20231116Final Comments.pdf

MEGAN GOICOECHEA ALLEN
Corporate Counsel
[e-mail]
November 16, 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 Final Comments 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 NOVEMBER 16, 2023 4:41PM
IDAHO PUBLIC
UTILITIES COMMISSION

IDAHO POWER COMPANY’S FINAL COMMENTS - 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
)
)
)
)
)
)
)
)

CASE NO. IPC-E-23-14

IDAHO POWER COMPANY’S FINAL
COMMENTS

COMES NOW, Idaho Power Company (“Idaho Power” or “Company”), in
accordance with Rule 203 of the Rules of Procedure of the Idaho Public Utilities
Commission (“Commission”) and the Notice of Modified Procedure, Order No. 35881,
issued August 10, 2023, respectfully submits its Final Comments1 in the above-
referenced case as follows.

1 Idaho Power indicated in its Notice filed November 2, 2023, that it would utilize these Final Comments
to respond to all comments submitted to date.

IDAHO POWER COMPANY’S FINAL COMMENTS - 2
I. INTRODUCTION
The situation and issues confronting the Commission in this docket are not
dissimilar to those that have, are, or will be faced by numerous state regulatory
commissions nationwide. Throughout the country, regulators have been compelled in
recent years to revisit and reform existing net energy metering (“NEM”) rules and
regulations that were established decades ago under vastly different circumstances. Like
Idaho, most states historically employed a relatively straightforward and administratively
simple approach at “netting” and valuing NEM on-site generation and consumption and
were able to overlook program design inefficiencies and resulting implications for other
customers when behind-the-meter systems were few in number. And similar to what has
occurred in Idaho, rapid growth of on-site generation systems and a changing energy
landscape has exacerbated the regulatory and policy concerns prompting many
regulators to reevaluate net energy metering policies to better align with sound regulatory
principles. Though each jurisdiction is unique with its own set of stakeholders, cost
studies, rate designs, average retail rates, and approaches to successor net metering
service offerings, net metering policy generally is in a period of transition across the
nation.2

2 According to the NC Clean Energy Technology Center’s (“NCCETC”) annual review and Q4 2022
update report, nearly every state in the country took some type of distributed solar policy action during
2022,“ a trend which has continued over the past several years and is likely to continue through 2023 and
beyond.” The top solar distributed policy trends of 2022 identified in the report include states moving
away from traditional net metering; net billing becoming the dominant successor tariff structure; growing
use of time-varying compensation rates for distributed generation; and distributed generation programs
increasing in complexity, with more granular credit rate structures and intricate program designs being
adopted. Apadula, E., et al. The 50 States of Solar: Q4 2022 & Annual Review Executive Summary at 9-
10, NC Clean Energy Technology Center, Jan. 2023.
Available at: https://nccleantech.ncsu.edu/wp-content/uploads/2023/01/Q4-22-Solar-Exec-Summary-
Final.pdf.

IDAHO POWER COMPANY’S FINAL COMMENTS - 3
In Idaho at least, this transition was inevitable; in considering the practice of retail
rate net metering over twenty years ago, Commission Staff cautioned:
For the Commission to accept a net metering tariff where
customer generation is credited at full retail rates, it must be
willing to accept the fact that Idaho Power may not recover its
full costs of providing service from net metering customers.3 

For its part, the Commission was amenable to this valuation approach in 2001 despite
concerns that some of the costs of serving net metering customers would likely be
subsidized by other customers given the limits on participation and its mandate for future
monitoring and assessment of the new service offering.4 The Company’s net metering
service fulfilled the Commission’s desire to implement a service offering, subject to
modification as experience was gained, and helped support the continuing development
of renewable energy resources and advances in energy generation technology.
Since the 1983 inception5 of Idaho Power’s retail net metering offering, the
Company has been taking incremental steps as it gained experience to lay the foundation
and prepare for updating its on-site generation offering to ensure equity among all
customers moving forward. In the interim, the solar industry in Idaho was able to gain its
footing and is thriving.6 Against the backdrop of these dynamic circumstances, the need
for transparency became paramount, even prompting the involvement of the Idaho

3 In the Matter of the Application of Idaho Power Company for Approval of a New Schedule 84—Net
Metering Tariff, Case No. IPC-E-01-39, Comments of the Commission Staff at 3 (Dec. 21, 2001).
4 Id., Order No. 28951 at 11-12 (Feb. 13, 2002); In the Matter of the Application of Idaho Power Company
for Amendments to Schedule 84—Net Metering, Case No. IPC-E-02-04, Order No. 29094 at 7 (Aug. 21,
2002).
5 Case No. U-1006-200, Order No. 18358 (Oct. 20, 1983).
6 In the last ten years the number of solar installers in Idaho Power’s service territory has increased from
19 known installers to over 65.

IDAHO POWER COMPANY’S FINAL COMMENTS - 4
Legislature, which added a new chapter to Idaho Code in 2019 requiring certain solar
contract disclosures in order to facilitate customers’ access to key information and guard
against misleading or inaccurate sales representations.7 Similarly, Idaho Power has
endeavored to ensure customers were and are fully apprised of the potential changes,
undertaking extensive efforts – including numerous direct mailings – over the years to
communicate with both customer-generators and non-participating customers regarding
the NEM service offering and regulatory proceedings related to potential changes.
Over the last several decades, the Company gained the requisite experience and
laid the foundation necessary for updating its on-site generation offering as proposed in
this case, which would, in conjunction with the changes to be implemented in the
Company’s current general rate case,8 result in offerings that are better aligned with
current circumstances, economically supportable, and fair to all customers.
II. COMPANY REVISED PROPOSAL
Based on the input received by Staff and other Parties9 and the analysis presented
in the following sections of its Final Comments, the Company recommends that the
Commission issue an order to:

7 To date, state-level mandatory solar contract disclosure policies have been adopted in many states
including Arizona, California, Florida, Hawaii, Idaho, Illinois, Maryland, Massachusetts, Minnesota,
Missouri, Nevada, New Jersey, New Mexico, New York, North Carolina, Oregon, South Carolina, Texas,
Utah, and Washington.
8 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 Account Treatment, Case No.
IPC-E-23-11 (filed June 1, 2023).
9 As referenced throughout Parties collectively refer to intervenors in this docket.

IDAHO POWER COMPANY’S FINAL COMMENTS - 5
(1) Implement real-time net billing with an avoided cost-based, seasonal, time-
variant Export Credit Rate (“ECR”), with the following modifications or
clarifications:
(a) Align the ECR Summer season with the base rate summer season
of June 1 through September 30 as proposed in the Company’s
general rate case in Case No. IPC-E-23-11. Direct the Company to
review and update the season in a general rate case filing as
appropriate;
(b) Define the ECR Summer On-Peak hours as 3 p.m. to 11 p.m.,
Monday through Saturday, excluding holidays, during the summer
season, and if future Integrated Resource Plan (“IRP”) analysis
indicates a need to update the hours of highest risk, the Company
should file a separate docket;
(c) Distribute the avoided energy value in alignment with the summer
and non-summer seasons;
(d) Use the most current levelized capacity cost for the least-cost-
dispatchable resource from the 2023 IRP;
(e) Use a five-year rolling average of the Effective Load Carrying
Capability (“ELCC”) to determine the avoided capacity value;
(f) Calculate the rolling average ELCC with the inclusion of line losses
applied to the hourly customer-generator exports to calculate the
avoided capacity value;

IDAHO POWER COMPANY’S FINAL COMMENTS - 6
(g) Include customer-generator exports for all hours in the calendar year
in the calculation of the rolling average ELCC;
(h) Apply the annual energy line losses to the energy value;
(i) Apply the peak hour line losses to the On-Peak hours and apply the
annual energy line losses to all other hours of the capacity value;
(2) Direct the Company to update all proposed components of the ECR except the
season and hours of highest risk in an annual filing beginning April 1, 2025.
(3) Maintain the current Schedule 6 and Schedule 8 eligibility caps.
(4) Modify the eligibility cap for Schedule 84 customers to the greater of 100
kilowatts (“kW”) and 100 percent of demand and direct the Company to include
additional proposed interconnection requirements in Schedule 68 concurrent
with the effective date of real-time net billing.
(5) Approve the Company’s proposal to exclude energy storage and only include
the nameplate capacity of generation to enforce the eligibility cap for Schedules
6, 8, and 84; and direct the Company to meet with Staff and submit its findings
to the Commission within 90 days of an order on the feasibility of implementing
a surcharge to recover ongoing costs of system upgrades.
(6) Approve the Company’s request to recover ECR expenditures as a net power
supply expense subject to 100 percent recovery through the Power Cost
Adjustment (“PCA”).
(7) Approve the Company’s proposals on the use and transferability of financial
credits.

IDAHO POWER COMPANY’S FINAL COMMENTS - 7
(8) Approve the Company’s proposal to convert accumulated kilowatt-hour (“kWh”)
credits to financial credits using a blended average retail energy rate on
December 31, 2024, for non-legacy systems.
(9) Direct the Company to transfer any accumulated financial credits when a
customer relocates within the Company’s service area within six months.
(10) Authorize the integration rates from the 2020 Variable Energy Resource (“VER”)
study as proposed for purposes of the ECR rates in this filing, and:
(a) Direct the Company to file an update to Schedule 87 rates and
integration costs from the 2020 VER study for Commission approval
to be used in future ratemaking that requires it.
(b) Direct the Company to file all future VER studies and integration
costs for Commission authorization if integration costs have
materially changed from those authorized.
(11) Direct the Company to adjust the language of Schedules 6, 8, 68, and 84,
according to all recommendations presented above in a compliance filing.
III. EXPORT CREDIT RATE
The Company appreciates the comprehensive review and comments from the
public and Parties in this matter. The Company has evaluated the Parties’ comments
while considering the primary objectives laid out in its Application:
(1) Develop a compensation structure that will accurately measure a customer-
generator’s use of the system for recording exported and consumed energy.
(2) Apply methods to ensure a fair and accurate valuation of customer exports.
IDAHO POWER COMPANY’S FINAL COMMENTS - 8
(3) Implement a repeatable method for updating the ECR to ensure timely
recognition of changing conditions on Idaho Power’s system and the broader
power markets that may warrant changes to the ECR.
(4) Balance accuracy with customer understandability.
After careful evaluation of each Party position, the Company has considered the
merits of modifications to its proposed ECR that would enhance understandability and
transparency, while ensuring progress towards modernizing the customer on-site
generation offering. A summary of the Company’s revised ECR is included in the below
table compared to its initially filed ECR and Attachment No. 1 is the revised workpaper.

IDAHO POWER COMPANY’S FINAL COMMENTS - 9
Table 1
Company Filed and Revised ECR

The Company’s Final Comments summarize the Parties’ positions for each
element of the Company’s proposal and Idaho Power’s filed and revised position to reflect
where it has modified its proposal. Staff and Vote Solar’s comments included substantive
positions on the various elements of the Company’s filed proposal and, therefore, have
been addressed explicitly in the summary table. Clean Energy Opportunities for Idaho
Season/Time Filed Revised
Export Profile
Volume (kWh per kW) Annual 1,465 1,465
Capacity Contribution (%) Annual 8.76% 10.12%
Export Credit Rate by Component (cents/kWh)
Energy Summer On-Peak 8.59 ¢ 5.65 ¢
Including integration and losses Summer Off-Peak 4.91 ¢ 5.65 ¢
Non-Summer 4.91 ¢ 4.84 ¢
Annual* 5.16 ¢ 5.16 ¢
Generation Capacity Summer On-Peak 11.59 ¢ 10.61 ¢
Summer Off-Peak 0.00 ¢ 0.00 ¢
Annual* 0.79 ¢ 1.01 ¢
Transmission & Distribution Capacity Summer On-Peak 0.25 ¢ 0.18 ¢
Summer Off-Peak 0.00 ¢ 0.00 ¢
Annual* 0.02$ 0.02 ¢
Total Summer On-Peak 20.42 ¢ 16.43 ¢
Summer Off-Peak 4.91 ¢ 5.65 ¢
Non-Summer 4.91 ¢ 4.84 ¢
Annual* 5.96 ¢ 6.18 ¢
*Annual values provided for informational purposes only and reflect seasonal
weighting for 12 months ending December 2022.
Note: The revised Summer season is defined as June 1 - September 30; the filed
Summer season was defined as June 15 - September 15. Revised and filed Summer On-
Peak hours defined as 3pm - 11pm, Monday - Saturday, excluding holidays, and all
other hours defined as Off-Peak.

IDAHO POWER COMPANY’S FINAL COMMENTS - 10
(“CEO”), City of Boise, Idaho Conservation League (“ICL”), and Irrigation Pumpers
Association, Inc.’s (“IIPA”) comments included positions on select elements of the
Company’s proposal and, therefore, have been consolidated under “Other Party
Positions” within the structure of the Company’s Final Comments.
A. Measurement Interval
Summary of Measurement Interval Positions
Party Idaho Power
(Filed) Staff Vote Solar Other Idaho Power
(Revised)
Position Real-Time Real-Time Not Specified City of Boise -
Hourly
Real-Time

The current NEM structure uses a monthly netting interval which allows the
exporting customer to “bank” credits from exports, in the form of a kWh credit, for use
during hours when the customer uses more energy than they generate. This allows a
customer to use any excess kWh credit from exports to offset their monthly billing
consumption when they are not exporting. The Company evaluated a real-time and hourly
measurement interval for net billing and proposed to implement a real-time measurement
where the meter will record real-time net grid electricity consumption and exports
independently and the customer would continue to “bank” credits from exports, in the form
of a financial credit.10

10 Aschenbrenner DI at 26.

IDAHO POWER COMPANY’S FINAL COMMENTS - 11
Staff Position
Staff considered both a real-time and hourly netting interval consistent with Order
No. 35631 and did not consider any interval larger than hourly, citing the lack of accuracy
the measurement provides. Staff noted “that a real-time interval presents many
advantages in terms of accuracy, understandability, and malleability of the ECR.”11
Additionally, by using a real-time measurement interval, exports would be tracked in a
manner consistent with imported power. Staff believes that having consistency between
exports and billing will increase customer understandability and transparency.12 Staff also
recognized that implementing a real-time measurement interval would likely increase bills
for on-site generation customers; however, the impact would be strictly from increasing
the accuracy of measuring exports and would reduce cost-shifting to non-customer
generators. Last, Staff notes that the Company would incur additional costs to implement
an hourly measurement with no additional benefit over implementing a real-time
measurement.13
Vote Solar Position
Vote Solar did not specifically address the measurement interval if the Commission
elects to approve an ECR. However, the avoided energy value calculated in Vote Solar’s
workpaper is weighted relative to the real-time exports in each hour.14 Therefore, it
appears that Vote Solar does not dispute the use of a real-time measurement.

11 Staff Comments at 10 (Oct. 12, 2023).
12 Id. at 11.
13 Id. at 12.
14 Vote Solar Workpapers A 10.12.23 (included as attachment to Vole Solar Comments).

IDAHO POWER COMPANY’S FINAL COMMENTS - 12
Other Party Positions
The City of Boise stated that the Commission should consider consistency in the
measurement interval with the Clean Energy Your Way – Construction service offering
(“CEYW-Construction”), and, therefore, consider implementing an hourly netting period.15
CEO, ICL, and IIPA did not specify a recommendation for the measurement
interval.
Idaho Power Position
The Company recommends that the Commission implement a real-time
measurement interval. The analysis provided in Staff’s comments comprehensively
captures the trade-offs between a real-time and hourly measurement interval.
The City of Boise suggests an hourly measurement interval should be considered
for consistency with CEYW-Construction. While the City of Boise acknowledges that the
program constraints differ, it fails to mention critical differences between that service
offering and on-site customer generation. Most notably, CEYW-Construction customers
continue to pay the fixed cost component of the retail energy rate for all energy offset by
the renewable energy facility. Said differently, a customer participating in CEYW-
Construction can only offset the cost of energy embedded in their volumetric rate, an
amount of around 3 cents per kWh. This same fixed-cost recovery does not occur for
customer on-site generation because customers taking service under Schedules 6, 8, and
84 are permitted to offset all costs included in the volumetric rate. Depending on the
customer class, this bypass results in an under-recovery of between 5 and 12 cents per

15 City of Boise Comments at 6-7 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 13
kWh consumed on-site. A difference in measurement interval is warranted to increase the
accuracy and reduce cost-shifting to non-customer generators.
B. ECR Rate Design
Summary of ECR Rate Design Positions
Party Idaho Power
(Filed) Staff Vote Solar Other Idaho Power
(Revised)
Position Seasonal/Time-
Variant Rate

Jun 15 - Sep 15
-11pm
Seasonal/Time-
Variant Rate

Jun 1 to Sep 30
-11pm
Flat & Optional
Seasonal/Time
Variant
IIPA – Separate
ECR by Class

CEO – Agreed
with Staff
Seasonal/Time-
Variant Rate

Jun 1 - Sep 30
-11pm

The Company’s proposal for the ECR in its Application included a seasonal time-
variant rate structure.16 The specific rate structure results in a higher ECR in the summer
on-peak hours and a lower ECR in all other hours. In its Application, the Company
proposed defining the summer season as June 15 to September 15 and the on-peak
hours as 3 p.m. to 11 p.m., Monday through Saturday.17 The Company determined the
season and hours based on the Loss of Load Expectation (“LOLE”) analysis which
identifies the timing of highest risk.
Staff Position
Staff recommends that the Company align the summer season of the ECR to
match the summer season of June 1 to September 30 presented in the concurrent general
rate case.18 Staff also recommends updating the seasons as part of future general rate
case filings as informed by the most recently filed IRP. As a result, Staff is comfortable
with the Company’s proposed on-peak ECR hours of 3 p.m. to 11 p.m. for the summer

16 Application at 19.
17 Id. at 20.
18 Staff Comments at 16 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 14
season of June 1 to September 30; however, it notes that there should be continued
alignment between the TOU and ECR highest risk hours. Staff recommends that, as IRP
analysis indicates a need to update hours of highest risk, the Company file a separate
docket to update the hours for both the ECR and Time of Use (“TOU”) rates.19
In response to IIPA’s proposal to calculate an ECR by customer class, Staff
recommends the Commission not adopt IIPA’s request.20 Staff believes that multiple
ECR’s would reduce transparency, increase confusion, and could lead to a dissatisfaction
among customers. Additionally, its notes that the intent of Schedules 6, 8, and 84 is to
provide customers the opportunity to offset their energy usage. Staff’s position is that if
irrigation customers want to receive compensation based on their export shape, they can
apply as a Qualifying Facility.21
Vote Solar Position
Vote Solar recommends that the Commission approve a flat annual average ECR
as the default offering and that an optional time-differentiated ECR be available to
customers with on-site generation at their discretion.22 Vote Solar suggests that a flat
annual average ECR as the default offering will allow customers with on-site generation
to adjust to the new construct of an export rate. Vote Solar does not agree with distributing
avoided energy value in alignment with summer and non-summer seasons as proposed

19 Staff Comments at 16 (Oct. 12, 2023).
20 Staff Reply Comments at 4 (Nov. 2, 2023).
21 Id.
22 Vote Solar Comments at 34-36 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 15
by Staff. Vote Solar’s rationale cites that the proposed method will not substantially
improve the economics of exporting power during the period.23
In response to IIPA’s recommendation to calculate an ECR by customer class,
Vote Solar does not agree with this approach and recommends the ECR should not vary
based on the customer that exports energy.24 Vote Solar states that the value of exported
energy does not vary based on the type of customer who generated the power and points
out that load profiles vary even among customers within a class.
Other Party Positions
IIPA recommends that irrigation and non-irrigation should have separately
calculated export credit rates. IIPA notes that a disproportionately large share of irrigation
net energy export occurs in winter and shoulder months, thus suggesting this warrants a
differently calculated export credit rate. 25
CEO supports Staff’s proposal to align the ECR summer season with the proposed
summer season in the Company’s general rate case definition of June 1 to September
30.26 Similarly, CEO supports the Company’s proposal and Staff’s support for defining
Summer on-peak as 3 p.m. to 11 p.m. CEO also supports Staff’s proposal to assign the
energy value by season, and to implement three ECR values: Non-Summer, Summer Off-
Peak, and Summer On-Peak.27

23 Vote Solar Reply Comments at 7 (Nov. 2, 2023).
24 Id. at 6.
25 IIPA Comments at 2 (Oct. 12, 2023).
26 CEO Reply Comments at 3 (Nov. 2, 2023).
27 Id. at 4.

IDAHO POWER COMPANY’S FINAL COMMENTS - 16
ICL and City of Boise did not specify a recommended rate design for the ECR.
However, ICL does recommend rejecting IIPA’s request for a separate ECR for Schedule
6, 8, and 84. ICL states that any energy exported to the grid at a given time should be
equal regardless of the source of the exported energy. 28
Idaho Power Position
The Company recommends the Commission approve Staff’s proposed
modifications to the ECR rate design. It is appropriate to generally align the season and
the hours for the ECR and TOU in place for consumption. Therefore, the Company
recommends that the Commission approve a June 1 to September 30 summer season
for the ECR. The Company maintains that the on-peak ECR hours should be 3 p.m. to 11
p.m., which generally aligns with its proposed mid- and on- peak hours for its TOU
offerings for residential, commercial, and industrial customers as proposed in the
Settlement Stipulation in Case No. IPC-E-23-11. This is aligned with recommendations
from Staff and CEO. The Company is also supportive of Staff’s recommendation to file a
separate docket to update the highest risk hours for both ECR and consumption rates as
indicated by future IRP analysis.
The Company appreciates Vote Solar’s concern for customer understandability,
which led to its recommendation for a flat annual ECR. However, the Company believes
that a seasonal time-variant structure is most accurate and appropriate, and this level of
complexity is not uncommon for the Company’s optional service offerings. The
Commission also recognized the value from “peak hour pricing or another variable pricing
mechanism so on-site generators who invest in storage can realize the value of their

28 ICL Reply Comments at 7-8 (Nov. 2, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 17
investment when they export stored energy.”29 Therefore, the Company recommends the
Commission decline Vote Solar’s recommendation to have a default flat annual ECR and
an optional seasonal, time-variant ECR. However, if the Commission elects to approve a
flat annual ECR, the Company requests to have a singular rate design option for the ECR
for all net billing customer-generators as optionality could lead to an overly complex and
less accurate annual update process, as well as potential gaming from customers
switching between offerings.
The Company is in agreement with other intervenors’ recommending that IIPA’s
proposal to have a separate ECR by customer class be rejected by the Commission. The
intent of an ECR representative of avoided costs should be applicable to exported energy
from customer-generators irrespective of customer class or generation source. The
Company evaluated the feasibility of implementing class-specific ECRs in advance of its
filing, as more fully explained on page 10 of Mr. Ellsworth’s pre-filed testimony, and the
Company ultimately determined a class-specific ECR would not be advisable, for many
of the reasons listed by Staff.
By aligning the rate design for the ECR with the hours of highest risk, it also sends
a price signal to customers with energy storage when dispatching their batteries to the
grid is valued and needed most. At the Customer Hearing on October 24, 2023, several
participants stated that there are barriers preventing them from dispatching battery
storage to the grid. However, such barriers don’t presently exist for customers that have

29 In the Matter of Idaho Power Company’s Application to Initiate a Multi-Phase Collaborative Process for
the Study of Costs, Benefits, and Compensation of Net Excess Energy Associated with Customer On-Site
Generation, Case No. IPC-E-21-21, Order No. 35284 at 16 (Dec. 30, 2021).

IDAHO POWER COMPANY’S FINAL COMMENTS - 18
batteries paired with their generation as an Exporting System; pursuant to Schedule 68,
the Exporting System incorporates both the generation and storage.
C. Avoided Energy
Summary of Avoided Energy Positions
Party Idaho Power
(Filed) Staff Vote Solar Other Idaho Power
(Revised)
Position EIM/ELAP

Trailing 12
Months,
Weighted
On/Of -Peak
EIM/ELAP

Trailing 12
Months,
Weighted by
Season
EIM/ELAP

Trailing 36
Months,
Weighted
On/Off Peak
IIPA – Adjusted
EIM/ELAP

CEO – Agreed
with Staff
EIM/ELAP

Trailing 12
Months,
Weighted by
Season

The Company proposed that the value of avoided energy be determined by the
hourly prices from the Energy Imbalance Market (“EIM”), which is the western region’s
real-time energy market. EIM prices vary by location, so the Company proposed to use
the EIM Load Aggregation Point (“ELAP”) prices independently determined on an hourly
basis by the California Independent System Operator (“CAISO”). The Company proposed
to use the 12 months of market data ending December 31 each year to calculate an
average price weighted for customer-generator exports for on-peak and off-peak avoided
energy values.30
Staff Position
Staff agrees with the Company’s proposed method for valuing avoided energy
based on historical weighted ELAP pricing. Staff believes hourly ELAP prices are
reasonable because they reflect the actual energy market value in the Company’s service
area. While historic pricing is less accurate than real-time pricing, Staff notes that a benefit
is rate stability and transparency for customers. Staff agrees with the Company’s proposal

30 Ellsworth DI at 10, 13.

IDAHO POWER COMPANY’S FINAL COMMENTS - 19
to use the most recent year’s pricing data and not to incorporate multiple years of pricing
data via some type of rolling average.31
However, Staff disagrees with the Company’s method of distributing the value of
avoided energy and recommends that the value of avoided energy be allocated between
the summer and non-summer seasons. Staff believes that the on-peak time window is
determined primarily by capacity considerations – not energy considerations. Staff’s
proposal would produce three ECR values: Non-Summer, Summer Off-Peak, and
Summer On-Peak.32
Staff disagrees with IIPA’s assertion that EIM pricing contains a component of
capacity-related value.33
Vote Solar Position
Vote Solar did not oppose the Company’s proposal to use ELAP prices to value
the avoided energy component of the ECR. However, Vote Solar proposed using a three-
year historical rolling average of market prices to mitigate severe price swings in the
avoided energy value from year to year and improve customer predictability and
stability.34 Vote Solar opposes IIPA’s proposals for a balancing account to track the
difference between the energy paid to customers and the value received and that ELAP

31 Staff Comments at 17 (Oct. 12, 2023).
32 Id. at 18.
33 Staff Reply Comments at 4 (Nov. 2, 2023).
34 Vote Solar Comments at 16 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 20
prices include a capacity component and maintains that they are a reasonable proxy for
the avoided energy costs that result from exports.35
Other Party Positions
IIPA suggests that the on-peak energy credit equal the off-peak energy credit to
avoid double counting capacity value.36 IIPA asserts that the “EIM prices used to calculate
the on-peak energy value are, on average, hours where scarcity pricing results in market
prices compensating for capacity as well as energy.”37 IIPA also suggests excluding the
Greenhouse Gas component of the ELAP prices.38 Additionally, IIPA recommends that
Idaho Power should develop a balancing account to track the difference between the
energy value paid to customers and the value received from customers and amortize the
balance in each ECR update.39
CEO agrees with Staff and the Company regarding the proposed method for
valuing avoided energy based on ELAP hourly pricing from the prior year weighted for
hourly exports in that year.40 However, CEO requests that the Company provide an
updated hourly Loss of Load Probability (“LOLP”) analysis which includes the use of
battery storage resource additions.41 CEO’s understanding of the intent of using ELAP
pricing was to reflect the local energy value in each hour – which conflicts with the position

35 Vote Solar Reply Comments at 8 and 12 (Nov. 2, 2023).
36 IIPA Comments at 8 (Oct. 12, 2023).
37 Id. at 7.
38 IIPA Comments at 8 (Oct. 12, 2023).
39 Id. at 10.
40 CEO Reply Comments at 3 (Nov. 2, 2023).
41 Id.

IDAHO POWER COMPANY’S FINAL COMMENTS - 21
from IIPA that suggests the ELAP prices are overstated by a Greenhouse Gas
component. CEO requests that the Company clarify whether a Greenhouse Gas adder
is, or is not, included in the ELAP price.
ICL and City of Boise did not provide specific recommendations for the avoided
energy value.
Idaho Power Position
The Company recommends the Commission approve the Company’s filed request
for the avoided energy component of the ECR to use 12 months of ELAP market prices
ending December 31 weighted for historical customer-generator exports to determine the
avoided energy value of the ECR. To keep the value of energy as accurate as possible,
the Company maintains its proposal to use the most recent year’s pricing data rather than
incorporating multiple years of pricing data as proposed by Vote Solar.
The Company is aligned with Staff’s proposal to allocate the value of avoided
energy between the summer and non-summer season rather than the on-peak and off-
peak hours as proposed in the Company’s initial filing. Vote Solar’s rationale for opposing
this approach is that it “will not substantially improve the economics of exporting power.”42
However, the Commission has been clear in previous orders that the purpose is to ensure
that customers are paid fair, just, and reasonable rates for their exports and non-self-
generating customers are not subsidizing the rates for self-generating customers – not to
ensure that customers who have installed self-generation facilities are able to recoup their

42 Vote Solar Reply Comments at 7 (Nov. 2, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 22
investment or earn a return on investment.43 Therefore, Vote Solar’s opposition to this
approach shouldn’t impact the decision for how to most appropriately calculate the
avoided energy value for the ECR.
As a matter of clarification, the Company believes IIPA misunderstood the
Greenhouse Gas component in the ELAP price. The Greenhouse Gas component reflects
a carbon compliance cost and is therefore a negative value. Therefore, the Company
disagrees with the proposal from IIPA to remove the value of the Greenhouse Gas
Component, as the ELAP price is representative of the avoided cost of energy provided
from customer-generators. The ELAP price reflects the balance of supply and demand,
and the Company does not have the opportunity to purchase energy from the EIM at
lower than market price, thus the ELAP price reflects the marginal cost for energy with
location-based adjustments for losses, congestion, and carbon compliance costs in any
period.
The Company is not opposed to the proposal by IIPA to create a balancing account
to track the differences in historical and average market prices; however, it also
acknowledges that such a mechanism does create an additional layer of complexity that
the Commission may not wish to adopt at this time. If the Commission determines there
is merit to IIPA’s concern related to the timing differences, it could direct the Company to
track and report on the impact over a certain number of years.

43 In the Matter of Idaho Power Company’s Application to Complete the Study Review Phase of the
Comprehensive Study of Costs and Benefits of On-Site Customer Generation & for Authority to
Implement Changes to Schedules 6, 8, and 84, Case No. IPC-E-22-22, Order No. 35631 at 28 (Dec. 19,
2022).

IDAHO POWER COMPANY’S FINAL COMMENTS - 23
The Company recommends the Commission approve the filed highest-risk hours
of 3 p.m. to 11 p.m. in the summer season and that any changes should be evaluated
within the context of the Company’s planning process. The Company agrees with Staff’s
recommendation that future changes to the hours should align between the ECR and
TOU rates for retail energy consumption.
The below table compares the avoided energy value between the Company’s filed
and revised proposal.
Table 2
Avoided Energy Value Comparison (cents per kWh)
Idaho Power – Filed Idaho Power - Revised
On-Peak
Jun. 15-Sep. 15,
3pm-11pm, excluding
Sunda s & Holida s
8.59 ¢ Summer
Jun. 1 – Sep. 30,
all hours
5.65 ¢
Off-Peak
All other days and hours 4.91 ¢ Non-Summer
Oct. – May 31,
all hours
4.84 ¢
Annual Weighted
Avera e
5.16 ¢ Annual Weighted
Avera e
5.16 ¢
Note: Revised values include the Company’s proposal for integration costs and line losses.
D. Avoided Generation Capacity
Summary of Avoided Generation Capacity Positions
Party Idaho Power
(Filed)
Staff Vote Solar Other Idaho Power
(Revised)
Position ELCC

Trailing 3-Year
Average ELCC
and Least-Cost
Dispatchable
Prox Resource
ELCC

Trailing 5-Year
Average ELCC
and Least-Cost
Dispatchable
Prox Resource
Capacity Factor

Battery Storage
as Proxy
Resource
CEO – Agreed
with Staff

City of Boise &
ICL - Battery
Storage as
Prox Resource
ELCC

Trailing 5-Year
Average ELCC
and Least-Cost
Dispatchable
Prox Resource

To determine the capacity contribution of customer-generators, the Company’s
proposed avoided generation calculations use a 3-year average of the ELCC, multiplied
by the maximum hourly exports (of the latest year’s data) and valuing it at the levelized

IDAHO POWER COMPANY’S FINAL COMMENTS - 24
capacity cost of the least-cost dispatchable resource in its most recently filed IRP.44 The
ELCC method measures a resource’s contribution during the hours of highest risk – as
more renewable generation is introduced to the grid, the hours of highest system load
and the hours of highest risk generally do not align. The true value of avoided capacity
occurs during the hours of highest risk, so the ELCC is a more accurate means of
assigning value than other methods such as the National Renewable Energy Laboratory
(“NREL”) 8,760-hour method, or the Peak Capacity Allocation Factor (“PCAF”) method.
These alternative methods assess a resource’s contribution during the hours of highest
system load – not necessarily during the hours of highest risk – and are therefore less
accurate approaches to assigning an avoided generation capacity value.45
Staff Position
Staff believes that the Company’s proposed method for valuing the avoided
generation capacity of exports is reasonable.46 However, Staff recommends that the
Company implement the following:
(1) Use a 5-year instead of a 3-year rolling average to estimate the ELCC;
(2) Modify the method to incorporate line losses in calculating capacity value;
(3) Use all exports from customer generators in its calculation of the ELCC.
Staff agrees with the Company’s proposal to use the levelized capacity cost of the
least-cost dispatchable resource as identified in the most recently filed IRP. On
September 30, 2023, the Company filed the 2023 IRP in Case No. IPC-E-23-23, which

44 Ellsworth DI at 16.
45 Ellsworth DI at 15.
46 Staff Comments at 19 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 25
identified the least-cost dispatchable resource as a single-cycle combustion turbine
(“SCCT”), with a levelized cost of $145.94 per kW-year.47 Staff recommends that this
updated value be used to determine the avoided capacity value because it is more current
and therefore more accurate.48 Staff believes a surrogate dispatchable resource to
establish a purely avoided cost of capacity should meet the following criteria:
(1) Have the lowest levelized fixed cost including capital cost and fixed
operation and maintenance cost;
(2) Be reliably dispatchable regardless of the time or duration need.
Staff does not believe that proposals by Vote Solar and City of Boise to use battery
storage as the proxy for avoided cost of capacity fits either of these two criteria. Therefore,
Staff suggests that using battery storage as a surrogate capacity resource does not
provide an ideal fit.49
The recommendation to increase the ELCC to a 5-year rolling average addresses
Staff’s concern that the ELCC could trend down as solar penetration increases. Staff
notes that utility-scale solar generators can lock in the ELCC through a contract with the
Company, but notes doing so is not practical for a class of customers with participants
who enter and exit the class continuously. Staff believes a reasonable workaround is to
extend the duration of the rolling average so the ELCC values of early years can continue
contributing to the overall capacity value for an extended period. Staff also notes that
2020 was the first year ELCCs could be accurately determined for customer-generator

47 2023 Integrated Resource Plan Appendix C: Technical Report at 18.
48 Staff Comments at 20 (Oct. 12, 2023).
49 Staff Reply Comments at 5 (Nov. 2, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 26
exports on Idaho Power’s system, so a full 5-year average would not be attainable until
the end of 2024. Therefore, if the Commission accepts Staff’s recommendation, the rolling
average would incorporate each year’s results as it became available through 2024.50
Staff acknowledged that the Company’s filed proposal grosses up the hourly
customer-generator exports by the corresponding line loss factor when importing the data
into its Reliability and Capacity Assessment Tool (“RCAT”), which is then utilized to
perform the ELCC calculations. Staff believes that the ELCC algorithms do not have the
resolution to account for the small line loss increases, thus nullifying line losses.51
Therefore, Staff recommends the Company account for line losses for capacity by
applying the line loss gross up after the ELCC and avoided capacity values are
determined. Staff also believes the Company’s proposal to distribute all generation
capacity value to the On-Peak hours is reasonable.52
Vote Solar Position
Vote Solar suggests it is “more appropriate to base avoided generation capacity
costs on the capital costs of battery storage, which results in a generation capacity cost
of $192 per kW-year.”53 Vote Solar believes that the “ELCC is computationally intensive
because doing so requires a substantial amount of data,” making “ELCC calculations less
transparent because the assumptions and calculations are challenging for stakeholders

50 Staff Comments at 19-21 (Oct. 12, 2023).
51 Staff Comments at 21 (Oct. 12, 2023).
52 Id.
53 Vote Solar Comments at 20 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 27
to review.”54 Vote Solar recommends the capacity factor method as a simplified
alternative to the ELCC and states that it is still “sufficiently accurate.”55
Vote Solar claims that it is the only intervenor that proposed a generation capacity
value that represents capacity costs actually avoided because it uses the levelized cost
of battery storage as the surrogate resource.56 Vote Solar states that its calculation
accounts for avoided line losses and Idaho Power’s planning reserve margin – suggesting
that when load is reduced by a kilowatt, the amount of generation the utility must procure
is reduced by a kilowatt plus its planning reserve margin.57 Vote Solar suggests that Idaho
Power’s capacity value calculations lack accuracy and transparency – pointing to Idaho
Power’s 2023 IRP ELCC values for existing and future resources.58 Vote Solar also
compared the Company’s analysis for the highest-risk hours with its proposed approach
of using the top ten percent of load hours and found that 99 percent of the high load hours
occurred in the On-Peak period (as identified by the Company’s highest-risk hours).59
Other Party Positions
CEO supports Staff’s request to use a five-year rolling average of the ELCC
instead of a three-year rolling average.60 CEO maintains that EIM prices do not reflect a

54 Id.
55 Id. at 21.
56 Vote Solar Reply Comments at 10-11 (Nov. 2, 2023).
57 Id. at 10.
58 Vote Solar Reply Comments at 14-15 (Nov. 2, 2023).
59 Id. at 16.
60 CEO Reply Comments at 5 (Nov. 2, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 28
capacity value and that the EIM transaction values reflect the marginal cost for energy,
with location-based adjustments for losses and congestion, as suggested by IIPA.61
City of Boise and ICL recommend the avoided generation capacity valuation use
battery storage as the alternative dispatchable resource.62
IIPA did not make specific recommendations for the avoided generation capacity
value. However, IIPA did suggest concerns with potential double counting between the
avoided energy value and capacity value as mentioned in the Avoided Energy section of
these comments.
Idaho Power Position
The Company is generally aligned with Staff’s proposed modifications to the
avoided generation capacity value:
(1) The Company agrees with Staff’s proposal to update the dispatchable
resource cost to $145.94 per kW-year as defined in the 2023 IRP.
(2) The Company agrees with Staff’s proposal to use a five-year rolling average
to calculate the ELCC value.
(3) The Company agrees with Staff’s proposal to include exports for all hours
in a calendar year in its rolling average ELCC calculation.
(4) If directed, the Company can adopt Staff’s recommendation to apply the line
losses after the ELCC calculation by instead modifying the avoided
generation capacity value equation to include the peak line loss factor,

61 Id.
62 ICL Comments at 2 (Oct. 12, 2023) and City of Boise Reply Comments at 6 (Nov. 2, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 29
however, the Company describes its revised proposal for the Commission’s
consideration in the comments that follow.
The table below compares the avoided generation capacity value components
between the Company’s filed and revised proposal, which accepts proposed changes by
Staff except for the application of line losses after the ELCC calculation.
Table 3
Avoided Generation Capacity Value Components Comparison
Idaho Power – Filed Idaho Power – Revised
ELCC
Jun. 15 - Sep. 15,
3:00 pm - 11:00 pm,
Excludes Sundays and
Holidays
8.76% ELCC
Jan. 1 - Dec. 31,
All Hours
10.12%
Max Output
Based on 2022 Data
62.86 MW Max Output
Based on 2022 Data 62.86 MW
Avoided Cost
LCOC of SCCT
From 2021 IRP
$131.6/kW-year Avoided Cost
LCOC of SCCT
From 2023 IRP
$145.94/kW-year
Energy Risk Hours
Jun. 15 - Sep. 15,
3:00 pm - 11:00 pm,
Exclude Sundays and
Holidays
6,255.03 MWh Energy Risk Hours
Jun. 1 - Sep. 30,
3:00 pm - 11:00 pm,
Exclude Sundays and
Holidays
8,752.71 MWh
Loss Coefficient
On-Peak
Credited Hours
Input to ELCC Calculation
1.050 Loss Coefficient
System Peak
Applied as an Input
1.053
(On-Peak Hours)
1.044
(All Other Hours)

The Company generally accepts Staff’s proposal for calculating the avoided
generation value; however, to maintain a clear record, it would like to address the
following for the Commission’s consideration regarding Staff’s proposed method of
applying line losses directly to the avoided generation capacity value instead of applying
to the exports as an input into the calculation. While Staff suggests that the ELCC
algorithms do not have the resolution to account for the small line loss escalations, the
resolution is a function of all resource nameplates included in the RCAT which makes it

IDAHO POWER COMPANY’S FINAL COMMENTS - 30
a discrete (not continuous) value. As customer-generator penetration increases the
impact will be accurately captured in the ELCC calculation under the Company’s
proposal. In illustration of this point, the Company modeled customer-generator exports
assuming an increased level of penetration on its system and calculated the ELCC with
and without losses applied, as seen in the table below.
Table 4
Line Loss Application Illustration – For a Single Test Year with Export Data Increased by a Factor of 2x
ELCC of Actual Export Data ELCC of Increased Export Data (2x)
No Losses
Applied
Losses
Applied
No Losses
Applied
Losses
Applied
2 MW 2 MW 5 MW 6 MW

The illustrative ELCC results show that as customer generation penetration
increases, the Company's filed method to apply line losses within the ELCC calculation
would increase the capacity contribution result. Staff's proposed method of applying the
line loss coefficient after the ELCC calculation may provide better transparency/simplicity
in the calculation of line losses to the avoided generation capacity value but would result
in the utilization of a less accurate methodology, which as shown in the above table, could
understate the value in the future. The table illustratively shows how the ELCC is impacted
by hourly line loss application when the 2022 exports are doubled - 2023 maximum
exports measured as much as 1.77x levels in 2022. Therefore, the issue Staff intends to
address is already not an issue at the current level of on-site generation penetration.
Accordingly, the Company contends its proposed method is most accurate, however, if
the Commission adopts Staff’s proposal, it will update the ECR as directed.
While Vote Solar recommends the capacity factor method as a simplified
alternative to the ELCC method, the Company disagrees that implementing a less

IDAHO POWER COMPANY’S FINAL COMMENTS - 31
accurate measurement is appropriate, particularly in light of recent widespread adoption
of the ELCC as the preferred method for measuring the resource adequacy contribution
of intermittent and energy-limited resources.63,64 Vote Solar’s comparison of the capacity
factor method as a reasonable approximate to the ELCC method is based on a report
written in 1997. This is irrelevant considering the significant changes undergone by the
electric system in the past 25 years. The Company last utilized a variant of the capacity
factor method in the 2017 IRP, where the capacity contribution of solar was calculated for
the top 150 load hours and resulted in a value of 28.4 percent for a fixed-tilt system
oriented due south.65 Recognizing that the basis of the capacity factor method was limited
and did not capture the impact of high solar penetration, the Company transitioned to the
8,760 hour-based method developed by the National Renewable Energy Laboratory
(“NREL”) in the 2019 IRP.66 To further capture the impact of higher variable and energy-
limited resource penetration levels, the Company, with the support of its Integrated
Resource Plan Advisory Council (“IRPAC”), adopted the preferred industry method,

63 ELCC has quickly gained traction among ISOs and utilities. See Olson, A., Ming, Z., and Carron, B.
ELCC Concepts and Considerations for Implementation at slide 12, Presentation for NYISO Installed
Capacity Working Group, Aug. 30, 2021.
Available at:
https://www.nyiso.com/documents/20142/24172725/NYISO%20ELCC_210820_August%2030%20Prese
ntation.pdf
64 N. Schlag, Z. Ming, A. Olson, L. Alagappan, B. Carron, K. Steinberger, and H. Jiang. Capacity and
Reliability Planning in the Era of Decarbonization: Practical Application of Effective Load Carrying
Capability in Resource Adequacy at 3, Energy and Environmental Economics, Inc., Aug. 2020.
Available at: https://www.ethree.com/wp-content/uploads/2020/08/E3-Practical-Application-of-ELCC.pdf
65 In the Matter of Idaho Power Company’s 2017 Integrated Resource Plan, Case No. IPC-E-17-11, 2017
IRP at 37 and 130.
66 In the Matter of Idaho Power Company’s 2019 Integrated Resource Plan, Case No. IPC-E-19-19, 2019
IRP at 37.

IDAHO POWER COMPANY’S FINAL COMMENTS - 32
ELCC, for the 2021 IRP.67 The Company also rejects Vote Solar’s attempt to suggest that
its method is not transparent and easily reviewable by stakeholders. The RCAT is simply
a code implementation/interface of a system reliability textbook methodology.68
The capacity factor method only utilizes the system load as a weighting factor for
evaluating capacity contribution and does not capture the shift in timing of the system’s
high-risk hours. In result, the capacity factor method determines capacity contribution
independent of renewable penetration which means it is incapable of adequately
accounting for changes in intermittent and energy-limited resource penetration on the
system. Vote Solar found that over 99 percent of high load hours occur in the months the
Company defines as the hours of highest risk;69 the observation is irrelevant as it does
not consider the timing of those hours nor does it consider if the highest risk hour occurs
when customer-generator exports occur.
Vote Solar states that it does not agree with Staff’s claim that the true value of
avoided capacity occurs during the hours of highest risk.70 Vote Solar incorrectly suggests
that if system peak load increases, then Idaho Power must construct or procure new
capacity resources to reliably serve customers.71 Vote Solar’s comments are ill-informed
and inaccurate – the highest-risk hours are the only time when capacity is avoided. Idaho

67 In the Matter of Idaho Power Company’s 2021 Integrated Resource Plan, Case No. IPC-E-21-43, 2021
IRP at 51.
68 Reliability Evaluation of Power Systems (Billinton, R. and Allan, R.N. (1996) Reliability Evaluation of
Power Systems. 2nd Edition, Plenum Press, New York).
69 Vote Solar Reply Comments at 16 (Nov. 2, 2023).
70 Id. at 17.
71 Id.

IDAHO POWER COMPANY’S FINAL COMMENTS - 33
Power will only procure new capacity resources if it is in a period of capacity shortfall as
measured by the reliability threshold. If system peak increases but the reliability, as
measured by the LOLE, does not change, Idaho Power will not procure more resources.
Additionally, Vote Solar’s avoided generation capacity value analysis includes a
cost increase by an amount equal to the Company’s 2021 IRP Planning Reserve Margin
(“PRM”).72 The PRM has no relation to the avoided capacity of a single resource. The
claim that the avoided generation should be increased by the PRM is flawed. Load is not
being reduced due to the presence of exports but rather load is being served by the
presence of exports. When exports do not appear or go away suddenly (e.g., due to
weather patterns or time of day) the load remains, and Idaho Power is still required to
serve it. As such, the valuation of avoided generation capacity should not include the
PRM in the calculations for the cost of avoided generation capacity.
Finally, the Company does not agree with the recommendation to utilize battery
storage as the alternative dispatchable resource. For avoided capacity cost calculations,
the Company finds it most appropriate to utilize the lowest levelized cost of capacity
resource which was identified as an SCCT in the 2023 IRP.73 The Company agrees with
Staff’s position that a surrogate dispatchable resource should have the lowest levelized
fixed cost and be reliably dispatched. Additionally, an August 2022 Commission order
upheld this approach as reasonable, where the Commission stated:

72 Vote Solar Reply Comments at 10 (Nov. 2, 2023).
73 2023 Integrated Resource Plan Appendix C: Technical Report at 18.

IDAHO POWER COMPANY’S FINAL COMMENTS - 34
We find it fair, just, and reasonable that the resource(s) used
as a surrogate to determine avoided capacity cost be
identified using the lowest-cost selectable resource from the
most recently acknowledged IRP… 74

In response to the recommendation from CEO to remove the non-firm
adjustment,75 the Company wishes to clarify that there is not a non-firm adjustment
included in the Company’s filed proposal and therefore there is no adjustment to remove
as suggested by CEO.
For the reasons stated herein, the Company recommends the Commission
approve the Company’s revised proposal for determining the avoided generation capacity
value of customer generator exports. The table below compares the avoided generation
capacity value between the Company’s filed and revised proposal which incorporates the
majority of Staff’s proposed modifications.
Table 5
Avoided Generation Capacity Value Comparison (cents per kWh)
Idaho Power – Filed Idaho Power – Revised
On-Peak
Jun. 15 - Sep. 15,
3:00 pm - 11:00 pm,
Exclude Sundays
Exclude Holidays
11.59 ¢ On-Peak
Jun. 1 - Sep. 30,
3:00 pm - 11:00 pm,
Exclude Sundays
Exclude Holidays
10.61 ¢
Off-Peak
All Other Days & Hours
0.00 ¢ Off-Peak
All Other Days & Hours
0.00 ¢
Annual Weighted Average 0.79 ¢ Annual Weighted Average 1.01 ¢
Note: Revised values reflect Idaho Power’s proposal for valuation of line loss coefficients in the ELCC.

74 In the Matter of Idaho Power Company’s Application for Approval of a Replacement Contract with
Micron Technology, Inc. and a Power Purchase Agreement with Black Mesa Energy, LLC, Case No. IPC-
E-22-06, Order No. 35482 at 17 (Aug. 1, 2022).
75 CEO Reply Comments at 5 (Nov. 2, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 35
E. Avoided Transmission and Distribution Capacity
Summary of Avoided Transmission and Distribution Capacity Positions
Party Idaho Power
(Filed) Staff Vote Solar Other Idaho Power
(Revised)
Position Project Deferral
Analysis

20-year project
specific review
Project Deferral
Analysis

20-year project
specific review
FERC
Transmission
Rate
CEO – Marginal
Transmission Line
Cost

City of Boise –
FERC Transmission
Rate

IIPCA – Rate Design
Considerations
Project Deferral
Analysis

20-year project
specific review

The Company compares transmission and distribution (“T&D”) capacity shortfalls
throughout its system and overlays customer exports to determine how long it can delay
projects that increase transmission and distribution capacity. The value is determined
based on the cost of capital of the project investment and length of time a project can be
delayed. The distribution of value for avoided T&D capacity follows similar rationale as
the allocation of value for avoided generation capacity. Therefore, the Company proposed
that the capacity value should be distributed to exports during the on-peak hours of
highest risk.
Staff Position
Staff believes the Company’s proposed method of project-by-project deferral
assessments is reasonable and agrees that assessing every T&D capacity project over
a 20-year time span is sufficiently comprehensive.76 Staff believes the Company’s
proposal to distribute all T&D deferred capacity value to the on-peak hours is
reasonable.77

76 Staff Comments at 22 (Oct. 12, 2023).
77 Id. at 23.

IDAHO POWER COMPANY’S FINAL COMMENTS - 36
Staff does not agree with IIPA’s assertion that the Company’s proposed method
assumes that 100 percent of the customer’s generation is exported.78 Additionally, Staff
does not agree with IIPA’s claim that there is double counting between the avoided
distribution value in the ECR and avoidance of energy charges for customer classes with
distribution-related costs embedded in their retail energy rates.79
Staff believes that City of Boise’s recommendation to use energy efficiency (“EE”)
T&D deferral value is inappropriate. Staff notes that while the input data is the same, the
2023 IRP describes that the EE avoided T&D costs are calculated using EE specific
assumptions and reduction amounts. Meanwhile, the proposed ECR uses export data
and assumptions specific to on-site generation customers to calculate the T&D deferral
value. Staff recommends that on-site generation export specific data and assumptions
are used to value ECR T&D deferral and believes it will result in a more accurate T&D
value specific to customer-generators.80
Vote Solar Position
Vote Solar recommends an avoided transmission cost value that is based on the
current Federal Energy Regulatory Commission (“FERC”)-approved transmission rate for
Idaho Power of $31.42/kW-year.81 Vote Solar’s proposed calculation results in a value of
7.39 cents per kWh during the on-peak period or 0.50 cents per kWh annually. Vote
Solar’s comments did not describe a proposed method for the avoided distribution

78 Staff Reply Comments at 4 (Nov. 2, 2023).
79 Id. at 5.
80 Id. at 5-6.
81 Vote Solar Comments at 24-25 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 37
capacity component, but in its ECR summary it includes a value of 0.254 cents per kWh
during the on-peak period or 0.017 cents per kWh annually.82 Vote Solar disagrees with
IIPA’s position and maintains that the value of avoided distribution capacity should be
included in the ECR and apply to all customers, regardless of their rate schedule.83
Other Party Positions
CEO requests that in future ECR updates, because new transmission lines are
anticipated to be used to access remote generation sources, the costs for those marginal
transmission lines should be treated in the same fashion as other marginal generation
resources when quantifying the T&D capacity contribution of self-generation.84 CEO also
disagrees with IIPA’s position and cites previous Commission findings that matters of
fixed cost recovery behind the meter are separate from matters of valuing excess
energy.85
City of Boise suggests that a “reasonable transmission & distribution deferral
value” should be included in the ECR. Specifically, City of Boise recommends a higher
value for avoided transmission costs be assigned by reflecting the Company’s FERC
transmission rate.86

82 Vote Solar Comments at 33 (Oct. 12, 2023).
83 Vote Solar Reply Comments at 18 (Nov. 2, 2023).
84 CEO Comments at 4 (Oct. 12, 2023).
85 CEO Reply Comments at 5 (Nov. 2, 2023).
86 City of Boise Comments at 3 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 38
IIPA recommends that the T&D capacity credit should only apply to schedules with
no transmission or distribution revenue requirement included in the energy charge.87 IIPA
is concerned that if the energy component of the customer’s bill includes distribution
costs, the customer will receive double compensation for reduced distribution costs, once
directly through the capacity component of the ECR and again through avoiding energy
charges with self-consumed energy.
ICL does not specify a recommendation related to deferred T&D capacity value for
the ECR.
Idaho Power Position
The Company recommends the Commission approve its proposed project deferral
analysis for valuing the T&D capacity deferral component of the ECR. The alternative
recommendations presented by Vote Solar, CEO, and City of Boise do not accurately
value the T&D cost deferred by customer-generator exports.
Vote Solar and City of Boise have not attempted to evaluate whether the results of
Idaho Power’s project deferral analysis were reasonable. Instead, both suggest a different
method should be used because the Company’s proposed method does not yield a high
enough value with no support for why the value is understated or the underlying
methodology is flawed. CEO also recommends including a marginal cost analysis for
transmission projects. The proposal to use the FERC transmission rate or other marginal
cost rate does not represent capacity costs actually avoided, or deferred, as directed by
the Commission.88

87 IIPA Comments at 11 (Oct. 12, 2023).
88 Case No. IPC-E-22-22, Order No. 35631 at 29.

IDAHO POWER COMPANY’S FINAL COMMENTS - 39
The Company agrees with Staff’s analysis that IIPA has incorrectly characterized
the T&D deferral approach, which uses the exports from customer-generators – not 100
percent of the generation. The Company also does not agree with IIPA that the proposed
T&D deferral value is double counting with the customer-generators ability to reduce
energy charges and its considerations for transmission and distribution-related costs
embedded in the energy charge for certain customer classes should instead be
addressed through rate design through a general rate case or separate proceeding.
The below table compares the Company’s filed T&D value, updated for the revised
summer and non-summer seasons as proposed by Staff.
Table 6
Avoided Transmission & Distribution Capacity Value Comparison (cents per kWh)
Idaho Power – Filed Idaho Power – Revised
On-Peak
Jun. 15-Sep. 15,
3pm-11pm, excluding
Sunda s & Holida s
0.25 ¢ On-Peak
Jun. 1 – Sep. 30,
3pm-11pm, excluding
Sunda s & Holida s
0.18 ¢
Off-Peak
All other da s and hours 0.00 ¢ Off-Peak
All other da s and hours 0.00 ¢
Annual Weighted
Avera e
0.02 ¢ Annual Weighted
Avera e
0.02 ¢

IDAHO POWER COMPANY’S FINAL COMMENTS - 40
F. Avoided Line Losses
Summary of Avoided Line Loss Positions
Party Idaho Power
(Filed) Staff Vote Solar Other Idaho Power
(Revised)
Position On-Peak and
Off-Peak Line
Loss
Coefficients
Average Energy
Losses and
Peak Capacity
Losses
Marginal Line
Losses
CEO & ICL –
Marginal Line
Losses
Average Energy
Losses and
Peak Capacity
Losses

Idaho Power completed its most recent system loss study in March 2023.89 The
electric utility industry typically calculates lines losses by evaluating the total system
losses over the entire year and during the peak hour of the year, which the Company
completed in the March 2023 line loss study. The originally filed On-Peak line loss
coefficient (1.050) was a modification of the calculated peak hour coefficient (1.053),
which accounted for all the hours within the previously identified On-Peak period. In the
March 2023 line loss study, the peak hour coefficient was adjusted using hourly data from
the 138-kV system to calculate the On-Peak line loss coefficient. The 138-kV system was
used as a proxy given the high-resolution data available and being an adequate
representation of the native load in the Company’s system as most of the wheeling across
Idaho Power’s transmission system occurs at higher voltage. The resulting on- and off-
peak loss coefficients in the Company’s filed proposal were applied to on- and off-peak
hours respectively.
Staff Position
Staff reviewed the Company’s line loss study completed in March 2023 and
concluded that the analysis was reasonably accurate but disagreed with the proposed

89 Ellsworth DI, Exh.4.

IDAHO POWER COMPANY’S FINAL COMMENTS - 41
coefficients.90 Staff believes the Company’s approach “embeds too many assumptions,
obfuscates the calculations, and jeopardizes the accuracy.”91 Staff also states that it is
inappropriate to apply a capacity-based loss rate to the ECR energy value. Staff
recommends that the ECR utilize “industry-typical loss calculations.” As a result, Staff
concludes that the avoided energy value should be grossed up by the annual energy loss
coefficient and the avoided capacity value should be grossed up by the standard peak
hour loss coefficient.
Vote Solar Position
Vote Solar claims that the Company’s suggested ECR includes average line
losses, and it recommends that marginal line losses should be used as they are “typically
at least twice as high as average system losses.”92 Vote Solar proposes doubling the
proposed line loss coefficients proposed by Idaho Power.
Other Party Positions
CEO requests that the Company’s proposal to decrease line loss assumptions,
relative to the line losses used in the October 2022 VODER Study, be denied, and that
the line loss should not be less than 5.8 percent – referring to the line loss value used in
Case No. IPC-E-22-22.93 ICL recommends the use of marginal line loss calculations.94

90 Staff Comments at 23 (Oct. 12, 2023).
91 Id.
92 Vote Solar Comments at 17 (Oct. 12, 2023).
93 CEO Comments at 5 (Oct. 12, 2023).
94 ICL Comments at 2 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 42
City of Boise and IIPA did not specify a proposed method for determining line
losses in their comments.
Idaho Power Position
The Company recommends the Commission approve Staff’s proposal of applying
the annual energy loss coefficient to the avoided energy value. The Company also
recommends the Commission approve Idaho Power’s revised proposal of applying the
standard peak hour loss coefficient to the On-Peak hours and the annual energy loss
coefficient to all other hours for customer-generator exports in the ELCC calculation which
is utilized to inform the avoided capacity value. The Company believes its proposal is an
accurate calculation and most representative of the distribution system for all on-peak
hours, on average. However, it is not opposed to Staff’s proposal if the Commission
believes the tradeoff between accuracy and understandability is warranted.
The Company would like to clarify that Vote Solar’s claim of the proposed ECR
including average line losses is incorrect, as the Company calculated separate peak and
average line losses in its line loss study. Peak losses were applied to the annual capacity
value and average line losses were applied to the annual energy value.
The Company experiences reverse power flow from the distribution system to the
transmission system in several substations due to generation on the distribution system,
which increases the line losses. Therefore, if the Commission were to approve the use of
marginal losses in the ECR calculation, it would result in additional costs to account for
the increase in line losses. Additionally, Vote Solar states that marginal losses are twice
as high as average system losses; this assumption is based on a 2011 study that

IDAHO POWER COMPANY’S FINAL COMMENTS - 43
analyzed a hypothetical utility and assumed annual resistive losses.95 The Company’s
2023 line loss study utilized hourly historical data to calculate the peak and average
losses, which provided the ability to calculate components such as the annual resistive
losses instead of relying on general assumptions. Therefore, the Company suggests that
the Commission reject Vote Solar’s proposed marginal line loss calculation.
The proposal by CEO to utilize line loss coefficients from the Company’s 2012 line
loss study does not rely on using the most recent data available to derive an accurate
ECR value. Therefore, the Company recommends the Commission reject the proposal
by CEO to maintain a line loss value of 5.8 percent or higher when more recent and
reflective data is available. The table below compares the Company’s filed and revised
proposal for line loss coefficients to account for line losses in the ECR.
Table 7
Line Losses Coefficient Comparison
Idaho Power – Filed Idaho Power – Revised
Credited Hours On-Peak
Jun. 15 - Sep. 15,
3:00 pm - 11:00 pm,
Excluding Sundays & Holidays
For Avoided Energy & Capacity
1.050 Capacity
Jun. 1 - Sep. 30,
3:00 pm - 11:00 pm,
Excluding Sundays & Holidays
For Avoided Capacity Only
1.053
(On-Peak)

1.044
(All Other Hours)
Off-Peak
Jan. 1 - Jun. 14 & Sep. 16 - Dec. 31,
All Days & All Hours
For Avoided Energy & Capacity
1.044 Energy
All Days & All Hours
For Avoided Energy Only
1.044

95 Vote Solar Comments at 17 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 44
G. Avoided Environmental Costs
Summary of Avoided Environmental Cost Positions
Party Idaho Power
(Filed) Staff Vote Solar Other Idaho Power
(Revised)
Position Not included Not included Reduced carbon
emissions
CEO & City of
Boise - Monetize
renewable
attributes
Not included

The Company has not proposed to include any avoided environmental benefits in
the ECR. Idaho Power is not subject to a carbon tax or a Renewable Portfolio Standard
(“RPS”). Idaho Power does not have a mandatory requirement to produce a set amount
of renewable energy and, therefore, has no need to purchase Renewable Energy
Certificates (“RECs”). Although customer generation from renewable resources may
avoid some fossil fuel generation, thereby reducing carbon emissions, Idaho Power is not
subject to a carbon tax and cannot monetize those emission reductions as a credit in
customer rates.
Staff Position
Staff considered the appropriateness of relying on a national carbon tax, an Idaho
RPS, social health, and RECs as options that could be used to provide a value of an
environmental benefit. Staff concluded that until state or federal legislation mandates a
quantifiable environmental cost or adder to the Company’s rates, it is not appropriate to
include any associated environmental benefits in the ECR.96

96 Staff Comments at 24 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 45
Vote Solar Position
Vote Solar mentions several topics regarding environmental and social costs and
benefits but does not make a specific recommendation for the Commission to consider.97
Vote Solar quantifies “additional benefits” that result in an additional value of
approximately 2.1 cents per kWh but doesn’t specifically suggest using this value in the
total ECR value.98
Other Party Positions
CEO and City of Boise recommend that the Company work with interested
stakeholders to evaluate further opportunities to monetize the renewable energy
attributes associated with exported energy.99 CEO specifically suggests residential
customer-generators opt out of the transfer of renewable attributes to the Company. CEO
also requests that the Company be directed to report on opportunities to monetize the
value of renewable energy attributes.
ICL and IIPA did not specify a recommendation related to quantifying a value for
environmental benefits for the ECR.
Idaho Power Position
The Company maintains its recommendation that until state or federal legislation
mandates a quantifiable environmental cost or adder to the Company’s rates, it is not
appropriate to include any associated environmental benefits in the ECR. The Company
has concerns with CEO and the City of Boise’s proposal to attempt to monetize the

97 Vote Solar Comments at 27-32 (Oct. 12, 2023).
98 Id. at 33.
99 CEO Comments at 5-7 (Oct. 12, 2023) and City of Boise Comments at 3 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 46
renewable attributes of customer generation on the customer’s behalf. While CEO
suggests these are “solvable” issues, Idaho Power maintains that these are not
representative of a cost avoided in customer rates.
In most states, including Idaho, the environmental attributes of on-site generation
remain with the owner. For Idaho Power to retain and retire (or sell) RECs on an on-site
generation customer’s behalf, the current registration process would require the customer
to legally transfer the environmental attributes of the on-site generation, and the customer
would no longer be able to claim the clean nature of the energy used to power their home
or business to prevent double counting of those attributes. Idaho Power does not believe
this is viable as customers typically install on-site generation, in part, for such claims of
clean energy as demonstrated in the public comments and testimony in this docket.
Further, Idaho Power does not have any mechanism that allows for the exchange of on-
site generation RECs – Idaho does not have a RPS with a distributed generation carve-
out, a Solar Renewable Energy Certificate market, or any legislation that establishes
specific treatment of on-site generation RECs. For these reasons, the Company
recommends that the Commission not direct further investigation as proposed by CEO
and City of Boise.

IDAHO POWER COMPANY’S FINAL COMMENTS - 47
H. Fuel Cost Risk
Summary of Fuel Cost Risk Positions
Party Idaho Power
(Filed) Staff Vote Solar Other Idaho Power
(Revised)
Position N/A N/A Valued at 5% of
Avoid Energy
Cost
Valued at 5% of
Avoid Energy
Cost
N/A

In response to feedback from stakeholders in Case No. IPC-E-22-22, the Company
evaluated the potential for a fuel-cost risk benefit for customer-generator exports. In the
October 2022 VODER Study, the Company found that exports from customer-generators
do not provide a fuel-cost hedge benefit. Customer-generator exports on Idaho Power’s
system occur intermittently in the midday hours when it is generally less valuable, rather
than on a firm basis in the highest net-peak hours, when it would be most needed –
resulting in no reduction in pricing risk during the net-peak load.100
Staff Position
Staff did not specifically address a fuel cost risk benefit in its comments regarding
the Company’s proposal.
Vote Solar Position
Vote Solar notes that gas prices are volatile and highly variable throughout the
year, concluding that when energy exported from on-site solar displaces a marginal gas-
fired power plant, customers benefit from reduced dependence on gas prices and lower
exposure to gas volatility.101 Vote Solar recommends the Commission acknowledge that
on-site generation does provide a hedge benefit and approve an avoided fuel cost risk

100 October 2022 VODER Study at 55.
101 Vote Solar Comments at 25-26 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 48
value equal to five percent of avoided energy costs – citing a methodology adopted by
the Public Utility Commission of Oregon.102
Other Party Positions
CEO cites the same method as Vote Solar which assigns a value of five percent
of the avoided energy component of the ECR as the fuel cost risk benefit. As an
alternative, CEO suggests the value should at least be set at 3.9 percent as suggested in
a study specific to Rocky Mountain Power (“RMP”).103 City of Boise and ICL also
recommend the Commission incorporate a non-zero fuel hedge value in similar support
to Vote Solar and CEO.104
IIPA did not specify or mention a value related to fuel cost risk.
Idaho Power Position
The Company recommends the Commission not include a value for fuel cost risk
in the ECR. Vote Solar, CEO, City of Boise, and ICL do not specifically address the issues
and concerns with the proposed reduction in fuel cost risk as evaluated in the October
2022 VODER Study. Instead, these stakeholders reference methods adopted in other
jurisdictions, which ignores the details specific to this proposal. In particular, the ELAP
price is directly impacted by natural gas market prices. To add a five percent premium
would result in double counting and over-inflate the value paid to customer-generators
and collected from all other customers. CEO posits that the Company’s response and
rationale is “inadequate” with no further support for its position. The Company does not

102 Vote Solar Comments at 26 (Oct. 12, 2023).
103 CEO Comments at 3-4 (Oct. 12, 2023).
104 City of Boise Comments at 8 (Oct. 12, 2023), City of Boise Reply Comments at 6 (Nov. 2, 2023), and
ICL Reply Comments at 8 (Nov. 2, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 49
believe that what other jurisdictions adopt is indicative of what should occur in Idaho
without consideration to the specific considerations in this docket. Other states have
elected to assign a value while acknowledging it is challenging to quantify a fuel risk
benefit. The Company believes it would be imprudent to follow similar logic as proposed.
In Case No. IPC-E-22-22, Crossborder Energy, which had support from CEO, ICL and
other intervenors for its review of the Company’ s study in that docket, stated the following
regarding the use of the ELAP market price and a corresponding fuel hedge value for
exported energy:
. . . there is little or no fuel hedge value. Electricity market
prices are directly impacted by natural gas market prices.
Rather, it is the behind the meter solar generation serving the
customer’s load that provides a hedge against the gas-cost
sensitive utility supply costs that otherwise would have to be
incurred by [Idaho Power].105

Vote Solar references an article titled “How Big is the Risk Premium in an Electricity
Forward Price? Evidence from the Pacific Northwest” to support its proposed five percent
adder for a fuel cost risk value. The article concludes that “there is a risk premium of about
5 percent in the forward price for delivery at the Mid-Columbia hub for the Pacific
Northwest.”106 Applying this five percent premium to the ECR when not using a forward
price from the Mid-Columbia hub would be an inappropriate use of the proposed method.
The ECR as proposed uses actual prices which already reflects the market-based

105 Case No. IPC-E-22-22, ICL’s Response to Request No. 22 of Idaho Power Company’s Second
Production Request to ICL.
106 DeBenedictis A., Miller, D., et al, “How Big is the Risk premium in an Electricity Forward Price?
Evidence from the Pacific Northwest,” The Electricity Journal Volume 24, Issue 3 April 2011, pages 72 –
76, available at https://www.sciencedirect.com/science/article/abs/pii/S1040619011000601 (emphasis
added).

IDAHO POWER COMPANY’S FINAL COMMENTS - 50
variability risk premium cited in the article.107 CEO’s suggestion that as an alternative to
the five percent, the Commission adopt a 3.9 percent adder (cited from RMP’s study) is
equally flawed, as RMP’s study envisioned the adder when the avoided energy
component was based on an energy price forecast, not actual prices.
In the Oregon docket referenced by Vote Solar, the OPUC-retained evaluator, E3,
rejected the idea that the avoided hedge value should be included in the calculation for
the value for solar because this hedge value does not accrue to all customers, but to the
owner of the solar generation:
[T]o the extent that a utility acquires a solar resource as part of its
generation portfolio, that resource allows the utility to avoid market
purchases of electricity and/or natural gas and any associated hedging
costs.
However, for behind-the-meter generation, this value accrues to the
owner of the solar installation, not to non-participating utility ratepayers.
Solar owners acquire the resource for the purpose of offsetting all or a
portion of their onsite consumption, thereby replacing their potentially
variable electricity bill with a more stable cost stream based on the cost of
solar ownership. The solar installation thereby provides a hedge value for
the solar owner.
The remaining load does not experience a reduction in volatility as a result
of the solar installation. Behind-the-meter solar does not become part of
the utility’s resource portfolio. Rather, behind-the-meter solar functions
like direct access, in which the load is separated from the remaining
bundled customers and served with a third-party resource, i.e., a resource
that is outside the utility’s portfolio. Since the utility does not own or
contract directly with the solar PV resource, the utility therefore will need
to continue to hedge any market transactions for the remaining load in the
same proportion as if the solar installation had not occurred. As a result,
the hedge value accrues to the system owner, and the remaining utility
ratepayers do not experience a reduction in bill volatility.108

107 See Idaho Power Company’s Response to Request No. 43 of the Fifth Production Request of
Commission Staff.
108 Investigation to Determine the Resource Value of Solar, OPUC Docket No. UM 1716, Staff Exhibit 401
of Exhibits in Support of Cross Responsive Testimony (Jul. 21, 2016), at Olson 23-24 (Staff Response to
TASC Data Request 20).

IDAHO POWER COMPANY’S FINAL COMMENTS - 51
The Commission has clearly stated in previous orders that generic conclusions
and benefits or costs that cannot be quantified or shown to affect customers’ rates should
not be considered in valuing an ECR.109 Therefore, the proposal to include a fuel cost risk
or hedging value related to reduced price volatility should be rejected.
I. Integration Costs
Summary of Integration Cost Positions
Party Idaho Power
(Filed)
Staff Vote Solar Other Idaho Power
(Revised)
Position VER Study
Case 1
VER Study
Case 1
VER Study
Case 9
CEO - VER
Study
Case 9
VER Study
Case 1

The Company proposes to use its 2020 Variable Energy Resources (“VER”)
Integration Study to determine the integration cost component of the ECR. Integration
studies are periodically conducted by the Company to quantify the cost of regulating
variable, non-firm energy sources into the Company’s system such as exports from
customer-generators. The Company proposes to use its VER Study Case 1 with an
integration cost of $0.00293/kWh in the ECR.
Staff Position
Staff agreed with the Company’s basis for and inclusion of the $0.00293/kWh
integration cost in the ECR.110 Staff recommends the Commission authorize the
integration rates for purpose of the ECR in this filing, direct the Company to file the 2020
VER study for Commission authorization to update Schedule 87, and direct the Company
to file all future VER studies and integration costs for Commission authorization.111

109 Case No. IPC-E-22-22, Order No. 35631 at 29.
110 Staff Comments at 25 (Oct. 12, 2023).
111 Id.

IDAHO POWER COMPANY’S FINAL COMMENTS - 52
Staff believes that the presence of battery storage in the Company’s system can
influence integration costs. Because the Company will have installed approximately 120
megawatts (“MW”) of battery storage by the end of the year, Staff recommends the
Company conduct a new integration study as soon as possible. Staff also recommends
that the Company file the study for Commission approval and incorporate the results into
the next possible ECR adjustment filing.112
Vote Solar Position
Vote Solar claims that Idaho Power’s actual resource portfolio is better reflected
by Case 9 in the VER integration study, reflecting an integration cost of $0.64 per
megawatt-hour (“MWh”). Vote Solar states that Case 9 assumes the addition of 251 MW
of solar and 200 MW of storage and that battery storage helps to smooth the variability of
output from resources like solar, reducing integration costs.113
Other Parties Position
CEO makes a similar argument to Vote Solar and suggests that the proposed ECR
should reflect the integration costs of $0.64 per MWh from Case 9.114
ICL, City of Boise, and IIPA did not comment on integration costs.

112 Staff Reply Comments at 6 (Nov. 2, 2023).
113 Vote Solar Comments at 18 (Oct. 12, 2023).
114 CEO Comments at 7-8 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 53
Idaho Power Position
The Company maintains that Case 1 continues to be the appropriate integration
cost scenario because it is most reflective of integration costs from distributed energy
resource exports on the Company’s system. Additionally, the Company is not opposed to
Staff’s proposal for the Commission to direct the Company to complete an updated
integration study as soon as possible and file for Commission approval and inclusion for
future ECR update.
Vote Solar and CEO’s proposal incorrectly applies the integration costs from the
2020 VER Integration Study. Case 1 includes the addition of 251 MW of solar above the
2020 level of utility-scale solar on the Idaho Power system. In comparison, Case 9 was a
sensitivity case to determine the incremental integration cost for adding 794 MW of solar
coupled with 200 MW of battery energy storage above the 251 MW of solar added in
Case 1.
The integration costs for Case 1 and Case 9 from the 2020 VER Integration Study
cannot be directly compared. The $2.93 per MWh integration cost from Case 1 is the
calculated cost for adding 251 MW of utility-scale solar. The integration cost of $0.64 per
MWh from Case 9 is the calculated incremental integration cost to integrate 794/200 MW
of coupled solar/battery beyond the 251 MW of utility-scale solar from Case 1 – this is not
representative of the cost to integrate customer-generator exports.

IDAHO POWER COMPANY’S FINAL COMMENTS - 54
IV. UPDATES TO ECR
Summary of ECR Update Positions
Party Idaho Power
(Filed) Staff Vote Solar Other Idaho Power
(Revised)
Position Annual ECR
Update for all
Net Billing
customers

All components
updated
Annual ECR
Update for all
Net Billing
customers

All components
except season
and hours
Vintage ECR by
interconnection
year and “lock
in” for at least 10
years
ICL – Update
every two years
like IRP
Annual ECR
Update for all
Net Billing
customers

All components
except season
and hours

The Company proposed to update the inputs that inform the ECR annually on April
1, to be effective June 1. This timeline is consistent with the Company’s other annual
spring update filings. Under the Company’s filed proposal, the real-time exports, ELAP
hourly market prices, contribution capacity, and peak annual exports would be updated
annually based on historical export and market data. Additionally, the Company proposed
to update the levelized cost of an avoided resource, hours of capacity need, T&D deferral,
line losses, and integration costs on a routine basis.115 These inputs are based on other
Company filings that are completed on a consistent cycle.
Staff Position
Staff believes updating the real-time exports, ELAP hourly market prices,
contribution capacity, and peak annual exports on an annual basis is a reasonable
amount of time between updates to help ensure rates closely resemble market conditions
while balancing the need for rate stability for customer generators.116 Staff agrees with
the Company’s proposal to file updates on April 1. Staff notes that if the Company were

115 Anderson DI at 29-33.
116 Staff Comments at 30 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 55
to update the hours of capacity need as part of a condensed filing timeline, Staff would
not be able to complete a thorough review of the proposed changes and their supporting
documentation. Staff agrees with the Company’s proposal to update the levelized cost of
avoided resource, T&D deferral, line loss and integration costs on a routine basis specific
to each input as proposed in the Company’s filing.117
However, Staff disagrees with the Company’s proposal to update the hours of
capacity need for on-peak hours in the proposed annual filing. Staff recommends that the
Commission order the Company to update the hours of capacity need in a separate filing.
Staff suggests that any changes to the structure of the ECR (i.e., season length, hours,
how credits are applied, etc.) should trigger a new case with ample time for all parties to
review and provide input.118
Vote Solar Position
Vote Solar recommends that the ECR should be locked-in for individual customers
with on-site generation at the rate effective at the time of the customer’s application to
interconnect their system for a period of at least 10 years.119 Vote Solar believes that it
“is impossible for a prospective solar customer to predict their long-term savings from
installing solar when they are subject to an export rate that changes every year.”120 Vote
Solar cites similar vintaging treatment that occurs in Nevada and Arizona. Vote Solar
supports Staff and CEO’s recommendation that if an ECR is implemented, the first annual

117 Staff Comments at 31 (Oct. 12, 2023).
118 Id.
119 Vote Solar Comments at 36 (Oct. 12, 2023).
120 Id.

IDAHO POWER COMPANY’S FINAL COMMENTS - 56
update should be effective June 1, 2025, and supports an ECR update period longer than
one year.121
Other Party Positions
ICL recommends the Commission approve an update period every two years to
follow Idaho Power’s IRP cycle.122 City of Boise recommends that any changes “be
phased in over a reasonable implementation period” but does not specify a specific
recommendation for timing.123 However, City of Boise also suggests that “the Company’s
proposed methodology for determining annual updates to the ECR could be
reasonable.”124
CEO and IIPA do not specify a recommendation for updates to the ECR.
Idaho Power Position
The Company recommends the Commission approve its revised proposal to
update the components of the ECR annually in a filing on April 1, with an effective date
of June 1, and to have any changes to the season and hours of highest risk be updated
as part of a separate filing.
The Company does not support Vote Solar’s recommendation to vintage
customers by year and lock-in the ECR at the time the customer interconnects. In its
justification, Vote Solar highlights similar vintaging of customer’s credits for exports in
other jurisdictions as a reason for why this Commission should follow suit; however it is

121 Vote Solar Reply Comments at 19 (Nov. 2, 2023).
122 ICL Reply Comments at 5 (Nov. 2, 2023).
123 City of Boise Comments at 3 (Oct. 12, 2023).
124 Id. at 6.

IDAHO POWER COMPANY’S FINAL COMMENTS - 57
important to note, at least one of the jurisdictions referenced – Arizona – is currently
considering a change to its 10-year export rate effective period and grandfathering policy
for net metering customers.125 Additionally, Vote Solar’s primary rationale for this proposal
is to provide certainty to customers regarding their ability to pay off their investment. The
Company believes this rationale ignores previous Commission orders:
[W]e want to reiterate here that the purpose of establishing a NEM rate is
not to ensure that customers who have installed self-generation facilities
are able to recoup their investment or earn a return on investment, it is to
ensure that customers are paid fair, just, and reasonable rates for their
exports and non-self-generating customers are not subsidizing the rates for
self-generating customers.
. . .
As we cautioned many times before, tariffs are not contracts and are subject
to change. Order No. 35284 at 10. It should come as no surprise to anyone
who invested in an on-site generation solar system after December 20,
2019, that the Company may be authorized by the Commission to change
fundamental aspects of its NEM program—including the imposition of an
ECR—which can affect the payback period for customers. Idaho Code §
48-1805 states that every solar installer must provide notice to a potential
customer, in capital letters, “with substantially the following form and
content: ‘LEGISLATIVE OR REGULATORY ACTION MAY AFFECT OR
ELIMINATE YOUR ABILITY TO SELL OR GET CREDIT FOR ANY
EXCESS POWER GENERATED BY THE SYSTEM AND MAY AFFECT
THE PRICE OR VALUE OF THAT POWER.’” We reiterate that a ‘reputable
seller of onsite generation systems would not and will not represent that the
program will never change.’ Order No. 34892.126

The Company will further address the recommendations by Parties to delay the
first annual update effective date to June 1, 2025, in its comments below regarding
transition/gradualism considerations.

125 In the Matter of the Application of the Arizona Corporation Commission’s Exploration of Changes to
the Up to 10 % Annual Reduction in the Export Credit Rate and the 10-Year Export Rate Effective Period
Under the Resource Comparison Proxy Methodology Approved in the Value and Cost of Distributed
Generation Docket (E-00000J-14-0023), Docket No. AHD-00000J-23-0273, Hearing Division
Memorandum (Oct. 16, 2023).
126 Case No. IPC-E-22-22, Order No. 35631 at 28, 30 (emphasis in original).

IDAHO POWER COMPANY’S FINAL COMMENTS - 58
V. TRANSITION/GRADUALISM CONSIDERATIONS
Summary of Transition/Gradualism Positions
Party Idaho Power
(Filed) Staff Vote Solar Other Idaho Power
(Revised)
Position None First Annual
Update
June 1, 2025
Multi-Year Glide
Path from Retail
Rate to ECR
CEO - First Annual
Update June 1, 2025

City of Boise – Delay
until June 1, 2024
First Annual
Update
June 1, 2025

After reviewing the relevant Commission orders and considering the extensive
communication by the Company and Commission to notify customers of the potential for
change, the Company did not include a proposal for transition and proposed that the
successor service offering should be applicable to all customers that the Commission
defines as not being grandfathered into the existing monthly NEM one-for-one kWh
compensation structure.
Staff Position
Staff does not recommend any transition period.127 Staff notes that the Company,
the Commission, and several intervening parties have been involved in changing the NEM
service offering since 2017 through a multitude of dockets. Staff believes the processing
of these dockets has provided customers with enough notice of potential changes that
additional transition to an ECR is not necessary. Staff does not recommend expanding
grandfathering, or legacy status, and believes that the Commission has been clear
through Order Nos. 34509, 34546, and 34854, that legacy status will not be expanded.128
However, Staff believes that under the Company’s proposal, customers will not
have had sufficient time to adjust to the new rate before the first proposed update to the

127 Staff Comments at 40 (Oct. 12, 2023).
128 Staff Reply Comments at 7 (Nov. 2, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 59
ECR. From the proposed ECR effective date of January 1, 2024, on-site generation
customers would only receive three bills showing the impact of the ECR before the
Company files its first update. Staff believes this may cause customer confusion and
therefore recommends that the Company delay the first effective update to the ECR until
June 1, 2025.129
Vote Solar Position
Vote Solar recommends the Commission implement a transition, if the ECR is
lower than the retail rate, by setting the initial ECR equal to the value of the average
volumetric retail rate for each customer class.130 Vote Solar recommends the rate decline
by a maximum amount, for example five percent, as the total capacity of on-site
generation installed in Idaho Power’s service area reaches defined thresholds.
Additionally, Vote Solar recommends customers remain on the rate current at the time
they apply for 10 years.
Other Party Positions
CEO supports Staff’s proposal to set the effective date for Schedule 84 as January
1, 2024, and the first update to occur June 1, 2025.131 ICL recommends the Commission
provide one year transitional period for Schedule 6 and 8 but no transition period for
Schedule 84.132 City of Boise recommends the Commission delay implementation of any

129 Staff Comments at 31 (Oct. 12, 2023).
130 Vote Solar Comments at 48 (Oct. 12, 2023).
131 CEO Reply Comments at 2 (Nov. 2, 2023).
132 ICL Comments at 2 (Oct. 12, 2023) and ICL Reply Comments at 5 (Nov. 2, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 60
changes in this docket until June 1, 2024, delay the first update until June 1, 2025, and
implement a transition period to phase in the ECR by 25 percent every two years.133
IIPA does not address transition/gradualism considerations.
Idaho Power Position
The Company is not opposed to the recommendation by Staff to delay the first
annual update to be filed April 1, 2025, with an effective date of June 1, 2025. The
Company agrees with Staff that it can use this “acclimation period” to provide educational
materials and for customers to adjust to the real-time net billing structure.134
The Company opposes all components of Vote Solar’s proposed transition. As
explained in its discussion of updates to the ECR, the Company believes locking in rates
for customers is inconsistent with previous Commission orders cautioning that tariffs are
not contracts and are subject to change.135 Additionally, the proposed transition would
result in a continuation of the cost shift from customer-generators to customers without
on-site generation. Vote Solar’s proposed transition would also impact other
considerations in the Company’s proposal. For example, modifications to the project
eligibility cap while customers continue to be overcompensated for their on-site
generation would exacerbate the problem that the existing cap was intended to address.
The application and transferability of financial credits also would need to be reconsidered
under any transition that results in an ECR which is higher than the avoided cost during
the transition period. If the Commission finds that an accurately valued ECR is aligned

133 City of Boise Comments at 6 (Oct. 12, 2023) and City of Boise Reply Comments at 5-6 (Nov. 2, 2023).
134 Staff Comments at 31-32 (Oct. 12, 2023).
135 Case No. IPC-E-21-21, Order No. 35284 at 10.

IDAHO POWER COMPANY’S FINAL COMMENTS - 61
with the Company’s proposal, it should be implemented for all customers the Commission
defines as not being grandfathered to mitigate – not intensify – the existing cost shift to
non-participants. However, in the event the Commission believes a transition period is
appropriate, the Company recommends it also considers delaying any modification to the
Schedule 84 project eligibility cap and reevaluate the proposed transfer criteria for excess
credits for the reasons discussed herein and in the Company’s Application.
VI. OTHER CONSIDERATIONS
A. Modifications to Project Eligibility Cap
Summary of Project Eligibility Cap Positions
Party Idaho Power
(Filed) Staff Vote Solar Other Idaho Power
(Revised)
Position Modify Schedule
84 Cap to 100%
of demand or
100 kW
Modify Schedule
84 Cap to 100%
of demand or
100 kW
Modify Schedule
84 Cap to 100%
of demand or
100 kW
Modify Schedule
84 Cap to 100%
of demand or
100 kW
Modify Schedule
84 Cap to 100%
of demand or
100 kW

The Company did not propose changes to the eligibility cap for Schedule 6 and
Schedule 8 customers because it believes the current cap of 25 kW is not limiting for
these customers. Coincident with the implementation of the proposed ECR, the Company
proposed modifying the Schedule 84 eligibility cap to 100 kW or 100 percent of demand
concurrent with a change to real-time net billing with a cost-based ECR.136 The
Company’s rationale for a demand-based cap for Schedule 84 cited concerns regarding
the ongoing cost associated with upgrades, that it does not routinely install facilities larger
than customer demand in other situations, and alignment with the intent of net metering
to offset energy usage behind the meter.137

136 Application at 3.
137 Ellsworth DI at 28, ll. 4-15.

IDAHO POWER COMPANY’S FINAL COMMENTS - 62
Additionally, the Company proposed that for systems with energy storage devices,
only the amount of generation nameplate capacity be used to determine whether the cap
is exceeded for Schedules 6, 8, and 84. If the aggregate capacity of generation and
storage triggers the need for upgrades to the system, the customer would be required to
pay the upfront cost.
Staff Position
Staff agrees with the Company’s proposal to maintain the project eligibility cap for
Schedule 6 and Schedule 8 but recommends the Company monitor when the cap
becomes limiting and consider changes to the cap if warranted.138 Additionally, Staff
recommends approval of the Company’s proposed eligibility cap for Schedule 84
customers to be the greater of 100 kW or 100 percent of demand.139
Staff also addresses several items regarding administration of a demand-based
project eligibility cap for Schedule 84: (1) how demand is determined, (2) demand
changes after installation, (3) additional interconnection requirements, and (4) additional
costs for system upgrades triggered by the addition of energy storage.140

138 Staff Comments at 33 (Oct. 12, 2023).
139 Id.
140 Id. at 33-38.

IDAHO POWER COMPANY’S FINAL COMMENTS - 63
Other Party Positions
Vote Solar, CEO, ICL, and City of Boise are generally supportive of the Company’s
proposal to modify the project eligibility cap for Schedule 84 and did not oppose the
recommendation to modify the application of the project eligibility cap to energy storage
not counting towards the defined capacity limits.141
IIPA did not comment on the proposed modification to the project eligibility cap for
Schedule 84.
Idaho Power Position
The Company continues to recommend the Commission maintain the project
eligibility cap for Schedule 6 and Schedule 8, and to modify the cap for Schedule 84 to
the greater of 100 kW and 100 percent of a customer’s demand. However, as mentioned
in its discussion of transition/gradualism, the Company has concerns with modification to
the cap if a transition period, such as Vote Solar suggests, were to be implemented. The
resulting transition, and therefore the corresponding delay in mitigating cost-shift, wouldn’t
match the timing for modification of the existing cap.
(1) How Demand is Determined for Schedule 84 Customers
Staff describes its concerns with the Company’s proposal for how to determine the
cap for customers without 12 months of billing data (i.e., Scenario B and C in Staff’s
Comments).142 To clarify, the Company did not propose to simply rely on a customer’s
beliefs as Staff interpreted its proposal. However, the Company’s revised proposal to
address Staff’s concern is that any customer without full 12 months of billing data could

141 Vote Solar Comments at 48-49 (Oct. 12, 2023) and CEO Comments at 8 (Oct. 12, 2023).
142 Staff Comments at 34 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 64
install up to their registered demand in the available billing months. In any case that a
Schedule 84 customer has a projected load ramp that exceeds actual billing demand
data, the Company proposes requiring the customer to provide an analysis of the facility’s
power needs performed by a third-party professional engineer and paid for by the
customer. An analysis by a professional engineer must include a detailed load analysis
based on the equipment that will be used at the service point. If the customer has a similar
business/service point (e.g., chain store) within Idaho Power’s service area, the customer
could use this as a proxy to reference that premise’s demand for Idaho Power to
determine whether the analysis by a professional engineer could be waived. The
Company believes it would be prudent to include additional language as part of Schedule
84 to clarify how determination of the project cap will be administered. If the Commission
approves the Company’s revised proposal, the Company will incorporate the necessary
conditions into Schedule 84 as part of its compliance filing for Staff and Commission
review.
(2) Demand Changes After Installation for Schedule 84 Customers
The Company proposed in its filing to maintain a customer’s current system size if
a customer’s demand decreases or if a new customer takes over the premises with a
lower power requirement. If a customer’s demand increases after the initial installation,
an expansion can be conducted pursuant to Schedule 68 by applying for a system
modification.143 Staff agrees with the Company’s proposal but recommends that the
description of the treatment be incorporated in Schedule 84 language. The Company
believes it would be prudent to include additional language as part of Schedule 84 to

143 Application at 22-23 and Anderson DI at 9-10.

IDAHO POWER COMPANY’S FINAL COMMENTS - 65
clarify how a system expansion would be handled. If the Commission approves the
Company’s proposal, the Company will incorporate the necessary language into
Schedule 84 as part of its compliance filing for Staff and Commission review.
(3) Additional Interconnection Requirements for Schedule 84
The Company proposed the following additional interconnection requirements in
Schedule 68 to accommodate the increase of the project eligibility cap for Schedule 84:
 Inverter-based generation of 100 kW and greater will provide
documentation to validate inverter settings.
 A power plant controller or a properly configured inverter will be installed on
the customer’s side of the point of delivery for systems 500 kW and greater.
 The existing uniform interconnection agreement and requirements
applicable to non-exporting systems larger than 3 MW will apply to exporting
systems 3 MW and greater.
Staff recommends approval of these changes in Schedule 68 as necessary to
interconnect exporting systems larger than 100 kW safely and reliably due to the increase
of the project eligibility cap for Schedule 84. Additionally, through responding to discovery,
the Company identified an additional modification to Schedule 68 is necessary to ensure
a prospective customer pays all costs incurred as part of the interconnection process. As
further explained in the Supplemental Response to the Ninth Production Request of the
Commission Staff in Response No. 55, included as Attachment No. 2, the Company
believes it is necessary to require projects greater than 100 kW to require a $1,000
deposit for any project where the Feasibility Review determines that a Feasibility Study
is required. This provision will ensure the Company is made whole for all costs incurred

IDAHO POWER COMPANY’S FINAL COMMENTS - 66
to evaluate the interconnection requirements for a prospective on-site generation
customer and that those costs are not borne by other customers. The Company believes
it would be prudent to include additional language as part of Schedule 84 to clarify the
deposit requirement for any project that requires a Feasibility Study be conducted. If the
Commission approves the Company’s request to increase the project eligibility cap for
Schedule 84 customers, the Company will incorporate this provision into Schedule 68 as
part of its compliance filing for Staff and Commission review.
(4) Upgrade Costs for Systems with Battery Storage
While, as a matter of principle, the Company is not opposed to Staff’s
recommendation for customers to fund ongoing operations and maintenance cost
associated with required system upgrades, the administration of such a charge is
potentially complex and burdensome. Accordingly, the Company respectfully requests
the Commission to direct Idaho Power and Staff to meet to discuss the feasibility of
implementing and administering a potential surcharge for the ongoing operations and
maintenance expense associated with system upgrades. Additionally, the Company
respectfully requests the Commission direct it to submit its findings and recommendation
in this docket for Commission consideration within 90 days of the Commission’s final
order.

IDAHO POWER COMPANY’S FINAL COMMENTS - 67
B. Recovery of ECR Expenditures
The Company recommends recovery of ECR expenditures as a net power supply
expense subject to 100 percent recovery through the PCA. Staff agrees with the
Company that the energy purchased from self-generators is a must-take resource and
should be recovered through the PCA.144
Vote Solar, CEO, ICL, City of Boise, and IIPA did not comment on the Company’s
proposal regarding recovery of ECR expenditures.
C. Financial Credit Use and Transferability
The Company proposed two recommendations for future use and transferability of
accumulated financial credits: (1) non-legacy customers be allowed to transfer financial
credits to other accounts held in their name for their own usage and (2) financial credits
apply to all billing components, including customer service charge, energy charges,
riders, and other billing components.
Staff and Vote Solar support the Company’s recommendation for the ECR financial
credits to offset all billing components and that customers be permitted to transfer
financial credits to other accounts in their name.145 Additionally, Vote Solar suggests that
customers should receive a payment for the value of any unused financial credits
remaining at the conclusion of their annual billing cycle. In contrast, ICL suggests the
financial value of unused financial credits should roll over into the next annual billing
period.146

144 Staff Comments at 39 (Oct. 12, 2023).
145 Staff Comments at 38 (Oct. 12, 2023) and Vote Solar Comments at 38 (Oct. 12, 2023).
146 ICL Comments at 2 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 68
The Company recommends the Commission reject Vote Solar’s proposal to
provide a financial payment to customers. Rejecting this proposal is consistent with the
Commission’s prior decisions:
[T]he primary thrust of net metering is to provide customers
the opportunity to offset their own load and energy
requirements. See Order No. 28951 at 11 (Case No. IPC-E-
01-39). We find that allowing a [bankable credit] furthers the
intent of net metering by encouraging potential net metering
customers to install only the distributed generation that they
need to offset their load. Conversely, we find that allowing a
financial payment for excess net energy would encourage
customers to install more distributed generation than they
need so they can sell excess power at wholesale to the
Company without entering into a power purchase contract
under Schedule 86. . . Again, the purpose of net metering is
to allow a customer to offset usage, not to sell power to the
Company. If a customer wishes to become a power seller,
then the customer must proceed with a contract under
Schedule 86.147

The Company also notes that under the Company’s filed proposal customer-
generator's unused financial credits would roll over into the next annual billing period as
requested by ICL. In fact, under the Company’s filed proposal the customer-generator's
unused financial credits would be retained indefinitely so long as the customer continues
taking service at the Point of Delivery associated with the Exporting System.

147 In the Matter of Idaho Power Company’s Application for Authority to Modify its Net Metering Service
and to Increase the Generation Capacity Limit, Case No. IPC-E-12-27, Order No. 32880 at 3 (Aug. 14,
2013) (emphasis in original).

IDAHO POWER COMPANY’S FINAL COMMENTS - 69
D. Financial Credit Expiration
The Company’s proposed tariff language for Schedules 6, 8, and 84 includes a
provision in the “Conditions of Purchase and Sale” that states:
Credits are non-transferrable in the event that a customer
relocates and/or discontinues service at the Point of Delivery
associated with the Exporting System. Any unused credits will
expire at the time the final bill is prepared.

The language is consistent with the provision for net energy metering as approved
by the Commission in Order No. 32846.148 However, Staff recommends that the
Commission order the Company to transfer financial credits to the customers new meter
when a customer relocates within the Company’s system or refund the amount of
accumulated financial credits to the customer in the event they relocate outside the
Company’s system.149
For the reasons discussed in the previous section regarding the transferability of
financial credits and the primary thrust of net metering, the Company recommends the
Commission reject the proposal to provide a financial payment to a customer in any event.
The Commission previously evaluated the merits of providing a financial credit, stating
that a financial payment
. . . may incent potential net metering customers to overbuild
their systems. The net metering tariff is for those who wish to
offset a portion of their load. Those wishing to be wholesale
power providers should look to Schedule 86 as the vehicle for
that type of transaction. We believe that removing the cash
payment takes away this gaming opportunity and encourages
customers to right-size their systems.150

148 Case No. IPC-E-12-27, Order No. 32846 at 15, 19 (Jul. 3, 2013).
149 Staff Comments at 39 (Oct. 12, 2023).
150 Case No. IPC-E-12-27, Order No. 32846 at 15.

IDAHO POWER COMPANY’S FINAL COMMENTS - 70
The Company is not, however, opposed to Staff’s second recommendation to
transfer a financial credit to other service points or meters on the customer’s account
when they relocate within the Company’s service area. Because the proposed transfer
when a customer relocates would require a manual process, if the Commission ultimately
adopts Staff’s recommendation, the Company requests the Commission limit the time
period under which it must track the financial credit. Accordingly, the Company requests
the Commission find that the transfer of financial credits must occur within six months of
the account being closed or be forfeited if not transferred. This provision is important
because the Company’s system is not able to hold a financial credit on a closed account
indefinitely. It should be noted that in the event a financial credit on a closed account is
forfeited, the Company will record the entire amount as a credit to the PCA, which is a
benefit to all customers with no shareholder benefit.
E. Accumulated kWh Conversion Rate and Timeframe
The Company has proposed that any accumulated kWh credits be converted to a
financial credit for customers with non-legacy systems as of December 31, 2024, using a
blended average retail energy rate to value any excess kWh credits. The calculation of
the blended average retail energy rate for each non-legacy customer class is the sum of
charges for energy, Fixed Cost Adjustment (“FCA”), and PCA, divided by the total kWh
consumed.
Staff recommends approval of the Company’s use of a blended average retail
energy rate to convert excess accumulated kWh credits at the end of 2024. Staff also
notes that the Company should notify each non-legacy customer with excess kWh credits
as of December 31, 2024, of how their excess credits will be converted, at what rate, and

IDAHO POWER COMPANY’S FINAL COMMENTS - 71
how it will be displayed on their next bill. Staff also supports the Company’s proposal that
the conversion of accumulated kWh credits to a financial credit be recovered through the
FCA for Residential and Small General Service customers and the PCA for Commercial,
Irrigation, and Industrial customers.151
Vote Solar, CEO, ICL, City of Boise, and IIPA did not comment on the treatment
of accumulated kWh credits and the conversion to a financial credit.
VII. CONCLUSION
The instant case is reflective of the larger national debate surrounding NEM, which
unfortunately often finds stakeholders at cross-purposes, with utility efforts to modify NEM
rules or rate design met with stiff resistance from solar contractors and customers and
others that desire to maintain the status quo. Like in prior dockets, the members of the
public that have chosen to participate in this case generally disfavor changes to Idaho
Power’s net metering practice, with common concerns being the high cost they paid for
their solar generation system, the impact that the proposed changes would have on the
payback period for customers (potentially making them unwilling or unable to pay for an
expensive solar system), and unawareness that fundamental aspects of NEM could
change.
Though Idaho Power is not privy to the details of the bilateral transactions between
sellers or installers of on-site generation systems and their customers, a number of
stakeholders appear to put the onus on the utility for ensuring the transaction is equitable
and economically supportable. This, however, is not within Idaho Power’s purview. As a
publicly regulated utility, Idaho Power is differently situated than a private seller or

151 Staff Comments at 40 (Oct. 12, 2023).

IDAHO POWER COMPANY’S FINAL COMMENTS - 72
installer; it is accountable to the Commission and legally obligated to consider the
collective interests of all its customers and to recommend rates that are just, reasonable,
and non-preferential.
Idaho Power understands and appreciates that some customers desire to offset
their energy bills through on-site self-generation and help reduce demand on the
Company’s system; goals that are consistent with the underlying intent of the Company’s
on-site generation offerings: to provide customers the opportunity to serve some of their
load through their own generation. These objectives, however, cannot be achieved with
a blind eye to the cost and effects on non-participants nor can the business or personal
interests of solar contractors and customers be pursued at the expense of non-
participating customers. The Company has a responsibility to approach this issue with a
focus on establishing mechanisms and rates that lead to safe, reliable, and affordable
energy for customers, rather than as a means to achieve particular policy goals. The
proposal presented in this docket, as summarized on pages 4 – 7 of these comments,
was developed by the Company pursuant to these fundamental principles and, consistent
with the study approved in Case No. IPC-E-22-22, will help ensure that on-site generation
continues to play an important role in the Company’s energy portfolio well into the future.

DATED at Boise, Idaho, this 16th day of November 2023.

MEGAN GOICOECHEA ALLEN
Attorney for Idaho Power Company

IDAHO POWER COMPANY’S FINAL COMMENTS - 73
CERTIFICATE OF SERVICE

I HEREBY CERTIFY that on the 16th day of November 2023, I served a true and
correct copy of Idaho Power Company’s Final Comments 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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Matthew A. Nykiel
Idaho Conservation League
710 North 6th Street
Boise, Idaho 83702

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Brad Heusinkveld
Idaho Conservation League
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Idaho Irrigation Pumpers
Association, Inc.
Eric L. Olsen
ECHO HAWK & OLSEN, PLLC
505 Pershing Avenue, Suite 100
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Pocatello, Idaho 83205
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IDAHO POWER COMPANY’S FINAL COMMENTS - 74
Lance Kaufman, Ph.D.
2623 NW Bluebell Place
Corvallis, OR 97330
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Clean Energy Opportunities for
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Kelsey Jae
Law for Conscious Leadership
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Michael Heckler
Courtney White
Clean Energy Opportunities for Idaho
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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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Micron Technology, Inc.
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IDAHO POWER COMPANY’S FINAL COMMENTS - 75
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
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Abigail R. Germaine
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Boise, ID 83701
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Kate Bowman
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Vote Solar
299 S. Main Street, Suite 1300
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Salt Lake City, UT 84111
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Stacy Gust, Regulatory Administrative
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BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-14

IDAHO POWER COMPANY

ATTACHMENT NO. 1
Revised Workpaper
SEE ATTACHED SPREADSHEET

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-14

IDAHO POWER COMPANY

ATTACHMENT NO. 2
Supplemental Response to the Ninth Production
Request of the Commission Staff

IDAHO POWER COMPANY’S SUPPLEMENTAL RESPONSE TO THE NINTH 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

)
)
)
)
)
)
)
)
)

CASE NO. IPC-E-23-14

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

COMES NOW, Idaho Power Company (“Idaho Power” or “Company”), and in
response to the Ninth Production Request of the Commission Staff (“Commission” or
“Staff”) dated September 13, 2023, herewith submits the following supplemental
information:

IDAHO POWER COMPANY’S SUPPLEMENTAL RESPONSE TO THE NINTH PRODUCTION
REQUEST OF THE COMMISSION STAFF - 2
STAFF REQUEST FOR PRODUCTION NO. 55: Please explain whether the
Company plans to charge customer generators for the cost of a power needs analysis, if
needed, for the following cases:
a. To ensure they do not go over the eligibility cap if a customer is new, doesn’t
have historical billing data available, or they are a new customer with demand that
exceeds prior customer needs; and
b. To determine if the sum of the customer' s generation nameplate capacity
plus the capacity of a battery exceeds the eligibility cap or requires an upgrade.
SUPPLEMENTAL RESPONSE TO STAFF’S REQUEST FOR PRODUCTION
NO. 55: After filing its initial response, Staff requested additional information regarding
any study or review required for a customer-generator. Idaho Power provides this
supplemental response to address potential study costs or system review costs and how
those would be funded by the customer/applicant.
Pursuant to Schedule 68, an initial Feasibility Review occurs for all customer-
generator applications, after which, as discussed in Response to Staff’s Request for
Production No. 46, there are up to three interconnection studies that may be required as
part of the interconnection process consisting of (1) Feasibility Study, (2) System Impact
Study, and (3) Facility Study. These steps and associated costs are described in more
detail as follows:
(1) Feasibility Review: Standard engineering review of a proposed customer-
generator system intended to ensure the Company’s system is equipped to
incorporate the proposed facilities. The Feasibility Review may determine
that upgrades are necessary. Funding, construction, installation, and
maintenance of required upgrades will be subject to the Company’s
standard Rule H regarding New Service Attachments and Distribution Line
Installations or Alterations. The cost of the Feasibility Review is covered by
the cost of the $100 application fee.

IDAHO POWER COMPANY’S SUPPLEMENTAL RESPONSE TO THE NINTH PRODUCTION
REQUEST OF THE COMMISSION STAFF - 3

(2) Feasibility Study: More detailed engineering assessment for Distributed
Energy Resources (“DERs”) as determined by the Feasibility Review. This
study includes protection coordination and system voltage management
requirements necessary for the project. For projects under 3 MVA,
Schedule 68 does not require a deposit, but the $100 application fee does
not cover the cost of the study. For projects 3 MVA or greater, the $1,000
application fee is applied against costs the Company incurs to perform the
Feasibility Study. The Company believes it would be appropriate, and
consistent with larger projects, to require a $1,000 deposit for any project
where the Feasibility Review determines that a Feasibility Study is required.
Please see the file labeled “Attachment – Supplemental Response to Staff
Request No. 55” for the Company’s proposed revision to Schedule 68.

(3) System Impact Study (only applicable for projects 3 MVA or greater): The
System Impact Study provides a detailed assessment of the distribution
and/or transmission system adequacy to accommodate the DER by
evaluating equipment capabilities and electrical performance requirements.
This step may not be necessary for some projects, depending on the size
and location of the project. The System Impact Study Agreement includes
a deposit of $2,000 for a distribution system impact study or a $10,000
deposit for a transmission system impact study.

(4) Facility Study (only applicable for projects 3 MVA or greater): The Facility
Study includes the engineering to determine the project's design
specifications. The Facility Study Agreement includes a deposit of 5% of the
total project costs specified in the System Impact Study Report ("SISR") or
the Feasibility Study Report if a SISR is not required, capped at $30,000.

The response to this Request is sponsored by Jared L. Ellsworth, Transmission,
Distribution & Resource Planning Director, Idaho Power Company.