20251226Application.pdf

0IQAHO POWER.
RECEIVED
DONOVAN WALKER DECEMBER 26, 2025
Lead Counsel IDAHO PUBLIC
dwalkerCa-idahopower.com UTILITIES COMMISSION
December 26, 2026
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. I PC-E-25-36
In the Matter of Idaho Power Company's 2025 Variable Energy Resource
Integration Study and Proposed Update to Schedule 87
Dear Commission Secretary:
Attached for electronic filing is Idaho Power Company's Application in the above
matter.
If you have any questions about any of the aforementioned documents, please do
not hesitate to contact me.
Very truly yours,
Donovan E. Walker
DEW:sg
Enclosures
1221 W. Idaho St(83702)
P.O. Box 70
Boise, ID 83707

DONOVAN E. WALKER (ISB No. 5921)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
dwalker(a-)_idahopower.com
Attorney for Idaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY'S 2025 VARIABLE ENERGY ) CASE NO. IPC-E-25-36
RESOURCE INTEGRATION STUDY AND )
PROPOSED UPDATE TO SCHEDULE 87 ) APPLICATION
Idaho Power Company ("Idaho Power" or "Company"), in accordance with Idaho
Code §§ 61-502 and 61-503, Idaho Public Utilities Commission's ("Commission") Rule of
Procedure' 52, and Order No. 36661, hereby respectfully makes application to the
Commission for an order approving Idaho Power's proposed Schedule 87, Intermittent
Generation Integration Charges ("Schedule 87"), updated rates, effective February 1,
2026, for which the Company's 2025 Variable Energy Resource ("VER") Integration Study
("2025 VER Study") is the basis of, and acknowledging the Company complied with the
Commission's directives within Order No. 36661.
In support of this Application, Idaho Power represents as follows:
Hereinafter citied as RP.
APPLICATION - 1

I. BACKGROUND
1. On December 31, 2024, the Company filed a compliance filing in
accordance with Order No. 36219,2 which required the Company to file an updated VIER
study and updated Schedule 87 proposed rates on or before such date. Accordingly, this
compliance filing submitted by the Company contained the Company's 2024 VIER
Integration Study ("2024 VIER Study") and updated Schedule 87 rates.
2. On February 4, 2025, Commission Staff ("Staff') issued a decision
memorandum recommending that the Commission open a new docket for this matter
because, among other things, the proposed rates in Schedule 87 affect all future Public
Utility Regulatory Policies Act of 1978 ("PURPA") rates in new and replacement3 PURPA
contracts.4 Through Order No. 36466, the Commission found it appropriate to open a new
docket for this matter,5 thereby establishing Case No. IPC-E-25-07.
3. Following Staff's review of Case No. IPC-E-25-07, Staff recommended
within their comments that the Commission order the Company to work with Staff on the
following issues before its next VIER Study:
a) How to determine capital and fixed Operations and Maintenance ("O&M") costs of
incremental resources;
b) 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
integration charges;
2 In the Matter of Idaho Power Company's Petition to Modify a Compliance Requirement Related to
Updating Schedule 87, Case No. IPC-E-24-08, Idaho Power Compliance Filing (Dec. 31, 2024).
3 While Staff uses the term "renewal," Idaho Power 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.
4 IPC-E-24-08, Staff Decision Memorandum at 1-2 (Feb. 4, 2025).
5 Id., Order No. 36466 at 2 (Feb. 18, 2025).
APPLICATION - 2

c) Whether Regulation Reserve Requirements should be updated;
d) How to reconcile differences in wind and solar integration cost for the Export Credit
Rates ("ECR");
e) How to address the under-allocation issue for the ECR; and
f) Whether on-site generation can be incorporated in the analysis through developing
a proxy to overcome the issue of data granularity.6
4. Additionally, Staff noted within their comments that the Company's proposal
only levelized integration charges for contracts with a term of 20 years and did not
consider the possibility that contracts may have terms shorter than 20 years.? As such,
Staff developed integration charges for contracts ranging from one year to 20 years and
included such charges within Attachment No. 1 to their comments, recommending that
the Commission approve this approach instead. Furthermore, Staff recommended that
for future VER studies, the Commission order the Company to file a new VER study within
six months after the filing of each Integrated Resource Plan ("IRP"), unless the Company
believes a new VER study is not necessary, in which case the Company should file for a
waiver of the study with evidence supporting such position within two months after filing
the IRP.B
5. In its reply comments, the Company agreed to work with Staff before its
next VER study on the issues stated above, as well as agreeing with Staff's recommended
cadence for updating its VER study and the process of requesting a waiver.9 Additionally,
6 In the Matter of Idaho Power Company's 2024 Variable Energy Resource Study and Proposed Update to
Schedule 87, Case No. IPC-E-25-07, Staff Comments at 10 (May 14, 2025).
Id., at 9.
8 Id., at 10-11.
9 Id., Idaho Power Reply Comments at 3 (May 21, 2025).
APPLICATION - 3

the Company found Staff's proposed integration charges contained in Attachment No. 1
to their comments to be reasonable.
6. Through Order No. 36661, the Commission directed the Company to work
with Staff prior to the next VER study to attempt to resolve the issues citied in Staff's
comments and to file a new VER study within six months after the filing of each IRP,
unless the Company believes a new VER study is unnecessary, in which case the
Company shall file for a waiver within two months after the filing of the IRP. Further, the
Commission approved Schedule 87 with Staff's proposed modifications.10
II. STAKEHOLDER ENGAGEMENT
7. The Company met with Staff on June 23, 2025, and July 2, 2025, prior to
developing its 2025 VER Study to resolve the issues citied above. The Company
incorporated Staff's feedback, and the Company and Staff largely aligned on the
methodology to be used as part of the 2025 VER Study, such as relying on the 2025 IRP's
preferred portfolio. The following summarizes the resolutions to the issues raised by Staff
in Case No. IPC-E-25-07:
a) How to determine capital and fixed O&M cost of incremental resources
In the 2025 VER Integration Study update, the Company applied a methodology
to account for the capital and fixed O&M cost of incremental resources. A detailed
discussion of the methodology and the outcome of its application can be found in
the Inclusion of Incremental Resource Capital Costs section of the 2025 VER
Integration Study.
10 Id., Order No. 36661 at 4 (Jul. 1, 2025).
APPLICATION - 4

b) 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
The Company and Staff aligned that the cost of integration resulting from dispatch
changes that resolve over periods longer than an hour should be included in the
study. As a point of clarity, these costs were included in the 2024 VER Integration
Study and they are again included in this study as the Aurora model used in the
analysis already accounts for dispatch decisions that resolve over multiple hours
and how VERs can change these decisions.
c) Whether Regulation Reserve Requirements should be updated
For the 2025 VER Integration Study, reserve amounts and the accounting for
which resources can provide those reserves and to what amount was reviewed
and updated.
d) How to reconcile differences in wind and solar integration cost for Export
Credit Rates ("ECR")
The resolution of separate solar and wind integration cost was resolved in that
there is not a need to bifurcate the ECR by technology type. There are effectively
no wind ECR customers for which a bifurcated rate would apply. Additionally,
Staff's comments in IPC-E-23-14 remain relevant in that, "[m]ultiple ECR's would
reduce transparency, increase confusion, and could lead to dissatisfaction among
customers".,'
" In the Matter of Idaho Power Company's Application for Authority to Implement Changes to the
Compensation Structure Applicable to Customer On-Site Generation Under Schedules 6, 8, and 84 and to
Establish an Export Credit Rate, Case No. IPC-E-23-14, Reply Comments of the Commission Staff at 3
(Nov. 2, 2023).
APPLICATION - 5

e) How to address the under-allocation issue for the ECR
The usage of the integration charges should remain consistent with Order No.
36048 which established the ECR methodology, unless changed in a future ECR
case, and is not an element of the integration study.
f) Whether on-site generation can be incorporated in the analysis through
developing a proxy to overcome the issue of data granularity.
Because the metering equipment installed at on-site generation customer sites
does not provide data with sufficient scope or granularity, the current method
remains the best option available.
8. The Company met with Staff and Clean Energy Opportunities for Idaho
("CEO") on December 3, 2025, to discuss the results of the 2025 VER Study. Staff and
CEO were generally supportive of the results of the 2025 VER Study and provided
additional feedback to the Company that it will take into consideration when it begins to
develop the next iteration of the VER Study in 2027.
III. 2025 VER STUDY
9. Idaho Power developed the 2025 VER Study by largely leveraging the
methodology of the 2024 VER Study, with the additions and changes aligned on with
Staff, as previously discussed. The 2024 VER Study's methodology was developed with
the expertise of a Technical Review Committee ("TRC"), which provided feedback
throughout the study process. The TRC, which included representatives from Staff,
National Renewable Energy Laboratory, University of Idaho, Idaho National Laboratory,
and Staff of Public Utility Commission of Oregon, reviewed and aligned on the
methodology for the 2024 VER Study. The methodology and the results of the 2025 VER
APPLICATION - 6

Study are described below and the 2025 VER Study is included as Attachment 1 to this
Application.
10. The 2025 VER Study leverages the preferred portfolio and the regulation
reserve requirements in the Company's most recently filed long-term planning effort,
the 2025 IRP. To be consistent with its IRP modeling process, Idaho Power used
Energy Exemplar's Aurora model for the VER study process.
11. Through the use of Aurora, the Company is able to quantify the cost of VER
integration by modeling the regulating reserves required to reliably deliver power to an
electric system with non-dispatchable generation. Specifically, the Aurora model
quantifies this cost with ancillary services in the form of "up regulation" and "down
regulation" products. For a resource to provide an up-regulating reserve, it needs to be
able to respond by increasing its output to match a decrease in generation of the VER
resource. Effectively, the resource needs to be online and be in a state to respond. For
most resources this means that instead of outputting a megawatt-hour, they are instead
held back such that additional capacity could be deployed.
12. To precisely identify the cost of integrating additional VER (specifically,
solar and wind), Idaho Power developed use cases that isolate the impact of adding
incremental VER generation. The Company selected four use cases in total — a 100
megawatt ("MW") and a 200 MW incremental addition of solar and a 100 MW and a 200
MW incremental addition of wind. The use of 100 MW block sizes was selected with input
from the TRC in 2024. For the current study, 100 MW block sizes were again selected
based on anticipated solar and wind generation and input from Staff.
APPLICATION - 7

13. These four use cases were then ran through the Aurora model with each of
the respective resource additions added to the base portfolio-the preferred portfolio from
the 2025 IRP12-in the year 2025 as must-take resources to reflect the must-take obligation
of PURPA qualifying facility projects. For each of the use case portfolios, the Company
conducted additional analysis in Aurora with no ancillary services calculations. Integration
costs were then calculated using the relative change between the base case with and
without the ancillary services calculations compared to the same cases with the
incremental resources. This analysis yielded the following results for the respective use
case:
Cost Differential
Portfolio Cost Portfolio Relative to
with Cost without Base Portfolio Incremental Integration
Ancillaries Ancillaries Difference Energy Cost
Portfolio $ x 1,000 $ x 1,000 $ x 1,000) (MWh) ($/MWh
Base Portfolio $19,806,678 $19,742,879 N/A N/A
100MW Solar $19,646,864 $19,576,261 $6,803 4,319,419 1.58
200MW Solar $19,494,416 $19,402,233 $28,384 8,638,835 3.29
100MW Wind $19,569,393 $19,498,788 $6,805 5,190,877 1.31
200MW Wind $19,344,360 $19,264,738 $15,823 10,381,756 1.52
IV. SCHEDULE 87
14. The Company has included its proposed updated Schedule 87 rates as
Attachment 2 to this Application in both clean and legislative format. Schedule 87 includes
integration charges for up to 200 MW of incremental wind and up to 200 MW of
incremental solar, which were determined to be reasonable amounts based upon
consultation with the TRC in 2024 and in recognition that the Company intends to update
its VER study and the associated integration charges after each IRP is filed, unless a
12 The base portfolio is the portfolio titled "With 111(d) Bridger 3&4 NG"from the 2025 IRP.
APPLICATION - 8

waiver is sought because the Company believes an updated VER study is unnecessary.
This updated VER study cadence will allow for a timely refresh of the cost of integration
and consideration of the actual penetration level on Idaho Power's system, thereby being
reflective of the fast-changing, dynamic resource and growth environment in which the
Company currently operates.
V. MODIFIED PROCEDURE
15. Idaho Power believes that a technical hearing is not necessary to consider
the issues presented herein and respectfully requests that this Application be processed
under Modified Procedure, i.e., by written submissions rather than by hearing. RP 201,
et. seq. However, the Company stands ready to present testimony supporting the
Application in a technical hearing if the Commission determines such a hearing is
required.
VI. COMMUNICATIONS AND SERVICE OF PLEADINGS
16. Communications and service of pleadings with reference to this Application
should be sent to the following:
Donovan Walker Timothy E. Tatum
Regulatory Dockets Riley Maloney
Idaho Power Company Mary Alice Taylor
1221 West Idaho Street (83702) Idaho Power Company
P.O. Box 70 1221 West Idaho Street (83702)
Boise, Idaho 83707 P.O. Box 70
dwalker(a-idahopower.com Boise, Idaho 83707
docketsCa-idahopower.com ttatumCa-idahopower.com
rmaloney(@Jdahopower.com
mtaylor(a_idahopower.com
APPLICATION - 9

VII. CONCLUSION
17. As described in greater detail above, Idaho Power respectfully requests that
the Commission issue an order: (1) approving the proposed updated Schedule 87 rates
effective February 1, 2026, for which Idaho Power's 2025 VER Study is the basis of, and
(2) acknowledging the Company complied with the Commission's directives within Order
No. 36661.
Respectfully submitted this 26th day of December 2025.
DONOVAN E. WALKER
Attorney for Idaho Power Company
APPLICATION - 10

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-36
IDAHO POWER COMPANY
ATTACHMENT NO. 1
2025 VER STUDY

4N al POWER.
2025 VER Integration
Cost Study
December 2025
© 2025 Idaho Power

Idaho Power Company 2025 VER Integration Study
Table of Contents
Tableof Contents..............................................................................................................................i
Acknowledgements......................................................................................................................... 1
Glossaryof Acronyms ..................................................................................................................... 2
ExecutiveSummary......................................................................................................................... 3
RegulatoryHistory .......................................................................................................................... 4
PriorStudy................................................................................................................................. 4
On-Site Generation and the Export Credit Rate....................................................................... 5
Future Cadence of Updates ............................................................................................................ 6
Study Integration and Process Flow ......................................................................................... 6
Methodology................................................................................................................................... 7
ModelBasis............................................................................................................................... 7
Ancillary Service Requirements and Reserves.......................................................................... 8
Incremental Resource Study Cases........................................................................................... 9
IntegrationBlock Size.......................................................................................................... 9
VERGroups ......................................................................................................................... 9
Inclusion of Incremental Resource Capital Costs.................................................................... 10
Metric and Threshold Evaluation...................................................................................... 10
Corrective Measure .......................................................................................................... 11
Determination of the Integration Cost................................................................................... 13
Results........................................................................................................................................... 14
Page i

Idaho Power 2025 VER Integration Study
Acknowledgements
Idaho Power would like to thank the members of the Technical Review Committee whose
expertise aided the development of the 2024 VER Integration Study, which was relied on as a
foundation for the 2025 VER Study.
Name Organization
Wesley Cole, Ph.D. National Renewable Energy Laboratory(NREL)
Brian Johnson, Ph.D., P.E. University of Idaho
Kurt Myers Idaho National Laboratory(INL)
Mike Louis, Matt Suess,Yao Yin Idaho Public Utilities Commission (IPUC)
Kim Herb, Ryan Bain, Ryan Kern Public Utility Commission of Oregon (OPUC)
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Idaho Power 2025 VER Integration Study
Glossary of Acronyms
BESS—Battery Energy Storage System
ECR—Export Credit Rate
EUA—Expected Unserved Ancillaries
EUE—Expected Unserved Energy
IPUC—Idaho Public Utilities Commission
IRP—Integrated Resource Plan
k—indicates a multiple of 1,000
MW—Megawatt
MWh—Megawatt-hour
O&M—Operations and Maintenance
OPUC—Public Utility Commission of Oregon
QF—Qualifying Facility
Recip—Reciprocating Engine
Staff—IPUC Staff
TRC—Technical Review Committee
VER—Variable Energy Resource
Page 2

Idaho Power 2025 VER Integration Study
Executive Summary
Idaho Power Company's (Idaho Power or Company) 2025 Variable Energy Resource (VER)
Integration Cost Study (2025 VER Integration Study) contains the Company's updated
integration costs and details the methodology by which they were produced. This is the same
methodology used in the prior study (the 2024 VER Integration Study) but based on the
updated 20251ntegroted Resource Plan (IRP). See the Methodology section for more details.
The Company assembled and leveraged the expertise of a Technical Review Committee (TRC) to
provide feedback throughout the 2024 VER Integration Study process and to provide expertise
on inputs for the 2025 IRP, which are being used in this study. The TRC met on September 19,
2024, to discuss the methodology of the 2024 VER Study and on October 17, 2024, to discuss
the preliminary results of the 2024 VER Study. See the Acknowledgements section for a list of
the members and organizations represented on the TRC. For this study, the TRC was also
instrumental in developing the methods used to determine the reserve requirements that were
used within the 2025 IRP model, as well as aligning upon the use of other methodologies that
continue to be employed.
The methodology proposed and implemented in this report leverages the base portfolio and
the regulation reserve requirements utilized in the 2025 IRP. The 2025 IRP is under review by
the Idaho Public Utilities Commission (IPUC)1 and was recently acknowledged by the Public
Utility Commission of Oregon (OPUC).Z The 2025 VER Integration Study is filed in accordance
with the timeline contemplated by IPUC Order No. 36661,3 which directed Idaho Power to file a
new VER study within six months after the filing of each IRP.4
Idaho Power's updated integration costs are in the last column of the following table:
Portfolio Cost Portfolio Cost Cost Differential Relative
with Ancillaries without Ancillaries to Base Portfolio Incremental Integration Cost
Portfolio ($x 1,000) ($x 1,000) Difference($x 1,000) Energy(MWh) ($/MWh)
Base Portfolio $19,806,678 $19,742,879 N/A N/A
100 MW Solar $19,646,864 $19,576,261 $6,803 4,319,419 1.58
200 MW Solar $19,494,416 $19,402,233 $28,384 8,638,835 3.29
100 MW Wind $19,569,393 $19,498,788 $6,805 5,190,877 1.31
200 MW Wind $19,344,360 $19,264,738 $15,823 10,381,756 1.52
1 See IPC-E-25-23.
2 See LC 87,Order No. 25-503 issued December 09, 2025.
3 In Order No. 36661 the IPUC directed Idaho Power to file a new VER study within six months after the filing of
each IRP.
4 The IPUC also provided that in the alternative, "should the Company believe that a new VER study is unnecessary,
the Company shall file for a waiver of the VER study with evidence supporting the Company's position within two
months after the filing of the IRP."Order No. 36661 at 4.
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Idaho Power 2025 VER Integration Study
Regulatory History
Idaho Power has historically used VER integration studies as the basis for developing the
Company's integration charges, specifically Schedule 87—Intermittent Generation Integration
Charges (Schedule 87) in Idaho. In Oregon, integration charges are addressed within
Schedule 85—Cogeneration and Small Power Production Standard Contract Rates, which Idaho
Power files with the OPUC.
Prior Study
The Company's last VER integration study was published in 2024 (2024 VER Integration Study)
and was filed in Case No. IPC-E-25-07 for IPUC review alongside proposed updates to
Schedule 87. Within Order No. 36661 in Case No. IPC-E-25-07, the IPUC approved updates to
Schedule 87, for which the 2024 VER Integration Study was the basis of, as well as finding:
1) that the Company shall file a new VER study within six months after the filing of each IRP
(unless the Company files a waiver from this requirement on the belief that the update is
unnecessary with supporting evidence), and 2) the Company shall work with IPUC Staff (Staff)
prior to the next VER study and attempt to resolve issues cited in Staff's comments in Case No.
IPC-E-25-07.
As it relates to the necessity of this update, the Company believes it is necessary to update the
VER integration study based on the 2025 IRP. The primary drivers are that the 2025 IRP process
selected a preferred portfolio with substantially different resources than the 2023 IRP and,
as part of the 2025 IRP, the Company revised the regulation reserve requirements after
consultation with the TRC in 2024.
The Company also consulted with Staff to work through the following issues:
1. How to determine capital and fixed operations and maintenance (0&M) cost of
incremental resources;
2. 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;
3. Whether Regulation Reserve Requirements should be updated;
4. How to reconcile differences in wind and solar integration cost for Export Credit Rates
("E C R");
5. How to address the under-allocation issue for the ECR; and
6. Whether on-site generation can be incorporated in the analysis through developing a
proxy to overcome the issue of data granularity.
In addition to the meetings Staff attended as part of the TRC in 2024, the Company met with
Staff on June 23, 2025, and July 2, 2025, to work through these issues.The Company
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Idaho Power 2025 VER Integration Study
appreciates Staff's continued collaboration and believes the identified issues have been
sufficiently addressed for this VER study. Below is a summary of the resolution to each issue:
1. In the 2025 VER Integration Study update, the Company applied a methodology to
account for the capital and fixed 0&M cost of incremental resources. A detailed
discussion of the methodology and the outcome of its application can be found in the
Inclusion of Incremental Resource Capital Costs section of this report.
2. The Company and Staff aligned that the cost of integration resulting from dispatch
changes that resolve over periods longer than an hour should be included in the study.
As a point of clarity, these costs were included in the 2024 VER Integration Study and
they are again included in this study as the Aurora model used in the analysis already
accounts for dispatch decisions that resolve over multiple hours and how VERs can
change these decisions.
3. For the 2025 VER integration study, reserve amounts and the accounting for which
resources can provide those reserves and to what amount was reviewed and updated.
4. The resolution of separate solar and wind integration costs was resolved in that there is
not a need to bifurcate the ECR by technology type. There are effectively no wind ECR
customers for which a bifurcated rate would apply. Additionally, Staff's comments in
Case No. IPC-E-23-14 remain relevant: "[m]ultiple ECRs would reduce transparency,
increase confusion, and could lead to dissatisfaction among customers".5
5. The usage of the integration charges should remain consistent with Order No. 36048 in
Case No. IPC-E-23-14, which established the ECR methodology, unless changed in a
future ECR case, and is not an element of the integration study.
6. Because the metering equipment installed at on-site generation customer sites does not
provide data with sufficient scope or granularity, the current method remains the best
option available.
Additionally, the Company and Staff agreed that the 2025 IRP Preferred Portfolio would be the
best base portfolio for this analysis.
On-Site Generation and the Export Credit Rate
The Company uses the results from the VER integration study as one of the components of the
ECR for on-site generation customers. The ECR is the rate paid to retail customers with on-site
generation taking service under net billing. Customer on-site generation, most typically from
solar generation, is a VER, meaning it does not provide firm or dispatchable energy to the
Company's system; therefore, there are costs associated with accommodating the uncertainty
associated with these resources. Idaho Power incurs integration costs due to reduced flexible
resource optimization, caused by VER uncertainty, when planning operations ahead of real
time. The ECR reflects the total costs and benefits of on-site generator customers' exports on
S Case No. IPC-E-23-14, Reply Comments of IPUC Staff at 3 (Nov. 2, 2023).
Page 5

Idaho Power 2025 VER Integration Study
the Company's system, including VER integration costs which will come from the most recent
VER Integration Cost Study.
While the VER integration study determined the cost of accommodating additional utility scale
solar, the Company found that a utility scale generation profile is a reasonable proxy for the
shape of on-site solar generation exports when considered as a whole. As such, the Company
assesses that the integration costs identified in this report are an appropriate input to the ECR
without modification.
Future Cadence of Updates
This study marks the second time that the Company has leveraged its most recent IRP to
perform the VER integration study. Historically, Idaho Power has filed VER integration studies as
one-off studies, each of which had a distinct and largely incomparable methodology and scope.
Moving forward, the Company intends to file a new VER study within six months after the filing
of each IRP, unless the Company files a waiver from this requirement with the IPUC on the
belief that the update is unnecessary with supporting evidence.
Relying on the most recently filed IRP allows for a simpler process as the extensive work done
to develop the IRP can be fully leveraged and it also aids in the scrutiny of this study as the IRP
is a familiar framework to many parties. The process has proven to be easily replicable, for this
update little changed between the 2024 VER Integration Study and the 2025 VER Integration
Study, other than utilizing the 2025 IRP model and the results it generates. As such, the
Company believes the framework developed in the 2024 VER Integration Study remains
workable and that no major revisions were required for the 2025 VER Integration Study.
Study Integration and Process Flow
Idaho Power has continued to use the two-part IRP to VER integration study process used in the
2024 VER Integration Study. To merge these processes and minimize duplicative work, the
determination of regulating reserve requirements are separated from the generation of VER
integration costs. Reserve requirements were determined as part of the standard process to
update IRP inputs. The normal IRP modeling process followed, determining the Preferred
Portfolio. With the IRP filed, the VER integration study commences in a structured and
methodological manner using the same model as the IRP. An overview diagram of the process is
outlined in the figure below, with the timing and order of actions moving from left to right:
Page 6

Idaho Power 2025 VER Integration Study
Data Long-Term portfolio VER Cost Study
Inputs Capacity Analysis IRP Filing Integration Filing
Expansion Cost Study
Costs Assessment ` ■
Generation of File Integration
Charge Update
Creation of Study Cases
Reserve F Determination
Compliant and
Portfolios for Risk Assessment Acknowledgment
Scenario and of the Preferred
Sensitivity Portfolio pm
Analysis Calculation of Update
All Other IRP Dependencies
Inputs and Additional
Assumptions Outputs
■
The figure above provides a graphical representation of the process with highlighted areas
showing where the VER integration cost study and development exist. Starting with Data
Inputs, the determination of reserve requirements and the resources that can provide those
reserves is part of the standard inputs gathered in an IRP. Those Data Inputs are used in Long-
Term Capacity Expansion and Portfolio Analysis in the IRP, which is consistent with the current
IRP process. Once the IRP is filed, the VER integration study commenced. Study cases were
determined and the VER integration costs are calculated using the IRP model with the results
filed in an update to the current charges.
Methodology
For this study, Idaho Power has continued to use the methodology from the 2024 VER
Integration Study for calculating VER integration charges, which are stated within Schedule 87.
The Company believes the study methodology adheres to the following goals:
• Leverage existing models to the extent possible,
• Use an evergreen process that is simple to update and is largely methodological, and,
based on the above,
• Transparent and easy to review.
No material deficiencies in the methodology relied upon for the 2024 VER Integration Study
were identified through the Commission review process undertaken in Case No. IPC-E-25-07,
therefore the Company did not change the process for this study outside of the procedural
input updates.
Model Basis
Where possible, this integration study has used the 2025 IRP model. While the Company has
not identified material changes that would warrant relying on a different basis than the 2025
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Idaho Power 2025 VER Integration Study
IRP model, through IPUC Staff's review of the 2025 IRP, it was discovered that the ramping
reserve requirements shown in Appendix D of the published 2025 IRP contained a presentment
error in that the table's values did not include the portfolio benefit that were included as part
of the IRP's analysis. The following table corrects for this presentment error and shows the
ramping reserve requirement values, which reflect the portfolio benefit, used within both this
integration study and the 2025 IRP.
%of Load %of Wind %of Solar
Spin Non-Spin Wind Reg Wind Ramp Solar Reg Solar Ramp
Month (10 min) (60 min) (2 min) (60 min) (2 min) (60 min)
January 3.0% 3.0% 10.7% 29.1% 18.9% 32.3%
February 3.0% 3.0% 10.7% 34.5% 18.9% 33.4%
March 3.0% 3.0% 10.7% 35.2% 18.9% 30.6%
April 3.0% 3.0% 10.7% 36.1% 18.9% 26.5%
May 3.0% 3.0% 10.7% 42.6% 18.9% 25.3%
June 3.0% 3.0% 10.7% 37.1% 18.9% 20.7%
July 3.0% 3.0% 10.7% 39.8% 18.9% 16.7%
August 3.0% 3.0% 10.7% 40.7% 18.9% 21.3%
September 3.0% 3.0% 10.7% 41.3% 18.9% 24.4%
October 3.0% 3.0% 10.7% 37.0% 18.9% 29.0%
November 3.0% 3.0% 10.7% 39.1% 18.9% 33.1%
December 3.0% 3.0% 10.7% 35.1% 18.9% 35.1%
Ancillary Service Requirements and Reserves
To be consistent with the 2025 IRP analysis, Idaho Power is leveraging Energy Exemplar's
Aurora software, the same tool that has been used for numerous prior plans. Idaho Power has a
long history using the Aurora electric market model as its primary tool for modeling resource
operations and determining operating costs among many other uses. Aurora is an economic
model that optimizes the dispatch of generation and transmission resources to match demand.
The operation of existing and future resources is based on forecasts of important drivers,
including but not limited to, demand, fuel prices, hydroelectric conditions, and operational
resource characteristics.
Aurora quantifies the cost of VER integration by modeling the regulating reserves required to
reliably deliver power to an electric system with non-dispatchable generation. Aurora does this
by modeling ancillary services with different time lengths and scale. In order for a resource to
provide an up-regulating reserve it needs to be able to respond by increasing its output to
match a decrease in generation of the VER resource. Effectively, the resource needs to be
Page 8

Idaho Power 2025 VER Integration Study
online and able to respond. For most resources, this means instead of outputting a megawatt-
hour (MWh), they are held in reserve so additional capacity could be deployed.
When Aurora dispatches resources, it optimizes to reduce the cost to serve load while adhering
to the ancillary or reserve requirements. In doing so, it also calculates the cost of providing
those regulating reserves. For this study, the regulating reserve requirements are the same as
those used in the 2025 IRP model.
Incremental Resource Study Cases
The first step in determining the cost of integrating the next incremental wind or solar resource
is selecting appropriate study or use cases. These cases were created considering a handful of
pertinent factors detailed below.
Integration Block Size
There are tradeoffs when selecting the size of the incremental resource used to study the cost
of VER integration. If the size is too small, it may be difficult to reasonably guess which block of
integration charges a project would be subject to without going through the full process of
understanding where a project is in the queue. If the size is too large, then a subsidy could
potentially be created between early and late entrants in a block. Thus, it is important to strike
a balance of reasonably sized blocks.
For this integration study, Idaho Power selected a 100 megawatt (MW) block size for the study,
which was the same block size that was selected for the 2024 VER Integration Study. This size
aligned with the 2025 IRP proxy wind or solar resource sizing. It also strikes a reasonable
balance to avoid, to the extent possible, the negative effects of having blocks that are too large
or too small. If historical trends continue with the average size of a wind or solar Public Utility
Regulatory Policies Act of 1978 qualifying facility (QF) at roughly 20 MW,6 the 100 MW block
approach would allow five projects to integrate before moving to the next block, thereby
ensuring near-term certainty of the integration charge a new QF project.
VER Groups
With the 100 MW block size determined, Idaho Power then focused on determining the
appropriate combination and total amount of the different VERs to study. Like incremental
block sizing, there are tradeoffs with the number and variety of cases to analyze. With too few
cases, the integration charge that a project is subject to may not reasonably represent the
system as it exists at the time of integration. With too many projects, significant effort can be
wasted studying cases that have low probability of occurring.
In consultation with the TRC in 2024, it was agreed that four incremental resource cases would
be studied for the 2024 VER Integration Study: 1)100 MW of solar, 2) 200 MW of solar,
6 2025 IRP Appendix C:Technical Appendix, page 27-28.Average Solar QF size 18 MW and Wind QF size of 20 MW.
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Idaho Power 2025 VER Integration Study
3) 100 MW of wind, and 4) 200 MW of wind. In discussions with IPUC Staff, it was agreed that
the same cases would be studied for the 2025 VER Integration Study. These cases represent
more than the expected increase in new QF VER development to occur between this update
and the next expected update following filing of the 2027 IRP. The 2025 IRP showed that if
recent trends in the development of either wind or solar QFs continue, even the 100 MW
blocks are not expected to be exceeded in the next few years,' which is well past the next
expected update to the integration charges. This is true with the inclusion of distributed solar
or wind installations as well.
Inclusion of Incremental Resource Capital Costs
During meetings with the TRC in 2024, the question was raised whether capital and fixed O&M
costs should be included in the update to integration charges. The TRC was concerned that,
because the IRP's base portfolio is optimized around a particular set of resources, the inclusion
of additional VER resources might not be able to meet the ancillary service requirements they
necessitate. Idaho Power agrees with the TRC that this is a possibility and is including these
resources for the first time in this 2025 VER Integration Study. Idaho Power first proposed the
current methodology to the TRC, included it for comment in the prior study, and discussed its
use in this case during the meetings with Staff about this study. Thus, the Company believes it is
reasonable to include incremental resource costs when additional VERB would require them.
At a high level, the method first involves determining a metric with which to evaluate unmet
ancillary needs and from there to determine a cutoff point at which a corrective action would
be necessary. Once the threshold is set, the IRP model is run to determine if there were
violations of the threshold and then also to determine the corrective generation resource to
bring any unmet ancillary needs under the threshold. With the corrective generation resources
added to the model, the additional capital and fixed O&M costs are captured, as well as any
cost-offsetting activities those resources could provide.
Metric and Threshold Evaluation
Consistent with the proposed methodology from the 2024 VER Integration Study, the Company
uses the Expected Unserved Ancillaries (EUA) value as reported by the Aurora model as the
metric to determine adequate reserve holding resources. As part of its algorithms, the Aurora
based 2025 IRP model already calculates if, when, and to what extent there would be an EUA.
With the ability to determine EUA readily available, it becomes necessary to set the threshold
for when corrective action would be required.
Although many regions within the United States are still in the exploratory phase of analyzing
the use of Expected Unserved Energy (EUE) as a primary reliability metric (a similar although
distinct metric from EUA), Australia is currently using it with a maximum value of 0.002% of
annual energy expected to be unserved and others are beginning to coalesce around this same
Cogeneration and Small Power Production Forecast, 2025 IRP Advisory Council Meeting Oct. 10, 2024.
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Idaho Power 2025 VIER Integration Study
value. Again, because this method has not yet been widely evaluated or adopted, in some
contexts the 0.002 percent threshold may be referred to as a 20 parts per million threshold. In
other words, for a utility expected to deliver 1,000,000 MWh in a year, they would set their
threshold at 20 MWh of EUE in that year, which is 0.002% of 1,000,000 MWh.
Having determined the 0.002%threshold, the next step is determining the basis by which to
calculate the expected unserved ancillaries—specifically whether the 0.002%threshold should
be applied strictly to the expected ancillaries each year or applied to some other value. In this
case, Idaho Power believes using the same expected delivered energy basis is appropriate. The
reason for this basis is within Aurora, as in actual operations, a reserve MWh and an energy
MWh are intermingled items. For a resource to provide a MWh of up regulation reserve, it must
be held in reserve from producing a MWh of energy. Because these values are so intertwined,
Idaho Power has used an EUA threshold of 0.002% of annual delivered energy for the cutoff
when a resource would need to be added to provide additional ancillary services.
Corrective Measure
The final component to analyzing the inclusion of incremental capital costs necessary for the
integration of VERB is the determination of a corrective measure. The determination of the
corrective measure requires considerable analysis, including identifying the cost-optimal
resource type and quantity of that resource to provide the ancillary reserves necessary for the
integration of VERB.
To align with the 202S IRP, SO MW blocks of 4-hour battery storage or 50 MW blocks of
reciprocating engines are considered. For this study, because these two resources provide
different ancillary and non-ancillary benefits, when a corrective resource is needed, both are
tested to determine the least cost option. In the case of the fast-ramping gas plant in the form
of a reciprocating engine (Recip), it can provide ancillaries but is limited by both its ramp rate
and the difference between its minimum and maximum capacity. In the case of a Recip, their
very low minimum outputs and exceptionally fast ramp rates allow them to provide 48.5 MW of
reserves. Additionally, because they can be called on and synchronized to the grid so quickly,
unlike other traditional gas turbines or steam boilers, they can provide reserves when they are
offline. Finally, because they are fully dispatchable, Recips can provide these reserves in all
hours irrespective of state of charge that can limit Battery Energy Storage System (BESS)
resources. In comparison, 4-hour storage resources can go from an idle state to full discharging
in very short periods which allows them to provide their full nameplate towards reserves. For
this to occur, the battery must be sufficiently charged, which means being able to provide this
amount is not always guaranteed. Thus, although a BESS resource should be able to provide its
nameplate towards reserves, this will not always occur, and it could take multiple BESS
resources to provide a particular reserve amount. Because these two resources could both
competitively provide ancillaries in a shortfall event, it is necessary in the 2025 IRP model to
test both options.
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Idaho Power 2025 VIER Integration Study
After determining the least-cost ancillary-providing resources, it becomes necessary to identify
the amount of that resource needed to bring the amount of expected unserved ancillaries
below the 0.002%threshold. After consulting with the TRC in 2024, Idaho Power chose to use
of the following algorithm:
1. Determine if the EUA in any given year exceeds the 0.002%threshold.
a. If a year exceeds the threshold, add a number of blocks equal to the expected
unserved ancillaries minus the total delivered energy times the threshold, all
divided by the ancillary-providing capability of the correcting resource block
rounded up. Should this value exceed the block additions in a prior year, the
incremental blocks are added.
b. If a year is determined to be below the 0.002%threshold, then no corrective
action is necessary and any blocks identified in a prior year are allowed to
remain.
2. A possibility exists that because of the state of charge or other operational constraints,
the blocks may be insufficient to provide the necessary ancillaries. To account for this
possibility, new resources are added to the portfolio, and it is rerun through Aurora to
determine if the additional resources provide the necessary ancillaries to reduce the
EUA below the threshold. If they do, the process ends; but if they do not, the process
repeats until sufficient ancillary-providing resources are added to the model.
The pseudocode for this process is provided below:
• While output max(EUAt) > 0.002% * Energyt
• If EUAt<_ 0.002% * Energyt
• Blockst = max(0,Blockst-1)
• If EUAt> 0.002% * Energyt
• Add 50 MW blocks of 4-hr Storage or Recip resources equal to:
_ EUAt-Energyt*EUAThreshold
• Blocks max ,Blocks
t AncillaryMaxOfCorrection t-1
• Loop
Where:
EUAt is the expected unserved ancillaries in a year t
Blockst is the number of blocks of resources in year t
Energyt is the total expected delivered energy in year t
And [x] represents the ceiling function or round up.
Page 12

Idaho Power 2025 VER Integration Study
Determination of the Integration Cost
The primary tool used to develop updated integration costs is the same Aurora model used to
develop and analyze the portfolios of the 2025 IRP. The process used to quantify those costs
was multi-step but largely procedural.
1. Start with the 2025 IRP's base portfolio, titled "With 111(d) Bridger 3&4 NG".1
2. Create the incremental resource builds. Reflecting the incremental resource study cases
previously discussed, the VERB were added to the base portfolio starting in year 2025 as
must-take resources reflecting the must-take obligation of QF projects.
3. Analyze the various portfolios using Aurora, consistent with the methods deployed in
the 2025 IRP. For each of these portfolios, perform additional analysis in Aurora with the
ancillary services calculations turned on.
4. The integration cost is then calculated using the relative change between the base case
with and without the ancillary services calculations compared to the same cases with
the incremental resource study cases. The pictures below detail the Integration Cost
calculation.
Scenario Scenario
Integration Portfolio Portfolio Incremental
•.
Cost m Cost Energy
WithoutAncillaries
J
Integration nario AncillaryService Base Portfolio
Cost Cost Service Cost
s Idaho Power 2025 IRP—Appendix C:Technical Appendix, page 43.
Page 13

Idaho Power 2025 VIER Integration Study
The process of producing integration charges is outlined in the following figure:
2025 IRP Study Cases Portfolio Costing VER Integration
Charge
��
and 200-MW Regulating Cost
2025 IRP Reserves Differential
.Preferred aind 200- L Between Same of
Without and Without
00
and 200-MW Reserves Reserves
Using this method leverages the Aurora-based 2025 IRP and associated inputs that have already
been discussed during the IRP process. Additionally, Aurora can model the holistic change in
operations required to reliably integrate renewables and, thus, is well suited to calculate the
cost of integration.
By considering how additional must-take VERs change Idaho Power's whole dispatch stack, the
entire cost and value stream of the additional resources can be considered in aggregate.
Results
Using the methods and procedures described above, the following net present value portfolio
costs are produced, along with associated integration costs, for each portfolio:
Cost Differential
Portfolio Cost Portfolio Cost Relative to Base Incremental Integration
with Ancillaries without Ancillaries Portfolio Difference Energy Cost
Portfolio ($x 1,000) ($x 1,000) ($x 1,000) (MWh) $/MWh
Base Portfolio $19,806,678 $19,742,879 N/A N/A
100 MW Solar $19,646,864 $19,576,261 $6,803 4,319,419 1.58
200 MW Solar $19,494,416 $19,402,233 $28,384 8,638,835 3.29
100 MW Wind $19,569,393 $19,498,788 $6,805 5,190,877 1.31
200 MW Wind $19,344,360 $19,264,738 $15,823 10,381,756 1.52
In the above table, the Portfolio column identifies the study cases, as well as the base portfolio,
which is the With 111(d) Bridger 3 & 4 NG portfolio from the 2025 IRP. The 100 MW Solar case
includes 100 MW of incremental must-take solar to the base portfolio. By extension, the other
portfolio case names specify the resource type and incremental must-take resource added.
Page 14

Idaho Power 2025 VER Integration Study
The Portfolio Cost with Ancillaries column shows the total portfolio cost using the same
financial assumptions' and calculation methods used in the 2025 IRP. The With Ancillaries
column shows the model had to account for the regulating reserves necessary to integrate the
VERB in the base portfolio, as well as the incremental VERB in the study cases where applicable.
The next column, Portfolio Cost without Ancillaries, uses the same financial assumptions and
calculation methods except that the Aurora dispatch model was allowed to integrate the VERB
in the various portfolios without regard for the need to hold regulating reserves.
The difference between the With Ancillaries and the Without Ancillaries cases is the model
estimated cost for holding regulating reserves for the VERs in each case. Thus, for the base
portfolio, the cost of the regulating reserves is the difference between $19,806,678k and
$19,742,879k or$63,799k.
The Cost Differential Relative to Base Portfolio Difference column calculates each study case's
regulating reserve cost and then subtracts the Preferred Portfolio difference. Working through
this for the 100 MW Solar case the calculation is ($19,646,864k—$19,576,261k)—
($19,806,678k—$19,742,879k) = $6,803k. This method isolates the additional regulating reserve
costs caused by the incremental VER resource in each study case.
The Incremental Energy column is the amount of energy associated with the incremental VER
resource over the planning horizon. Finally, the Integration Cost column divides the regulating
reserve cost due to the incremental resources and the energy expected from those resources
and converts it to a $/MWh. In the 100 MW Solar case, $6,803,000/4,319,419 MWh =
$1.58/MWh. The other integration costs follow this same calculation specific to each portfolio.
Additionally, the results presented include costs related to additional capital for portfolios that
need to include additional integrating resources to accommodate the must-take VERB.
The results of this study indicate that none of the portfolios required additional integrating
resources. Below is the table of EUA as a percentage of load in each portfolio tested showing
that each of them remains below the 0.002%threshold which would require corrective action:
9 Idaho Power 2025 IRP-Appendix C:Technical Appendix, page 21.
Page 15

Idaho Power 2025 VER Integration Study
EUA as a%of Load Base Portfolio 100 MW Solar 200 MW Solar 100 MW Wind 200 MW Wind
2026 0.000% 0.000% 0.000% 0.000% 0.000%
2027 0.000% 0.000% 0.000% 0.000% 0.000%
2028 0.000% 0.000% 0.000% 0.000% 0.000%
2029 0.000% 0.000% 0.000% 0.000% 0.000%
2030 0.000% 0.000% 0.000% 0.000% 0.000%
2031 0.000% 0.000% 0.000% 0.000% 0.000%
2032 0.000% 0.000% 0.000% 0.000% 0.000%
2033 0.000% 0.000% 0.000% 0.000% 0.000%
2034 0.000% 0.000% 0.000% 0.000% 0.000%
2035 0.000% 0.000% 0.000% 0.000% 0.000%
2036 0.000% 0.000% 0.000% 0.000% 0.000%
2037 0.000% 0.000% 0.000% 0.000% 0.000%
2038 0.000% 0.000% 0.000% 0.000% 0.000%
2039 0.000% 0.000% 0.000% 0.000% 0.000%
2040 0.000% 0.000% 0.000% 0.000% 0.000%
2041 0.000% 0.000% 0.000% 0.000% 0.000%
2042 0.000% 0.000% 0.000% 0.000% 0.000%
2043 0.000% 0.000% 0.000% 0.000% 0.000%
2044 0.000% 0.000% 0.000% 0.000% 0.000%
2045 0.000% 0.000% 0.000% 0.000% 0.000%
The EUA results of this study are different from the 2024 VER Integration Study in that none of
the additional VER cases show a need for incremental integrating resources. This and the
general reduction in VER integration rates are consistent with the differences between the
2023 IRP and the 2025 IRP base portfolios. The primary portfolio difference causing the changes
to this study is the 2025 IRP's addition of new firm and flexible gas resources and an overall
reduction of VER resources. By adding new gas resources, especially highly flexible
reciprocating engines, the 2025 IRP portfolio can more easily accommodate the variable and
unpredictable nature of VER resources. The other important difference is the reduction in the
total amount of VER resources expected in the 2025 IRP Preferred Portfolio. Having fewer VERB
on the system means other resources are not as stressed trying to integrate them. The results
of the 2025 VER Integration Study reflect both changes.
Page 16

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-36
IDAHO POWER COMPANY
ATTACHMENT NO. 2
SCHEDULE 87
(CLEAN AND LEGISLATIVE)

Idaho Power Company Second Revised Sheet No. 87-1
Cancels
I.P.U.C. No. 30, Tariff No. 101 First Revised Sheet No. 87-1
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
APPLICABILITY
This schedule is applicable to all qualifying facility ("QF") generators interconnected to the
Company that have generation of an intermittent nature, such as wind and solar generation. The initial
charges within this schedule are to be assessed to intermittent generation based upon the total
nameplate capacity of a specific type of intermittent generation interconnected to Company's system.
The appropriate charges within this schedule will be included in all QF contracts, both published
and negotiated, at the time those contracts are executed and, once added, shall remain unchanged in
the contract for its duration. Subsequent changes to the charges within this schedule will only apply to
new QF contracts at the time those contracts are executed.
PART 1 —WIND INTEGRATION CHARGES
The following tables are applicable to all QF wind generation contracts that come online on or
after February 1, 2026:
Continued on next page
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective— February 1, 2026 1221 West Idaho Street, Boise, Idaho

Idaho Power Company Third Revised Sheet No. 87-2
Cancels
I.P.U.C. No. 30, Tariff No. 101 Second Revised Sheet No. 87-2
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
WIND INTEGRATION CHARGES (Continued)
0 — 100 MW Wind Capacity Penetration Level
NON-LEVELIZED
NON-
CONTRACT LEVELIZED
YEAR RATES
2026 $1.31
2027 $1.34
2028 $1.37
2029 $1.41
2030 $1.44
2031 $1.48
2032 $1.51
2033 $1.55
2034 $1.58
2035 $1.62
2036 $1.66
2037 $1.70
2038 $1.74
2039 $1.78
2040 $1.83
2041 $1.87
2042 $1.92
2043 $1.96
2044 $2.01
2045 $2.06
2046 $2.11
2047 $2.16
2048 $2.21
2049 $2.26
2050 $2.32
2051 $2.37
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective — February 1, 2026 1221 West Idaho Street, Boise, Idaho

Idaho Power Company Third Revised Sheet No. 87-3
Cancels
I.P.U.C. No. 30, Tariff No. 101 Second Revised Sheet No. 87-3
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
WIND INTEGRATION CHARGES (Continued)
0 - 100 MW Wind Capacity Penetration Level
Levelized
Online Year
Contract Length 2026 2027 2028 2029 2030 2031
1 $1.31 $1.34 $1.37 $1.41 $1.44 $1.48
2 $1.33 $1.36 $1.39 $1.42 $1.46 $1.49
3 $1.34 $1.37 $1.41 $1.44 $1.47 $1.51
4 $1.36 $1.39 $1.42 $1.46 $1.49 $1.53
5 $1.37 $1.40 $1.44 $1.47 $1.51 $1.54
6 $1.39 $1.42 $1.45 $1.49 $1.52 $1.56
7 $1.40 $1.43 $1.47 $1.50 $1.54 $1.58
8 $1.42 $1.45 $1.48 $1.52 $1.56 $1.59
9 $1.43 $1.46 $1.50 $1.54 $1.57 $1.61
10 $1.44 $1.48 $1.51 $1.55 $1.59 $1.63
11 $1.46 $1.49 $1.53 $1.57 $1.60 $1.64
12 $1.47 $1.51 $1.54 $1.58 $1.62 $1.66
13 $1.49 $1.52 $1.56 $1.60 $1.63 $1.67
14 $1.50 $1.54 $1.57 $1.61 $1.65 $1.69
15 $1.51 $1.55 $1.59 $1.62 $1.66 $1.70
16 $1.53 $1.56 $1.60 $1.64 $1.68 $1.72
17 $1.54 $1.58 $1.61 $1.65 $1.69 $1.73
18 $1.55 $1.59 $1.63 $1.67 $1.71 $1.75
19 $1.56 $1.60 $1.64 $1.68 $1.72 $1.76
20 $1.58 $1.62 $1.65 $1.69 $1.73 $1.78
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective - February 1, 2026 1221 West Idaho Street, Boise, Idaho

Idaho Power Company Third Revised Sheet No. 87-4
Cancels
I.P.U.C. No. 30, Tariff No. 101 Second Revised Sheet No. 87-4
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
WIND INTEGRATION CHARGES (Continued)
100 — 200 MW Wind Capacity Penetration Level
NON-LEVELIZED
NOW
CONTRACT LEVELIZED
YEAR RATES
2026 $1.52
2027 $1.56
2028 $1.60
2029 $1.64
2030 $1.68
2031 $1.72
2032 $1.76
2033 $1.80
2034 $1.84
2035 $1.89
2036 $1.93
2037 $1.98
2038 $2.03
2039 $2.07
2040 $2.12
2041 $2.18
2042 $2.23
2043 $2.28
2044 $2.34
2045 $2.39
2046 $2.45
2047 $2.51
2048 $2.57
2049 $2.63
2050 $2.69
2051 $2.76
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective — February 1, 2026 1221 West Idaho Street, Boise, Idaho

Idaho Power Company Third Revised Sheet No. 87-5
Cancels
I.P.U.C. No. 30, Tariff No. 101 Second Revised Sheet No. 87-5
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
WIND INTEGRATION CHARGES (Continued)
100 -200 MW Wind Capacity Penetration Level
Levelized
Online Year
Contract
Length 2026 2027 2028 2029 2030 2031
1 $1.52 $1.56 $1.60 $1.64 $1.68 $1.72
2 $1.54 $1.58 $1.62 $1.66 $1.70 $1.74
3 $1.56 $1.60 $1.64 $1.67 $1.71 $1.76
4 $1.58 $1.61 $1.65 $1.69 $1.73 $1.78
5 $1.59 $1.63 $1.67 $1.71 $1.75 $1.79
6 $1.61 $1.65 $1.69 $1.73 $1.77 $1.81
7 $1.63 $1.67 $1.71 $1.75 $1.79 $1.83
8 $1.65 $1.68 $1.73 $1.77 $1.81 $1.85
9 $1.66 $1.70 $1.74 $1.78 $1.83 $1.87
10 $1.68 $1.72 $1.76 $1.80 $1.85 $1.89
11 $1.69 $1.74 $1.78 $1.82 $1.86 $1.91
12 $1.71 $1.75 $1.79 $1.84 $1.88 $1.93
13 $1.73 $1.77 $1.81 $1.85 $1.90 $1.94
14 $1.74 $1.78 $1.83 $1.87 $1.92 $1.96
15 $1.76 $1.80 $1.84 $1.89 $1.93 $1.98
16 $1.77 $1.82 $1.86 $1.90 $1.95 $2.00
17 $1.79 $1.83 $1.88 $1.92 $1.97 $2.01
18 $1.80 $1.85 $1.89 $1.94 $1.98 $2.03
19 $1.82 $1.86 $1.91 $1.95 $2.00 $2.05
20 $1.83 $1.88 $1.92 $1.97 $2.02 $2.06
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective - February 1, 2026 1221 West Idaho Street, Boise, Idaho

Idaho Power Company Second Revised Sheet No. 87-6
Cancels
I.P.U.C. No. 30, Tariff No. 101 First Revised Sheet No. 87-6
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
PART 2 — SOLAR INTEGRATION CHARGES
The following tables are applicable to all QF solar generation contracts that come online on or after
February 1, 2026:
Continued on next page
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective — February 1, 2026 1221 West Idaho Street, Boise, Idaho

Idaho Power Company Third Revised Sheet No. 87-7
Cancels
I.P.U.C. No. 30, Tariff No. 101 Second Revised Sheet No. 87-7
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
SOLAR INTEGRATION CHARGES (Continued)
0 — 100 MW Solar Capacity Penetration Level
NON-LEVELIZED
CONTRACT NON-LEVELIZED
YEAR RATES $/MWh
2026 $1.58
2027 $1.61
2028 $1.65
2029 $1.69
2030 $1.73
2031 $1.77
2032 $1.82
2033 $1.86
2034 $1.90
2035 $1.95
2036 $2.00
2037 $2.04
2038 $2.09
2039 $2.14
2040 $2.20
2041 $2.25
2042 $2.30
2043 $2.36
2044 $2.41
2045 $2.47
2046 $2.53
2047 $2.59
2048 $2.65
2049 $2.72
2050 $2.78
2051 $2.85
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective — February 1, 2026 1221 West Idaho Street, Boise, Idaho

Idaho Power Company Third Revised Sheet No. 87-8
Cancels
I.P.U.C. No. 30, Tariff No. 101 Second Revised Sheet No. 87-8
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
SOLAR INTEGRATION CHARGES (Continued)
0 - 100 MW Solar Capacity Penetration Level
Levelized
Online Year
Contract
Length 2026 2027 2028 2029 2030 2031
1 $1.58 $1.61 $1.65 $1.69 $1.73 $1.77
2 $1.59 $1.63 $1.67 $1.71 $1.75 $1.79
3 $1.61 $1.65 $1.69 $1.73 $1.77 $1.81
4 $1.63 $1.67 $1.71 $1.75 $1.79 $1.83
5 $1.65 $1.69 $1.73 $1.77 $1.81 $1.85
6 $1.67 $1.71 $1.75 $1.79 $1.83 $1.87
7 $1.68 $1.72 $1.76 $1.81 $1.85 $1.89
8 $1.70 $1.74 $1.78 $1.83 $1.87 $1.91
9 $1.72 $1.76 $1.80 $1.84 $1.89 $1.93
10 $1.73 $1.78 $1.82 $1.86 $1.91 $1.95
11 $1.75 $1.79 $1.84 $1.88 $1.93 $1.97
12 $1.77 $1.81 $1.85 $1.90 $1.94 $1.99
13 $1.78 $1.83 $1.87 $1.92 $1.96 $2.01
14 $1.80 $1.84 $1.89 $1.93 $1.98 $2.03
15 $1.82 $1.86 $1.91 $1.95 $2.00 $2.05
16 $1.83 $1.88 $1.92 $1.97 $2.02 $2.06
17 $1.85 $1.89 $1.94 $1.99 $2.03 $2.08
18 $1.86 $1.91 $1.96 $2.00 $2.05 $2.10
19 $1.88 $1.92 $1.97 $2.02 $2.07 $2.12
20 $1.89 $1.94 $1.99 $2.03 $2.08 $2.13
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective - February 1, 2026 1221 West Idaho Street, Boise, Idaho

Idaho Power Company Third Revised Sheet No. 87-9
Cancels
I.P.U.C. No. 30, Tariff No. 101 Second Revised Sheet No. 87-9
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
SOLAR INTEGRATION CHARGES (Continued)
100 — 200 MW Solar Capacity Penetration Level
NON-LEVELIZED
NON-
LEVELIZED
CONTRACT YEAR RATES $/MWh
2026 $3.29
2027 $3.36
2028 $3.45
2029 $3.53
2030 $3.61
2031 $3.70
2032 $3.79
2033 $3.88
2034 $3.97
2035 $4.07
2036 $4.17
2037 $4.27
2038 $4.37
2039 $4.47
2040 $4.58
2041 $4.69
2042 $4.80
2043 $4.92
2044 $5.04
2045 $5.16
2046 $5.28
2047 $5.41
2048 $5.54
2049 $5.67
2050 $5.81
2051 $5.94
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective — February 1, 2026 1221 West Idaho Street, Boise, Idaho

Idaho Power Company Third Revised Sheet No. 87-10
Cancels
I.P.U.C. No. 30, Tariff No. 101 Second Revised Sheet No. 87-10
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
SOLAR INTEGRATION CHARGES (Continued)
100 -200 MW Solar Capacity Penetration Level
Contract
Length 2026 2027 2028 2029 2030 2031
1 $3.29 $3.36 $3.45 $3.53 $3.61 $3.70
2 $3.32 $3.40 $3.49 $3.57 $3.65 $3.74
3 $3.36 $3.44 $3.53 $3.61 $3.70 $3.78
4 $3.40 $3.48 $3.56 $3.65 $3.74 $3.83
5 $3.44 $3.52 $3.60 $3.69 $3.78 $3.87
6 $3.47 $3.56 $3.64 $3.73 $3.82 $3.91
7 $3.51 $3.59 $3.68 $3.77 $3.86 $3.95
8 $3.55 $3.63 $3.72 $3.81 $3.90 $3.99
9 $3.58 $3.67 $3.76 $3.85 $3.94 $4.03
10 $3.62 $3.71 $3.79 $3.89 $3.98 $4.07
11 $3.65 $3.74 $3.83 $3.92 $4.02 $4.11
12 $3.69 $3.78 $3.87 $3.96 $4.06 $4.15
13 $3.72 $3.81 $3.90 $4.00 $4.09 $4.19
14 $3.76 $3.85 $3.94 $4.03 $4.13 $4.23
15 $3.79 $3.88 $3.98 $4.07 $4.17 $4.27
16 $3.82 $3.92 $4.01 $4.11 $4.21 $4.31
17 $3.86 $3.95 $4.04 $4.14 $4.24 $4.34
18 $3.89 $3.98 $4.08 $4.18 $4.28 $4.38
19 $3.92 $4.02 $4.11 $4.21 $4.31 $4.42
20 $3.95 $4.05 $4.14 $4.24 $4.35 $4.45
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective - February 1, 2026 1221 West Idaho Street, Boise, Idaho

Idaho Power Company Forst Second Revised Sheet No. 87-1
Cancels
I.P.U.C. No. 30, Tariff No. 101 Q4g+na-First Revised Sheet No. 87-1
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
APPLICABILITY
This schedule is applicable to all qualifying facility ("QF") generators interconnected to the
Company that have generation of an intermittent nature, such as wind and solar generation. The initial
charges within this schedule are to be assessed to intermittent generation based upon the total
nameplate capacity of a specific type of intermittent generation interconnected to Company's system.
The appropriate charges within this schedule will be included in all QF contracts, both published
and negotiated, at the time those contracts are executed and, once added, shall remain unchanged in
the contract for its duration. Subsequent changes to the charges within this schedule will only apply to
new QF contracts at the time those contracts are executed.
PART 1 —WIND INTEGRATION CHARGES
The following tables are applicable to all QF wind generation contracts that come online on or
after dune 1, 202February 1, 2026:
Continued on next page
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective—jURe 1, 2025February 1, 2026 1221 West Idaho Street, Boise, Idaho

Idaho Power Company SeGGRd Third Revised Sheet No. 87-2
Cancels
I.P.U.C. No. 30, Tariff No. 101 €4rst-Second Revised Sheet No. 87-2
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
WIND INTEGRATION CHARGES (Continued)
0 - 100 MW Wind Capacity Penetration Level
NON-LEVELIZED
NON-
CONTRACT LEVELIZED
YEAR RATES
242-5 $9:95
2026 $4-.371.31
2027 $4-91.34
2028 $4.0331.37
2029 $4�61.41
2030 $4-. .44
2031 $4-. 41.48
2032 $4-. 41.51
2033 $4-71.55
2034 $4-.2O 58
2035 $4-.2-31.62
2036 $4-.61.66
2037 $4-91.70
2038 $4-331.74
2039 $4-61.78
2040 $4-491.83
2041 $4-.441.87
2042 $4-.471.92
2043 $4.541.96
2044 $4-.�552.01
2045 $4392.06
2046 $4-:632.11
2047 $4�2.16
2048 $4.722.21
2049 $4:7-62.26
2050 $4-.842.32
2051 $Z.37
IDAHO Issued by IDAHO POWER COMPANY
Issued NevemberT20 25per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective--
Deeember 7, 202 February 1, 2026 1221 West Idaho Street, Boise, Idaho
n,I„Ir.o nip 225_n2

Idaho Power Company SeGGRd Third Revised Sheet No. 87-3
Cancels
I.P.U.C. No. 30, Tariff No. 101 F4rst-Second Revised Sheet No. 87-3
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
WIND INTEGRATION CHARGES (Continued)
0 - 100 MW Wind Capacity Penetration Level
Levelized
Online Year
Contract Length 202 -5 2026 2027 2028 2029 2030 2031
1 $9 96 $0.991.31 $4-.W .34 $4-031.37 $4-061.41 $4-.091.44 IC48
2 $0 96 $9.991.33 $4-.021.36 $4�41.39 $4-71.42 $4-91.46 $1.49
3 $0 93 $4-.W1.34 $4-.931.37 $451.41 $41.44 $4A 41.47 $1.51
4 $0 9 $4-."1.36 $4-041.39 $4-.N .42 $4401.46 $4-.4-21.49 $1.53
5 $a-89 $4-.031.37 $4-.051.40 $4-.081.44 $4-4 47 $4 U1.51 $1.54
6 $4-04 $4-.041.39 $4-.061.42 $4-.091.45 $4-21.49 $44-51.52 $1.56
7 $4-.0-51.40 $4-.091.43 $4-.4-01.47 $4-431.50 $4�1.54 $1.58
8 $4-.061.42 $4-.Gg 45 $4-21.48 $4-51.52 $4�1.56 $1.59
9 $4-.N .43 $4-.4-01.46 $4-431.50 $4-.4-61.54 $4-.4-91.57 $1.61
10 $a-06 $4�1.44 $4- 1.48 $4-.41.51 $4-71.55 $4-.2-01.59 $1.63
11 $1 7 $4-.4 01.46 $4 21.49 $4 51.53 $4 1.57 $4.41.60 1.64
12 $a-08 $4-.141.47 $4-431.51 $4-461.54 $4-491.58 $4-.2-31.62 $1.66
13 $4-. 149 $4-51.52 $4-. .56 $4-.24 60 $4-.241.63 $1.67
14 $4-431.50 $4-.-61.54 $4-.4-91.57 $4-221.61 $4-.2-51.65 $1.69
15 $4�41.51 $4-.4-71.55 $4-.201.59 $4-.2-31.62 $4-.2-61.66 $1.70
16 $ 2 $4-51.53 $4-. .56 $4-241.60 $4-.241.64 $4.271.68 $1.72
17 $4-.-61.54 $4-.4-91.58 $4-221.61 $4-.251.65 $4-.2-91.69 $1.73
18 $ 44 $4-71.55 $4-.2-01.59 $4-.2-31.63 $4-.261.67 $4-.W1.71 $1.75
19 $ 5 $4-.4-91.56 $4.241.60 $4-.241.64 $4-271.68 $4-.341.72 $1.76
20 $4-491.58 $4-.221.62 $4-.2-51.65 $4-.2-91.69 $4-321.73 $1.78
IDAHO Issued by IDAHO POWER COMPANY
Issued.- November 2025 per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective- February 1, 2026z eeernbe T, 2025 1221 West Idaho Street, Boise, Idaho
dV'Ge No. 25_02

Idaho Power Company SeGGRd Third Revised Sheet No. 87-4
Cancels
I.P.U.C. No. 30, Tariff No. 101 €&t-Second Revised Sheet No. 87-4
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
WIND INTEGRATION CHARGES (Continued)
100 - 200 MW Wind Capacity Penetration Level
NON-LEVELIZED
NOW
CONTRACT LEVELIZED
YEAR RATES
- 2025 $4-.31- -
2026 $4- 51.52
2027 $4-.381.56
2028 $4-421.60
2029 $4-.451.64
2030 $4-491.68
2031 $4-531.72
2032 $4-571.76
2033 $4-.�1.80
2034 $a-6-51.84
2035 $4-.7-01.89
2036 $a-. 41.93
2037 $4-.791.98
2038 $4-832.03
2039 $4-.�2.07
2040 $4-.932.12
2041 $4-.�2.18
2042 $2.032.23
2043 $2 032.28
2044 $2.442.34
2045 $24-92.39
2046 $2-.-2-52.45
2047 $2-.42.51
2048 $2.372.57
2049 $2 432.63
2050 $2.492.69
2051 $Z.76
IDAHO Issued by IDAHO POWER COMPANY
Issued NevernbeF 7, 2025per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective- February 1, 2026z eeernber 7, 2025 1221 West Idaho Street, Boise, Idaho
dV'Ge Ne 25_02

Idaho Power Company SeGGRd Third Revised Sheet No. 87-5
Cancels
I.P.U.C. No. 30, Tariff No. 101 €4rst-Second Revised Sheet No. 87-5
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
WIND INTEGRATION CHARGES (Continued)
100 -200 MW Wind Capacity Penetration Level
Levelized
Online Year
Contract
Length 2025 2026 2027 2028 2029 2030 2031
1 $4-34 $4-451.52 $4-391.56 $4-.21.60 $4-451.64 $4 -91.68 $1.72
2 $4-.361.54 $4401.58 $4-.441.62 $4-.71.66 $4-.541.70 $1.74
3 $4 5 $1-361.56 $4.421.60 $4-451.64 $4-491.67 $4-5-31.71 1.76
4 $4 36 $4-.401.58 $4-4331.61 $4-471.65 $4- 1-1.69 $4-�551.73 $1.78
5 $4 38 $4.41.59 $4451.63 $4.491.67 $4.5-3 71 $4-571.75 $1.79
6 $4-.N $4-431.61 $4-.71.65 $4-.501.69 $4�41.73 $4-.591.77 $1.81
7 $4-4� $4-451.63 $4-.481.67 $4-.521.71 $4-.561.75 $4-01.79 $1.83
8 $4-42 $4461.65 $4.5G 68 $4.541.73 $4.58 77 $4-21.81 1.85
9 $4-44 $4-.491.66 $4-521.70 $4-.561.74 $4.W .78 $4�41.83 $1.87
10 $4-46 $4-491.68 $4- 31.72 $4-.571.76 $4-41.80 $4-51.85 $1.89
11 $4 $4-641.69 $4-.551.74 $4-.5-91.78 $4-.631.82 $4-71.86 1.91
12 $4 49 $4- 1.71 $4-.561.75 $4-.W .79 $4�1.84 $4�1.88 $1.93
13 $4 59 $4.541.73 $4.58 77 $4-21.81 $4-61.85 $4:741.90 $1.94
14 $4-.54 $4-.551.74 $4-.591.78 $4�41.83 $4-.691.87 $4-.721.92 $1.96
15 " $4-.571.76 $4-41.80 $4-51.84 $4-91.89 $4 741.93 $1.98
16 $4:54 $4.58 77 $4-21.82 $4. 71.86 $4-.41.90 $4-.7-51.95 2.00
17 $4-56 $4-.W .79 $4�41.83 $4�1.88 $4-.7-91.92 $4a71.97 2.01
18 $4. $4-41.80 $4-51.85 $4a01.89 $4.741.94 $4:7-91.98 2.03
19 $4-.921.82 $4-471.86 $4a41.91 $4-.7-51.95 $4-.W2.00 2.05
20 $4-69 $4-.�&41.83 $4-.691.88 $4a21.92 $4a71.97 $4-.922.02 $2.06
IDAHO Issued by IDAHO POWER COMPANY
Issued NevembeF 7,20 25per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective- February 1, 2026z eeernber7,2025 1221 West Idaho Street, Boise, Idaho
odV!Ge Ne 25_n2

Idaho Power Company Forst Second Revised Sheet No. 87-6
Cancels
I.P.U.C. No. 30, Tariff No. 101 04q+r a-First Revised Sheet No. 87-6
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
PART 2 — SOLAR INTEGRATION CHARGES
The following tables are applicable to all QF solar generation contracts that come online on or after
ju,,e 1, 2025February 1, 2026:
Continued on next page
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. 9 Timothy E. Tatum, Vice President, Regulatory Affairs
Effective—jURe 1, 202 February 1, 2026 1221 West Idaho Street, Boise, Idaho

Idaho Power Company SeGGRd Third Revised Sheet No. 87-7
Cancels
I.P.U.C. No. 30, Tariff No. 101 €&t-Second Revised Sheet No. 87-7
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
SOLAR INTEGRATION CHARGES (Continued)
0 — 100 MW Solar Capacity Penetration Level
NON-LEVELIZED
CONTRACT NON-LEVELIZED
YEAR RATES $/MWh
- 242-5 $7 8 -
2026 $7.981.58
2027 $&.4-91.61
2028 $8-.401.65
2029 $&.621.69
2030 $8-.941.73
2031 $9071.77
2032 $9--941.82
2033 $9-551.86
2034 $9-.801.90
2035 $40-.061.95
2036 $40-.322.00
2037 $40.592.04
2038 $40-.962.09
2039 $44. 42.14
2040 $44-.432.20
2041 $41 732.25
2042 $42$32.30
2043 $42-452.36
2044 $42�72.41
2045 $43-.02.47
2046 $43 342.53
2047 $43-.692.59
2048 $44042.65
2049 $44402.72
2050 $44-.7-92.78
2051 $Z.85
IDAHO Issued by IDAHO POWER COMPANY
Issued NovemberTz825per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective— February 1, 2026z eeernber 7, 2025 1221 West Idaho Street, Boise, Idaho
dV'Ge Ne 25_02

Idaho Power Company SeGGRd Third Revised Sheet No. 87-8
Cancels
I.P.U.C. No. 30, Tariff No. 101 irst-Second Revised Sheet No. 87-8
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
SOLAR INTEGRATION CHARGES (Continued)
0 - 100 MW Solar Capacity Penetration Level
Levelized
Online Year
Contract
Length 242-6 2026 2027 2028 2029 2030 2031
1 $7 78 $7�81.58 $8.4-91.61 $8 401.65 $8.21.69 $8-.841.73 1.77
2 $7:88 $8-.081.59 $8-91.63 $8�41.67 $8-7-31.71 $8-.N1.75 $1.79
3 $ -.97 $9. -81.61 $8-391.65 $8�41.69 $8�41.73 $9.071.77 $1.81
4 $8-.07 $8-.81.63 $8-.491.67 $8.721.71 $8-.941.75 $9-1-71.79 $1.83
5 $8-1-7 $8-.381.65 $8.601.69 $8-.K .73 $9-.051.77 $9-.281.81 $1.85
6 $8:26 $8-.471.67 $8�91.71 $8sJ21.75 $9451.79 $9-.391.83 $1.87
7 $8.-35 $8371.68 $8-.791.72 $9-.G21.76 $9-.261.81 $9-581.85 $1.89
8 $8:45 $8.661.70 $8-.91.74 $9-421.78 $9.351.83 $9401.87 $1.91
9 $8-54 $8.761.72 $8-.9-91.76 $9-.221.80 $9A-61.84 $9-.741.89 $1.93
10 $8�3 $8-.51.73 $9-.081.78 $9.321.82 $9-.561.86 $9-.-841.91 $1.95
11 $8-.7-2 $8-.941.75 $9. -81.79 $9 41.84 $9.661.88 $9-.941.93 $1.97
12 $8-.90 $9-.031.77 $9-71.81 $9-541.85 $9:761.90 $10.011.94 $1.99
13 $8-.89 $9-A-21.78 $9-.361.83 $9 601.87 $9:851.92 $49.11.96 $2.01
14 $8-98 $9-.241.80 $9 451.84 $9-701.89 $9$51.93 $10.211.98 $2.03
15 $ -. 6 $9-.301.82 $9-541.86 $9-.7-91.91 $10.041.95 $40 302.00 $2.05
16 " $9.381.83 $9.681.88 $9.991.92 $10.131.97 $10.402.02 $2.06
17 $9-.2-3 $9 471.85 $9.741.89 $9 971.94 $10.231.99 $10.492.03 $2.08
18 $9-.3 $9-.551.86 $9�01.91 $49-51.96 $40.312.00 $10.582.05 $2.10
19 " $9.631.88 $9.-881.92 $40-.1-41.97 $10.402.02 $10.672.07 $2.12
20 $9 47 $9 741.89 $ 961.94 $40-.221.99 $40.92.03 $40:7-62.08 $2.13
IDAHO Issued by IDAHO POWER COMPANY
Issued NevembeF 7,20 25per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective- February 1, 2026z eeernber7,2025 1221 West Idaho Street, Boise, Idaho
dViGe nip 25_n2

Idaho Power Company SeGGRd Third Revised Sheet No. 87-9
Cancels
I.P.U.C. No. 30, Tariff No. 101 irst-Second Revised Sheet No. 87-9
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
SOLAR INTEGRATION CHARGES (Continued)
100 — 200 MW Solar Capacity Penetration Level
NON-LEVELIZED
NON-
LEVELIZED
CONTRACT YEAR RATES $/MWh
2025 $a 9 07 -
2026 $10.333.29
2027 $10.603.36
2028 $10.883.45
2029 $44.163.53
2030 $11.453.61
2031 $44.753.70
2032 $42.053.79
2033 $12.373.88
2034 $12.693.97
2035 $43.024.07
2036 $13.364.17
2037 $40.704.27
2038 $14.064.37
2039 $14.434.47
2040 $14.804.58
2041 $15.194.69
2042 $45.584.80
2043 $15.994.92
2044 $16.405.04
2045 $ 35.16
2046 $17275.28
2047 $47.745.41
2048 $18.185.54
2049 $48.655.67
2050 $19.135.81
2051 $5.94
IDAHO Issued by IDAHO POWER COMPANY
Issued NevemberT20z'25per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective— February 1, 2026z eeernber7,2025 1221 West Idaho Street, Boise, Idaho
dViGe nip 25_n2

Idaho Power Company SeGend Third Revised Sheet No. 87-10
Cancels
I.P.U.C. No. 30, Tariff No. 101€4rst-Second Revised Sheet No. 87-10
SCHEDULE 87
INTERMITTENT GENERATION INTEGRATION CHARGES
(Continued)
SOLAR INTEGRATION CHARGES (Continued)
100 -200 MW Solar Capacity Penetration Level
Contract
Length 2M 2026 2027 2028 2029 2030 2031
1 $40.07 $10.333.29 $40:603.36 $40.883.45 $44-4Q.53 $41-:453.61 $3.70
2 $40.20 $10.463.32 $10.743.40 $44-." 49 $41.303.57 $44-.593.65 $3.74
3 $10.32 $10.593.36 $40-.973.44 $44.153.53 $44-443.61 $44�43.70 $3.78
4 $10.45 $40.723.40 $44.003.48 $44-83.56 $44.583.65 $44-.M3.74 $3.83
5 $10.57 $10.853.44 $11.133.52 $41.423.60 $44-.743.69 $42-.023.78 $3.87
6 $10-69 $40.973.47 $44-.2Q.56 $44.553.64 $44-453.73 $42-463.82 $3.91
7 $10-81 $44.03.51 $41383.59 $44-.683.68 $11.983.77 $42-.3G 86 $3.95
8 $10.93 $11.223.55 $44.513.63 $44.813.72 $42-423.81 $42-433.90 $3.99
9 $11-05 $44.343.58 $44-.&33.67 $44.943.76 $42�53.85 $42-.57-3.94 $4.03
10 $11-17 $11.463.62 $44.763.71 $42.063.79 $42.383.89 $42-.-T03.98 $4.07
11 $1w.29 $44583.65 $11.983.74 $12.193.83 $42-.543.92 $42-.934.02 $4.11
12 $11.40 $44a03.69 $42.-003.78 $42.313.87 $42�33.96 $42-.964.06 $4.15
13 $11-51 $44.813.72 $12 123.81 $42-433.90 $12�64.00 $4�-094.09 $4.19
14 $1 1.62 $11.933.76 $12 243.85 $12.553.94 $4264.03 $43-.244.13 $4.23
15 $11-73 $42.043.79 $42.-3-Q.88 $42.673.98 $4-3 004.07 $43-.344.17 $4.27
16 $11.84 $12.153.82 $42.463.92 $42-.7-94.01 $40.124.11 $43-.464.21 $4.31
17 $11-95 $42.263.86 $42-.583.95 $42.904.04 $43-.244.14 $43 584.24 $4.34
18 $4 2.05 $42.363.89 $42.693.98 $4�-024.08 $43.354.18 $43-.7-04.28 $4.38
19 $12.15 $12 473.92 $12 794.02 $13.134.11 $43-.474.21 $43 24.31 $4.42
20 $12.25 $42.573.95 $42-.904.05 $43.244.14 $48-584.24 $43-.934.35 $4.45
IDAHO Issued by IDAHO POWER COMPANY
Issued NevembeF 7,20 25per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective- February 1, 2026z eeernber7,2025 1221 West Idaho Street, Boise, Idaho
dViGe nip 25_n2