20250401APPLICATION.pdf

IDAHO POWER.
RECEIVED
MEGAN GOICOECHEA ALLEN April 1, 2025
Corporate Counsel IDAHO PUBLIC
mgoicoecheaallenC�idahopower.com UTILITIES COMMISSION
April 1, 2025
Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Boulevard
Building 8, Suite 201-A
Boise, Idaho 83714
Re: Case No. IPC-E-25-15
Application for Its First Annual Update to the Export Credit Rate for Non-
Legacy On-Site Generation Customers from June 1, 2025 through May 31,
2026, In Compliance with Order No. 36048
Commission Secretary:
Attached for electronic filing is Idaho Power Company's Application in the above-
entitled matter.
In addition, please find attached the Direct Testimony of Jared Ellsworth and Mary
Alice Taylor, filed in support of the Application. A Word version of the testimonies will also
be sent in a separate email for the convenience of the Reporter.
If you have any questions about the attached documents, please do not hesitate
to contact me.
Sincerely,
I f�C� Q►.�Uiv1.
Megan Goicoechea Allen
MGA:sg
Enclosures
P.O.Box 70(83707)
1221 W.Idaho St.
Boise,ID 83702

MEGAN GOICOECHEA ALLEN (ISB No. 7623)
DONOVAN WALKER (ISB No. 5921)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
mgoicoecheaallen(a).idahopower.com
dwalker(a)idahopower.com
Attorneys for Idaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY'S APPLICATION FOR ITS ) CASE NO. IPC-E-25-15
FIRST ANNUAL UPDATE TO THE EXPORT )
CREDIT RATE FOR NON-LEGACY ON- ) APPLICATION
SITE GENERATION CUSTOMERS FROM )
JUNE 1, 2025 THROUGH MAY 31, 2026, IN )
COMPLIANCE WITH ORDER NO. 36048. )
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. 36048 hereby respectfully applies to the Commission for
an order authorizing Idaho Power, in compliance with Commission Order No. 36048, to
implement the Export Credit Rate ("ECR") for non-legacy on-site generation customers
from June 1, 2025 through May 31, 2026, and to approve the Company's corresponding
proposed changes to Schedule 6, Residential Service On-Site Generation ("Schedule 6"),
Hereinafter cited as RP.
APPLICATION - 1

Schedule 8, Small General Service On-Site Generation ("Schedule 8"), and Schedule 84,
Large General, Large Power, and Irrigation On-Site Generation Service ("Schedule 84").
With this filing the Company proposes an ECR which will apply on a per kilowatt-hour
("kWh") of excess energy exported to Idaho Power's system by non-legacy Schedule 6,
8, and 84 customers of 14.05980 for summer on-peak exports, 1.76820 for summer-off
peak exports, and 0.95400 for all exported energy in the non-summer season.
Additionally, concurrently with this filing, the Company is submitting its annual
Distributed Energy Resources ("DER") report and, for the reasons more fully described
herein, notifies the Commission that moving forward it intends to consolidate its annual
DER reporting requirement with its annual ECR update, which the Commission directed
in Order No. 36048 be filed on April 1st, and respectfully requests the Commission advise
if it does not agree with the Company's proposed procedural approach in this regard.
In support of this Application, Idaho Power has filed the Direct Testimony of Mary
Alice J. Taylor("Taylor Testimony"), the Direct Testimony of Jared L. Ellsworth ("Ellsworth
Testimony"). In further support of this Application, Idaho Power represents as follows:
I. BACKGROUND
On-Site Generation Offering Structure
1. Under Idaho Power's on-site generation service offerings, retail customers
can choose to install their own electricity-generating equipment at their home or business
to offset some or all of their electric needs. Currently, customers that generate their own
electricity and who wish to interconnect Exporting Systems are billed under Schedule 6,
Schedule 8, or Schedule 84.
APPLICATION - 2

2. The extensive history of the Company's net metering service offering
demonstrates an on-going and incremental effort by the Company to establish a
foundation for modernizing its on-site generation offering to support enhanced adoption
of renewable energy resources and advances in energy generation technology, while
simultaneously ensuring equity among all customers. Over the last several years, with
guidance from the Commission, Idaho Power has modernized the on-site generation
compensation structure through a series of customer-self generation dockets.
3. In 2019 and 2020, the Commission established criteria to define legacy
treatment for existing systems, providing a clear distinction between existing and new
customers based on the customers' reasonable expectations when they procured an on-
site generation system.2 Under this established criteria, systems qualifying for legacy
treatment continue to take service under the rules for net energy metering until legacy
status terminates, while non-legacy systems are subject to future changes to the program
fundamentals, including to the compensation structure applied to excess energy.
4. The Commission also established a process to ensure any changes to the
Company's on-site generation service offering are well-reasoned and data driven,
requiring that the Company undertake a comprehensive study of the costs and benefits
of on-site generation before any changes applicable to non-legacy customer
compensation would be considered.3
2 In the Matter of the Petition of Idaho Power Company to Study the Costs, Benefits, and Compensation of
Net Excess Energy Supplied by Customer On-Site Generation, Case No. I PC-E-18-15, Order No. 34509 at
10 (Dec. 20, 2019); In the Matter of Idaho Power Company's Application for Authority to Modify Schedule
84's Metering Requirement and to Grandfather Existing Customers with Two Meters, IPC-E-20-26, Order
No. 34854 at 10 (Dec. 1, 2020).
3 In the Matter of the Application of Idaho Power Company for Authority to Establish New Schedules for
Residential and Small General Service Customers with On-Site Generation, Case No. IPC-E-17-13, Order
No. 34046 at 22 (May 9, 2018).
APPLICATION - 3

5. More recently, Idaho Power initiated the multi-phase process for a
comprehensive study of the costs and benefits of on-site generation. In 2021, the study
design phase of the process concluded and was subsequently followed in 2022 by a study
review phase.4 Ultimately, the Commission found the Company October 2022 Value of
Distributed Energy Resource ("VODER") study complied with its previous directives and
"should serve as a basis for the Company's implementation recommendations in a
subsequent case."5
6. Having completed the process established by the Commission to prepare
for changes to its on-site generation offering, on May 1, 2023, Idaho Power filed Case
No. IPC-E-23-14, to establish an updated offering, proposing modifications to the
compensation structure for on-site generators with non-legacy systems that were
intended to more accurately measure, record, and value excess energy. More specifically,
the Company proposed to implement real-time net billing with an avoided cost-based
financial credit rate for exported energy. Under net billing, customers first use all energy
generated from their system to offset their own energy needs valued at the applicable full
retail rate, which reduces the amount of energy customers consume from the grid. Non-
legacy customers receive a financial bill credit for any exports to the grid based on an
avoided cost-based ECR that varies based on the season and time of export. The
4 In the Matter of the Application of Idaho Power Company's Application to Initiate a Multi-Phase
Collaborative Process for the Study of Costs, Benefits, and Compensation of Net Excess Energy
Associated with Customer On-Site Generation, Case No. IPC-E-21-21; In the Matter of Idaho Power
Company's Application to Complete the Study Review Phase of the Comprehensive Study of Costs and
Benefits of On-Site Customer Generation &For Authority to Implement Changes to Schedules 6, 8, and 84
for Non-Legacy Systems, Case No. IPC-E-22-22 .
5 Id., Order No. 35631 at 31 (Dec. 19, 2022).
APPLICATION -4

Company's proposal contemplated annual updates to the ECR, with the ECR updates to
be based on a Commission-approved methodology.
7. In Order No. 36048, the Commission approved the Company's request to
implement, effective January 1, 2024, real-time net billing to measure and charge
customers for all kWh consumed from the grid at the retail rate, and measure and
compensate customers for all kWh exported to the grid at a time-differentiated ECR .6
The changes were approved to take effect with non-legacy customers' January 2024
billing period. The Commission further ordered that the Company update all components
of the ECR except the season and hours of highest risk in an annual filing beginning in
2025, with a filing date of April 1 and an effective date of June 1.7
DER Reporting Requirements
8. Since 2014, the Company has filed an annual status report ("DER Status
Report"8) with the Commission outlining net metering service provisions and pricing,
system reliability considerations, and information on meter aggregation in accordance
with Order Nos. 328469 and 3292510 issued in Case No. IPC-E-12-27.
9. Subsequently, in Order No. 34955, issued in Case No. IPC-E-20-30, the
Commission found it prudent to require that the Company's annual DER Status Report
also include any known or foreseeable DER related distribution circuit issues or costs and
potential smart inverter functionality updates that could address the issues or lower
6 In the Matter of Idaho Power Company's Application for Authority to Implement Changes to the
Compensation Structure Applicable to Customers On-Site Generation Under Schedules 6, 8, and 84 and
to Establish an Export Credit Rate, Case No. IPC-E-23-14, Order No. 36048 at 6 (Dec. 29, 2023).
Id. at 18.
8 Previously referred to as the "Net Metering Report."
9 In the Matter of Idaho Power Company's Application to Modify Net Metering Service, Case No IPC-E-12-
27, Order No. 32846 at 19 (Jul. 3, 2013).
11 Id., Order No. 32925 at 7 (Nov. 19, 2013).
APPLICATION - 5

costs." In that same case, the Commission found that the annual DER Status Report
should be the primary means by which the Company apprises the Commission of activity
related to on-site generation, but that the Company should also include the information in
its annual Demand-Side Management ("DSM") Report.
10. Recently, the Company requested to expand its reporting requirements for
the DER Status Report to document and assess the quantity and cost of system upgrades
caused by on-site generation customers to assess whether and when seeking to recover
ongoing operations and maintenance ("O&M") costs associated with those upgrades may
be prudent. The Company's proposal in this regard stemmed from the Commission
directing Idaho Power to meet with Staff to discuss the feasibility of implementing a
surcharge to recover the ongoing costs of system upgrades. In its compliance filing
submitted on March 28, 2024, the Company set forth the results of its evaluation, pursuant
to which the Company did not believe it was advisable to implement a surcharge at that
time. Instead, the Company recommended collecting additional data and using its annual
DER Status Report to track the quantity and cost of all upgrades for on-site generation
customers, along with an approximation of the associated ongoing operations and
maintenance Costs.12
11. The Company files its annual DER Status Report as a compliance filing in
closed Case No. IPC-E-12-27, which is a closed docket on the Commission's website. In
recent years, the Company has submitted this filing on or before April 30 of each year.
11 In the Matter of Idaho Power Company's Application for Authority to Establish Tariff Schedule 68, Case
No. IPC-E-20-30, Order No. 34955 at 11 (Mar. 9, 2021).
12 Case No. IPC-E-23-14, Compliance Filing at 5 (Mar. 28, 2024).
APPLICATION - 6

The Company also includes a link to its most recent three annual DER Status Reports in
its annual DSM Report, which is filed on or around March 15 of each year.
II. ECR METHODOLOGY
12. In Order No. 36048, the Commission approved a seasonal and time variant
ECR with avoided cost-based value considerations.13 The Commission-approved
summer season is June 1 through September 30. During the summer season, the on-
peak hours are 3 p.m. to 11 p.m. Monday through Saturday, excluding holidays, and the
off-peak hours during the summer season are between 11 p.m. and 3 p.m. Monday
through Saturday, and all hours on Sundays and holidays. The non-summer season is
October 1 through May 31, and during the non-summer season all hours are considered
off-peak.14 As approved by the Commission in Order No. 36048, the following are the
components of the ECR: Avoided Energy Costs, Avoided Line Losses, Integration Costs,
Avoided Generation Capacity, and Avoided or Deferred Transmission and Distribution
("T&D") Capacity Costs. A description of the Commission approved methods for
calculating each of these components is set forth below and further described in the
Ellsworth Testimony.
13. Avoided Energy Costs: The avoided energy costs are determined using
twelve months (January 1 through December 31) of Energy Imbalance Market ("EIM")
Load Aggregation Point ("ELAP") market prices, weighted for historical customer-
generator exports ("ELAP Weighted Average"). Avoided energy costs are distributed in
alignment with the summer and non-summer seasons.
13 Id., Order No. 36048 at 6.
14 Id.
APPLICATION - 7

14. Avoided Line Losses: Avoided line losses are valued using the most
recently completed line loss study. The Commission directed the Company to apply the
annual energy line losses to the avoided energy value. Further, the peak loss coefficient
is applied to the avoided capacity calculation.
15. Integration Costs: In Order No. 36048, the Commission approved the use
of the then most recently completed Variable Energy Resource ("VER") Study, which was
the 2020 VER Study. However, the Commission also directed Idaho Power to complete
an updated integration study as soon as possible and to file for Commission approval and
inclusion for future ECR updates. Integration costs are accounted for as an offset to the
avoided energy component.
16. Avoided Generation Capacity: Three primary inputs are used to determine
the avoided generation capacity value: (1) contribution to capacity (adjusted by the on-
peak line loss coefficient), (2) the cost of an alternative resource, and (3) the energy
exported during the on-peak hours. The avoided generation capacity value is applied to
the on-peak hours of the summer season.
17. The Commission approved the Effective Load Carrying Capacity ("ELCC")
method to calculate the capacity contribution for all on-site customer generation exports
that occur over the course of a year. ELCC values are individually calculated by year, and
these results are averaged to produce a five-year trailing average. The five-year average
ELCC is then multiplied by the maximum export value from the most-recently available
year's data; the resulting capacity contribution is then multiplied by the on-peak line loss
coefficient. This value represents the total capacity contribution utilized in the calculation
of the avoided generation capacity value.
APPLICATION - 8

18. The Company was ordered to use the most current levelized capacity cost
for the least-cost dispatchable resource from its most recently filed Integrated Resource
Plan ("IRP").
19. Avoided or Deferred T&D Capacity Costs: The Commission approved a
method where T&D capacity is valued using a project-by-project deferral analysis,
assessing every T&D capacity project over a 20-year time frame. To determine the 20-
year time frame the Company will reference the most recently filed IRP. The T&D capacity
value is applied to the on-peak hours of the summer season.
III. PROPOSED ECR UPDATE
20. Pursuant to Order No. 36048, the Company has reviewed and updated all
value components of the ECR as highlighted below, except the season and on- and off-
peak hours, which the Commission directed only be updated in a separate docket or in a
General Rate Case ("GRC") filing as appropriate. As a result, the Company proposes to
implement the following updated ECR values per kWh of exported energy for June 1,
2025, through May 31, 2026: 14.05980 for summer on-peak, 1.76820 for summer off-
peak, and 0.95400 for all hours during the non-summer season.
21. The proposed Schedule 6, Schedule 8, and Schedule 84 tariff schedules
incorporating the updated ECR values are included as Attachment 1 to this Application,
in both clean and legislative format.
22. A summary of the proposed updated values for each of the ECR
components is set forth in Figure 1 and more fully described, in turn, below along with a
comparison with existing ECR values and explanation of the primary drivers of the
differences.
APPLICATION - 9

Figure 1: Proposed ECR values
ECR SUMMARY
Season ECR
Export Profile
Volume(kWh per kW) Annual 1,362
Capacity Contribution(%) Annual 10.07%
Export Credit Rate by Component(cents/kWh)
Energy Summer 1.7682¢
Including integration and losses Non-Summer 0.95400
Annual* 1.28520
Generation Capacity On-Peak 11.90170
Off-Peak 0.00000
Annual* 1.13600
Transmission&Distribution Capacity On-Peak 0.3899 ¢
Off-Peak 0.00000
Annual* 0.03720
Total Summer On-Peak 14.05980
Summer Off-Peak 1.76820
Non-Summer 0.95400
Annual* 2.45850
*Annual values provided for informational purposes only and reflect seasonal weighting for 12
months ending December 2024.
Note:Summer season is defined as June 1 -September 30. On-Peak hours is defined as 3pm-
11pm, Monday-Saturday, excluding holidays. All other Summer hours defined as Off-Peak. Non-
Summer season defined as October I -May 31.
23. Avoided Energy Costs: To determine the avoided energy component, the
Company first used the 2024 hourly ELAP market prices, weighted for historical
customer-generator exports, and then included adjustments for avoided line losses and
integration costs and distributed the values in alignment with the summer and non-
summer season. The energy-related component (which includes avoided energy valued
at the weighted average ELAP prices, line losses, and integration), per kWh of exported
energy, are 1.76820 for the summer season and 0.95400 for the non-summer season.
24. The updated energy component decreased, primarily due to lower 2024
ELAP prices during export hours as compared to 2022 ELAP prices (those relied upon
APPLICATION - 10

for the ECR rates currently in effect). There are many factors that can lead to fluctuations
in ELAP prices. Overall, the ELAP prices are a function of supply and demand and lower
ELAP prices mean there was either high energy supply, or low demand, or both. Notably,
in the spring months there are more negative prices due to more hydropower output
during spring run-off conditions and more solar on the market combined with a lower
demand for electricity. This creates oversupply conditions, which can lead to negative
prices. Additional factors that affect prices include the cost of coal and gas and extreme
weather events.
25. Avoided Line Losses: The Company relied on its most recent line loss study,
which remains the 2023 line loss study (this study was also relied on to determine the
current ECR values). Specifically, in determining the proposed line loss values applied to
the energy component, the Company applied a loss coefficient of 1.044.
26. The proposed avoided per kWh line losses are 0.1040 and 0.0700 in the
summer and non-summer seasons, respectively, which compares to 0.2510 and 0.2160
for the same period in the current ECR. Because the specific line loss coefficients have
not changed — and the avoided line-losses are simply a function of the ELAP Weighted
Average and the coefficients — the driver of the decrease in the line losses was the result
of a lower ELAP Weighted Average in 2024.
27. Integration Costs: The Company relied on its 2024 VER Study, which was
completed in December 2024.15 The integration cost most appropriate to use in the ECR
15 On December 31, 2024, the Company made a compliance filing submitting its 2024 VER Integration
Study and accompanying Schedule 87 integration charges. Subsequently, the Commission opened a new
docket to consider the matter and issued a Notice of Filing and Intervention Deadline, Order No. 36510, on
March 14, 2024.
APPLICATION - 11

update is from the 0-100 megawatt solar portfolio, which translates to a reduction in the
energy component of 0.6970 per kWh. This compares to integration costs of 0.2930 per
kWh that are included in the current ECR.
28. Between the 2020 VER Study and the 2024 VER Study, the cost to integrate
solar resources with Idaho Power's system has increased, primarily attributed to an
increase in solar on Idaho Power's system. As the amount of solar on the system
increases, the need and use of integrating resources increases proportionally. It is the
increased need to provide more integration capability with the increased solar resources
that has increased the cost of integration.
29. Avoided Generation Capacity: The Company updated its five-year trailing
average ELCC to include 2023 and 2024. The ELCC values for years 2020 through 2024
were then averaged to produce an ELCC of 10.07 percent. To calculate the capacity
contribution the Company multiplied the updated average ELCC by the maximum export
value from 2024 (the latest year of available data) and the on-peak line loss coefficient.
As stated in the avoided line loss section above, the line losses have not been updated
since the current ECR was filed, therefore the Company is using the same on-peak line
loss coefficient of 1.053. The cost of an alternate resource was also not updated as the
Company has not filed a new IRP since it filed its current ECR values. The most recently
filed IRP is the 2023 IRP and the least cost dispatchable resource is a simple cycle
combustion turbine at a cost of $145.94/kilowatt-year. The energy generated during on-
peak hours was updated using 2024 customer exports.
30. The generation capacity value of 11.90170 per kWh is only applied to the
summer on-peak hours.
APPLICATION - 12

31. As noted above, only the ELCC, the maximum export value, and the energy
generated during on-peak hours changed. The maximum export value and the energy
generated during on-peak hours both increased because of more customer generators
on the Company's system in 2024 versus 2022, the year used in the current ECR. The
updated average ELCC value is 10.07 percent as compared to 10.12 percent from the
current ECR.
32. Avoided or Deferred T&D Capacity Costs: Using the Commission-approved
methodology to determine the value of on-site generation in deferring the need for the
Company to build additional T&D resources, the Company identified local peak hours for
each T&D resource. Local peak hours are specific to the amount of types of loads
connected to individual resources. The analysis incorporated the 20 years of project data
from the 2023 IRP, 2007 to 2026, to identify the historical trends and projected T&D
projects and the capacity need for each project.
33. The updated avoided or deferred T&D capacity costs, per kWh of exported
energy for summer on-peak is 0.38990 compared to 0.17550 in the current ECR.
34. The primary driver of the increase in the avoided or deferred T&D capacity
costs was related to an increase in solar penetration from 0.61 percent to 2.12 percent
and an increase in customer generator exports. Using 20 years of project data from the
2023 IRP, the number of deferrable T&D projects increased from nine to 42, which
increased the dollar value of deferral savings.
IV. BILL IMPACTS
35. As of December 31, 2024, the Company had a total 13,825 active and
pending non-legacy Exporting Systems in its Idaho jurisdiction. The DER Status Report
APPLICATION - 13

included as Attachment 2 to this Application contains count of systems by customer class
and total installed nameplate capacity by customer class.
36. Included with the Taylor Testimony are Exhibit Nos. 6, 7, 8, and 9, which
summarize the bill impact for residential, small general service, large general service, and
irrigation customers, respectively.
37. Generally, the bill impact analysis relies on 12 months of hourly metering
data ending December 31, 2024, for non-legacy customers with Exporting Systems who
were online for all of calendar year 2024. To isolate the impact from a change in the ECR,
the Company estimated annual bills for delivered services using base rates currently in
effect. The Company then estimated the annual financial credit associated with exported
energy under both the ECR currently in effect and then with the proposed ECR. Finally,
the analysis quantifies an average monthly bill under the current ECR and an average
monthly bill under the proposed ECR. The Taylor Testimony provides an overview of the
results of the bill impact analysis for each of the customer classes.
V. CONSOLIDATION OF COMPLIANCE REPORTING REQUIREMENTS
38. This filing represents the Company's inaugural update of the ECR for non-
legacy on-site generation customers in accordance with Commission Order No. 36048,
which will hereafter continue annually with a filing date of April 1 and an effective date of
June 1. As noted, the Company also files annually in April its DER Status Report, which
is the primary means by which the Company apprises the Commission of activity related
to on-site generation, as a compliance filing in a closed docket (Case No. IPC-E-12-27).16
16 The Company also includes a link in its annual DSM Report, which is filed on or around March 15 of each
year, to its most recent three annual DER Status Reports.
APPLICATION - 14

The DER Status Report has historically been filed by the Company on or before April 30tn
of each year, though this timing was based on course of practice rather than mandated
by Commission order, and the Company believes that moving forward the most
expeditious approach would be to align the filing of the DER Status Report with its annual
ECR update based on the April 1 st date directed by the Commission for the latter.
39. Moreover, the Company is concerned that submitting the DER Status
Report in a closed docket, as has previously been done, does not provide broad visibility
for interested stakeholders, as more fully describe in the Taylor Testimony, and suggests
another procedure be utilized moving forward. More specifically, the Company believes
that submitting its annual DER Status Report concurrently with its annual filing to update
the ECR will increase transparency for the Commission, Staff, customers, and other
stakeholders. Moreover, because the DER Status Report contains information that is
relevant to the annual ECR update (namely, the number of customers who will be
impacted by an update to the ECR), filing these together will make it easier to access and
compare that information. Finally, filing the DER Status Report with the ECR update will
make it more accessible to those who are less familiar with the historical case files on the
Commission's website or may not realize the information is available in unrelated or
closed dockets.
40. As such, the Company notifies the Commission that it is submitting its
annual DER Status Report concurrently with its annual ECR update and intends to follow
this approach moving forward on the April 1 st filing deadline, and respectfully requests the
Commission advise if it prefers a different procedural approach.
APPLICATION - 15

VI. MODIFIED PROCEDURE
41. 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. The Company has, however, contemporaneously filed the Ellsworth Testimony
and Taylor Testimony and stands ready to present its testimony and support the
Application if the Commission determines a technical hearing is required.
VII. COMMUNICATIONS AND SERVICE OF PLEADINGS
42. This Application will be brought to the attention of impacted customers by
means of a post card sent to all non-legacy Schedule 6, 8, or 84 customers. A copy of
the customer communication is included as Attachment 3 to this Application. The
customer notice will be mailed to customers following the filing of this Application, with all
post cards being mailed no later than the week of April 14t". Additionally, the Company
will send new on-site generation applicants (those who submit an application between
April 1 and May 31, 2025) an email upon receipt of application containing information
about this filing and the proposed ECR.
43. Communications and service of pleadings with reference to this Application
should be sent to the following:
Megan Goicoechea Allen Connie Aschenbrenner
Donovan Walker Mary Alice Taylor
Regulatory Dockets Idaho Power Company
Idaho Power Company 1221 West Idaho Street (83702)
1221 West Idaho Street (83702) P.O. Box 70
P.O. Box 70 Boise, Idaho 83707
Boise, Idaho 83707 caschenbrenner(a�_idahopower.com
mgoicoeacheaallen(a-)idahopower.com [e-mail]
[e-mail]
[e-mail]
APPLICATION - 16

VIII. REQUEST FOR RELIEF
44. As described in greater detail above, Idaho Power respectfully requests that
the Commission issue an order: (1) authorizing that this matter be processed by Modified
Procedure, and (2) authorizing Idaho Power to implement the updated ECR for non-
legacy on-site generation customers from June 1, 2025 through May 31, 2026 of
14.05980 per kWh for summer on-peak, 1.76820 per kWh for summer-off peak, and
0.95400 per kWh for all hours during the non-summer season.
DATED at Boise, Idaho this 1st day of April 2025.
MEGAN GOICOECHEA ALLEN
Attorney for Idaho Power Company
APPLICATION - 17

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-15
IDAHO POWER COMPANY
ATTACHMENT 1
PROPOSED TARIFF SCHEDULES

Idaho Power Company Third Revised Sheet No. 6-9
Cancels
I.P.U.C. No. 30, Tariff No. 101 Second Revised Sheet No. 6-9
SCHEDULE6
RESIDENTIAL SERVICE
ON-SITE GENERATION
(Continued)
MONTHLY CHARGE
The Monthly Charge is the sum of the following charges, and may also include charges as set forth
in Schedule 54 (Fixed Cost Adjustment), Schedule 55 (Power Cost Adjustment), Schedule 91 (Energy
Efficiency Rider), Schedule 95 (Adjustment for Municipal Franchise Fees), Schedule 96 (Blaine County
Surcharge to Fund the Undergrounding of Certain Facilities), and Schedule 98 (Residential and Small Farm
Energy Credit).
The following rate structure and charges are subject to change upon Commission approval:
STANDARD RATES (DEFAULT)
Summer Non-summer
Service Charge, per month $15.00 $15.00
Energy Charge, per kWh
First 800 kWh 9.93980 8.74760
801-2000 kWh 11.95180 9.64390
All Additional kWh Over 2000 14.19850 10.68050
TIME-OF-USE RATES (OPTIONAL)
Summer Non-summer
Service Charge, per month $15.00 $15.00
Energy Charge, per kWh
On-Peak 24.73980 12.82670
Mid-Peak 12.37010 n/a
Off-Peak 6.18500 8.55110
EXPORT CREDIT RATE
The following rate structure and credits are subject to change upon Commission approval:
Summer Non-summer
Export Credit Rate, per kWh
On-Peak 14.05980 0.95400
Off-Peak 1.76820 0.95400
PAYMENT
The monthly bill rendered for service supplied hereunder is payable upon receipt, and becomes
past due 15 days from the date on which rendered.
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective — June 1, 2025 1221 West Idaho Street, Boise, Idaho

Idaho Power Company Third Revised Sheet No. 8-8
Cancels
I.P.U.C. No. 30, Tariff No. 101 Second Revised Sheet No. 8-8
SCHEDULE8
SMALL GENERAL SERVICE
ON-SITE GENERATION
(Continued)
MONTHLY CHARGE (Continued)
The following charges are subject to change upon Commission approval:
Summer Non-summer
Service Charge, per month $25.00 $25.00
Energy Charge, per kWh
First 300 kWh 7.17820 7.17820
All Additional kWh 8.20320 7.18000
EXPORT CREDIT RATE
The following rate structure and credits are subject to change upon Commission approval:
Summer Non-summer
Export Credit Rate, per kWh
On-Peak 14.05980 0.95400
Off-Peak 1.76820 0.95400
PAYMENT
The monthly bill rendered for service supplied hereunder is payable upon receipt, and becomes
past due 15 days from the date on which rendered.
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective — June 1, 2025 1221 West Idaho Street, Boise, Idaho

Idaho Power Company First Revised Sheet No. 84-9
Cancels
I.P.U.C. No. 30, Tariff No. 101 Original Sheet No. 84-9
SCHEDULE 84
LARGE GENERAL, LARGE POWER, AND IRRIGATION
ON-SITE GENERATION SERVICE
(Continued)
SUMMER AND NON-SUMMER SEASONS
The summer season begins on June 1 of each year and ends on September 30 of each year.
The non-summer season begins on October 1 of each year and ends on May 31 of each year.
TIME PERIODS — EXPORT CREDIT RATE
The time periods for the Export Credit Rate are defined as follows. All times are stated in
Mountain Time.
Summer Season
On-Peak: 3:00 p.m. to 11:00 p.m. Monday through Saturday, except holidays
Off-Peak: 11:00 p.m. to 3:00 p.m. Monday through Saturday and all hours on
Sunday and holidays
Non-summer Season
Off-Peak: All hours Monday through Sunday
Holidays are New Year's Day (January 1), Memorial Day (last Monday in May), Independence
Day (July 4), Labor Day (first Monday in September), Thanksgiving Day (fourth Thursday in November),
and Christmas Day (December 25). If New Year's Day, Independence Day, or Christmas Day falls on
Saturday, the preceding Friday will be designated a holiday. If New Year's Day, Independence Day, or
Christmas Day falls on Sunday, the following Monday will be designated a holiday.
EXPORT CREDIT RATE
The following rate structure and credits are subject to change upon Commission approval:
Summer Non-summer
Export Credit Rate, per kWh
On-Peak: 14.05980 0.95400
Off-Peak: 1.76820 0.95400
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective —June 1, 2025 1221 West Idaho Street, Boise, Idaho

Idaho Power Company SeGGRd-Third Revised Sheet No. 6-9
Cancels
I.P.U.C. No. 30, Tariff No. 101 €4&t-Second Revised Sheet No. 6-9
SCHEDULE6
RESIDENTIAL SERVICE
ON-SITE GENERATION
(Continued)
MONTHLY CHARGE
The Monthly Charge is the sum of the following charges, and may also include charges as set forth
in Schedule 54 (Fixed Cost Adjustment), Schedule 55 (Power Cost Adjustment), Schedule 91 (Energy
Efficiency Rider), Schedule 95 (Adjustment for Municipal Franchise Fees), Schedule 96 (Blaine County
Surcharge to Fund the Undergrounding of Certain Facilities), and Schedule 98 (Residential and Small Farm
Energy Credit).
The following rate structure and charges are subject to change upon Commission approval:
STANDARD RATES (DEFAULT)
Summer Non-summer
Service Charge, per month $15.00 $15.00
Energy Charge, per kWh
First 800 kWh 9.93980 8.74760
801-2000 kWh 11.95180 9.64390
All Additional kWh Over 2000 14.19850 10.68050
TIME-OF-USE RATES (OPTIONAL)
Summer Non-summer
Service Charge, per month $15.00 $15.00
Energy Charge, per kWh
On-Peak 24.73980 12.82670
Mid-Peak 12.37010 n/a
Off-Peak 6.18500 8.55110
EXPORT CREDIT RATE
The following rate structure and credits are subject to change upon Commission approval:
Summer Non-summer
Export Credit Rate, per kWh
On-Peak 16.996614.0598¢ 4.83650.95400
Off-Peak 5.65331.7682¢ 4.836550.95400
PAYMENT
The monthly bill rendered for service supplied hereunder is payable upon receipt, and becomes
past due 15 days from the date on which rendered.
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. 36438 Timothy E. Tatum, Vice President, Regulatory Affairs
Effective—_ February , 2-025June 1, 2025 1221 West Idaho Street, Boise, Idaho

Idaho Power Company SeGGRd-Third Revised Sheet No. 8-8
Cancels
I.P.U.C. No. 30, Tariff No. 101 F4st-Second Revised Sheet No. 8-8
SCHEDULE8
SMALL GENERAL SERVICE
ON-SITE GENERATION
(Continued)
MONTHLY CHARGE (Continued)
The following charges are subject to change upon Commission approval:
Summer Non-summer
Service Charge, per month $25.00 $25.00
Energy Charge, per kWh
First 300 kWh 7.17820 7.17820
All Additional kWh 8.20320 7.18000
EXPORT CREDIT RATE
The following rate structure and credits are subject to change upon Commission approval:
Summer Non-summer
Export Credit Rate, per kWh
On-Peak 16.996614.05980 4.83650.95400
Off-Peak 5.65331.76820 4.83650.95400
PAYMENT
The monthly bill rendered for service supplied hereunder is payable upon receipt, and becomes
past due 15 days from the date on which rendered.
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. 86439 Timothy E. Tatum, Vice President, Regulatory Affairs
Effective— February 1, 2025 1221 West Idaho Street, Boise, Idaho

Idaho Power Company First Revised Sheet No. 84-9
Cancels
I.P.U.C. No. 30, Tariff No. 101 Original Sheet No. 84-9
SCHEDULE 84
LARGE GENERAL, LARGE POWER, AND IRRIGATION
ON-SITE GENERATION SERVICE
(Continued)
SUMMER AND NON-SUMMER SEASONS
The summer season begins on June 1 of each year and ends on September 30 of each year.
The non-summer season begins on October 1 of each year and ends on May 31 of each year.
TIME PERIODS — EXPORT CREDIT RATE
The time periods for the Export Credit Rate are defined as follows. All times are stated in
Mountain Time.
Summer Season
On-Peak: 3:00 p.m. to 11:00 p.m. Monday through Saturday, except holidays
Off-Peak: 11:00 p.m. to 3:00 p.m. Monday through Saturday and all hours on
Sunday and holidays
Non-summer Season
Off-Peak: All hours Monday through Sunday
Holidays are New Year's Day (January 1), Memorial Day (last Monday in May), Independence
Day (July 4), Labor Day (first Monday in September), Thanksgiving Day (fourth Thursday in November),
and Christmas Day (December 25). If New Year's Day, Independence Day, or Christmas Day falls on
Saturday, the preceding Friday will be designated a holiday. If New Year's Day, Independence Day, or
Christmas Day falls on Sunday, the following Monday will be designated a holiday.
EXPORT CREDIT RATE
The following rate structure and credits are subject to change upon Commission approval:
Summer Non-summer
Export Credit Rate, per kWh
On-Peak: 16.996614.05980 4.83650.95400
Off-Peak: 5.65331.76820 4.83650.95400
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. 36042 R 36 Timothy E. Tatum, Vice President, Regulatory Affairs
Effective— JaRuary 1, 2024June 1, 2025 1221 West Idaho Street, Boise, Idaho

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-15
IDAHO POWER COMPANY
ATTACHMENT 2
2024 ANNUAL DER STATUS REPORT

HIDAHO Fuwr.R.
2024 Distributed Energy
Resources Annual Report
April 2025
© Idaho Power

Idaho Power Company Introduction and Table of Contents
INTRODUCTION
Idaho Power Company ("Idaho Power" or "Company") presents its annual Distributed Energy
Resources ("DER") Status Report to the Idaho Public Utilities Commission ("Commission") as
required by Order Nos. 328461 and 329252, Order No. 349553, and Order No. 3615 94. The report
begins with a brief regulatory update on recent orders impacting the compensation structure
applicable to customers with DERs, followed by an update on current participation levels and
growth rates since the Company's last DER Status Report filed with the Commission in April 2024.
Next, the report discusses system reliability considerations, and provides an update on meter
aggregation activity, credit transfers, and accumulated excess net energy credits. Finally, it
concludes with a discussion on system upgrades caused by on-site generation customers and
provides an update of the ongoing operations and maintenance ("O&W) costs associated with
those upgrades.
Tableof Contents.......................................................................................................................... 1
Introduction.................................................................................................................................. 1
Listof Tables .................................................................................................................................2
Listof Figures................................................................................................................................2
I. Customer Generation in Idaho................................................................................................4
RegulatoryBackground...........................................................................................................4
Current Participation (Exporting Systems) ..............................................................................5
LegacySystems.................................................................................................................. 6
Non-Legacy Systems.......................................................................................................... 7
TotalSystems .................................................................................................................... 8
II. System Reliability Considerations ......................................................................................... 10
1 In the Matter of the Application of Idaho Power Company for Authority to Modify its Net Metering Service and to
Increase the Generation Capacity Limit,Case No. IPC-E-12-27, Order No.32846 at 19 (July 3, 2013).
z Id., Order No. 32925 at 7(Nov. 19,2013).
3 In the Matter of Idaho Power Company's Application to Establish Tariff Schedule 68—Interconnections to Customer
Distributed Energy Resources,Case No. IPC-E-20-30, Order No.34955 at 11 (Mar. 9, 2021).
4 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,Order No. 36159 at 2(Apr. 30, 2024).
Distributed Energy Resources 2024 Annual Report Page 1

Idaho Power Company Introduction and Table of Contents
Installation Concentration versus Capacity........................................................................... 10
SmartInverter Installation .................................................................................................... 11
III. 2024 Excess Net Credit Transfers.......................................................................................... 12
Meter Aggregation Eligibility- Legacy.................................................................................... 12
Meter Aggregation Eligibility- Non-Legacy............................................................................ 12
Customer Communication .................................................................................................... 13
Credit Transfer Requests for Calendar Year 2024 ................................................................. 13
Credit Transfer Magnitude- Legacy....................................................................................... 15
Credit Transfer Magnitude- Non-Legacy............................................................................... 15
Accumulated Excess Net Energy Credit Balances.................................................................. 16
Accumulated Excess Net Financial Credit Balances............................................................... 16
IV. System Upgrades and O&M Costs......................................................................................... 17
System Upgrades and O&M Costs......................................................................................... 17
V. Conclusion............................................................................................................................. 18
LIST OF TABLES
Table 1 Legacy- Idaho Active Exporting Systems as of December 31, 2024.............................6
Table 2 Legacy- Idaho Active Exporting Systems Nameplate Capacity (MW) as of
December31, 2024..................................................................................................... 6
Table 3 Non-Legacy- Idaho Active and Pending Exporting Systems as of December 31,
2024 ............................................................................................................................ 7
Table 4 Non-Legacy- Idaho Active and Pending Exporting Systems Nameplate
Capacity (MW) as of December 31, 2024....................................................................7
Table 5 System Upgrades and O&M Costs............................................................................. 17
LIST OF FIGURES
Figure 1 Cumulative Exporting System Counts by Customer Type, 2015—2024.......................8
Figure 2 Cumulative Exporting System Capacity by Customer Type, 2015—2024....................9
Figure 3 Excess Net Energy Credit Transfers by Customer Class, 2020—2024........................ 15
Figure 4 Excess Net Financial Credit Transfers by Customer Class, 2024 ................................ 15
Distributed Energy Resources 2024 Annual Report Page 2

Idaho Power Company Introduction and Table of Contents
Figure 5 Accumulated Unused Excess Net Energy Credit Balance, 2015—2024 ..................... 16
Distributed Energy Resources 2024 Annual Report Page 3

Idaho Power Company Customer Generation in Idaho
I. CUSTOMER GENERATION IN IDAHO
Regulatory Background
Over the last several years, Idaho Power, as directed by the Commission, has engaged in a
series of cases related to studying the costs and benefits of on-site generation on the Company's
system. In 2019 and 2020, the Commission established "legacy" and "non-legacy" status for
residential and small general service customers and commercial, industrial, and irrigation
customers, respectively.'Through their orders, the Commission found that legacy customers will
continue to participate in net energy metering (one-for-one kWh credit for excess net energy)
under certain criteria through 20451 and non-legacy customers would be subject to future
changes to the program fundamentals, including to the compensation structure applied to excess
energy.The Commission also ordered the Company to undertake a comprehensive study process
before any changes applicable to non-legacy customer compensation would be considered.'
Idaho Power undertook this study process throughout 2021 and 2022.8 Ultimately, the
Commission found the Company had complied with its previous orders by acknowledging the
Company's October 2022 Value of Distributed Energy Resource study.9 In that order, the
S In the Matter of the Petition of Idaho Power Company to Study the Costs, Benefits,and Compensation of Net Excess
Energy Supplied by Customer On-Site Generation,Case No. IPC-E-18-15,Order No. 34509 at 10(Dec. 20,2019);In
the Matter of Idaho Power Company's Application for Authority to Modify Schedule 84's Metering Requirement
and to Grandfather Existing Customers with Two Meters, IPC-E-20-26,Order No.34854 at 10(Dec. 1, 2020).
6 In the Matter of the Petition of Idaho Power Company to Study the Costs,Benefits,and Compensation of Net Excess
Energy Supplied by Customer On-Site Generation, Case No.IPC-E-18-15,Order No.34546 at 9(Feb.5,2020);In the
Matter of Idaho Power Company's Application for Authority to Modify Schedule 84's Metering Requirement and to
Grandfather Existing Customers with Two Meters, Case No. IPC-E-20-26,Order No. 34854 at 10(Dec. 1,2020).
In the Matter of the Application of Idaho Power Company for Authority to Establish New Schedules for Residential
and Small General Service Customers with On-Site Generation, Case No. IPC-E-17-13,Order No. 34046 at 22(May
9, 2018).
8 In the Matter of the Application of Idaho Power Company's Application to Initiate a Multi-Phase Collaborative
Process for the Study of Costs, Benefits,and Compensation of Net Excess Energy Associated with Customer On-Site
Generation, Case No. IPC-E-21-21; In the Matter of Idaho Power Company's Application to Complete the Study
Review Phase of the Comprehensive Study of Costs and Benefits of On-Site Customer Generation & For Authority
to Implement Changes to Schedules 6, 8, and 84 for Non-Legacy Systems, Case No. IPC-E-22-22.
s In the Matter of Idaho Power Company's Application to Complete the Study Review Phase of the Comprehensive
Study of Costs and Benefits of On-Site Customer Generation&for Authority to Implement Changes to Schedules 6,
8, and 84, Case No. IPC-E-22-22,Order No.35631 at 31(Dec. 19,2022).
Distributed Energy Resources 2024 Annual Report Page 4

Idaho Power Company Customer Generation in Idaho
Commission also directed the Company to file a new case requesting to implement changes to
its on-site generation offering.10
On May 1, 2023, Idaho Power filed Case No. IPC-E-23-14, where it sought to implement
changes to the on-site generation offering, which included a modified compensation structure
(net billing) that would be applicable to non-legacy on-site generation customers. Under net
billing,customers continue to offset their usage with all on-site production consumed on-site and
are compensated per kWh exported with an avoided cost-based export credit rate ("ECR") that
varies based on the season and time of export. In Order No. 36048, the Commission approved
the Company's filing, with modifications, and authorized new program parameters to take effect
with non-legacy customers' January 2024 billing period.11 In that same order, the Commission
directed Idaho Power to meet with Staff to discuss the feasibility of implementing a surcharge to
recover the ongoing costs of system upgrades and to submit its findings to the Commission by
means of a compliance filing.12 On March 28, 2024, Idaho Power submitted a compliance filing
setting forth the results of its evaluation, pursuant to which the Company did not believe it was
advisable to implement a surcharge at that time. Instead,the Company recommended collecting
additional data and expanding its reporting requirements to help assess whether and when
seeking to recover ongoing O&M caused by system upgrades may be warranted. More
specifically,the Company proposed to document and assess the quantity and cost of all upgrades
for on-site generation customers, as part of its annual DER Status Report. The Commission
accepted the Company's filing as complying with the requirements set forth in Order No. 36048.11
As a result of the recent changes to the Company's on-site generation offering, this year's
DER Status Report contains additional elements related to: (1) meter aggregation (as 2024 was
the first-year non-legacy customers were eligible to transfer financial credits), and (2) updated
reporting requirements related to the quantity and cost of all upgrades for on-site generation
customers,along with an approximation of their associated ongoing operations and maintenance
costs.
10 Id.
11 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 Order No.36048 at 6 and 18(Dec. 29, 2023).
12 Id., at 7.
13 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 Order No.36159 at 1 (Apr.30, 2024).
Distributed Energy Resources 2024 Annual Report Page 5

Idaho Power Company Customer Generation in Idaho
Current Participation (Exporting Systems)
As of December 31, 2024, Idaho Power had 19,323 total active and pending On-Site
Generation Exporting Systems ("Exporting Systems")14 with a cumulative nameplate capacity of
188.68 megawatts("MW") in its Idaho service area.All new systems interconnected in 2024 were
solar photovoltaic ("PV").
Legacy Systems
Table 1 provides the total number of active Exporting Systems with legacy status in the
Company's Idaho jurisdiction by resource type and customer class.
Table 1 Legacy- Idaho Active Exporting Systems as of December 31, 2024
Customer Segment Solar PV Wind Hydro/Other Total
Schedule 6
Residential 5,055 21 7 5,083
Schedule 8
Small General 43 - 2 45
Schedule 84
Commercial & Industrial 162 - 1 163
Irrigation 207 - - 207
Total 5,467 21 10 5,498
Table 2 provides the total nameplate capacity of active Exporting Systems with legacy status in
the Company's Idaho jurisdiction by resource type and customer class.
Table 2 Legacy- Idaho Active Exporting Systems Nameplate Capacity(MW) as of December 31,
2024
Customer Segment Solar PV Wind Hydro/Other Total
Schedule 6
Residential 39.66 0.10 0.07 39.82
Schedule 8
Small General 0.30 - 0.05 0.34
14 Exporting Systems take service under the terms of Schedule 6, Residential Service On-Site Generation ("Schedule
6"), Schedule 8, Small General On-Site Generation ("Schedule 8"), and Schedule 84, Large General, Large Power,
and Irrigation On-Site Generation ("Schedule 84")and are designed to transfer excess energy to the Company.
Distributed Energy Resources 2024 Annual Report Page 6

Idaho Power Company Customer Generation in Idaho
Customer Segment Solar PV Wind Hydro/Other Total
Schedule 84
Commercial & Industrial 5.60 - 0.03 5.62
Irrigation 19.50 - - 19.50
Total 65.05 0.10 0.14 65.30
Note:Totals may not sum due to rounding.
Non-Legacy Systems
Table 3 provides the total number of active and pending Exporting Systems with non-legacy
status in the Company's Idaho jurisdiction by resource type and customer class.
Table 3 Non-Legacy- Idaho Active and Pending Exporting Systems as of December 31, 2024
Customer Segment Solar PV Wind Hydro/Other Total
Schedule 6
Residential 13,599 1 1 13,601
Schedule 8
Small General 35 - - 35
Schedule 84
Commercial & Industrial 102 - - 102
Irrigation 87 - - 87
Total 13,823 1 1 13,825
Table 4 provides the total nameplate capacity of active and pending Exporting Systems with
non-legacy status in the Company's Idaho jurisdiction by resource type and customer class.
Table 4 Non-Legacy- Idaho Active and Pending Exporting Systems Nameplate Capacity(MW)as of
December 31, 2024
Customer Segment Solar PV Wind Hydro/Other Total
Schedule 6
Residential 105.31 0.002 0.004 105.31
Schedule 8
Small General 0.33 - - 0.33
Schedule 84
Commercial & Industrial 4.49 - - 4.49
Irrigation 13.26 - - 13.26
Total 123.38 0.002 0.004 123.38
Note:Totals may not sum due to rounding.
Distributed Energy Resources 2024 Annual Report Page 7

Idaho Power Company Customer Generation in Idaho
Total Systems
Figures 1 and 2 detail the cumulative customer Exporting System counts and nameplate
capacity, respectively, by customer class in the Company's Idaho jurisdiction regardless of legacy
status, from 2015 through the end of calendar year 2024 (including pending applications).
Figure 1 Cumulative Exporting System Counts by Customer Type, 2015—2024
20,000
18,000 •
16,000
14,000
c
0 12,000
U
E 10,000
m
y, 8,000
Cn 6,000
4,000
2,000 .
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
■Residential ■Commercial & Industrial ■ Irrigation
Distributed Energy Resources 2024 Annual Report Page 8

Idaho Power Company Customer Generation in Idaho
Figure 2 Cumulative Exporting System Capacity by Customer Type,2015—2024
200
180
160
140
2 120
E 100
a 80
v 60
40
20 ■
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
■Residential ■Commercial & Industrial ■ Irrigation
Distributed Energy Resources 2024 Annual Report Page 9

Idaho Power Company System Reliability Considerations
II. SYSTEM RELIABILITY CONSIDERATIONS
There are 698 electrical distribution circuits in the Company's service area. Considering all
customer-owned on-site generation installations across all jurisdictions, all rate classes, and all
resources, as of December 31, 2024, there were 19,185 active, customer-owned on-site
generation systems. These systems total approximately 182.8 MW on 538 distribution circuits.
Installation Concentration versus Capacity
The circuits containing the greatest number of customer-owned on-site generation systems
are in Ada and Elmore County,with the densest concentrations in southeast and south Boise and
north Mountain Home. The largest number of customer-owned on-site generation systems
connected on a single distribution circuit is 255, with a total rated capacity of 1,707 kilowatts
("kW"). This circuit primarily serves residential customers in Boise.
The distribution circuit in Idaho with the greatest customer-owned on-site generation
capacity primarily serves irrigation and rural customers in the Magic Valley and has a total of 30
solar PV systems with a total rated capacity of 2,823 kW (average system size 94 kW).This circuit
has a summer peak load of approximately 7,200 kW. The distribution circuit in Idaho with the
second-highest customer-owned on-site generation capacity also serves irrigation and rural
customers in the Magic Valley and has a total of 68 solar PV systems with a total rated capacity
of 1,970 kW (average system size is 29 kW).This circuit has a summer peak load of approximately
19,400 kW.
There are 20 circuits with total customer-owned on-site generation capacity greater than
1,000 kW.Those 20 circuits hosted a total of 29.4 MW of generation. Twelve of these circuits are
in the Magic Valley(one serves industrial and residential customers,and all others serve irrigation
and rural customer loads). Of the remaining, five are in Ada County, two in Canyon County, and
one in Elmore County, all of which primarily serve residential customers.
The customer-owned on-site generation connected capacity on the Company's distribution
system as a percent of the total system peak load in 2024 was 4.7 percent. The Company has
managed the impacts on these circuits, when necessary, by requiring customer-funded
distribution upgrades pursuant to Rule H and, in very rare instances, requiring customer-funded
substation upgrades.
Distributed Energy Resources 2024 Annual Report Page 10

Idaho Power Company System Reliability Considerations
Smart Inverter Installation
All new systems applying to interconnect are required to install smart inverters15 to support
the distribution system's ongoing stability and reliability. As of January 1, 2024, Idaho Power
requires inverters to comply with the IEEE 1547-2018 certification16 which meet all smart inverter
requirements as defined by the Institute of Electrical and Electronics Engineers ("IEEE").The IEEE
Standard 1547 establishes the technical standard for interconnection and interoperability of
distributed energy resources and Idaho Power is an active participant in the review process of
this standard which is expected to be updated and revised in 2026.
1s Order No. 34955 issued in Case No. IPC-E-20-30 approved Schedule 68, effective March 23, 2021. Schedule 68
requires smart inverter functionality to be enabled for all new applications for customer generation.
16 Underwriters Laboratories Standard for Safety 1741 — Inverters, Converters, Controllers and Interconnection
System Equipment for Use with Distributed Energy Resources,Supplement B.
Distributed Energy Resources 2024 Annual Report Page 11

Idaho Power Company 2024 Excess Net Credit Transfers
III. 2024 EXCESS NET CREDIT TRANSFERS
Meter Aggregation Eligibility- Legacy
Schedules 6, 8, and 84 provide legacy customers with Exporting Systems the ability to submit
requests to transfer excess net energy credits annually. Applications must be received by January
31 and the Company applies the following criteria for legacy systems to all requests received
from legacy customers:
i. The account subject to offset is held by the customer; and
ii. The meter is located on, or contiguous to, the property on which the Designated Meter
(the meter psychically connected to the Exporting System) is located. For the purposes of
the tariff, contiguous property includes property that is separated from the premises of
the Designated Meter by public or railroad rights of way; and
iii. The meter is served by the same primary feeder as the Designated Meter at the time the
customer files the application for the Exporting System; and
iv. The electricity recorded by the meter is for the customer's requirements; and
v. For customers taking service under Schedule 6, or Schedule 8 credits may only be
transferred to meters taking service under Schedule 1, Schedule 6, Schedule 7, or
Schedule 8. For Schedule 84 customers taking service under Schedule 9, Schedule 19, or
Schedule 24, credits may only be transferred to meters taking service under Schedule 9,
Schedule 19, or Schedule 24.17
Meter Aggregation Eligibility- Non-Legacy
Schedules 6, 8, and 84 also provide non-legacy customers with Exporting Systems the ability
to submit requests to transfer excess net financial credits annually.Applications must be received
by January 31 and the Company applies the following criteria for non-legacy systems from
Schedules 6, 8, and 84 to all requests received from non-legacy customers:
i. The account subject to offset is held by the customer; and
ii. The electricity recorded by the meter is for the customers' requirements.
i7 Schedule 84 is an "adder" in Idaho Power's billing system. Schedules 9, 19, and 24 customers take service under
those primary schedules and those with on-site generation have 84 added to their primary service schedule.
Distributed Energy Resources 2024 Annual Report Page 12

Idaho Power Company 2024 Excess Net Credit Transfers
Customer Communication
In November 2024, prior to the credit transfer window opening on December 1, Schedule 6,
8, and 84 customers with excess net energy or net financial credits were sent a postcard
reminding them of the meter aggregation process, a list of important things to note about the
transfer process, the deadline for them to apply, and a phone number to contact. The postcard
also contained a web address which contains the requirements and an online form.This postcard
was sent to a total of 5,861 legacy and non-legacy customers.
In January 2025, the Company sent an email or provided a bill message on Schedule 6, 8, and
84 customers' bills to inform them of when the transfer window closed and to provide a link to a
webpage where customers could find more information. Lastly, in January the Company also sent
an email reminder to 121 customers who submitted transfer requests in 2023 but had not yet
submitted a request for 2024. This email reminded these customers of the meter aggregation
process and deadline and provided a link for them to submit a transfer request.
Credit Transfer Requests for Calendar Year 2024
As of the application deadline, January 31, 2025, the Company received 344 applications for
transfer. Of the total transfer requests, 231 applications were from legacy customers and 113
were from non-legacy customers. The applications were reviewed against the applicable
aggregation criteria and the Company determined that 303 of the requests were eligible for
transfer based on the aggregation criteria. Of the eligible transfer requests, 201 were from legacy
customers and 102 were from non-legacy customers.
The total amount of kWh credits transferred was 14,693,176 kilowatt-hours ("kWh")
generated from Exporting Systems taking service under Irrigation (89 percent), Large General
(seven percent), Residential (four percent), and Small General (one percent) rate schedules. The
14,693,176 kWh were transferred to customers taking service under Irrigation (77 percent), Large
General (eight percent), Residential (four percent), and Small General (less than one percent)
rate schedules.
The total amount of financial credits transferred was $16,989 from Exporting Systems taking
service under Large General (81 percent) and Residential (19 percent) rate schedules. The
$16,989 was transferred to customers taking service under Irrigation (three percent), Large
General (81 percent), Residential (nine percent), and Small General (eight percent) rate
schedules. 18
11 Totals may not sum due to rounding.
Distributed Energy Resources 2024 Annual Report Page 13

Idaho Power Company 2024 Excess Net Credit Transfers
The Company received 41 applications that were ineligible for transfer based on the
following:
Legacy
• Four applications requested a transfer to a meter that was not on contiguous property.
• One application was not on the same feeder.
• Two applications requested to transfer to rate schedules that do not qualify.
• 12 failed due to two or more of the criteria not being met.
• 11 applications did not qualify for other reasons.19
Non-Legacy
• Four applications had no excess credits.
• Two applications were from meters that were not an on-site generation service meter (a
"designated meter").
• Five applications did not qualify for other reasons.
The Company sent letters to all customers whose requests were ineligible for transfer explaining
the reason for the denial.
19 Other reasons include a variety of scenarios, examples include: applications that were canceled by the customer,
duplicate requests,or requests to transfer to and from the same meter.
Distributed Energy Resources 2024 Annual Report Page 14

Idaho Power Company 2024 Excess Net Credit Transfers
Credit Transfer Magnitude- Legacy
Figure 3 shows the total excess kWh credit transfers for the last five years (2020 through
2024) by customer class.
Figure 3 Excess Net Energy kWh Credit Transfers by Customer Class, 2020—2024
25,000,000
20,000,000 19,263,396
15,000,000 13,626,674
14,693,176
Y
10,000,000
5,000,000 4,627,989
3,241,836
M kLb.
2020 2021 2022 2023 2024
■Residential ■Commercial ■Irrigation
Credit Transfer Magnitude- Non-Legacy
This was the first year non-legacy customers could request to transfer excess net financial
credits. Figure 4 shows the total excess net financial credit transfers for 2024, by class.
Figure 4 Excess Net Financial Credit Transfers by Customer Class, 2024
$18,000.00 $16,989
$15,000.00
$12,000.00
U)
L
o $9,000.00
$6,000.00
$3,000.00
2024
■Residential ■Commercial ■Irrigation
Distributed Energy Resources 2024 Annual Report Page 15

Idaho Power Company 2024 Excess Net Credit Transfers
Accumulated Excess Net Energy Credit Balances
Figure 5 shows the accumulated excess net energy kWh credit balance for 2014 through
2024.20
Figure 5 Accumulated Unused Excess Net Energy Credit Balance,2015—202421
40
35 34.8 34.3
30 28.9
c 25
20 17.1
15 11.3
10 7.6
5 4.3
1.3 2.6
= ■ ■
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
Accumulated Excess Net Financial Credit Balances
In 2024, non-legacy customers began earning financial credits. At the end of 2024, the
balance of accumulated excess net financial credits was approximately $0.45 million.
20 In Order No.32846,the Commission stated, "we find it fair,just,and reasonable for the kWh credit to indefinitely
carry forward to offset future bills as long as the customer remains on the net metering service at the same
generation site.Allowing the credits to carry forward indefinitely ensures that customers will be able to use their
credits when they need them and thus receive the benefits of their systems."
2'The accumulated excess net energy credit balance represents all unused credits as of December 31. It does not
reflect the potential reduction due to future offset at the premise generated or transferred to another meter for
offset.
Distributed Energy Resources 2024 Annual Report Page 16

Idaho Power Company System Upgrades and 0&M Costs
IV. SYSTEM UPGRADES AND O&M COSTS
System Upgrades and O&M Costs
In 2024, 27 on-site generation projects out of approximately 2,150 systems were notified that
transformer or feeder upgrades would be necessary as a result of the Feasibility Review. Of those
27 projects, 13 included an energy storage device. Ultimately, seven of the 27 projects chose to
proceed with funding the upgrades. Four of the seven projects included a DC coupled energy
storage device. Because DC coupled energy storage devices share an inverter with the on-site
generation system, an upgrade would have been required even if the energy storage device had
not been included with the project. Table 5 provides information for each of the seven projects,
including the size of the project, the upgrade that was required, the total cost of that upgrade,
and the estimated annual O&M.
Table 5 System Upgrades and O&M Costs
Project Customer Class Size (kW Scope of Required Upgrade Total Cost of Estimated
AC) Upgrade Annual O&M
1 Residential 22.8 10 Wa (single phase)to 25 $4,195 $0.42
Wa (single phase)
2 Residential 24.46* 25 Wa (single phase)to 50 $3,259 $0.33
Wa (single phase)
3 Residential 23* 15 Wa (single phase)to 50 $5,659 $0.57
Wa (single phase)
4 Residential 23* 25 Wa (single phase)to 50 $5,769 $0.58
Wa (single phase)
5 Irrigation 100 75 Wa (three phase) to 150 $10,792 $1.08
Wa (three phase)
6 Residential 15* 25 Wa (single phase)to 50 $1,131 $0.11
Wa (single phase)
7 Irrigation 260 Feeder-two controllers $10,400 $1.04
updated from CL6s to CL7s
*Project has DC coupled battery
Distributed Energy Resources 2024 Annual Report Page 17

Idaho Power Company Conclusion
V. CONCLUSION
The continued expansion of on-site generation on Idaho Power's system highlights the
evolution of the Company's electrical grid, along with the importance of evaluating service
provisions and pricing to ensure safe, reliable, and fair-priced electricity. Idaho Power will
continue to monitor customer generation and keep the Commission informed of its impact on
system reliability.
Distributed Energy Resources 2024 Annual Report Page 18

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-15
IDAHO POWER COMPANY
ATTACHMENT 3
BILL INSERT AND CUSTOMER NOTICE

"q%&
-NIQAHO POWER.
Annual Update to the Export Credit Rate
The export credit rate(ECR)is the credit value for energy exported from an on-site
generation system to the electrical grid. It is updated annually,per an Idaho Public
Utilities Commission(IPUC)approved methodology. Idaho Power filed the annual ECR Why is the ECR decreasing?
update with the IPUC on April 1. If the ECR is approved as filed,these updated export The primary driver for the ECR decrease is lower 2024 market
rates will take effect June 1,2025:
prices compared to the 2022 market prices used to determine
Mill Summer Non-summ�" the current ECR. Integration costs have also increased slightly.
On-Peak 114.059U n/a I How is the ECR determined?
The ECR is reflective of the market value of the energy at
Off-Peak 1.7682Q 0.9540Q the time it is being exported to Idaho Power,combined with
additional compensation for the benefit on-site generators
If approved,this ECR decrease will result in the monthly bill for an average residential bring to the grid.The annual update recognizes changing
on-site generation customer increasing about 34%,from $62 to$84 per month.Actual conditions on Idaho Power's electrical grid and broader power
bill impacts will depend on how much energy a system exports. For more details about markets where electric utilities buy and sell energy as needed.
the ECR,visit idahopower.com/customergeneration. Generally,the IPUC-approved methodology relies on avoided
The summer season begins on June 1 and ends on Sept.30 of each year. cost principles as a foundation for the ECR—meaning the
The non-summer season begins on Oct.1 and ends on May 31 of each year. costs Idaho Power avoids having to incur due to energy
received from customers'on-site generation systems.
Summer Season The following elements comprise the ECR:
On-Peak:3 p.m.to 11 p.m.(Mountain Time), Monday through Saturday,
except holidays • Avoided Energy:Energy from customer generators
reduces the amount of energy Idaho Power needs to
Off-Peak: 11 p.m.to 3 p.m. (Mountain Time), Monday through Saturday and produce or purchase.
all hours on Sunday and holidays • Avoided Generation:Energy from customer generators
helps meet peak demand(when all customers'energy
Non-summer Season needs are highest),which reduces the cost for additional
Off-Peak:All hours Monday through Sunday grid generation resources.
Continued on back

Continued from front
IDAWPRE-SORTED STANDARD
99 POMR U.S.POSTAGE
P.O.Box 70 PA I D
Boise,ID 83707-0070 BOISE,ID
PERMIT NO.679
• Avoided Transmission and Distribution: Energy from customer generators
can reduce customer energy needs during times of peak demand,which
can defer and delay the need for additional transmission and distribution
resources.
• Avoided Line Losses:Idaho Power loses a small percentage of the energy it
generates as electricity travels along powerlines. Energy exports from on-site
generators help avoid some of these losses.Avoided line losses are included
in the avoided energy and avoided generation components of the ECR.
• Integration Costs:Idaho Power incurs costs to ensure energy and power
quality remain stable despite the intermittent nature of renewable energy
production.These costs are included as a reduction to the avoided energy
component of the ECR.
Where can I read the filing?
Idaho Power's filing is subject to public review and requires approval by the
IPUC.Copies of the application are available to the public on idahopower.com,
or at the IPUC website,puc.idaho.gov,at the IPUC offices(11331 W.Chinden
Blvd. Building 8,Suite 201-A,Boise,ID 83714),and Idaho Power offices.
Customers may also subscribe to the IPUC's RSS feed to receive periodic updates
via email about the case.Written comments(Case No. IPC-E-25-15)regarding
Idaho Power's application may be filed with the IPUC(puc.idaho.gov/form/
casecomment).
More information on the ECR can be viewed in Schedules 6,8,84,and in the
Frequently Asked Questions at idahopower.com/customergeneration.
0 2025 Idaho Power