20250401APPLICATION.pdf

qN -HIQAW POWER.
RECEIVED
MEGAN GOICOECHEA ALLEN April 1, 2025
Corporate Counsel IDAHO PUBLIC
mgoicoecheaallen(a-)idahopower.com UTILITIES COMMISSION
April 1, 2025
Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Boulevard
Building 8, Suite 201-A
Boise, Idaho 83714
Re: Case No. IPC-E-25-17
Idaho Power Company's Application for its Annual Update to Marginal Pricing
Used in Certain Schedules
Dear Commission Secretary:
Attached for electronic filing, please find Idaho Power Company's Application in
the above-entitled matter.
If you have any questions about the attached documents, please do not hesitate
to contact me.
Sincerely,
n I fJIP,f�I,?A l
Megan Goicoechea Allen
MGA:cd
Attachments
1221 W. Idaho St(83702)
P.O.Box 70
Boise, ID 83707

MEGAN GOICOECHEA ALLEN (ISB No. 7623)
DONOVAN WALKER (ISB No. 5921)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
mgoicoecheaallenCa�,idahopower.com
dwalkerCa)_idahopower.com
Attorneys for Idaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY'S APPLICATION FOR ITS ) CASE NO. IPC-E-25-17
ANNUAL UPDATE TO MARGINAL )
PRICING USED IN CERTAIN ) APPLICATION
SCHEDULES )
Idaho Power Company ("Idaho Power" or "Company"), pursuant to Idaho Code §
§ 61-502 and 503 and Idaho Public Utilities Commission's ("Commission") Rule of
Procedure ("RP") 52, submits its Application to update the marginal cost-based energy
prices in Schedule 20, Speculative High-Density Load ("Schedule 20"), and Schedule 34,
Lamb Weston Special Contract ("Schedule 34"). The proposed tariff schedules are
provided in Attachment No. 1 to the Application.
In further support of this Application, Idaho Power represents as follows:
APPLICATION - 1

I. BACKGROUND
Case No. IPC-E-21-37- Schedule 20, Speculative High-Density Load
1. On November 4, 2021, Idaho Power filed Case No. IPC-E-21-37 seeking
authority to establish a new schedule to serve speculative high-density customers,
Schedule 20, Speculative High-Density Load.' In its application, the Company explained
that the rates included in Schedule 20 incorporate certain modifications to the existing
rate design for Schedule 9 and Schedule 19, including a proposal to price energy at a
marginal cost in all pricing periods, based on Avoided Cost Averages ("ACA") as
contained in Technical Report Appendix C of the Company's Integrated Resource Plan
("IRP").2 In its comments, Commission Staff ("Staff') noted that, while it agreed in
principle with using a marginal energy rate under the circumstances, it was concerned
with using an IRP-derived avoided cost in customer rates.3 Accordingly, Staff
recommended that the Company be authorized to rely on ACA from the Company's
Integrated Resource Plan as the initial basis for the cost of marginal energy in the
proposed Schedule 20, but that it be directed to evaluate that method against other
methods, "including a marginal energy cost rate derived from a test year in preparation of
the next general rate case.114
2. On June 15, 2022, the Commission issued Order No. 35428 approving
Schedule 20 as filed and ordering the Company, in pertinent part, "to evaluate and
compare other methods for determining a marginal cost of energy in addition to the use
In the Matter of the Application of Idaho Power Company for Authority to Establish a New Schedule to
Serve Speculative High-Density Load Customers, Case No. IPC-E-21-37, Application (Nov. 4, 2021).
2 Id. at 14-15.
3 Id., Staff Comments at 6 (Apr. 12, 2022).
4 Id.
APPLICATION - 2

of ACA in the IRP for setting the Schedule 20 energy rate" before its next general rate
case.5
3. As directed by the Commission, the Company collaborated with Staff
following its evaluation, meeting with Staff on January 20, 2023, and again on February
2, 2023, to discuss the results of Idaho Power's evaluation and to solicit Staff's feedback.
Following these two discussions, Staff provided a memo ("Staff Memo"), which is included
as Attachment No. 2 to this Application, that memorializes the discussions between the
Company and Staff regarding the basis for marginal pricing of energy and outlines five
general criteria that should be considered when developing marginal cost-based
customer energy rates:
(i) The resources used in a model for determining marginal cost
should be based on the resources that are highly likely to exist
during the rate period.
(ii) The amount of incremental load used to determine the
marginal cost rate should reflect the amount of incremental
load for the portion of load that will be priced at marginal cost.
(iii) The marginal cost rates should have enough granularity to
reflect time difference (e.g., seasonality, time of day) value of
Marginal Cost within the Company's system to provide
accurate price signals.
(iv) If the marginal cost rates are based on a forecast, due to the
lack of marginal costs being trued-up in the PCA, they should
be updated often enough that they reflect current conditions or
find a way to true up the marginal cost to actual marginal cost.
(v) If market costs are used, cost of transmission transaction and
wheeling costs should be included.
5 Id., Order No. 35428 at 7 (Jun. 15, 2022).
APPLICATION - 3

Case No. IPC-E-23-18 - Lamb Weston Special Contract
4. Around the same time it was engaged in discussions with Staff regarding
marginal cost-based pricing methods, the Company had been exchanging information
and negotiating the terms, conditions, and rates with an existing retail customer, Lamb
Weston, relative to a new Special Contract ("Lamb Weston Special Contract")
necessitated by the customer expanding its operations to include new manufacturing
lines, raw and cold storage, and ancillary facilities.
5. After the parties reached agreement on the terms and conditions of the
Lamb Weston Special Contract, Idaho Power filed Case No. IPC-E-23-18 on May 23,
2023, requesting Commission approval of the same.6 In its application the Company
explained that it was proposing a two-block pricing structure, which contemplated an
embedded-cost pricing block, Block 1, and a marginal energy cost pricing block, Block 2.
6. The Company's proposed "Block 2 Energy Charge" was based on the per
kilowatt-hour ("kWh") marginal cost of energy based on the simulated hourly operation of
the Company's power supply system over expected hydro conditions.' Under this
method, net power supply expenses are first quantified using the Company's expected
load for the test year, then an incremental load increase is added to determine the
resulting increase in power supply expenses and generation. The difference in monthly
power supply expenses between the initial and subsequent simulation is divided by the
incremental generation to produce a marginal cost per kWh.
7. The Company's proposed method for determining the marginal cost of
6 In the Matter of Idaho Power Company's Application for Approval of Special Contract and Tariff
Schedule 34 to Provide Electric Service to Lamb Weston, Inc., Case No. IPC-E-23-18, Application (May
23, 2023).
Id. at 7.
APPLICATION - 4

energy in the Lamb Weston Special Contract was consistent with those principles
identified by Staff as best practices that should be considered when evaluating marginal
pricing methodologies as set forth in the Staff Memo.
8. In the application, the Company further explained that to ensure the
marginal energy price applied to Lamb Weston's Block 2 energy usage keeps pace with
conditions experienced on the Company's system, the pricing should be updated
annually. More specifically, the Company proposed to submit an annual update to the
marginal energy price that would be filed around the time of the Company's annual Power
Cost Adjustment ("PCA") filing, with the updated marginal energy price proposed to be
effective June 1, consistent with PCA rates.$
9. On September 21, 2023, the Commission issued Order No. 35929
approving the Lamb Weston Special Contract and proposed pricing methodologies,
including the proposed marginal price method for the Block 2 Energy Charge and the
annual update to the marginal energy prices to be effective June 1st.
Case No. IPC-E-23-11 — 2023 General Rate Case
10. On June 1, 2023, Idaho Power filed its application in Case No. IPC-E-23-11
('2023 GRC"), requesting authority to increase its rates and charges for electric service.9
As part of its case, the Company proposed changes to Schedule 20 rates to reflect the
principles contained within the Staff Memo including the Company-proposed updating of
the marginal energy component basis of Schedule 20 and aligning to the time-of-use
8 Id. at 10.
9 In the Matter of the Application of Idaho Power Company for Authority to Increase its Rates and
Charges for Electric Service in the State of Idaho and for Associated Regulatory Treatment, Case No.
IPC-E-23-11, Application (June 1, 2023).
APPLICATION - 5

periods with those proposed for Schedules 9 and 19.10 More specifically, the Company
proposed replacing the current ACA-based marginal rates with an AURORA-based
method to be updated annually on June 1 using a forward test year consisting of the 12-
month period April through the subsequent March, consistent with spring power cost
filings.11
11. As part of the 2023 GRC, the Company also described its rate design
proposals for the Company's existing special contract customers, which sought to move
the rate design components toward class cost-of-service ("CCOS") informed amounts
when increasing forecast collections to recover the revenue requirement. This includes
reestablishing or updating the contract demand charge based on the same methodology
the Company recently employed for pending special contract customers, which at that
time included Lamb Weston. The Company explained that the marginal energy cost
portion of Lamb Weston's two-block pricing structure is based on an annual power supply
cost forecast consistent with the PCA test year, with proposed marginal cost rate updates
to occur at an annual interval in the spring with updated effective marginal energy rate
each June 1st
12. The parties agreed to resolve and settle all the issues in the 2023 GRC
following a series of settlement discussions, and as a result, on October 27, 2023, the
Company filed a Motion for Approval of a Stipulation and Settlement ("Settlement
Stipulation"). With respect to CCOS, the Settlement Stipulation provided that the parties
did not agree on any particular cost-of-service methodology and specified that it was not
10 Id., Goralski Direct Testimony at 50-51.
11 Id. at 52-53.
APPLICATION - 6

requesting that the Commission approve a particular CCOS methodology.12 It further
stated, however, that the Company's filed CCOS methodology, updated to reflect the
settled revenue requirement, was utilized on a limited basis to update certain rates,
including special contract rates, which included rates contained within the Schedule 34,
Lamb Weston Special Contract, that had been approved by the Commission effective
September 21, 2023.13
13. On December 28, 2023, the Commission issued Order No. 36042 approving
the Settlement Stipulation and authorizing the Company to implement its revised tariff
schedule with the terms of the Settlement, effective January 1, 2024. Thereafter, the
Commission issued Order No. 36067, approving the Company's compliance filings.
Case No. IPC-E-24-15 — Annual Update to Marginal Pricinq Used in Certain
Schedules
14. On April 1, 2024, the Company filed its application in Case No. IPC-E-24-
15 requesting to update the marginal cost-based energy prices contained in Schedule 20
and Schedule 34. The Company requested to update the marginal energy price
component for these schedules effective June 1, 2024. Consistent with the Commission-
approved methodology, the marginal cost of energy was determined by simulating the
hourly operation of the Company's power supply system under expected resources,
streamflow conditions, and fuel prices for the April 2024 through March 2025 test year.
First, base case net power supply expenses were quantified, then the model was rerun
with an additional 15 megawatts ("MW") of load. The difference in power supply expenses
between the base and the base-plus-15 MW scenario was divided by the difference in
12 Id., Stipulation and Settlement at 9 (Oct. 27, 2023).
13 Case No. IPC-E-23-18, Order No. 35959 (Oct. 13, 2023).
APPLICATION - 7

megawatt-hours to calculate the marginal cost of energy ("Two Run Method"). The 15
MW incremental load used in the base-plus-15 MW scenario was based on Lamb
Weston's expected incremental load. The same 15 MW basis was proposed for Schedule
20 because the Company did not have any Schedule 20 customers, and the Company
believed 15 MW represented a reasonable proxy until the Company had Schedule 20
customers taking or projected to take service. The Company also noted that it planned to
continue its investigation of methodologies for calculating marginal cost-based rates for
current and future customers and would engage with Staff to determine the best
method(s) moving forward.
15. On May 31, 2024, the Commission issued Order No. 36201 approving the
Company's request to update the marginal energy price component of Schedule 20 and
Schedule 34, to be effective June 1, 2024.
16. Around this same time, Idaho Power held follow up discussions with Staff
to review the Two Run Method and explore potential refinements to the methodology.
More specifically, Idaho Power identified that the introduction of battery resources into the
model caused inaccurate and unintuitive marginal cost prices at the hourly level, as each
scenario run dispatched the batteries differently. As a result of the evaluation and
discussions with Staff, Idaho Power identified an improvement to its marginal cost of
energy methodology, which as more fully described herein, is referred to as the Single
Run Method.
17. Idaho Power seeks to apply the Two Run Method for use in Schedule 34
because the Lamb Weston Special Contract prescribes use of that methodology.
However, Idaho Power believes it is appropriate to implement the Single Run Method for
APPLICATION - 8

use in the updated Schedule 20 pricing, as the results of the Two Run Method does not
provide accuracy at the hourly level.14
II. REQUEST
18. The Company makes the instant filing requesting to update the marginal
energy price component of Schedule 20 and Schedule 34 to be effective June 1, 2025,
as detailed below. Attachment 1 to the Application contains the clean and legislative
versions of the tariff schedules proposed to take effect June 1, 2025.
19. The Two Run Method, as approved by the Commission in Case No. IPC-E-
24-15, remains unchanged and was used to calculate the marginal cost-based energy
price for Schedule 34. Because the Two Run Method is explicitly described in Lamb
Weston's Special Contract, the Company cannot propose a change without first
negotiating a contract amendment with Lamb Weston.
20. In preparation of this case, Idaho Power identified relying on the Two Run
Method for use in Schedule 20 produced inaccurate hourly pricing. As previously
described, this occurs because the model dispatches the batteries at different times
between the runs. Because the Two Run Method cannot be relied on to inform accurate
price signals based on time of day, Idaho Power proposes to rely on the Single Run
Method for determining the marginal energy cost-based energy price for Schedule 20.
21. The Single Run Method is described as follows: Idaho Power simulated the
hourly operation of the Company's power supply system under expected resources,
streamflow conditions, and fuel prices for the April 2025 — March 2026 test year, based
14 Specifically, criteria (iii)of the Staff Memo envisions an appropriate methodology will produce rates with
"enough granularity to reflect time difference (e.g., seasonality, time of day)value of Marginal Cost within
the Company's system to provide accurate price signals."
APPLICATION - 9

on the most current information available at the time the filing was prepared. The hourly
marginal resource price is determined based on the Company's expected load (net of the
marginal cost-priced load) for the test year, plus an incremental load increase added in
100 MW increments. A weighted average marginal-cost based rate is then calculated
based on the total marginal cost-priced load expected to be operational during the test
year.
22. In assessing the appropriate MW increment to rely on as a basis for the
Single Run Method, Idaho Power sought to balance the need for a repeatable, easy to
understand process with the goal of accurately estimating the impact that incremental
load has on power supply costs. Idaho Power determined that 100 MW is a reasonable
increment; in its analysis, Idaho Power found that smaller increments will increase
complexity and run time without a commensurate increase in accuracy. For example,
reducing the MW increment to 50 MW would require double the amount of model runs,
and yield similar results (less than a 2 percent variance) to the 100 MW incremental runs.
23. Both the Two Run Method and the Single Run Method are consistent with
the principles identified by Staff as best practices that should be considered when
evaluating marginal pricing methodologies as outlined in the Staff Memo. However, the
Single Run Method represents further honing of the methodology to address the identified
limitations with the Two Run Method.
24. The resulting annual and time-differentiated marginal costs— using the Two
Run Method for Schedule 34 and the Single Run Method for Schedule 20 — are included
in Attachment 3 to the Application. For informational purposes, the Company has also
included in Attachment 3 the time-differentiated marginal costs for Schedule 20 under the
APPLICATION - 10

Two Run Method.
25. To the extent that service is provided under Schedule 20 or Block 2 of
Schedule 34, all associated energy sales will be tracked in the PCA and included as an
offset to power supply expenses.
III. MODIFIED PROCEDURE
26. Idaho Power believes that a hearing is not necessary to consider the issues
presented herein and respectfully requests that this Application be processed under
Modified Procedure, i.e., by written submissions rather than by hearing. RP 201 , et seq.
If, however, the Commission determines that a technical hearing is required, the
Company stands ready to prepare and present testimony in support of this Application in
such hearing.
IV. COMMUNICATIONS AND SERVICE OF PLEADINGS
27. Communications and service of pleadings, exhibits, orders, and other
documents relating to this proceeding should be served on the following:
Megan Goicoechea Allen Matthew T. Larkin
Donovan Walker Grant T. Anderson
IPC Dockets 1221 West Idaho Street (83702)
1221 West Idaho Street (83702) P.O. Box 70
P.O. Box 70 Boise, ID 83707
Boise, ID 83707 mlarkin(a)_idahopower.com
mgoicoecheaallenCcb,idahopower.com [e-mail]
dwalker(c�idahopower.com
dockets idaho power.com
V. REQUEST FOR RELIEF
28. The methods underlying the Company's proposals to update marginal cost-
based customer energy rates in this case is consistent with that previously approved by
the Commission, and therefore, Idaho Power Company respectfully requests that the
APPLICATION - 11

Commission issue an order authorizing it to update the marginal energy price component
of Schedules 20 and 34 effective June 1, 2025.
DATED at Boise, Idaho, this 1 St day of April 2025.
MEGAN GOICOECHEA ALLEN
Attorney for Idaho Power Company
APPLICATION - 12

CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 1st day of April, 2025 1 served a true and correct
copy of IDAHO POWER COMPANY'S APPLICATION upon the following named parties
by the method indicated below, and addressed to the following:
Commission Staff Hand Delivered
Chris Burdin U.S. Mail
Deputy Attorney General Overnight Mail
Idaho Public Utilities Commission FAX
11331 W. Chinden Blvd., Bldg No. 8 FTP Site
Suite 201-A (83714) X Email Chris.burdin(a-),puc.idaho.gov
PO Box 83720
Boise, ID 83720-0074
C9
Christy Davenport
Legal Administrative Assistant
APPLICATION - 13

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-17
IDAHO POWER COMPANY
ATTACHMENT NO. 1
PROPOSED TARIFF SCHEDULES

Idaho Power Company Fourth Revised Sheet No. 20-6
Cancels
I.P.U.C. No. 30, Tariff No. 101 Third Revised Sheet No. 20-6
SCHEDULE 20
SPECULATIVE HIGH-DENSITY LOAD
(Continued)
MONTHLY CHARGE
The Monthly Charge is the sum of the following charges, and may also include charges as set
forth in Schedule 91 (Energy Efficiency Rider), and Schedule 95 (Adjustment for Municipal Franchise
Fees).
Large General Service Rates
PRIMARY SERVICE Summer Non-summer
Service Charge, per month $340.00 $340.00
Basic Charge, per kW of $1.79 $1.79
Basic Load Capacity
Demand Charge, per kW of $8.71 $8.28
Billing Demand
Energy Charge, per kWh
On-Peak 7.51940 6.63730
Mid-Peak 7.11980 5.68240
Off-Peak 5.28930 5.14810
TRANSMISSION SERVICE Summer Non-summer
Service Charge, per month $340.00 $340.00
Basic Charge, per kW of
Basic Load Capacity $1.07 $1.07
Demand Charge, per kW of
Billing Demand $7.75 $6.85
Energy Charge, per kWh
On-Peak 7.45160 6.54230
Mid-Peak 7.05200 5.58770
Off-Peak 5.21570 5.05280
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective —June 1, 2025 1221 West Idaho Street, Boise, Idaho

Idaho Power Company Fourth Revised Sheet No. 20-7
Cancels
I.P.U.C. No. 30, Tariff No. 101 Third Revised Sheet No. 20-7
SCHEDULE 20
SPECULATIVE HIGH-DENSITY LOAD
(Continued)
MONTHLY CHARGE (Continued)
Large Power Service Rates
PRIMARY SERVICE Summer Non-summer
Service Charge, per month $415.00 $415.00
Basic Charge, per kW of $2.17 $2.17
Basic Load Capacity
Demand Charge, per kW of $10.35 $8.97
Billing Demand
Energy Charge, per kWh
On-Peak 7.35710 6.46070
Mid-Peak 6.95750 5.50540
Off-Peak 5.12040 4.96990
TRANSMISSION SERVICE Summer Non-summer
Service Charge, per month $415.00 $415.00
Basic Charge, per kW of
Basic Load Capacity $1.83 $1.83
Demand Charge, per kW of
Billing Demand $10.50 $9.11
Energy Charge, per kWh
On-Peak 7.34010 6.43120
Mid-Peak 6.94050 5.47570
Off-Peak 5.10030 4.94010
PAYMENT
The monthly bill for service supplied hereunder is payable upon receipt, and becomes past due
15 days from the date on which rendered.
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective —June 1, 2025 1221 West Idaho Street, Boise, Idaho

Idaho Power Company Third Revised Sheet No. 34-4
Cancels
I.P.U.C. No. 30, Tariff No. 101 Second Revised Sheet No. 34-4
SCHEDULE 34
IDAHO POWER COMPANY
ELECTRIC SERVICE RATE
FOR
LAMB WESTON, INC.
(Continued)
BLOCK 2
MONTHLY CHARGE
The Monthly Charge is the sum of the following charges, and may also include charges as set forth in
Schedule 91 (Energy Efficiency Rider), and Schedule 95 (Adjustment for Municipal Franchise Fees).
Daily Excess Demand Charge
$1.293 per each kW over the Contract Demand.
Monthly Contract Demand Charge
$3.23 per kW of Contract Demand.
Monthly Billing Demand Charge
$23.75 per kW of Billing Demand but not less than Minimum Monthly Billing Demand.
Energy Charge
4.26380 per kWh of Block 2 Energy.
Minimum Monthly Billing Demand
The Minimum Monthly Billing Demand will be 20,000 kilowatts.
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective—June 1, 2025 1221 West Idaho Street, Boise, Idaho

Idaho Power Company Third Fourth Revised Sheet No. 20-6
Cancels
I.P.U.C. No. 30, Tariff No. 101d-Third Revised Sheet No. 20-6
SCHEDULE 20
SPECULATIVE HIGH-DENSITY LOAD
(Continued)
MONTHLY CHARGE
The Monthly Charge is the sum of the following charges, and may also include charges as set
forth in Schedule 91 (Energy Efficiency Rider), and Schedule 95 (Adjustment for Municipal Franchise
Fees).
Large General Service Rates
PRIMARY SERVICE Summer Non-summer
Service Charge, per month $340.00 $340.00
Basic Charge, per kW of $1.79 $1.79
Basic Load Capacity
Demand Charge, per kW of $8.71 $8.28
Billing Demand
Energy Charge, per kWh
On-Peak 5.2 297.51940
6.2851-6.63730
Mid-Peak 4.49277.11980
7 40565.68240
Off-Peak 5.61515.28930
6.71495.1481¢
TRANSMISSION SERVICE Summer Non-summer
Service Charge, per month $340.00 $340.00
Basic Charge, per kW of
Basic Load Capacity $1.07 $1.07
Demand Charge, per kW of
Billing Demand $7.75 $6.85
Energy Charge, per kWh
On-Peak 5.14517.45160
6.1901-6.54230
Mid-Peak 4.42497.05200
7.31095.58770
Off-Peak 5.54155.21570
60.6 955.05280
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No.-36466 Timothy E. Tatum, Vice President, Regulatory Affairs
Effective— February , 2825June 1, 2025 1221 West Idaho Street, Boise, Idaho

Idaho Power Company Third Fourth Revised Sheet No. 20-7
Cancels
I.P.U.C. No. 30, Tariff No. 101d-Third Revised Sheet No. 20-7
SCHEDULE 20
SPECULATIVE HIGH-DENSITY LOAD
(Continued)
MONTHLY CHARGE (Continued)
Large Power Service Rates
PRIMARY SERVICE Summer Non-summer
Service Charge, per month $415.00 $415.00
Basic Charge, per kW of $2.17 $2.17
Basic Load Capacity
Demand Charge, per kW of $10.35 $8.97
Billing Demand
Energy Charge, per kWh
On-Peak 5-05067.3571¢
6.10856.46070
Mid-Peak 4.33046.95750
7.22865.50540
Off-Peak 5.44625.12040
6.53664.96990
TRANSMISSION SERVICE Summer Non-summer
Service Charge, per month $415.00 $415.00
Basic Charge, per kW of
Basic Load Capacity $1.83 $1.83
Demand Charge, per kW of
Billing Demand $10.50 $9.11
Energy Charge, per kWh
On-Peak 5.03367.3401¢
6.07906.43120
Mid-Peak 4.31346.94050
7.19895.47570
Off-Peak 5.42615.10030
6.50694.9401¢
PAYMENT
The monthly bill for service supplied hereunder is payable upon receipt, and becomes past due
15 days from the date on which rendered.
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No.-36433 Timothy E. Tatum, Vice President, Regulatory Affairs
Effective—Febr,�, 282-5June 1, 2025 1221 West Idaho Street, Boise, Idaho

Idaho Power Company SeGGRd Third Revised Sheet No. 34-4
Cancels
I.P.U.C. No. 30, Tariff No. 101 €arst-Second Revised Sheet No. 34-4
SCHEDULE 34
IDAHO POWER COMPANY
ELECTRIC SERVICE RATE
FOR
LAMB WESTON, INC.
(Continued)
BLOCK 2
MONTHLY CHARGE
The Monthly Charge is the sum of the following charges, and may also include charges as set forth in
Schedule 91 (Energy Efficiency Rider), and Schedule 95 (Adjustment for Municipal Franchise Fees).
Daily Excess Demand Charge
$1.293 per each kW over the Contract Demand.
Monthly Contract Demand Charge
$3.23 per kW of Contract Demand.
Monthly Billing Demand Charge
$23.75 per kW of Billing Demand but not less than Minimum Monthly Billing Demand.
Energy Charge
4.6894.26380 per kWh of Block 2 Energy.
Minimum Monthly Billing Demand
The Minimum Monthly Billing Demand will be 20,000 kilowatts.
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. 36438 Timothy E. Tatum, Vice President, Regulatory Affairs
Effective— JaRuary 1, 2 June 1, 2025 1221 West Idaho Street, Boise, Idaho

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-17
IDAHO POWER COMPANY
ATTACHMENT NO. 2
STAFF MEMO

Memorandum
Date: 2/16/2023
From: Yao Yin, Utilities Analyst, Idaho Public Utilities Commission
To: Connie Aschenbrenner, Idaho Power Company
Subject: Investigation in Methods to determine Marginal Cost of Energy for Schedule 20.
Background
Order No. 35428 directed Idaho Power to evaluate and compare other methods for
determining a marginal cost of energy in addition to the use of Avoided Cost Averages in the
Integrated Resource Plan for setting the Schedule 20 energy rate, before the next general rate
case is developed and filed.
On January 31, 2013, Idaho Power met with Staff and discussed potential methods for
determining marginal cost of energy for the Schedule 20 energy rate and possibly for other
customers using marginal cost of energy for their energy rates. As a result of the meeting, Staff
agreed to develop some criteria for the Company to consider for developing a method.
Criteria
Although this list may not be exhaustive, Staff identified the following criteria that could
be used for determining the final method:
• The resources used in a model for determining marginal cost should be based on the
resources that are highly likely to exist during the rate period.
• The amount of incremental load used to determine the marginal cost rate should reflect
the amount of incremental load for the portion of load that will be priced at marginal cost.
• The marginal cost rates should have enough granularity to reflect time difference (e.g.
seasonality,time of day) value of Marginal Cost within the Company's system to provide
accurate price signals.
• If the marginal cost rates are based on a forecast, due to the lack of Marginal Costs being
trued-up in the PCA, they should be updated often enough that they reflect current
conditions or find a way to true up the marginal cost to actual marginal cost.
• If market costs are used, cost of transmission transaction and wheeling costs should be
included.

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-17
IDAHO POWER COMPANY
ATTACHMENT NO. 3
MARGINAL COST

Rates Effective February 1,2025-Schedule 9P Schedule 20 Large General Service Primary Rates-Proposed
Charge Type Charge Type Summer Non-Summer
Service Charge(per customer) $ 340.00 $ 340.00 Service Charge(per customer) $ 340.00 $ 340.00
Basic Charge per kW of BLC $ 1.79 $ 1.79 Basic Charge per kW of BLC $ 1.79 $ 1.79
Demand Charge per kW $ 8.18 $ 7.75 (rate+b) Demand Charge per kW $ 8.71 $ 8.28
On-Peak Demand charge per kW $ 1.56 n/a On-Peak Demand charge per kW n/a n/a
On Peak Energy Charge per kWh $ 0.052834 $ 0.047992 (rate-c+a) On Peak Energy Charge per kWh $ 0.075194 $ 0.066373
Mid Peak Energy Charge per kWh $ 0.052834 $ 0.045625 (rate-c+a) Mid Peak Energy Charge per kWh $ 0.071198 $ 0.056824
Off Peak Energy Charge per kWh $ 0.047357 $ 0.043735 (rate-c+a) Off Peak Energy Charge per kWh $ 0.052893 $ 0.051481
Rates Effective February 1,2025-Schedule 9T Schedule 20 Large General Service Transmission Rates-Proposed
Charge Type Charge Type Summer Non-Summer
Service Charge(per customer) $ 340.00 $ 340.00 Service Charge(per customer) $ 340.00 $ 340.00
Basic Charge per kW of BLC $ 1.07 $ 1.07 Basic Charge per kW of BLC $ 1.07 $ 1.07
Demand Charge per kW $ 7.22 $ 6.32 (rate+b) Demand Charge per kW $ 7.75 $ 6.85
On-Peak Demand charge per kW $ 1.56 n/a On-Peak Demand charge per kW n/a n/a
On Peak Energy Charge per kWh $ 0.052156 $ 0.047042 (rate-c+a) On Peak Energy Charge per kWh $ 0.074516 $ 0.065423
Mid Peak Energy Charge per kWh $ 0.052156 $ 0.044678 (rate-c+a) Mid Peak Energy Charge per kWh $ 0.070520 $ 0.055877
Off Peak Energy Charge per kWh $ 0.046621 $ 0.042782 (rate-c+a) Off Peak Energy Charge per kWh $ 0.052157 $ 0.050528
(a) Marginal Cost($/kWh) S NS
On-Peak $ 0.052673 $ 0.048694
Mid-Peak $ 0.048677 $ 0.041512
Off-Peak $ 0.035849 $ 0.038059
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(b) Peak Demand Adder($/kW) $ 0.53
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(c) Embedded Energy Rate($/kWh) $ 0.030313
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Case No. IPC-E-25-17
Attachment 3
Page 1 of 5

Rates Effective February 1,2025-Schedule 19P Schedule 20 Large Power Primary Rates-Proposed
Charge Type Charge Type Summer Non-Summer
Service Charge(per customer) $ 415.00 $ 415.00 Service Charge(per customer) $ 415.00 $ 415.00
Basic Charge per kW of BLC $ 2.17 $ 2.17 Basic Charge per kW of BLC $ 2.17 $ 2.17
Demand Charge per kW $ 9.84 $ 8.46 (rate+b) Demand Charge per kW $ 10.35 $ 8.97
On-Peak Demand charge per kW $ 1.56 n/a On-Peak Demand charge per kW n/a n/a
On Peak Energy Charge per kWh $ 0.051263 $ 0.046278 (rate-c+a) On Peak Energy Charge per kWh $ 0.073571 $ 0.064607
Mid Peak Energy Charge per kWh $ 0.051263 $ 0.04,3907 (rate-c+a) Mid Peak Energy Charge per kWh $ 0.069575 $ 0.055054
Off Peak Energy Charge per kWh $ 0.045720 $ 0.042005 (rate-c+a) Off Peak Energy Charge per kWh $ 0.051204 $ 0.049699
Rates Effective February 1,2025-Schedule 19T Schedule 20 Large Power Transmission Rates-Proposed
Charge Type Charge Type Summer Non-Summer
Service Charge(per customer) $ 415.00 $ 415.00 Service Charge(per customer) $ 415.00 $ 415.00
Basic Charge per kW of BLC $ 1.83 $ 1.83 Basic Charge per kW of BLC $ 1.83 $ 1.83
Demand Charge per kW $ 9.99 $ 8.60 (rate+b) Demand Charge per kW $ 10.50 $ 9.11
On-Peak Demand charge per kW $ 1.56 n/a On-Peak Demand charge per kW n/a n/a
On Peak Energy Charge per kWh $ 0.051093 $ 0.045983 (rate-c+a) On Peak Energy Charge per kWh $ 0.073401 $ 0.064312
Mid Peak Energy Charge per kWh $ 0.051093 $ 0.043610 (rate-c+a) Mid Peak Energy Charge per kWh $ 0.069405 $ 0.054757
Off Peak Energy Charge per kWh $ 0.045519 $ 0.041707 (rate-c+a) Off Peak Energy Charge per kWh $ 0.051003 $ 0.049401
(a) Marginal Cost($/kWh) S NS
On-Peak $ 0.052673 $ 0.048694
Mid-Peak $ 0.048677 $ 0.041512
Off-Peak $ 0.035849 $ 0.038059
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(b) Peak Demand Adder($/kW) $ 0.51
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(c) Embedded Energy Rate($/kWh) $ 0.030365
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Case No. IPC-E-25-17
Attachment 3
Page 2 of 5

Schedule 34
Lamb Weston, Inc.
Current Proposed %
Block 2-Energy Charge($/kWh) $ 0.046890 $ 0.042638 -9%
Case No. IPC-E-25-17
Attachment 3
Page 3 of 5

NPSE - Marginal Price Differentials 2025 Marginal Cost Update - Single Run Method
Summer(June-September) Total Hours %of Total $/MWh Price Ratio
On-Peak 408 14% $ 52.67 1.30
Mid-Peak 510 17% $ 48.68 1.20
Off-Peak 2,010 69% $ 35.85 0.89
Summer Average 2,928 100% $ 40.43 1.00
Non-Summer(October-May) Total Hours %of Total $/MWh Price Ratio
On-Peak 1,236 21% $ 48.69 1.19
Mid-Peak 1,236 21% $ 41.51 1.01
Off-Peak 3,360 58% $ 38.06 0.93
Non-Summer Average 5,832 100% $ 41.04 1.00
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Annual Average 8,760 $ 40.84
Case No. IPC-E-25-17
Attachment 3
Page 4 of 5

NPSE - Marginal Price Differentials 2025 Marginal Cost Update -Two Run Method
Summer(June-September) Total Hours %of Total $/MWh Price Ratio
On-Peak 408 14% $ 26.02 1.87
Mid-Peak 510 17% $ (10.59) (0.76)
Off-Peak 2,010 69% $ 17.73 1.27
Summer Average 2,928 100% $ 13.95 1.00
Non-Summer(October-May) Total Hours %of Total $/MWh Price Ratio
On-Peak 1,236 21% $ 67.61 1.19
Mid-Peak 1,236 21% $ 5.31 0.09
Off-Peak 3,360 58% $ 72.18 1.27
Non-Summer Average 5,832 100% $ 57.04 1.00
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Annual Average 8,760 $ 42.64
Case No. IPC-E-25-17
Attachment 3
Page 5 of 5