20250530Direct Anderson.pdf

RECEIVED
May 30, 2025
IDAHO PUBLIC
UTILITIES COMMISSION
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR ) CASE NO. IPC-E-25-16
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE )
IN THE STATE OF IDAHO AND )
AUTHORITY TO IMPLEMENT CERTAIN )
MEASURES TO MITIGATE THE IMPACT OF )
REGULATORY LAG. )
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
GRANT T . ANDERSON

1 I . INTRODUCTION
2 Q. Please state your name, business address, and
3 present position with Idaho Power Company ("Idaho Power" or
4 "Company") .
5 A. My name is Grant T . Anderson. My business
6 address is 1221 West Idaho Street, Boise, Idaho 83702 . I am
7 employed by Idaho Power as the Pricing and Tariff
8 Administration Leader in the Company' s Regulatory Affairs
9 Department.
10 Q. Please describe your educational background and
11 work experience before Idaho Power.
12 A. I received a Bachelor of Science degree in
13 Microbiology from Oregon State University in May 2013 and
14 earned a Master of Business Administration degree from Boise
15 State University in May 2015 . In March 2015, I accepted a
16 position as a Corporate Development Analyst for Albertsons and
17 was later promoted to Corporate Development Manager in 2017 . I
18 served in that capacity until I joined Idaho Power in 2018 . I
19 have also completed the electric utility ratemaking course
20 "Practical Regulatory Training for the Electric Industry"
21 through New Mexico State University' s Center for Public
22 Utilities, as well as the "Utility Finance and Accounting"
23 course through the Financial Accounting Institute .
24 Q. Please describe your work experience with Idaho
25 Power.
ANDERSON, DI 1
Idaho Power Company

1 A. I began working at Idaho Power in 2018 as a
2 Regulatory Analyst in the Company' s Regulatory Affairs
3 Department. In that role, I supported rate design and tariff
4 activities for the Company' s Commercial and Industrial
5 customer classes . In 2021, I was promoted to a Regulatory
6 Consultant and assumed responsibilities for developing complex
7 cost-of-service studies, pricing strategies, and supporting
8 the Company' s class cost-of-service efforts . In April 2025, I
9 was promoted to my current role as Pricing and Tariff
10 Administration Leader, where I manage the Company' s overall
11 pricing strategy and oversee the administration of all tariff
12 schedules and rules .
13 Q. What is the purpose of your direct testimony in
14 this proceeding?
15 A. The purpose of my direct testimony is to present
16 and support Idaho Power' s proposed pricing changes for each of
17 the Company' s major customer classes, including residential,
18 general service, irrigation, large power, lighting, and
19 special contract customers . My testimony also addresses
20 proposed updates to select tariff schedules and rules .
21 Q. Are you sponsoring any Exhibits that accompany
22 your testimony?
23 A. Yes . I supervised the preparation of, and am
24 sponsoring, Exhibit No. 44 - Calculation of Proposed Rates and
25 Exhibit No . 45 - Monthly Adjusted Base Revenue Comparison for
ANDERSON, DI 2
Idaho Power Company

1 the Company' s retail service schedules . A table of contents
2 for my testimony is as follows :
Table of Contents Page
I . Introduction 1
II . Residential Service Pricing 3
III . General Service Pricing 19
IV. Large Power Service Pricing 24
V. Irrigation Service Pricing 26
VI . Lighting and Non-Metered Pricing 31
VII . Special Contract Pricing 35
VIII . Other Service Schedule Pricing 37
IX. Tariff Administration 43
3 II . RESIDENTIAL SERVICE PRICING
4 A. Residential Service Overview
5 Q. What are the Company' s residential service
6 schedules?
7 A. Idaho Power offers four residential service
8 schedules : Schedules 1, 3, 5, and 6 . Schedule 1 is the
9 standard residential service and is available to all customers
10 receiving electric service for general domestic use . Schedule
11 3 is limited to master-metered mobile home parks that are
12 included on the Company' s list of "grandfathered" mobile home
13 parks . Schedule 5 is a time-of-use pricing option that
14 includes distinct time periods for energy pricing. Schedule 6
15 is an optional service for customers with on-site generation.
ANDERSON, DI 3
Idaho Power Company

1 Q. What is the annual revenue requirement to be
2 recovered from residential service customers?
3 A. The annual revenue requirement to be recovered
4 from residential service customers, which includes customers
5 served under Schedules 1, 3, 5, and 6, is $814, 155, 998, as
6 shown on page 2 of Company Witness Mr. Riley Maloney' s Exhibit
7 No . 41, representing a 17 . 02 percent change .
8 Q. What pricing changes is the Company proposing
9 for residential service?
10 A. The Company is proposing to revise each of the
11 billing components for residential customers to better align
12 with the cost of providing service as informed by the
13 Company' s proposed class cost of service ("CCOS") study
14 presented in this case. Specifically, the Company proposes to
15 increase the monthly Service Charge from $15 . 00 to $25 . 00 . In
16 addition to the Service Charge, Energy Charges within each
17 schedule will be adjusted to recover the targeted revenue
18 requirement.
19 Q. Where can the comparison of present and proposed
20 rates be found?
21 A. A comparison of the present and proposed rates
22 for each of the Company' s residential service schedules is
23 provided on pages 1 through 7 of Exhibit No. 44, which I will
24 discuss later in my testimony.
ANDERSON, DI 4
Idaho Power Company

1 B. Schedule 1, Residential Service Standard Plan
2 Q. Could you please describe the present pricing
3 structure under Schedule 1?
4 A. Yes . Under the current Schedule 1, customers pay
5 a monthly Service Charge of $15 . 00 and Energy Charges that are
6 based on a three-tier structure. Tier 1 applies to usage from
7 0 to 800 kilowatt-hours ("kWh") per month; Tier 2 applies to
8 usage from 801 to 2, 000 kWh; and Tier 3 applies to all usage
9 over 2, 000 kWh per month. Each of these tiers has distinct
10 pricing for summer and non-summer seasons .
11 Q. How does the Company propose to spread the
12 proposed revenue increase for Schedule 1 across the pricing
13 components within the schedule?
14 A. The Company proposes to recover the revenue
15 requirement for Schedule 1 by increasing both the monthly
16 Service Charge and the Energy Charges . The Service Charge
17 would increase from $15 . 00 to $25 . 00 per month. The Energy
18 Charges for each tier would also increase; however, the
19 Company proposes to reduce the differential between tiers as
20 described more fully later in my testimony. The proposed
21 changes to Schedule 1 are shown on page 2 of Exhibit No. 44 .
22 Q. What is the proposed bill impact for a typical
23 residential customer?
24 A. For a residential customer using an average of
25 900 kWh per month, the proposed rate changes would result in a
ANDERSON, DI 5
Idaho Power Company

1 bill increase of approximately $19 . 89 per month, or a 19 . 3
2 percent increase. Under current rates, the monthly bill for a
3 customer using 900 kWh is approximately $103 . 30, which would
4 increase to $123 . 19 under the proposed rates . A detailed bill
5 comparison across various usage levels is provided on page 1
6 of Exhibit No. 45 .
7 C. Schedule 3, Master-Metered Mobile-Home Park Residential
8 Service
9 Q. Does the Company propose any changes to the
10 pricing structure for Schedule 3?
11 A. The Company is not proposing any changes to the
12 existing pricing structure for Schedule 3 . This schedule will
13 continue to include a monthly Service Charge and a single-tier
14 Energy Charge applicable to all usage.
15 Q. How does the Company propose to spread the
16 proposed revenue increase for Schedule 3 across the pricing
17 components within the schedule?
18 A. To recover the proposed revenue requirement for
19 Schedule 3, the Company proposes to increase the monthly
20 Service Charge from $15 . 00 to $25 . 00 . In addition, the Energy
21 Charge will increase to meet the required revenue target for
22 this schedule. The proposed changes to Schedule 3 are shown on
23 page 4 of Exhibit No. 44 .
24 D. Schedule 5, Residential Service Time-of-Use Plan
25 Q. Could you please describe the present pricing
26 structure under Schedule 5?
ANDERSON, DI 6
Idaho Power Company

1 A. Schedule 5 includes a monthly Service Charge of
2 $15 . 00 and time-of-use Energy Charges that vary by season and
3 time of day. During the summer season, there are three time-
4 of-use periods : on-peak, mid-peak, and off-peak. In the non-
5 summer season, there are two time-of-use periods : on-peak and
6 off-peak.
7 Q. How does the Company propose to spread the
8 proposed revenue increase for Schedule 5 across the pricing
9 components within the schedule?
10 A. The Company proposes to increase the monthly
11 Service Charge from $15 . 00 to $25 . 00 and to increase the
12 Energy Charges proportionally while maintaining the current
13 differential between the time-of-use periods . The proposed
14 changes to Schedule 5 are shown on page 6 of Exhibit No. 44 .
15 Q. What is the proposed impact on a typical
16 Schedule 5 customer?
17 A. For a residential customer using an average of
18 1, 500 kWh per month, the proposed pricing changes would result
19 in a bill increase of approximately $29 . 58 per month, or 17 . 2
20 percent. Under current rates, a customer with this usage would
21 pay approximately $171 . 78 per month, which would increase to
22 $201 . 36 under the proposed rates . A bill comparison across
23 different usage levels is provided on page 2 of Exhibit No.
24 45 .
ANDERSON, DI 7
Idaho Power Company

1 Q. Did the Company evaluate the time-of-use periods
2 for Schedule 5 to determine whether modifications were
3 warranted?
4 A. Yes . The Company reviewed the current time-of-
5 use periods to assess whether they continue to align with the
6 hours of highest system risk. The existing definitions remain
7 generally representative of the Company' s reliability risk
8 profile.
9 The time-of-use periods were most recently updated in
10 the Company' s 2023 general rate case, and no further
11 modifications are proposed in this proceeding. Because
12 Schedule 5 is an optional service that requires customers to
13 actively manage their usage in response to time-varying
14 prices, changes to the time periods should be infrequent to
15 provide customers with a stable and predictable framework for
16 managing their energy consumption.
17 E. Schedule 6, Residential On-Site Generation Service
18 Q. Could you please describe the present pricing
19 structure under Schedule 6?
20 A. The current pricing structure for residential
21 customers served under Schedule 6 mirrors the pricing of
22 Schedule 1 for standard pricing and Schedule 5 for the
23 optional time-of-use pricing. In other words, customers on
24 Schedule 6 are subject to the same Service Charge and Energy
25 Charges as customers on the corresponding retail schedule,
ANDERSON, DI 8
Idaho Power Company

1 depending on whether they elect standard or time-of-use
2 pricing.
3 Q. What pricing structure is the Company proposing
4 under Schedule 6?
5 A. The Company proposes to maintain the existing
6 pricing relationship between Schedule 6 and the applicable
7 retail schedule. Customers taking service under Schedule 6
8 would continue to be priced according to either Schedule 1 or
9 Schedule 5, depending on their selected pricing option.
10 Q. Why is the Company proposing to retain this
11 pricing structure for Schedule 6?
12 A. While the Company' s CCOS study indicates that
13 the cost to serve customers on Schedule 6 is higher than that
14 of customers receiving standard service, the Company believes
15 that pricing changes should be implemented gradually to avoid
16 rate shock to individual customers . As was the case in the
17 Company' s 2023 general rate case, Idaho Power continues to
18 evaluate options for aligning Schedule 6 pricing more closely
19 with the cost to serve and may bring forward proposals in
20 future proceedings .
21 F. Residential Service Charge
22 Q. Please summarize the Company' s proposal for the
23 residential Service Charge in this proceeding.
24 A. The Company proposes to continue progress in the
25 residential Service Charge to better align prices with the
ANDERSON, DI 9
Idaho Power Company

1 fixed costs of serving customers . In the Company' s 2023
2 general rate case, Idaho Power introduced a multi-year plan to
3 increase the Service Charge. The Commission approved the first
4 two steps of that plan in Order No . 36042 . An additional step,
5 an increase to $25 . 00 per month effective January 1, 2026, is
6 proposed in this proceeding.
7 Table 1
8 Residential Monthly Service Charge
Effective January 1 Schedule 1/3/5/6
2024 $10 . 00
2025 (Current) $15 . 00
2026 (Proposed) $25 . 00
9 Q. Why is the Company proposing a multiyear
10 transition for the Service Charge?
11 A. The Company believes a gradual transition helps
12 moderate bill impacts, particularly for lower-use customers,
13 and avoids rate shock. This phased approach aims to balance
14 the goal of aligning fixed charges with fixed costs while
15 remaining sensitive to customer impacts .
16 Q. What is the cost basis for increasing the
17 residential Service Charge?
18 A. A large portion of the Company' s costs — such as
19 distribution plant and associated operations — are fixed and
20 do not vary with customer usage. The total monthly customer-
21 allocated costs, as shown in Mr. Maloney' s Exhibit No. 37,
22 page 1, are approximately $42 . 84 per customer per month. The
ANDERSON, DI 10
Idaho Power Company

1 Company believes it is appropriate to recover a greater share
2 of these fixed costs through the Service Charge . When the
3 Service Charge is set too low, the Company must recover fixed
4 costs through higher volumetric Energy Charges, resulting in
5 high-usage customers subsidizing low-usage customers .
6 Q. How does the Company' s proposed $25 . 00
7 residential Service Charge compare to those of other electric
8 utilities in Idaho?
9 A. The proposed $25 . 00 per month Service Charge is
10 generally in line with the fixed monthly charges assessed by
11 other Idaho electric utilities serving more than 1, 000
12 customers . The table below shows a comparison of current fixed
13 charges among these utilities .
14 Table 2
15 Fixed Monthly Residential Charges for Idaho Electric Utilities
Utility Price
Avista $ 20.00
City of Idaho Falls $ 23.00
Fall River Rural Electric Cooperative $ 39.00
Idaho Power $ 15.00
Inland Power& Light Company $ 31.52
Kootenai Electric Cooperative $ 32.50
Lower Valley Energy $ 18.00
Northern Lights $ 30.00
Raft Rural Electric Cooperative $ 25.50
Rocky Mountain Power Idaho $ 16.50
Salmon River Electric Cooperative $ 46.00
United Electric Cooperative $ 26.00
Average $ 26.92
ote:All axed monthly charges available from each utility's website as ofMay 23, 2025.
ANDERSON, DI 11
Idaho Power Company

1 Q. Has the Commission supported aligning fixed cost
2 collection with fixed charges?
3 A. The approved residential Service Charge changes
4 in Idaho Power' s 2023 general rate case were part of the
5 Commission-approved Settlement Stipulation. Additionally, in
6 Order No. 35909, the Commission approved a similar proposal by
7 Avista to increase its residential Service Charge . In that
8 order, the Commission stated:
9 The Commission is persuaded by the Company' s testimony on
10 the average cost of service for customers including
11 distribution plant and operating costs to provide reliable
12 service. The Commission believes that accurately assigning
13 costs is a fair component of rate design, and the
14 misalignment of costs can create revenue recovery
15 distortions and give an incorrect perception of the cost
16 and value of the Company' s services . The proposed change
17 to the basic charge is movement to ensure that all
18 customers are paying a proper amount of fixed costs
19 required to serve them.
20 The Commission is sensitive to customer concerns with the
21 potential impact of increasing the basic charge; however,
22 the Commission is not persuaded by ICL/NWEC' s claims that
23 the proposed changes will send a negative price signal for
24 energy efficiency and conservation, and disproportionately
25 effect low-income and low-usage customers . Further, the
26 Commission does not believe that at this time any
27 alteration is necessary to the Company' s cost-
28 effectiveness calculation for energy efficiency, nor is it
29 necessary at this time to require the Company to increase
30 funding for low-income customers . Similarly, the
31 Commission does not believe that it is necessary at this
32 time to open an investigatory docket into the interplay
33 between the high fixed charges and revenue decoupling.
34 G. Residential Tiered Energy Charges
35 Q. Please describe the structure of the Company' s
36 current tiered Energy Charges in Schedule 1?
ANDERSON, DI 12
Idaho Power Company

1 A. Schedule 1 includes seasonal inclining block
2 Energy Charges, meaning the price per kWh increases once a
3 customer exceeds a set monthly usage threshold. In addition to
4 the tiered pricing, Energy Charges vary seasonally, with
5 higher prices in the summer season of June through September
6 and lower prices in the non-summer season of October through
7 May.
8 Q. Historically, why were tiered Energy Charges
9 implemented?
10 A. Inclining block pricing has historically been
11 used as a tool to encourage lower energy usage. The first
12 block is priced lower to help maintain bill affordability,
13 while subsequent blocks are priced higher to provide an
14 incentive for customers to reduce their consumption. Under
15 this design, energy-efficient actions — such as replacing
16 lighting with LEDs — would yield greater bill savings for
17 customers using electricity in the higher tiers .
18 Q. Do tiered Energy Charges necessarily encourage
19 energy efficiency?
20 A. Not necessarily. A customer' s total monthly
21 usage may be influenced by factors unrelated to energy
22 efficiency, such as the number of occupants in the home or the
23 primary fuel source for heating. These factors can result in
24 higher usage independent of conservation behavior.
ANDERSON, DI 13
Idaho Power Company

1 Q. Why is the Company proposing to reduce the
2 differential between energy tiers?
3 A. While a tiered pricing structure is well-
4 intentioned, it has created challenges in pricing. The Company
5 believes that tiered Energy Charges are not economically
6 justified and result in unfair cost allocation among
7 customers . The proposed change reflects a gradual movement
8 away from tiered pricing to improve fairness and align prices
9 more closely with cost causation.
10 Q. Please explain why tiered Energy Charges are not
11 economically justified.
12 A. There is no cost-based rationale for charging a
13 higher rate for the kWh consumed beyond an arbitrary threshold
14 such as 800 or 2, 000 kWh. Unlike the timing of energy
15 consumption — which can impact costs due to system load or
16 market prices — higher monthly energy use alone does not
17 increase the utility' s cost to deliver the next unit of
18 energy. Cost drivers are more closely tied to time of energy
19 consumption and load factor, rather than total monthly usage .
20 Q. How do tiered Energy Charges result in unfair
21 cost allocation?
22 A. Inclining block pricing shifts a larger share of
23 the cost burden to customers with higher monthly usage, who
24 may use more energy for reasons outside their control . For
25 example, customers who heat with electricity or have larger
ANDERSON, DI 14
Idaho Power Company

1 households are more likely to fall into higher usage tiers . In
2 contrast, customers using natural gas for heating or living
3 alone may remain in lower tiers and pay less, even though the
4 cost to serve each customer does not differ as dramatically.
5 Q. Is there another benefit to reducing or removing
6 tiered Energy Charges?
7 A. Yes . Flattening the tiered structure makes it
8 easier for customers to compare Schedule 1 with Schedule 5,
9 the optional residential time-of-use schedule . This
10 simplification helps customers make more informed decisions
11 about which pricing plan best meets their needs . The Company
12 believes flattening the tiers in this case will also better
13 position the Company to consider a future transition to
14 default or mandatory time-of-use rates .
15 Q. What specific change is the Company proposing to
16 the Schedule 1 energy tiers?
17 A. The Company proposes to reduce the differentials
18 between the current tiered prices but is not proposing to
19 eliminate tiered pricing entirely in this proceeding. This
20 approach balances cost alignment with gradualism to moderate
21 customer bill impacts . The proposed tiered prices are shown on
22 page 2 of Exhibit No. 44 .
23 H. Residential TOU Bill Protection
24 Q. Are there any additional changes proposed for
25 Schedule 5?
ANDERSON, DI 15
Idaho Power Company

1 A. Yes . The Company is proposing to implement a
2 bill protection program for residential customers who begin
3 taking service under Schedule 5 effective January 1, 2026 .
4 Q. What is the purpose of introducing bill
5 protection for customers on Schedule 5?
6 A. The purpose of bill protection is to reduce
7 financial uncertainty for customers transitioning from
8 Schedule 1 to Schedule 5 . The program is intended to encourage
9 participation in the optional TOU pricing by ensuring
10 customers will not pay more than $10 above what they would
11 have paid under Schedule 1 for their first twelve months of
12 service on Schedule 5 . This customer protection feature lowers
13 the barrier to entry and supports broader adoption of TOU
14 rates .
15 Q. How does the proposed bill protection mechanism
16 work?
17 A. After twelve consecutive months of service on
18 Schedule 5, a customer' s actual billed energy charges will be
19 compared to what the customer would have paid under Schedule 1
20 for the same usage. If the Schedule 5 charges for the first
21 twelve months exceed the Schedule 1 charges by more than $10
22 on an annual basis, the customer will receive a one-time bill
23 credit for the amount above the $10 threshold.
24 Q. Who is eligible for this bill protection
25 program?
ANDERSON, DI 16
Idaho Power Company

1 A. Residential customers who begin taking service
2 under Schedule 5 on or after January 1, 2026, are eligible . To
3 qualify, customers must remain on Schedule 5 at the same
4 premises for a full twelve consecutive months . Customers who
5 have previously received service under Schedule 5, do not
6 complete the full twelve-month period, or are served under
7 Schedule 6 are not eligible for the program.
8 Q. Is bill protection available beyond the first
9 year of a customer' s enrollment in Schedule 5?
10 A. No. Bill protection is only available during the
11 first twelve consecutive months that a customer takes service
12 under Schedule 5 at a given premises . The intent of the
13 program is to provide a transitional safety net for customers
14 who are new to time-of-use pricing. After the first year,
15 customers will continue service under Schedule 5 without bill
16 protection or they may self-select out of the optional service
17 and revert to the standard plan under Schedule 1 .
18 Q. What are the expected benefits of this proposal
19 for customers and the Company?
20 A. For customers, the bill protection program
21 offers a low-risk opportunity to try TOU pricing, which may
22 help them reduce their bills by shifting usage to lower priced
23 off-peak periods . For the Company, broader TOU participation
24 can support load management and help reduce peak demand, which
25 may lower overall system costs over time.
ANDERSON, DI 17
Idaho Power Company

1 Q. Did the Company evaluate the potential financial
2 impact to the Company?
3 A. Yes . The Company has considered the potential
4 financial implications of the bill protection program on the
5 FCA mechanism. If a customer opts in to Schedule 5 and
6 exhibits higher usage during the on-peak and mid-peak periods,
7 they are more likely to trigger the bill protection provision.
8 In those cases, while the customer receives a bill credit, the
9 FCA will reflect a higher level of fixed cost recovery due to
10 the elevated volumetric energy charges associated with peak-
11 period usage . This may result in a lower FCA deferral than
12 what would have occurred under Schedule 1 pricing for those
13 customers that trigger the TOU Bill Protection.
14 Q. Is the Company proposing to implement a tracking
15 mechanism?
16 A. Not currently - the Company does not anticipate
17 the initial rate of adoption to result in a material financial
18 impact . However, depending on the level of customer adoption
19 of Schedule 5 and the number of customers who ultimately
20 receive a bill credit through the bill protection mechanism,
21 the cumulative impact could necessitate a future evaluation of
22 a tracking mechanism to mitigate financial harm to the
23 Company.
ANDERSON, DI 18
Idaho Power Company

1 III . GENERAL SERVICE PRICING
2 A. Schedule 7 and 8 , Small General Service
3 Q. What are the Company' s small general service
4 schedules?
5 A. Idaho Power offers two small general service
6 schedules : Schedules 7, the standard small general service,
7 and Schedule 8, which is an optional service for small general
8 service customers with on-site generation.
9 Q. What is the annual revenue requirement to be
10 recovered from small general service under Schedules 7 and 8?
11 A. The annual revenue requirement to be recovered
12 from small general service customers under Schedules 7 and 8
13 is $23, 641, 536, as shown on page 2 of Mr. Maloney' s Exhibit
14 No. 41, representing a 17 . 02 percent change.
15 Q. What pricing structure changes is the Company
16 proposing for small general service?
17 A. The Company is not proposing any changes to the
18 existing pricing structure for either Schedule 7 or Schedule
19 8 .
20 Q. What is the present pricing structure under
21 Schedules 7 and 8?
22 A. Both Schedule 7 and Schedule 8 currently include
23 a monthly Service Charge of $25 . 00 and a two-tier Energy
24 Charge structure . Tier 1 applies to the first 300 kWh of
25 monthly usage, and Tier 2 applies to all usage above 300 kWh.
ANDERSON, DI 19
Idaho Power Company

1 Q. Why is the Company proposing to retain this
2 pricing structure for Schedule 8?
3 A. While the Company' s class cost of service study
4 indicates that the cost to serve Schedule 8 customers is
5 higher than for customers receiving standard service, the
6 Company believes pricing changes should be made gradually to
7 avoid rate shock. As in the Company' s 2023 general rate case,
8 Idaho Power continues to evaluate options for aligning
9 Schedule 8 pricing more closely with cost of service and may
10 bring forward proposals in future proceedings .
11 Q. How does the Company propose to spread the
12 proposed revenue increase for Schedules 7 and Schedule 8 to
13 the pricing components within the schedules?
14 A. The Company proposes to recover the increased
15 revenue requirement for Schedules 7 and 8 by increasing both
16 the monthly Service Charge and the tiered Energy Charges . The
17 Service Charge would increase from $25 . 00 to $30 . 00 per month.
18 The Energy Charge for each tier would also increase . The
19 proposed changes to Schedule 7 and Schedule 8 are shown on
20 page 8 of Exhibit No. 44 .
21 Q. Have you prepared an exhibit that shows the
22 billing impact of this pricing proposal?
23 A. Yes . Page 3 of Exhibit No. 45 presents a billing
24 comparison between the present and proposed rates for Schedule
25 7 .
ANDERSON, DI 20
Idaho Power Company

1 B. Schedule 9, Large General Service (Secondary)
2 Q. What is the annual revenue requirement to be
3 recovered from large general service customers under Schedule
4 9 Secondary Service?
5 A. The annual revenue requirement to be recovered
6 from large general service customers under Schedule 9
7 Secondary Service is $331, 880, 068, as shown on page 2 of Mr.
8 Maloney' s Exhibit No. 41, representing a 7 . 19 percent change .
9 Q. What pricing structure changes is the Company
10 proposing for Schedule 9 Secondary Service?
11 A. The Company is not proposing any changes to the
12 existing pricing structure for Schedule 9 Secondary Service .
13 Q. What is the present pricing structure under
14 Schedule 9 Secondary Service?
15 A. The current pricing structure under Schedule 9
16 Secondary Service includes a monthly Service Charge, a Basic
17 Charge, and seasonal Billing Demand and Energy Charges . The
18 Energy Charges are available under either a default or
19 optional time-of-use pricing structure.
20 Q. How does the Company propose to spread the
21 proposed revenue increase for Schedule 9 Secondary Service to
22 the pricing components within that schedule?
23 A. For all pricing components, the Company is
24 proposing prices that represent a uniform 20 percent movement
25 toward the costs to serve that pricing component. For the
ANDERSON, DI 21
Idaho Power Company

1 optional time-of-use pricing the Energy Charge differentials
2 are informed by the three-year average hourly Energy Imbalance
3 Market ("EIM") prices for each time-of-use period. The costs
4 to serve each rate component are identified on page 5 of Mr.
5 Maloney' s Exhibit No. 37, and the proposed changes to Schedule
6 9 Secondary Service are shown on pages 11 and 12 of Exhibit
7 No . 44 .
8 Q. Have you prepared an exhibit that shows the
9 billing impact of this pricing proposal?
10 A. Yes . Page 4 of Exhibit No. 45 presents a billing
11 comparison between the present and proposed rates for Schedule
12 9 Secondary Service. In general, higher load factor customers
13 would experience a smaller percentage increase in their bills
14 than lower load factor customers .
15 C. Schedule 9, Large General Service (Primary/Transmission)
16 Q. What is the annual revenue requirement to be
17 recovered from large general service customers under Schedule
18 9 Primary and Transmission Service?
19 A. The annual revenue requirement to be recovered
20 from large general service customers under Schedule 9 Primary
21 and Transmission Service is $56, 288, 766, as shown on page 2 of
22 Mr. Maloney" s Exhibit No. 41, representing a 6 . 88 percent
23 change .
24 Q. What pricing structure changes is the Company
25 proposing for Schedule 9 Primary and Transmission Service?
ANDERSON, DI 22
Idaho Power Company

1 A. The Company is not proposing any changes to the
2 existing pricing structure for Schedule 9 Primary and
3 Transmission Service.
4 Q. What is the present pricing structure for
5 Schedule 9 Primary and Transmission Service?
6 A. The current pricing structure under Schedule 9
7 Primary and Transmission Service includes a monthly Service
8 Charge, a Basic Charge, seasonal Demand Charges, a summer On-
g Peak Demand Charge, and seasonal time-of-use Energy Charges .
10 In addition, customers may pay a Facilities Charge if Company-
11 owned facilities are installed beyond Idaho Power' s Point of
12 Delivery.
13 Q. How does the Company propose to spread the
14 proposed revenue increase for Schedule 9 Primary and
15 Transmission Service to the pricing components within the
16 schedule?
17 A. The Company is proposing to increase the Service
18 Charge to align with cost of service. For all other pricing
19 components, the Company is proposing prices that represent a
20 uniform 20 percent movement towards the costs to serve that
21 pricing component, and Energy Charges informed by the three-
22 year average hourly EIM prices for each time-of-use period.
23 The costs to serve each rate component are identified on page
24 6 of Mr. Maloney' s Exhibit No. 37, and the proposed change to
ANDERSON, DI 23
Idaho Power Company

1 Schedule 9 Primary and Transmission Service are shown on pages
2 13 and 14 of Exhibit No. 44 .
3 Q. Have you prepared an exhibit that shows the
4 billing impact of this pricing proposal?
5 A. Yes . Page 5 of Exhibit No . 45 presents a billing
6 comparison between the present and proposed pricing for
7 Schedule 9 Primary Service. In general, customers with higher
8 load factors would experience a lower overall increase in
9 their monthly bills compared to customers with lower load
10 factors .
11 IV. LARGE POWER SERVICE PRICING
12 Q. What is the annual revenue requirement to be
13 recovered from Large Power Service customers taking service
14 under Schedule 19?
15 A. The annual revenue requirement for customers
16 taking service under Schedule 19 is $176, 645, 167, as shown on
17 page 2 of Mr. Maloney' s Exhibit No. 41, representing a 9 . 97
18 percent increase.
19 Q. What pricing structure changes is the Company
20 proposing for Schedule 19?
21 A. The Company is not proposing any changes to the
22 existing pricing structure for Schedule 19 .
23 Q. What is the present pricing structure under
24 Schedule 19?
ANDERSON, DI 24
Idaho Power Company

1 A. Service under Schedule 19 is available at the
2 Secondary, Primary, and Transmission service levels . The
3 current pricing structure includes a monthly Service Charge, a
4 Basic Charge, seasonal Demand Charges, a summer On-Peak Demand
5 Charge, and seasonal time-of-use Energy Charges . Customers
6 taking Primary or Transmission service may also pay a
7 Facilities Charge for Company-owned facilities installed
8 beyond Idaho Power' s Point of Delivery. Additionally, Schedule
9 19 includes a minimum Billing Demand of 1, 000 kilowatts per
10 month and a minimum Basic Load Capacity.
11 Q. How does the Company propose to spread the
12 proposed revenue increase for Schedule 19 across the pricing
13 components within the schedule?
14 A. For all pricing components, the Company is
15 proposing prices that represent a uniform 20 percent movement
16 toward the costs to serve that pricing component, and Energy
17 Charges informed by the three-year average hourly EIM prices
18 for each time-of-use period. The costs to serve each pricing
19 component are identified on page 7 of Mr. Maloney' s Exhibit
20 No . 37, and the proposed change to Schedule 19 are shown on
21 pages 15 - 17 of Exhibit No . 44 .
22 Q. Have you prepared an exhibit that shows the
23 billing impact of this pricing proposal?
24 A. Yes . Page 6 of Exhibit No. 45 presents a billing
25 comparison between the present and proposed pricing for
ANDERSON, DI 25
Idaho Power Company

1 Schedule 19 . In general, customers with higher load factors
2 would experience a smaller overall increase in their monthly
3 bills compared to customers with lower load factors .
4 V. IRRIGATION SERVICE PRICING
5 A. Schedule 24 , Agricultural Irrigation Service
6 Q. What is the annual revenue requirement to be
7 recovered from irrigation customers under Schedule 24?
8 A. The annual revenue requirement to be recovered
9 from customers taking service under Schedule 24 is
10 $209, 823, 654, as shown on page 2 of Mr. Maloney' s Exhibit No.
11 41, representing a 17 . 02 percent change.
12 Q. What pricing structure changes is the Company
13 proposing for Schedule 24?
14 A. The Company is not proposing any changes to the
15 existing pricing structure for Schedule 24 . However, the
16 Company is proposing a change to the definition of the in-
17 season and out-of-season periods, which I will address later
18 in my testimony.
19 Q. What is the present pricing structure for
20 Schedule 24?
21 A. Schedule 24 classifies service as either "in-
22 season" or "out-of-season. " The in-season currently begins
23 with the customer' s meter reading for the May billing period
24 and ends with the meter reading for the September billing
25 period. The out-of-season includes all other billing periods .
ANDERSON, DI 26
Idaho Power Company

1 Customers pay a higher monthly Service Charge during
2 the in-season period and a lower Service Charge during the
3 out-of-season period. The purpose of the reduced out-of-season
4 charge is to encourage customers to maintain year-round
5 service rather than frequently disconnecting and reconnecting
6 around the irrigation season.
7 During the in-season, customers pay both a Demand
8 Charge and an Energy Charge based on metered usage . During the
9 out-of-season, customers pay only an Energy Charge . Both
10 Secondary Service and Transmission Service are available under
11 Schedule 24, although no customers are currently taking
12 service at the transmission level .
13 Q. How does the Company propose to spread the
14 proposed revenue increase for Schedule 24 to the pricing
15 components within the schedule?
16 A. The Company is proposing to increase the monthly
17 Service Charge to move closer to cost-of-service-informed
18 pricing. Specifically, the in-season Service Charge would
19 increase from $30 to $35, while the out-of-season Service
20 Charge would increase from $6 to $9 . For the in-season Demand
21 Charge, the Company is not proposing additional movement
22 towards cost of service in this proceeding. The costs to serve
23 each pricing component is identified on page 8 of Mr.
24 Maloney' s Exhibit No. 37, and the proposed changes to Schedule
25 24 Secondary Service are shown on page 18 of Exhibit No. 44 .
ANDERSON, DI 27
Idaho Power Company

1 Q. Why is the Company proposing essentially no
2 movement towards cost-of-service informed pricing as part of
3 its proposal for Schedule 24?
4 A. In the 2023 general rate case, the approved rate
5 design for Schedule 24 implemented a 30 percent movement
6 towards cost-of-service, including approximately a 100 percent
7 increase in the billing demand price. While that shift was
8 supported by the underlying class cost-of-service study, it
9 resulted in larger bill impacts for low load factor customers
10 due to the transition from energy-based to demand-based
11 collection. In recognition of those impacts and consistent
12 with the principle of gradualism, the Company is not proposing
13 additional movement toward cost-of-service for Schedule 24 in
14 this case and instead proposes to maintain the pricing
15 relationship established in the prior general rate case .
16 Q. How were the prices for Transmission Service
17 determined?
18 A. Although no customers currently take
19 Transmission Service under Schedule 24, the Company developed
20 Transmission Service prices by applying the same percentage
21 increase to each pricing component as was applied to Secondary
22 Service. This approach maintains the current proportional
23 relationship between Transmission and Secondary Service
24 pricing components .
ANDERSON, DI 28
Idaho Power Company

1 Q. Have you prepared an exhibit that shows the
2 billing impact of this pricing proposal on customers taking
3 service under Schedule 24?
4 A. Yes . Page 7 of Exhibit No. 45 provides a
5 comparison of the present and proposed pricing for Schedule
6 24 . In general, customers with higher load factors would
7 experience a lower overall increase in their monthly bills
8 compared to customers with lower load factors .
9 B. Irrigation In-Season Period
10 Q. What is the present seasonal structure for
11 irrigation service under Schedule 24?
12 A. Service under Schedule 24 is classified as
13 either "in-season" or "out-of-season. " Under the current
14 structure, the in-season period begins with each customer' s
15 meter reading for the May billing period and ends with the
16 meter reading for the September billing period. The out-of-
17 season period includes all other billing months .
18 Q. Is the Company proposing a change to the
19 definition of the seasonal periods under Schedule 24?
20 A. Yes . The Company is proposing to define the in-
21 season period as June 1 through September 30 and the out-of-
22 season period as October 1 through May 31 .
23 Q. Why is the Company proposing to revise the
24 definition of the seasonal periods?
ANDERSON, DI 29
Idaho Power Company

1 A. The proposed revision is intended to establish a
2 more consistent, equitable, and easily understood definition
3 for when the irrigation in-season begins and ends each year.
4 The Company' s evaluation and proposal in this proceeding are
5 based on three primary drivers :
6 First, consistency and transparency. Under the current
7 structure, seasonal definitions are tied to each service
8 point' s meter read cycle. This results in seasonal periods
9 varying by customer. For example, an irrigation service on an
10 early meter read cycle could begin the in-season as early as
11 April 29 and end around August 30, while another customer on a
12 later cycle may begin in-season service on May 29 and end
13 around September 26 . This variability creates inconsistency
14 across customers .
15 Second, customer understanding and administrative
16 simplicity. The current structure can be confusing for
17 customers, particularly those with multiple irrigation service
18 points that may have different seasonal start and end dates .
19 The dates for each service can also shift slightly from year
20 to year based on the meter reading schedule . A consistent
21 definition for all irrigation customers improves transparency
22 and is expected to reduce confusion.
23 Third, alignment with future system upgrades . The
24 current seasonal structure, which is tied to individual meter
25 read dates, would require additional customization and
ANDERSON, DI 30
Idaho Power Company

1 complexity as the Company transitions to a new Customer
2 Information System. By adopting a fixed calendar-based
3 definition of the in-season and out-of-season periods, the
4 Company can avoid unnecessary customization, reduce costs, and
5 simplify system implementation.
6 Q. Has the Company discussed the proposed change to
7 the definition of the irrigation in-season period with
8 customers?
9 A. Yes . On March 20, 2025, Idaho Power
10 representatives participated in a meeting hosted by the Idaho
11 Irrigation Pumpers Association ("IIPA") , during which the
12 proposed change to the in-season period was presented.
13 Feedback from IIPA members — many of whom are Idaho Power
14 irrigation customers — was generally positive, particularly
15 with respect to improving the customer experience and
16 enhancing the clarity of seasonal definitions .
17 VI . LIGHTING & NON-METERED PRICING
18 Q. What are the Company' s lighting and non-metered
19 service schedules?
20 A. The Company' s lighting and non-metered service
21 schedules include Schedule 15 (Dusk to Dawn Customer
22 Lighting) , Schedule 41 (Street Lighting Service) , Schedule 42
23 (Traffic Control Signal Lighting Service) , and Schedule 40
24 (Non-Metered General Service) .
ANDERSON, DI 31
Idaho Power Company

1 A. Schedule 15, Dusk to Dawn Customer Lighting
2 Q. What is the annual revenue requirement to be
3 recovered from customers taking service under Schedule 15?
4 A. The annual revenue requirement to be recovered
5 from Schedule 15 customers is $1, 430, 757, as shown on page 2
6 of Mr. Maloney' s Exhibit No. 41, representing a 3 . 93 percent
7 change .
8 Q. What is the current pricing structure under
9 Schedule 15?
10 A. Customers taking service under Schedule 15 are
11 charged on a per-lamp basis . Fixtures available under this
12 schedule include 40, 85, and 200 watt Light Emitting Diode
13 ("LED") area lighting, and 85, 150, and 300 watt LED flood
14 lighting.
15 Q. Has the Company prepared an exhibit that
16 illustrates the pricing proposal for Schedule 15?
17 A. Yes . The pricing proposal for Schedule 15 is
18 provided on page 20 of Exhibit No. 44 . The Company proposes to
19 allocate the class revenue requirement to pricing components
20 based on a separate lighting cost-of-service study conducted
21 for both Schedules 15 and 41 .
22 B. Schedule 40 , Non-Metered General Service
23 Q. What is the annual revenue requirement to be
24 recovered from customers taking service under Schedule 40?
ANDERSON, DI 32
Idaho Power Company

1 A. The annual revenue requirement for Schedule 40
2 customers is $1, 619, 008, as shown on page 2 of Mr. Maloney' s
3 Exhibit No. 41, representing an 8 . 21 percent change .
4 Q. What is the current pricing structure under
5 Schedule 40?
6 A. Customers under Schedule 40 are non-metered but
7 have fixed loads and usage profiles . A flat Energy Charge is
8 applied to estimated usage. The current minimum monthly charge
9 is $2 . 00 . An Intermittent Usage Charge may also be applied to
10 qualifying municipal or government agency loads with variable
11 usage patterns .
12 Q. What pricing changes is the Company proposing
13 for Schedule 40?
14 A. The pricing proposal for Schedule 40 is shown on
15 page 21 of Exhibit No. 44 . The Company proposes to increase
16 the Energy Charge to recover the proposed revenue requirement
17 and increase the Intermittent Usage Charge from $2 . 00 to
18 $2 . 50 .
19 C. Schedule 41 , Street Lighting Service
20 Q. What is the annual revenue requirement to be
21 recovered from customers taking service under Schedule 41?
22 A. The annual revenue requirement to be recovered
23 from Schedule 41 customers is $4, 160, 824, as shown on page 2
24 of Mr. Maloney" s Exhibit No. 41, representing a 3 . 93 percent
25 change .
ANDERSON, DI 33
Idaho Power Company

1 Q. What is the current pricing structure for
2 Schedule 41?
3 A. Schedule 41 includes two service options . Option
4 A applies to Idaho Power-owned and maintained systems . Option
5 C applies to customer-owned, customer-maintained systems .
6 Option A includes unmetered lighting billed on a per-lamp
7 basis . Fixtures include LED equivalents of 40, 85, 140, and
8 200 watts . Option C allows for both metered and non-metered
9 systems, with maintenance performed by the customer.
10 Q. Has the Company prepared an exhibit that
11 illustrates the pricing proposal for Schedule 41?
12 A. Yes . The pricing proposal for Schedule 41 is
13 shown on pages 22 and 23 of Exhibit No . 44 .
14 D. Schedule 42 , Traffic Control Signal Lighting Service
15 Q. What is the annual revenue requirement to be
16 recovered from customers taking service under Schedule 42?
17 A. The annual revenue requirement for Schedule 42
18 customers is $291, 430, as shown on page 2 of Mr. Maloney' s
19 Exhibit No. 41, representing a 17 . 02 percent change .
20 Q. What is the current pricing structure under
21 Schedule 42?
22 A. Customers pay an Energy Charge based on actual
23 or estimated energy use. For non-metered service, energy use
24 is estimated based on lamp type and typical operating hours .
25 There is no minimum monthly charge under this schedule .
ANDERSON, DI 34
Idaho Power Company

1 Q. Has the Company prepared an exhibit that
2 illustrates the pricing proposal for Schedule 42?
3 A. The pricing proposal for Schedule 42 is shown on
4 page 24 of Exhibit No. 44 .
5 VII . SPECIAL CONTRACT PRICING
6 Q. Please provide an overview of the Company' s
7 Special Contract customers .
8 A. The Company currently serves six customers under
9 Commission-approved Special Contracts, each with an associated
10 Energy Services Agreement and tariff schedule . These include :
11 Schedule 26 (Micron Technology, Inc. ) , Schedule 29 (J.R.
12 Simplot Company - Pocatello) , Schedule 30 (United States
13 Department of Energy) , Schedule 32 (J.R. Simplot Company -
14 Caldwell) , Schedule 33 (Brisbie, LLC) , and Schedule 34 (Lamb
15 Weston, Inc. ) .
16 Q. What pricing structure changes is the Company
17 proposing for Special Contract customers?
18 A. The Company proposes to maintain the existing
19 pricing structures for each Special Contract. These pricing
20 structures generally include a Contract Demand Charge, Billing
21 Demand Charge, and Energy Charges . While the Company is not
22 proposing to modify the pricing structures, the Company -
23 proposes to move each pricing component toward its cost to
24 serve . This includes reestablishing Contract Demand Charges
ANDERSON, DI 35
Idaho Power Company

1 using the same methodology approved in the Company' s 2023
2 general rate case.
3 Q. How was the Contract Demand Charge derived?
4 A. The Contract Demand Charge is based on the
5 Company' s Open Access Transmission Tariff ("OATT") rate
6 effective October 1, 2024 . This approach is consistent with
7 the methodology used to set Contract Demand pricing in the
8 2023 general rate case. The OATT-based charge reflects the
9 reservation cost that any other entity would pay for
10 transmission service on Idaho Power' s system. The Billing
11 Demand Charge is then adjusted to recover any remaining fixed
12 costs not collected through the Contract Demand Charge . For
13 Brisbie and Lamb Weston, the pricing includes a two-block
14 structure: Block 1 Billing Demand Charges are derived from
15 Schedule 19 pricing, while Block 2 Billing Demand Charges are
16 based on embedded costs .
17 Q. What other pricing components are proposed to be
18 updated based on cost to serve?
19 A. The Company proposes to update the Energy
20 Charges to reflect the embedded energy cost as identified on
21 pages 9 - 13 of Mr . Maloney' s Exhibit No. 37 . For Brisbie and
22 Lamb Weston, the pricing includes a two-block structure : Block
23 1 Energy Charges are derived from Schedule 19 pricing, while
24 Block 2 Energy Charges are based on marginal cost pricing
25 principles .
ANDERSON, DI 36
Idaho Power Company

1 Q. Has the Company prepared an exhibit illustrating
2 the proposed pricing for Special Contract customers?
3 A. Yes . The pricing proposal for each Special
4 Contract customer, including a comparison of the present and
5 proposed pricing, is shown on pages 25 - 30 of Exhibit No. 44 .
6 VIII . OTHER SERVICE SCHEDULES
7 A. Schedule 20 , Speculative High-Density Load
8 Q. Does the Company currently have any customers
9 taking service under Schedule 20, or are any such customers
10 included in the 2025 test year?
11 A. No. There are no active customers currently
12 taking service under Schedule 20, and none were included in
13 the 2025 test year.
14 Q. Is the Company proposing any changes to Schedule
15 20 pricing in this proceeding?
16 A. Yes . The Company proposes to continue aligning
17 embedded pricing components for Schedule 20 under the
18 previously adopted methodology, with the cost basis of
19 Schedules 9 and 19 until enough Schedule 20 customers exist to
20 support a class-specific cost assignment. The Company is not
21 proposing changes to the marginal cost-based energy component
22 at this time, as that component is updated annually through a
23 separate filing process . The Company' s proposed pricing for
24 Schedule 20 incorporates the relevant pricing for Schedule 9
ANDERSON, DI 37
Idaho Power Company

1 and Schedule 19 and the marginal cost-based energy pricing
2 update as presented in Case No . IPC-E-25-17 .
3 B. Schedule 45 and Schedule 31 , Standby Service
4 Q. Please describe the Company' s Standby Service
5 offerings .
6 A. The Company provides Standby Service under
7 Schedule 45, which is available to customers with on-site
8 generation who wish to reserve capacity from Idaho Power in
9 case their generation becomes unavailable. The service is
10 optional and is currently available to both large general
11 service and large power service customers . The Company also
12 provides a customized standby service to Amalgamated Sugar
13 Company under Schedule 31 pursuant to a Commission-approved
14 agreement.
15 Q. What is the benefit of electing Standby Service?
16 A. Customers who elect Standby Service are assured
17 access to backup capacity during planned or unplanned outages
18 of their on-site generation. Idaho Power includes the reserved
19 capacity in its system planning and load forecasts to ensure
20 reliability. Customers who choose not to take Standby Service
21 may find that the Company is not able to serve the full load
22 during outages, as that demand was not anticipated.
23 Q. Is the Company proposing pricing changes for
24 Schedule 45?
ANDERSON, DI 38
Idaho Power Company

1 A. Yes . While the overall pricing structure remains
2 unchanged, the Company is proposing updates to the derivation
3 of standby generation, transmission components, and excess
4 demand charges . These updates incorporate the Company' s Open
5 Access Transmission Tariff ("OATT") rate effective October 1,
6 2024, and revised cost inputs from the Company' s class cost-
7 of-service study for Schedule 9 Secondary and Primary Service
8 and Schedule 19 Primary Service.
9 Q. Is the Company proposing pricing changes for
10 Schedule 31?
11 A. Yes . The Company is also proposing to update the
12 standby charges for Amalgamated Sugar Company under Schedule
13 31, using the same methodology described for Schedule 45 . This
14 includes applying the OATT rate components and updated unit
15 costs from the Schedule 19 Primary Service cost-of-service
16 study. These changes are consistent with the methodology from
17 the Company' s last general rate case and is the same method
18 used for special contract pricing.
19 C. Schedule 46, Alternate Distribution Service
20 Q. What is Alternate Distribution Service?
21 A. Alternate Distribution Service is an optional
22 offering available to commercial and industrial customers who
23 desire increased reliability through redundancy. The service
24 allows for automatic switching to an alternate distribution
25 circuit in the event of a distribution-related outage on the
ANDERSON, DI 39
Idaho Power Company

1 customer' s primary circuit . This service is currently utilized
2 by six customers and is available to those taking service
3 under the Company' s large general service or large power
4 service schedules .
5 Q. What is the benefit of electing Alternate
6 Distribution Service?
7 A. Alternate Distribution Service provides an
8 additional layer of reliability by reducing the risk of a
9 complete service interruption caused by a single distribution
10 circuit failure . While the service does not guarantee
11 uninterrupted power, it reduces the likelihood that a
12 distribution-related outage will disrupt a customer' s
13 operations—particularly for customers without on-site backup
14 generation.
15 Q. Is the Company proposing pricing changes for
16 Schedule 46?
17 A. Yes . The proposed Capacity Charge derivation is
18 consistent with the Company' s last general rate case . These
19 costs are based on updated unit cost data from the class cost-
20 of-service study for Schedule 19 Primary Service .
21 Additionally, the Company proposes updates to the mileage
22 charge and average distribution line length, calculated using
23 the same methodology previously accepted by the Commission.
24 Q. How is the proposed Capacity Charge derived?
ANDERSON, DI 40
Idaho Power Company

1 A. The Capacity Charge is calculated using the
2 distribution demand-related revenue requirement components for
3 substations, primary lines, and primary transformers allocated
4 to Schedule 19 Primary Service. Specifically, these components
5 total $16, 697, 494 and are divided by a total billed demand of
6 4, 907, 546 kilowatts . These values are identified on page 7 of
7 Mr. Maloney' s Exhibit No . 37 .
8 Q. How is the mileage charge calculated?
9 A. The mileage charge is designed to recover the
10 operating and maintenance costs associated with constructing
11 and maintaining the additional distribution facilities
12 required to provide Alternate Distribution Service . The charge
13 is calculated based on the per-mile cost of constructing a
14 three-phase overhead distribution circuit, adjusted by the
15 Company' s proposed facilities charge for assets older than 31
16 years . This total is then divided by the total capacity of the
17 circuit to arrive at a per-mile, per-kilowatt cost.
18 D. Schedule 66, Miscellaneous Charges
19 Q. Is the Company proposing any changes to charges
20 for Schedule 66?
21 A. Yes . The Company is proposing to update the Rule
22 M Monthly Facilities Charge Rate. All other miscellaneous
23 charges were updated in the Company' s 2023 general rate case
24 and the Company is not proposing changes in this proceeding.
ANDERSON, DI 41
Idaho Power Company

1 Q. What monthly rates is the Company proposing for
2 facilities charges?
3 A. The Company is proposing to update the monthly
4 facilities charge rates as listed in Table 3 .
5 Table 3
6 Proposed Facilities Charge Rates
Facilities Facilities
Rate Schedule Installed 31 Years Installed More Than
or Less 31 Years
Schedule 9 1 . 42% 0 . 65%
Schedule 15 1 . 77% 1 . 77%
Schedule 19 1 . 42% 0 . 65%
Schedule 24 1 . 42% 0 . 65%
Schedule 29 1 . 42% 0 . 65%
Schedule 32 1 . 42% 0 . 65%
Schedule 41 1 . 21% 1 . 21%
Schedule 45 1 . 42% 0 . 65%
Schedule 46 1 . 42% 0 . 65%
7 Q. Is the Company proposing changes to the
8 methodology used to derive facilities charges?
9 A. No. The Company proposes to rely on the same
10 methodology and cost components that the Commission approved
11 in Case No. IPC-E-11-08 and IPC-E-23-11 .
12 Q. What is driving the proposed increase in the
13 monthly facilities charge rates?
14 A. The proposed increase in the monthly facilities
15 charge rates — 0 . 08 percent for facilities installed 31 years
16 or less and 0 . 04 percent for facilities installed more than 31
ANDERSON, DI 42
Idaho Power Company

1 years — is driven by increases in the requested rate of
2 return, operations and maintenance expenses, administrative
3 and general, and working capital requirements . These cost
4 increases are partially offset by a decrease in property tax
5 expense .
6 Q. What is the estimated change in the Company' s
7 revenue from the proposed facilities charge rates?
8 A. Overall, the Company estimates that its proposed
9 facilities charge rates will result in an increase to revenue
10 received through facilities charges of approximately $631, 800
11 per year.
12 IX. TARIFF ADMINISTRATION
13 Q. Is the Company proposing changes to its tariff
14 as part of this case?
15 A. Yes . The Company is requesting several
16 administrative and housekeeping edits to certain rules and
17 schedules within its tariff. These changes are intended to
18 ensure clarity, transparency, and consistency. I supervised
19 the coordination with internal customer-facing teams to
20 develop recommendations for these updates . Attachment Nos . 1
21 and 2 to the Application contain the legislative and clean
22 versions of the requested tariff changes .
23 Q. How did you arrive at the proposed changes to
24 the Company' s General Rules and Regulations?
ANDERSON, DI 43
Idaho Power Company

1 A. The changes proposed to the Company' s General
2 Rules and Regulations are the result of collaborative efforts
3 between representatives from various business units within the
4 Company.
5 Q. Do you intend to discuss each of the proposed
6 changes to the tariff?
7 A. No. While some proposed changes are substantive,
8 many are purely administrative or stylistic and do not
9 materially affect the function or interpretation of the tariff
10 provisions . Accordingly, I will explain the rationale for each
11 of the more substantive changes in the sections that follow.
12 E. Schedule 6, Schedule 8, and Schedule 84
13 Q. What changes is the Company proposing to
14 Schedules 6, 8, and 84?
15 A. The Company proposes several clarifying edits to
16 improve the transparency and administration of the existing
17 provisions . These changes are not intended to modify the
18 intent of prior Commission orders but instead aim to more
19 clearly reflect that intent in the tariff language . In
20 addition to administrative edits, the Company proposes
21 modifications related to the treatment of remaining financial
22 credits when a customer ends service, application of the
23 eligibility cap for irrigation customers, and revisions to the
24 process for determining project size when historical billing
25 demand is unavailable.
ANDERSON, DI 44
Idaho Power Company

1 Q. Please summarize the proposed clarifying edits .
2 A. In the Applicability section, the Company is
3 proposing two changes to the conditions for maintaining Legacy
4 status . First, Customers who expand their systems beyond
5 Legacy criteria do not need to agree to separate metering if
6 they do not wish to retain Legacy status for the original
7 system. The current tariff language could be interpreted to
8 mean the customer must agree to separate metering, which is
9 not consistent with the prior case history. The Company is
10 also proposing to add a condition to clarify that a customer
11 with Legacy status may self-forfeit that status . This
12 clarification is consistent with Staff' s Reply Comments in
13 Case No . IPC-E-23-14, which describe how termination of legacy
14 status may occur including when a self-generator self-forfeits
15 their legacy status .' Including clarifying language in the
16 tariff for these elements will ease administration of the
17 Legacy conditions for Company representatives .
18 The Company also proposes adding definitions for
19 "Financial Credit" and "kWh Credit" to distinguish between
20 credit types under Net Billing and Net Energy Metering without
21 changing how credits are administered.
1 In the Matter of Idaho Power'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 Methodology, Case No. IPC-E-23-14, Staff Reply Comments at 7 (Nov. 2,
2023) .
ANDERSON, DI 45
Idaho Power Company

1 Q. How does the Company currently administer excess
2 financial credits once a customer ends service?
3 A. Excess financial credits carry forward at a
4 given service point so long as the customer maintains electric
5 service at that point of delivery. If a customer ends service,
6 two conditions apply: (1) the financial credit can be
7 transferred in the event the customer is relocating within the
8 Company' s service area, and (2) if a customer discontinues
9 service and does not intend to reestablish service in the
10 Company' s service area, the unused credits will be paid out at
11 the time the final bill is prepared. In its order directing
12 this treatment, the Commission found:
13 [I] t reasonable that accumulated financial credits
14 be transferrable when a customer relocates within
15 the Company' s service area. At this time no time
16 limit will be set for such a transfer. Additionally,
17 if a customer completely discontinues service with
18 the Company, any accumulated unused financial
19 credits shall be paid out to the customer. The
20 Commission is cognizant of the potential behavior
21 impacts inherent in a system that pays out financial
22 credits; however, the Commission believes that the
23 limited conditions under which a customer may
24 receive a payout mitigates those impacts .z
25 Q. What challenges has the Company experienced in
26 administering this requirement?
27 A. If a customer ends service and does not
28 immediately establish a new account, Idaho Power must track
2 Case No. IPC-E-23-14, Order No. 36048 at 19 (Dec. 29, 2023) .
ANDERSON, DI 46
Idaho Power Company

1 the credit indefinitely. It is then the customer' s
2 responsibility to request a transfer when reestablishing
3 service. This process can result in confusion and inconsistent
4 customer experiences .
5 Q. What is the Company proposing?
6 A. The Company proposes to pay out any unused
7 financial credits at the time of final billing for Schedules
8 6, 8, and 84, consistent with how other customer credit
9 account balances are treated when a final bill is prepared.
10 This change will streamline internal processes and improve
11 clarity for customer support representatives .
12 Q. How does the Company propose to address existing
13 credit balances?
14 A. If the proposed changes are approved, Idaho
15 Power will issue refunds for any financial credits currently
16 being tracked, consistent with its standard refund practices .
17 Q. What is the current project eligibility cap for
18 Schedule 84 customers?
19 A. For commercial, industrial, and irrigation
20 customers taking service under Schedule 84, the project
21 eligibility cap is the greater of 100 kW or 100 percent of the
22 customer' s demand at the service point. This provision has
23 been in effect since January 1, 2024, pursuant to Order No.
24 36048 .
ANDERSON, DI 47
Idaho Power Company

1 Q. Has the Company proposed modifications to this
2 cap?
3 A. Yes . Based on its experience implementing the
4 cap, the Company submitted a clarifying tariff advice filing,
5 IPC-TAE-24-02, on June 17, 2024 . The Commission approved the
6 revisions at its July 23, 2024, decision meeting.
7 Q. Has the Company identified further issues in
8 administering this provision?
9 A. Yes . While the provisions for commercial and
10 industrial customers generally provide sufficient safeguards,
11 the Company has found that, for irrigation customers, the
12 existing criteria may allow installations that exceed actual
13 demand.
14 Q. Please explain the Company' s concerns .
15 A. Irrigation customers — unlike commercial or
16 industrial customers — generally have highly predictable
17 demand determined by the installed motor and pump equipment.
18 Once equipment is installed, irrigation load does not
19 typically fluctuate. Pumps operate in binary fashion: either
20 "on" or "off, " and when operating, they run at a fixed
21 capacity based on motor and pump specifications . Additionally,
22 irrigation service points experience relatively high turnover
23 due to crop rotations, ownership changes, or lease
24 arrangements, which may result in extended periods with no
25 historical billing data.
ANDERSON, DI 48
Idaho Power Company

1 Under the current tariff, if a customer lacks 12
2 months of recent billing history, they may qualify for
3 alternate sizing methods — including submission of equipment
4 documentation for use with a conversion factor. However, in
5 practice, many irrigation systems have only the motor
6 nameplate visible, and a customer may submit an application
7 based on an oversized motor even if the associated pump limits
8 actual usage . This could result in systems being sized in
9 excess of what is reasonably needed to serve the expected
10 load.
11 Q. What changes is the Company proposing?
12 A. The Company proposes to revise the tariff to
13 separate the project sizing provisions that apply to
14 commercial and industrial customers from those that apply to
15 irrigation customers . For commercial and industrial customers,
16 the existing options — such as relying on similar facilities
17 or third-party analysis — would remain. For irrigation
18 customers, the Company proposes to add specific criteria based
19 on the predictable nature of pump operation and motor-to-pump
20 sizing. The revised language would clarify how the conversion
21 factor is to be applied and prevent reliance solely on motor
22 nameplate ratings in cases where historical demand is
23 unavailable but the installed equipment has not changed. The
24 Company believes these proposed changes are consistent with
25 the intent of Order No. 36048 and will improve transparency,
ANDERSON, DI 49
Idaho Power Company

1 reduce customer confusion, and ensure more accurate system
2 sizing for irrigation applicants .
3 F. Schedule 68 , Interconnections to Customer Distributed
4 Energy Resources
5 Q. What changes to Schedule 68 is the Company
6 proposing as part of this case?
7 A. The Company is proposing several administrative
8 and housekeeping edits to Schedule 68, in addition to targeted
9 changes to improve clarity and transparency in the
10 interconnection application process .
11 Q. Please describe the current interconnection
12 application process .
13 A. Customers seeking to interconnect new or
14 expanded on-site generation systems must submit a completed
15 application that includes system specifications and a non-
16 refundable application fee. Once the application is received,
17 customers have one year to complete interconnection before the
18 application expires .
19 Q. Why is the Company proposing changes to the
20 application process, and what specific changes are included?
21 A. While most customers complete the
22 interconnection process within the current timeframes, the
23 Company has identified several opportunities to improve the
24 administration of Schedule 68 and enhance customer
25 understanding. The proposed changes include :
ANDERSON, DI 50
Idaho Power Company

1 (1) Adding a definition for "Incomplete
2 Application, "
3 (2) Clarifying the process for prospective customers
4 who do not yet have established electric service with
5 Idaho Power,
6 (3) Refining requirements for customer generators
7 when additional studies are needed beyond a
8 Feasibility Study, and
9 (4) Modifying the timeline for transitioning
10 existing customers to the appropriate on-site
11 generation service schedule.
12 Q. Why is the Company proposing to define
13 "Incomplete Application"?
14 A. The current tariff is silent on how to handle
15 applications that are missing required information. Company
16 representatives attempt to contact applicants to resolve
17 deficiencies, but in many cases, customers who are no longer
18 interested do not respond. Holding incomplete applications
19 open for the full year creates unnecessary administrative
20 burden. The Company proposes that if required information is
21 not received within 60 days of initial submission, the
22 application will be considered withdrawn.
23 Q. What is the Company proposing for applicants who
24 do not yet have established electric service?
ANDERSON, DI 51
Idaho Power Company

1 A. Some interconnection applications are submitted
2 for new construction projects or for customers who have not
3 yet begun taking service from Idaho Power. In these cases, the
4 Company proposes that the expiration of the interconnection
5 application be tied to the expected in-service date provided
6 in the application, rather than defaulting to a one-year
7 expiration. This change will reduce administrative burden and
8 improve alignment with project development timelines .
9 Q. Why is the Company proposing to modify the
10 timeline for moving a customer to the applicable on-site
11 generation schedule?
12 A. The Company has found that for customers taking
13 service under schedules with a Basic Load Capacity ("BLC")
14 component — such as Schedules 9 and 19 — transitioning
15 customers mid-billing cycle results in a loss of billing
16 history necessary to accurately calculate BLC. This occurs
17 because the billing system "closes" the account when the
18 contract is ended and "opens" a new contract under the new
19 rate schedule. To preserve this history, the Company proposes
20 that the rate schedule change occur no later than the next
21 billing cycle. This change will maintain billing accuracy
22 while ensuring customers are placed on the correct schedule in
23 a timely manner.
ANDERSON, DI 52
Idaho Power Company

1 G. Schedule 24 , Agricultural Irrigation Service
2 Q. What administrative changes to Schedule 24 is
3 the Company requesting as part of this case?
4 A. The Company is proposing changes to Schedule 24
5 to refine the Tier 1 and Tier 2 deposit criteria and to revise
6 the definition of "New Irrigation Customer" to improve
7 accuracy in customer records and simplify administration.
8 Q. Why is the Company proposing to revise the
9 definition of a New Irrigation Customer?
10 A. The current definition is restrictive,
11 particularly in cases where a customer has been financially
12 responsible for a Schedule 24 account but was not listed as
13 the account holder. This has created an unintended incentive
14 for customers to avoid account name changes in order to bypass
15 the deposit requirement applicable to new irrigation
16 customers . To address this, the Company proposes incorporating
17 a "financially responsible party" component into the
18 definition, which will better reflect actual customer behavior
19 and improve billing accuracy.
20 Q. How does the Company currently administer Tier 1
21 Deposits?
22 A. A Tier 1 Deposit is assessed on all Schedule 24
23 accounts when the customer meets any of the following
24 conditions : (1) receipt of two or more payment reminder
25 notices within the last twelve months; (2) service termination
ANDERSON, DI 53
Idaho Power Company

1 for nonpayment within the last four years with no subsequent
2 resumption of Schedule 24 service; or (3) a prior Tier 2
3 Deposit was required in the previous irrigation season.
4 Q. What changes is the Company proposing to Tier 1
5 deposit criteria?
6 A. The Company is proposing to add a screening
7 criterion to ensure that reminder notices are associated with
8 accounts that represent a meaningful portion of the customer' s
9 total irrigation billing. Specifically, a Tier 1 Deposit would
10 only be assessed if the total annual billed amount on the
11 accounts that received reminder notices is equal to or greater
12 than 15 percent of the customer' s total annual billed amount
13 across all its Schedule 24 accounts .
14 The Company encourages customers with multiple service
15 points to enroll in joint invoicing to simplify billing and
16 improve account visibility. However, in rare cases, some
17 accounts may remain outside of the joint invoice and generate
18 separate bills . This can lead to confusion if one of these
19 "orphaned" accounts receives two or more reminder notices and,
20 under current criteria, triggers a Tier 1 Deposit across all
21 accounts — even if the customer is otherwise in good standing.
22 Q. How are Tier 2 Deposits currently administered?
23 A. Tier 2 Deposits are required when a customer' s
24 Cumulative Past Due Balance — defined as the total of all past
25 due Schedule 24 accounts under the customer' s responsibility —
ANDERSON, DI 54
Idaho Power Company

1 equals or exceeds $1, 500 on December 31 . The deposit is
2 assessed across all Schedule 24 accounts .
3 Q. What changes is the Company proposing to Tier 2
4 deposit criteria?
5 A. The Company proposes three refinements :
6 (1) Grace Period Extension - Allowing an additional
7 five days beyond December 31 to satisfy the past due balance
8 before a Tier 2 Deposit is triggered. This adjustment is
9 intended to account for postal delays that may impact
10 customers ' ability to submit timely payments .
11 (2) Per-Service Threshold - A Tier 2 Deposit would
12 only be assessed if the Cumulative Past Due Balance is equal
13 to or greater than $1, 500 and the average past due balance per
14 service point is equal to or greater than $750 . This means
15 that customers with many accounts and a relatively small
16 balance per account would not trigger a deposit requirement
17 unless both conditions are met.
18 (3) Absolute Threshold - Regardless of the number of
19 service points, if the customer' s total past due balance
20 equals or exceeds $10, 000, a Tier 2 Deposit would be required.
21 These changes are intended to improve fairness and
22 transparency while preserving the Company' s ability to manage
23 financial risk associated with past-due irrigation accounts .
24 The proposed balance thresholds will allow the Company to
ANDERSON, DI 55
Idaho Power Company

1 better assign deposits to its highest risk customers and avoid
2 unwarranted impact to its lower credit risk customers .
3 H. Rule H, New Service Attachments and Distribution Line
4 Installations or Alterations
5 Q. What changes is the Company proposing to Rule H?
6 A. The Company is proposing one minor change to
7 allow greater flexibility on removals of unused distribution
8 equipment located in high fire risk zones and is proposing to
9 expand the tariff-based charges in Rule H to include a
10 standard charge for Three-Phase Underground Service Attachment
11 requests involving a single run of cable. Currently, these
12 requests require a customer-specific work order, even for
13 relatively standardized installations . This change would align
14 the treatment of single-run three-phase installations with the
15 Company' s existing tariff-based approach for single-phase
16 underground services - as outlined on Page H-7, Section
17 4 (b) (iii) - and improve administrative efficiency.
18 Q. How does the Company currently administer
19 charges for Three-Phase Underground Service Attachments?
20 A. Under current practice, applicants requesting
21 Three-Phase Underground Service must pay a non-refundable
22 charge equal to the full estimated Work Order Cost. This
23 process requires customers to submit a formal service request,
24 pay applicable engineering fees, and wait for the Company to
25 complete the cost estimate—typically a two- to three-week
26 timeline .
ANDERSON, DI 56
Idaho Power Company

1 Q. Why is the Company proposing to move to tariff-
2 based charges for these requests?
3 A. Single-run three-phase underground installations
4 are relatively standard in design and cost, much like single-
5 phase underground services . Moving to a tariff-based charge
6 for these installations will streamline the process for
7 customers and reduce internal administrative workload, while
8 maintaining fair and consistent pricing for all applicants .
9 Q. How does the Company propose to calculate the
10 new tariff-based charge for Three-Phase Underground Service?
11 A. The proposed charge is based on a standard
12 installation scenario: 100 feet of cable installed by a two-
13 person crew with 30 minutes of travel time. The calculation
14 uses the same methodology and overhead factors employed in the
15 Company' s most recent Rule H annual update, consistent with
16 Commission Order Nos . 30853, 30955, and 32472 .
17 Q. Is the Company proposing any changes to other
18 charges, credits, or rates under Rule H?
19 A. No. In accordance with Commission Order Nos .
20 30853, 30955 and 32472, the Company will continue to submit
21 its annual update to Rule H charges, credits, and overhead
22 rates prior to January 1 each year. The Company is not
23 proposing changes to any other components of Rule H in this
24 proceeding. The proposed Three-Phase Underground Service
ANDERSON, DI 57
Idaho Power Company

1 Attachment charge will be incorporated into future annual
2 updates .
3 I . Rule N, Special Arrangements for Substation Allowances
4 and Transmission Vested Interest
5 Q. Please describe the Company' s proposed Rule N.
6 A. The Company is proposing to incorporate the
7 existing Substation Allowance and Transmission Vested Interest
8 provisions currently located in Schedule 19 into a "rule" to
9 be more consistent with other general rules that could apply
10 to multiple customer classes . These provisions would be
11 removed from Schedule 19 and relocated into Rule N for
12 improved administrative consistency and broader applicability.
13 Q. Why is the Company proposing to move these
14 provisions into Rule N?
15 A. The Company believes that the Substation
16 Allowance and Transmission Vested Interest provisions are
17 better suited, for administrative purposes, within a general
18 tariff rule rather than being limited to a specific schedule .
19 While relatively uncommon, there are instances where a
20 Schedule 9 customer may be required to fund substation
21 upgrades in anticipation of increasing load and ultimately
22 transitioning to Schedule 19 .
23 Currently, because the Substation Allowance provisions
24 reside solely in Schedule 19, such customers are ineligible
25 for the allowance at the time the upgrades are made .
26 Relocating these provisions to Rule N ensures that eligibility
ANDERSON, DI 58
Idaho Power Company

1 is based on the nature of the investment and service
2 characteristics—rather than a customer' s current schedule
3 designation—and provides for more consistent and equitable
4 administration across similarly situated large service
5 customers .
6 Q. Beyond relocating the provisions to a rule and
7 expanding eligibility to Schedule 9, is the Company proposing
8 any changes to how the Substation Allowance or Transmission
9 Vested Interest provisions are administered?
10 A. No. The Company is not proposing substantive
11 changes to how the Substation Allowance or Transmission Vested
12 Interest provisions are administered. The proposed relocation
13 to Rule N is intended solely to improve administrative
14 consistency and expand eligibility to Schedule 9 customers,
15 without modifying the existing criteria, calculation
16 methodology, or application of the provisions .
17 Q. Does this conclude your direct testimony in this
18 case?
19 A. Yes, it does .
20
21
ANDERSON, DI 59
Idaho Power Company

1 DECLARATION OF GRANT T. ANDERSON
2 I, Grant T . Anderson, declare under penalty of
3 perjury under the laws of the state of Idaho:
4 1 . My name is Grant T . Anderson. I am employed
5 by Idaho Power Company as the Pricing and Tariff
6 Administration Leader in the Regulatory Affairs Department.
7 2 . On behalf of Idaho Power, I present this
8 pre-filed direct testimony and Exhibit Nos . 44 and 45 in
9 this matter.
10 3 . To the best of my knowledge, my pre-filed
11 direct testimony and exhibits are true and accurate .
12 I hereby declare that the above statement is true to
13 the best of my knowledge and belief, and that I understand
14 it is made for use as evidence before the Idaho Public
15 Utilities Commission and is subject to penalty for perjury.
16 SIGNED this 30th day of May 2025, at Boise, Idaho.
��� �12�G�Q/ZdByL
17
18 Signed:
19 Grant T . Anderson
ANDERSON, DI 60
Idaho Power Company

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-16
IDAHO POWER COMPANY
ANDERSON , DI
TESTIMONY
EXHIBIT NO. 44

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Residential Service
Schedule 1 and Schedule 6
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 6,449,658 $ 15.00 $ 96,744,876 $ 25.00 $ 161,241,460
(2) Minimum Charge 54,848 3.00 164,543 3.00 164,543
(3) Summer Energy(Jun-Sep)
(4) First 800 kWh 1,264,784,734 $ 0.101779 $ 128,728,525 $ 0.125685 $ 158,964,469
(5) 801-2,000 kWh 543,222,448 0.122380 66,479,563 0.137920 74,921,240
(6) All Additional kWh 95,968,279 0.145385 13,952,348 0.151580 14,546,872
(7) Subtotal-Summer Energy 1,903,975,460 $ 0.109855 $ 209,160,437 $ 0.130481 $ 248,432,581
(8) Non-Summer Energy(Oct-Mays
(9) First 800 kWh 2,550,684,323 $ 0.089569 $ 228,462,244 $ 0.099581 $ 253,999,696
(10) 801-2,000 kWh 1,029,597,595 0.098750 101,672,763 0.104567 107,661,932
(11) All Additional kWh 358,232,694 0.109361 39,176,686 0.110331 39,524,171
(12) Subtotal- Non-Summer Energy 3,938,514,612 $ 0.093769 $ 369,311,692 $ 0.101862 $ 401,185,799
(13) Subtotal-Total Energy 5,842,490,073 $ 578,472,129 $ 649,618,380
(14) Transfer Adjustment Revenue 17,688,957
(15) Total Adjusted Base Revenue $ 693,070,505 $ 811,024,383
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 1 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Residential Service Standard Plan
Schedule 1
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 6,223,666 $ 15.00 $ 93,354,993 $ 25.00 $ 155,591,655
(2) Minimum Charge 54,176 3.00 162,527 3.00 162,527
(3) Summer Energy(Jun-Sep)
(4) First 800 kWh 1,224,254,394 $ 0.101779 $ 124,603,388 $ 0.125685 $ 153,870,414
(5) 801-2,000 kWh 532,104,954 0.122380 65,119,004 0.137920 73,387,915
(6) All Additional kWh 93,673,900 0.145385 13,618,780 0.151580 14,199,090
(7) Subtotal-Summer Energy 1,850,033,248 $ 0.109912 $ 203,341,172 $ 0.130515 $ 241,457,419
(8) Non-Summer Energy(Oct-Mays
(9) First 800 kWh 2,464,568,540 $ 0.089569 $ 220,748,940 $ 0.099581 $ 245,424,200
(10) 801-2,000 kWh 997,228,306 0.098750 98,476,295 0.104567 104,277,172
(11) All Additional kWh 343,191,848 0.109361 37,531,804 0.110331 37,864,700
(12) Subtotal- Non-Summer Energy 3,804,988,695 $ 0.093760 $ 356,757,039 $ 0.101857 $ 387,566,072
(13) Subtotal-Total Energy 5,655,021,943 $ 560,098,211 $ 629,023,490
(14) Transfer Adjustment Revenue 17,121,371
(15) Total Adjusted Base Revenue $ 670,737,102 $ 784,777,672
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 2 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Residential Service On-Site Generation
Schedule 6
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 225,992 $ 15.00 $ 3,389,883 $ 25.00 $ 5,649,805
(2) Minimum Charge 672 3.00 2,016 3.00 2,016
(3) Summer Energy(Jun-Sep)
(4) First 800 kWh 40,530,339 $ 0.101779 $ 4,125,137 $ 0.125685 $ 5,094,056
(5) 801-2,000 kWh 11,117,494 0.122380 1,360,559 0.137920 1,533,325
(6) All Additional kWh 2,294,379 0.145385 333,568 0.151580 347,782
(7) Subtotal-Summer Energy 53,942,212 $ 0.107880 $ 5,819,265 $ 0.129308 $ 6,975,162
(8) Non-Summer Energy(Oct-Mays
(9) First 800 kWh 86,115,783 $ 0.089569 $ 7,713,305 $ 0.099581 $ 8,575,496
(10) 801-2,000 kWh 32,369,289 0.098750 3,196,467 0.104567 3,384,759
(11) All Additional kWh 15,040,846 0.109361 1,644,882 0.110331 1,659,472
(12) Subtotal- Non-Summer Energy 133,525,918 $ 0.094024 $ 12,554,654 $ 0.102001 $ 13,619,727
(13) Subtotal-Total Energy 187,468,130 $ 18,373,918 $ 20,594,889
(14) Transfer Adjustment Revenue 567,586
(15) Total Adjusted Base Revenue $ 22,333,403 $ 26,246,710
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 3 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Master-Metered Mobile Home Park Residential Service
Schedule 3
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 227 $ 15.00 $ 3,406 $ 25.00 $ 5,677
(2) Total Energy 5,073,613 0.109482 555,469 0.131324 666,287
(3) Transfer Adjustment Revenue 15,361
(4) Total Adjusted Base Revenue $ 574,237 $ 671,964
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 4 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Residential Service-Time-of-Use
Schedule 5+6 TOU
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 12,228 $ 15.00 $ 183,414 $ 25.00 $ 305,690
(2) Minimum Charge 14 3.00 42 3.00 42
(3) Summer Energy(Jun-Sep)
(4) On-Peak 1,031,679 $ 0.252957 $ 260,970 $ 0.322968 $ 333,199
(5) Mid-Peak 1,078,494 0.126480 136,408 0.161484 174,160
(6) Off-Peak 3,821,764 0.063241 241,692 0.080742 308,577
(7) Subtotal-Summer Energy 5,931,938 $ 0.107734 $ 639,071 $ 0.137550 $ 815,936
(8) Non-Summer Energy(Oct-Mays
(9) On-Peak 3,071,371 $ 0.131150 $ 402,810 $ 0.143396 $ 440,422
(10) Off-Peak 9,388,580 0.087433 820,872 0.095597 897,520
(11) Subtotal- Non-Summer Energy 12,459,952 $ 0.098209 $ 1,223,682 $ 0.107380 $ 1,337,942
(12) Subtotal-Total Energy 18,391,889 $ 1,862,753 $ 2,153,878
(13) Transfer Adjustment Revenue 55,684
(14) Total Adjusted Base Revenue $ 2,101,892 $ 2,459,610
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 5 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Residential Service-Time-of-Use Plan
Schedule 5
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 11,882 $ 15.00 $ 178,224 $ 25.00 $ 297,040
(2) Minimum Charge 11 3.00 33 3.00 33
(3) Summer Energy(Jun-Sep)
(4) On-Peak 1,017,779 $ 0.252957 $ 257,454 $ 0.322968 $ 328,710
(5) Mid-Peak 1,073,980 0.126480 135,837 0.161484 173,431
(6) Off-Peak 3,741,492 0.063241 236,616 0.080742 302,096
(7) Subtotal-Summer Energy 5,833,251 $ 0.107986 $ 629,907 $ 0.137871 $ 804,236
(8) Non-Summer Energy(Oct-Mays
(9) On-Peak 3,016,127 $ 0.131150 $ 395,565 $ 0.143396 $ 432,500
(10) Off-Peak 9,173,697 0.087433 802,084 0.095597 876,978
(11) Subtotal- Non-Summer Energy 12,189,823 $ 0.098250 $ 1,197,649 $ 0.107424 $ 1,309,478
(12) Subtotal-Total Energy 18,023,075 $ 1,827,556 $ 2,113,715
(13) Transfer Adjustment Revenue 54,567
(14) Total Adjusted Base Revenue $ 2,060,380 $ 2,410,788
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 6 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Residential Service-Time-of-Use
Schedule 6 TOU
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 346 $ 15.00 $ 5,190 $ 25.00 $ 8,650
(2) Minimum Charge 3 3.00 9 3.00 9
(3) Summer Energy(Jun-Sep)
(4) On-Peak 13,900 $ 0.252957 $ 3,516 $ 0.322968 $ 4,489
(5) Mid-Peak 4,514 0.126480 571 0.161484 729
(6) Off-Peak 80,273 0.063241 5,077 0.080742 6,481
(7) Subtotal-Summer Energy 98,686 $ 0.092855 $ 9,164 $ 0.118553 $ 11,700
(8) Non-Summer Energy(Oct-Mays
(9) On-Peak 55,245 $ 0.131150 $ 7,245 $ 0.143396 $ 7,922
(10) Off-Peak 214,884 0.087433 18,788 0.095597 20,542
(11) Subtotal- Non-Summer Energy 270,128 $ 0.096374 $ 26,033 $ 0.105373 $ 28,464
(12) Subtotal-Total Energy 368,815 $ 35,197 $ 40,164
(13) Transfer Adjustment Revenue 1,117
(14) Total Adjusted Base Revenue $ 41,512 $ 48,822
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 7 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Small General Service
Schedule 7 and Schedule 8
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 361,406 $ 25.00 $ 9,035,148 $ 30.00 $ 10,842,177
(2) Minimum Charge 294 3.00 881 3.00 881
(3) Summer Energy(Jun-Sep)
(4) First 300 kWh 21,553,455 $ 0.074534 $ 1,606,465 $ 0.088802 $ 1,913,990
(5) All Additional kWh 25,566,818 0.085176 2,177,679 0.101485 2,594,649
(6) Subtotal-Summer Energy 47,120,273 $ 0.080308 $ 3,784,145 $ 0.095684 $ 4,508,638
(7) Non-Summer Energy(Oct-May)
(8) First 300 kWh 44,503,584 $ 0.074534 $ 3,317,030 $ 0.088802 $ 3,952,007
(9) All Additional kWh 48,834,292 0.074552 3,640,694 0.088827 4,337,804
(10) Subtotal- Non-Summer Energy 93,337,877 $ 0.074543 $ 6,957,724 $ 0.088815 $ 8,289,811
(11) Subtotal-Total Energy 140,458,150 $ 10,741,869 $ 12,798,449
(12) Transfer Adjustment Revenue 425,257
(13) Total Adjusted Base Revenue $ 20,203,154 $ 23,641,507
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 8 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Small General Service
Schedule 7
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 360,412 $ 25.00 $ 9,010,298 $ 30.00 $ 10,812,357
(2) Minimum Charge 294 3.00 881 3.00 881
(3) Summer Energy(Jun-Sep)
(4) First 300 kWh 21,484,436 $ 0.074534 $ 1,601,321 $ 0.088802 $ 1,907,861
(5) All Additional kWh 25,463,564 0.085176 2,168,885 0.101485 2,584,170
(6) Subtotal-Summer Energy 46,948,000 $ 0.080306 $ 3,770,205 $ 0.095681 $ 4,492,031
(7) Non-Summer Energy(Oct-May)
(8) First 300 kWh 44,366,384 $ 0.074534 $ 3,306,804 $ 0.088802 $ 3,939,824
(9) All Additional kWh 48,613,690 0.074552 3,624,248 0.088827 4,318,208
(10) Subtotal- Non-Summer Energy 92,980,074 $ 0.074543 $ 6,931,052 $ 0.088815 $ 8,258,032
(11) Subtotal-Total Energy 139,928,074 $ 10,701,257 $ 12,750,063
(12) Transfer Adjustment Revenue 423,652
(13) Total Adjusted Base Revenue $ 20,136,088 $ 23,563,301
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 9 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Small General Service On-Site Generation
Schedule 8
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 994 $ 25.00 $ 24,850 $ 30.00 $ 29,820
(2) Minimum Charge - 3.00 - 3.00 -
(3) Summer Energy(Jun-Sep)
(4) First 300 kWh 69,019 $ 0.074534 $ 5,144 $ 0.088802 $ 6,129
(5) All Additional kWh 103,254 0.085176 8,795 0.101485 10,479
(6) Subtotal-Summer Energy 172,273 $ 0.080912 $ 13,939 $ 0.096404 $ 16,608
(7) Non-Summer Energy(Oct-May)
(8) First 300 kWh 137,200 $ 0.074534 $ 10,226 $ 0.088802 $ 12,184
(9) All Additional kWh 220,603 0.074552 16,446 0.088827 19,595
(10) Subtotal- Non-Summer Energy 357,803 $ 0.074545 $ 26,672 $ 0.088817 $ 31,779
(11) Subtotal-Total Energy 530,076 $ 40,611 $ 48,387
(12) Transfer Adjustment Revenue 1,605
(13) Total Adjusted Base Revenue $ 67,066 $ 78,207
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 10 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Large General Service
Schedule 9 Secondary Service-Standard (Default)
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 474,816 $ 25.00 $ 11,870,403 $ 30.00 $ 14,244,483
(2) Minimum Charge 247 3.00 742 3.00 742
(3) Basic Charge
(4) Total Basic Charge 15,582,930 $ 1.58 $ 24,621,029 $ 2.03 $ 31,633,347
(5) Demand Charge
(6) Summer(Jun-Sep) 4,171,093 $ 8.12 $ 33,869,272 $ 10.14 $ 42,294,879
(7) Non-Summer(Oct-May) 7,373,578 6.39 47,117,161 8.16 60,168,393
(8) Total Demand 11,544,670 $ 80,986,433 $ 102,463,272
(9) Energy Charge
(10) Summer(Jun-Sep) 1,204,733,146 $ 0.054658 $ 65,848,304 $ 0.054088 $ 65,161,606
(11) Non-Summer(Oct-May) 2,200,115,815 0.052721 115,992,306 0.053804 118,375,031
(12) Subtotal-Total Energy 3,404,848,961 $ 181,840,610 $ 183,536,638
(13) Transfer Adjustment Revenue 10,308,657
(14) Total Adjusted Base Revenue $ 309,627,873 $ 331,878,482
$ 299,319,216
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 11 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Large General Service
Schedule 9 Secondary Service-Time-of-Use(Optional)
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 474,816 $ 25.00 $ 11,870,403 $ 30.00 $ 14,244,483
(2) Minimum Charge 247 3.00 742 3.00 742
(3) Basic Charge
(4) Total Basic Charge 15,582,930 $ 1.58 $ 24,621,029 $ 2.03 $ 31,633,347
(5) Demand Charge
(6) Summer(Jun-Sep) 4,171,093 $ 8.12 $ 33,869,272 $ 10.14 $ 42,294,879
(7) Non-Summer(Oct-May) 7,373,578 6.39 47,117,161 8.16 60,168,393
(8) Total Demand 11,544,670 $ 80,986,433 $ 102,463,272
(9) Summer Energy(Jun-Sep)
(10) On-Peak 165,847,351 $ 0.058489 $ 9,700,246 $ 0.071725 $ 11,895,401
(11) Mid-Peak 238,538,268 0.058489 13,951,865 0.060348 14,395,307
(12) Off-Peak 800,347,526 0.052709 42,185,518 0.048568 38,871,279
(13) Subtotal-Summer Energy 1,204,733,146 $ 0.054649 $ 65,837,628 $ 0.054088 $ 65,161,987
(14) Non-Summer Energy(Oct-May)
(15) On-Peak 491,567,320 $ 0.055755 $ 27,407,336 $ 0.059560 $ 29,277,750
(16) Mid-Peak 516,485,446 0.053259 27,507,498 0.054608 28,204,237
(17) Off-Peak 1,192,063,049 0.051273 61,120,649 0.051083 60,894,157
(18) Subtotal- Non-Summer Energy 2,200,115,815 $ 0.052741 $ 116,035,483 $ 0.053805 $ 118,376,144
(19) Subtotal-Total Energy 3,404,848,961 $ 181,873,111 $ 183,538,131
(20) Transfer Adjustment Revenue 10,308,657
(21) Total Adjusted Base Revenue $ 309,660,375 $ 331,879,975
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 12 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Large General Service
Schedule 9 Primary Service
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 3,501 $ 340.00 $ 1,190,272 $ 360.00 $ 1,260,288
(2) Minimum Charge 2 50.00 100 50.00 100
(3) Basic Charge
(4) Total Basic Charge 2,079,364 $ 1.83 $ 3,805,236 $ 2.22 $ 4,616,188
(5) Demand Charge
(6) Summer(Jun-Sep) 476,216 $ 8.35 $ 3,976,402 $ 11.04 $ 5,257,422
(7) Non-Summer(Oct-May) 1,198,406 7.91 9,479,390 9.91 11,876,202
(8) Total Demand 1,674,622 $ 13,455,792 $ 17,133,624
(9) On-Peak Summer Demand (Jun-Sep) 468,866 $ 1.59 $ 745,497 $ 2.10 $ 984,618
(10) Summer Energy(Jun-Sep)
(11) On-Peak 32,775,131 $ 0.053937 $ 1,767,792 $ 0.066710 $ 2,186,429
(12) Mid-Peak 46,014,976 0.053937 2,481,910 0.055532 2,555,304
(13) Off-Peak 161,805,090 0.048346 7,822,629 0.043957 7,112,466
(14) Subtotal-Summer Energy 240,595,198 $ 0.050177 $ 12,072,331 $ 0.049270 $ 11,854,199
(15) Non-Summer Energy(Oct-May)
(16) On-Peak 93,275,039 $ 0.048995 $ 4,570,011 $ 0.054064 $ 5,042,822
(17) Mid-Peak 96,201,361 0.046579 4,480,963 0.049269 4,739,745
(18) Off-Peak 224,818,193 0.044649 10,037,908 0.045854 10,308,813
(19) Subtotal- Non-Summer Energy 414,294,594 $ 0.046076 $ 19,088,881 $ 0.048495 $ 20,091,380
(20) Subtotal-Total Energy 654,889,792 $ 31,161,212 $ 31,945,579
(21) Transfer Adjustment Revenue 1,982,771
(22) Total Adjusted Base Revenue $ 52,340,880 $ 55,940,398
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 13 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Large General Service
Schedule 9 Transmission Service
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 68 $ 340.00 $ 23,120 $ 360.00 $ 24,480
(2) Minimum Charge - 50.00 - 50.00 -
(3) Basic Charge
(4) Total Basic Charge 18,439 $ 1.09 $ 20,099 $ 0.96 $ 17,702
(5) Demand Charge
(6) Summer(Jun-Sep) 5,575 $ 7.38 $ 41,142 $ 8.63 $ 48,110
(7) Non-Summer(Oct-May) 8,873 6.46 57,319 8.44 74,887
(8) Total Demand 14,448 $ 98,460 $ 122,997
(9) On-Peak Summer Demand (Jun-Sep) 3,731 $ 1.59 $ 5,933 $ 2.10 $ 7,836
(10) Summer Energy(Jun-Sep)
(11) On-Peak 135,603 $ 0.053305 $ 7,228 $ 0.068460 $ 9,283
(12) Mid-Peak 213,681 0.053305 11,390 0.056891 12,157
(13) Off-Peak 958,526 0.047648 45,672 0.044914 43,051
(14) Subtotal-Summer Energy 1,307,810 $ 0.049159 $ 64,290 $ 0.049312 $ 64,491
(15) Non-Summer Energy(Oct-May)
(16) On-Peak 510,120 $ 0.048079 $ 24,526 $ 0.054073 $ 27,584
(17) Mid-Peak 558,666 0.045663 25,510 0.049282 27,532
(18) Off-Peak 1,214,966 0.043725 53,124 0.045870 55,731
(19) Subtotal- Non-Summer Energy 2,283,752 $ 0.045172 $ 103,161 $ 0.048537 $ 110,846
(20) Subtotal-Total Energy 3,591,562 $ 167,451 $ 175,338
(21) Transfer Adjustment Revenue 10,874
(22) Total Adjusted Base Revenue $ 325,937 $ 348,352
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 14 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Large Power Service
Schedule 19 Secondary Service
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 12 $ 85.00 $ 1,020 $ 125.00 $ 1,500
(2) Minimum Charge - 3.00 - 3.00 -
(3) Basic Charge
(4) Total Basic Charge 14,300 $ 2.01 $ 28,743 $ 2.47 $ 35,321
(5) Demand Charge
(6) Summer(Jun-Sep) 4,155 $ 10.50 $ 43,629 $ 13.99 $ 58,130
(7) Non-Summer(Oct-May) 8,540 8.45 72,163 12.01 102,565
(8) Total Demand 12,695 $ 115,791 $ 160,695
(9) On-Peak Summer Demand (Jun-Sep) 3,811 $ 1.82 $ 6,936 $ 2.42 $ 9,222
(10) Summer Energy(Jun-Sep)
(11) On-Peak 306,402 $ 0.059941 $ 18,366 $ 0.073300 $ 22,459
(12) Mid-Peak 387,352 0.059941 23,218 0.062088 24,050
(13) Off-Peak 1,413,300 0.054287 76,724 0.050473 71,333
(14) Subtotal-Summer Energy 2,107,054 $ 0.056149 $ 118,308 $ 0.055928 $ 117,843
(15) Non-Summer Energy(Oct-May)
(16) On-Peak 944,371 $ 0.054204 $ 51,189 $ 0.060834 $ 57,450
(17) Mid-Peak 976,851 0.051783 50,584 0.055984 54,688
(18) Off-Peak 2,418,525 0.049842 120,544 0.052530 127,045
(19) Subtotal- Non-Summer Energy 4,339,747 $ 0.051228 $ 222,317 $ 0.055115 $ 239,183
(20) Subtotal-Total Energy 6,446,801 $ 340,625 $ 357,026
(21) Transfer Adjustment Revenue 19,519
(22) Total Adjusted Base Revenue $ 512,634 $ 563,764
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 15 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Large Power Service
Schedule 19 Primary Service
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 1,560 $ 415.00 $ 647,442 $ 490.00 $ 764,449
(2) Minimum Charge - 50.00 - 50.00 -
(3) Basic Charge
(4) Total Basic Charge 4,818,510 $ 2.21 $ 10,648,907 $ 2.60 $ 12,528,125
(5) Demand Charge
(6) Summer(Jun-Sep) 1,468,360 $ 10.04 $ 14,742,330 $ 13.09 $ 19,220,827
(7) Non-Summer(Oct-May) 2,805,397 8.64 24,238,630 11.93 33,468,387
(8) Total Demand 4,273,757 $ 38,980,961 $ 52,689,214
(9) On-Peak Summer Demand (Jun-Sep) 1,297,943 $ 1.59 $ 2,063,729 $ 2.07 $ 2,686,742
(10) Summer Energy(Jun-Sep)
(11) On-Peak 104,043,423 $ 0.052314 $ 5,442,928 $ 0.066358 $ 6,904,113
(12) Mid-Peak 134,487,570 0.052314 7,035,583 0.055115 7,412,282
(13) Off-Peak 492,482,409 0.046655 22,976,767 0.043474 21,410,180
(14) Subtotal-Summer Energy 731,013,402 $ 0.048502 $ 35,455,277 $ 0.048873 $ 35,726,576
(15) Non-Summer Energy(Oct-May)
(16) On-Peak 308,030,308 $ 0.047227 $ 14,547,347 $ 0.053897 $ 16,601,910
(17) Mid-Peak 315,781,072 0.044805 14,148,571 0.049044 15,487,167
(18) Off-Peak 795,765,487 0.042863 34,108,896 0.045589 36,278,153
(19) Subtotal- Non-Summer Energy 1,419,576,868 $ 0.044242 $ 62,804,814 $ 0.048160 $ 68,367,229
(20) Subtotal-Total Energy 2,150,590,270 $ 98,260,092 $ 104,093,805
(21) Subtotal 19P Excluding Clean Energy Your Way $ 150,601,129 $ 172,762,335
(22) Schedule 62 Clean Energy Your Way-Optional
(23) Summer Embedded Energy Fixed Cost (June-Sep)
(24) On-Peak 2,391,844 $ 0.010012 $ 23,947 $ 0.016993 $ 40,645
(25) Mid-Peak 5,945,167 0.010012 59,523 0.016993 101,026
(26) Off-Peak 262,608 0.009611 2,524 0.016993 4,462
(27) Subtotal-Summer Embedded Energy Fixed( 8,599,619 $ 0.010000 $ 85,994 $ 0.016993 $ 146,133
(28) Non-Summer Embedded Energy Fixed Cost (Oct-May)
(29) On-Peak 3,128,757 $ 0.018270 $ 57,162 $ 0.016745 $ 52,391
(30) Mid-Peak 5,411,634 0.018130 98,113 0.016745 90,618
(31) Off-Peak 1,024,877 0.018018 18,466 0.016745 17,162
(32) Subtotal- Non-Summer Embedded Energy Fi 9,565,268 $ 0.018164 $ 173,742 $ 0.016745 $ 160,170
(33) Subtotal-Total Embedded Energy Fixed Cost 18,164,887 $ 259,736 $ 306,304
(34) Transfer Adjustment Revenue 6,511,213
(35) Total Adjusted Base Revenue $ 157,372,078 $ 173,068,639
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 16 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Large Power Service
Schedule 19 Transmission Service
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 36 $ 415.00 $ 14,940 $ 490.00 $ 17,640
(2) Minimum Charge - 50.00 - 50.00 -
(3) Basic Charge
(4) Total Basic Charge 74,736 $ 1.87 $ 139,756 $ 1.72 $ 128,546
(5) Demand Charge
(6) Summer(Jun-Sep) 23,215 $ 10.20 $ 236,791 $ 14.18 $ 329,185
(7) Non-Summer(Oct-May) 48,951 8.78 429,791 12.42 607,974
(8) Total Demand 72,166 $ 666,582 $ 937,159
(9) On-Peak Summer Demand (Jun-Sep) 18,352 $ 1.59 $ 29,180 $ 2.07 $ 37,990
(10) Summer Energy(Jun-Sep)
(11) On-Peak 1,722,227 $ 0.052142 $ 89,800 $ 0.067062 $ 115,496
(12) Mid-Peak 2,183,930 0.052142 113,874 0.055665 121,568
(13) Off-Peak 9,142,393 0.046451 424,673 0.043865 401,031
(14) Subtotal-Summer Energy 13,048,549 $ 0.048155 $ 628,348 $ 0.048902 $ 638,095
(15) Non-Summer Energy(Oct-May)
(16) On-Peak 5,624,628 $ 0.046927 $ 263,947 $ 0.053955 $ 303,477
(17) Mid-Peak 5,644,025 0.044504 251,182 0.049099 277,116
(18) Off-Peak 14,737,529 0.042561 627,244 0.045641 672,636
(19) Subtotal- Non-Summer Energy 26,006,182 $ 0.043927 $ 1,142,373 $ 0.048190 $ 1,253,228
(20) Subtotal-Total Energy 39,054,731 $ 1,770,721 $ 1,891,324
(21) Transfer Adjustment Revenue 118,244
(22) Total Adjusted Base Revenue $ 2,739,423 $ 3,012,658
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 17 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Agricultural Irrigation Service
Schedule 24 Secondary Service
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Current Season-Meter Read Cycle
(2) Service Charge In-Season 78,564 $ 30.00 $ 2,356,905
(3) Service Charge Out-of-Season 158,480 6.00 950,880
(4) Minimum Charge 538 3.00 1,615
(5) Demand Charge(Current Season)
(6) In-Season 3,891,290 $ 15.06 $ 58,602,829
(7) Out-of-Season - - -
(8) Energy Charge(Current Season)
(9) In-Season 1,441,717,277 $ 0.061295 $ 88,370,060
(10) Out-of-Season 328,446,778 0.072053 23,665,576
(11) Total Energy 1,770,164,055 $ 112,035,636
(12) Proposed Season-Calendar Month
(13) Service Charge In-Season 78,564 $ 35.00 $ 2,749,723
(14) Service Charge Out-of-Season 158,480 9.00 1,426,320
(15) Minimum Charge 538 3.00 1,615
(16) Demand Charge(Proposed Season)
(17) In-Season 3,790,953 $ 18.75 $ 71,080,369
(18) Out-of-Season - - -
(19) Energy Charge(Proposed Season)
(20) In-Season 1,398,685,535 $ 0.074279 $ 103,892,963
(21) Out-of-Season 371,525,754 0.082558 30,672,423
(22) Total Energy 1,770,211,289 $ 134,565,386
(23) Transfer Adjustment Revenue 5,359,420
(24) Total Adjusted Base Revenue $ 179,307,284 $ 209,823,412
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 18 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Agricultural Irrigation Service
Schedule 24 Transmission Service
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge In-Season - $ 415.00 $ - $ 490.00 $ -
(2) Service Charge Out-of-Season - 6.00 - 9.00 -
(3) Minimum Charge - 3.00 - 3.00 -
(4) Demand Charge
(5) In-Season - $ 13.92 $ - $ 17.33 $ -
(6) Out-of-Season - - -
(7) Energy Charge
(8) In-Season - $ 0.057529 $ - $ 0.069715 $ -
(9) Out-of-Season - 0.067352 - 0.077172 -
(10) Total Energy - $ - $ -
(11) Transfer Adjustment Revenue -
(12) Total Adjusted Base Revenue $ - $ -
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 19 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Dusk to Dawn Customer Lighting
Schedule 15
Column (A) (B) (C) (D) (E) (F)
Current Test Year Proposed Proposed
Line Annual Base Base Effective Effective
No. Description Lamps Rate Revenue Rate Revenue
(1) Lamps
(2) Area Lighting
(3) 40 Watt Max 88,276 $ 9.82 $ 866,869 $ 11.17 $ 986,041
(4) 85 Watt Max 9,549 11.95 114,116 11.89 113,543
(5) 200 Watt Max 1,792 17.27 30,945 14.73 26,394
(6) Subtotal-Lamps $ 1,011,930
(7) Flood Lighting
(8) 85 Watt Max 15,893 $ 19.50 $ 309,912 $ 16.49 $ 262,074
(9) 150 Watt Max 933 21.47 20,035 17.43 16,265
(10) 300 Watt Max 1,145 25.28 28,946 23.01 26,347
(11) Subtotal-Lamps $ 358,893
(12) Transfer Adjustment Revenue 5,865
(13) Total Adjusted Base Revenue $ 1,376,688 1,430,664
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 20 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Non-Metered General Service
Schedule 40
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 22,284 $ - $ - $ - $ -
(2) Minimum Bills 1,385 2.00 2,770 2.00 2,770
(3) Total Energy 14,484,473 0.100058 1,449,287 0.111557 1,615,844
(4) Intermittent Usage 156 2.00 312 2.50 390
(5) Transfer Adjustment Revenue 43,854
(6) Total Adjusted Base Revenue $ 1,496,223 $ 1,619,004
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 21 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Street Lighting Service
Schedule 41 -Summary
Column (A) (B) (C) (D)
Test Year Proposed
Line Test Year Base Effective
No. Description Usage Revenue Revenue
(1) A-Company-Owned, Non-Metered, Maintem 2,275,478 $ 2,603,947 $ 3,340,555
(2) C-Customer-Owned, Non-Metered, No Mair 11,659,258 791,780 5049741
(3) CM-Customer-Owned, Metered, No Mainten 6,484,878 546,033 3159511
(4) Total kWh 20,419,614
(5) Transfer Adjustment Revenue $ 61,823
(6) Total Adjusted Base Revenue $ 4,003,584 $ 4,160,807
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 22 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Street Lighting Service
A-Company-Owned, Non-Metered, Maintenance
Column (A) (B) (C) (D) (E) (F)
Current Test Year Proposed Proposed
Line Annual Base Base Effective Effective
No. Description Lamps Rate Revenue Rate Revenue
(7) LED Fixture
(8) 40W Max 181,437 $ 12.30 $ 2,231,678 $ 15.98 $ 2,898,560
(9) 85W Max 20,240 14.31 289,640 17.29 349,981
(10) 140W Max 2,674 16.43 43,936 18.82 50,314
(11) 200W Max 1,680 20.44 34,342 21.93 36,848
(12) Total LED 206,032 $ 2,599,596 $ 3,335,703
(13) Non-Metered-Variable Energy Use 43,492 $ 0.100058 $ 4,352 $ 0.111557 $ 4,852
(14) A-Company-Owned, Non-Metered, Maintenance $ 2,603,947 $ 3,340,555
NM Ado
$ 0.023549
C-Customer-Owned, Non-Metered, No Maintenance
Current Test Year Proposed Proposed
Line Test Year Base Base Effective Effective
No. Description Usage Rate Revenue Rate Revenue
(15) Energy Charge
(16) Per kWh 11,659,258 $ 0.067910 $ 791,780 $ 0.043291 $ 504,741
(17) C-Customer-Owned, Non-Metered, No Maintenance $ 791,780 $ 504,741
CM-Customer-Owned, Metered, No Maintenance
Current Test Year Proposed Proposed
Line Test Year Base Base Effective Effective
No. Description Usage Rate Revenue Rate Revenue
(18) Service Charge per Meter 18,899 $ 5.59 $ 105,645 $ 1.84 $ 34,774
(19) Energy Charge
(20) Per kWh 6,484,878 $ 0.067910 $ 440,388 $ 0.043291 $ 280,737
(21) CM-Customer-Owned, Metered, No Maintenance $ 546,033 $ 315,511
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 23 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Traffic Control Signal Lighting Service
Schedule 42
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Service Charge 10,308 $ - $ - $ - $ -
(2) Total Energy 3,056,155 0.078462 239,792 0.095358 291,429
(3) Transfer Adjustment Revenue 9,253
(4) Total Adjusted Base Revenue $ 249,045 $ 291,429
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 24 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Micron Technology, Inc.
Schedule 26
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Contract Demand 1,062,000 $ 3.37 $ 3,578,940 $ 3.12 $ 3,313,440
(2) Billing Demand 1,027,098 17.83 18,313,161 23.35 23,982,743
(3) Excess Demand - 1.288 - 1.248 -
(4) Embedded Energy Fixed Cost - - - - -
(5) Total Energy 635,708,728 $ 0.030394 19,321,731 $ 0.027585 17,536,025
(6) Transfer Adjustment Revenue 1,924,697
(7) Total Adjusted Base Revenue $ 43,138,529 $ 44,832,208
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 25 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
J.R.Simplot Company- Pocatello
Schedule 29
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Contract Demand 300,000 $ 3.25 $ 975,000 $ 3.12 $ 936,000
(2) Billing Demand 330,992 14.80 4,898,679 18.55 6,139,898
(3) Excess Demand - 1.267 - 1.248 -
(4) Total Energy 211,750,000 0.031006 6,565,521 0.030782 6,518,089
(5) Transfer Adjustment Revenue 641,103
(6) Total Adjusted Base Revenue $ 13,080,302 $ 13,593,987
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 26 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
United States Department of Energy
Schedule 30
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Contract Demand
(2) Billing Demand 434,422 $ 10.17 $ 4,418,073 $ 19.80 $ 8,601,557
(3) Excess Demand
(4) Total Energy 241,000,000 $ 0.042488 $ 10,239,608 $ 0.030664 $ 7,390,024
(5) Transfer Adjustment Revenue 729,661
(6) Total Adjusted Base Revenue $ 15,387,342 $ 15,991,581
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 27 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
J.R.Simplot Company-Caldwell
Schedule 32
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Contract Demand
(2) Summer 100,000 $ 3.30 $ 330,000 $ 3.12 $ 312,000
(3) Non-Summer 200,000 3.30 660,000 3.12 624,000
(4) Billing Demand
(5) Summer 87,426 $ 19.60 $ 1,713,554 $ 23.99 $ 2,097,355
(6) Non-Summer 163,126 16.20 2,642,635 20.39 3,326,132
(7) Excess Demand
(8) Summer - $ 1.293 $ - $ 1.248 $ -
(9) Non-Summer - 1.293 - 1.248 -
(10) Energv
(11) Summer 54,274,353 $ 0.030405 $ 1,650,212 $ 0.031464 $ 1,707,688
(12) Non-Summer 100,725,647 0.032844 3,308,233 0.031073 3,129,848
(13) Transfer Adjustment Revenue 469,284
(14) Total Adjusted Base Revenue $ 10,773,918 $ 11,197,023
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 28 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Brisbie, LLC.
Schedule 33
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Block 1
(2) Service Charge 12 $ 415.00 $ 4,980 $ 490.00 $ 5,880
(3) Basic Charge
(4) Total Basic Charge 240,000 $ 1.87 $ 448,800 $ 1.72 $ 412,800
(5) Demand Charges
(6) Summer(Jun-Sep) 80,000 $ 10.20 $ 816,000 $ 14.18 $ 1,134,400
(7) Non-Summer(Oct-May) 160,000 8.78 1,404,800 12.42 1,987,200
(8) Total Demand 240,000 $ 2,220,800 $ 3,121,600
(9) On-Peak Summer Demand (Jun-Sep) - $ 1.59 $ - $ 2.07 $ -
(10) Summer Energy(Jun-Sep)
(11) On-Peak - $ 0.052142 $ - $ 0.067062 $ -
(12) Mid-Peak - 0.052142 - 0.055665 -
(13) Off-Peak - 0.046451 - 0.043865 -
(14) Subtotal-Summer Energy - $ - $ -
(15) Non-Summer Energy(Oct-May)
(16) On-Peak - $ 0.046927 $ - $ 0.053955 $ -
(17) Mid-Peak - 0.044504 - 0.049099 -
(18) Off-Peak - 0.042561 - 0.045641 -
(19) Subtotal- Non-Summer Energy - $ - $ -
(20) Subtotal-Total Energy - - -
(21) Subtotal- Block 1 $ 2,674,580 $ 3,540,280
(22) Block 2
(23) Contract Demand 120,000 $ 3.28 $ 393,600 $ 3.12 $ 374,400
(24) Billing Demand - 22.29 - 22.29 -
(25) Excess Demand - 1.293 - 1.248 -
(26) Subtotal- Block 2 $ 393,600 $ 374,400
(27) Transfer Adjustment Revenue - -
(28) Total Adjusted Base Revenue $ 3,068,180 $ 3,914,680
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 29 of 30

Idaho Power Company
State of Idaho
Calculation of Proposed Rates
Filed May 30,2025
IPC-E-25-16
Lamb Weston, Inc.
Schedule 34
Column (A) (B) (C) (D) (E) (F)
Test Year Current Test Year Proposed Proposed
Line Billing Base Base Effective Effective
No. Description Units Rate Revenue Rate Revenue
(1) Block 1
(2) Service Charge 12 $ 415.00 $ 4,980 $ 490.00 $ 5,880
(3) Basic Charge
(4) Total Basic Charge 240,000 $ 2.21 $ 530,400 $ 2.60 $ 624,000
(5) Demand Charges
(6) Summer(Jun-Sep) 80,000 $ 10.04 $ 803,200 $ 13.09 $ 1,047,200
(7) Non-Summer(Oct-May) 160,000 8.64 1,382,400 11.93 1,908,800
(8) Total Demand $ 2,185,600 $ 2,956,000
(9) On-Peak Summer Demand (Jun-Sep) 78,960 $ 1.59 $ 125,546 $ 2.07 $ 163,447
(10) Summer Energy(Jun-Sep)
(11) On-Peak 6,161,916 $ 0.052314 $ 322,354 $ 0.066358 $ 408,892
(12) Mid-Peak 7,907,125 0.052314 413,653 0.055115 435,801
(13) Off-Peak 29,384,248 0.046655 1,3707922 0.043474 1,277,451
(14) Subtotal-Summer Energy 43,453,289 $ 2,106,930 $ 2,122,144
(15) Non-Summer Energy(Oct-May)
(16) On-Peak 6,269 $ 0.047227 $ 296 $ 0.053897 $ 338
(17) Mid-Peak 88,577,191 0.044805 3,968,701 0.049044 4,344,180
(18) Off-Peak 17,021 0.042863 730 0.045589 776
(19) Subtotal- Non-Summer Energy 88,600,480 $ 3,969,727 $ 4,345,294
(20) Subtotal-Total Energy 132,053,769 6,076,657 6,467,438
(21) Subtotal- Block 1 $ 8,923,183 $ 10,216,765
(22) Block 2
(23) Contract Demand 48,000 $ 3.30 $ 158,400 $ 3.12 $ 149,760
(24) Billing Demand 31,778 24.19 768,704 9 286,000
(25) Excess Demand 1.293 - 1.248 -
(26) Subtotal- Block 2 $ 927,104 $ 435,760
(27) Transfer Adjustment Revenue 399,811 -
(28) Total Adjusted Base Revenue $ 10,250,099 $ 10,652,525
Exhibit No.44
Case No. IPC-E-25-16
G.Anderson, IPC
Page 30 of 30

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-16
IDAHO POWER COMPANY
ANDERSON , DI
TESTIMONY
EXHIBIT NO. 45

Idaho Power Company
State of Idaho
Monthly Adjusted Base Revenue Comparison
Filed May 30,2025
IPC-E-25-16
Residential Service-Standard Plan
Schedule 1
Column (A) (B) (C) (D) (E) (F) (G) (H) (1) 0) (K)
Monthly Billing Change Weighted
Line Current Proposed $ % Average Change
No. kWh Summer Non-Summer Summer Non-Summer Summer Non-Summer Summer Non-Summer $ %
1 100 $ 25.48 $ 24.26 $ 37.57 $ 34.96 $ 12.09 $ 10.70 47.4% 44.1% $ 11.16 45.2%
2 200 35.96 33.52 50.14 44.92 14.18 11.40 39.4% 34.0% 12.32 35.9%
3 300 46.44 42.78 62.71 54.87 16.26 12.10 35.0% 28.3% 13.48 30.6%
4 400 56.92 52.04 75.27 64.83 18.35 12.79 32.2% 24.6% 14.65 27.3%
5 500 67.40 61.30 87.84 74.79 20.44 13.49 30.3% 22.0% 15.81 25.0%
6 600 77.88 70.56 100.41 84.75 22.53 14.19 28.9% 20.1% 16.97 23.2%
7 700 88.36 79.82 112.98 94.71 24.61 14.89 27.9% 18.7% 18.13 21.9%
8 800 98.85 89.08 125.55 104.66 26.70 15.59 27.0% 17.5% 19.29 20.9%
9 900 111.39 99.26 139.34 115.12 27.95 15.87 25.1% 16.0% 19.90 19.3%
10 1,000 123.93 109.43 153.13 125.58 29.21 16.15 23.6% 14.8% 20.50 17.9%
11 1,200 149.01 129.79 180.72 146.49 31.71 16.70 21.3% 12.9% 21.70 15.9%
12 1,400 174.09 150.14 208.30 167.41 34.21 17.26 19.7% 11.5% 22.91 14.5%
13 1,600 199.17 170.50 235.88 188.32 36.71 17.82 18.4% 10.5% 24.12 13.4%
14 1,800 224.25 190.85 263.47 209.23 39.22 18.38 17.5% 9.6% 25.32 12.5%
15 2,000 249.33 211.21 291.05 230.15 41.72 18.93 16.7% 9.0% 26.53 11.8%
16 2,500 323.54 267.40 366.84 285.31 43.30 17.91 13.4% 6.7% 26.37 9.2%
17 3,000 397.75 323.60 442.63 340.48 44.88 16.88 11.3% 5.2% 26.21 7.5%
18 5,000 694.57 548.38 745.79 561.14 51.22 12.76 7.4% 2.3% 25.58 4.3%
Exhibit No. 45
Case No. IPC-E-25-16
G. Anderson, IPC
Page 1 of 7

Idaho Power Company
State of Idaho
Monthly Adjusted Base Revenue Comparison
Filed May 30,2025
IPC-E-25-16
Residential Service-Time-of-Use Plan
Schedule 5
Column (A) (B) (C) (D) (E) (F) (G) (H) (1) 0) (K)
Monthly Billing Change Weighted
Line Current Proposed $ % Average Change
No. kWh Summer Non-Summer Summer Non-Summer Summer Non-Summer Summer Non-Summer $ %
1 100 $ 26.10 $ 25.13 $ 38.79 $ 35.74 $ 12.69 $ 10.61 48.6% 42.2% $ 11.31 44.4%
2 200 37.20 35.26 52.57 46.48 15.37 11.23 41.3% 31.9% 12.61 35.1%
3 300 48.30 45.38 66.36 57.23 18.06 11.84 37.4% 26.1% 13.92 30.0%
4 400 59.41 55.51 80.15 67.97 20.74 12.46 34.9% 22.4% 15.22 26.8%
5 500 70.51 65.64 93.94 78.71 23.43 13.07 33.2% 19.9% 16.53 24.6%
6 600 81.61 75.77 107.72 89.45 26.11 13.69 32.0% 18.1% 17.83 22.9%
7 700 92.71 85.89 121.51 100.20 28.80 14.30 31.1% 16.7% 19.14 21.7%
8 800 103.81 96.02 135.30 110.94 31.49 14.92 30.3% 15.5% 20.44 20.7%
9 900 114.91 106.15 149.08 121.68 34.17 15.53 29.7% 14.6% 21.75 19.9%
10 1,000 126.01 116.28 162.87 132.42 36.86 16.15 29.2% 13.9% 23.05 19.3%
11 1,250 153.77 141.60 197.34 159.28 43.57 17.68 28.3% 12.5% 26.31 18.1%
12 1,500 181.52 166.92 231.81 186.14 50.29 19.22 27.7% 11.5% 29.58 17.2%
13 1,750 209.27 192.24 266.27 212.99 57.00 20.76 27.2% 10.8% 32.84 16.6%
14 2,000 237.03 217.56 300.74 239.85 63.72 22.29 26.9% 10.2% 36.10 16.1%
15 2,250 264.78 242.87 335.21 266.70 70.43 23.83 26.6% 9.8% 39.36 15.7%
16 2,500 292.53 268.19 369.68 293.56 77.14 25.37 26.4% 9.5% 42.63 15.4%
17 3,000 348.04 318.83 438.61 347.27 90.57 28.44 26.0% 8.9% 49.15 15.0%
18 5,000 570.07 521.39 714.36 562.12 144.29 40.73 25.3% 7.8% 75.25 14.0%
Bills are calculated using the average time-of--use(TOU)energy proportions by season for existing Schedule 5 customers.Actual TOU energy proportions for customers may vary.
Exhibit No. 45
Case No. IPC-E-25-16
G. Anderson, IPC
Page 2 of 7

Idaho Power Company
State of Idaho
Monthly Adjusted Base Revenue Comparison
Filed May 30,2025
IPC-E-25-16
Small General Service
Schedule 7
Column (A) (B) (C) (D) (E) (F) (G) (H) (1) 0) (K)
Monthly Billing Change Weighted
Line Current Proposed $ % Average Change
No. kWh Summer Non-Summer Summer Non-Summer Summer Non-Summer Summer Non-Summer $ %
1 50 $ 28.88 $ 28.88 $ 34.44 $ 34.44 $ 5.56 $ 5.56 19.3% 19.3% $ 5.56 19.3%
2 150 36.63 36.63 43.32 43.32 6.69 6.69 18.3% 18.3% 6.69 18.3%
3 250 44.39 44.39 52.20 52.20 7.81 7.81 17.6% 17.6% 7.81 17.6%
4 350 52.68 52.15 61.71 61.08 9.04 8.93 17.2% 17.1% 8.97 17.1%
5 450 61.50 59.91 71.86 69.96 10.36 10.06 16.9% 16.8% 10.16 16.8%
6 550 70.32 67.66 82.01 78.85 11.69 11.18 16.6% 16.5% 11.35 16.6%
7 650 79.14 75.42 92.16 87.73 13.02 12.31 16.5% 16.3% 12.55 16.4%
8 750 87.96 83.18 102.31 96.61 14.35 13.43 16.3% 16.1% 13.74 16.2%
9 850 96.78 90.94 112.46 105.50 15.68 14.56 16.2% 16.0% 14.93 16.1%
10 950 105.60 98.70 122.61 114.38 17.00 15.68 16.1% 15.9% 16.12 16.0%
11 1,050 114.42 106.45 132.75 123.26 18.33 16.81 16.0% 15.8% 17.32 15.9%
12 1,150 123.24 114.21 142.90 132.14 19.66 17.93 16.0% 15.7% 18.51 15.8%
13 1,250 132.06 121.97 153.05 141.03 20.99 19.06 15.9% 15.6% 19.70 15.7%
14 1,350 140.88 129.73 163.20 149.91 22.32 20.18 15.8% 15.6% 20.89 15.7%
15 1,450 149.70 137.49 173.35 158.79 23.65 21.31 15.8% 15.5% 22.09 15.6%
16 1,550 158.52 145.24 183.50 167.67 24.97 22.43 15.8% 15.4% 23.28 15.6%
17 1,650 167.34 153.00 193.65 176.56 26.30 23.56 15.7% 15.4% 24.47 15.5%
18 1,750 176.16 160.76 203.79 185.44 27.63 24.68 15.7% 15.4% 25.66 15.5%
19 1,850 184.98 168.52 213.94 194.32 28.96 25.81 15.7% 15.3% 26.86 15.4%
20 1,950 193.80 176.27 224.09 203.21 30.29 26.93 15.6% 15.3% 28.05 15.4%
Exhibit No. 45
Case No. IPC-E-25-16
G. Anderson, IPC
Page 3 of 7

Idaho Power Company
State of Idaho
Monthly Adjusted Base Revenue Comparison
Filed May 30,2025
IPC-E-25-16
Large General-Secondary Service
Schedule 9
Column (A) (B) (C) (D) (E) (F) (G) (H) (1) 0) (K) (L) (M)
Monthly Billing Change Weighted
Line Load Size Load Current Proposed $ % Average Change
No. kW Factor kWh Summer Non-Summer Summer Non-Summer Summer Non-Summer Summer Non-Summer $ %
1 10 20% 1,000 $ 185.21 $ 165.98 $ 212.89 $ 192.80 $ 27.68 $ 26.83 14.9% 16.2% $ 27.11 15.7%
2 35% 3,000 300.58 277.47 321.06 300.41 20.48 22.94 6.8% 8.3% 22.12 7.8%
3 50% 4,000 358.27 333.22 375.15 354.22 16.88 21.00 4.7% 6.3% 19.62 5.7%
4 65% 5,000 415.95 388.97 429.24 408.02 13.29 19.05 3.2% 4.9% 17.13 4.3%
5 80% 6,000 473.64 444.72 483.33 461.82 9.69 17.11 2.0% 3.8% 14.63 3.2%
6 20 20% 3,000 $ 403.11 $ 362.70 $ 449.87 $ 409.41 $ 46.76 $ 46.71 11.6% 12.9% $ 46.73 12.4%
7 35% 5,000 518.48 474.20 558.04 517.02 39.56 42.82 7.6% 9.0% 41.74 8.5%
8 50% 7,000 633.85 585.69 666.22 624.63 32.36 38.94 5.1% 6.6% 36.75 6.1%
9 65% 10,000 806.91 752.94 828.48 786.04 21.57 33.10 2.7% 4.4% 29.26 3.8%
10 80% 12,000 922.28 864.44 936.66 893.65 14.38 29.21 1.6% 3.4% 24.27 2.7%
11 50 20% 7,000 $ 941.43 $ 841.37 $ 1,052.62 $ 951.63 $ 111.19 $ 110.26 11.8% 13.1% $ 110.57 12.6%
12 35% 13,000 1,287.55 1,175.87 1,377.15 1,274.46 89.60 98.59 7.0% 8.4% 95.59 7.9%
13 50% 18,000 1,575.98 1,454.61 1,647.59 1,543.48 71.61 88.87 4.5% 6.1% 83.12 5.6%
14 65% 24,000 1,922.09 1,789.10 1,972.12 1,866.30 50.03 77.20 2.6% 4.3% 68.14 3.7%
15 80% 29,000 2,210.52 2,067.84 2,242.56 2,135.32 32.04 67.48 1.4% 3.3% 55.66 2.6%
16 100 20% 15,000 $ 1,915.55 $ 1,713.50 $ 2,129.33 $ 1,927.07 $ 213.78 $ 213.57 11.2% 12.5% $ 213.64 12.0%
17 35% 26,000 2,550.09 2,326.73 2,724.30 2,518.91 174.20 192.18 6.8% 8.3% 186.19 7.8%
18 50% 37,000 3,184.64 2,939.97 3,319.26 3,110.76 134.63 170.79 4.2% 5.8% 158.74 5.3%
19 65% 48,000 3,819.18 3,553.20 3,914.23 3,702.60 95.05 149.40 2.5% 4.2% 131.28 3.6%
20 80% 59,000 4,453.72 4,166.44 4,509.20 4,294.44 55.48 128.01 1.2% 3.1% 103.83 2.4%
21 300 20% 44,000 $ 5,638.97 $ 5,034.74 $ 6,273.90 $ 5,667.40 $ 634.93 $ 632.66 11.3% 12.6% $ 633.41 12.1%
22 35% 77,000 7,542.60 6,874.45 8,058.80 7,442.93 516.20 568.48 6.8% 8.3% 551.06 7.8%
23 50% 110,000 9,446.22 8,714.15 9,843.70 9,218.46 397.48 504.31 4.2% 5.8% 468.70 5.2%
24 65% 143,000 11,349.85 10,553.86 11,628.61 10,994.00 278.76 440.14 2.5% 4.2% 386.35 3.6%
25 80% 176,000 13,253.48 12,393.56 13,413.51 12,769.53 160.04 375.97 1.2% 3.0% 303.99 2.4%
26 500 20% 73,000 $ 9,362.39 $ 8,355.99 $ 10,418.47 $ 9,407.73 $ 1,056.08 $ 1,051.74 11.3% 12.6% $ 1,053.19 12.1%
27 35% 128,000 12,535.10 11,422.16 13,393.31 12,366.95 858.21 944.79 6.8% 8.3% 915.93 7.8%
28 50% 183,000 15,707.81 14,488.34 16,368.15 15,326.17 660.34 837.83 4.2% 5.8% 778.67 5.2%
29 65% 238,000 18,880.52 17,554.51 19,342.99 18,285.39 462.47 730.88 2.4% 4.2% 641.41 3.6%
30 80% 293,000 22,053.23 20,620.69 22,317.83 21,244.61 264.60 623.92 1.2% 3.0% 504.15 2.4%
Bills are based on class average energy consumption by time period and season.
Exhibit No. 45
Case No. IPC-E-25-16
G. Anderson, IPC
Page 4 of 7

Idaho Power Company
State of Idaho
Monthly Adjusted Base Revenue Comparison
Filed May 30,2025
IPC-E-25-16
Large General-Primary Service
Schedule 9
Column (A) (B) (C) (D) (E) (F) (G) (H) (1) 0) (K) (L) (M)
Monthly Billing Change Weighted
Line Load Size Load Current Proposed $ % Average Change
No. kW Factor kWh Summer Non-Summer Summer Non-Summer Summer Non-Summer Summer Non-Summer $ %
1 300 40% 88,000 $ 8,678.33 $ 7,715.78 $ 9,455.03 $ 8,425.03 $ 776.70 $ 709.25 8.9% 9.2% $ 731.73 9.1%
2 50% 110,000 9,848.83 8,796.05 10,538.98 9,491.29 690.15 695.24 7.0% 7.9% 693.54 7.6%
3 60% 132,000 11,019.33 9,876.32 11,622.92 10,557.56 603.59 681.24 5.5% 6.9% 655.36 6.4%
4 70% 154,000 12,189.83 10,956.59 12,706.87 11,623.82 517.04 667.23 4.2% 6.1% 617.17 5.4%
5 80% 176,000 13,360.33 12,036.86 13,790.82 12,690.09 430.48 653.22 3.2% 5.4% 578.98 4.6%
6 400 40% 117,000 $ 11,440.04 $ 10,158.00 $ 12,470.28 $ 11,097.21 $ 1,030.25 $ 939.21 9.0% 9.2% $ 969.56 9.2%
7 50% 146,000 12,982.97 11,581.99 13,899.12 12,502.74 916.15 920.75 7.1% 7.9% 919.22 7.6%
8 60% 176,000 14,579.11 13,055.09 15,377.23 13,956.74 798.12 901.65 5.5% 6.9% 867.14 6.4%
9 70% 205,000 16,122.04 14,479.09 16,806.07 15,362.27 684.03 883.19 4.2% 6.1% 816.80 5.4%
10 80% 234,000 17,664.97 15,903.08 18,234.91 16,767.80 569.94 864.72 3.2% 5.4% 766.46 4.6%
11 500 40% 146,000 $ 14,201.75 $ 12,600.22 $ 15,485.54 $ 13,769.40 $ 1,283.79 $ 1,169.18 9.0% 9.3% $ 1,207.38 9.2%
12 50% 183,000 16,170.32 14,417.05 17,308.54 15,562.66 1,138.22 1,145.62 7.0% 7.9% 1,143.15 7.6%
13 60% 220,000 18,138.89 16,233.87 19,131.54 17,355.93 992.65 1,122.06 5.5% 6.9% 1,078.93 6.4%
14 70% 256,000 20,054.25 18,001.58 20,905.27 19,100.72 851.02 1,099.14 4.2% 6.1% 1,016.43 5.4%
15 80% 293,000 22,022.82 19,818.40 22,728.27 20,893.99 705.45 1,075.58 3.2% 5.4% 952.21 4.6%
16 600 40% 176,000 $ 17,016.66 $ 15,091.55 $ 18,550.06 $ 16,490.05 $ 1,533.40 $ 1,398.50 9.0% 9.3% $ 1,443.47 9.2%
17 50% 220,000 19,357.66 17,252.10 20,717.95 18,622.58 1,360.29 1,370.49 7.0% 7.9% 1,367.09 7.6%
18 60% 264,000 21,698.66 19,412.64 22,885.85 20,755.11 1,187.18 1,342.47 5.5% 6.9% 1,290.71 6.4%
19 70% 307,000 23,986.46 21,524.08 25,004.47 22,839.18 1,018.01 1,315.10 4.2% 6.1% 1,216.07 5.4%
20 80% 351,000 26,327.46 23,684.62 27,172.36 24,971.71 844.90 1,287.08 3.2% 5.4% 1,139.69 4.6%
21 700 40% 205,000 $ 19,778.37 $ 17,533.78 $ 21,565.31 $ 19,162.24 $ 1,786.95 $ 1,628.46 9.0% 9.3% $ 1,681.29 9.2%
22 50% 256,000 22,491.80 20,038.04 24,078.10 21,634.04 1,586.30 1,595.99 7.1% 8.0% 1,592.76 7.6%
23 60% 307,000 25,205.24 22,542.31 26,590.89 24,105.83 1,385.65 1,563.52 5.5% 6.9% 1,504.23 6.4%
24 70% 359,000 27,971.87 25,095.68 29,152.94 26,626.09 1,181.07 1,530.42 4.2% 6.1% 1,413.97 5.4%
25 80% 410,000 30,685.31 27,599.94 31,665.73 29,097.89 980.42 1,497.94 3.2% 5.4% 1,325.44 4.6%
26 800 40% 234,000 $ 22,540.08 $ 19,976.00 $ 24,580.57 $ 21,834.43 $ 2,040.49 $ 1,858.43 9.1% 9.3% $ 1,919.11 9.2%
27 50% 293,000 25,679.15 22,873.09 27,487.52 24,693.95 1,808.37 1,820.86 7.0% 8.0% 1,816.70 7.6%
28 60% 351,000 28,765.01 25,721.08 30,345.19 27,505.02 1,580.18 1,783.93 5.5% 6.9% 1,716.02 6.4%
29 70% 410,000 31,904.08 28,618.17 33,252.14 30,364.55 1,348.06 1,746.37 4.2% 6.1% 1,613.60 5.4%
30 80% 468,000 34,989.95 31,466.16 36,109.82 33,175.61 1,119.87 1,709.44 3.2% 5.4% 1,512.92 4.6%
Bills are based on class average energy consumption by time period and season.
Exhibit No. 45
Case No. IPC-E-25-16
G. Anderson, IPC
Page 5 of 7

Idaho Power Company
State of Idaho
Monthly Adjusted Base Revenue Comparison
Filed May 30,2025
IPC-E-25-16
Large Power Service-Primary
Schedule 19
Column (A) (B) (C) (D) (E) (F) (G) (H) (1) 0) (K) (L) (M)
Monthly Billing Change Weighted
Line Load Size Load Current Proposed $ % Average Change
No. kW Factor kWh Summer Non-Summer Summer Non-Summer Summer Non-Summer Summer Non-Summer $ %
1 1,000 40% 295,000 $ 29,553.27 $ 25,491.22 $ 32,758.60 $ 29,558.69 $ 3,205.33 $ 4,067.47 10.8% 16.0% $ 3,780.09 14.1%
2 50% 365,000 33,160.31 28,800.09 36,179.69 32,929.91 3,019.38 4,129.82 9.1% 14.3% 3,759.67 12.4%
3 60% 440,000 37,025.00 32,345.31 39,845.14 36,541.93 2,820.14 4,196.63 7.6% 13.0% 3,737.80 11.0%
4 70% 510,000 40,632.05 35,654.18 43,266.23 39,913.15 2,634.18 4,258.98 6.5% 11.9% 3,717.38 10.0%
5 80% 585,000 44,496.73 39,199.39 46,931.68 43,525.18 2,434.94 4,325.78 5.5% 11.0% 3,695.50 9.0%
6 2,500 40% 730,000 $ 72,874.21 $ 62,751.03 $ 80,794.96 $ 72,800.53 $ 7,920.75 $ 10,049.50 10.9% 16.0% $ 9,339.92 14.1%
7 50% 915,000 82,407.11 71,495.90 89,836.41 81,710.18 7,429.30 10,214.29 9.0% 14.3% 9,285.96 12.4%
8 60% 1,100,000 91,940.01 80,240.76 98,877.85 90,619.84 6,937.84 10,379.07 7.5% 12.9% 9,232.00 11.0%
9 70% 1,280,000 101,215.26 88,749.29 107,674.93 99,288.69 6,459.67 10,539.40 6.4% 11.9% 9,179.49 9.9%
10 80% 1,465,000 110,748.16 97,494.16 116,716.37 108,198.34 5,968.22 10,704.18 5.4% 11.0% 9,125.53 9.0%
11 3,500 40% 1,025,000 $ 102,012.48 $ 87,827.24 $ 113,063.57 $ 101,869.22 $ 11,051.08 $ 14,041.98 10.8% 16.0% $ 13,045.01 14.1%
12 50% 1,280,000 115,152.42 99,880.98 125,526.10 114,150.10 10,373.67 14,269.11 9.0% 14.3% 12,970.63 12.4%
13 60% 1,535,000 128,292.36 111,934.72 137,988.63 126,430.97 9,696.26 14,496.25 7.6% 13.0% 12,896.25 11.0%
14 70% 1,795,000 141,689.95 124,224.81 150,695.52 138,952.64 9,005.57 14,727.83 6.4% 11.9% 12,820.41 9.9%
15 80% 2,050,000 154,829.89 136,278.55 163,158.05 151,233.52 8,328.16 14,954.97 5.4% 11.0% 12,746.03 8.9%
16 5,000 40% 1,465,000 $ 145,591.07 $ 125,323.40 $ 161,344.29 $ 145,351.86 $ 15,753.22 $ 20,028.46 10.8% 16.0% $ 18,603.38 14.1%
17 50% 1,830,000 164,399.22 142,576.79 179,182.81 162,930.37 14,783.60 20,353.58 9.0% 14.3% 18,496.92 12.3%
18 60% 2,195,000 183,207.37 159,830.18 197,021.34 180,508.87 13,813.97 20,678.69 7.5% 12.9% 18,390.45 11.0%
19 70% 2,560,000 202,015.52 177,083.57 214,859.86 198,087.38 12,844.34 21,003.80 6.4% 11.9% 18,283.98 9.9%
20 80% 2,930,000 221,081.32 194,573.31 232,942.75 215,906.68 11,861.43 21,333.37 5.4% 11.0% 18,176.06 8.9%
21 7,000 40% 2,050,000 $ 203,609.96 $ 175,239.49 $ 225,637.13 $ 203,248.45 $ 22,027.17 $ 28,008.96 10.8% 16.0% $ 26,015.03 14.1%
22 50% 2,560,000 229,889.84 199,346.97 250,562.19 227,810.19 20,672.35 28,463.22 9.0% 14.3% 25,866.27 12.3%
23 60% 3,075,000 256,427.37 223,690.79 275,731.62 252,612.74 19,304.24 28,921.95 7.5% 12.9% 25,716.04 11.0%
24 70% 3,585,000 282,707.26 247,798.27 300,656.68 277,174.49 17,949.42 29,376.21 6.3% 11.9% 25,567.28 9.9%
25 80% 4,100,000 309,244.79 272,142.10 325,826.10 301,977.03 16,581.32 29,834.93 5.4% 11.0% 25,417.06 8.9%
26 8,500 40% 2,490,000 $ 247,188.55 $ 212,735.64 $ 273,917.85 $ 246,731.08 $ 26,729.31 $ 33,995.44 10.8% 16.0% $ 31,573.40 14.1%
27 50% 3,110,000 279,136.64 242,042.77 304,218.91 276,590.46 25,082.27 34,547.69 9.0% 14.3% 31,392.55 12.3%
28 60% 3,735,000 311,342.38 271,586.25 334,764.33 306,690.64 23,421.95 35,104.39 7.5% 12.9% 31,210.24 11.0%
29 70% 4,355,000 343,290.47 300,893.38 365,065.38 336,550.02 21,774.91 35,656.64 6.3% 11.9% 31,029.39 9.8%
30 80% 4,980,000 375,496.21 330,436.86 395,610.80 366,650.20 20,114.59 36,213.34 5.4% 11.0% 30,847.09 8.9%
Bills are based on class average energy consumption by time period and season.
Exhibit No. 45
Case No. IPC-E-25-16
G. Anderson, IPC
Page 6of7

Idaho Power Company
State of Idaho
Monthly Adjusted Base Revenue Comparison
Filed May 30,2025
IPC-E-25-16
Agricultural Irrigation Service-Secondary
Schedule 24
Column (A) (B) (C) (D) (E) (F) (G) (H) (1) 0) (K) (L) (M)
Monthly Billing Change Weighted
Line Load Size Load Current Proposed $ % Average Change
No. kW Factor kWh In-Season Out-Season In-Season Out-Season In-Season Out-Season In-Season Out-Season $ %
1 10 20% 1,440 $ 273.22 $ 114.12 $ 329.46 $ 127.88 $ 56.24 $ 13.77 20.6% 12.1% $ 24.33 18.6%
2 35% 2,520 342.69 195.20 409.68 217.05 66.99 21.84 19.5% 11.2% 30.61 16.9%
3 50% 3,600 412.16 276.29 489.90 306.21 77.74 29.92 18.9% 10.8% 36.89 15.9%
4 65% 4,680 481.63 357.38 570.13 395.37 88.50 37.99 18.4% 10.6% 43.16 15.3%
5 80% 5,760 551.10 438.46 650.35 484.53 99.25 46.07 18.0% 10.5% 49.44 14.9%
6 50 20% 7,200 $ 1,246.12 $ 546.58 $ 1,507.31 $ 603.42 $ 261.19 $ 56.84 21.0% 10.4% $ 107.01 17.8%
7 35% 12,600 1,593.47 952.02 1,908.42 1,049.23 314.95 97.21 19.8% 10.2% 138.39 16.3%
8 50% 18,000 1,940.81 1,357.45 2,309.52 1,495.04 368.71 137.59 19.0% 10.1% 169.77 15.4%
9 65% 23,400 2,288.15 1,762.89 2,710.63 1,940.86 422.48 177.97 18.5% 10.1% 201.15 14.9%
10 80% 28,800 2,635.49 2,168.32 3,111.74 2,386.67 476.24 218.35 18.1% 10.1% 232.53 14.5%
11 100 20% 14,400 $ 2,462.25 $ 1,087.16 $ 2,979.62 $ 1,197.84 $ 517.37 $ 110.67 21.0% 10.2% $ 210.35 17.7%
12 35% 25,200 3,156.93 1,898.03 3,781.83 2,089.46 624.90 191.43 19.8% 10.1% 273.11 16.2%
13 50% 36,000 3,851.62 2,708.90 4,584.04 2,981.09 732.43 272.18 19.0% 10.0% 335.87 15.3%
14 65% 46,800 4,546.30 3,519.77 5,386.26 3,872.71 839.96 352.94 18.5% 10.0% 398.63 14.8%
15 80% 57,600 5,240.98 4,330.64 6,188.47 4,764.34 947.49 433.70 18.1% 10.0% 461.39 14.5%
16 300 20% 43,200 $ 7,326.74 $ 3,249.48 $ 8,868.85 $ 3,575.51 $ 1,542.11 $ 326.02 21.0% 10.0% $ 623.71 17.7%
17 35% 75,600 9,410.79 5,682.10 11,275.49 6,250.38 1,864.70 568.29 19.8% 10.0% 812.00 16.1%
18 50% 108,000 11,494.85 8,114.71 13,682.13 8,925.26 2,187.29 810.55 19.0% 10.0% 1,000.28 15.3%
19 65% 140,400 13,578.90 10,547.32 16,088.77 11,600.14 2,509.87 1,052.82 18.5% 10.0% 1,188.56 14.8%
20 80% 172,800 15,662.95 12,979.93 18,495.41 14,275.02 2,832.46 1,295.09 18.1% 10.0% 1,376.85 14.4%
21 500 20% 72,000 $ 12,191.23 $ 5,411.81 $ 14,758.09 $ 5,953.18 $ 2,566.86 $ 541.37 21.1% 10.0% $ 1,037.08 17.7%
22 35% 126,000 15,664.65 9,466.16 18,769.15 10,411.31 3,104.50 945.15 19.8% 10.0% 1,350.88 16.1%
23 50% 180,000 19,138.08 13,520.52 22,780.22 14,869.44 3,642.14 1,348.92 19.0% 10.0% 1,664.69 15.3%
24 65% 234,000 22,611.50 17,574.87 26,791.29 19,327.57 4,179.79 1,752.70 18.5% 10.0% 1,978.50 14.8%
25 80% 288,000 26,084.92 21,629.22 30,802.35 23,785.70 4,717.43 2,156.48 18.1% 10.0% 2,292.30 14.4%
26 750 20% 108,000 $ 18,271.85 $ 8,114.71 $ 22,119.63 $ 8,925.26 $ 3,847.79 $ 810.55 21.1% 10.0% $ 1,553.78 17.7%
27 35% 189,000 23,481.98 14,196.24 28,136.23 15,612.46 4,654.25 1,416.22 19.8% 10.0% 2,024.49 16.1%
28 50% 270,000 28,692.11 20,277.77 34,152.83 22,299.66 5,460.72 2,021.89 19.0% 10.0% 2,495.20 15.3%
29 65% 351,000 33,902.25 26,359.30 40,169.43 28,986.86 6,267.18 2,627.55 18.5% 10.0% 2,965.91 14.8%
30 80% 432,000 39,112.38 32,440.84 46,186.03 35,674.06 7,073.65 3,233.22 18.1% 10.0% 3,436.62 14.4%
Weighted Average Bills are based on four months of in-season,fours month of out-season, and four months of zero usage.
Exhibit No. 45
Case No. IPC-E-25-16
G. Anderson, IPC
Page 7 of 7