20230808IPC to Staff 15-36.pdf

MEGAN GOICOECHEA ALLEN
Corporate Counsel
[e-mail]

August 8, 2023

Jan Noriyuki, Secretary
Idaho Public Utilities Commission
11331 W. Chinden Boulevard
Building 8, Suite 201-A
Boise, Idaho 83714

Re: Case No. IPC-E-23-14
Application for Authority to Implement Changes to the Compensation
Structure Applicable to Customer On-Site Generation Under Schedules 6, 8,
and 84 and to Establish an Export Credit Rate Methodology

Dear Ms. Noriyuki:

Attached for electronic filing is Idaho Power Company’s Response to the Third
Production Request of the Commission Staff to Idaho Power Company in the above-
entitled matter.

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

Sincerely,

Megan Goicoechea Allen

MGA:sg
Enclosures
RECEIVED
2023 AUGUST 8, 2023 4:28PM
IDAHO PUBLIC
UTILITIES COMMISSION

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 1
MEGAN GOICOECHEA ALLEN (ISB No. 7623)
LISA D. NORDSTROM (ISB No. 5733)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]

Attorneys for Idaho Power Company

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF IDAHO POWER
COMPANY’S APPLICATION FOR
AUTHORITY TO IMPLEMENT CHANGES
TO THE COMPENSATION STRUCTURE
APPLICABLE TO CUSTOMER ON-SITE
GENERATION UNDER SCHEDULES 6,
8, AND 84 AND TO ESTABLISH AN
EXPORT CREDIT RATE
METHODOLOGY

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CASE NO. IPC-E-23-14

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

COMES NOW, Idaho Power Company (“Idaho Power” or “Company”), and in
response to the Third Production Request of the Commission Staff (“Commission” or
“Staff”) dated July 18, 2023, herewith submits the following information:

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 2
STAFF REQUEST FOR PRODUCTION NO. 15: The Company's Revised Study
Framework in Case No. IPC-E-21-21 includes 100% and 125% of a customer's demand
for determining the project eligibility cap. Please explain why the Company's proposed
cap is based on 100% of a customer's demand and not 125%.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 15: The Revised
Study Framework was relied on to inform the scope of the information contained within
the Company’s Value of Distributed Energy Resources (“VODER”) Study and the
discussion of considerations related to a 100 or 125 percent project eligibility cap is
contained within Section 9 of the October 2022 VODER Study.
The primary rationale for proposing a 100 percent demand cap in this case is
contained on pages 27 and 28 of Company witness Jared Ellsworth’s testimony, where
he indicated that a demand cap of larger than 100 percent of a customer’s demand could
be implemented, but
not without system upgrades – some of which could be
significant. While the on-site generation customer would be
responsible for the initial cost of that equipment, the ongoing
cost, including maintenance, replacement, property taxes,
and other ancillary costs will become the responsibility of the
Company. These costs are collectively paid for by all
customers. The Company does not routinely install facilities in
excess of customer demand in any other instance and it would
be inappropriate to do so here. Ultimately, the benefit of tying
a system size to customer demand is to ensure Idaho Power
does not have oversized distribution equipment on its system
necessary to serve those customers.

Further, as described more fully on pages 5 through 11 of Company witness Grant
Anderson’s testimony, the proposed cap aligns with the intent of net metering, which is to
allow a customer to offset their energy usage behind the meter, and is responsive to
stakeholder feedback received in preceding cases.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 3
A commercial, industrial or irrigation customer who desires to install an on-site
generation system larger than 100 percent of their demand has the option to do so by
either selling their renewable energy to Idaho Power as a Qualifying Facility under
Schedule 86 or configuring their system to be non-exporting.
The response to this Request is sponsored by Grant Anderson, Regulatory
Consultant, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 4
STAFF REQUEST FOR PRODUCTION NO. 16: Please explain why the proposed
project eligibility cap should apply to all Schedule 84 customers, instead of only irrigation
customers under Schedule 84. Please provide evidence to support your answer.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 16: Pursuant to
Schedule 84, the current 100 kilowatt (“kW”) project eligibility cap for on-site generation
systems applies to all large general service, industrial and irrigation customers.
Recognizing that nearly 8 percent of non-solar large general service and industrial
customers registered an annual peak demand of over 100 kW, as can be seen within the
below figure, the Company proposed that modification to Schedule 84’s project eligibility
cap be applicable to all customer classes subject to the existing project eligibility cap. To
date, the Company has not identified a reason to support the need for irrigation customers
to have a project eligibility cap different than that of large general service and industrial
customers.
Non-solar large general service and industrial customer service point histogram,
based on usage data from July 2022 through June 2023.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 5
The response to this Request is sponsored by Grant Anderson, Regulatory
Consultant, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 6
STAFF REQUEST FOR PRODUCTION NO. 17: Please explain why the Company
does not propose any change to the project eligibility cap for Schedule 6 and Schedule 8
customers. Also, please explain why these reasons do not apply to commercial and
industrial customers under Schedule 84.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 17: Relative to
the existing 25 kW project eligibility cap, the most commonly installed on-site generation
system for residential or small general service customers is nearly 7.5 kW in size, and
only about 2 percent of non-solar customers in these classes registered an annual peak
demand in excess of the existing cap. As such, the Company believes the existing 25 kW
project eligibility cap to not be limiting for nearly all residential and small commercial
customers desiring to offset their electric needs behind the meter and therefore remains
a reasonable threshold for administering interconnection for service under Schedules 6
and 8.
As explained in the Response to Request No. 16, Idaho Power evaluated the
Schedule 84 project eligibility cap in the context of all customer classes subject to the
existing 100 kW project eligibility cap.
The response to this Request is sponsored by Grant Anderson, Regulatory
Consultant, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 7
STAFF REQUEST FOR PRODUCTION NO. 18: The Application states "[ijn
evaluating the appropriateness of the existing cap under Schedule 84 for the purpose of
making its implementation recommendations in this case, the Company considered
whether the cap is undermining the intent of net metering to allow customers to offset
energy usage behind the meter." Also, Page 5 of Grant Anderson's Direct Testimony
states that "[t]he intent of net metering is to offset one's energy usage behind the meter."
Please respond to the following.
a. If the intent of net metering is to offset energy usage behind the meter, please
explain why the proposed project eligibility cap is the greater of 100 kW and
100% demand, instead of 100% demand alone;
b. When 100 kW is greater than 100% demand, does it undermine the intent of net
metering by allowing customers to sell extra energy to the Company, instead of
focusing on offsetting energy usage behind the meter?; and
c. Page 119 of the Value of Distributed Energy Resources ("VODER") study stated
that Schedule 84 customers who elect to interconnect a Non-Exporting system
are not limited to the project eligibility cap. If a customer can achieve offsetting
energy usage through installing a Non-Exporting system that is not subject to the
cap, please explain why the Company needs to set a cap for exporting systems
at a level that is potentially higher than 100% of demand,
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 18:
a. The Commission previously determined a project eligibility cap of 100 kW for all
Schedule 84 customers was reasonable and, as such, the 100 kW project eligibility
cap has been in place since approximately 2002 (Case No. IPC-E-02-04). The

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 8
Company’s proposal in this matter to use the greater of 100 kW or 100 percent of
a customer’s demand for the project eligibility cap leaves the existing project
eligibility cap as a “floor” and provides an upper limit based on a customer’s actual
demand, to which Schedule 84’s existing project eligibility cap is agnostic.
The Company considered implementing a project eligibility cap that was
equal to 100 percent of demand for all Schedule 84 customers, but ultimately
determined that the administrative burden the Company may experience through
the implementation of a purely demand-based project eligibility cap for smaller
sized projects, for which applications tend to be more voluminous, may prove to
be challenging.
b. As noted in the response to part (a), the Commission has previously found the 100
kW cap to be reasonable. The Company believes that its concurrent proposal to
update the measurement interval and export credit rate will appropriately mitigate
any economic incentive for customers to oversize their net metering systems.
c. As explained within Response to Request No. 16, the Company does not routinely
install facilities in excess of customer demand given that the ongoing costs of these
installations are collectively paid for by all customers. In the event a customer
installs a non-exporting system sized in excess of their demand beyond the
Company’s point of delivery, the customer bears full responsibility for all costs
associated with installing, maintaining and ensuring that their system does not
export power onto the Company’s system. As such, neither the Company nor its
customers incur any additional ongoing costs associated with oversized non-
exporting systems.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 9
The response to this Request is sponsored by Grant Anderson, Regulatory
Consultant, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 10
STAFF REQUEST FOR PRODUCTION NO. 19: The Application states that "[f]or
irrigation customers without a full in-season billing history, a conversion factor related to
the horsepower of their pump(s) at the service point would determine the maximum
demand." Please provide an example to illustrate the process of determining the
maximum demand in this scenario.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 19: For irrigation
service locations without an in-season billing history (such as in the case of new irrigation
service locations), the Company will apply a conversion factor of 0.8 to the total nameplate
horsepower (“HP”) of the motor(s) at the service location to determine the anticipated
maximum kW demand.
kW Cap = HP x 0.8
This factor takes into account the conversion from HP to kW (1 HP = 0.748 kW),
which is a standard imperial to metric conversion, and then applies an estimated motor
efficiency of 93 percent, which represents the average efficiency of motors greater than
100 kW in size. Of note, motors used for irrigation operations that are greater than 100
kW in size are typically between 90 percent and 95 percent efficient. As such, an
estimated efficiency of 93 percent is a mid-point approximation of these motors’ typical
efficiency range.
0.748 𝑘𝑊
1 𝐻𝑃 𝑥 0.93 0.8

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 11
For example, a customer installing a net-metering generation system on a new
irrigation service with a 200 HP motor would be limited to a net metering generation
system size of 160 kW, which the Company anticipates is the expected demand of that
system.
200 HP x 0.8 = 160 kW
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 THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 12
STAFF REQUEST FOR PRODUCTION NO. 20: Please provide updates to
VODER study Figure 9.1 and Figure 9.3 using the most recent twelve months of non-
solar service point data. In your answer, please provide the percentage of non-solar
service points in each customer category that exceeds the eligibility cap.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 20: Please see
below for updated VODER study Figures 9.1 and 9.3, both of which utilize customer
usage data from July 2022 through June 2023.
Within the non-solar residential customer class, approximately 2 percent of
customers would exceed the project eligibility cap of 25 kW if they installed 100 percent
of their annual peak demand.
Updated Figure 9.1
Non-solar residential customer service point histogram

Within the non-solar irrigation customer class, approximately 13 percent of
customers would exceed the project eligibility cap of 100 kW if they installed 100 percent
of their annual peak demand.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 13
Updated Figure 9.3
Non-solar irrigation customer service point histogram

The response to this Request is sponsored by Jordan Prassinos, Load Forecast
Manager and Principal Economist, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 14
STAFF REQUEST FOR PRODUCTION NO. 21: Please update Table 9.1 in the
VODER study using the most current data.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 21: Please see
the below table, which is an updated version of the October 2022 VODER Study Table
9.1 using data through June 2023.
Updated Table 9.1
Active and pending exporting systems count, total capacity (MW), and average system
size (kW), as of June 2023
Customer Type  Count 
Total Capacity  
(MW) 
Average  
Size (kW) 
Project  
Cap (kW) 
Avg. Size as  
% of Cap 
Residential  16,498 125.73 7.62 25 30%
Small General  77 0.62 8.07 25 32%
Commercial & Industrial  249 8.99 36.12 100 36%
Irrigation  274 25.09 91.56 100 92%
Total 17,098 160.44 9.38 ‐ 34.4%
Note: Original table 9.1’s Total Average Size as % of Cap was rounded up to 35% from 34.6%.  
           Numbers may not add up due to rounding. 

The response to this Request is sponsored by Jordan Prassinos, Load Forecast
Manager and Principal Economist, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 15
STAFF REQUEST FOR PRODUCTION NO. 22: Page 126 of the VODER study
states that "increasing the cap to a customer's demand could negatively impact the
switching process during seasons or certain times with low customer load." Please
explain how the Company plans to address this issue and how the Company plans to
implement the solution.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 22: The
Company will continue to evaluate large Distributed Energy Resource (“DER”) projects in
accordance with Section 2 of Schedule 68 of the Company’s tariff in order to determine
whether any operational requirements and/or system reliability impacts exist. Factors that
are evaluated as part of this study may include but are not limited to: (1) the relationship
of the project to switching devices; (2) the size of the DER; (3) the load characteristics of
the distribution line; (4) the specific distribution line segment where the project
interconnects; and (5) other DERs on the distribution line. For a DER project that is
determined to impact system operations, the solution may include curtailment of the
resource during switching times and the DER being permitted to return to full output only
after Idaho Power's system is returned to its normal configuration.
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 THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 16
STAFF REQUEST FOR PRODUCTION NO. 23: Please list all the potential
reliability issues associated with an increased eligibility cap which were identified in the
VODER study and explain whether the Company's proposal in this case has addressed
all these issues.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 23: The potential
reliability issues identified in the VODER study are: 
 Distribution voltage and line equipment impacts
 Voltage flicker from generation output variability
 Deadline reclosing
 Ground fault current contribution limits
 Other system upgrades
 Switching impacts
These issues will be resolved through a more detailed study process that will identify
any system upgrades required to accommodate each DER. Additionally, to ensure proper
configuration of a DER, Schedule 68 has been revised to include the following (proposed
revisions are in bold):
Schedule 68, Section 1 (Inverter Settings)
Inverter setting documentation will be required for all DERs with a Total
Nameplate Capacity of 100 kilovolt-ampere (“kVA”) or greater.
Schedule 68, Section 2 (Application Process)
The Company on-site inspection may include the following:
a. Verification that actual installed components correspond to the information
provided on the initial application and the System Verification Form.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 17
b. Verification that the disconnect is functional and reconnection time complies with
IEEE 1547.
c. Verification of the proximity and visibility of the disconnect or a sign indicating the
location of the disconnect.
d. Photographic documentation of the installation.
e. Posting of appropriate Company signage.
f. Documentation of the meter number and system configuration.
g. Verification of Smart Inverters, including the settings for all inverter-based
DERs 100 kVA and greater.
h. Verification of Total Nameplate Capacity.
i. Verification of plant controller for all DERs 500 kVA and greater.
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 THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 18
STAFF REQUEST FOR PRODUCTION NO. 24: Please explain if gaming
opportunities exist between the choice of being an on-site customer with a nameplate
above 100 kW and the choice of being a Public Utility Regulatory Policies Act of 1978
("PURPA") solar qualifying facility with a nameplate above 100 kW. If so, how does the
Company plan to prevent gaming?
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 24: While a
potential gaming opportunity may exist if the Export Credit Rate (“ECR”) is non-cost based
(i.e., it is set above the avoided cost of the energy), the Company believes that
implementing an ECR based on avoided costs will minimize opportunities for gaming that
might otherwise exist. Moreover, due to PURPA facilities’ interconnection and contract
requirements, and the differing types of interconnection studies required, it is not
expected that a customer would routinely switch from being a PURPA Qualifying Facility
to becoming an on-site generation customer, or vice versa.
The response to this Request is sponsored by Grant Anderson, Regulatory
Consultant, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 19
STAFF REQUEST FOR PRODUCTION NO. 25: The proposed changes to
Schedule 6, Schedule 8, and Schedule 84 include a statement that "[t]he capacity of an
Energy Storage Device shall not be used to calculate the capacity limits in this schedule."
Please respond to the following:
a. Please explain why this statement is added and what potential problem this
statement is intended to address;
b. Please explain why an Energy Storage Device shall not be used to calculate the
capacity limits; and
c. Please provide an example where an Energy Storage Device is used to calculate
the capacity and explain how the Energy Storage Device changes the capacity.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 25:
a. Under the current provisions of Schedules 6, 8, and 84, Idaho Power must deny
the interconnection application of customers seeking to add energy storage
devices that, when combined with the capacity of their on-site generation system,
exceeds the respective project eligibility cap. By applying the project eligibility cap
based on the aggregate capacity rating of an on-site generation system and AC-
coupled energy storage device(s), customers’ ability to add energy storage to new
and existing systems is occasionally limited.
b. The Company proposes to modify how it administers the project eligibility cap
under Schedules 6, 8, and 84 so that the capacity of an energy storage device is
only considered as part of the Company’s feasibility review and not as part of a
customer’s project eligibility cap. As a result of this proposed modification,
customers will be afforded the opportunity to install on-site generation systems up

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 20
to their respective project eligibility caps, while preserving their ability to also add
energy storage devices, and the Company’s feasibility review will continue to
ensure that interconnection of a project’s overall capacity will not jeopardize the
safety or reliability of Idaho Power’s system.
c. Under the current provisions of Schedules 6, 8 and 84, when an AC-coupled
energy storage device is paired with a customer generation system, the kW
capacity of the energy storage device is added to the AC size of the customer
generation system in order to derive the total system size, which is then compared
against the respective project eligibility cap. As an example of this current practice,
if a customer generation system with a capacity of 22 kW is paired with an AC-
coupled energy storage device with a capacity of 4 kW, the total system size is
calculated as 26 kW, which exceeds the project eligibility cap for Schedules 6 and
8 despite the generation system’s size being below the project eligibility cap.
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 THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 21
STAFF REQUEST FOR PRODUCTION NO. 26: Page 12 of Anderson's Direct
Testimony states that "[t]he Company is aware of limited circumstances where AC-
coupled energy storage devices have resulted in a customer's proposed system to
exceed the project eligibility cap." Please respond to the following.
a. Please provide the "limited circumstances" where AC-coupled energy storage
devices have resulted in a customer's proposed system exceeding the project
eligibility cap; and
b. Energy storage devices typically shift the time of energy output. Please explain
why and how energy storage devices can change a proposed system's nameplate
capacity.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 26:
a. In the context mentioned, the “limited circumstances” refers to the frequency in
which customers have attempted to install an on-site generation system with an
energy storage device that, when such capacities are aggregated, exceeded the
respective project eligibility cap. Although this has been a rare occurrence to date,
the Company anticipates that the frequency of these situations may increase as
more customers use energy storage devices.
b. The nameplate capacity of a system can be changed if a customer elects to
simultaneously export the capacity of their energy storage device and on-site
generation system. Using the example provided in Response to Request No. 25c,
if only the generation system were exporting then the capacity being delivered to
the Company’s system would be 22 kW. However, if the generation system and
AC-coupled energy storage device were exporting simultaneously, then the

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 22
capacity being delivered to the Company’s system would be 26 kW, thereby
changing the exporting system’s nameplate capacity. To account for these types
of situations, the Company’s feasibility review will continue to evaluate the
aggregate capacity of a generation system and energy storage device(s), as
described in Response to Request No. 25b.
The response to this Request is sponsored by Grant Anderson, Regulatory
Consultant, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 23
STAFF REQUEST FOR PRODUCTION NO. 27: As required in Order No. 32925,
to be able to transfer credits between meters under the existing Schedule 6, 8, and 84,
the meter has to be "located on, or contiguous to, the property on which the Designated
Meter is located" and "served by the same primary feeder as the Designated Meter."
Please explain why these requirements are removed for non-legacy customers under the
proposed Schedule 6, 8, and 84.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 27: A financial
credit that is based on avoided costs does not carry the same rationale mentioned by the
Commission in Order No. 32925, which in-part focused on net metering customers
potentially not paying their full fixed costs given the structure of the existing export credit
rate. Because the Company is proposing to implement an export credit rate based on
avoided costs, the Company’s potential under-recovery of fixed costs from on-site
generation customers is partly mitigated. While the Company believes it is important to
continue to require that a customer’s excess generation only be allowed to offset their
own usage, under the Company’s proposal, non-legacy net metering customers will no
longer be subject to the restriction of being able to only transfer excess credits between
contiguous meters served by the same primary distribution feeder.
The response to this Request is sponsored by Grant Anderson, Regulatory
Consultant, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 24
STAFF REQUEST FOR PRODUCTION NO. 28: The proposed Schedule 84
defines Billing Demand as "the average kW supplied during the 15-consecutive-minute
period of maximum use during the Billing Period, adjusted for Power Factor." Please
explain how Power Factor is determined and provide an example of the Power Factor
adjustment.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 28: The concept
of Power Factor (PF) in electrical engineering is used to describe the relationship between
active power (kW) and apparent power (kVA) in an AC circuit. The Power Factor can be
calculated using the cosine of the phase angle between the current and voltage
waveforms. A Power Factor of 1 (or 100 percent) means that all of the power is being
effectively used for work (active power). A Power Factor less than 1 typically indicates a
load is consuming some reactive power.
Active Power (kW): This represents the power that does useful work in an electrical
system. This is represented by the value in column “B” in the example below.
Reactive Power (kVAR): This represents the power that is absorbed or outputted by
inductive or capacitive devices. Typically, a load will absorb reactive power (inductive),
which requires the grid to provide that reactive power through generators or installed
shunt capacitors. While reactive power doesn’t perform any useful work, it is necessary
for voltage and current waveforms to be maintained. This is the value in column “C” in the
example below.
Example: The monthly Billing Demand, represented by the average kW supplied over
the 15-consecutive-minute period of maximum use, along with the associated kVAR and
calculated Power Factor, is utilized to determine the need for a Power Factor adjustment.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 25
The initial step entails determining the Billing Demand for the given billing cycle. Using
the example below, which is a small sample of interval data, a Billing Demand of 66.24
kW with a corresponding Power Factor of .8376 is observed.
If the Power Factor falls below .90, a Power Factor Adjustment may become necessary.
In this example, given that the Power Factor during the Billing Demand is beneath the .90
threshold, an adjustment may be warranted. Below is the formula used to compute this
adjustment. The outcome of a Power Factor Adjustment could result in the Billing Demand
being increased from 66 kW to 71 kW.
(Peak kW * .9) / Power Factor
(66.24 * .9) / .8376 = 71.17 kW

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 THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 26
STAFF REQUEST FOR PRODUCTION NO. 29: Please explain why the proposed
Schedule 6, Schedule 8, and Schedule 84 change the timeframe for submitting requests
to transfer Excess Net Energy credits from "January 1 to January 31 of each year" to
"December 1 and January 31 of each year". Also, please confirm that "December 1 and
January 31 of each year" intends to express December 1 of one year through January 31
of the following year.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 29: The
Company is proposing to change the timeframe for customers to submit Excess Net
Energy Credit transfer requests for two reasons. First, the proposal seeks to provide
customers with additional time to submit their requests. Second, due to the increasing
volume of transfer requests, the Company needs additional time to review and process
all the requests, especially for irrigation services, given one of the eligibility criteria for
transferring credits is that the services must be on contiguous property. As part of transfer
requests for irrigation services, Idaho Power must review parcel maps to identify each
irrigation service point and confirm that the services are on contiguous property.
The intended timeframe of the Company’s proposal is December 1 of one year
through January 31 of the following year.
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 THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 27
STAFF REQUEST FOR PRODUCTION NO. 30: Do Schedule 84 customers
experience revenue requirement deficiencies similar to Schedule 6 and Schedule 8
customers? If yes, please explain how the Company plans to resolve the issue for legacy
customers and non-legacy customers, respectively. If not, please explain why Schedule
84 customers do not experience such issue.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 30: Yes, similar
to Schedules 6 and 8, the Company can experience an under-recovery of fixed costs from
Schedule 84 customers. However, the magnitude of such under-recovery of fixed costs
from Schedule 84 customers is lessened because a larger portion of the class’s fixed
charge amounts are collected through the respective service, demand and, where
applicable, basic load capacity charges. Because of the difference in rate design between
rate schedules, there is less of a reliance on the volumetric energy charge to recover fixed
costs for Schedule 84 customers compared to that of Schedule 6 and 8 customers.
For non-legacy customers, the under-recovery of fixed costs will be partially
mitigated by the Company’s proposal in this case to shorten the measurement interval.
Additionally, the Company’s rate design proposals within its current general rate case,
filed as Case No. IPC-E-23-11, are also intended to help mitigate the extent of fixed costs
being under-recovered from non-legacy and legacy customers, the latter of which will
continue to be partially subsidized through rate design until the expiration of legacy status
in December 2045.
The response to this Request is sponsored by Grant Anderson, Regulatory
Consultant, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 28
STAFF REQUEST FOR PRODUCTION NO. 31: A European study (The Effect of
Net Metering Methods on Prosumer Energy Settlements by Ziras, Calearo, and Marinelli)
has shown that a smart meter monitoring a three-phase system will yield different results
if metering is tracked per phase versus summing the results for all three phases. Please
explain how the Company's smart meters measure and aggregate a typical split-phase
residential system, and a typical three-phase system. Please explain if the aggregation
method is changeable or if it is hardwired into the Company's meters.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 31: For both split-
phase residential and typical three-phase systems, the metering for each phase is
summed within the meter. This is hardwired within the meter and is not changeable.
The response to this Request is sponsored by Lewis McKillop, Meter Systems
Leader, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 29
STAFF REQUEST FOR PRODUCTION NO. 32: In its accounting for avoided line
losses, the Company proposes that customer exports will avoid some line losses but not
others. Specifically, the Company asserts that customer exports cannot avoid all
transformer core losses and all secondary distribution losses. However, it seems
reasonable to assume that customer generated exports travel only to the next home on
the street, which should avoid all line losses. Please explain why the Company believes
that customer exports incur transformer core losses and secondary distribution losses.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 32: Transformer
core losses are a result of the energization of the magnetic field inside the transformer;
this magnetic field is present regardless of the amount of power flowing through the
transformer. This means that transformer core losses cannot be avoided by customers
with on-site generation.
Secondary distribution losses refer to the losses experienced on the system in
between the customer’s meter and the high voltage side of the distribution transformer
serving the customer. Because the secondary system is a radial system, losses will occur
regardless of whether power flows into a customer’s home or from a customer’s home
back to the grid and then to a next-door neighbor’s home. As a result of these factors,
secondary distribution losses cannot be avoided by customers with on-site generation.
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 THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 30
STAFF REQUEST FOR PRODUCTION NO. 33: Company Witness Ellsworth
states, "Starting with the 2023 IRP and each successive IRP, the Company will evaluate
and update the hours of greatest system need that will inform the annual update to the
ECR." Ellsworth at 14. Understanding that the greatest system need is determined by the
Loss of Load Probability ("LOLP"), but that the specific hours of highest LOLP vary
significantly from year to year, what criteria does the Company propose to bracket the
critical hours? Will these criteria account for the rising LOLP in the winter months?
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 33: The
Company currently determines the hours of highest LOLPs by utilizing set thresholds that
are dependent on the selected load and resource year and the corresponding buildout.
First, the hourly LOLPs must be calculated. The Company’s Reliability and Capacity
Assessment Tool (“RCAT”) currently utilizes 6 test years of historical hourly data (which
is adjusted for daylight savings and leap years) to maintain the relationship between
weather, load, and renewable generation. The Company also adjusts historical hourly
load for demand response and to reflect forecasted monthly 70th percentile peak loads.
This approach allows Idaho Power to capture the varying weather conditions that can
occur from year to year while also forecasting the expected value of future years. Once a
load and resource year and the corresponding buildout are selected, the hourly LOLPs
can be calculated for each of the 6 test years.
The hourly LOLPs can then be separated by month for each of the 6 test years.
The Company sorts the hourly LOLPs for each individual month from highest to lowest
risk (descending order) and sets the risk threshold to a current predetermined value of 50
percent. For example, if the sum of all of the LOLPs in the month of July were to equal

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 31
0.07, then the highest risk hours are added together until they equal 0.035. The number
of hours (number of hours equals “X”) it takes to reach the 50 percent threshold can
change by month and by test year. The resulting “X” LOLPs and their corresponding hour
of occurrence represents the 50 percent risk threshold distribution for the highest-risk
hours in a specified month.
The predetermined threshold distribution results for each of the 6 test years are
then combined to show in what hour of the day the overall highest-risk hours are occurring
in a particular month. The percent of occurrences data is directly used to determine the
highest-risk hours. For the 2025 load and resource year, the highest-risk consecutive
hours are determined by taking the percentage of occurrences greater than 15 percent
for the summer months and the percentage of occurrences greater than 10 percent for
the winter months.
This criterion will account for rising LOLP values in any given month (meaning
should a winter month have increasing highest-risk hours, they will be accounted for).
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 THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 32
STAFF REQUEST FOR PRODUCTION NO. 34: Page 9 of Ellsworth's Direct
Testimony states that "[t]he proposed on-peak hours are 3pm to 11pm, June 15 through
September 15, Monday through Saturday, excluding holidays. As described in more detail
in the avoided generation capacity section of my testimony, these hours are those
currently identified as the hours of the Company's greatest system need for energy and
capacity." These on-peak hours correspond to those determined in Case No. IPC-E-21-
32. Since then, the Company has updated on-peak hours at least three times, with peak
data as recent as December 23, 2022: IPC-E-21-35, Case No. IPC-E-22-06, and Case
No. IPC-E-22-26. Please respond to the following:
a. Please explain why the proposed hours are still "currently identified as the hours
of the Company's greatest system need for energy and capacity";
b. Please provide the latest on-peak hours identified by the Company, and the
workpapers used to support these hours; and
c. Please provide the top 100 summer hours, top 100 winter hours, and top 100
annual hours for the Company's system peak, peak net of distributed energy
resources, peak net of all variable energy resources, and highest risk hours for
2020 through 2022.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 34:
a. The on-peak hours determined in Case No. IPC-E-21-32 represent the high-risk
LOLP hours for the 2023 load and resource year, as calculated by the Company’s
RCAT.
 The peak and premium peak hours determined in Case No. IPC-E-21-35
were used to calculate capacity payments for battery storage resources in

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 33
the Incremental Cost Integrated Resource Plan’s (“ICIRP”) avoided cost
model. As described in the Company’s Supplement to Application in Case
No. IPC-E-21-35, the LOLP data evaluated was from the 2019 Integrated
Resource Plan (“IRP”), which should not be compared to the reliability
methodologies implemented in the 2021 IRP and first utilized in Case No.
IPC-E-21-32 to develop the system’s highest-risk hours.
 The 2023 load and resource high LOLP hours identified in Case No. IPC-
E-22-06 were developed to inform the performance metric portion of the
monthly capacity payment calculation. Because the power purchase
agreement entails the operation of a solar photovoltaic generation facility
that can supply output to Idaho Power’s system every day in the calendar
year, high LOLP hours needed to be identified for more than just the
summer period. Please note that while the high LOLP hours determined for
Case No. IPC-E-22-06 serve a different purpose than the high-risk LOLP
hours calculated for Case No. IPC-E-21-32, both recognize 3:00 pm to
11:00 pm as the high LOLP hours for the summer season, signifying that
the system’s highest-risk hours, as determined by the RCAT, did not
undergo nor require an update.
 The peak and premium peak hours determined in Case No. IPC-E-22-26
were used to calculate avoided capacity costs for energy storage qualifying
facilities in the ICIRP model. As described in the Company’s Application as
part of Case No. IPC-E-22-26, the peak and premium hours are identified
by “looking at forecasted load, current year load net of solar, and current

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 34
year [Western Energy Imbalance Market] pricing.” LOLP results from the
2021 IRP were simply utilized to validate the timing of the peak and
premium peak hours, meaning the system’s highest-risk hours as
determined by the RCAT did not undergo nor require an update but were
instead used as a reasonability check.
In the studies conducted since the filing of Case No. IPC-E-21-32, the Company
has not experienced significant load and resource changes for the 2023 calendar
year compared to historical forecasts. In other words, Idaho Power’s
corresponding LOLP profile has not significantly deviated from the previously
identified high-risk LOLP hours. The Company does intend to evaluate the
system’s highest-risk hours for a future calendar year in the upcoming 2023 IRP
filing and will continue this evaluation practice in subsequent IRPs.
b. Please see the attachment provided in response to this request, which details the
2025 load and resource year’s highest-risk hours as calculated by the RCAT for
defining the proposed Time of Use periods.
c. Please see attachment 1 provided in response to this request and note the
scenarios described below:
 System peak
- Load data includes demand reductions associated with the
Company’s Demand Response programs.
 Peak net of distributed energy resources
- The Company used the total output of customers with distributed
generation to obtain the above data, assuming the “distributed

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 35
energy resources” referenced in the question was referring to
customers with on-site generation.
 Peak net of all variable energy resources
- Variable energy resources include wind, solar, run-of-river, and
cogeneration and small power production (including PURPA)
resources.
Please see attachment 2 provided in response to this request, which supports the
data previously provided in Response to Request No. 5.
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 THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 36
STAFF REQUEST FOR PRODUCTION NO. 35: Page 27 of Ellsworth's Direct
Testimony states that "Idaho Power expects to complete its next VER Integration Study,
if necessary, following the completion of the 2025 IRP." Please explain what prevents the
Company from conducting the next VER Integration Study after the completion of the
2023 IRP. Also, please identify what would or would not make the VER Integration Study
necessary.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 35: A Variable
Energy Resource (“VER”) Integration Study may not be necessary after the completion
of the 2023 IRP given the current and forecasted resource mix of Idaho Power’s system,
which has not varied significantly from the previously conducted VER Integration Study.
Idaho Power’s previously conducted VER Integration Study covered integration costs for
solar penetration levels over 1,300 MW and for wind penetration levels up to
approximately 1,400 MW. Idaho Power’s current and forecasted solar and wind
penetration levels have not approached the penetration levels modeled in the previously
conducted VER Integration Study. Idaho Power will assess the need for a new VER
Integration Study as the Company’s system continues to change (resource mix,
transmission, load, etc.).
The response to this Request is sponsored by Jared Hansen, Resource Planning
Leader, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 37
STAFF REQUEST FOR PRODUCTION NO. 36: Please provide the "IPC Loss
Factor.xlsx" excel file imported by the MATLAB script PDF provided in Response to
Production Request No. 4.
RESPONSE TO STAFF’S REQUEST FOR PRODUCTION NO. 36: Please see
the attachment previously provided in Response to Request No. 2. The hourly “’On-Peak’
Loss Factors” are the same as those imported into MATLAB® via the
“IPC_Loss_Factor.xlsx” Excel file.
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 THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 38
DATED at Boise, Idaho, this 8th day of August 2023.

MEGAN GOICOECHEA ALLEN
Attorney for Idaho Power Company

IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 39
CERTIFICATE OF SERVICE

I HEREBY CERTIFY that on the 8th day of August, 2023, I served a true and correct
copy of Idaho Power Company’s Response to the Third Production Request of the
Commission Staff upon the following named parties by the method indicated below, and
addressed to the following:

Commission Staff
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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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 Conservation League
Marie Callaway Kellner
Idaho Conservation League
710 North 6th Street
Boise, Idaho 83702

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Brad Heusinkveld
Idaho Conservation League
710 North 6th Street
Boise, Idaho 83702

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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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IDAHO POWER COMPANY’S RESPONSE TO THE THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 40
Lance Kaufman, Ph.D.
2623 NW Bluebell Place
Corvallis, OR 97330
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Clean Energy Opportunities for Idaho
Kelsey Jae
Law for Conscious Leadership
920 N. Clover Dr.
Boise, Idaho 83703
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Michael Heckler
Courtney White
Clean Energy Opportunities for Idaho
3778 Plantation River Dr., Suite 102
Boise, ID 83703

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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 THIRD PRODUCTION REQUEST OF THE
COMMISSION STAFF - 41
City of Boise
Darrell G. Early
Deputy City Attorney
Boise City Attorney’s Office
150 N. Capitol Blvd.
PO Box 500
Boise, Idaho 83701-0500
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Wil Gehl
Energy Program Manager
Boise City Dept. of Public Works
150 N. Capitol Blvd.
Boise, Idaho 83701-0500

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Vote Solar
Abigail R. Germaine
Elam & Burke, PA
251 E. Front Street, Suite 300
PO Box 1539
Boise, ID 83701
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Kate Bowman
Regulatory Director
Vote Solar
299 S. Main Street, Suite 1300
PMB 93601
Salt Lake City, UT 84111
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Stacy Gust, Regulatory Administrative
Assistant

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-23-14
IDAHO POWER COMPANY
ATTACHMENT
REQUEST NO. 34b
SEE ATTACHED SPREADSHEET
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-23-14
IDAHO POWER COMPANY
ATTACHMENT 1
REQUEST NO. 34c
SEE ATTACHED SPREADSHEET
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-23-14
IDAHO POWER COMPANY
ATTACHMENT 2
REQUEST NO. 34c
SEE ATTACHED SPREADSHEET