20251209Reply Comments.pdf

HIQAHO POWERO
MEGAN GOICOECHEA ALLEN RECEIVED
Corporate Counsel DECEMBER 9, 2025
mgoicoecheaallen(a)idahopower.com IDAHO PUBLIC
UTILITIES COMMISSION
December 9, 2025
VIA ELECTRONIC FILING
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-25-23
Idaho Power Company's 2025 Integrated Resource Plan
Dear Commission Secretary:
Attached for electronic filing are Idaho Power Company's Reply Comments in the
above-referenced matter.
If you have any questions, please do not hesitate to contact me.
Very truly yours,
Ay�r T I I
U4 &
Megan Goicoechea Allen
MGA:cd
Attachments

MEGAN GOICOECHEA ALLEN (ISB No. 7623)
DONOVAN WALKER (ISB No. 5921)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
mgoicoecheaallenCa�,idahopower.com
dwalkerCa-)_idahopower.com
Attorneys for Idaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY'S 2025 INTEGRATED ) CASE NO. IPC-E-25-23
RESOURCE PLAN. )
IDAHO POWER COMPANY'S
REPLY COMMENTS
COMES NOW, Idaho Power Company ("Idaho Power" or "Company"), and,
pursuant to Idaho Public Utilities Commission's ("Commission") Rules of Procedure 201-
204 and Order No. 36786, hereby respectfully submits the following Reply Comments
regarding the Company's 2025 Integrated Resource Plan ("IRP").
I. INTRODUCTION
The Company's 2025 IRP is a comprehensive analysis of the optimal mix of both
demand and supply-side resources needed to reliably serve customer demand and
flexible capacity needs over the 20-year planning period from 2026 to 2045. As a result
of collaborative work with Commission Staff and other stakeholders through the IRP
IDAHO POWER COMPANY'S REPLY COMMENTS - 1

Advisory Council ("IRPAC"), the 2025 IRP constitutes a robust analysis confirmed by
comprehensive validation and verification, resulting in a Preferred Portfolio that
represents the best combination of least-cost and least-risk.
While the biennial development of the IRP's 20-year forecast period has historically
allowed Idaho Power to timely update its long-term resource plan based on changing
circumstances, balancing load and resources has become increasingly more dynamic
over the past several years as major planning inputs and assumptions are subject to
change in real time. Accordingly, within its 2025 IRP, Idaho Power underscores the critical
importance of flexibility and adaptability in resource planning.
In each IRP, Idaho Power endeavors to develop a Preferred Portfolio that captures
the best available information at the time and, to the extent possible, reasonably accounts
for the challenges noted above. As a result, each IRP is a snapshot in time in an otherwise
fluid planning environment and should be considered in the context in which it was
developed. The resources represented in one IRP may not be the same resources that
drive the next IRP, as new circumstances and market dynamics may change what
technology or technologies are the most cost-effective to satisfy the Company's growing
demand.
The Preferred Portfolio of the 2025 IRP, which includes a diverse mix of generation
resources, storage systems, and transmission lines, successfully positions Idaho Power
to continue to provide reliable and economic service to its customers into the future.
Additionally, the 2026-2030 Near-Term Action Plan associated with the Preferred
Portfolio primarily includes core resource actions that fall into two major categories:
capacity additions and transmission development. The current regional electric market,
IDAHO POWER COMPANY'S REPLY COMMENTS - 2

regulatory environment, pace of technological change, and rapid load growth make the
Near-Term Action Plan especially relevant. Between the Preferred Portfolio and Near-
Term Action Plan, the kinds of activities Idaho Power plans to undertake to provide
consistent, reliable, and affordable electricity to its growing customer base are broadly
reflected.
Idaho Power appreciates the opportunity to offer these Reply Comments in
response to Comments filed by Commission Staff ("Staff'), Renewable Northwest
("RNW") and Northwest Energy Coalition ("NWEC"), Renewable Energy Coalition
("REC"), and the Idaho Irrigation Pumpers Association Inc. ("IIPA"), as well as public
comments submitted by IRPAC members, the City of Boise on August 4, 2025, and Clean
Energy Opportunities for Idaho ("CEO") on November 12, 2025 (collectively, the
"Stakeholders"). The comments submitted by Stakeholders reflect a broad range of
perspectives on long-term resource needs, modeling assumptions, reliability planning,
and the role of emerging technologies. Idaho Power values Stakeholders' participation
and recognizes the importance of a transparent planning process.
Accordingly, Idaho Power offers the following responses to Stakeholder comments
to clarify the Company's modeling choices, address misunderstandings or concerns
where they exist, and highlight where certain issues raised fall outside the scope of the
IRP process.
II. REPLY COMMENTS
A. Staff
Staff recommends acknowledgement of Idaho Power's 2025 IRP. In their
comments, Staff recognizes the significant time and effort the Company invested in
IDAHO POWER COMPANY'S REPLY COMMENTS - 3

developing the 2025 IRP and noted appreciation of the vast amount of information
compiled within it.' Staff also acknowledges that the IRP has become increasingly
complex and increasingly important.2 Although Staff suggests a number of items for the
Company to consider when developing its next IRP, Staff's analysis of the Company's
2025 IRP found that the inputs, assumptions, model constraints, methodology and results
of the portfolio development process to largely be reasonable. Moreover, Staff found the
Near-Term Action Plan to be reasonable but noted the acknowledgement of certain items
is not appropriate or necessary given separate filings or processes contemplating the
same already exist,3 which the Company does not take issue with as part of this
proceeding. Additionally, Staff concluded the Preferred Portfolio, anchored by converting
Bridger Units 3 and 4 to natural gas, is both cost-effective and resilient across a wide
range of policy, fuel-price, and load-uncertainty scenarios. Staff's review of the planning
cases, sensitivity analyses, and model validation efforts concluded that such portfolio
performs well relative to alternatives and is likely to remain the least-cost option under
realistic future conditions. Idaho Power appreciates Staff's thorough and thoughtful review
of its 2025 IRP and addresses each of Staff's recommendations, which largely focus on
increased transparency, standardization of certain elements, proactive consideration of
schedule risk for major transmission projects, and handling of Public Utility Regulatory
Policy Act ("PURPA") new development and replacement rates, in greater detail below.
Staff Recommendation 1: Provide rationale for the overnight plant capital
selected for each resource in next IRP.
Staff Recommendation 2: Publish the annual capacity factor values selected for
each resource that requires one in next IRP.
Staff's Comments (Nov. 13, 2025) at 2.
21d.
3 See, generally,Staff's Comments at 9
IDAHO POWER COMPANY'S REPLY COMMENTS -4

In reviewing the Levelized Cost of Capacity ("LCOC") for each resource, Staff
offered observations regarding overnight plant capital ("OPC"), interconnection capital
("IC"), and capacity factors ("CF"), which are three sub-factors used in the development
of the LCOC calculation. While Staff was appreciative of the new approach employed by
the Company regarding how it approached IC estimates, Staff believes that additional
information should be included in the Company's next IRP to help substantiate the OPC
amounts and CIF required by certain resources.
Idaho Power believes these recommendations are reasonable and will provide
increased transparency into its IRP process. The Company looks forward to working with
Staff and other members of IRPAC to implement these recommendations as part of its
next IRP.
Staff Recommendation 3: Simplify and standardize the escalation factors
applied to LCOC calculations.
As part of its review of the escalation rates applied to each resource's LCOC, Staff
noted that the Company's escalation rates from one year to the next seemed arbitrary,
and Staff also observed that the escalation rates drop significantly for all resources
between 2030 and 2031 .4 While the Company provided rationale that near-term
escalation factors are based on inflation and that the change in 2031 is due to relying on
NREL's Annual Technology Baseline ("ATB") cost curves because of greater long-term
uncertainty, Staff believes a simpler, more standardized approach is preferable.
While Idaho Power believes basing its 2025 IRP escalation factors on NREL ATB
cost curves, which is a widely used industry source for resource cost-related planning
4 Staff's Comments at 4.
IDAHO POWER COMPANY'S REPLY COMMENTS - 5

inputs, to be a reasonable method, the Company is not opposed to exploring
implementation of alternatives contemplated by Staff. The Company looks forward to
working with Staff and other members of IRPAC to evaluate this approach when
developing its next IRP.
Staff Recommendation 4: Build delay into the modeled COD for new
transmission resources.
While reviewing the model constraints used by the Company related to certain
transmission projects, which rely on each project's most current target commercial
operation date ("COD"), Staff suggested the Company consider adding delays as a risk
variable, or include additional buffer to the modeled COD for transmission projects that
do not have all permitting and right-of-way issues resolved, to better determine how
portfolios would need to change so that least-cost contingencies can be developed.5
Idaho Power appreciates Staff's concern regarding transmission resource timing,
especially given new transmission lines' vulnerability to legal and regulatory delays, and
will update its transmission assumptions with any material changes that occur between
now and its next IRP. Additionally, the Company will work with Staff and other members
of IRPAC regarding transmission assumptions utilized in preparation of the Company's
2027 IRP.
Staff Recommendation 5: Engage the Commission when tradeoffs arise
between serving new large loads and providing fair,just, and reasonable rates.
As noted by Staff, the Company anticipates large load growth commencing in 2026
and continuing until at least 2031, and that two main case scenarios contemplated within
the Company's 2025 IRP assume even greater load growth from other potential large
5 Staff's Comments at 4.
IDAHO POWER COMPANY'S REPLY COMMENTS - 6

load customers locating within Idaho Power's service area.6 Coupled with the potential
for expected resources to be canceled or delayed, and the risks that this would create,
Staff recommends the Company engage the Commission prior to making any decisions
that could jeopardize its obligation to serve customers in its service area while providing
electric service at fair, just, and reasonable rates.
Idaho Power agrees with Staff's assessment that it anticipates substantial near-
term load growth and recognizes the potential challenges that may arise as a result.
Accordingly, the Company commits to engaging with the Commission should a situation
materialize where there are tradeoffs between the Company's obligation to serve
customers and meeting its obligation to provide service at fair, just, and reasonable rates.
Staff Recommendation 6: Provide additional Energy Efficiency (EE) details.
Staff highlighted a concern related to the cost-effectiveness of non-cost-effective
energy efficiency ("EE") selected by Energy Exemplar's Aurora model in the Preferred
Portfolio. However, because the magnitude of the additional EE selected was relatively
small at only 57 megawatts (WW") and the timing of when the Aurora model relies upon
such capacity is not until 2031 , Staff does not believe an immediate concern exists as it
relates to the Company's 2025 IRP. However, Staff does note that the pursuit of non-
cost-effective measures could cause complications with the Company's existing EE
programs and therefore requests increased transparency regarding how these selections
are made and how they should be considered.
The Company understands Staff's concern related to relying on a selection of non-
cost-effective EE measures to meet future resource needs. Although the non-cost-
6 Staff's Comments at 10.
IDAHO POWER COMPANY'S REPLY COMMENTS - 7

effective EE measures selected by the Aurora model were, comparatively, the lowest cost
bundles of measures, the Company is not opposed to exploring whether continuing to
make these types of resources available for selection is reasonable.
Staff PURPA Recommendation 7: Develop Oregon's rates and Idaho's rates
separately and use Idaho-specific data for PURPA new development and
replacement rates.
Staff PURPA Recommendation 8: Separately develop Idaho PURPA new
development and replacement rates for SAR-method projects and ICIRP-
method projects.
Staff PURPA Recommendation 9: Contact Idaho projects nearing contract
expiration to understand renewal intentions when empirical data is insufficient
for determining replacement rates.
To recognize the different policy environments between Oregon and Idaho, and
belief that baseline assumptions regarding PURPA new development rates and
replacement rates should reflect actual circumstances as closely as possible, Staff
recommends that the Company bifurcate the development and application of such rates
between the Company's Idaho and Oregon jurisdictions as part of its next IRP. Moreover,
Staff believes the Company should separately develop Idaho's PURPA new development
and replacement rates for projects using the SAR method and for projects using the ICIRP
method as a means of recognizing the difference in these projects' maximum contract
terms (20 years and 2 years, respectively). Finally, Staff recommends that the Company
contact projects with near-term expirations to try and gain a greater understanding of their
intent to enter into a replacement contract.
Idaho Power appreciates Staff's analysis and nuanced recommendations as they
relate to the forecasting of PURPA project contract renegotiation rates and the addition
of new PURPA projects. The Company agrees that creating PURPA new development
IDAHO POWER COMPANY'S REPLY COMMENTS - 8

and contract replacement rate forecasts to better reflect state-specific data could be
considered as part of its next IRP. The Company also agrees with Staff that such
forecasts should reflect the differences in terms and conditions available to SAR and
ICIRP projects, recognizing the forecasts used by the Company in its 2025 IRP reflected
this difference in that newly developed Qualifying Facilities ("QF") and replacement
contracts were assumed to have eligible contract lengths for the specific type of resource
and whether the resource qualifies for SAR or ICIRP pricing and terms and conditions.
Prior to its next IRP, Idaho Power will evaluate additional methodological changes to the
forecast of PURPA generation, including consideration of differences in terms and
conditions available to SAR and ICIRP projects, and will share its analysis with Staff and
IRPAC members to determine an appropriate approach ahead of developing its next IRP.
Finally, the Company appreciates Staff's recommendation regarding obtaining
information from projects with expiring contracts whether they intend to enter into
replacement contracts. The Company agrees this could be a useful data point and will
work to gather this information, although it notes this could leave remaining questions or
uncertainty, depending on the response(s)7 received. Accordingly, the Company will
coordinate with Staff and members of IRPAC regarding its anticipated approach as it
relates to this recommendation.
For example, a project may express intent to enter into a replacement contract but may not yet have
requested indicative avoided cost pricing or may have requested and been provided such pricing but not
yet accepted it. As Idaho Power understands it, pricing can be a major factor into a project's decision
whether to enter into a contract. Idaho Power agrees that anecdotal information from the projects may be
helpful in understanding intent regarding replacement contracts but acknowledges that expressions of
intent may not accurately reflect the project's ultimate decisions on replacement contracts. Idaho Power
looks forward to considering these issues in its development of assumptions for the next IRP.
IDAHO POWER COMPANY'S REPLY COMMENTS - 9

Staff Recommendation 10: Illustrate the calibration process between the LTCE
and RCA T models.
After assessing the calibration process used by the Company to achieve similar
capacity positions between the Aurora Long Term Capacity Expansion ("LTCE") model
and the Reliability and Capacity Assessment Tool ("RCAT"), Staff believes more
transparency, especially as it relates to adjustments of the seasonal Planning Reserve
Margin ("PRM") and the Effective Load Carrying Capability ("ELCC") curves, should be
included in the next IRP.
Idaho Power appreciates Staff's feedback regarding the content of the 2025 IRP's
Appendix D, which is a new addition to the Company's IRP that seeks to discuss in greater
detail many of the more technical modeling aspects of the Company's IRP, such as
calibration between the LTCE model and RCAT. The Company intends to incorporate
Staff's recommendation and, as part of its next IRP process, will more transparently
illustrate the calibration process between the LTCE model and the RCAT, with specific
focus on adjustments related to the seasonal PRM and ELCC curves.
Staff Recommendation 11: Explore incorporating the flexible ramping
requirement into the IRP.
When reviewing how the Company modeled its reserve requirements resulting
from participation in the Western Energy Imbalance Market ("WEIM"), Staff noted that
WEIM's flexible ramping requirements are tested every 15 minutes, yet the Aurora model
used in developing the IRP is focused on hourly conditions. Accordingly, Staff
recommends as part of the Company's next IRP that it explore the possibility of
IDAHO POWER COMPANY'S REPLY COMMENTS - 10

incorporating WEIM's 15-minute flexible ramping requirements to ensure sufficient
reserve requirements.
To clarify, the Aurora model does capture sub-hourly inputs for reserves and
flexibility. As such, the Company is confident that the flexible ramping requirements from
the WEIM are already captured in the way the model holds reserves without explicitly
modeling the WEIM requirement directly.
B. RNW and NWEC
Idaho Power appreciates RNW and NWEC's participation in this proceeding and
their constructive engagement with the 2025 IRP. The Company especially appreciates
RNW and NWEC's recognition of the RCAT's value in validating portfolio reliability and
the need for transmission as part of the plan going forward. Within the comments
submitted by RNW and NWEC, focus generally centers around the Company's perceived
change in direction from its 2023 IRP and alleged weaknesses in the 2025 IRP's input
assumptions, risk assessment, and treatment of new large loads, as well as offering
suggestions for the Company's consideration to ensure selection of the least-cost, least-
risk plan for customers. In these Reply Comments, Idaho Power addresses the common
themes reflected in RNW and NWEC's comments as more fully set forth below.
RNW and NWEC Contention: Resource cost assumptions stray from industry
benchmarks and are fraught with significant variability, creating unacceptable
levels of uncertainty and risk in the 2025 IRP results.
RNW and NWEC question whether candidate resource cost assumptions align
with industry benchmarks, pointing to perceived disparities between the Company's
assumptions for natural gas, wind, and storage resources. Data relied on by the Company
is informed by bid-level data from recent competitive solicitations and commercial
IDAHO POWER COMPANY'S REPLY COMMENTS - 11

discussions and benchmarked against reputable public sources (National Renewable
Energy Laboratory ("NREL"), the U.S. Energy Information Administration (TIA"), Lazard,
and others), as well as Idaho Power's own procurement experience.
It is also important to note that these cost assumptions were developed and vetted
before the 2025 IRP was filed, using the best information available at that time, and with
input from stakeholders during the IRP advisory process. Some of the materials RNW
and NWEC cite were published after the IRP assumptions were set and therefore could
not have reasonably been considered in the base planning cases. In comments, RNW
and NWEC indicate that the Company's IRP process should consider a full range of
recent, demonstratable market uncertainty.$
However, recognizing that resource cost forecasts are inherently uncertain and
that different data sources may diverge, the Company did not rely on a single deterministic
cost trajectory. Instead, Idaho Power modeled a range of higher-resource-cost and
higher-gas-price futures to understand least-cost portfolios under a wide spread of
plausible cost outcomes. Across these alternative futures, the modeling results
consistently identify portfolios that include firm flexible natural gas resources and
expanded interregional transmission as least-cost and least-risk, once reliability
constraints and load growth are fully represented.
Idaho Power remains committed to using the most recently available and
demonstrably robust information when developing resource input assumptions in future
IRPs and will continue to refine assumptions as markets evolve and new data becomes
available. Moreover, as noted by Staff within their comments, "the resources included in
8 RNW and NWEC Comments (Nov. 12, 2025) at 2.
IDAHO POWER COMPANY'S REPLY COMMENTS - 12

the Company's Preferred Portfolio are proxies that the Company selected based on
assumptions at that moment in time."9 This perspective is shared by the Company and is
precisely how an IRP should be viewed — as a snapshot in time using factors believed to
be most relevant at that time, which is then updated biennially to provide directional
guidance to the utility. Should changes warranting a different set of assumptions
materialize after the Company's development of its IRP, such factors will be considered,
to the extent they remain relevant, when the Company develops its subsequent IRP.
However, attempting to measure an IRP's results using certain data elements not
available at the time such plan was developed is improper and creates the potential for
an IRP to remain in perpetual limbo due to the rapidly changing environment in which the
Company operates.
RNW and NWEC Contention: The Company omits key reliability considerations
for thermal resources and its increased reliance on new thermal capacity
exposes the system to fuel price volatility and supply risk.
The Company appreciates RNW and NWEC's support for its use of RCAT. For
clarity, RCAT is a probabilistic model that applies the Billinton-Allan reliability framework,
and pages 7 through 16 within Appendix D of the Company's 2025 IRP explains how
RCAT informs Effective Load Carrying Capability ("ELCU), Planning Reserve Margin
("PRM"), and the identification of high-risk seasons and hours used across the analysis.
Reliability assumptions for new thermal resources rely on North American Electric
Reliability Corporation Generation Availability Data System Equivalent Forced Outage
Rate during Demand ("NERC GADS EFORd") values, as also discussed within Appendix
D of the Company's 2025 IRP. RNW and NWEC challenge the value of GADS data
9 Staff's Comments at 2.
IDAHO POWER COMPANY'S REPLY COMMENTS - 13

indicating it "does not consider operating with frequent daily cycling to integrate variable
energy resources that is more stressful than traditional baseload service and can cause
faster performance degradation."10 However, NERC publishes a 5-year rolling average,
so any degradation resulting from more frequent cycling and integration is accounted for
in the metric. Also, because the data is historical, any disruption on pipelines or extreme
cold events, such as the December 2022 winter storm, are present in the dataset.
Pointing to the 2025 IRP's Preferred Portfolio as including 450 MW of new thermal
resources, RNW and NWEC raise concerns regarding fuel price volatility and gas
deliverability, creating what they characterize as "elevated reliability and ratepayer risk."
The Company disagrees with this assessment and provides evidence in the 2025 IRP to
show that the Preferred Portfolio minimizes cost while satisfying the reliability thresholds.
First, the Preferred Portfolio shows significant portfolio diversity adding 700 MW of new
wind, 745 MW of new solar, 705 MW of new Battery Energy Storage Systems ("BESS"),
two new transmission links to two diverse energy markets, 89 MW of DSM resources, 450
MW of new gas resources, and the conversion of two coal plants to natural gas in the
Action Plan window." This significant portfolio diversity will both increase reliability and
reduce customer risk by not relying on any single type of resource. RNW and NWEC
highlight that adding new natural gas resources could increase exposure to fuel price
volatility and gas deliverability.12 The 2025 IRP illustrates how the Company is planning
to mitigate this risk and it is also important to note that when accounting for natural gas
price volatility, the Preferred Portfolio remains risk and price optimal. First, the Company
10 RNW and NWEC Comments at 7.
11 2025 IRP Report at 124, Table 11.1 Preferred Portfolio (With 111(d) Bridger 3&4 NG) resource
selections.
12 RNW and NWEC Comments at 5.
IDAHO POWER COMPANY'S REPLY COMMENTS - 14

is actively working to diversify its natural gas supply. Historically, the Company has relied
mostly on gas from the Sumas basin. With the conversion of Bridger Units 1 and 2 from
coal to natural gas, the Company began procuring gas directly at the Opal hub and its
future fuel procurement strategy includes using Sumas, Stanfield, and Opal gas over
multiple pipelines.13 Having a geographically diverse supply of natural gas combined with
the interregional transmission buildout of the Preferred Portfolio will significantly limit the
impact of combined events like the January 2024 simultaneous dunkelflaute,14 cold snap,
and pipeline disruption. With new gas resources that are not reliant on the Northwest Gas
pipeline, the Company would be better able to shield customers from the price impacts of
multi-day low solar and wind events during cold weather even if one of the three gas
supplies it pulls from has a supply disruption. This resource diversity is in addition to the
substantial regional diversity from the Desert Southwest that the SWIP-N line will provide.
The Company knows that despite these efforts, volatility will remain in the natural gas
markets which is why it includes a wide range of natural gas prices in the stochastic
analysis including one that had many years of annual average gas prices over $20 per
Million British thermal units ("MMBtu").15 The results of the stochastic analysis show that
a non-diverse portfolio like the "No New Gas" portfolio performs substantially worse than
the Preferred Portfolio, even when accounting for gas price volatility.16
To further bolster their claims that the Company's 2025 IRP doesn't accurately
capture fuel price volatility and supply risk, RNW and NWEC Comments point to the price
13 2025 IRP Report at 94.
14 Also referred to as a "dark doldrum," i.e., the simultaneous occurrence of darkness and a lull in wind
activity.
15 2025 IRP, Appendix C: Technical Appendix at 97.
16 Id. at 102.
IDAHO POWER COMPANY'S REPLY COMMENTS - 15

differential between the Preferred Portfolio and the scenario portfolios for Low Gas Price
and High Gas & Carbon Prices. Through their assessment, the Company believes that
RNW and NWEC have missed important context stated in the IRP immediately preceding
the sensitivities table 10.3 where the costs for these portfolios are displayed." RNW and
NWEC have not accounted for the varying conditions between these portfolios and
suggest a conclusion from the table that does not exist. For a comparison between the
Preferred Portfolio and the High Gas & High Carbon portfolio where conditions are the
same in each, the stochastic analysis is a more precise comparison. The stochastic
analysis shows that in 95 percent of possible futures which include varying gas prices,
the Preferred Portfolio results in lower costs than the High Gas & High Carbon portfolio.
This demonstrates that the Preferred Portfolio minimizes cost and risk while the High Gas
& High Carbon portfolio is an expensive hedge for an unlikely future.
RNW and NWEC further claim, "the fuel supply strategy is a work in progress. The
feasibility and timeline for the expansion of the Northwest Pipeline are not addressed in
the 2025 IRP," and after highlighting excerpts from the IRP, conclude: "On any given day,
the Company expects to procure additional transportation capacity via the short-term
capacity release market, further jeopardizing the certainty of the supply and delivered
price."'$This comment mischaracterizes the following statement from page 94 of the 2025
IRP:
Idaho Power projects (located in Idaho) that require additional natural gas
generating capacity would require an expansion of Northwest Pipeline. A
pipeline expansion would provide diversification benefits from the current
mix of firm transportation composed of 100 [percent] from Northwest basins
17 See 2025 IRP, at 113, which states: "Please note that these scenarios have varying conditions and
constraints (see Chapter 9) associated with each specific future. Comparisons made between these
scenario costs must take this into account."
18 RNW and NWEC Comments at 9.
IDAHO POWER COMPANY'S REPLY COMMENTS - 16

and no firm capacity from the Rocky Mountain supply region. The 2025 IRP
modeled between $0.50 and $1.20 per Million British thermal units19
(MMBtu) transportation rates for new units. The expansion options are fluid
and this is an area that the company is actively monitoring. It is assumed
that any additional transportation would be procured in the short-term
capacity release market, or through delivered supply transactions to cover
100 percent of the requirements on any given day.
The Company notes that it did model the feasibility and timeline for the expansion
of the Northwest Pipeline and also explained how the Company plans to fuel its units in
a way that minimizes volatility. The Company is committed to continually analyzing this
highly dynamic and important element of its future resource strategy in order to minimize
portfolio costs and risks.
RNW and NWEC Recommendation: The Company and Commission create more
transparency and rigor to future new large-load forecasts and flexibility.
RNW and NWEC recommend that Idaho Power develop new large-load tariffs to
enhance flexibility and consider opportunities for increased demand-side flexibility from
large loads and "innovative large-load tariffs" to help mitigate reliability and planning risks,
such as the over procurement of capacity for unprecedented load growth. Idaho Power is
open to continued dialogue on tariff design in the appropriate regulatory venues and notes
that it has and will continue to consider creative solutions to address the amount of load
growth the Company is experiencing. As a planning document, the IRP incorporates load
forecasts and resource options; on the other hand, ratemaking and tariff design are
addressed in separate proceedings. Of note, however, pursuant to Idaho Power's
Commission-approved Schedule 19, large loads in excess of 20 MW are required to make
19 The Company has expressed these transportation rates in the typical fashion of$/MMBtu. For gas
transport, the maximum possible fuel consumption in a day is multiplied by this rate which is multiplied by
he days in a year. As an example, for the proxy simple cycle units modeled in the 2025 IRP, at 150MW
and a heat rate of 9.700 MMBtu/MWh, the max hourly burn rate is 1,455 MMBtu/Hour. Multiplied by 8,760
for the hours in a non-leap year results in an annual fixed transportation cost of$6,372,900 per year at
$0.50/MMBtu and $15,294,960 per year at$1.20/MMBtu.
IDAHO POWER COMPANY'S REPLY COMMENTS - 17

special contract arrangements to address cost recovery adequacy, and as part of these
arrangements the Company discusses with such large load customers their willingness
to participate in demand response programs and whether their loads are flexible.
Moreover, Idaho Power disagrees with RNW and NWEC's contention that the
Company's current approach is susceptible to over procurement of capacity. As the
Company has explained through discovery responses, it thoroughly vets large load
commitments before their inclusion in load forecasts to avoid speculative additions. Idaho
Power maintains regular communication with prospective new large load customers and
performs due diligence to ensure the forecast is the best representation of large loads
that are likely to materialize, thereby excluding speculative loads. As described by Staff
within their comments:
It is important to reiterate that the Commission's acknowledgement of the
IRP does not imply that prudence is conferred to the resources included in
the Preferred Portfolio. Staff considers that the resources included in the
Company's Preferred Portfolio are proxies that the Company selected
based on assumptions at that moment in time. Staff expects that the
Company will select each resource at the time of acquisition by evaluating
it against the range of alternatives that are available at that time and at
current prices to obtain a determination of prudence.
Building upon Staff's remarks, the Company's IRP is an analysis based on a
snapshot in time in an otherwise fluid planning environment and is intended to provide
directional guidance to the Company. Although the Company has included only those
large loads it believes to be most likely to materialize in its 2025 IRP load forecast, the
Company's resource procurement decisions will necessarily reflect the reality known at
that time.
IDAHO POWER COMPANY'S REPLY COMMENTS - 18

C. REC
Idaho Power appreciates REC's engagement and focus on planning assumptions
for Qualifying Facilities ("QFs"). As an initial clarification, Idaho Power notes that REC
sometimes uses different terminology than the Company in discussing a QF entering into
another contract upon the expiration of its existing contract. While REC uses the terms
"renewal" or "replacement," Idaho Power solely uses the term "replacement" to describe
this concept, as the new contract that is entered into is not a "renewal" of the prior
contract, it is a new contract with new applicable rates, terms, and conditions.
REC Contention:Idaho Power is inaccurately modeling renewal of existing wind
and solar QFs.
REC comments that Idaho Power's application of the 75 percent PURPA contract
replacement rate for wind and solar QFs is neither reasonable nor accurate.20 Citing
REC's opening comments from Oregon Commission Docket LC 87, IIPA makes similar
claims that the Company's methodology results in a low QF renewal rate.21
Idaho Power disagrees that its 2025 IRP's implementation of the 75 percent
contract replacement rate for wind and solar resources is unreasonable. As background,
the Commission oversees acknowledgement of Idaho Power's IRP and the contracts for
QFs delivering their output to the Company in Idaho, while contracts for QFs delivering
their output to the Company in Oregon are governed by the Oregon Public Utility
Commission ("OPUC"). Prior to the development of the 2025 IRP, both Commissions
offered guidance or direction for QF assumptions: this Commission through Order No.
36233 and the OPUC through Order No. 24-285. The 2025 IRP implements both
20 REC Comments (Nov. 13, 2025) at 2.
21 IIPA Comments (Nov. 13, 2025) at 5.
IDAHO POWER COMPANY'S REPLY COMMENTS - 19

Commissions' directives by using data-driven assumptions for resource types where data
is available (as directed by the Idaho Commission), and by using a 75 percent planning
assumption for replacements for resource types where no existing contracts have yet
expired (as directed by the OPUC). Because the assumed replacement contracts will
themselves one day expire, Idaho Power considered those future expirations and
continued to assume a replacement rate of 75 percent for the contracts at that time, with
the assumed expirations based on the term lengths available to QFs in each state. This
assumption primarily impacts Idaho QFs that are above the cap for eligible published
standard avoided cost rates, which are only eligible for two-year contract terms. For
Oregon QFs, where replacement contracts have a 20-year term, this assumption has
minimal effect given the IRP's 20-year planning horizon.
REC indicates that its research suggests that all of Idaho Power's wind QFs plan
to enter into replacement contracts; however, the Company notes that assumption
appears to be based on anecdotal information.22 While it remains to be seen what percent
of QFs actually enter into replacement contracts, Idaho Power's experience indicates it
may not be 100 percent. The uncertainty the Company has experienced with these types
of projects is exemplified by the Company's recent experience with two wind projects.
Idaho Power had provided information to both these projects regarding the process and
timeline for requesting a replacement contract numerous times over the past year(s).
However, these projects have not been timely in indicating their intent to enter into a
replacement contract, with one of these projects executing a replacement contract only
five calendar days prior to the expiration of their existing contract. The second project's
22 REC Comments at 5-6.
IDAHO POWER COMPANY'S REPLY COMMENTS - 20

contract will expire in early 2026 and that developer has not requested a draft contract,
nor indicated their intent to enter into one despite multiple and repeated inquiries from
Idaho Power. While the first of these projects has now executed a replacement contract,
the lack of timely and actionable information regarding the projects' intent in advance to
enter into a replacement contract creates significant uncertainty for Idaho Power on
whether it will be able to continue to rely on the project's capacity to serve customers'
loads. These data points support a conservative replacement rate assumption until signed
successor agreements exist.
While REC asserts that the Commission's current policies regarding QF contract
length will negatively affect QF renewal rates and will lead Idaho Power to over-procure
resources and potentially miss out on more cost-effective resources,23 REC does not offer
evidence supporting such claims. Rather, as noted above, of the two wind QFs whose
existing contracts have or will soon expire, one QF has entered into a replacement
contract under the current policies, rates, terms, and conditions, and one has not
indicated whether it intends to do so. Thus, at best the data with respect to Idaho Power's
system is mixed regarding QFs' intent to enter into replacement contracts.
Regarding resource procurements, the Company's needs are evaluated based on
the most up-to-date information at the time. If, at the time a resource is procured, more
QFs have entered into replacement contracts than were forecasted to do so in an IRP,
those replacement contracts will be considered in the Company's evaluation of its needs
as part of the procurement efforts, ensuring the Company does not procure more
resources than is necessary. Conversely, if fewer QFs have entered into replacement
23 REC Comments at 6-7.
IDAHO POWER COMPANY'S REPLY COMMENTS - 21

contracts than were forecasted to do so in the IRP, the Company's identified deficits will
be greater than initially forecast. In that case, the Company must be able to plan its
procurements to ensure reliability and appropriately should evaluate its resulting needs
and seek to procure resources to meet those needs. Further, if QF replacements of
variable energy resources are assumed, additional flexible resources are required for
integration, which can increase the quantity of storage or natural-gas flexibility selected
by the IRP's model.
To be clear, Idaho Power is not taking a position as to how many Us may enter
into replacement contracts in the coming years or what the most correct eventual
replacement rate will be considering there may be many factors that influence each
individual QF's decision as it relates to entering into a replacement contract. However,
Idaho Power's experience to date, as described above, suggests that the decision will be
made individually and that a blanket "100 percent replacement rate" assumption may not
be reasonable. In light of this uncertainty and considering the directives from the Idaho
and Oregon Commissions leading up to the 2025 IRP, the Company believes the
assumptions used when developing the 2025 IRP are a reasonable and appropriate
implementation of such directives.
D. IIPA
As an initial matter, several of the issues included in IIPA's comments pertain to
concerns that extend beyond the purpose and scope of an IRP. The IRP is a long-term
planning document intended to evaluate system needs, resource portfolios, and
uncertainty, and not a determination of cost allocation or assignment of cost responsibility
to individual customer groups or to resolve ratemaking questions. Issues related to cost
IDAHO POWER COMPANY'S REPLY COMMENTS - 22

causation, cost allocation, and rate design are more appropriately addressed within a
general rate case or other proceeding specifically contemplating those determinations.
Accordingly, the Company provides the following comments to address the
aspects of I IPA's comments that fall within the scope of an IRP filing, clarify Idaho Power's
planning assumptions where necessary, and distinguish between planning-related
considerations and issues that are more appropriately handled as part of a separate,
future proceeding.
IIPA Contention: The IRP's modeling creates artificial summer scarcity by
applying reduced imports, higher losses, and seasonal constraints only in
summer.
IIPA contends that the way Idaho Power model's transmission resources is
designed to create artificial summer scarcity. Idaho Power disagrees with this claim. The
availability of transmission capacity during the summer months is objectively lower than
during non-summer months. For example, neighboring systems have greater demand in
the summer and, as such, those utilities reserve transmission capacity to serve their
system's loads—this reservation of transmission system capacity reduces the Company's
ability to import and export energy. The Company also models higher system losses in
the summer because warmer conductors, when coupled with higher demand, experience
greater line losses. Thus, the warmer temperatures experienced in summer increase
system losses.
IIPA's misunderstanding and/or misrepresentation of the Company's transmission
modeling is evident as they reach several incorrect conclusions. For example, IIPA claims
that B2H will drive prices up by pointing to the Mid-C and Intermountain Prices (which
tend to be higher in the winter); however, B2H was modeled as a summer only resource
IDAHO POWER COMPANY'S REPLY COMMENTS - 23

(a fact acknowledged by IIPA). More plainly stated, Idaho Power's modeling does not rely
on any winter capacity provided by B2H for resource adequacy. Because B2H is not being
leveraged as a winter resource, the Company will only transact energy to the Pacific
Northwest when it is economically feasible.
In its comments, IIPA argues that irrigation customers should not be responsible
for transmission expansion costs and suggests that seasonal reallocation of existing
capacity could avoid the need for new transmission. They further claim that only
continuous industrial load growth is the primary driver for transmission projects like 132H
and Gateway West. However, these assertions misrepresent confidential outage data
provided by the Company during discovery, which represented wildfire-related tie-line
outages during the summer only— not all the outages in the transmission system as IIPA
implies. B2H has consistently been identified as a cost-effective resource over the last
several IRPs and claiming that this project (or other transmission projects) is directly
caused by only industrial load is inaccurate given broader reliability and resource
adequacy needs.
11PA Contention: The IRP risks stranded costs because it assumes large
industrial load materializes on schedule but includes no sensitivity for delayed
or failed load.
IIPA raises concern surrounding the risk of stranded or transferred costs should
the large loads included within the load forecast used in development of Company's 2025
IRP.24
It is important to note, the load forecast only reflects those customers that have
made a sufficient and significant binding investment and/or interest indicating a
24 IIPA Comments at 3.
IDAHO POWER COMPANY'S REPLY COMMENTS - 24

commitment of the highest probability of locating within the service area. The large
number of prospective businesses that have indicated some interest in locating in Idaho
Power's service area but have not made sufficient commitments are not included in the
sales and load forecast. Accordingly, Idaho Power has sufficiently considered the risk of
speculative load when developing its 2025 IRP in order to reduce the potential for
resources that are otherwise only necessary to support speculative loads from being
selected. While cost recovery is not an element of the IRP, the Company notes that other
dockets and the special contracts themselves work to mitigate stranded cost risk.
Furthermore, given the substantial interest from a variety of customer segments for
increased demand, the Company focused its time and resources on analyzing higher load
scenarios as these have a higher probability of materializing than low load scenarios.
However, as more fully detailed above in response to NWEC and RNW, should loads not
materialize as anticipated within the Company's 2025 IRP, the Company's resource
procurement decisions will necessarily reflect the reality known at that time.
IIPA Contention: The IRP is flawed because it includes the 600 MW Jackalope
Wind project, which appears infeasible by 2027, with no alternative or sensitivity
testing.
While IIPA suggests the Company's 2025 IRP is incomplete because it does not
account for the indefinite pause of the Jackalope Wind project, which is more fully
discussed within Case No. IPC-E-25-28, IIPA fails to account for the timing of when the
2025 IRP was developed and when such indefinite pause became known to the
Company. As noted within Staff's comments, to which the Company agrees: the
IDAHO POWER COMPANY'S REPLY COMMENTS - 25

resources included in the Company's Preferred Portfolio are proxies that the Company
selected based on assumptions at that moment in time.25
Indeed, at the time of the 2025 IRP's development there were no indications that
the Jackalope Wind project would be indefinitely paused due to changes in federal
permitting. Thus, the Company does not believe it reasonable to label the 2025 IRP as
incomplete due to this change.
IIPA Contention: The IRP is inconsistent with the Bennett Gas Expansion filing,
which relies on the 2023 IRP instead of the 2025 IRP.
IIPA's suggestion that the Company's capacity need supporting its request for a
Certificate of Public Convenience and Necessity ("CPCN") for the Bennet Gas Expansion
Project relies entirely on the 2023 IRP's capacity analysis and therefore demonstrates a
disconnect between IRP filings because the 2025 IRP's results were not considered, is
false. For clarification, issuance of the 2028 RFP, which solicited resources in 2028 and
beyond, occurred in October 2024, prior to the development of the 2025 IRP, and was
based on the capacity needs identified in the 2023 IRP. Ultimately, the final shortlist of
the beyond April 2028 bids from the 2028 RFP, which identified the Bennett Gas
Expansion Project as the least-cost, least-risk resource addition, was approved by the
OPUC on August 19, 2025, in accordance with competitive bidding rules for which the
Company is currently required to follow. Following approval of the final shortlist of beyond
April 2028 bids and acknowledging that during the near-term decision-making phase the
annual capacity positions can be very fluid, Idaho Power performed an assessment of
system reliability using refreshed load and resource inputs to identify the most up-to-date
annual capacity position. It was this system reliability assessment, which was performed
25 Staff's Comments at 2.
IDAHO POWER COMPANY'S REPLY COMMENTS - 26

subsequent to the 2025 IRP, that was the basis for the Company's request for a CPCN
for the Bennett Gas Expansion Project. Furthermore, the 2025 IRP preferred portfolio
identified 150 MW of proxy reciprocating engines as optimal resources to serve system
load in 2029, which very closely aligns with the least-cost, least-risk resource identified
on the final shortlist of beyond April 2028 bids, the Bennett Gas Expansion Project.
11PA Contention: Transmission projects (B2H, Gateway West, SWIP-N) appear
in all cases regardless of load scenario, with no updated economic justification.
IIPA raises concern around the Action Plan included within the Company's 2025
IRP failing to present several major transmission and generation additions.26 As it relates
to B2H and Gateway West Segment 8, these transmission additions' exclusion is due to
the projects having either been committed to prior to the 2025 IRP or because of their
universal need. Specifically, the B2H transmission project was considered committed and
included in all scenarios within the 2025 IRP because a CPCN was previously granted
and B2H pre-construction activities had already commenced at the time of the 2025 IRP's
development. Second, Gateway West Segment 8 was included in all portfolios because
it is not feasible to create a reliable resource portfolio build without inclusion of a
transmission capacity upgrade to Idaho Power's backbone transmission system
regardless of scenario. Stated more plainly, Idaho Power's existing transmission system
east of Boise is fully utilized, and in order to move on-system and imported resources to
load, additional internal transmission capability is necessary irrespective of the scenario
contemplated within the 2025 IRP. Given permitting and citing difficulties in the Treasure
Valley, the bulk of new resource additions are expected to occur east of Boise. Gateway
26 IIPA Comments at 3.
IDAHO POWER COMPANY'S REPLY COMMENTS - 27

West Segment 8 will increase Idaho Power's transmission capacity on the Midpoint West
and the Boise East paths, enabling resource additions.
With respect to IIPA's concerns related to SWIP-N, a "No SWIP" scenario was
modeled as a Future Scenario and compared against the Preferred Portfolio. The results
of the analysis, which generally shows significantly more resources at a greater cost
needing to be acquired absent SWIP-N, can be located within Chapter 11 of the 2025
IRP.
Finally, IIPA's contention that transmission expansion is driven by new industrial
load, not reliability needs, is without merit. The transmission projects support broader
system reliability and capacity and are planned, procured, and operated to optimize
service for all customers as part of Idaho Power's long-term planning for regional growth,
grid reliability, and resource interconnection needs.
IIPA Contention: Idaho Power's Loss-of-Load Expectation (LOLE) and
Effective Load Carrying Capability (ELCC) binding reliability constraints
occur during the winter months.
IIPA claims that the portfolio's most expensive capacity additions are triggered by
new winter load and not by summer load. While cost allocation is outside of the scope of
the IRP, the claims made by IIPA that reliability constraints occur in winter months are
inaccurate and not based on analysis or data provided by the Company. To the contrary,
as published in Appendix D of the IRP, summer remains Idaho Power's highest risk
season, with July accounting for over half of the total risk. Further, the Preferred Portfolio
seasonal LOLE analysis shows higher summer risk in all years of the 20-year planning
period.
IDAHO POWER COMPANY'S REPLY COMMENTS - 28

E. Public Comments
Idaho Power appreciates the thoughtful public input provided in this docket and
thanks CEO and the City of Boise for their participation at the Company's IRPAC meetings
and providing their expertise therein. The comments submitted by CEO and the City of
Boise reflect a shared interest in ensuring that Idaho Power continues to plan responsibly
for a rapidly changing energy landscape, including growing large loads, evolving market
conditions, and increasing climate-related uncertainties. Idaho Power values the
additional perspective provided and addresses key themes raised within these comments
as follows.
Within the comments submitted by CEO, emphasis is placed on the notion that
increasing penetration of solar and storage in regional markets fundamentally reshapes
marginal cost patterns and the traditional understanding of a "flat" load being lowest cost
to serve. CEO points to the 2025 IRP's hourly price and LOLE outputs, particularly the
concentration of reliability risk in a small set of summer and shoulder-season hours, as
evidence that future IRPs would benefit from a more targeted, hourly orientation when
evaluating price-based demand-side management ("DSM") and load flexibility
opportunities. CEO also raises questions about the interaction between DSM, rate design,
and large-load contract structures, encouraging Idaho Power to coordinate internal
expertise more fully in future IRP cycles. Finally, CEO recommends improving marginal
cost inputs for DSM analysis and expanding consideration of price-responsive programs
across all customer classes.
Idaho Power appreciates CEO's perspective and agrees that DSM resources are
an important component of system planning. The Company generally agrees with several
IDAHO POWER COMPANY'S REPLY COMMENTS - 29

of CEO's observations regarding hourly pricing and seasonal capacity, and acknowledges
that if new or shifted load primarily occurs during low-cost hours, it would reduce overall
cost to serve. However, the Company disagrees with two key assertions: (1) that a large,
easily accessible pool of shiftable load exists, and (2) that the IRP fails to incorporate
Company-wide expertise for incorporating DSM opportunities.
CEO's claim of vast untapped load-shifting potential does not align with Idaho
Power's third-party potential study or operational experience. Idaho Power offers optional
residential time-of-use rate energy pricing, and large general and industrial customer
pricing structures already include time-of-use pricing elements. In addition, the Company
is currently evaluating the feasibility and efficacy of an optional time-of-use pricing
structure for irrigation customers. Additional DSM potential is already assessed in the IRP
based on hourly economic value, including midday low-price and evening high-price
differentials. The Company's load forecast reflects realistic adoption patterns for time-of-
use and demand response programs. Consequently, meaningful cross-departmental
DSM opportunities are already embedded in the preferred portfolio.
It is also important to note that utility-scale batteries have become a cost-effective
solution for absorbing low-cost solar energy during midday hours. Idaho Power has
installed or contracted over 800 MW of 4-hour battery energy storage, primarily charged
during these low-cost time periods. As a result, the incremental capacity benefit of
additional load-shifting programs is significantly diminished compared to a scenario
without utility-scale battery storage.
The City of Boise expresses support for the 2025 IRP's substantial additions of
solar, wind, and storage and its planned exits from coal generation. At the same time, the
IDAHO POWER COMPANY'S REPLY COMMENTS - 30

City of Boise raises concerns about additions of new natural gas capacity, citing potential
inconsistency with Idaho Power and the City of Boise's long-term clean-energy goals.27
Boise recommends deeper incorporation of climate-driven risks such as including
hydropower uncertainty, public safety power shutoff ("PSPS") events, wildfire exposure,
carbon price scenarios, and fuel price risk into core IRP portfolios rather than limited
sensitivity analyses. The City of Boise also requests increased transparency around joint
ownership decisions associated with Jim Bridger Units 3 and 4 and encourages Idaho
Power to give geothermal resources a more substantial role within future portfolio
evaluations.
Idaho Power appreciates City of Boise's recognition of the Company's inclusion of
wildfire impacts on transmission availability modeled in the 2025 IRP risk assessments,
but notes that PSPS events have typically occurred internal to Idaho Power's system
which is currently outside the scope of resource adequacy efforts. However, if mitigation
measures come into place that directly affect resource planning processes, Idaho Power
looks forward to working with stakeholders on how to best incorporate them in future
I RPs.
III. CONCLUSION
Based on the detailed and comprehensive analysis set forth in the 2025 IRP, Idaho
Power has demonstrated that its Preferred Portfolio, which includes a diverse buildout of
resources, is the best combination of least-cost, least risk resources to meet the
Company's growing demand over the next 20 years.
27 City of Boise Public Comments at 2.
IDAHO POWER COMPANY'S REPLY COMMENTS - 31

The Company is grateful for Stakeholders' interest and commitment to the IRP
process. Idaho Power appreciates Staff's recommendation that the Commission
acknowledge the 2025 IRP, as well as its recommendations regarding considerations for
future IRPs. Idaho Power respectfully requests that the Commission accept and/or
acknowledge the Company's 2025 IRP and find that it meets the requirements of Order
Nos. 22299 and 25260, consistent with Staff's recommendation in this matter.
Respectfully submitted this 9th day of December 2025.
T I'
MEGAN GOICOECHEA ALLEN
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S REPLY COMMENTS - 32

CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 9th day of December 2025, 1 served a true and
correct copy of Idaho Power Company's Reply Comments upon the following named
parties by the method indicated below, and addressed to the following:
Commission Staff Hand Delivered
Jeff Loll U.S. Mail
Deputy Attorney General Overnight Mail
Idaho Public Utilities Commission FTP Site
11331 W. Chinden Blvd., Bldg No. 8, X Email jeff.loll puc.idaho.gov
Suite 201-A (83714)
PO Box 83720
Boise, ID 83720-0074
Micron Technology, Inc. Hand Delivered
Austin Rueschhoff U.S. Mail
Thorvald A. Nelson Overnight Mail
Kristine A.K. Roach FTP Site
Holland & Hart, LLP X Email darueschhoff(c)_hol land hart.com
555 17th Street, Suite 3200 tnelson hollandhart.com
Denver, CO 80202 awlensen(a)_hol land hart.com
karoach hollandhart.com
aclee(o)_hollandhart.com
tlfriel hol land hart.com
Idaho Irrigation Pumpers Association, Hand Delivered
Inc. U.S. Mail
Eric L. Olson Overnight Mail
Echo Hawk & Olson, PLLC FTP Site
505 Pershing Ave., Ste. 110 X Email eloCcDechohawk.com
P.O. Box 6119 taysha(c)_echohawk.com
Pocatello, ID 83205
Lance Kaufman, Ph.D. Hand Delivered
2623 NW Bluebird Place U.S. Mail
Corvallis, OR 87330 Overnight Mail
FTP Site
X Email lance aegisinsight.com
IDAHO POWER COMPANY'S REPLY COMMENTS - 33

Northwest Energy Coalition Hand Delivered
Renewable Northwest U.S. Mail
Benjamin J. Otto Overnight Mail
1407 W. Cottonwood Crt. FTP Site
Boise, ID 83702 X Email ben nwenergy.org
lauren(c)-nwenergy.org
derek _nwenergy.org
mike renewablenw.org
katherine(a),renewablenw.org
kyle(o)_renewablenw.org
Renewable Energy Coalition Hand Delivered
Irion Sanger U.S. Mail
Sanger Greene, P.C. Overnight Mail
4031 SE Hawthorne Blvd. FTP Site
Portland, OR 97214 X Email irion sanger-law.com
diego(a-).sanger-Iaw.com
dustinCc)_sanger-law.com
0ohn recoalition.com
C9 >
Christy Davenport
Legal Administrative Assistant
IDAHO POWER COMPANY'S REPLY COMMENTS - 34