20230811IPC to Staff 135-154.pdf

LISA D. NORDSTROM
Lead Counsel
[e-mail]

August 11, 2023

VIA ELECTRONIC FILING

Jan Noriyuki, Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg 8,
Suite 201-A (83714)
PO Box 83720
Boise, Idaho 83720-0074

Re: Case No. IPC-E-23-11
Idaho Power Company’s General Rate Case

Dear Ms. Noriyuki:

Enclosed for electronic filing, please find Idaho Power Company’s Response to the
Sixth Production Request of the Commission Staff to Idaho Power Company.

Due to the collectively voluminous confidential and non-confidential information
provided in response to data requests in this case, the Company is posting the
attachments to these requests to the secure FTP site to allow parties to view the
requested information remotely unless otherwise noted in the response. Because certain
attachments contain confidential information, the FTP site is divided between confidential
and non-confidential information.

The login information for the non-confidential portion of the FTP site has been
provided to all parties that have intervened to date. The login information for the
confidential portion of the FTP site has been provided the parties that have executed the
Protective Agreement in this matter.

If you have any questions about the attached filing, please do not hesitate to
contact me.

Very truly yours,
Lisa D. Nordstrom
LDN:sg
Enclosures
RECEIVED
Friday, August 11, 2023 3:57:45 PM
IDAHO PUBLIC
UTILITIES COMMISSION

CERTIFICATE OF ATTORNEY

ASSERTION THAT INFORMATION CONTAINED IN AN IDAHO PUBLIC UTILITIES
COMMISSION FILING IS PROTECTED FROM PUBLIC INSPECTION
Case No. IPC-E-23-11
In the Matter of the Application of Idaho Power Company for Authority to Increase
Its Rates and Charges for Electric Service to Its Customers In the State of Idaho
and For Associated Regulatory Accounting Treatment

The undersigned attorney, in accordance with Commission Rules of Procedure 67,
believes that some of the attachments in Response to Requests Nos. 142, 147, and 148,
to Idaho Power Company’s Response to the Sixth Production Request of the Commission
Staff dated August 11, 2023, contain information that Idaho Power Company and a third
party claim are trade secrets, and/or business records of a private enterprise required by
law to be submitted to or inspected by a public agency, as described in Idaho Code § 74-
101, et seq., and/or § 48-801, et seq. As such, it is protected from public disclosure and
exempt from public inspection, examination, or copying.

DATED this 11th day of August, 2023.

LISA D. NORDSTROM
Counsel for Idaho Power Company

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 1
LISA D. NORDSTROM (ISB No. 5733)
DONOVAN E. WALKER (ISB No. 5921)
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]
[e-mail]
[e-mail]
[e-mail]

Attorneys for Idaho Power Company

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

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
ACCOUNTING TREATMENT.
)
)
)
)
)
)
)
)

CASE NO. IPC-E-23-11

IDAHO POWER COMPANY’S
RESPONSE TO THE SIXTH
PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO
POWER COMPANY

COMES NOW, Idaho Power Company (“Idaho Power” or “Company”), and in
response to the Sixth Production Request of the Commission Staff (“Commission” or
“Staff”) dated July 28, 2023, herewith submits the following information:

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 2
REQUEST FOR PRODUCTION NO. 135: Page 11 of Jessica Brady's Direct
Testimony states the Public Utility Regulatory Policies Act of 1978 ("PURPA") contracts
and power purchase agreements ("PPA") are quantified outside of AURORA, but energy
from these contracts is modeled as must-take in the AURORA simulation. Please explain
the following.
a. How the energy from these contracts is modeled as must-take in AURORA; and
b. The difference between PURPA contracts and PPA contracts, and why PPA
contracts should be treated as must-take like PURPA contracts.
RESPONSE TO REQUEST FOR PRODUCTION NO. 135:
a. Energy from PURPA and PPA resources is modeled as must-take in Aurora by
labeling the resource as “Must Run” within the model, and ensuring the associated
“Minimum Capacity” setting is 100 percent. Setting a resource as “Must Run” will
always dispatch the specified minimum capacity of the given resource, which in
this case is set to 100 percent. This ensures that AURORA will dispatch the
resource(s) according to the input generation profile(s).
b. From a modeling perspective, there is no difference between PPA and PURPA
contracts. Both PURPA and PPA generation are modeled as must-take resources
in AURORA because they are non-dispatchable, renewable resources, whose
energy is forecast based on historical actual data, contract information, or a
combination of both. As a result, the Company forecasts generation profiles for
each project for the test year and inputs them directly into the model. By having
forecast generation for renewables, AURORA can more accurately simulate the
Company’s load and resource balance on an hourly basis, and most accurately

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 3
dispatch the non “must-run” or dispatchable resources and/or market purchases
and sales.
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 4
REQUEST FOR PRODUCTION NO. 136: Page 25 of Matt Larkin's Direct
Testimony states that "Account 447.050 reflects financial payments made to Idaho Power
as compensation for the Company generating electricity to offset transmission losses to
third parties wheeling through Idaho Power's transmission system...Idaho Power is
proposing to include in its base NPSE determination both the cost of serving third party
losses as well as the offsetting revenues received through Account 447.050. Therefore,
Idaho Power added 36 average megawatts ("aMW") to its load forecast utilized for
AURORA modeling purposes to account for this load service requirement, and Ms. Brady
determined an offsetting revenue amount to include in Account 447.050." Please explain
the following:
a. How the 36 aMW is determined and provide workpapers with formulas intact;
b. Why the Planning Reserve Margin in the load forecast does not include reserves
addressing transmission losses and why an additional 36 aMW is added;
c. How the AURORA model determines transmission losses; and
d. Whether the 36 aMW corresponds to the amounts of transmission losses
identified in the AURORA dispatch.
RESPONSE TO REQUEST FOR PRODUCTION NO. 136:
a. The referenced 36 aMW was determined by multiplying the energy wheeled across
Idaho Power’s system by the associated loss factors. Please note that:
 The described energy wheeled represents the amount of energy flowing
through the Company’s system that does not serve Idaho Power’s native load.
 Loss factors were calculated for each delivery point/system level in the
Company’s 2022 loss study.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 5
The total amount of energy lost at each of the system levels was summed together
to obtain the annual energy loss due to wheeling. The total energy losses (MWh)
were then divided by the total energy wheeled (MWh) and then divided by 8,760
(total hours in the year) to arrive at the 36 aMW. This calculation is shown in the
table below and was also provided on page 10 of the workpaper of Matthew T.
Larkin.
Wheelin MWh Loss Facto Ener Loss MWh Avera e M
Transmission 9,114,526 1.029 264,321.254 30.17
Sales for Resale 1,318,132 1.029 38,225.828 4.36
Station 91,552 1.036 3,295.872 0.38
Distribution Primar 656 1.051 33.456 0.00
Distribution Secondar 117,676 1.076 8,943.376 1.02
Total 314,819.786 35.94

The attachment provided in response to this request contains the values presented
in the table above, as well as more detailed inputs and calculations. The majority
of input data is from the 2022 FERC Form No. 1 or internal databases.
b. There is no Planning Reserve Margin (“PRM”) included in the load forecast. The
36 aMW was added to the load forecast to capture the energy that the Company
needs to generate to support the system flows that do not serve Idaho Power’s
native load.
c. AURORA is a zonal model that does not simulate internal transmission systems.
Instead, AURORA models the links between zones with the corresponding loss
factor for each link. For example, if AURORA is moving energy from zone 1 to zone
2, the model would utilize the zone 1 to zone 2 loss factor. To incorporate internal
zonal losses for the Idaho Power zone, losses are calculated and included in the

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 6
load forecast. Additional information on how losses are treated in the AURORA
model is provided in the Company’s response to Request No. 151.
d. The 36 aMW does not correspond to the amounts of transmission losses identified
in the AURORA dispatch model. The 36 aMW represents the losses due to third-
party wheeling across Idaho Power’s system. To put it differently, transmission
losses are only calculated in AURORA on purchases or sales, where Idaho Power
is the buying or selling entity of the transaction. AURORA does not capture energy
generated by Idaho Power associated with losses to serve non-native load. To
account for this, the 36 aMW was included in the load forecast input into AURORA.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution, and Resource Planning Director, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 7
REQUEST FOR PRODUCTION NO. 137: Page 26 of Matt Larkin's Direct
Testimony states that "when the 2013 NPSE Update was performed, third party wheeling
customers had the option to account for wheeling losses in two ways: 1) financially-
meaning the customer would pay Idaho Power to generate the additional energy to
account for the losses, or 2) physically- meaning the customer would generate or acquire
additional physical energy to account for the losses themselves, resulting in no additional
payment to Idaho Power. However, with the advent of the energy imbalance market
("EIM"), nearly all wheeling customers now settle their losses financially, meaning they
pay Idaho Power to generate the physical energy to account for wheeling losses through
the Company's system." Please explain the following.
a. Whether the revenues associated with wheeling losses are calculated based on
the assumption that all wheeling customers choose Option 1), not Option 2);
b. Why the advent of EIM resulted in "nearly all wheeling customers now settle
their losses financially"; and
c. Please provide and explain the actual rate that a wheeling customer pays the
Company to settle losses financially.
RESPONSE TO REQUEST FOR PRODUCTION NO. 137:
a. The revenues associated with wheeling losses are calculated based on the
assumption that all wheeling customers choose Option 1 – to settle financially.
b. Upon entry into the Western EIM, Idaho Power modified Schedule 12 of its Open
Access Transmission Tariff removing the option for physical loss return. As a
result, the only option to settle losses under the Open Access Transmission Tariff
is financially. Financial settlement of losses more closely tracks actual costs than

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 8
physical loss replacement as physical loss replacement has an inherent lag that
can exploit variations in energy price. The change was approved by the Federal
Energy Regulatory Commission (“FERC”) in Docket No. ER17-2075.
c. The wheeling rate that a wheeling customer pays to settle losses financially is
based on Schedule 12 of the Idaho Power Open Access Transmission Tariff
(“OATT”). The amount of real power financial losses in a given hour is the product
of the transmission customer base schedule in the hour in MWhs, and the
applicable loss factor as defined in Section 15.7 and 28.5 of the Idaho Power OATT
(3.6%). This quantity is then multiplied by the Energy Imbalance Market (“EIM”)
hourly Load Aggregation Price (“LAP”) for the IPC BAA (IPCO_ELAP-APND) in
that hour as established by the Market Operator in accordance with section
29.11(b)(3)(C) of the Market Operator tariff.
The response to this Request is sponsored by Jennifer Gerard, Operations
Settlement Leader, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 9
REQUEST FOR PRODUCTION NO. 138: Order No. 32821 directed the Company
to include a base level of third-party transmission revenues in the next rate case so that
deviations from the base level can be tracked in PCA. Please respond to the following:
a. Please explain whether the Company includes transmission revenues in the
NPSE;
b. If yes, please identify where the revenues are recorded; and
c. If not, please explain why the revenues are not included.
RESPONSE TO REQUEST FOR PRODUCTION NO. 138:
a. No. Third-party transmission revenues are not currently considered to be net
power supply expenses (“NPSE”) for tracking through the Power Cost Adjustment
(“PCA”). However, third-party transmission revenues are included in base rates as
an offset to the Company’s transmission revenue requirement.
b. Please see the response to Part A.
c. “The PCA quantifies and tracks annual differences between actual Net Power
Supply Expenses (“NPSE”) and the normalized or “base level” of NPSE recovered
in the Company’s base rates, resulting in a credit or surcharge that is updated
annually on June 1.” Order No. 35804 at 2. Idaho Power does not consider
transmission revenue from third parties as a component of NPSE. Transmission
revenue from third parties is not tied to the variable cost of serving Idaho Power
loads and does not vary based on Idaho Power’s load service or related costs.
Rather transmission revenue from third parties varies based on 1) changes to the
Company’s Open Access Transmission Tariff rates and 2) the level of utilization of

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 10
Idaho Power’s transmission system by third parties based on their respective load
service needs.
In the base rate setting process, transmission revenue from third parties
serves to help offset some of the cost of Idaho Power’s transmission system, which
is also not included in NPSE. The Idaho jurisdictional revenue requirement offset
related to point-to-point transmission revenue from third parties included in this
case is $46,361,643. This value can be found on Exhibit No. 35, page 10, Row
389.
Idaho Power is aware of the Commission’s Order No. 32821, and its
directives related to transmission revenue. However, the Company is also guided
by the Commission’s subsequent Order No. 33313, which states:
...consistent with our prior Order No. 32821, we find that a base level of
third-party transmission revenues must first be established through a
general rate case before changing the PCA methodology.
Idaho Power interprets Order No. 33313 to indicate that the Commission
wished to use general rate case information to inform future changes to the PCA,
presumably as part of a separate PCA-specific docket. Idaho Power has argued in
past cases, and continues to believe, that should third-party transmission revenue
be tracked as part of the PCA, the most recent actual transmission cost should
also be tracked in the PCA to ensure a proper matching of costs and revenue.
These and other complexities related to how amounts should or should not be
included in the PCA support the Company’s interpretation that a separate docket
may be warranted.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 11
The response to this Request is sponsored by Timothy Tatum, Vice President of
Regulatory Affairs, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 12
REQUEST FOR PRODUCTION NO. 139: Jessica Brady's workpaper "Brady
Workpaper 4 - 565, 447.050.xlsx" states a Market Price of $31.27/MWh is "2023 Aurora
generated average annual zonal price, net of wheeling and losses." Please explain the
following:
a. What "2023 Aurora generated average annual zonal price, net of wheeling and
losses" means; and
b. Why the Market Price is used to calculate revenues of wheeling losses.
RESPONSE TO REQUEST FOR PRODUCTION NO. 139:
a. The zonal price in AURORA represents the marginal resource cost for that zone.
If the marginal resource in a given hour is a market purchase, then the zonal price
will also include wheeling costs and losses. The “2023 AURORA-generated
average annual zonal price, net of wheeling and losses” is an approximate annual
marginal cost rate that does not include the wheeling costs and losses. The
Company reduced the AURORA-stated zonal price by the weighted average
wheeling rate in the model and the Company’s loss rate of 3.6 percent.
b. The zonal price, net of wheeling and losses, was used to calculate wheeling loss
revenue as it represents an approximate marginal resource price, which is similar
to the Energy Imbalance Market (“EIM”) hourly Load Aggregation Price (“LAP”)
discussed in the Company’s response to Request No. 137.
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 13
REQUEST FOR PRODUCTION NO. 140: Page 12 of Jessica Brady's Direct
Testimony states that "the Company uses AURORA to model various water conditions
using current loads and current resources. At this time, 37 water conditions have been
evaluated to develop an average or normalized NPSE." Please respond to the following:
a. Please confirm that "current loads" means 2023 normalized load;
b. If not, please define "current loads";
c. Please explain how "current loads" are developed; and
d. "Exhibit No. 30 - Base NPSE.xlsx" shows 37 water years from 1981 through
2017. Please explain why years after 2017 are not used.
RESPONSE TO REQUEST FOR PRODUCTION NO. 140:
a. Yes. “Current loads” means the 2023 normalized hourly load forecast that was
input into the AURORA model.
b. Please see the response to Part A.
c. The Company leverages several different modeling specifications in developing
the 2023 load forecast. Those different model specifications are segmented by
customer classification; residential, commercial/industrial, irrigation, and additional
firm loads (or energy supply agreements) and align to the different characteristics
of those classes. These are offset by estimations for electric vehicle adoption and
on-site generation. For the residential classification, the Company uses a
statistically adjusted end use (“SAE”) modeling technique. For
commercial/industrial and irrigation forecasting models, ordinary least squares
(“OLS”) models are developed. For additional firm load, information is adopted as
per the forecast that the customer provides. The modeling specifications

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 14
conducted by the Company are rooted in historical billing level data to inform or
train the prediction model and calibrated to near term load levels. The aggregation
of these techniques then develops the overall assessment of the most probable
outcome of load assuming normal weather conditions. Additional information on
the load forecasting process is provided in the workpaper of Matthew T. Larkin.
d. The ending year of 2017 is related to the RiverWare planning model that Idaho
Power uses to simulate the hydrogeneration in each year of the hydrology period
of record. The RiverWare model is present-conditioned through water year 2018
(September 30, 2018). This means that the model is representative of reservoir
operations, irrigation patterns, and groundwater conditions at the end of the 2018
water year (2017 calendar year), such that simulated hydrogeneration in a
historical year of the period of record is still representative of how the system as it
is operated today would respond to a given hydrologic condition. Since it is a
significant effort to present-condition planning models, this type of update is
conducted infrequently. The U.S. Bureau of Reclamation, which originally
developed the RiverWare model that Idaho Power adapted for the Integrated
Resource Plan modeling, only present-conditions models approximately every 10
years. The end year of 2017 results from this infrequent update period.
The response to parts A and B of this Request is sponsored by Jessi Brady,
Regulatory Analyst, Idaho Power Company. The response to part C of this Request is
sponsored by Jordan Prassinos, Load Forecast Manager and Principal Economist, Idaho
Power Company. The response to part D of this Request is sponsored by Kresta Davis,
Water Resources & Policy Senior Manager, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 15
REQUEST FOR PRODUCTION NO. 141: Page 14 of Jessica Brady's Direct
Testimony states that "Idaho Power updated expected generation from PURPA projects
based on current and expected contracts." Please respond to the following:
a. Please explain what "current" means;
b. Are all "current" PURPA projects approved and operational?;
c. Please explain what "expected" means;
d. Are there any "expected" projects that have been approved?; and
e. If yes, what are their expected online dates?
RESPONSE TO REQUEST FOR PRODUCTION NO. 141:
A. “Current” means PURPA projects currently online and generating energy.
B. Yes. All “current” PURPA projects are approved and operational.
C. “Expected” projects are any PURPA projects not yet online but are expected to
come online during the 2023 test year.
D. Yes. Coleman Hydro, which has been approved, is not yet online but is
expected to come online during the 2023 test year.
E. Coleman Hydro is currently working towards an operational date. Idaho Power
expects that they will be online in Fall 2023.
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 16
REQUEST FOR PRODUCTION NO. 142: Regarding the Jim Bridger Power Plant,
Page 27 of Matt Larkin's Direct Testimony states that "the Company will cease coal-fired
operations at units 1 and 2 at year-end 2023, converting these units to natural gas, with
an expected online date of summer 2024." Additionally, Page 15 of Jessica Brady's Direct
Testimony states that "I was directed to model Bridger units 1 and 2 as natural gas units
online for the entire 2023 test year in order to more closely align 2023 Base Level NPSE
with the time period in which rates will take effect."
Please respond to the following:
a. Please explain whether the Company will seek Commission approval to convert
Bridger units 1 and 2 to gas units;
b. If so, please explain when the Company plans to seek approval;
c. Please explain how long the conversion process of the plant will likely take; and
d. Please provide evidence (such as documentations including signed contracts,
invoices for equipment, etc.) to show Bridger units 1 and 2 will be converted to a
gas plant at year-end 2023.
RESPONSE TO REQUEST FOR PRODUCTION NO. 142:
a. The conversion of Bridger units 1 and 2 was a component of Idaho Power’s 2021
– 2027 Action Plan contained within its 2021 Integrated Resource Plan, which was
acknowledged by the Idaho Public Utilities Commission (“Commission”) with Order
No. 35603 issued in Case No. IPC-E-21-43. Idaho Power does not intend to seek
further Commission acknowledgement or approval prior to the conversion of these
units. However, the Company will seek a prudence determination from the
Commission when requesting cost recovery once the converted units are placed

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 17
in service.
b. Please see the Company’s Response to part A above.
c. The natural gas conversion of Bridger Units 1 and 2 will occur following cessation
of coal-fired operations on December 31, 2023, consistent with the Regional Haze
Consent Decree with the United States Environmental Protection Agency.
Subsequently, both units will be converted to natural gas, with a target
dispatchable online date for Unit 2 on March 22, 2024, and Unit 1 on April 30,
2024.
d. For evidence to support the natural gas conversion of Bridger Units 1 and 2, please
see Confidential Attachment 1 – Response to Staff Request No. 142 and
Confidential Attachment 2 – Response to Staff Request No. 142 for the general
services contract for the replacement of the existing coal burner equipment to the
gas-fired burner system and the change order associated with the contract,
respectively. In addition, Attachment 3 – Response to Staff Request No. 142
includes the Old Dominion Bill of Lading for the shipment of pressure regulators,
pressure reducing valves and pressure relief valves required for the natural gas
conversion, received on June 29, 2023. Further, Confidential Attachment 4 –
Response to Staff Request No. 142 includes the Purchase Order associated with
the delivery and installation of piles to support the natural gas pipeline structure
from inside the plant fence line to the high-pressure skid. In addition, Attachments
5 through 15 – Response to Staff Request No. 142 are pictures of the progress
made on the pipeline structures and piles as well as excavation for the heater skid.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 18
The response to parts a and b of this Request are sponsored by Matthew Larkin,
Revenue Requirement Senior Manager, Idaho Power Company. The response to parts c
and d of this Request are sponsored by John Carstensen, Joint Projects Leader, Idaho
Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 19
REQUEST FOR PRODUCTION NO. 143: Page 14 of Jessica Brady's Direct
Testimony states "the 2023 AURORA model includes the removal of two resources,
Boardman Coal and North Valmy Unit 1." Please respond to the following:
a. Has North Valmy Unit 1 retired?
b. If not, why does the Company exclude it in the AURORA model?
c. When is the plant expected to retire? Please provide evidence to support your
answer.
RESPONSE TO REQUEST FOR PRODUCTION NO. 143:
a. Idaho Power exited participation in coal-fired operations of North Valmy Unit 1 on
December 31, 2019, and therefore no longer receives any generation from the unit.
b. See part (a). Absent participation in coal-fired operations of North Valmy Unit 1,
there is no available generation to model in AURORA.
c. Pursuant to the North Valmy Project Framework Agreement between NV Energy
and Idaho Power dated as of February 22, 2019, approved by the Commission
with Order No. 34349 in Case No. IPC-E-19-08, cessation of coal-fired operations
at Valmy is anticipated to occur for both parties by December 31, 2025.
The response to this Request is sponsored by Lindsay Barretto, 500-kV and Joint
Projects Senior Manager, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 20
REQUEST FOR PRODUCTION NO. 144: Page 15 of Jessica Brady's Direct
Testimony states that Black Mesa Solar is scheduled to come online June 2023. Please
verify the date that the project came or will come online.
RESPONSE TO REQUEST FOR PRODUCTION NO. 144: The Black Mesa Solar
project was commercially operational on June 1, 2023.
The response to this Request is sponsored by Eric Hackett, Projects and Design
Senior Manager, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 21
REQUEST FOR PRODUCTION NO. 145: Page 16 of Jessica Brady's Direct
Testimony states that the Black Mesa Battery is scheduled to come online September
2023 and the 80 MW Grid Battery is scheduled to come online June 2023. Please respond
to the following:
a. Please verify the date that the 80 MW Grid Battery came or will come online;
b. If there is a delay, please provide reasons;
c. Please verify the date that the Black Mesa Battery came or will come online; and
d. If there is a delay, please provide reasons.
RESPONSE TO REQUEST FOR PRODUCTION NO. 145:
a. The 80 MW Grid Battery began partial charge/discharge cycles on June 30, 2023,
and full capacity charge/discharge cycles on July 15, 2023.
b. The 80 MW Grid Battery came online partially as anticipated in June 2023. The
approximate two-week delay to reach full capacity was related to capacity
performance testing, troubleshooting communication infrastructure protocols, and
replacement of a failed local-service transformer and transformer bushing.
c. The Black Mesa Battery is anticipated to come online on August 21, 2023.
d. The Black Mesa Battery was delayed due to manufacturing and vendor delivery
delays. All equipment has been delivered and final installation, testing, and
commissioning is underway.
The response to this Request is sponsored by Eric Hackett, Projects and Design
Senior Manager, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 22
REQUEST FOR PRODUCTION NO. 146: Please respond the following regarding
Demand Response.
a. Please explain why the dispatched amounts of Demand Response are the same
across all water years;
b. Please explain how the cost of Demand Response ($10,240,003) is determined
and provide workpaper with formula intact;
c. Does the cost correspond to the dispatched amounts listed in Exhibit No. 30 -
Base NPSE.xlsx? Please explain; and
d. Please explain why the cost is not determined in the AURORA model.
RESPONSE TO REQUEST FOR PRODUCTION NO. 146:
a. Similar to Power Purchase Agreements (“PPA”) and Public Utility Regulatory
Policies Act of 1978 (“PURPA”) projects, demand response was modeled as a
“must-run” supply-side resource, with an hourly generation profile based on 2022
actual participation in the Company’s three programs. Therefore, AURORA will not
dispatch it differently across the different hydro scenarios.
b. The Company’s 2021 Integrated Resource Plan (“IRP”) identified 340 megawatts
(“MW”) of demand response capacity needed in the preferred portfolio by 2025.
This was the capacity total Idaho Power used when estimating demand response
costs to be included in net power supply expenses. The full sixty (60) hour costs
of each of the Company’s three demand response programs were calculated using
the current incentive levels approved by the Commission in IPC-E-21-32 as well
as historical program participation proportions between programs and jurisdictions.
Of the full sixty (60) hour costs, only the estimated fixed incentives for the programs

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 23
were included in net power expenses. The estimated variable incentives for the
Company’s Irrigation and Commercial & Industrial demand response programs
were not included. The residential air conditioner cycling program only has a fixed
incentive and does not have a variable incentive. Please see Attachment –
Response to Staff Request No. 146 provided for this response for the $10,240,003
in fixed demand response incentives calculated by program for the Company’s
Idaho jurisdiction.
c. No. The goal of demand response programs is to minimize or delay the need to
build a new supply-side resource. As such, demand response program costs are
evaluated based on the avoided capital cost of capacity, rather than the avoided
cost of energy. Because demand response program costs are not evaluated based
on energy, it would be incorrect to state that the costs discussed in Part B of this
response correspond to the dispatched amounts listed in Exhibit No. 30 – Base
NPSE.
d. Please see the Company’s responses to Parts B and C.
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company, and Zack Thompson, Regulatory Analyst, Idaho Power
Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 24
REQUEST FOR PRODUCTION NO. 147: Page 17 of Jessica Brady's Direct
Testimony states that "the Company segmented PURPA into three categories, "PURPA
Wind", "PURPA Solar", and all "other PURPA." PURPA Wind was modeled by applying
a five-year average (2018 - 2022) hourly actual generation shape to the total nameplate
capacity of combined PURPA wind projects. PURPA Solar was modeled by applying the
2022 actual hourly shape to the total monthly forecasted generation amounts. All other
PURPA resources were modeled on a monthly basis..." Please respond to the following:
a. Please provide workpapers to show how PURPA Wind was modeled;
b. Please provide workpapers to show how PURPA Solar was modeled;
c. Please provide workpapers to show how other PURPA resources were modeled;
d. Please explain why PURPA Wind used a five-year average hourly actual
generation shape, while PURPA Solar used a one-year hourly shape; and
e. Please explain why the wind shape is applied to "nameplate", while the solar
shape is applied to "generation amounts".
RESPONSE TO REQUEST FOR PRODUCTION NO. 147:
a. Please see Attachment 1 to this response. Due to the volume of data in the “5-
Year Avg Data” tab, formulas are only maintained in the top row (highlighted in
yellow).
b. Please see Confidential Attachment 2 to this response.
c. Please see Confidential Attachment 3 to this response.
d. PURPA Solar and Wind shapes were calculated according to the availability of
data. PURPA Solar did not have a full 5-year dataset, and therefore the Company
shaped the forecast solar generation using 2022 actuals.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 25
e. The difference in terminology (“nameplate” vs “generation amounts”) is related to
how the forecasts were input into the model. In this case, the hourly wind shape
was input so that when multiplied by the input nameplate capacity, AURORA would
calculate the desired hourly Megawatts (“MW”). Conversely, PURPA Solar’s
generation profile was input as hourly MW totals. While each modeling technique
results in a different calculation performed, the end result is the same (hourly MW
value).
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 26
REQUEST FOR PRODUCTION NO. 148: Please respond to the following
regarding "Fixed Capacity Charge Gas Transportation ($ x 1000)" in Exhibit No. 30 - Base
NPSE.xlsx.
a. Please define "Fixed Capacity Charge - Gas Transportation ($ x 1000)";
b. Please explain how this item is determined or calculated; and
c. Please provide workpapers used to calculate "Fixed Capacity Charge - Gas
Transportation ($ x 1000)" with formula intact.
RESPONSE TO REQUEST FOR PRODUCTION NO. 148:
a. The fixed capacity charge includes costs of firm natural gas transport capacity on
the Northwest Pipeline and the Mountain West Overthrust Pipeline, and also
include the Jackson Prairie and Spire storage costs.
b. Idaho Power has 55,584 million British Thermal Units (“MMBtu”) of transportation
capacity at the current rate of $.3725/MMBtu/day and 25,000 MMBtu‘s of
transportation capacity at the current rate of $.30/MMBtu/day on Northwest
Pipeline. Idaho Power will have 89,000 MMBtu’s/day of transport capacity on
Mountain West Overthrust Pipeline at the rate of $.05326/MMBtu/day. Jackson
Prairie storage facility costs on average $23.2k/month and Spire Storage will cost
$153.7k/ month.
c. Please see the confidential attachment to this request.
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 27
REQUEST FOR PRODUCTION NO. 149: Please respond to the following
regarding "Surplus Sales" in Exhibit No. 30 - Base NPSE.xlsx.
a. The "Surplus Sales" section includes "Revenue ($ x 1000)" and "Revenue - No
Wheeling ($ x 1000)." Please define them and describe the difference between
the two;
b. Please explain how "Revenue ($ x 1000)" and "Revenue - No Wheeling ($ x
1000)" are modeled differently in the AURORA model; and
c. "Revenue ($ x 1000)" is $24,826.5. "Revenue - No Wheeling ($ x 1000)" is
$19,175.3. Please explain whether the 756,582.5 MWh energy amount
corresponds to the $24,826.5 or $19,175.3 amount.
RESPONSE TO REQUEST FOR PRODUCTION NO. 149:
a. As discussed in the Company’s response to Request No. 139, wheeling costs are
included in the AURORA zonal price, which is used to determine the market price
on purchases and sales. As a result, the AURORA-calculated market purchase
expense and surplus sales revenue both include expenses and revenues
associated with wheeling. In order to determine the purchase expense and sales
revenue amounts net of wheeling, the Company used an actual 3-year average
wheeling rate to approximate total wheeling expenses and revenues included in
the AURORA output. The approximate wheeling expenses and revenues were
then subtracted from the AURORA-calculated totals. In summary, the “Revenue ($
x 1000)” value includes wheeling revenues, and the “Revenue – No wheeling ($ x
1000)” is the total revenue, excluding approximate wheeling revenues.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 28
b. “Revenue ($ x 1000) is the AURORA-calculated revenue associated with surplus
sales. As discussed in Part A of this response, “Revenue - No Wheeling ($ x 1000)
shows the calculated revenue from surplus sales with approximate wheeling
revenue removed.
c. Please see Parts A and B to this response.
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 29
REQUEST FOR PRODUCTION NO. 150: Page 20 of Jessica Brady's Direct
Testimony states that natural gas prices for the 2023 Base Level NPSE are forecasted to
be $3.36/MMBtu for Henry Hub, $4.28/MMBtu for natural gas delivered to Bridger, and
$4.70/MMBtu for natural gas delivered to Langley, Bennett Mountain, and Danskin.
Please respond to the following:
a. Please explain how $3.36/MMBtu,$4.28/MMBtu, and $4.70/MMBtu are
determined;
b. Please provide workpapers that calculate these numbers with formula intact; and
c. Please provide the 2024 natural gas forwards prices for these items and provide
workpapers that calculate these prices with formula intact.
RESPONSE TO REQUEST FOR PRODUCTION NO. 150:
a. The Henry Hub, Rockies Basis and Sumas Basis prices are sourced from
Intercontinental Exchange Inc. (“ICE”). $3.36 is an annual average of the 2023
monthly ICE Henry Hub prices. The delivered price for Bridger gas at $4.28
includes a yearly average of the Henry Hub plus Rockies Basis prices and
Mountain West Overthrust’s pipeline volumetric and fuel rates. The delivered price
for Langley, Bennett Mountain, and Danskin at $4.70 includes a yearly average of
the Henry Hub plus Sumas Basis monthly prices and Northwest Pipeline’s
volumetric and fuel rates. The Sumas and Rockies Basis monthly prices included
a 3-year average of actual settlement prices (2020-2022) for January and February
and forward market prices for March 2023 through December 2023.
b. Please see the confidential attachment provided in the Company’s response to
Request No. 148.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 30
c. Please see the confidential attachment provided in the Company’s response to
Request No. 148.
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 31
REQUEST FOR PRODUCTION NO. 151: Page 22 of Jessica Brady's Direct
Testimony states that transmission losses on market purchases are incorporated into the
market price. Please respond to the following regarding transmission losses associated
with market purchases.
a. Please explain how transmission losses are valued in the AURORA model.
b. Are transmission losses associated with market sales?
c. If so, should market prices be adjusted higher to incorporate transmission losses,
when the Company sells power?
RESPONSE TO REQUEST FOR PRODUCTION NO. 151:
a. Transmission losses in AURORA are calculated on every market transaction
dispatched in the simulation. They are calculated based on the loss factors applied
to each line in the model. For example, Zone A is purchasing 100 MW from Zone
B for $50. In order for the energy to travel to Zone A, it uses a single transmission
line, which has a loss factor of 0.01 and a wheeling rate of $3. Ultimately, Zone B
will generate 101 MW in order to account for the 0.01 loss factor. In addition, Zone
A will pay the marginal resource price ($50) plus the wheeling rate ($3), which is
then grossed up according to the loss factor of 0.01. This equates to an
approximate price of $53.53. The purchase expense for Zone A would be $5,353
(100 MW x $53.53). The surplus sales revenue for Zone B would be $5,407 (101
MW x 53.53).
b. Yes. As discussed in Part A of this response, the market price is grossed up to
account for losses according to the loss factor. In addition, the seller will generate
the additional MWh to account for total losses associated with the transaction.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 32
c. Please see the responses to Part A and B.
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 33
REQUEST FOR PRODUCTION NO. 152: Please respond to the following
regarding Third-Party Transmission Expense in the workpaper "Brady Workpaper 4 - 565,
447.050.xlsx". Are transmission expenses only incurred for market purchases, but not for
market sales?
RESPONSE TO REQUEST FOR PRODUCTION NO. 152: Please see the
Company’s responses to Request Nos. 139 and 149. Wheeling costs are included in the
AURORA zonal price, which is used to determine the market price on purchases and
sales. Accordingly, the AURORA-calculated market purchase expense and surplus sales
revenue both include expenses and revenues associated with wheeling. As a result, the
Company used an actual 3-year average wheeling rate to approximate total wheeling
expenses and revenues and remove them from the respective purchase expenses and
surplus sales revenue totals.
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 34
REQUEST FOR PRODUCTION NO. 153: Page 24 of Jessica Brady's Direct
Testimony states that Demand Response was forecast for the 2023 test year based on
Idaho-jurisdiction forecast costs associated with projected participation in the three
programs. Please respond to the following:
a. Is $10,240,003 an Idaho-jurisdiction forecast?
b. Are all other expenses in Table 5 on Page 24 of Jessica Brady's Direct Testimony
Idaho-jurisdiction expenses or system-based expenses?
RESPONSE TO REQUEST FOR PRODUCTION NO. 153:
a. Yes. Please see Attachment – Response to Staff Request No. 146 showing the
calculation of the $10,240,003 in fixed demand response incentives for the
Company’s Idaho jurisdiction.
b. All other expenses in Table 5 of Jessica Brady’s Direct Testimony are system-
based expenses.
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 35
REQUEST FOR PRODUCTION NO. 154: Referencing Exhibit No. 34 -
Development of System Revenue Requirement 2023 Test Year.xlsx, please define each
of the following and explain how each item is determined in terms of NPSE.
a. "2022 Actual";
b. "2022 Actual Adjustments";
c. "2022 Base";
d. "Forecast Adjustment";
e. "2023 Unadjusted Test Year";
f. "Annualizing Adjustment"; and
g. "2023 Test Year".
RESPONSE TO REQUEST FOR PRODUCTION NO. 154:
a. 2022 Actual is actual NPSE that occurred in 2022.
b. 2022 Actual Adjustments is the difference between the 2022 Base and 2022 Actual
values.
c. 2022 Base is the current system level base NPSE, approved in 2013.
d. Forecast Adjustment is the difference between the 2023 Unadjusted Test Year and
the 2022 Base values.
e. 2023 Unadjusted Test Year is the proposed system level base NPSE, as
presented in Ms. Brady’s testimony and exhibits.
f. Annualizing Adjustment is not applicable to NPSE accounts.
g. 2023 Test Year is the same values as the 2023 Unadjusted Test Year because
there are no Annualizing Adjustments to NPSE accounts.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 36
The response to this Request is sponsored by Kelley Noe, Regulatory Consultant,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 37
DATED at Boise, Idaho, this 11th day of August 2023.

LISA D. NORDSTROM
Attorney for Idaho Power Company

DONOVAN E. WALKER
Attorney for Idaho Power Company

MEGAN GOICOECHEA ALLEN
Attorney for Idaho Power Company

IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 38
CERTIFICATE OF SERVICE

I HEREBY CERTIFY that on the 11th day of August 2023, I served a true and
correct copy of Idaho Power Company’s Response to the Sixth Production Request of
the Commission Staff to Idaho Power Company upon the following named parties by the
method indicated below, and addressed to the following:

Commission Staff
Dayn Hardie
Chris Burdin
Deputy Attorney General
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg No. 8
Suite 201-A (83714)
PO Box 83720
Boise, ID 83720-0074

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Clean Energy Opportunities for Idaho
Kelsey Jae
Law for Conscious Leadership
920 N. Clover Dr.
Boise, ID 83703
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Courtney White
Mike Heckler
Clean Energy Opportunities for Idaho
3778 Plantation River Drive, Suite 102
Boise, ID 83703

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Industrial Customers of Idaho Power
Peter J. Richardson
Richardson Adams, PLLC
515 N. 27th Street
Boise, Idaho 83702

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IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 39
Dr. Don Reading
280 Silverwood Way
Eagle, Idaho 83616

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Idaho Irrigation Pumpers Association,
Inc.
Eric L. Olsen
ECHO HAWK & OLSEN, PLLC
505 Pershing Avenue, Suite 100
P.O. Box 6119
Pocatello, Idaho 83205

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Lance Kaufman, Ph.D.
2623 NW Bluebell Place
Corvallis, OR 97330
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Micron Technology, Inc.
Austin Rueschhoff
Thorvald A. Nelson
Austin W. Jensen
Holland & Hart, LLP
555 Seventeenth Street, Suite 3200
Denver, Colorado 80202

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Jim Swier
Micron Technology, Inc.
8000 South Federal Way
Boise, Idaho 83707
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IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 40
City of Boise
Ed Jewell
Darrell Early
Boise City Attorney’s Office
150 N. Capitol Blvd.
Boise, ID 83701
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Wil Gehl
Boise City Dept. of Public Works
150 N. Capitol Blvd.
P.O. Box 500
Boise, Idaho 83701-0500

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Idaho Conservation League
Marie Callaway Kellner
Idaho Conservation League
710 N. 6th Street
Boise, Idaho 83702

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Brad Heusinkveld
Idaho Conservation League
710 N. 6th Street
Boise, Idaho 83702
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IdaHydro
C. Tom Arkoosh
Arkoosh Law Offices
913 W. River Street, Suite 450
P.O. Box 2900
Boise, Idaho 83701

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IDAHO POWER COMPANY’S RESPONSE TO THE SIXTH PRODUCTION REQUEST OF THE
COMMISSION STAFF - 41
Federal Executive Agencies
Peter Meier
Paige Anderson
Tanner Crowther
U.S. Department of Energy
1000 Independence Ave., S.W.
Washington, DC 20585

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Dwight Etheridge
Exeter Associates
5565 Sterrett Place, Suite 310
Columbia, MD 21044
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NW Energy Coalition
F. Diego Rivas
1101 8th Ave
Helena, MT 59601
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Stacy Gust, Regulatory Administrative
Assistant