20240618Final_Order_No_36233.pdf

Office of the Secretary
Service Date
June 18,2024
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER ) CASE NO. IPC-E-23-23
COMPANY'S 2023 INTEGRATED )
RESOURCE PLAN ) ORDER NO. 36233
On September 29, 2023, Idaho Power Company ("Company") filed an application
("Application") with the Idaho Public Utilities Commission ("Commission") requesting that the
Commission issue an order acknowledging the Company's 2023 Integrated Resource Plan
("IRP").
The Company stated that the 2023 IRP represented a comprehensive analysis of the optimal
mix of both demand- and supply-side resources available to reliably serve customer demand and
flexible capacity needs from 2024 to 2043. Application at 1-2.
The Company represented that the primary goals of the 2023 IRP were to: (1) identify
sufficient resources to reliably serve the growing demand for energy within the Company's service
area throughout the 20-year planning period (2024-2043); (2) ensure the selected Preferred
Portfolio balances cost and risk, while including environmental considerations; (3) give equal and
balanced treatment to supply-side resources, demand-side measures, and transmission resources;
and(4) involve the public in the planning process in a meaningful way. Id. at 5.
The Company represented that it used the AURORA model to develop portfolios for the
2023 IRP. Id. at 7-8. The Company stated that two notable trends emerged in the 2023 IRP, the
vital nature of added transmission and the substantial downward trend in portfolio greenhouse gas
emissions.Id. at 10.
The Company represented that it identified several key resources or potential projects to
evaluate in additional detail, and the Company required the model to build portfolios both with
and without each resource or project. Id. at 14. The Company stated that those models with and
without views include: (1)with and without the 132H project; (2)with and without different phases
of the Gateway West projects; and (3)with and without specific Valmy Unit 1 and Unit 2 natural
gas conversion assumptions. Id.
The Company represented that, based on its analysis, it selected a Preferred Portfolio
identified in the 2023 IRP as"Valmy 1 &2",referring to the portfolio's conversion of both Valmy
units from coal to natural gas. Id. at 14-15. The Company stated that the Preferred Portfolio was
ORDER NO. 36233 1

the least-cost,least-risk option that incorporated positive changes toward clean,low-cost resources
without compromising system reliability. Id.
The Company's Preferred Portfolio adds 3,325 megawatts ("MW") of solar, 1,800 MW of
wind, 1,453 MW of storage (four- and eight-hour batteries, as well as long-duration 100-hour
storage), 360 MW of additional energy efficiency("EE"), 340 MW of hydrogen("1­12"), 160 MW
of new demand response ("DR"), and 30 MW of geothermal.Id. at 3.
Additionally,the Preferred Portfolio includes conversions of multiple coal-fired generation
units to natural gas, showing the Company exiting coal entirely in 2030 and adding a net total of
261 MW of natural gas via coal conversions through 2043 (reflecting the addition of 967 MW of
gas conversions and 706 MW of gas conversion exits, netting 261 MW of additional gas
generation). Id.
The Company represented that, in total, the Preferred Portfolio adds 6,888 MW of
incremental resource capacity over the next 20 years and includes the B2H transmission line
beginning in July 2026 and three Gateway West transmission line segments phased in from 2029
to 2040. Id.
The 2023 IRP also contains the Company's Near-Term Action Plan that reflects near-term
actionable items of the Preferred Portfolio necessary to successfully position the Company to
provide reliable, economic, and environmentally sound service to its customers into the future.Id.
at 15. The Company represented that the 2023 IRP incorporates prior recommendations it received
concerning several issues, and the 2023 IRP provides additional analysis/discussion of those
issues. Id. at 17.
On October 31, 2023, the Commission issued a Notice of Application and Notice of
Intervention Deadline. Order No. 35974. The Commission granted intervention to Micron
Technology, Inc. Order No. 36014. On December 1, 2023, a Notice of Parties was issued.
STAFF COMMENTS
Based on its review, Staff recommended the Commission acknowledge the Company's
2023 IRP. Staff Comments at 3. However, Staff believed that the Company's Preferred Portfolio
might not be the least-cost portfolio, and Staff recommended that the Company perform additional
analyses to validate the least-cost, least-risk portfolio and submit a supplemental report with the
results. Id.
ORDER NO. 36233 2

Staff s comments focused on: (1)The Preferred Portfolio; (2)The Near-Term Action Plan;
(3) The Load Forecast; (4) The Demand-Side Management Program; (5) The Seasons and Hours
of Highest Risk; (6) PURPA and Other Planning Assumptions; and (7) Review of 2021 Staff
Recommendations.Id. at 4.
Preferred Portfolio
With respect to the Preferred Portfolio, Staff examined the portfolio development process
and found evidence that the Preferred Portfolio may not be the least-cost portfolio. Id. Over the
IRP's 20-year time window the Company forecasted that system load would grow by 975 average
megawatts ("aMW"), and the peak load would increase by 1,507 MW. IRP Appendix C at 16-17.
To satisfy this increased load, the Company proposed a Preferred Portfolio containing a
mix of new resources. Staff Comments at 5. To satisfy the 975 aMW increase, the Company
proposes to reduce its dispatchable resources, build five times more variable generation than the
average load increase, and add 1,500 MW of BESS resources.Id. at 6. The Company's calculated
net present value ("NPV") for this 20-year portfolio is $9.7 billion. Application at 11.
Staff created a simplified model of the load requirement, and Staff devised a hypothetical
way to satisfy it using a combination of baseload and peaking dispatchable resources. Staff
Comments at 6.
Figure No. 1:Model of a Hypothetical Dispatchable Resource Portfolio
Average Load & Peak Load
6000
5000
>PeakLoadgrowth 1507 MW peak increase
covered by 1658 MW SCCT
4000
------------------------
3000
Avera�Loadgrowth 975 aMW increase
covered by 1773 MW CCCT
2000 - - - -
1000
0
2024 - 2043
ORDER NO. 36233 3

Staff also recalculated the Variable Energy Resource and BESS portions of the Preferred Portfolio
cost by using the same method as the dispatchable portfolio.Id. at 7.
Table No. 3: `Dispatchable' Portfolio Cost versus `VER& BESS' Portfolio Cost
Fixed
Total Years O&M Variable
Reqd Capacity Nominal Capital of ($/kW- O&M Variable Total Cost Portfolio Cost
Resource MW Factor MW ($/kW) Capital Cost Ops month) Fixed O&M ($/MWh) O&M($)' ($) ($)
CCCT 975 55.0% 1773 $ 1,590 $2,818,636,364 20 $ 1.40 $ 595,636,364 $ 3.10 $529,542,000 $ 3,943,814,727 $ 6,739,155,758
SCOT 1507 90.9% 1658 $ 991 $1,642,944,994 20 $ 2.10 $ 835,564,356 $ 6.00 $316,831,680 $ 2,795,341,031
Solar 3325 $ 1,222 $4,063,150,000 20 $ 1.90 $1,516,200,000 $ - $ - $ 5,579,350,000
Wind(ID) 18M $ 1,782 $3,207,6W,000 20 $ 4.10 $1,771,200,000 $ - $ - $ 4,978,800,000 $ 13,894,238,000
BESS 1453 $ 1,600 $2,324,800,000 20 $ 2.90 $1,011,288,000 $ $ $ 3,336,088,000
Note 1:To estimate the fuel costs,the CCCT is assumed to operate 100%of all hours,and the SCCTto operate 20%of all hours over the 20-year period.
Staff reasoned that the $7 billion portfolio cost difference calls into question the accuracy of the
LTCE model and the Company's validation process. Id.
Staff believed there were several possible sources of potential bias in the Company's LTCE
modeling process including: (1) externally imposed constraints on the LTCE model; (2) internal
cost inputs and operating assumptions used by the model; and (3) selection and optimization
algorithms within the model.Id. at 8.
Based on its review Staff believed that the 2023 IRP's Preferred Portfolio might not be the
least-cost portfolio, and a portfolio with a larger share of dispatchable fossil fuel resources
appeared to be substantially less expensive.Id. at 14. Because the Company uses IRP assumptions
and results as part of its justification for future resource projects, Staff believed that the Company
should resolve some of those concerns through additional analysis and through a supplement to
the IRP.Id.
The Near-Term Action Plan
The Company requested that the Commission acknowledge the Company's Near-Term
Action Plan; however, Staff recommended that the Commission refrain from doing so and only
acknowledge the overall 2023 IRP. Staff Comments at 15. Staff noted that the Near-Term Action
Plan consists of eight action items, some of which derive from the Preferred Portfolio, and Staff
believed the Preferred Portfolio might not be least-cost because Action Plan items that are based
on the portfolio might not be appropriate. Id.
The Load Forecast
Staff explained that the Company used a P50 load forecast and a more stringent reliability
target than the industry standard in its 2021 IRP analyses;however,for the 2023 IRP,the Company
adopted the industry standard reliability target, but used a P70 load forecast. Id. at 18. Staff
ORDER NO. 36233 4

identified two issues with the Company's decisions: (1) Staff believed the Company lacked proper
justification for using P70 load forecast for reliability purposes; and (2) there were potential
inflated expected energy costs for rates and avoided costs when using the higher load forecast.Id.
Staff recommended that for future IRPs, if the Company determines its Preferred Portfolio
by using something other than the P50 load forecast, the Company should still use the P50 loads
in its dispatch model to calculate IRP portfolio energy costs and marginal avoided costs.Id. at 20.
Further, Staff recommended that for tariffs that are affected by avoided cost calculations(i.e.Lamb
Weston, Brisbie, Schedule 20), separate dockets should be filed, and Staff would analyze the
Company's cost bases in those dockets.Id.
The Demand-Side Management Program
Staff noted that the Demand-Side Management ("DSM") program is fundamentally
connected to the IRP. Id. Staff was concerned that the 2023 IRP avoided costs were based on the
Preferred Portfolio and the P70 load forecast, and therefore the avoided costs might be incorrect.
Id. at 21.
Staff recommended that the Company not use the 2023 IRP DSM avoided costs included
in the 2023 filing and reassess the avoided costs as part of Staff s recommended supplemental
filing. Id. However, if the Company does not file a supplemental IRP by the time the Company
either evaluates its 2024 DSM program or conducts 2025 DSM program planning, Staff believed
the Company should use the DSM avoided costs from the Company's 2021 IRP. Id. Staff also
recommended that the Company use the P50 load when determining avoided costs in the next IRP.
Id.
The Seasons and Hours of Highest Risk
Staff believed that the methods supporting the seasons and hours of highest risk were
generally reasonable; however, Staff did have concerns with certain assumptions and practices,
and Staff did not recommend updating the seasons or hours of highest risk in conjunction with this
report.Id. at 22.
PURPA and Other Planning Assumptions
Staff recommended that the Company adjust its PURPA assumptions in future IRPs. Id. at
24. Specifically, Staff recommended that the Company conduct a PURPA trend analysis that
includes the most recent data and apply the analysis results in the base planning conditions starting
the first year of the planning horizon in the next IRP. Id.
ORDER NO. 36233 5

Review of 2021 Staff Recommendations
Staff noted that the 2025 IRP schedule could be in jeopardy due to Staff s supplemental
2023 filing recommendation,and Staff recommended that the Company plan accordingly to ensure
that it files the 2025 IRP on time. Id. at 28. Additionally, Staff recommended that in the next IRP
filing, the Company provide justification for why the CBM should be included in the L&RB. Id.
at 29. Finally, Staff reiterated its recommendation that the Company provide separate filings for
each proposed conversion or closure of Valmy and Bridger.Id. at 30.
Final Recommendations
Based on its analysis, Staff recommended that the Commission acknowledge the 2023 IRP.
Id. In addition, Staff recommended:
1. The Commission order the Company to submit a supplemental filing for the 2023 IRP that
addressed the Preferred Portfolio concerns, which should include:
a. Establish a meeting of interested Parties to resolve concerns about model cost inputs
and the selection algorithms. Include BESS degradation incremental costs;
b. Re-run the most prominent existing scenarios with recommended changes to the
baseline planning assumptions;
i. Modify the forced coal exits to allow the model to choose between coal
continuation, exit, or conversion to gas, for Valmy and Bridger;
ii. Eliminate the forced exit from Bridger in 2037. If the Company justifies an end-
of-life closure, allow the model to choose between an exit or a service-life
extension;
c. Cost test at least one new portfolio that has a preponderance of dispatchable fossil
fuel resources;
d. Confirm the 2023 DSM avoided cost data; and
e. Allow for comments from Parties on the Supplement.
2. The Commission order the Company to submit separate filings for approval of each
proposed conversion or exit of Valmy and Bridger.
3. The following changes to future IRPs:
a. Display the assumed peak and energy Us for each selectable resource;
b. Display both nominal LCOCs and CF-adjusted LCOCs for each resource;
c. Display the underlying estimates used to determine interconnection costs;
d. Provide more detailed information about the scope and cost of the SWIP-N project;
ORDER NO. 36233 6

e. Clarify how the Company selects between distribution-connected and transmission-
connected battery projects;
f. Meet with Staff to determine the method for selecting the load probability profile;
g. Use the P50 in the dispatch model to calculate IRP portfolio costs and IRP marginal
avoided costs;
h. Include BESS and DR resources in analysis of seasons and hours of highest risk;
i. Provide analysis that supports the percentage of total risk hours threshold used to
select seasons of highest risk;
j. Provide analysis that supports the percentage of total risk hours threshold used to
select hours of highest risk;
k. Conduct a PURPA trend analysis that includes the most recent data and apply the
analysis results in the base planning conditions starting the first year of the planning
horizon in the next IRP; and
1. Include BESS degradation incremental costs.
in. Justify why the L&RB should include the CBM.
INTERVENER COMMENTS
Micron Technology, Inc. ("Micron") encouraged the Company to continue working with
Micron and other large customers to develop large-scale customer-dedicated generation resources
that meet their mutual sustainability goals. Micron Comments at 3. Micron encouraged the
Company to continually investigate strategies to mitigate energy transition rate impacts and
implement such strategies where appropriate. Id. Finally, Micron encouraged the Company to
continually investigate and analyze regional markets and coordination efforts and seek
opportunities to participate in such programs that result in increased reliability and lower costs to
customers.Id. at 5.
PUBLIC COMMENTS
1. City of Boise City ("City")
The City supported the 2023 IRP's evaluation and selection of additional demand-side
resources. Additionally, the City supported the Company's incorporation of Inflation Reduction
Act incentives,and encouraged the Company to identify and evaluate federal funding opportunities
that may support the implementation of the Company's Near-Term Action Plan.
2. FFP Project 101, LLC ("Goldendale")
Goldendale sought clarification regarding certain methodologies and values as they relate
to the IRP's analysis of pumped storage hydro ("PSH") technology. Goldendale Comments at 1.
Goldendale represented that the IRP does not reference the Investment/Production Tax Credits
ORDER NO. 36233 7

("ITC/PTC") available to PSH, and it was unclear whether the IRP assigns an Effective Load
Carrying Capability("ELCC") value specific to PSH. Id.
Goldendale requested that the Company implement RFPs that have long lead time
resource-specific considerations in order to enable these PSH resources to fairly compete with all
other resource types. Id. at 2. Goldendale represented that to the extent the IRP does not use a
PSH-specific ELCC, the Company should also revise the IRP to do so, and the Company should
identify and procure PSH projects now given the long lead-time of these resources.Id. at 7.
3. KitzWorks LLC ("KitzWorks")
KitzWorks provided comments related to comparisons between Air Source Heat Pumps
("ASHPs") and the other for Ground Source Heat Pumps ("GHPs"). KitzWorks Comments at 1.
KitzWorks noted that the difference in results of the two sensitivity studies may suggest that GHPs
deserve a higher incentive than ASHPs. Id. KitzWorks noted that it could be valuable for the
company to conduct a separate study outside of the IRP process to quantify the benefit of large-
scale deployment of GHPs. Id. at 3. KitzWorks reasoned that assuming that there was a benefit to
ratepayers from GHPs, a proportional incentive could be considered to encourage ratepayers to
adopt GHPs.Id.
4. Zanskar Geothermal & Minerals, Inc. ("Zanskar")
Zanskar recommended that the Company: (1) consider contracted PPA prices, which have
been less than$70/MWh versus $78/MWh LCOE in the IRP; (2)increase geothermal power plant
capacity factor to 95%,to reflect standard industry practice; (3) adjust monthly capacity factors to
reflect that plant overhauls will occur in low-value months; (4) capture all tax benefits for which
geothermal power projects are eligible, including a 30% to 50% ITC, MACRS, and Intangible
Drilling Cost; and (5) incorporate demonstrated cost reductions that are already occurring in the
industry, especially related to drilling. Zanskar Comments at 3. Zanskar also recommended that
the Company conduct an avoided cost analysis of 200MW of new geothermal power over the next
10 years to encourage investment in the exploration and drilling required to define a new
geothermal resource. Id. at 4.
5. Kenneth Winer
Mr. Winer urged the Commission to direct the Company to not invest in more fossil gas
infrastructure and instead invest in 100% renewable energy and storage technologies as the
Company looks to replace its coal power.
ORDER NO. 36233 8

COMPANY REPLY COMMENTS
1. Company's Reply to Staff Comments
a. The Preferred Portfolio
With respect to Staff s analysis of the Preferred Portfolio, the Company identified what it
considered material deficiencies including: (1)no inclusion of the cost of fuel for natural gas fired
plants; (2)no accounting for the cost of a natural gas pipeline expansion associated with additional
gas generation greater than 600 megawatts ("MW"); (3) no reduction in the cost of renewable
resources for the sale of renewable energy credits ("REC"); (4) no offset to the cost of renewable
resources for Production Tax Credits("PTC"); (5)no offset to the cost of battery storage resources
for Investment Tax Credits ("ITC"); (6) no consideration of the time needed to permit and
construct new resources; (7) no accounting for transmission pathways or where energy will come
from; and(8)no accounting for the time value of money. Company Reply Comments at 6.
The Company recognized that more conversations about modeling assumptions would be
of value to both Staff and the Company,and the Company welcomed continued conversations with
Staff and other interested stakeholders to inform future modeling assumptions.Id. at 14. However,
the Company did not believe Staffs recommendation for a supplemental IRP was warranted. Id.
at 24.
The Company indicated it was not opposed to Staff s recommendations for separate filings
for Valmy and Bridger and implementing changes in future IRPs.Id. The Company also indicated
that it would pay particular attention to its discussion of CFs, LCOC, and interconnection costs in
future IRPs, and the Company welcomed further discussions with Staff and other interested
stakeholders to identify opportunities for continued improvement in its planning process. Id.
b. The Near-Term Action Plan
The Company represented that it employed a robust and thorough portfolio analysis that
accounted for foundational elements of resource planning and system reliability. Id. at 25. The
Company stated that it conducted comprehensive verification and validation model runs to support
the identification of the Preferred Portfolio as least-cost and least-risk, and the Company believed
that the Commission should acknowledge the Action Plan items that are derived from the Preferred
Portfolio.Id.
ORDER NO. 36233 9

c. The Load Forecast
The Company represented that it recognized Staff s concern with the load forecast
percentile and LOLE threshold selections used in the 2023 IRP; however,the Company noted that
those decisions were made early on in the IRP development process and were publicly introduced
in the IRPAC meeting on December 8, 2022.Id. at 30. The Company believed that the use of P70
was appropriate and justified but the Company was open to making adjustments and considering
other options for accounting for extreme weather and other reliability risks in future IRPs.Id. The
Company welcomed additional discussions with Staff and other interested parties to find a path
forward.Id. at 32.
The Company noted that a change in load forecast from P70 to P50 created an approximate
1.0 percent change in avoided costs that, in the Company's estimation, did not warrant a concern
or a need to reevaluate rates based on the 2023 IRP and a P70 load forecast.Id. at 33.The Company
agreed that the appropriate venue to have such conversations was within the specific cases where
avoided cost rates are used, and the Company indicated it would seek explicit Commission
approval for any rates that are informed by the IRP prior to implementation. Id.
d. The Demand-Side Management Program
The Company reiterated its position that Staffs assertion, that a portfolio buildout with
more dispatchable resources would be lesser cost than the Preferred Portfolio,was incorrect.Id. at
35.The Company again represented that it did not believe there was a need to create a supplemental
filing to the 2023 IRP and there was no basis to reject the avoided costs generated in the 2023 IRP
based on resource selection. Id.
Further, the Company maintained that its analysis showed that over the entire 20-year
planning horizon, the change in load forecast from P70 to P50 created an approximate 1.0 percent
change in avoided costs and, given the close agreement in the avoided costs produced using the
P70 or P50 load forecast and that both were generated from the same modeling methods, the
Company believed there was sufficient support of either load forecast percentile for calculating
avoided costs. Id. at 36. However, the Company stated that it was open to incorporating Staffs
recommendation to use the P50 load when determining avoided costs in the 2025 IRP or to identify
another method that may not require the Company to plan at a load forecast percentile other than
P50. Id.
ORDER NO. 36233 10

e. The Seasons of Highest Risk
The Company agreed that it should evaluate and justify the selected percentage of total risk
hours threshold utilized to develop the seasons of highest risk in the next IRP, and the Company
believed that would be a valuable improvement to the methodology for future IRPs. Id. at 37.
While the Company believed that the hours of highest risk presented in the 2023 IRP were accurate
and valid for their intended purpose,the Company agreed to Staff s recommendation of providing
an analysis that supports the percentage of total risk hours threshold used to select the hours of
highest risk in the next IRP.Id.
The Company did not agree with Staffs recommendation to include BESS and DR
resources in the analysis, rather the Company suggested that it could work with Staff to evaluate
those assumptions as part of the broader discussions regarding hours of highest risk.Id. at 38.
f. PURPA and other Planning Assumptions
The Company represented that it discussed its PURPA assumptions for the 2023 IRP at
length with IRPAC and provided opportunity for feedback from stakeholders. Id. at 39. The
Company stated that assumptions about new PURPA development are so speculative that they
should remain in a separate scenario and not be included in base planning conditions, so as not to
distort the Company's identified capacity need and resource selections in the IRP process. Id. at
40.
The Company indicated that it would use the most recent data available for this assumption,
as it does for all assumptions, in its next IRP. Id. at 41. The Company also represented that a
planning horizon outside of the Action Plan window allows the Company adequate time to
evaluate and shift to alternative resources, if forecasted PURPA projects do not materialize. Id. at
42-43.
2. Company's Reply to Micron
The Company represented that it was sensitive to the rates and charges paid by its
customers, and that through the IRP process, the Company sought to produce a portfolio of
resources that represents the least-cost, least-risk path to serving its customers' needs over the
planning horizon.Id. at 48.
ORDER NO. 36233 11

3. Company's Reply to Public Comments
a. City of Boise
The Company stated it was eager to convene the IRPAC in the forthcoming development
of the 2025 IRP, and the Company looked forward to continued work and collaboration with the
City of Boise.Id. at 49.
b. FFP Project 101, LLC
The Company appreciated Goldendale's comments and explained that due to pumped
hydro storage's long duration,the Company assumes an approximately 100 percent ELCC for the
resource.Id. the Company agreed with Goldendale's comments regarding the need to issue longer
lead time RFPs. Id.
c. KitzWorks,LLC
The Company stated that it looked forward to continued collaboration with KitzWorks on
future IRP electrification scenario assumptions. Id.
d. Zanskar
The Company represented that it would consider the points listed by Zanskar, and the
Company looked forward to finding ways to refine geothermal assumptions in the next IRP. Id. at
50.
4. Conclusion
The Company requested that the Commission acknowledge the Company's 2023 IRP as
meeting both the procedural and substantive requirements of Order Nos.22299,25260,and 30317;
and reject Staffs specific recommendations regarding an IRP supplement and the Near-Term
Action Plan. Id. at 51-52.
COMMISSION FINDINGS AND DECISION
The Commission has jurisdiction over the Company's Application and the issues in this
case under Title 61 of the Idaho Code including Idaho Code §§ 61-301 through 303. The
Commission is empowered to investigate rates, charges,rules,regulations,practices, and contracts
of all public utilities and to determine whether they are just, reasonable, preferential,
discriminatory, or in violation of any provisions of law, and to fix the same by order. Idaho Code
§§ 61-501 through 503.
ORDER NO. 36233 12

The Commission appreciates the active participation and input of Staff and the intervenors,
and the Commission is confident that their continued work helps the Company develop a better
and more comprehensive IRP.
With respect to Staff s recommendations, the Commission does not believe that a
supplemental filing is necessary at this time; however, the Commission notes the importance of
ensuring that the IRP process uses the most accurate information and that the IRP itself presents
the best representation of the Company's ongoing commitment to serving the needs of its
customers. The Commission directs the Company to meet with Staff, as expeditiously as possible,
to discuss and resolve those concerns enumerated in Staff s comments including model cost inputs,
selection algorithms, and other concerns, prior to the next IRP.
Having reviewed the record, the Commission finds that the Company's 2023 IRP satisfies
the requirements in the Commission's prior orders, and the Commission acknowledges the
Company's 2023 IRP. In doing so, the Commission reiterates that an IRP is a working document
that incorporates many assumptions and projections at a specific point in time. An IRP is a plan,
not a blueprint, and by issuing this Order the Commission merely acknowledges the Company's
ongoing planning process, not the conclusions or results reached through that process.
The Commission does not approve the Company's 2023 IRP, or any resource acquisitions
referenced in it,endorse any particular element in it,opine on the Company's prudence in selecting
the 2023 IRP's preferred portfolio, nor allow or approve any form of cost recovery. The
appropriate place to determine the prudency of the Company's decisions to follow or not follow
the 2023 IRP is in a general rate case or other proceeding where the issue is noticed.
ORDER
IT IS HEREBY ORDERED that the Company's 2023 IRP is acknowledged.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date upon this Order regarding any
matter decided in this Order. Within seven (7) days after any person has petitioned for
reconsideration, any other person may cross-petition for reconsideration. Idaho Code §§ 61-626
and 62-619.
ORDER NO. 36233 13

DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho, this 18t'day of
June 2024.
ERIC ANDERSON, PRESIDENT
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R. HAMMOND JR., COMMISSIONER
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EDWARD LODGE, CO T SSIONER
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Commission Secretary
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ORDER NO. 36233 14