20250129IPC to Staff 1-5.pdf

"4%611-0IQAW POWER.
RECEIVED
Wednesday,January 29, 2025
MEGAN GOICOECHEA ALLEN IDAHO PUBLIC
Corporate Counsel UTILITIES COMMISSION
mgoicoecheaallenC&_idahopower.com
January 29, 2025
Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Boulevard
Building 8, Suite 201-A
Boise, Idaho 83714
Re: Case No. IPC-E-24-44
Idaho Power Company's Application for Approval of a Special Contract and
Tariff Schedule 28 to Provide Electric Service to Micron Idaho Semiconductor
Manufacturing (Triton) LLC
Dear Commission Secretary:
Attached for electronic filing, please find Idaho Power Company's Response to the
First Production Request of the Commission Staff to Idaho Power in the above-entitled
matter.
The confidential attachments will be provided to the parties who sign the Protective
Agreement.
If you have any questions about the attached documents, please do not hesitate
to contact me.
Sincerely,
ukr I f��Cfi�1.PA
Megan Goicoechea Allen
MGA:sg
Attachments
1221 W. Idaho St(83702)
P.O. Box 70
Boise, ID 83707

CERTIFICATE OF ATTORNEY
ASSERTION THAT INFORMATION CONTAINED IN AN IDAHO PUBLIC UTILITIES
COMMISSION FILING IS PROTECTED FROM PUBLIC INSPECTION
Idaho Power Company's Application for Approval of Special Contract and Tariff
Schedule 28 to Provide Electric Service to Micron Idaho Semiconductor
Manufacturing (Triton) LLC
Case No. IPC-E-24-44
The undersigned attorney, in accordance with Commission Rules of Procedure
67, believes that Attachments Nos. 1, 3, 4, and 5 to Response No. 1 and the
Attachment to Response No. 3 to Idaho Power Company's Response to the First
Production Request of the Commission Staff to Idaho Power, dated January 29, 2025,
contains information that Idaho Power and a third party claim constitutes trade secrets,
confidential business records, and/or other non-public records exempt from disclosure
under state or federal law including but not limited to Idaho Code § 48-801, et seq.;
Idaho Code § 74-101, et seq.; and/or U.S. Code of Federal Regulations Title 17." As
such, it is protected from public disclosure, inspection, examination, or copying.
DATED this 29th day of January 2025.
Megan Goicoechea Allen
Counsel for Idaho Power Company

MEGAN GOICOECHEA ALLEN (ISB No. 7623)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
mgoicoecheaallenCo)idahopower.com
Attorney for Idaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY'S APPLICATION FOR ) CASE NO. IPC-E-24-44
APPROVAL OF SPECIAL CONTRACT AND )
TARIFF SCHEDULE 28 TO PROVIDE ) IDAHO POWER COMPANY'S
ELECTRIC SERVICE TO MICRON IDAHO ) RESPONSE TO THE FIRST
SEMICONDUCTOR MANUFACTURING ) PRODUCTION REQUEST OF THE
(TRITON) LLC. ) COMMISSION STAFF TO IDAHO
POWER
COMES NOW, Idaho Power Company ("Idaho Power" or "Company"), and in
response to the First Production Request of the Commission ("Commission" or "IPUC")
Staff to Idaho Power Company dated January 8, 2025, herewith submits the following
information:
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER- 1

REQUEST FOR PRODUCTION NO. 1: In reference to the proposed Demand and
Energy Charges discussed on pages 7-9 of the Application, please respond to the
following:
a. Please provide all workpapers used to determine the Demand Charges. Please
provide all workpapers in electronic format with formulas enabled.
b. Please provide all model runs and workpapers used to determine the Energy
Charge. For the model runs, please provide the assumptions used for each model
run. Please provide all files in electronic format with formulas enabled.
c. Please explain if the Company considered any other methods to determine the
Energy Charge for Schedule 28 besides the marginal cost method discussed in
the Application. If other methods were considered, please explain the method(s)
considered and why these method(s)were not selected. If no other method(s)were
considered, please explain why no other methods were considered.
d. Please explain if the Company evaluated the proposed Energy Charge
differentiated by season and by On, Mid, and Off-peak hour pricing similar to
Demand-Side Management Avoided Cost Averages. If the Company did evaluate
the time periods, please explain why the time periods were not used and provide
the Company's workpapers from the evaluation. If the Company did not evaluate
these time periods, please explain why these time periods were not evaluated.
e. Please provide a proposal for Energy Charges differentiated by season and by On,
Mid, and Off-peak hours with electronic workpapers documenting the method.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER- 2

RESPONSE TO REQUEST FOR PRODUCTION NO. 1: Please see responses
below regarding the proposed Demand and Energy Charges:
a. Please see the file labeled "Confidential Attachment 1 — Response to Staff Request
No. 1 — Pricing Workpaper" for the derivation of the Billing Demand Charge. The
Contract Demand Charge is consistent with the Contract Demand charge
approved by the Commission for all special contract customers at the time the
Electric Service Agreement ("ESA") was executed.
b. Please see the file labeled "Attachment 2 — Response to Staff Request No. 1 —
Zonal Prices" for the hourly zonal prices from the AURORA run used to determine
the annual Energy Charge. Input assumptions are based on the Company's 2023
Integrated Resource Plan ("IRP") AURORA model, with updates to load, fuel
prices, and expected hydro generation for the April 2024 — March 2025 test year.
Please see Confidential Attachments 3 — 5 and Attachment 6.
c. Yes. Following Order No. 35428 received in Idaho Power's application to establish
a new schedule to serve Schedule 20 customers (Case No. IPC-E-21-37), Idaho
Power was directed to evaluate methods for determining a marginal cost of energy
in addition to the use of IRP Avoided Cost Averages. On January 31, 2023, Idaho
Power met with Staff and discussed three potential methods for determining the
marginal cost of energy for Schedule 20 and for other future customers priced at
a marginal cost-based energy rate. The three methods evaluated in that discussion
were IRP Avoided Cost Averages, AURORA-modeled marginal energy prices with
an incremental load increase ("AURORA Method"), and market prices. Please see
the file labeled "Attachment 7 — Response to Staff Request No. 1 — Marginal Cost
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER- 3

Methods" for a summary of that discussion. Ultimately, Idaho Power utilized the
AURORA Method in determining marginal cost-based rates for Schedule 20
customers beginning June 1, 2023.
In May and June 2024, Idaho Power held follow up discussions with Staff to refine
the AURORA Method. Idaho Power incorporated feedback received from Staff to
arrive at the methodology utilized in determining the proposed Energy Rate for
Schedule 28 in this filing.
d. No, the Company did not consider seasonal and/or time-of-use rates due to the
lack of variability in the load. This approach is consistent with other special contract
customers.
e. Because the Company did not consider or propose such an approach, it has no
such analysis to present. See response to part d of this response.
The response to this Request is sponsored by Grant T. Anderson, Regulatory
Consultant, and Jessi Brady, Senior Regulatory Analyst, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER-4

REQUEST FOR PRODUCTION NO. 2: In reference to the option under Section
7.2 to reevaluate the basis for Energy Charges discussed on page 9 of the Application,
please respond to the following:
a. Please explain the rationale for allowing a reevaluation after the schedule ramp
period end versus a different time period; and
b. Please provide examples of when the Company would consider pricing the Micron
FAB facility at its then embedded variable energy costs.
RESPONSE TO REQUEST FOR PRODUCTION NO. 2:
a. Evaluating the basis for Energy Charges after the scheduled ramp period is
intended to seek a balance between incremental costs of customer load growth in
a customer class of one and upward rate pressure to all other customers, along
with fair, just, and reasonable rates for standard service as part of the Company's
obligation to serve that customer class of one at a time when Idaho Power's system
is constrained. The Company's existing customers are allocated a share of
existing, embedded systems costs. The marginal cost-based Energy Charge in the
near term recognizes the incremental cost of load growth from Micron but provides
a future point in time when the customer's load may receive embedded cost
assignment consistent with other existing Idaho Power customers. Additionally, the
Commission has approved similar provisions to transition from marginal cost-
based to embedded rates in special contracts for electric service for Hoku
Materials, Inc. in Case No. IPC-E-08-21 and Lamb Weston, Inc. in Case No. IPC-
E-23-18. In each of those cases, the provisions contemplated a five-year period
which the scheduled ramp in the instant case exceeds.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER- 5

b. As referenced in Section 7.2 of the Micron FAB Electric Service Agreement
("ESA"), Idaho Power would reevaluate the basis of the Energy Charge after the
scheduled ramp period ends and the load has reached steady state.
The response to this Request is sponsored by Grant T. Anderson, Regulatory
Consultant, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER- 6

REQUEST FOR PRODUCTION NO. 3: Please provide all annual and hourly load
forecasts for the years 2025 through 2031 the Company has for the Micron FAB facility.
Please provide files in electronic format with formulas enabled.
RESPONSE TO REQUEST FOR PRODUCTION NO. 3: Please see the file
labeled "Confidential Attachment — Response to Staff Request No. 3 - Load Forecasts"
for the load forecasts provided by Micron for the Micron FAB facility. The load forecasts
include a monthly peak demand and load factor with an assumed flat hourly shape for
each month.
The response to this Request is sponsored by Grant T. Anderson, Regulatory
Consultant, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER- 7

REQUEST FOR PRODUCTION NO. 4: Please explain how the Company plans
to incorporate Schedule 28 into future rate cases.
RESPONSE TO REQUEST FOR PRODUCTION NO. 4: The Company would
include Schedule 28 in a future general rate case test year and allocate the applicable
share in a class cost-of-service study to derive the Demand Charges. While the Company
has not yet identified the exact method, it anticipates proposing a "known and
measurable" adjustment be applied to the test year to account for the Micron FAB billing
determinants during the scheduled ramp period.
The response to this Request is sponsored by Grant T. Anderson, Idaho Power
Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER- 8

REQUEST FOR PRODUCTION NO. 5: Please explain if Micron FAB's Scheduled
Ramp Contract Demand set forth in Exhibit 3 of the Special Contract is still accurate
based on any changes that have occurred in their schedule for expanding operations.
RESPONSE TO REQUEST FOR PRODUCTION NO. 5: Micron provided an
updated load forecast in December 2024. The updated load forecast included an increase
to Scheduled Ramp Contract Demand of 7.0 MW effective February 1, 2028, 16.5
MW effective June 1, 2028, and 13.5 MW effective October 1, 2028.
The response to this Request is sponsored by Grant T. Anderson, Regulatory
Consultant, Idaho Power Company.
Respectfully submitted this 29t" day of January 2025.
nr T I yze UA &
MEGAN GOICOECHEA ALLEN
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER- 9

CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 29th day of January 2025, 1 served a true and
correct copy of Idaho Power Company's Response to the First Production Request of the
Commission Staff to Idaho Power 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(cbpuc.idaho.gov
PO Box 83720
Boise, ID 83720-0074
Stacy Gust
Regulatory Administrative Assistant
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER- 10

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-44
IDAHO POWER COMPANY
CONFIDENTIAL
RESPONSE TO REQUEST NO. 1
ATTACHMENT NO. 1

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-44
IDAHO POWER COMPANY
RESPONSE TO REQUEST NO. 1
ATTACHMENT 2

SEE ATTACHED SPREADSHEET

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-44
IDAHO POWER COMPANY
CONFIDENTIAL
RESPONSE TO REQUEST NO. 1
ATTACHMENT 3

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-44
IDAHO POWER COMPANY
CONFIDENTIAL
RESPONSE TO REQUEST NO. 1
ATTACHMENT 4

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-44
IDAHO POWER COMPANY
CONFIDENTIAL
RESPONSE TO REQUEST NO. 1
ATTACHMENT 5

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-44
IDAHO POWER COMPANY
RESPONSE TO REQUEST NO. 1
ATTACHMENT 6

SEE ATTACHED SPREADSHEET

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-44
IDAHO POWER COMPANY
RESPONSE TO REQUEST NO. 1
ATTACHMENT 7

Attachment 7-Response to Staff Request No.1
IDPW
&�,.POMR®
An IDACORP Cnmpany
Methods for Determining
Marginal Cost
For Discussion Purposes Only
January 2023
© 2023 Idaho Power

Idaho Power Company Methods for Determining Marginal Cost
Table of Contents
Tableof Contents..............................................................................................................................i
Listof Tables .....................................................................................................................................i
Background ............................................................................................................................... 1
IRP Demand Side-Management (DSM) Avoided Cost Averages............................................... 2
How is marginal cost calculated under this method? ........................................................ 2
Application.......................................................................................................................... 2
Benefits............................................................................................................................... 3
DiscussionPoints................................................................................................................. 3
Power Cost Modeling with Incremental Load Increase —AURORA.......................................... 4
How is marginal cost calculated under this method? ........................................................ 4
Application.......................................................................................................................... 4
Benefits............................................................................................................................... 5
Power Cost Modeling with Incremental Load Increase —Op Plan ........................................... 5
MarketPrices............................................................................................................................ 6
How is marginal cost calculated under this method? ........................................................ 6
DiscussionPoints................................................................................................................. 6
EmbeddedEnergy Mill Rate...................................................................................................... 7
How is the embedded energy mil rate calculated?............................................................ 7
DiscussionPoints................................................................................................................. 7
List of Tables
Table 1
DSM Avoided Cost Averages calculated in the 2021 IRP............................................................. 2
Table 2
Marginal cost rate based on power cost modeling in AURORA with incremental load
increase........................................................................................................................................ 4
For Discussion Purposes Only Page i

Idaho Power Company Methods for Determining Marginal Cost
Table 3
Energy-classified costs included in rates ..................................................................................... 7
For Discussion Purposes Only Page ii

Idaho Power Methods for Determining Marginal Cost
Background
Following Order No. 35428 received in Idaho Power's application to establish a new schedule to
serve speculative high-density load customers', Idaho Power was directed, in advance of filing
its next GRC, to "evaluate and compare other methods for determining a marginal cost of
energy in addition to the use of [Avoided Cost Averages] ACA in the IRP for setting the Schedule
20 energy rate."
The Company has evaluated three methods, including the current Demand-Side Management
ACA used in Schedule 20, as potential approaches for determining the marginal cost of energy.
The chosen method will be used to calculate the marginal cost of energy for Schedule 20 rates
and may further be applied to customers taking service under a Special Contract which includes
energy priced at a marginal rate.
The three methods evaluated include:
1. IRP Demand-Side Management (DSM)Avoided Cost Averages
2. Power Cost Modeling with Incremental Load Increase
a. AURORA
b. Op Plan
3. Market Prices
In addition to these, for comparative purposes, Idaho Power has also included a section
describing the embedded energy mill rate.
1 Docket No. IPC-E-21-37
For Discussion Purposes Only Page 1

Idaho Power Methods for Determining Marginal Cost
IRP Demand Side-Management (DSM) Avoided Cost Averages
DSM Avoided Cost Averages (also referred to as DSM Alternate Costs) are calculated marginal
cost rates used to evaluate the cost-effectiveness of the Company's DSM measures and
programs. They are calculated every two years with each Integrated Resource Plan (IRP).
How is marginal cost calculated under this method?
1. Using the load and resource balance from the most recently acknowledged IRP
preferred portfolio, Idaho Power uses the AURORA tool to simulate the Company's
power supply system and calculate estimated net power supply expenses (NPSE) on an
hourly basis.
2. The output from this simulation is an hourly resource stack, which includes the resource
generating the last unit of power in each hour and the associated cost of that resource.
3. The data is then condensed to show the marginal resource and cost for every hour.
4. These hourly prices are then averaged by time-block (Summer On-Peak, Summer Mid-
Peak, Sumer Off-Peak, Non-Summer Mid-Peak, Non-Summer Off-Peak) for each year
that the simulation is run (20-year IRP planning period).
Application
If this method is applied to a marginal cost rate in a tariff or special contract, the Company
would use the Avoided Cost Average(s) for the year that the rate is in effect. If it were to apply
this method to a contract being evaluated in 2023, it would use the rates (or an annual average
rate) for the 2023 year in Table 1. Underlying hourly calculations have been provided to Staff in
Workpaper 1.
Table 1
DSM Avoided Cost Averages calculated in the 2021 IRP'
Summer Summer Summer Non-Summer Non-Summer Annual
Year e
On-Peak Mid-Peak Off-Peak Mid-Peak Off-Peak Average
2022 $ 32.83 $ 26.70 $ 23.62 $ 26.41 $ 23.64 $ 25.57
2023 $ 47.75 $ 40.76 $ 35.04 $ 36.78 $ 33.10 $ 36.31
2024 $ 49.14 $ 41.34 $ 36.00 $ 36.46 $ 33.57 $ 36.57
2025 $ 49.63 $ 41.03 $ 36.28 $ 34.61 $ 32.32 $ 35.43
2026 $ 50.40 $ 40.01 $ 34.38 $ 35.11 $ 32.97 $ 35.61
2027 $ 50.75 $ 35.14 $ 31.16 $ 30.71 $ 31.06 $ 32.41
2028 $ 54.17 $ 36.81 $ 32.71 $ 31.79 $ 33.55 $ 34.19
2029 $ 53.51 $ 36.42 $ 33.44 $ 33.05 $ 35.85 $ 35.49
'Published DSM Avoided Costs (excluding annual average) included in the 2021 IRP Appendix C:
https://puc.idaho.gov/Fileroom/PublicFiles/ELEC/IPC/IPCE2143/CaseFiies/20211230IRP/`2OAppendix%20C.pdf
For Discussion Purposes Only Page 2

Idaho Power Methods for Determining Marginal Cost
2030 $ 51.51 $ 30.48 $ 30.30 $ 30.44 $ 36.23 $ 33.57
2031 $ 54.93 $ 31.80 $ 32.57 $ 31.69 $ 37.22 $ 34.97
2032 $ 55.88 $ 32.56 $ 33.72 $ 33.05 $ 39.16 $ 36.46
2033 $ 55.06 $ 29.37 $ 33.17 $ 31.75 $ 40.52 $ 36.01
2034 $ 57.35 $ 31.20 $ 34.77 $ 32.64 $ 41.68 $ 37.24
2035 $ 57.24 $ 31.79 $ 35.03 $ 34.11 $ 43.54 $ 38.52
2036 $ 58.88 $ 32.54 $ 36.79 $ 36.38 $ 44.18 $ 40.00
2037 $ 56.64 $ 29.74 $ 35.62 $ 30.80 $ 39.90 $ 35.84
2038 $ 58.93 $ 32.09 $ 38.00 $ 32.12 $ 42.51 $ 37.82
2039 $ 61.82 $ 34.40 $ 40.23 $ 32.53 $ 42.10 $ 38.46
2040 $ 62.84 $ 35.36 $ 41.54 $ 32.02 $ 42.16 $ 38.57
Benefits
- The IRP is a published document, and the preferred portfolio is vetted via IRPAC
meetings.
- It is a repeatable and transparent process.
- Hourly data is available, which allows for flexibility of rate design in the future.
Discussion Points
- DSM Avoided Costs are calculated every two years with IRP filings, resulting in
potentially outdated modeling assumptions (load, fuel prices, etc.).
o Idaho Power could calculate DSM Avoided Costs on off-IRP years using the same
preferred portfolio but with an updated load forecast and updated fuel
assumptions.
- There is no incremental load increase with this method, as DSM Avoided Cost Averages
are meant to represent an avoided cost as a result of a reduction in load due to energy
efficiency activities. In other words, while this method is reasonable to determine the
value of DSM programs and/or energy efficiency activities, it does not calculate the cost
of the additional energy generated as a result of increased load to the system.
For Discussion Purposes Only Page 3

Idaho Power Methods for Determining Marginal Cost
Power Cost Modeling with Incremental Load Increase — AURORA
The calculated change in NPSE divided by the change in generation as a result of adding
incremental load to the system.
How is marginal cost calculated under this method?
Using the AURORA tool, the Company would calculate forecast NPSE and generation for a test
year under two scenarios:
- forecast load
- forecast load + incremental load increase
The test year would align with the PCA year (forward looking April — March). This time period
allows the Company to more accurately forecast expected water conditions based on the
winter snowpack.
The below table shows total NPSE and total generation calculated for both scenarios. For this
example, the Company used an incremental 50 MW increase in load. Underlying hourly
calculations have been provided to Staff in Workpaper 2.
Table 2
Marginal cost rate based on power cost modeling in AURORA with incremental load increase
Scenario Type Total
Base Case Energy(MWh) 14,008,633
Base Case Cost $236,097,560
+50 aMW Energy(MWh) 14,447,834
+50 aMW Cost $253,672,560
Application
If this method is applied to a marginal cost rate in a tariff or special contract, the Company
would use the below formula to calculate an annual marginal cost rate for the test year.
Marginal Cost Rate — ($253,672,560 — $236,097,560)
(14,447,834 MWh — 14,008,633 MWh)
Marginal Cost Rate = 40.02 $/MWh3
a Because expected hydro conditions are not available yet for the 2023—2024 test year, normal or average hydro
conditions were used for this analysis.The Company expects that due to lower than normal expected hydro
conditions for the upcoming test year,actual calculated marginal cost rates will be higher.
For Discussion Purposes Only Page 4

Idaho Power Methods for Determining Marginal Cost
Benefits
- Idaho Power is currently calculating net power supply expenses (base case scenario)
annually for use in the Oregon Power Cost filing.
- Follows methodology consistent with how marginal energy costs are developed for the
Company's energy marginal cost weighting in the cost-of-service model. The
incremental load increase method (50 aMW) is based on the National Economic
Research Associates Inc (NERA) marginal cost model used for cost-of-service.
- It is a repeatable and transparent process.
- Hourly data is available, which allows for flexibility of rate design in the future
- A forward-looking test year coincides with the PCA process (April — March test year with
rates in effect June 1).
- This method is based on adding incremental load to the system
o Staff comments in Brisbie case: "Staff agrees that a marginal energy rate is
appropriate since it is based on the cost of the next increment of electricity
beyond what is needed by the Company's core customers."
Power Cost Modeling with Incremental Load Increase — Op Plan
Idaho Power currently forecasts NPSE as a part of the Op Plan process for use in PCA filings.The
Company evaluated the possibility of using the Op Plan process to calculate a marginal cost rate
based on the same method described above (the difference between a base case NPSE and
incremental load increase NPSE compared to the difference in generation). Throughout this
evaluation, the Company determined that the Op Plan process is not designed to run different
load forecast scenarios, and therefore, wouldn't be a good solution to calculate a marginal cost
rate.
For Discussion Purposes Only Page 5

Idaho Power Methods for Determining Marginal Cost
Market Prices'
The Company evaluated two different pricing sources for use in a marginal cost rate. These are
the Mid-C forward curve at a point in time or historical EIM prices.
How is marginal cost calculated under this method?
- Forward Mid-C curve: at an agreed upon date, the Company would pull the daily
forward Mid-C heavy load and light load prices for the test year. These could be
averaged into an annual rate or time-blocked rates.
- EIM prices: the Company could use historical EIM prices to come up with an annual or
time-blocked rate.
Discussion Points
- While market prices might be used as a proxy for a marginal cost rate, the Company
does not believe it is the best representation of the marginal cost paid by the Company.
- Market prices have been volatile over the last year.
- Assuming a market purchase is the marginal resource does not consider potential
transmission constraints.
- The EIM does not reflect the likely market in which Idaho Power would transact to
purchase additional energy to meet Schedule 20 or Special Contract customer load
requirements.
4 Because the Company doesn't believe market prices are the preferred method, it has not included actual or
forward market prices for review in this document.
For Discussion Purposes Only Page 6

Idaho Power Methods for Determining Marginal Cost
Embedded Energy Mill Rate
Costs classified as energy-related through Idaho Power's cost-of-service allocation process (fuel
is considered 100% energy-related, for example). Certain production plant accounts and
purchased power expenses utilize Idaho Power's jurisdictional load factor to classify costs
between demand-related and energy-related.
How is the embedded energy mil rate calculated?
- The Idaho Power jurisdictional load factor is determined at the time of a general rate
case; calculated as normalized test year sales, generation level including line losses;
divided by system coincident demand at the generation level for same test year.
- In the 2011 GRC, the jurisdictional load factor was 53.897 percent.
- Where the jurisdictional load factor is applied to allocate FERC accounts, 53.897 percent
is classified as energy-related, with the remaining 46.103 percent classified as capacity-
related.
Discussion Points
- Use of the jurisdictional load factor approach varies from a more traditional, accounting
basis approach to classify fixed and variable expenses. As an example, purchased power
on an accounting basis is likely to be classified as 100 percent energy-related, while
hydro plant is more likely to be considered 100 percent demand-related as the majority
of hydro-production cost is incurred independent of the amount of energy the plant
produces.
- This contrasts with application of the jurisdictional load factor which considers both
purchased power and hydro plant to be 54%/46% energy/demand classified. While the
Company's net power supply expense is traditionally thought of as a variable cost, the
cost-of-service allocation methodology has a different basis in cost assignment. Thus,
Idaho Power's net power supply expenses are unlikely to completely align with costs
allocated by the jurisdictional load factor as energy-classified.
Table 3
Energy-classified costs included in rates
Schedule Description Energy-Classified as of June 1,
2022(1 per KWh)
1 and 5 Residential Service 3.0995
7 Small General Service 3.1403
9S Large General Service 3.0473
9P and 9T Large General Service 2.7819
19 Large Power Service 2.8136
24 Irrigation Service 2.7150
26 Micron Special Contract 2.5518
For Discussion Purposes Only Page 7

Idaho Power Methods for Determining Marginal Cost
29 Simplot Special Contract 2.5678
30 DOE Special Contract 2.5225
For Discussion Purposes Only Page 8

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-44
IDAHO POWER COMPANY
CONFIDENTIAL
RESPONSE TO REQUEST NO. 3
ATTACHMENT