or the
average output over a year as a percentage of nameplate, is different than peaking
capacity, which assesses how much a given resource can contribute to the Company’s
timing of need.
d. Please see the attached Excel spreadsheet for the requested information.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 17
e. The capacity factors of solar and wind are mainly driven by the resource type and their
geographic location. Meanwhile, the capacity factor of a CCCT is based on numbers from
the Energy Information Administration (“EIA”). The assumed solar resource in the 2023
IRP has a capacity factor of 31 percent. The assumed Idaho wind resource in the 2023
IRP has a 36 percent capacity factor. The assumed Wyoming wind resource in the 2023
IRP has a 47 percent capacity factor. The 55 percent CCCT capacity factor from EIA is
consistent with the US fleet average.2
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

2 U.S. Energy Information Administration, Annualized capacity factor of U.S. combined-cycle natural gas
turbine power plants, November 20, 2023,
https://www.eia.gov/todayinenergy/detail.php?id=60984#:~:text=The%20average%20utilization%20rate%2
0(or,2008%20to%2057%25%20in%202022

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 18
STAFF REQUEST FOR PRODUCTION NO. 41: Please explain why the Company, when
calculating the LCOE for all storage resources, does not consider the cost of energy to fill that
resource.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 41:
The levelized cost of energy (“LCOE”) is intended to be a simplified approximation of
relative resource costs that depends on many assumptions. Energy storage resources are
particularly ill-suited to the standard LCOE metric, as the cost of energy required to fill the storage
resource and the revenue generated from its discharge varies depending on factors such as how
and when the storage resource is used, market conditions (which themselves depend on myriad
factors), and presumptions of future resource builds. It is notable that Lazard, one of the leading
research firms that produces annual LCOE reports, recognized the difficulties of applying a basic
LCOE view to storage and, to address this issue, created a special levelized-cost report specific
to storage.3 Idaho Power notes this to explain that modeling storage resources is particularly
complex and that, given the speculative nature of many of storage cost assumptions and their
variation across each portfolio, Idaho Power has not endeavored to estimate these costs for
inclusion. Please note that the AURORA Long-Term Capacity Expansion (“LTCE”) model
accounts for all of the costs of energy storage resources, including the cost of energy and the
value of the discharged energy.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

3 https://www.lazard.com/media/42dnsswd/lazards-levelized-cost-of-storage-version-70-vf.pdf

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 19
STAFF REQUEST FOR PRODUCTION NO. 42: The Company states that "the wholesale
energy purchases and sales made available through B2H capacity are not included in the graphed
LCOE values." IRP at 115. Please explain why the Company does not consider the cost of energy
purchases in its determination of LCOE values for transmission resources. Please explain why
transmission resources are missing from the LCOC and LCOE tables.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 42:
The levelized cost of energy (“LCOE”) is intended to be a simplified approximation of
relative resource costs that depends on many assumptions and is used specifically to provide
snapshot costs for energy generating resources. As noted in the Company’s response to Staff’s
Request for Production No. 41, energy storage is difficult to fit into the simplistic LCOE framework.
Similarly, transmission is not a generating resource and, as such, cannot be evaluated using
LCOE. It should be noted that Table 8.4, which is the direct reference to the IRP text on p. 115,
to which Staff refers, does not provide LCOE for any transmission resource, including B2H. With
the statement highlighted by Staff, the Company was simply trying to communicate that wholesale
energy purchases and sales from B2H, a major identified resource need in the IRP, is not reflected
on the table because the transmission itself is not listed on the table.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 20
STAFF REQUEST FOR PRODUCTION NO. 43: Table 8.5 lists the unquantifiable
attributes of various resources. Please explain if and how the AURORA LTCE model considers
these attributes in its resource selection. If the LTCE model does not consider them, please
explain how the Company uses the attribute information to select resources.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 43:
Table 8.5 of the 2023 Integrated Resource Plan (“IRP”) shows a summary of general
resource attributes of selectable resources based on the way they are modeled in the IRP’s
AURORA Long-Term Capacity Expansion (“LTCE”) model. The LTCE considers each resource
attribute as follows:
 Dispatchable Capacity-Providing resources are modeled by AURORA as resources to be
dispatched economically and that provide capacity.
 Balancing- and Flexibility-Providing resources are resources that are allowed to provide
ancillary and regulation requirements in the model.
 Energy Providing Resources are resources that are modeled to provide energy.
 Variable Energy Resources (“VER”) are renewable resources characterized by variable
output that have the potential to cause an increased need for Balancing- and Flexibility-
Providing Resources. As such, the variable nature of VERs is modeled by using a
generation profile along with specific solar and wind regulation requirements. The
regulation requirements help model the need for more Balancing- and Flexibility-Providing
Resources that support VER generation.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 21
STAFF REQUEST FOR PRODUCTION NO. 44: In the Company's response to
Production Request No. 10, the Company stated that "[t]he estimated cost has been updated to
reflect preliminary bids received for materials and construction." As supplement to the Company's
Confidential Attachment 1, please provide the following:
a. Please explain when the Company expects to have finalized bids for materials and
construction;
b. Please explain what the new line item "BPA funding of 2023 Permitting" entails;
c. Please explain the decrease for the cost estimate for "BPA's Share of Pre-Construction
Costs";
d. Please explain if the cost estimate for the "Right of Way Option Costs" reflects the final
cost of Right of Way expenses or a portion of Right of Way expenses incurred to date;
e. Please explain why there is a decrease for the cost estimate "Transmission Line
Construction & Mitigation Contingency"; and
f. Please explain the increase for the cost estimate of "BPA Permitting Buyout".
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 44:
a. The Company anticipates finalized bids for materials and construction in the first quarter
of 2024.
b. Bonneville Power Administration (“BPA”) funded Boardman to Hemingway (“B2H”)
permitting costs in accordance with the B2H Joint Permit Funding Agreement until their
permitting interest was transferred to Idaho Power in March 2023, upon execution of the
B2H Purchase, Sale, and Security Agreement. The Company previously anticipated this
would occur in 2022.
c. The pre-construction costs incurred prior to BPA’s transfer of B2H permitting interest were
lower than initially estimated.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 22
d. “Right of Way Option Costs” includes the costs related to obtaining and funding option
agreements only. Right of Way costs associated with exercising the options is included in
“Construction and Mitigation Direct Costs.”
e. The Company reduced construction contingency to 5 percent when the estimated cost
was updated to reflect preliminary bids received for materials and construction.
f. The negotiation period between the Company, BPA, and PacifiCorp took longer than
originally estimated, so BPA funded the B2H project for longer, increasing the cost of the
“BPA Permitting Buyout.”
The response to this Request is sponsored by Lindsay Barretto, 500KV and Joint Projects
Senior Manager, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 23
STAFF REQUEST FOR PRODUCTION NO. 45: As supplement to the Company's
response to Production Request No. 13, please explain if the Company has considered any
alternative actions if the Gateway West Phase 1 ("GWW1") is delayed beyond 2029. If so, please
provide the Company's considered actions. Additionally, please explain who the project manager
for Segments 8 and 10 will be.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 45:
In the event Gateway West Phase 1 is delayed beyond 2029 and planned incremental
resource additions are dependent on the upgrade, a limited operation transmission service study
would need to be completed to develop operating plans to allow resources to be brought online
subject to curtailment. Further known delay risks and levels of potential resource curtailment
would also be analyzed and considered in future resource Request for Proposal (“RFP”) analysis
performed by the Company.
The project manager for both Segment 8 and 10 is currently PacifiCorp.
The response to this Request is sponsored by Curtis Westhoff, System Consulting
Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 24
STAFF REQUEST FOR PRODUCTION NO. 46: As supplement to the Company's
Attachment 1 for its response to Production Request No. 15, in excel format, please provide the
historical total Customer Count by month for:
a. Residential Customer Class: for 2012 through 2023;
b. Commercial Customer Class: for 2012 through 2023; and
c. Irrigation Customer Class: for 2012 through 2023.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 46:
Please see the attached Excel spreadsheet for the requested information.
The response to this Request is sponsored by Jordan Prassinos, Load Forecast Manager
and Principal Economist, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 25
STAFF REQUEST FOR PRODUCTION NO. 47: In the Company's Attachment 1 for its
response to Production Request No. 15, the Residential and Irrigation customer generation
forecasts both transition to using a customer forecast month over month growth in 2034 and 2029,
respectfully. Please explain why the Commercial customer generation forecast does not transition
to a similar forecast.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 47:
The Commercial customer generation forecast does not transition to using the class
month-over-month growth, as the Company is confident that the forecasted terminal saturation is
reasonable. In both the Residential and Irrigation customer generation forecasts, the terminal
saturation exceeds what the Company deems reasonable, necessitating the implementation of
the class month-over-month growth governor.
The response to this Request is sponsored by Jordan Prassinos, Load Forecast Manager
and Principal Economist, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 26
STAFF REQUEST FOR PRODUCTION NO. 48: As supplement to the Company's
response to Production Request No. 16 — Attachment 1, please provide the R.L. Polk & Co.;
Moody's Analytics Forecast that the Company used in its forecast for electric vehicle adoption.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 48:
Please see Attachment 1 of the Company’s response to Request No. 16. The R.L. Polk &
Co.; Moody's Analytics Forecast is located in the sheet titled ‘MoodyVehFcst’. This data includes
both historic and forecast levels of new vehicle registrations for both Idaho and the United States.
The response to this Request is sponsored by Jordan Prassinos, Load Forecast Manager
and Principal Economist, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 27
STAFF REQUEST FOR PRODUCTION NO. 49: In the Company's response to
Production Request No. 17, the Company stated that "[o]nce the built-out precipitation benefits
were estimated, the process for determining the hydro resource impact followed the same
modeling procedures as with the current build-out precipitation benefits." Please provide and
explain the assumed benefits of the built-out precipitation.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 49:
As an initial point of clarification, Idaho Power’s use of the term “built out” is intended to
reflect a program at scale. In 2003, Idaho Power began its initial cloud seeding efforts targeted
the south and middle forks of the Payette watershed. Over time, the Company’s Payette project
reached build-out, allowing cloud seeding operations to be expanded to target additional
watersheds (the Boise Basin, the Wood River Basin, and the Upper Snake). At build-out, the
Payette program had one aircraft and 17 remote ground-seeding generators located to seed a
wide range of storm directions and atmospheric conditions that can bring snow to the Payette.
Remote ground-seeding equipment is located on high-elevation private property or state land,
and sites are roughly five to seven miles apart where access allowed. The project has
meteorological instrumentation to provide observed weather and atmospheric conditions to guide
operations.
While the Boise and Wood River Basins are not built out to the level of the Payette, they
do have an aircraft for airborne seeding and remote generators. However, there is still potential
for additional remote ground-seeding equipment in the Boise and Wood River Basins to target
the high elevation areas of the watersheds more thoroughly over a wider range of storm and
atmospheric conditions, further increasing runoff. Similarly, Idaho Power’s Upper Snake cloud
seeding project has one aircraft, 25 remote ground generators, and some meteorological
instrumentation. Yet, there is still opportunity to target the Upper Snake more adequately by
adding aircraft and remote ground generators.
In total, the Company’s total cloud seeding program has 57 remote ground generators

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 28
across the Payette, Boise, Wood, and Upper Snake River Basins. Using the Payette as a
reference for a built-out program, considering characteristics including terrain, equipment spacing
(density), available land for siting, and prevailing atmospheric conditions, Idaho Power has
estimated that building out the Boise, Wood and Upper Snake programs would bring the count of
total remote ground generators to between approximately 80 to 85 units.
There is currently not a way to directly simulate increased precipitation (or runoff) benefits
resulting from a new or expanded program. Instead, Idaho Power uses a statistical target-control
analysis to estimate precipitation benefits of the current programs in the Payette, Boise, Wood
River, and Upper Snake River Basins. Criteria including availability of land to site additional
seeding equipment (and the resulting equipment density), and the sites ability to seed the target
area (proximity to the target, terrain type, typical storm directions, site elevation relative to
inversion) were considered in estimating increased precipitation benefits of a built-out program.
Relative comparisons were made to relate each basin’s current build level (and resulting target-
control precipitation benefits) to what the potential build out level could be. The Company then
compared these results to the fully built-out Payette Basin to estimate the precipitation benefits
for an expanded Boise, Wood and Upper Snake River Basin cloud seeding project.
For more details of the quantified benefits, please see the attached Excel spreadsheet.
The response to this Request is sponsored by Shaun Parkinson, Meteorology and Cloud
Seeding Leader, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 29
STAFF REQUEST FOR PRODUCTION NO. 50: As supplement to the Company's
response to Production Request No. 18, please explain any anticipated customer benefits for the
Company's involvement in Southwest Intertie Project - North ("SWIP-N"). Please provide the
assumptions used in determining benefits.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 50:
The Southwest Intertie Project-North (“SWIP-N”) project would provide Idaho Power
additional transmission capacity to an energy market hub that is diverse from the winter-peaking
Pacific Northwest Mid-C market. As described in the Southwest Market Opportunity section of
Chapter 7 in the 2023 Integrated Resource Plan (“IRP”), the desert southwest is a summer-
peaking region with a large gap between its peak summer demand and peak winter demand. The
SWIP-N project could enable the Company to access the liquid desert southwest market during
winter, while avoiding more costly internal resource builds to meet the forecasted growth in peak
winter energy demands. With the anticipated growth in solar and battery energy storage
development in the southwest region, it is reasonable to assume that the line could also provide
some limited summer capacity benefit for Idaho Power customers that would also be diverse from
Idaho-based solar generation and Mid-C market imports.
Further, as the existing electrical system becomes increasingly utilized, new transmission
line infrastructure like SWIP-N allows additional operational flexibility, which ultimately benefits
Idaho Power’s customers. For example, additional operational flexibility would significantly benefit
customers when responding to outages on the single 345-kilovolt (“kV”) line from the North Valmy
plant to Midpoint. Idaho Power resources interconnected on this line path include the North Valmy
plant, Jackpot Solar, and the planned Franklin Solar and Battery projects. Currently, when
sections of the 345 kV line are taken out of service (whether planned or unplanned), system
operators must search to find and reserve alternative transmission paths to bring the energy to
the Idaho Power system. This is challenging today, because the Northern Nevada transmission
system only has a few connections with the rest of the Western Interconnection. The SWIP-N line

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 30
creates a new path from Nevada to Idaho, which would help resolve transmission redundancy
issues with the Valmy-Midpoint 345 kV line.
The response to this Request is sponsored by Curtis Westhoff, System Consulting
Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 31
STAFF REQUEST FOR PRODUCTION NO. 51: As supplement to the Company's
response to Production Request No. 20 — Attachment 1, please explain the following:
a. In the "Preferred Portfolio" tab, please explain why the amount of "Transmission" does not
change from the amount provided in the "Pre IRP" tab; and
b. In the "Preferred Portfolio" tab, please explain why the Company's "Highest Risk Season"
changes to "Winter" in 2028 rather than 2027 as described in the "Pre IRP" tab.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 51:
a. Firm transmission and the capacity associated with Boardman to Hemingway (“B2H”)
were considered base case portfolio assumptions, meaning the “Preferred Portfolio” and
the “Pre-IRP” sheets, as provided in the attachment to the Company’s response to
Request No. 20, have identical transmission capacity.
b. The highest risk season is a function of the load forecast and the resource buildout for any
given year. The “Preferred Portfolio” sheet has different resources than the “Pre-IRP”
sheet’s buildout, which results in a differing distribution of risk across the seasons for any
given year.
The response to this Request is sponsored by Andrés Valdepeña Delgado, System
Planning Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 32
STAFF REQUEST FOR PRODUCTION NO. 52: In its August Energy Efficiency Advisory
Group ("EEAG") meeting, the Company discussed changing the methodology used to plan and
evaluate its Demand Side Management ("DSM") programs from "acknowledged" to "filed" IRP
avoided costs. Please explain if the Company is implementing that change as of this filing and, if
so, provide the reasoning and support for the change.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 52:
As discussed at the August 2023 Energy Efficiency Advisory Group (“EEAG”) meeting,
the Company has implemented the change from relying on the most recently “acknowledged” to
the most recently "filed" Integrated Resource Plan (“IRP”) avoided costs in its energy efficiency
program planning. This change was incorporated into 2024 program planning, which relied on
avoided costs from the 2023 IRP. However, as stated at EEAG, the Company is not retroactively
applying the change in its current reporting. Meaning, for measuring the cost-effectiveness of
energy efficiency programs operated in 2023, the most recently acknowledged IRP at the time of
program planning for 2023 will be relied upon, which will be the 2021 IRP. The change from relying
on “acknowledged” to “filed” IRP avoided costs impacted program planning for 2024 programs
and reporting and beyond. This change was intended to recognize changes in avoided costs in a
timelier manner in program planning and ultimately cost-effectiveness evaluation.
The response to this Request is sponsored by Quentin Nesbitt, Customer Relations and
Programs Manager, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 33
STAFF REQUEST FOR PRODUCTION NO. 53: In the November 8 EEAG, the Company
presented the "Cost-Effectiveness Refresher and 2024 preview" showing several updates to the
DSM avoided cost calculation. Please answer the following and provide supporting workpapers
in excel format with equations intact and enabled:
a. Please explain how the Company differentiates risk into the low, mid and high risk time
blocks for each season; and
b. Please explain the methodology used to calculate the seasonal risk allocation factor.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 53:
a. Please note that the risk hours presented in the November 8, 2023, Energy Efficiency
Advisory Group (“EEAG”) meeting are the same as those identified in the Timing of
Highest Risk subsection of the Company’s 2023 Integrated Resource Plan (“IRP”)
Appendix C. For a detailed explanation regarding how the timing of highest risk was
developed for the 2023 IRP, please see the Company’s responses to Request Nos. 4
through 8.
b. The seasonal risk allocation was derived from the Loss of Load Expectation (“LOLE”)
analysis utilized to determine the Company’s timing of highest risk. The data provided in
the monthly LOLE percentage table on page 96 of the 2023 IRP Appendix C was utilized
to determine the seasonal risk allocation; summing months May through October for the
summer (85.2 percent), and months November through April for the winter (14.8 percent).
The response to this Request is sponsored by Andrés Valdepeña Delgado, System
Planning Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 34
STAFF REQUEST FOR PRODUCTION NO. 54: Please list the selected energy efficiency
bundles for each forecast year. Please provide a list of measures and the associated input
information for each selected bundle.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 54:
No additional energy efficiency bundles were selected besides the cost-effective energy
efficiency (“EE”) measures built into the base load forecast in the Preferred Portfolio. For the EE
bundle information please see page 19 of the 2023 Integrated Resource Plan (“IRP) Appendix C.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 35
STAFF REQUEST FOR PRODUCTION NO. 55: Please list the selected Demand
Response ("DR") bundles for each forecast year. Please provide a list of the measures and the
associated input information for each selected bundle.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 55:
Please see the following for the types of demand response (“DR”) bundles selected by the
Long-Term Capacity Expansion (“LTCE”) model in the Preferred Portfolio:
Program Description
Megawatts
(“MW”) Year
Existing Program Expansion 20 2029
Existing Program Expansion 20 2033
Existing Program Expansion 20 2034
Existing Program Expansion 20 2035
Existing Program Expansion 20 2036
New DR Storage Program 20 2034
New DR Storage Program 20 2035
New DR Storage Program 20 2036

For the DR inputs, please see the attached Excel spreadsheet.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 36
STAFF REQUEST FOR PRODUCTION NO. 56: Please provide workpapers supporting
the avoided cost averages shown in Appendix C at 18. Please clearly show each avoided cost
component (e.g., avoided energy, avoided capacity, transmission and distribution deferral) and
any calculations relevant to supporting those values.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 56:
For the data and calculations used to create the avoided energy cost averages table,
please see the attached Excel spreadsheet. Avoided capacity and transmission and distribution
deferral benefits are added to these values when the Company does cost effective analysis for
energy efficiency programs or measures.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 37
STAFF REQUEST FOR PRODUCTION NO. 57: In Staff's Comments for the 2021 IRP, it
recommended that the Company discuss and explore adjusting the 20 MW threshold cap on
additional DR capacity with its EEAG and Integrated Resource Planning and Advisory Committee
in the development of the 2023 IRP. Please describe the consideration and discussion given to
the topic. Please provide the reasoning for continuing to model DR selections using the 20 MW
threshold cap.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 57:
The Company initially discussed the modeling attributes of demand response (“DR”) for
inclusion in the 2023 Integrated Resource Plan (“IRP”) at the combined Energy Efficiency
Advisory Group ("EEAG”)/IRP Advisory Council (“IRPAC”) meeting held on May 4, 2022, and
again at the IRPAC meeting held on November 10, 2022. Feedback was solicited in both
meetings, but no other annual block sizes were suggested. As the Company evaluated the
reasonableness of its proposed 20 MW bundles, its considerations included available DR program
sizes, program ramp rates, and the sufficient resource size able to influence resource selection.
Additionally, new DR buckets were discussed to focus on three DR categories (see 2023
IRP Report, page 70 and 71). The overall DR availability was updated in the 2023 IRP based on
the 2022 DR Potential Study.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 38
STAFF REQUEST FOR PRODUCTION NO. 58: Page 96 of Appendix C of the 2023 IRP
states that "[w]hile the identified seasons and hours capture over 95% of the total hourly risk, the
magnitude of LOLP values vary." Please explain whether "95%" should have been "90%" as
described on Page 92.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 58:
The referenced percentages of “90%” and “95%” from the Company’s 2023 Integrated
Resource Plan (“IRP”) Appendix C were stated as intended and are correct. The Loss of Load
Probabilities (“LOLP”), which make up 90 percent of the total hourly risk, as described on page
92, represent the threshold utilized to identify the seasons of highest risk. Meanwhile, the 95
percent of total hourly risk, as described on page 96, represents the sum of the LOLPs when
utilizing only the values from the identified seasons and hours, and dividing that value by the sum
of all LOLPs from every hour in the calendar year. For more information on how the “90%” was
used to determine the seasons of highest risk, please see the Company’s responses to request
Nos. 4 through 6.
The response to this Request is sponsored by Andrés Valdepeña Delgado, System
Planning Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 39
STAFF REQUEST FOR PRODUCTION NO. 59: Response to Staff Production Request
No. 21(b) states:
"The 70th percentile energy load forecast was utilized in response to the selection of the
70th percentile peak load forecast for reliability purposes. The Company considers it important to
maintain consistency in the relationship between the energy and peak load forecast percentiles.
"
Please respond to the following:
a. Please explain why it is important to maintain consistency in the relationship between the
energy and peak load forecast percentiles;
b. Has the Company ever allowed inconsistency in the relationship between the energy and
peak load forecast percentiles in any past IRPs? If so, please describe when they were
different and why;
c. Please list all of the marginal cost rates, avoided cost rates, and rates for consumption
that are leveraged from the IRP that would be different depending on whether the
Company used a 50th percentile energy load forecast instead of the 70th percentile
energy load forecast (e.g. PURPA IRP-based rates, DSM avoided cost rates, Schedule
20 marginal cost rates, etc.);
d. For each of the rates listed above, please provide which percentile energy load forecast
is actually used, and explain the Company's justification for each;
e. Please explain whether using a 50th percentile energy load forecast instead of the 70th
percentile energy load forecast would cause a difference in the loss of load probability
heat maps and/or timeframes used to determine performance-based capacity payments
for CEYW-Construction customers, DR program timeframes, Time-of-Use Rates, etc.; and
f. Please confirm that all the portfolios in the Portfolio Costing Analysis use 70th percentile
energy load forecast.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 40
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 59:
a. The Company adjusted both the peak and energy forecasts to the 70th percentile in an
effort to remain most consistent with Staff’s recommendation to adjust the load forecast
instead of the reliability target,4 as both peak and energy forecasts encompass the
Company’s load forecast. Additionally, there are mechanical reasons that consistency
between peak and energy forecast is warranted for planning conditions. Adjusting one or
the other independently can inadvertently change the expected system load factor, which
can bias the selection of resources by changing expected ramp rates or over-flattening
the hourly profile. By adjusting both in tandem, the relationship between the variables is
maintained.
b. Yes, in the ‘Climate Change’ scenario of the 2021 Integrated Resource Plan (“IRP”), the
Company used an inconsistent energy and peak load forecast. This is similar to the
inconsistent energy and peak load forecast used in the ‘Extreme Weather’ scenario in the
2023 IRP. The inconsistency between the energy and peak load forecasts in these
scenarios is intentionally used to represent the more exaggerated peak loads (compared
to average loads) that could occur in potential extreme weather or temperature futures,
which helps the Company assess how resource buildouts might differ in different futures.
c. The only rates directly leveraged from the IRP that would be different if the Company
were to change the IRP’s energy load forecast percentile are the rates referenced in
Schedule 33, Idaho Power Company Electric Service Rate for Brisbie, LLC. The approved
special contract references relying on the Demand-Side Management (“DSM”) avoided
cost averages from the most recently acknowledged IRP.
Historically, Idaho Power’s Public Utility Regulatory Policies Act of 1978 (“PURPA”)
IRP-based rates utilized inputs from the IRP planning process, in accordance with Order

4 IPC-E-21-43, Staff’s Comments, p. 9

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 41
No. 32697.5 However, in Case No. IPC-E-23-25, the Commission approved Staff’s
recommendation6 that the Company use a 50th percentile energy load forecast for PURPA
IRP-based rates, despite the IRP using a different load forecast percentile. 7 As such, the
Company’s PURPA IRP-based rates are no longer directly leveraged from the IRP.
d. The Company interprets Staff’s question about DSM avoided cost “rates” to mean the
DSM avoided cost averages contained on page 18 of Technical Appendix C to the IRP,
which use the same load forecast percentiles as the IRP planning conditions. For the 2023
IRP, the 70th percentile energy and peak load forecasts were the planning condition
forecasts used to calculate the avoided cost averages.
As described in part (c) above, PURPA IRP-based rates use a 50th percentile
energy load forecast, per Order No. 36067.
e. Utilizing a 50th percentile energy load forecast instead of a 70th percentile energy load
forecast would have no impact on reliability-based results. As mentioned on page 56 of
the 2023 IRP report, the Company’s Reliability and Capacity Assessment Tool (“RCAT”)
utilizes historical data to create its six different test years. The historical hourly load from
each of the six test years is scaled so that the monthly peaks match the monthly peaks
from the load forecast. The energy load forecast is not utilized in the development of the
RCAT’s six test years. Altering the percentile of the energy load forecast will not change
calculated loss of load probabilities, the timing of highest risk, performance-based capacity
payments for Clean Energy Your Way Construction customers, demand response
program and time-of-use timeframes, etc.

5 Idaho Public Utility Commission Order No. 32697, p. 22.
6 IPC-E-23-25, Staff’s Comments, p. 4., “…the 50th percentile load forecast proposed in this case is
appropriate for the purpose of determining IRP-based avoided cost rates because the 50th percentile
energy load reflects expected load under normal conditions and represents the cost of energy that the
Company will likely avoid. The Company used the 70th percentile load in the 2023 IRP, because the
purpose of the load forecast in the IRP is to ensure sufficient resources are identified necessary for
reliability.”
7 Idaho Public Utility Commission Order No. 36067, p.4.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 42
f. All portfolios in the Portfolio Costing Analysis use the 70th percentile energy load forecast
except the air-source heat pumps (“ASHP”) and ground-source heat pumps (“GSHP”)
electrification scenarios, which use a separate electrification-based load forecast as
described Chapter 9 of the 2023 IRP Report.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
and Alison Williams, Regulatory Policy and Strategy Leader, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 43
STAFF REQUEST FOR PRODUCTION NO. 60: Response to Staff Production Request
No. 21(c) states:
Idaho Power moved forward with the combination of the 70th percentile peak load forecast
and a 0.1 event-days per year LOLE threshold for the 2023 IRP, as it produced similar reliability
results when compared to the combination of the 50th percentile peak load forecast and a 0.05
event-days per year LOLE threshold.
Please explain whether "similar reliability results" refer to the 0-MW capacity position and
16-MW capacity position in the 2021 IRP case and the 2023 IRP case, respectively, contained in
the "Response to Staffs Request No. 21 - Attachment 1 - Load Forecast & Loss of Load
Expectation" Excel file. If not, please explain, define, and provide the "similar reliability results."
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 60:
Yes, the “similar reliability results” refer to the 0-megawatt (“MW”) capacity position (Base
Case – 2021 IRP – 50th Percentile Peak Load – 0.05 Event-Days/Year LOLE Threshold) and the
16 MW capacity position (Case No. 2 – 2023 IRP – 70th Percentile Peak Load – 0.1 Event-
Days/Year LOLE Threshold) provided in the Company’s response to Request No. 21 and the
associated attachment.
The response to this Request is sponsored by Andrés Valdepeña Delgado, System
Planning Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 44
STAFF REQUEST FOR PRODUCTION NO. 61: The "Extreme Weather" scenario uses
70th percentile energy and 95th percentile peak load forecast. Please confirm that the 70th
percentile energy is used in determining the cost of the portfolio selected under the 95th percentile
peak. If not confirmed, please explain how the 70th percentile energy load forecast is used for the
Extreme Weather scenario.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 61:
Yes, a 70th percentile energy forecast is used to determine the cost of the portfolio selected
under the 95th percentile peak forecast. It should be noted that both the energy and peak forecasts
are used in conjunction to select the resources for all portfolios.
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 45
STAFF REQUEST FOR PRODUCTION NO. 62: Response to Staff Production Request
No. 24 states that "[t]he EIA forecasts also validate the stochastic gas price forecast spread."
Please respond to the following:
a. Please explain how the EIA forecasts validate the stochastic gas price forecast spread;
b. Please explain whether the EIA forecasts are used in the Natural Gas Sampling described
on Page 84 of Appendix C of the 2023 IRP; and
c. If so, please explain how the EIA forecasts are used in the Natural Gas Sampling
described on Page 84 of Appendix C of the 2023 IRP.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 62:
a. The US Energy Information Administration (“EIA”) forecasts validate the range of the
Company’s stochastic natural gas price analysis because the EIA forecasts generally sit
near the 25th and 75th percentiles of the stochastic natural gas price range (see graph
below). Because the EIA forecasts represent similar probabilities to the stochastic natural
gas prices used in the IRP, it was a validation to this particular model output. The following
graph was presented to the Integrated Resource Plan (“IRP”) Advisory Council on August
31, 2023, and used the same data as the graph on page 84 of the 2023 IRP Appendix C:

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 46

In the graph above, the distribution from page 84 of Appendix C is presented as a box and whisker
plot with the EIA forecasts as the high and low gas price sensitivities.
b. The EIA forecasts were used as a validation, as described above, but are not part of the
stochastic distribution.
c. N/A
The response to this Request is sponsored by Jared Hansen, Resource Planning Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 47
STAFF REQUEST FOR PRODUCTION NO. 63: Figure No. 1 was shown during Portfolio
Reliability Analysis presentation in the August 15, 2023, Integrated Resource Plan Advisory
Council meeting.
Figure No. 1 Reliability & Capacity Assessment Tool (“RCAT”) Modeling Flowchart

Response to Staff Production Request No. 2 (a) in Case No. IPC-E-23-27 states that the
System Adjusted Load = System Load + Demand Response Dispatched. Response to Staff
Production Request No. 2 (d) in Case No. IPC-E-23-27 states that "the adjustments to the test
year hourly load take place before any resources are netted out." Please respond to the following.
a. Please explain whether the "System Load" in "System Adjusted Load = System Load +
Demand Response Dispatched" refers to the adjusted' test year hourly load based on a
given Load and Resource ("L&R") year.
b. Please explain how the "Demand Response Dispatched" is determined. In the response,
please clarify if it is based on the actual Demand Response data in the corresponding test
year and whether any adjustment was needed.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 48
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 63:
a. The “System Load” in the “System Adjusted Load = System Load + Demand Response
Dispatched” equation represents the Company’s historical hourly load from a particular
test year. The corresponding test year’s historical demand response dispatch is added
back to the historical hourly load so that the Company’s Reliability & Capacity Assessment
Tool (“RCAT”) can optimize the dispatch of Idaho Power’s demand response (“DR”)
programs in future Load & Resource (“L&R”) years. Once the historical DR dispatch has
been added to the historical hourly load for a particular test year, this new “System
Adjusted Load” shape is scaled so that the monthly peaks match the monthly peaks from
the load forecast for a particular L&R year.
b. Yes, the “Demand Response Dispatched” refers to the historical DR of a particular test
year. The “Demand Response Dispatched,” or load reductions for each DR program, is
calculated for every hour that the programs are dispatched. The reductions attributed to
the programs are calculated by measuring actual participant load during the time of the
event and subtracting it from a calculated baseline. This baseline calculation uses recent
historical data to understand what the participants’ load would have been if the DR event
had not been called. The hourly DR load reductions are reconstituted with (added to, in
this case) the measured “System Load” to calculate the “System Adjusted Load.”
The response to this Request is sponsored by Andrés Valdepeña Delgado, System
Planning Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 49
STAFF REQUEST FOR PRODUCTION NO. 64: In Figure No. 1 above, Net Load is further
adjusted by Energy Limited Resources, which include Battery Energy Storage System, Demand
Response, and Hybrid. Please respond to the following.
a. Please explain how Energy Limited Resources and their three components are
determined and whether they depend on a test year or a Load and Resource year?
b. Please define "Hybrid".
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 64:
a. The Company’s Reliability & Capacity Assessment Tool (“RCAT”) creates an hourly profile
for Energy Limited Resources (“ELR”) for each of the six historical test years and for each
year in the IRP 20-year planning horizon. The ELR hourly profiles are created based on
the identified resource’s characteristics and the hourly net load. A Battery Energy Storage
System (“BESS”) profile is created based on characteristics such as the number of hours
storage is available, round-trip efficiency, and the time required to charge. For demand
response (“DR”), the parameters for each program are considered when creating the
profile, which includes maximum number of hours in a season the program is available,
maximum number of hours the program can be dispatched in a week, and time of the day.
For hybrid resources, in addition to the limitations of each resource type, the Point of
Interconnection (“POI”) limit is also considered when creating the hourly profile.
b. Hybrid refers to resources that share a common POI, such as a solar photovoltaic (“PV”)
plant sharing the same POI with a BESS. The POI limit can be less than the sum of the
nameplates for the resources connected at that same POI. For example, a 40 megawatt
(“MW”) solar PV plant paired with a 40 MW BESS at a POI limit of 40 MW has a combined
nameplate of 80 MW but can be restricted to 40 MW at that POI.
The response to this Request is sponsored by Andrés Valdepeña Delgado, System
Planning Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 50
STAFF REQUEST FOR PRODUCTION NO. 65: Response to Staff Production Request
No. 2 (e) in Case No. IPC-E-23-27 states that the net load is derived by subtracting the generation
that Idaho Power does not control (such as run-of-river hydro, wind, solar, and cogeneration and
small power production) from the system-adjusted load, and that "the historical data of these
resources is scaled up or down depending on additions and/or retirements in any given L&R year."
Please explain in detail and provide illustrative examples to show how "the historical data of these
resources is scaled up or down depending on additions and/or retirements in any given L&R year."
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 65:
For the generation that Idaho Power does not control (run-of-river hydro, wind, solar and
cogeneration and small power production), the Company, in its Reliability & Capacity Assessment
Tool (“RCAT”), uses historical data to scale up or down by dividing the actual measured value
during each hour of the specified test year by the resources’ nameplate to create a normalized
data shape. The normalized data shape is then multiplied by the anticipated nameplate in a given
Load & Resource (“L&R”) year.
The table below provides an example of how the RCAT resource scaling process works.
The actual measured output for solar and wind for a day in July 2022 are shown in Columns 2
and 3, with the associated timestamps located in Column 1. The wind and solar nameplates in
July 2022 were 725 megawatts (“MW”) and 316.25 MW, respectively. Assuming the wind
nameplate would be 606 MW in 2028 due to retirements, and the solar nameplate would be 516
MW due to new additions, the corresponding hourly output for both resources is calculated as: 𝐹𝑢𝑡𝑢𝑟𝑒 𝑉𝑎𝑙𝑢𝑒=𝑀𝑒𝑎𝑠𝑢𝑟𝑒𝑑 𝑉𝑎𝑙𝑢𝑒𝑁𝑎𝑚𝑒𝑝𝑙𝑎𝑡𝑒𝐴𝑐𝑡𝑢𝑎𝑙⋅𝑁𝑎𝑚𝑒𝑝𝑙𝑎𝑡𝑒𝐹𝑢𝑡𝑢𝑟𝑒

The resulting wind and solar output (in MW) that would be utilized in the RCAT for that day in July
2028 for the identified test year are shown in the last two columns of the table.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 51
Date Wind (Measured) Solar (Measured) Wind (2028) Solar (2028)
01-Jul-22 00:00:00 123.4 0 103.2 0.0
01-Jul-22 01:00:00 122.9 0 102.8 0.0
01-Jul-22 02:00:00 128.9 0 107.7 0.0
01-Jul-22 03:00:00 126.3 0 105.6 0.0
01-Jul-22 04:00:00 124.5 0 104.1 0.0
01-Jul-22 05:00:00 116.7 0 97.5 0.0
01-Jul-22 06:00:00 112.2 16 93.8 26.1
01-Jul-22 07:00:00 113.0 126 94.5 205.6
01-Jul-22 08:00:00 107.8 252 90.1 411.2
01-Jul-22 09:00:00 96.7 284 80.8 463.4
01-Jul-22 10:00:00 81.6 291 68.2 474.8
01-Jul-22 11:00:00 75.1 294 62.8 479.7
01-Jul-22 12:00:00 66.1 291 55.3 474.8
01-Jul-22 13:00:00 63.3 288 52.9 469.9
01-Jul-22 14:00:00 64.3 286 53.7 466.6
01-Jul-22 15:00:00 64.4 289 53.8 471.5
01-Jul-22 16:00:00 128.6 273 107.5 445.4
01-Jul-22 17:00:00 172.9 274 144.5 447.1
01-Jul-22 18:00:00 174.1 258 145.6 421.0
01-Jul-22 19:00:00 177.5 184 148.3 300.2
01-Jul-22 20:00:00 187.1 63 156.4 102.8
01-Jul-22 21:00:00 170.7 4 142.7 6.5
01-Jul-22 22:00:00 161.3 0 134.8 0.0
01-Jul-22 23:00:00 144.8 0 121.0 0.0

The response to this Request is sponsored by Andrés Valdepeña Delgado, System
Planning Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 52
STAFF REQUEST FOR PRODUCTION NO. 66: The Effective Load-Carrying Capability
("ELCC") results listed on Page 92 of Appendix C of the 2023 IRP include "ELCC of Existing and
Expected Resources" and "ELCC of Future Resources". Response to Staff Production Request
No. 4 (a) in Case No. IPC-E-23-27 further states that Expected Resources "are resources that
are under contract and/or expected to come online in the near-term but not yet in service" and
Future Resources "are resources that do not have a contract." Response to Staff Production
Request No. 4 (e) in Case No. IPC-E-23-27 states that both the "ELCC of Existing and Expected
Resources" and the "ELCC of Future Resources" are calculated using the "last-in" ELCC
methodology. Please respond to the following:
a. Please explain and provide an illustrative example of the "last-in" ELCC methodology.
b. Please explain if there is any different treatment for Existing Resources, Expected
Resources, and Future Resources under the "last-in" ELCC methodology.
c. Please explain how historical generation data of Existing Resources are used in the "last-
in" ELCC methodology.
d. Please explain how forecasted generation profiles of Expected Resources and Future
Resources are used in the "last-in" ELCC methodology.
e. Does AURORA use the ELCC of Existing Resources or the historical generation data of
Existing Resources?
f. Please confirm that AURORA uses the ELCC of Expected Resources and Future
Resources and explain how AURORA uses the ELCC.
g. Please explain whether, for the same type of Future Resources, ELCC will change over
time across different L&R years.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 66:
a. The “Last-In” Effective Load Carrying Capability (“ELCC”) methodology measures the
ELCC of a particular resource after all other variable and energy-limited resources have
been added to the system. The “Last-In” ELCC calculation captures interactive effects with

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 53
other resources. The figure8 below shows an illustrative example of the different types of
ELCC calculations, with “ELCC Capacity” reflecting cumulative capacity contribution of
multiple resources and “Installed Capacity” reflecting the total nameplate capacity of the
cumulative resources. In this example, the “First-In” ELCC does not consider any other
Variable Energy Resources (“VER”) or Energy Limited Resources (“ELR”), which (in this
example) results in a higher ELCC value. Meanwhile, the “Last-In” ELCC approach
identifies a resource’s individual—marginal—ELCC by evaluating its impact after
accounting for other existing resources, which (in this example) results in a lower ELCC
value.

For the ELCC of Existing and Expected Resources table referenced on page 92 of
Appendix C of the 2023 Integrated Resource Plan (“IRP”), the “Last-In” ELCC means that
when a resource ELCC was calculated, all other resources were considered in the

8 N. Schlag, Z. Ming, A. Olson, L. Alagappan, B. Carron, K. Steinberger, and H. Jiang, "Capacity and
Reliability Planning in the Era of Decarbonization: Practical Application of Effective Load Carrying
Capability in Resource Adequacy," Energy and Environmental Economics, Inc., Aug. 2020.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 54
Company’s Reliability & Capacity Assessment Tool (“RCAT”). For example, when the
solar ELCC was calculated, all other resources (wind, demand response, 4-hour stand-
alone battery storage, etc.) were included in the RCAT; when the wind ELCC was
determined, all other resources (solar, demand response, 4-hour stand-alone battery
storage, etc.) were considered in the RCAT.
b. Under the “Last-In” ELCC methodology, there is one notable difference between the
treatment of Existing and Expected Resources as compared to Future Resources. For the
Existing and Expected Resources, the “Last-In” ELCC is calculated using the Existing and
Expected Resources only. For the Future Resources, the “Last-In” ELCC is calculated
utilizing the Existing and Expected Resources plus the Future Resource being analyzed.
c. Generation profiles utilized in the “Last-In” ELCC calculation are dependent upon the
resource type being analyzed. For solar and wind, historical generation profiles are used.
For Battery Energy Storage Systems (“BESS”) and demand response (“DR”), the
generation profiles are generated based on the parameters of the resource and hourly net
load (see the Company’s response to Request for No. 64). For information on how a
resource ELCC is calculated, please see pages 89 and 90 of Appendix C (when a resource
is “added to the system”, the identified generation profile is being included in the RCAT
simulation).
d. Please see the response to part (c).
e. As stated on page 92 of Appendix C, the ELCC of Existing & Expected Resources values
were provided for informational purposes. As stated on page 122 of the 2023 IRP report,
Idaho Power implemented seasonal resource specific ELCC saturation curves for variable
energy resources (“VER”) and energy limited resources (“ELR”) in the AURORA Long-
Term Capacity Expansion (“LTCE”) model.
f. For existing resources, an ELCC for all resources combined was used in AURORA while
for future resources the ELCC saturation curves are used.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 55
g. Yes, the ELCC will change over time across different Load and Resource (“L&R”) years,
even if the same type of future resources is utilized. The ELCC calculation is a function of
both load and generation, meaning if the load changes from year to year, so will the ELCC
of a resource.
The response to this Request is sponsored by Andrés Valdepeña Delgado, System
Planning Engineer, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 56
DATED at Boise, Idaho, this 4th day of January 2024.

MEGAN GOICOECHEA ALLEN
Attorney for Idaho Power Company

IDAHO POWER COMPANY’S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE
COMMISSION STAFF- 57
CERTIFICATE OF SERVICE

I HEREBY CERTIFY that on the 4th day of January 2024, I served a true and correct copy
of Idaho Power Company’s Response to the Second 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

Hand Delivered
U.S. Mail
Overnight Mail
FTP Site
X Email [e-mail]

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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U.S. Mail
Overnight Mail
FAX
_ FTP Site
X Email [e-mail]
[e-mail]
[e-mail]
[e-mail]
[e-mail]

Jim Swier
Micron Technology, Inc.
8000 South Federal Way
Boise, Idaho 83707
Hand Delivered
U.S. Mail
Overnight Mail
FAX
FTP Site
X Email [e-mail]

________________________________
Christy Davenport
Legal Administrative Assistant

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-23

IDAHO POWER COMPANY

RESPONSE TO STAFF PRODUCTION REQUEST
NO. 35

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CASE NO. IPC-E-23-23

IDAHO POWER COMPANY

RESPONSE TO STAFF PRODUCTION REQUEST
NO. 36

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CASE NO. IPC-E-23-23

IDAHO POWER COMPANY

RESPONSE TO STAFF PRODUCTION REQUEST
NO. 38

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CASE NO. IPC-E-23-23

IDAHO POWER COMPANY

RESPONSE TO STAFF PRODUCTION REQUEST
NO. 40

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IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-23

IDAHO POWER COMPANY

RESPONSE TO STAFF PRODUCTION REQUEST
NO. 46

ATTACHMENT 1

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CASE NO. IPC-E-23-23

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RESPONSE TO STAFF PRODUCTION REQUEST
NO. 49

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BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-23

IDAHO POWER COMPANY

RESPONSE TO STAFF PRODUCTION REQUEST
NO. 55

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BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-23

IDAHO POWER COMPANY

RESPONSE TO STAFF PRODUCTION REQUEST
NO. 56

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