20250515Staff Comments.pdf

RECEIVED
Thursday, May 15, 2025
ERIKA K. MELANSON IDAHO PUBLIC
DEPUTY ATTORNEY GENERAL UTILITIES COMMISSION
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 11560
Street Address for Express Mail:
11331 W CHINDEN BLVD, BLDG 8, SUITE 201-A
BOISE, ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY'S 2024 VARIABLE ENERGY ) CASE NO. IPC-E-25-07
RESOURCE STUDY AND PROPOSED )
UPDATE TO SCHEDULE 87 )
COMMENTS OF THE
COMMISSION STAFF
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission
("Commission"), by and through its Attorney of record, Erika K. Melanson, Deputy Attorney
General, submits the following comments.
BACKGROUND
On February 27, 2024, Idaho Power Company("Company")petitioned the Commission
to modify a compliance requirement in Commission Order No. 36048. Case No. IPC-E-24-08.
The Company requested that the Commission modify the Company's compliance requirement
issued in Case No. IPC-E-23-14 to: (1) authorize the Company to update Schedule 87,
Intermittent Generation Integration Charges ("Schedule 87") integration costs based on the
forthcoming 2024 Variable Energy Resource ("VER") Study, instead of the 2020 VER Study;
STAFF COMMENTS 1 MAY 14, 2025

and(2) authorize the Company to file both the forthcoming 2024 VER Study and updated
Schedule 87 no later than December 31, 2024. Id.
On June 10, 2024, the Commission issued Order No. 36219, granting the Company's
request to modify the compliance requirement in Order No. 36048, and directing the Company to
file both the 2024 VER Study and updated Schedule 87 proposed rates no later than December
31, 2024. Order No. 36219 at 2. On December 31, 2024, the Company submitted a compliance
filing with its 2024 VER Study and Updated Schedule 87 proposed rates. Case No. IPC-24-08.
On February 18, 2025, the Commission issued Order No. 36466 in Case No. IPC-E-24-
08 ordering a new docket be opened to consider the Company's proposed update to Schedule 87
rates. As a result, this case (Case No. IPC-E-25-07) was opened.
STAFF ANALYSIS
Staffs review focused on the overall methodology, capital, and fixed operation and
maintenance ("O&M") cost of incremental resources, the portfolio choice, the lack of an inter-
hour analysis, the regulation reserve requirements, the analysis of on-site generation, the
penetration levels, the portfolio results, the integration charges, the filing time, and the effective
date. Staff recommends that the Commission approve the integration charges contained in
Attachment No. 1 for Schedule 87 with an effective date of June 1, 2025. Staff also recommends
that the Company file an updated Schedule 87 in a compliance filing to reflect the updated
integration charges in Attachment No. 1, if approved.
Before the next VER study, Staff recommends that the Commission order the Company
to work with Staff on the following issues:
• How to determine capital and fixed O&M cost of incremental resources;
• Whether it is reasonable to include an analysis of inter-hour integration costs in the
next study and whether inter-hour integration costs should be incorporated into the
integration charges;
• Whether Regulation Reserve Requirements should be updated;
• How to reconcile differences in wind and solar integration cost for Export Credit
Rates (`ECR");
• How to address the under-allocation issue for the ECR; and
STAFF COMMENTS 2 MAY 14, 2025

• Whether on-site generation can be incorporated in the analysis through developing a
proxy to overcome the issue of data granularity.
For future VER studies, Staff recommends that the Commission order the Company to
file a new VER study within six months after the filing of each Integrated Resource Plan
("IRP"),using the information from the IRP as a starting point but updating it with the latest
information possible. Staff also recommends that, if the Company believes a new VER study is
not necessary, the Commission order the Company to file a waiver for the study with evidence
supporting the Company's position within two months after the filing of the IRP.
Overall Methodology
The 2024 VER Study calculates integration charges by dividing the difference between
ancillary service costs of each scenario (i.e. 100 MW Solar, 200 MW Solar, 100 WM Wind, or
200 MW Wind) and ancillary service costs of the base (i.e. updated Preferred Portfolio
"November 2026 132H Valmy 1&2")by the incremental energy associated for each scenario as
illustrated in Figure No. 1 below. The ancillary service costs of the scenario are determined by
the difference between the scenario portfolio cost with and without ancillaries. The ancillary
service costs of the base are determined by the difference between the base portfolio cost with
and without ancillaries. The overall methodology calculates integration charges caused by
adding an incremental 100 MW of solar nameplate capacity, an incremental 200 MW of solar
nameplate capacity, an incremental 100 MW of wind nameplate capacity, or an incremental 200
MW wind nameplate capacity to the base in Year 2025. The calculation is conducted over the
20-year IRP planning horizon. Staff believes the overall methodology is reasonable.
STAFF COMMENTS 3 MAY 14, 2025

Figure No. 1: Overall Methodology
Integration Portfotio Cost PortfoLio Cost '• remental
Cost With Without Scenario
Energy
� - - � Incremental
Energy
Capital Costs and Fixed O&M of Incremental Resources
Although Staff believes the overall methodology is reasonable, Staff recommends that the
Company work with Staff on how to determine capital and fixed O&M cost of incremental
resources before the next VER study.
When existing ancillary services are not sufficient to integrate growing renewables,
incremental resources will need to be built to provide additional ancillary services. At that point,
capital and fixed O&M cost of incremental resources caused by increasing renewables should be
reflected in the integration charges. However, the Company "found little information on how to
assess unmet ancillary needs and no information on how to correct an unmet ancillary need
should one be found." The 2024 VER Study at 8. Therefore, the Company did not consider
capital and fixed O&M cost of incremental resources in this study, even though it explored a
possible method to be used in future studies. Due to little information on this topic, Staff
believes it is acceptable to not include any capital and fixed O&M cost of incremental resources
in this study and in the proposed Schedule 87 rate. However, Staff recommends that the
Company work with the Staff on how to determine and incorporate capital and fixed O&M cost
of incremental resources before the next VER study.
Portfolio Choice
The 2024 VER Study used the updated Preferred Portfolio titled"November 2026 B2H
Valmy 1 & 2" from the 2023 IRP for the analysis to reflect the timing change of the Boardman
to Hemingway Transmission Line (B214"). Since then, the online date of B2H has changed to
STAFF COMMENTS 4 MAY 14, 2025

year 2028.1 Because the 2024 VER Study is based on the entire IRP planning horizon, Staff
believes the near-term change does not have a significant impact on the study results and on
proposed Schedule 87 rates.
Inter-hour Analysis
Staff recommends the Company work with Staff to determine whether it is reasonable to
include an analysis of inter-hour integration costs in the next VER study and determine whether
inter-hour integration costs should be incorporated into the integration charges. The 2024 VER
is only focused on intra-hour integration costs of regulation reserves for products that occur at 2-
minute, 10-minute and 60-minute time frames. Response to Staff Production Request No. 10.
However, inter-hour integration costs may be incurred when committed resources based on a
forecast of load and renewable generation are not used in real-time, or used but not optimized
due to the difference between the forecasts and the actuals of load and renewable generation.
Regulation Reserve Requirements
The Company used the Regulation Reserve Requirements as shown in Table No. 2 below
to determine the amount of reserve capacity that needs to be held to balance variability of wind,
solar, and load. These amounts were originally developed in the 2021 IRP. Response to Staff
Production Request No. 9 (a). Staff recommends that the Company work with Staff to determine
if such requirements should be updated before the next VER study.
'See"Preliminary Portfolio Results"presented at the Integrated Resource Plan Advisory Council meeting on April
17,2025.
STAFF COMMENTS 5 MAY 14, 2025

Table No. 2. Regulation Reserve Requirements (Page 123 of 2023 IRP)
%of Load %of Load %of Wind %of Wind %of Solar %of Solar
Month Load Up Load Dn Wind Up Wind on Solar Up Solar Dn
1 8.20,6 1.70,6 19.6°b 19.606 51.9% 57.6°A
2 8.306 1.604 15.9°A 21.2°A 32.10A 39.3°A
3 8.306 1.706 21.4036 22.106 59.3°b 59.3°A
4 8.206 1.70A 20.306 26.006 45.90A 50.6°A
5 8.206 1.696 25.4°A 34.506 45.604 53.7°A
6 8.10,6 1.60A 27.40,6 21.706 43.156 29.30.6
7 8.2036 1.496 19.4°h 22.006 36.00,6 24.6°A
8 8.206 1.50A 18.806 23.80A 42.50A 31.9°A
9 8.506 1.80A 29.906 29.90A 42.50.6 40.5°A
10 8.30,6 1.696 21.0°A 31.806 49.2% 51.4°A
11 8.406 1.80A 18.3°A 29.20A 87.806 71.8°A
12 8.106 1.60A 20.5°b 39.306 65.90A 73.3°DA
Inputs to AURORA Model
Calculated Reserve Amounts by Percentage of Corresponding Load/Generation
Analysis of On-site Generation
The Company proposed applying the solar integration costs determined in the 2024 VER
Study to the ECR for on-site generation customers, because the generation profile of on-site
generation is similar to that of utility-scale solar. Although Staff generally agrees with this
treatment, Staff is concerned with several specific issues discussed as follows.
a. On-site Wind Generation
Among the 14,000 non-legacy on-site generation customers who will be subject to annual
ECR updates, there are only two wind on-site generation customers. Responses to Staff
Production Request Nos. 3 (b) and 7 (c). Although the Company proposed to apply solar
integration charges and wind integration charges separately for QFs, it proposed to use solar
integration charges to all on-site generation customers, including the two wind customers.
However, the integration cost between wind and solar are significantly different with solar
integration costs being 8 to 10 times higher than wind. Staff believes that this is a material
difference and should be considered in the ECR.
b. Under-allocation of Integration Costs
STAFF COMMENTS 6 MAY 14, 2025

The Company believes that between utility-scale solar and on-site solar generation,
integration costs are under-allocated to on-site generation customers due to the following
reasons. First, for on-site generation customers, integration costs are incurred based on
generation profiles,but they are recovered based on export profiles. Response to Staff
Production Request No. 7 (b). Second, utility-scale solar typically has axis tracking that reduces
solar variability, whereas on-site solar generation does not. Id. Third,utility-scale solar projects
typically oversize the panel to inverter ratio, which further reduces solar variability. Id. Exports
generally occur more often in high-output, low-load hours, when the need for integrating
resources are greater. Id.
The Company could not conduct a separate integration study specifically for on-site
generation, because the meters installed for retail service have a limitation in the granularity of
interval data. Id. Utility-scale solar meters capture data in 1-minute increments, which is a
required granularity for this type of integration analysis. Id. But on-site generation meters report
data on an hourly basis, which is not granular enough for a separate analysis of exports. Id.
Staff understands the limitation of on-site generation data,but Staff recommends that the
Company work with Staff to address the under-allocation issue before the next study.
Penetration Levels
The 2024 VER Study started with the penetration level of wind and solar QFs and Power
Purchase Agreement("PPA")projects identified in the 2023 IRP, without considering on-site
generation, and then added incremental 100 MWs and 200 MWs of renewables for scenario
analyses.
For wind, the penetration level identified in the 2023 IRP was about 726 MWs, which
included about 625 MWs of QFs and about 101 MWs of PPAs. Response to Staff Production
Request No. 4 (d). Because the penetration level has not changed and because there are only two
wind on-site generation customers, Staff believes that the wind integration charges calculated
based on QFs and PPAs identified in the 2023 IRP are robust.
For solar, the penetration level identified in the 2023 IRP was about 651 MWs, which
included about 391 MWs of QFs and about 260 MWs of PPAs. Response to Staff Production
Request No. 5 (d). However, three projects (i.e. Moore's Hollow Solar, Durkee Solar, and
Prairie City Solar) totaling about 74 MWs failed to come online. Response to Staff Production
STAFF COMMENTS 7 MAY 14, 2025

Request No. 5 (a). Because on-site solar generation and utility-scale solar generation have
similar generation profiles and because there is about 107 MWs of on-site solar generation on the
Company's system (Exhibit No. 1 of Mr. Ellsworth's Direct Testimony in Case No. IPC-E-25-
15), Staff believes that this can make up for the three projects that failed to come online and that
the modeled results to determine integration charges remain reasonable. However, Staff
recommends that the new penetration ranges should be 683.38 MWs to 783.37 MWs for Block 1
and 783.38 MWs to 883.37 MWs for Block 2, where the starting point of 683.38 MWs is
calculated as 650.55 MWs (i.e. the penetration level from the 2023 IRP)minus 74.3 MWs (i.e.
the total nameplate capacity of Moore's Hollow Solar, Durkee Solar, and Prairie City Solar)plus
107.13 MWs (i.e. the total nameplate capacity of on-site generation).
Staff also recommends that the Company work with Staff on whether on-site generation
can be incorporated in the analysis through developing a proxy to overcome the issue of data
granularity before the next study.
Portfolio Results
After the Company ran the Aurora model, the Company calculated average integration
costs in 2024 dollars based on the portfolio data in Table No. 3. However, there is a mismatch
between the cost data and energy data. The cost data is based on a 20-year model run that started
in 2024, whereas the incremental energy is based on a 19-year calculation that started in 2025.
Response to Staff Production Request No. 17.
Table No. 3: Portfolio Cost and Energy Data
Portfolio
Portfolio Cost Cost Differential
Cost with without Relative to
Ancillaries Ancillaries Preferred Portfolio
NPV($x NPV ($x Difference($x Incremental Integration
Portfolio 1,000) 1,000) 1,000) Energy(MWh) Cost$/MWh
Preferred Portfolio $9,678,287 $9,406,427 N/A N/A
100MW Solar $9,677,224 $9,369,718 $35,646 5,116,037 6.97
200MW Solar $9,696,854 $9,330,309 $94,685 10,232,074 9.25
100MW Wind $9,589,833 $9,314,133 $3,840 6,005,227 0.64
200MW Wind $9,505,452 $9,220,324 $13,268 12,010,455 1.10
Because Year 2024 has passed, Staff believes the cost and energy should be aligned
based on 19 years. Table No. 4 shows the new average integration costs in 2024 dollars based on
19 years from 2025 to 2043. Third Supplemental Response to Request No. 17. Staff also
STAFF COMMENTS 8 MAY 14, 2025

updated the non-levelized integration charges accordingly in Attachment No. 1. Staff
recommends that the Commission approve the non-levelized integration charges in Attachment
No. 1 for Schedule 87.
Table No. 4: Updated Results based on 19 Years
20-Year 19-Year
Block Result Result
100MW Solar $6.97 $7.78
200MW Solar $9.25 $10.07
100MW Wind $0.64 $0.95
200MW Wind $1.10 $1.31
Integration Charges for ECR
In Case No. IPC-E-25-15, the Company proposed to use the Block 1 solar integration
costs for 2025 as the integration charge for the ECR, which is $6.97/MWh. Response to Staff
Production Request No. 3 (c). In March 2025, the 200-MW Pleasant Valley Solar project came
online pushing the current solar penetration level into Block 2, indicating that the integration
charge in 2025 should be $10.07/MWh. Because of the issues regarding ECR integration costs
described above, and because there is likely to be another VER study soon after the 2025 IRP is
filed, Staff believes it would be preferable to keep the integration costs in the 2025 ECR annual
update at current levels so that Staff and the Company can reconcile the issues, and use updated
values from the upcoming VER study in next year's ECR annual update. However, treatment of
the cost to be included in the ECR is outside of the scope of this case and should be decided in
Case No. IPC-E-25-15.
Levelized Integration Charges
The Company only proposed levelized integration charges for contracts with a term of 20
years, without considering the possibility that contracts may have terms shorter than 20 years.
Therefore, Staff developed integration charges for contracts ranging from one year to 20 years in
Attachment No. 1, using a discount rate of 7.247%, which was approved for the Company's
Surrogate Avoided Resource Model. Staff recommends that the Commission approve the
levelized integration charges in Attachment No. 1 for Schedule 87.
STAFF COMMENTS 9 MAY 14, 2025

Filing
The Company plans to update its VER study after each IRP,but if the Company believes
a new VER study is not necessary, it will communicate with Staff. Response to Staff Production
Request No. 6 (a). Given the timeline of the 2024 VER Study, which started around July 2024
and concluded in December 2024, Staff recommends that the Company file a new VER study
within six months after the filing of each IRP using the information from the IRP as a starting
point but updating it with the latest information. Staff also recommends that, if the Company
believes a new VER study is not necessary, the Company file a waiver for the study with
evidence supporting the Company's position within two months after the filing of the IRP.
Effective Date
Staff recommends an effective date of June 1, 2025, for the updated Schedule 87.
STAFF RECOMMENDATION
Staff recommends that the Commission approve the integration charges contained in
Attachment No. I for Schedule 87 with an effective date of June 1, 2025. Staff also recommends
that the Company file an updated Schedule 87 in a compliance filing to reflect the updated
integration charges in Attachment No. 1, if approved.
Before the next VER study, Staff recommends that the Commission order the Company
to work with Staff on the following issues:
• How to determine capital and fixed O&M cost of incremental resources;
• Whether it is reasonable to include an analysis of inter-hour integration costs in the
next study and whether inter-hour integration costs should be incorporated into the
integration charges;
• Whether Regulation Reserve Requirements should be updated;
• How to reconcile differences in wind and solar integration cost for the ECR;
• How to address the under-allocation issue for the ECR; and
• Whether on-site generation can be incorporated in the analysis through developing a
proxy to overcome the issue of data granularity.
For future VER studies, Staff recommends that the Commission order the Company to
file a new VER study within six months after the filing of each IRP, using the information from
STAFF COMMENTS 10 MAY 14, 2025

the IRP as a starting point but updating it with the latest information. Staff also recommends
that, if the Company believes a new VER study is not necessary, the Commission order the
Company to file a waiver of the study with evidence supporting the Company's position within
two months after the filing of the IRP.
Respectfully submitted this 14th day of May 2025.
E&JJO,A&�rl�
Erika K. Melanson
Deputy Attorney General
Technical Staff: Yao Yin
I:\Utility\UMISC\COMMENTS\IPC-E-25-07 Comments.docx
STAFF COMMENTS 11 MAY 14, 2025

Attachment No. 1
Wind Integration Charges 725.82-825.81MW 7.247% (Weighted Average Cost of Capital Approved for SAR Model)
Non-Levelized Rates Levelized Rates Online Year
Year $IMWh Contract Length 2025 2026 2027 2028 2029 2030
2025 0.95 1 0.951 0.98 1.00 1.03 1.06 1.08
2026 0.98 2 0.96 0.99 1.02 1.04 1.07 1.10
2027 1.00 3 0.98 1.00 1.03 1.05 1.08 1.11
2028 1.03 4 0.99 1.01 1.04 1.07 1.10 1.12
2029 1.06 5 1.00 1.03 1.05 1.08 1.11 1.14
2030 1.08 6 1.01 1.04 1.06 1.09 1.12 1.15
2031 1.11 7 1.02 1.05 1.08 1.10 1.13 1.16
2032 1.14 8 1.03 1.06 1.09 1.12 1.15 1.18
2033 1.17 9 1.05 1.07 1.10 1.13 1.16 1.19
2034 1.20 10 1.06 1.08 1.11 1.14 1.17 1.20
2035 1.23 11 1.07 1.10 1.12 1.15 1.18 1.21
2036 1.26 12 1.08 1.11 1.13 1.16 1.19 1.23
2037 1.30 13 1.09 1.12 1.15 1.18 1.21 1.24
2038 1.33 14 1.10 1.13 1.16 1.19 1.22 1.25
2039 1.36 15 1.11 1.14 1.17 1.20 1.23 1.26
2040 1.40 16 1.12 1.15 1.18 1.21 1.24 1.27
2041 1.44 17 1.13 1.16 1.19 1.22 1.25 1.28
2042 1.47 18 1.14 1.17 1.20 1.23 1.26 1.30
2043 1.51 19 1.15 1.18 1.21 1.24 1.27 1.31
2044 1.55 20 1.16 1.19 1.22 1.25 1.28 1.32
2045 1.59 21
2046 1.63 22
2047 1.68 23
2048 1.72 24
2049 1.76 25
2050 1.81 26
STAFF COMMENTS 12 MAY 14, 2025

Attachment No. 1
Wind Integration Charges 825.82-925.81MW 7.247% (Weighted Average Cost of Capital Approved for SAR Model)
Non-Levelized Rates Levelized Rates Online Year
Year $IMWh Contract Length 2025 2026 2027 2028 2029 2030
2025 1.31 1 1.31 1.35 1.38 1.42 1.45 1.49
2026 1.35 2 1.33 1.36 1.40 1.44 1.47 1.51
2027 1.38 3 1.35 1.38 1.42 1.45 1.49 1.53
2028 1.42 4 1.36 1.40 1.43 1.47 1.51 1.55
2029 1.45 5 1.38 1.41 1.45 1.49 1.53 1.57
2030 1.49 6 1.39 1.43 1.47 1.50 1.54 1.58
2031 1.53 7 1.41 1.45 1.48 1.52 1.56 1.60
2032 1.57 8 1.42 1.46 1.50 1.54 1.58 1.62
2033 1.61 9 1.44 1.48 1.52 1.56 1.60 1.64
2034 1.65 10 1.46 1.49 1.53 1.57 1.61 1.65
2035 1.70 11 1.47 1.51 1.55 1.59 1.63 1.67
2036 1.74 12 1.49 1.52 1.56 1.60 1.65 1.69
2037 1.79 13 1.50 1.54 1.58 1.62 1.66 1.71
2038 1.83 14 1.51 1.55 1.59 1.64 1.68 1.72
2039 1.88 15 1.53 1.57 1.61 1.65 1.69 1.74
2040 1.93 16 1.54 1.58 1.62 1.67 1.71 1.75
2041 1.98 17 1.56 1.60 1.64 1.68 1.73 1.77
2042 2.03 18 1.57 1.61 1.65 1.70 1.74 1.79
2043 2.08 19 1.58 1.62 1.67 1.71 1.75 1.80
2044 2.14 20 1.60 1.64 1.68 1.72 1.77 1.82
2045 2.19 21
2046 2.25 22
2047 2.31 23
2048 2.37 24
2049 2.43 25
2050 2.49 26
STAFF COMMENTS 13 MAY 14, 2025

Attachment No. 1
Solar Integration Charges 683.38-783.37MW 7.247% (Weighted Average Cost of Capital Approved for SAR Wdel)
Non-Levelized Rates Levelized Rates Online Year
Year $IMWh Contract Length 2025 2026 2027 2028 2029 2030
2025 7.78 1 7.78 7.98 8.19 8.40 8.62 8.84
2026 7.98 2 7.88 8.08 8.29 8.51 8.73 8.96
2027 8.19 3 7.97 8.18 8.39 8.61 8.84 9.07
2028 8.40 4 8.07 8.28 8.49 8.72 8.94 9.17
2029 8.62 5 8.17 8.38 8.60 8.82 9.05 9.28
2030 8.84 6 8.26 8.47 8.69 8.92 9.15 9.39
2031 9.07 7 8.35 8.57 8.79 9.02 9.26 9.50
2032 9.31 8 8.45 8.66 8.89 9.12 9.36 9.60
2033 9.55 9 8.54 8.76 8.99 9.22 9.46 9.71
2034 9.80 10 8.63 8.85 9.08 9.32 9.56 9.81
2035 10.06 11 8.72 8.94 9.18 9.41 9.66 9.91
2036 10.32 12 8.80 9.03 9.27 9.51 9.76 10.01
2037 10.59 13 8.89 9.12 9.36 9.60 9.85 10.11
2038 10.86 14 8.98 9.21 9.45 9.70 9.95 10.21
2039 11.14 15 9.06 9.30 9.54 9.79 10.04 10.30
2040 11.43 16 9.15 9.38 9.63 9.88 10.13 10.40
2041 11.73 17 9.23 9.47 9.71 9.97 10.23 10.49
2042 12.03 18 9.31 9.55 9.80 10.05 10.31 10.58
2043 12.35 19 9.39 9.63 9.88 10.14 10.40 10.67
2044 12.67 20 9.47 9.71 9.96 10.22 10.49 10.76
2045 13.00 21
2046 13.34 22
2047 13.68 23
2048 14.04 24
2049 14.40 25
2050 1 14.78 26
STAFF COMMENTS 14 MAY 14, 2025

Attachment No. 1
Solar Integration Charges 783.38-883.37MW 7.247% (Weighted Average Cost of Capital Approved for SAR Model)
Non-Levelized Rates Levelized Rates Online Year
Year $IMWh Contract Length 2025 2026 2027 2028 2029 2030
2025 10.07 1 10.07 10.33 10.60 10.88 11.16 11.45
2026 10.33 2 10.20 10.46 10.74 11.01 11.30 11.59
2027 10.60 3 10.32 10.59 10.87 11.15 11.44 11.74
2028 10.88 4 10.45 10.72 11.00 11.28 11.58 11.88
2029 11.16 5 10.57 10.85 11.13 11.42 11.71 12.02
2030 11.45 6 10.69 10.97 11.26 11.55 11.85 12.16
2031 11.75 7 10.81 11.10 11.38 11.68 11.98 12.30
2032 12.05 8 10.93 11.22 11.51 11.81 12.12 12.43
2033 12.37 9 11.05 11.34 11.63 11.94 12.25 12.57
2034 12.69 10 11.17 11.46 11.76 12.06 12.38 12.70
2035 13.02 11 11.29 11.58 11.88 12.19 12.51 12.83
2036 13.36 12 11.40 11.70 12.00 12.31 12.63 12.96
2037 13.70 13 11.51 11.81 12.12 12.43 12.76 13.09
2038 14.06 14 11.62 11.93 12.24 12.55 12.88 13.21
2039 14.43 15 11.73 12.04 12.35 12.67 13.00 13.34
2040 14.80 16 11.84 12.15 12.46 12.79 13.12 13.46
2041 15.19 17 11.95 12.26 12.58 12.90 13.24 13.58
2042 15.58 18 12.05 12.36 12.69 13.02 13.35 13.70
2043 15.99 19 12.15 12.47 12.79 13.13 13.47 13.82
2044 16.40 20 12.25 12.57 12.90 13.24 13.58 13.93
2045 16.83 21
2046 17.27 22
2047 17.71 23
2048 18.18 24
2049 18.65 25
2050 19.13 26
STAFF COMMENTS 15 MAY 14, 2025

CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS I DAY OF MAY 2025, SERVED THE
FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE NO. IPC-E-25-07,
BY E-MAILING A COPY THEREOF TO THE FOLLOWING:
DONOVAN E. WALKER ALISON WILLIAMS
IDAHO POWER COMPANY IDAHO POWER COMPANY
PO BOX 70 PO BOX 70
BOISE ID 83707-0070 BOISE ID 83707-0070
E-MAIL: dwalkergidahopower.com E-MAIL: awilliams cr�idahopower.com
dockets c idahopower.com
PATRICIA JORDAN, S CRETARY
CERTIFICATE OF SERVICE