20221219Final_Order_No_35631.pdf

ORDER NO. 35631 1
Office of the Secretary
Service Date
December 19, 2022
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

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
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CASE NO. IPC-E-22-22

ORDER NO. 35631

On June 30, 2022, Idaho Power Company (“Company” or “Idaho Power”) applied to the
Commission requesting the Commission complete the study review phase of the comprehensive
study of the costs, and benefits, of on-site customer generation and for authority to implement
changes to Schedules 6, 8, and 84 (“Application”). In conjunction with its Application, the
Company also filed the Value of Distributed Energy Resources study (“VODER Study or “Study”)
along with 31 appendices, a customer notice and bill insert, and the Direct Testimony of Grant T.
Anderson, regulatory consultant.
On July 14, 2022, the Commission issued a Notice of Application and Notice of a 21-day
Intervention Deadline. Order No. 35464.
The Commission granted intervention to Clean Energy Opportunities for Idaho (“CEO”),
Idaho Hydroelectric Power Producers Trust, an Idaho Trust, d/b/a IdaHydro, Idaho Irrigation
Pumpers Association, Inc. (“IIPA”), Idaho Conservation League (“ICL”), Industrial Customers of
Idaho Power, the city of Boise City (“Boise City”), Richard E. Kluckhohn, and Wesley A.
Kluckhohn pro se, Micron Technology Inc., ABC Power Company LLC, and Idaho Solar Owners
Network, (“Intervenors” and collectively, with Commission Staff (“Staff”) and the Company, the
“Parties”). Order Nos. 35472, 35493, 35499, and 35505.
On August 24, 2022, the Commission issued a Notice of Schedule, Notice of Workshops,
and set deadlines for the Parties to file initial written comments and reply comments, and for the
Company to file final response comments. Order No. 35512. The Commission also set a deadline
for persons to file written comments on the Study and to further reply to all party comments. Id.
The Commission ordered Staff and the Parties to work together to develop potential customer
hearing times and dates. Id.
ORDER NO. 35631 2
On October 7, 2022, the Commission issued a Notice of Public Hearings. Order No. 35558.
The Commission also extended the non-party written comment deadline to November 4, 2022.
Staff, the Company, CEO, IIPA, ICL, and Boise City filed initial and reply comments. On
October 26, 2022, the Company filed final response comments, an updated VODER Study
(“October VODER Study” or “October Study”) in both a clean and redlined format, and 35
supporting appendices.
On October 27, 2022, the Commission held an in-person customer hearing in Pocatello
where 27 people provided testimony on the record. On November 2, 2022, the Commission held
an in-person customer hearing in Twin Falls where 12 people provided testimony on the record.
On November 3, 2022, the Commission held an in-person customer hearing at its office in Boise
where 46 people testified on the record. In addition, over 950 public comments were received.
With this Order, as set forth below, we acknowledge the Study and direct the Company to make
implementation recommendations to its on-site generation program offerings in a future case.
BACKGROUND
An “On-Site Customer-Generator” or “Customer-Generator” is defined as a “customer
applying to operate or operating a DER [Distributed Energy Resource] in parallel with the electric
utility system.” VODER Study at xvii. Rooftop solar is an example of a DER as it is a “source of
electric power that is not directly connected to the BPS [Bulk Power System].” Id. at xiii. The
Company’s “Net-Metering” or “Net-Energy Metering” (“NEM”) program allows customers to
generate electricity, most commonly using photovoltaic technologies, i.e., solar panels, and export
any energy they produce in excess of what they consume back to the utility grid in exchange for a
kilowatt-hour (“kWh”) energy credit on their bill that can be used to offset their energy
consumption within the current or future billing cycles. VODER Study at xvi. NEM merely
requires a “single bi-directional meter read for the billing period.” Id.
An alternative to NEM is a “Net Billing” compensation structure. Unlike NEM, Net Billing
requires advanced metering technology with one channel that separately measures energy exported
to the grid and another channel that measures energy consumed by the customer. Id. at 16. Under
Net Billing, a customer does not receive a kWh credit that can offset future energy consumption.
Rather, under Net Billing, the amount paid to a customer generator for exported energy is referred
to as the “Export Credit Rate” (“ECR”) which is assigned a monetary value (ECR value). Id. at
xvi, 17.
ORDER NO. 35631 3
On-site generating customers who export to the Company’s system are currently billed
under the following rate schedules: Schedule 6, Residential service On-Site Generation, (Schedule
6”), Schedule 8 Small General Service On-Site Generation (“Schedule 8”), and Schedule 84
Customer Energy Production/Net Metering Service (“Schedule 84”) (collectively, “NEM
Schedules”). Id. at 4.
A. Case No. IPC-E-17-13
In 2017, the Company applied to the Commission to, among other things, close its
residential and small general service (“R&SGS”) net-metering service schedule to new customers,
establish a new customer classification for R&SGS customers with on-site generation, and
commence a generic docket “to establish a compensation structure for customer-owned . . . DER
. . . that reflects both the benefits and costs that DER interconnection brings to the electric system.”1
In that case, the Commission approved the creation of Schedule 6 for residential, on-site
generating customers, and Schedule 8 for small general service customer generators. Order No.
34046 at 15, 30, 31. The Commission also ordered Idaho Power “to initiate a docket to
comprehensively study the costs and benefits of on-site generation on Idaho Power’s system, as
well as proper rates and rate design, transitional rates, and related issues of compensation for net
excess energy provided as a resource to the Company.” Id. at 31.
B. Case No. IPC-E-18-15
In Case No. IPC-E-18-15, the Company petitioned the Commission to “initiate a docket to
‘comprehensively study the costs and benefits of on-site generation on Idaho Power’s system, as
well as proper rates and rate design, transitional rates, and related issues of compensation for net
excess energy provided as a resource to the Company’ as envisioned by Order No. 34046.”2
The parties in Case No. IPC-E-18-15 agreed to a proposed settlement that, if approved,
“would have changed a number of fundamental aspects to the Company’s net-metering program.”
Order No. 34509 at 2. However, the Commission rejected the proposed settlement agreement
because it found the record was inadequate to determine whether the settlement agreement was
fair, just, reasonable, and in the public interest. Id. at 6. The Commission specifically found that
the public was not “adequately notified” that significant changes to the net-metering program

1 ln the Matter of Idaho Power Company’s Application for Authority to Establish New Schedules for Residential and
Small General Service Customers with On-Site Generation, Case No. IPC-E-17-13, Application at 2 (July 27, 2018).
2 ln the Matter of the Application of Idaho Power Company to Study the Costs, Benefits, and Compensation of Net
Excess Energy Supplied by Customer On-Site Generation, Case No. IPC-E-18-15, Petition at 1 (October 19, 2018).
ORDER NO. 35631 4
would occur in Case No. IPC-E-18-15. Id. The Commission found that filing the settlement
agreement “in the absence of a comprehensive study does not comply with our directive to parties
in Order No. 34046.” Id.
As such, the Commission determined the Company must “prepare and file a credible and
fair study on the costs and benefits of distributed on-site generation to the Company’s system.” Id.
at 9 (capitalization omitted). In delineating the scope and nature of the study, the Commission
determined that the study should use the “most current data possible that is readily available to the
public”; that the Company design the study “in coordination with the parties and the public,” with
“the final scope of the study . . . [to be] . . . determined by the Commission,” and that the study be
“written so it is understandable to an average customer, but its analysis must be able to withstand
expert scrutiny.” Id. The Commission clarified that before “the Company files a case to change its
net-metering program structure, the Commission must approve the study as credible and fair.” Id.
The Commission contemplated that, in the “‘study design’ phase, the public will be able to
comment on what questions they would like the study to address.” Id. at 9-10. The Commission
also envisioned there being a “‘study review’” phase where the public could “comment on whether
the study sufficiently addressed their concerns, and their opinions on what the study shows.” Id. at
10.
The Commission ordered the Company to “submit a comprehensive study of the costs and
benefits of net metering to the Commission before any further proposals to change the Company’s
net-metering program.” Id. at 17. The Commission ordered “[t]his study . . . [to] . . . incorporate
public feedback and concerns in the design and review of the study, including public workshops
and public comments on the record.” Id.
In addition to outlining the scope and process for the Company’s study in Case No. IPC-
E-18-15, the Commission delineated the parameters of “grandfathering” or “legacy” status.
Specifically, in Order No. No. 34509, the Commission defined a “legacy” (or grandfathered
system) as a “person or business who either has an on-site generation system interconnected with
Idaho Power’s system as of” December 20, 2019, “or who has made binding financial
commitments to install an on-site generation system as of” December 20, 2019 “and who proceeds
to interconnect their system” by December 20, 2020. Order No. 34509 at 14. In sum, the
Commission grandfathered existing customers into Schedule 6 or Schedule 8 as those Schedules
existed on December 20, 2019. Id. The Commission noted that, while legacy systems would
ORDER NO. 35631 5
continue to receive a 1:1 monthly kWh offset, the monthly service and energy charges under the
existing Schedules 6 and 8 on December 20, 2019, were subject to change. Id.3
The Commission also reiterated its previous warnings to potential customers that the
Company’s electric tariffs are subject to fundamental changes “which can substantially affect the
repayment period for a customer’s investment.” Id. at 13. The Commission further advised “all
stakeholders in the on-site generation industry to be completely transparent with potential investors
that a utility’s rate schedule, including program fundamentals, is subject to change and there is no
guaranteed return on investment.” Id.
C. Case Nos. IPC-E-19-15 and IPC-E-20-26
While Case No. IPC-E-18-15 was still under review, the Company filed case No. IPC-E-
19-15 requesting the Commission consider the net-metering rules governing commercial,
industrial, and irrigation (“CI&I”) customers under Schedule 84.4 The Application was
subsequently withdrawn after the Commission rejected the settlement agreement in Case No. IPC-
E-18-15.
The Company then initiated Case No. IPC-E-20-26 for authorization to modify Schedule
84’s two-meter requirement and to “grandfather existing customers and applicants with two-meter
systems under the current one-for-one [1:1] net metering billing construct provided for in Schedule
84, for a period of no more than 10 years.”5
The Commission ultimately approved the Company’s request to move to a single-meter
requirement for new onsite generation systems under Schedule 84 and also established criteria
similar to Case No. IPC-E-18-15, for defining legacy treatment for existing Schedule 84 systems.
Order No. 34854 at 11-12. In its order denying reconsideration in that case, the Commission
reiterated that Schedule 84 is a tariff and that “tariffs are not contracts and are subject to change.”
Order No. 34892 at 8. The Commission cautioned that, “[n]o person, entity, business or
organization should be representing that investment in and installation of solar panels under a

3 In reconsideration Order No. 34546, the Commission clarified that it is the “system” rather than the “customer” that
retains grandfather status. Order No. 34546 at 9. The Commission further clarified: (1) that a grandfathered system
can maintain its grandfathered status until December 20, 2045; (2) that grandfather status for a system terminates if
the system is off-line for more than six months; and (3) that a grandfathered system can increase its capacity by the
greater of 10% of its original capacity or 1 kilowatts to replace degraded or broken panels without losing its status. Id.
4 ln the Matter of Idaho Power Company’s Application for Authority to Study the Measurement Interval, Compensation
Structure, and Value of Net Excess Energy for On-Site Generation Under Schedule 84 and to Temporarily Suspend
Schedule 84 Net Metering Service to New Idaho Applicants, Case No. IPC-E-19-15, Application at 1 (April 5, 2019).
5 ln the Matter of Idaho Power Company’s Application for Authority to Modify Schedule 84’s Metering Requirement
and to Grandfather Existing Customers with Two Meters, Case No. IPC-E-20-26, Application at 1-2 (June 19, 2020).
ORDER NO. 35631 6
particular tariff will result in payback within a time certain because the rates under the then current
tariff do not become fixed at the time such an investment is made.” Id. The Commission noted that
a “reputable seller of onsite generation systems would not and will not represent that the program
will never change.” Id.
D. Case No. IPC-E-21-21
In Case No. IPC-E-21-21, the Company requested the Commission “initiate the multi-
phase process for a comprehensive study of the costs and benefits of on-site generation.”6 The
Company ultimately requested that the Commission “approve a final scoping document, which
will conclude the ‘study design’ phase.”7 The Company contemplated that if an order in Case No.
IPC-E-21-21 came out by the end of 2021, it would use 2021 data to complete the study then
initiate a “‘study review’” phase by June 2022.8 The Company anticipated waiting to make any
request to implement any changes to its “net metering rate design, compensation structure, or ECR
after the Commission acknowledges a study.”9
The Commission found that the “Study Framework” provided by the Company, as further
discussed by the Commission, met its directive to the Company to file a “credible and fair study.”
Order No. 35284 at 9.10 The Commission outlined a Study Framework for the Company. Id. at 12-
32. Under the Study Framework, the Commission directed what topics the Company was and was
not to evaluate in its study and the extent to which the Company was to evaluate each topic. The
Commission reiterated that the study “must use the most current data possible, and the data must
be readily available to the public and in the Commission’s decision-making record.” Id.
In response to the suggestion that the Commission have a third party conduct the study, the
Commission stated that the Company “is best positioned to access and study the extensive data
and issues specific to the Idaho Power system at a reasonable cost.” Id. at 10. The Commission
also directed the Company “to provide sufficient data along with the study conclusions so that
others have insight as to how the results were derived.” Id. at 11.

6 ln 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, Application at 1 (June 28, 2021).
7 Id.
8 Id. at 8.
9 Id.
10 The draft Study Framework was provided as an attachment to Idaho Power’s Application in Case No. IPC-E-21-
21.
ORDER NO. 35631 7
Ultimately, the Commission ordered the Company to “complete the study design for its
Comprehensive study on the costs and benefits of on-site generation based on the Commission’s
Study Framework findings and conclusions as more specifically defined and explained . . . [in
Order No. 35284].” Id. at 32.
COMPANY’S APPLICATION
The Company specifically requested the Commission:
(1) establish a formal process and timeline for . . . Staff . . . intervenors, and the
public to review and comment on the Study; and (2) issue an order acknowledging
that the Study satisfies the Commission directives outlined in Order Nos. 34046[11],
34509[12], and 35284[13] and directing modifications to the Company’s on-site
generation service offerings be implemented with the ultimate goal of establishing
more sustainable offerings by implementing a more equitable pricing and
compensation structure.

Application at 2. The Company also proposed a “procedural schedule that would position the
Commission to issue an order directing changes to the on-site customer generation service offering
by December 30, 2022.” Id. at 16-17.
The Company provided an overview of the structure of the current customer generation
program and the relevant regulatory history and explained the parameters of the VODER Study
and its compliance with Order No. 34509’s requirements. The Company highlighted the
collaborative process it facilitated in pursuing the Study, clarified important “key findings” of the
Study, and outlined areas in which it believes its recommendations would focus. Finally, the
Company proposed a procedural and implementation schedule and explained its notification
process.
A. Customer On-Site Generation Program
The Company stated that it first offered a net metering option in 1983 when it had a single
customer with on-site generation who wished to interconnect to the Company’s system. Id. at 2.
The Company claimed that over the intervening decades, as more and more customers availed and
continue to avail themselves of the NEM program and receive “bi-directional service from Idaho
Power,” it had become apparent that the “existing retail rate net metering compensation structure”
did not “accurately reflect the costs to serve customers . . . .” Id. at 3. As a result, the Company

11 Case No. IPC-E-17-13, Order No. 34046 at 31.
12 Case No. IPC-E-18-15, Order No. 34509 at 17.
13 Case No. IPC-E-21-21, Order No. 35284 at 32-33.
ORDER NO. 35631 8
claimed that the rates “net metering customers are being charged . . . do not appropriately reflect
the benefits and costs of interconnecting customer-owned on-site generation to Idaho Power’s
system . . . .” Id. According to the Company, “this has resulted in a situation susceptible to
inequitable cost shifts between customers who choose to install on-site generation and those who
do not.” Id.
B. Regulatory History
The Company cited the history of customer on-site generation cases, beginning in 2017
with Case No. IPC-E-17-13 through Case No. IPC-E-22-12.14 In sum, those cases, as the Company
highlighted, illustrate the Commission’s prior decisions relating to: (1) the necessity of the
Company filing a comprehensive study prior to the Company proposing any changes to its on-site
generation program; (2) legacy status for systems under the Company’s NEM Schedules; and (3)
the proper scope and framework of the comprehensive study the Company was directed to file. Id.
at 5-9.
C. The VODER Study
The Company stated that the Study, as outlined by the Commission in Order No. 34509,
must:
(1) use the most current data possible, and the data must be readily available to the
public, and in the Commission's decision-making record’; (2) be designed ‘in
coordination with the parties and the public, and the final scope of the study will be
determined by the Commission’ and (3) ‘be written so it is understandable to an
average customer, but its analysis must be able to withstand expert scrutiny.

Application at 9 (quoting Order No. 34509 at 9). The Company explained that the
VODER Study integrated the Commission’s directives as evidenced by the Company’s solicitation
of public input and focus on making the Study understandable, its inclusion of supporting data and
appendices, and an analysis supporting the Study that “relies on a robust technical assessment of
the costs and benefits of customer generation on Idaho Power’s system.” Id. at 10. The Company
further explained that, as directed by the Commission, the Study did not include, “a full cost-of-
service evaluation, in-depth study of rate design options, and implementation of transitional rates”
but did, however, address the nine topics envisioned by the “Commission-approved Study

14 In the Matter of Clean Energy Opportunities [“CEO”] for Idaho’s Petition for an Order to Modify the Schedule 84
100kW Cap & to Establish a Transition Guideline for Changes to Schedule 84 Export Credit Compensation Values.
On September 30, 2022, the Commission issued a final order in this case dismissing CEO’s Petition. Order No. 35547
at 11.
ORDER NO. 35631 9
Framework” in Case No. IPC-E-21-21. Id. at 10. Specifically, the Company explained that the
Study discussed: “(1) measurement interval; (2) export credit rate; (3) frequency of export credit
rate updates; (4) compensation structure; (5) class cost-of-service; (6) recovering export credit rate
expenditures; (7) project eligibility cap; (8) other areas of study; and (9) implementation
considerations including transitional rates and administrative and communication materials.” Id at
10-11. The Company pointed out that the Study “itself does not advocate for a single position
regarding potential modifications to the current net metering service, but rather examines several
methods of valuing customer-owned generation energy exports and explores other important
considerations.” Id. at 11.
E. Collaboration and Public Input
The Company highlighted its efforts to involve the public in completing the Study. The
Company facilitated a public workshop on May 2, 2022, advertising the workshop as focusing
“‘on the export credit rate—the amount customers with on-site generation systems, such as rooftop
solar panels, are credited for the excess energy they send back to Idaho Power’s grid.’” Id. at 11.
The Company stated that it notified the public of the workshop as well as all the intervenors in
Case No. IPC-E-21-21. Id. at 11-12.
The Company noted that 40 members of the public as well as several intervenors from
previous cases attended the Company’s workshop. Id. at 12. The Company stated it received five
comments from the public and four recommendations from CEO after the workshop which it
considered in its Application. Id.
F. Study Review and Recommendations, Study Review and Implementation Schedule, and
Customer and Stakeholder Notification
The Company noted the following “key findings” supported by the Study: (1) “the
Company has the technical capability to reduce the measurement interval for on-site generation
exports and that such a modification would improve the accuracy of cost assignment and
compensation for on-site generation customers”[;] (2) the “Study presents multiple valid methods
of valuing excess energy from on-site generators, each of which differ materially from current
retail energy rates, suggesting consideration of modifications is warranted”[;] and (3) “the Study
presents several implementation considerations that can adequately inform the appropriate timing
of transitioning to a successor service offering.” Id. at 14. The Company anticipated the Parties
and the public would make recommendations in the following areas of the Study: (1) compensation
ORDER NO. 35631 10
structure; (2) frequency of updates; (3) recovery of export credit expenditures; (4) project
eligibility cap; and (5) transitional rates. Id. at 15. The Company clarified that the Commission
“can assess if a transition period is fair, just, and reasonable for on-site customer-generators with
non-legacy systems once changes to the compensation structure are known” based on feedback in
receives from the Parties and the public. Id.
The Company’s proposed schedule allowed for vetting of the Study “before stakeholders,
including the Company, take positions on recommended methods for implementing a successor
service offering for non-legacy on-site customer-generator systems.” Id. at 16. The Company
requested that any changes to its “on-site generation service offering . . . not occur before June 1,
2023.” Id. at 17.
The Company represented that it issued a news release of its Application and would
directly notify all its existing customers that it had filed the Study. The Company stated that it
would also send different letters to pending and existing on-site generation customers notifying
them of this case and that the outcome of the case could have an impact on the compensation
amount to customers with non-legacy systems. Id. at 17-18.
VODER Study
The VODER Study is organized by 11 main headings—(1) Executive Summary; (2)
Introduction; (3) Measurement Interval; (4) ECR; (5) Frequency of ECR Updates; (6)
Compensation Structure; (7) Class Cost-of-Service (“CCOS”); (8) Recovering ECR Expenditures;
(9) Project Eligibility Cap; (10) Other Areas of Study; and (11) Implementation Considerations.
Study at i-iv. Each of these main topics are further broken down into sub-topics or components
which, in some cases, are themselves further broken down. For example, section (4.) “ECR”, is
further divided into (4.1) “Avoided Energy Costs” which is further divided into (4.1.1) “Energy
Price: Inputs and Assumptions” which is further divided into (4.1.1.1) “Integrated Resource Plan”
(4.1.1.2) “ICE Mid-C Index Price” and (4.1.1.3) “Energy Imbalance Market Load Aggregation
Point (ELAP) Price.” Study at i-ii, 35-37.
The Parties’ comments, for the most part, focused on the topics and the components within
each main topic. The predominant focus of all the Parties’ comments was, however, on the various
components within the ECR value.

ORDER NO. 35631 11
THE COMMENTS
A. Initial Party Comments
Staff
Staff reviewed the Study for its compliance with the approved Study Scope in Order No.
35284 and in consideration of the Commission’s previous directives that the Study be transparent,
developed with public participation, and technically robust but comprehensible to the average
customer. Staff Comments at 2, 3. Overall, Staff believed the Study complied with the
Commission’s directives in Order Nos. 34046, 34509, and 35284. Staff believed that the
Commission should acknowledge the Study, provided that the Company make certain
modifications or amendments. Id. at 20.
The following are the topics which Staff initially stated did not need further clarification
or discussion in amendments to the VODER Study: the measurement interval; the integration
costs, avoided risk components, and avoided transmission and distribution (“T&D”) costs within
the ECR value topic; frequency of ECR updates; compensation structure; CCOS; recovery of ECR
expenditures; and other areas. Id. at 3-4.
Staff recommended the Company amend or modify the Study to further address issues
related to the project eligibility cap, and the following subtopics within the ECR value topic:
avoided energy value, avoided capacity value, avoided line losses, and environmental and other
benefits. Id. at 3-4, 21. While it did not explicitly recommend the Study be amended in the
following areas, Staff discussed that CCOS and rate design must be evaluated and implemented in
the Company’s next general rate case, and that transition guidelines would be proffered during an
implementation process. Id. at 21. Staff also addressed the main issues raised in public comments
received as of September 21, 2022. Id. at 19-20.
Overall, Staff believed that the Study complied with Order No. 35284 in its exposition of
the value of avoided energy costs. That said, Staff recommended the Company amend the Study
to provide further discussion and data supporting “(1) the firm to non-firm energy adjustment; and
(2) the proposed ‘On Peak’ high-value time window.” Id. at 7. Staff believed there were two
significant considerations in valuing avoided energy costs: “(1) whether to use actual market
pricing or a weighted-average of established energy prices; and (2) the source of pricing
information.” Id. Staff believed that using actual market prices would be the most accurate, value-
wise, but least stable and predictable whereas using weighted average market prices would be
ORDER NO. 35631 12
stable and predictable but, less accurate. Id. Staff further believed that all sources of pricing data—
Integrated Resource Plan (“IRP”), and the two market indices—would be equally stable and
predictable but the IRP would be the least accurate, because it is a forecast of prices over time. Id.
at 8. Staff suggested that the Study should be amended to better explore these issues.
Staff believed the Study generally complied in its analysis of avoided capacity costs, but
that the Company needed to amend its Study to “provide more information and justification as to
why On and Off-peak time-differentiation windows used for valuing capacity is appropriate for
valuing energy.” Id.
Staff thought the Study generally complied with its exposition of avoided line losses, but
that the Study should be amended to include discussion of transformer losses, line losses from
energy and capacity, and explicitly apply the line loss adjustment factor. Id. at 11.
Staff noted the Study identified three potential costs that could be avoided pursuant to the
Commission’s directive in Order No. 35284 to evaluate all quantifiable, and measurable
environmental costs that affect rates. Id. Three potential avoided costs that Staff identified were:
Renewable Energy Credit(s) (“REC(s)”), carbon taxes, and fulfillment of Renewable Portfolio
Standard (“RPS”). Id. Staff recommended the Company amend its Study to further explain its
conclusions concerning RECs.
Although Staff noted that the Study complied with previous Commission orders in
examining the Project Eligibility Cap, Staff recommended the Company supplement the Study
with additional information relating to information Staff received from the Company in the
discovery process, and policy factors that must be considered in raising the cap. Id. at 14-17.
Staff also recommended that the Company evaluate the potential of customers choosing to
construct a Public Utilities Regulatory Policies Act of 1978 (“PURPA”) Qualifying Facility
(“QF”) project rather than a customer-generation project under the NEM program or vice-versa to
obtain more favorable rates. Id. at 16. Additionally, Staff identified considerations relating to
implementing a demand-based cap that were considered by the Study which Staff believed were
important if a demand-based eligibility cap was implemented. Id. at 16-17.
Staff noted that the five most common themes in the public comments concerned public
hearings, grandfathering, compensation and structure, considering environmental and social
benefits in calculating an ECR value, and rejection of the VODER Study. Id. at 19-20.

ORDER NO. 35631 13
IIPA
IIPA commented making several recommendations related to the following topics:
compensation structure, frequency of ECR updates, recovery of ECR expenditures, the project
eligibility cap, and transitional rates. IIPA Comments at 2. IIPA did not specifically assert that the
Study was inadequate, or needed to be amended.
In calculating the compensation structure—i.e., the ECR—IIPA recommended the
Company: use “sub-hourly measurement and pricing intervals”; measure avoided energy costs
based on the Company’s 2021 IRP or other “Idaho specific measure”; calculate avoided capacity
costs using a Company-specific Effective Load Carrying Capacity (“ELCC”); apply the method
provided in the VODER Study for calculating avoided T&D; consider adding a transmission
charge for the cost of moving exported energy to market; and that it treat line loss “consistent with
pricing and other cost calculations.” Id. at 4-6.
IIPA further recommended that the avoided energy component of the ECR be updated
annually because this figure is easily updated and variable year-to-year, while all the other
components of the ECR should be updated in conjunction with the Company’s biennial IRP cycle.
Id. at 7. IIPA also recommended that ECR expenditures be recovered through the power cost
adjustment mechanism consistent with the treatment of the Company’s other power cost purchases.
Id. at 8.
Finally, IIPA recommended the Company consider “softening the project eligibility cap”
so long as it designed base rates and the ECR to minimize subsidization to self-generators and the
costs incurred to accommodate large projects were directly charged to the participating customer.
Id.
ICL
ICL explained that it appreciated “the Company’s clarity and detailed explanations in the
VODER [S]tudy[,]” but that it was concerned that the Study undervalued “distributed generation
to a degree that will inhibit development and contribute to an adverse economic and regulatory
environment in future policy decisions.” ICL Initial Comments at 1-2. ICL also identified, via the
Crossborder Energy Study (“CBE study”)15 which it attached to its comments, environmental and
external costs that should be considered by the Company in determining an ECR value. Id.

15The Company noted that the “Crossborder Energy Study was paid for by the Idaho Conservation League, the Idaho
Chapter of the Sierra Club, EGT Solar, Vote Solar, the Portneuf Resource Council, the Snake River Alliance, CED
ORDER NO. 35631 14
Specifically, ICL averred that the VODER Study failed to account for the recent shifts in
energy markets and therefore failed to present an accurate or meaningful estimate of avoided
energy costs. ICL Initial Comments at 5. ICL’s CBE study recommended the VODER Study use
the most recent 12-month Energy Imbalance Market (“EIM”) prices, adjusted for natural gas
forward market prices for the next year, as this would better account for market volatility than IRP
and average ELAP and ICE Mid-C price estimates. Id.
ICL also stated that the VODER Study lacked a substantive discussion of the fuel hedging
benefits from DER development. Id. at 9. ICL’s CBE study concluded that the Company failed to
appropriately account for the how the benefit of renewable generation from DER can decrease if
a utility’s ECR is driven by electric market prices that are driven by natural gas prices. CBE study
at 10.
Regarding avoided generation capacity costs, ICL contended that the Company’s Study
did not consider appropriate alternatives to DER that provide equivalent capacity. ICL Initial
comments at 6. ICL’s CBE study disputed the VODER Study’s use of the Company’s ELCC,
contending that this was too complex and inaccurate. The CBE study proposed the Study consider
the value of self-consumed energy, use a “simpler peak capacity allocation factor (“PCAF”)
calculation” to cure the defects with the Company’s ELCC figure, use battery storage as a surrogate
rather than a single cycle combustion turbine (“SCCT”) and add an additional 15.5% planning
reserve margin (“PRM”). CBE study at 3-4.
ICL contended the Study failed to capture the greatest need for additional T&D resources
“by assuming an average distributed generation system across all instances . . . .” ICL Initial
Comments at 7. ICL noted that the CBE study proposed the Study use a regression model that
would better account for marginal T&D costs and infrastructure investments avoided by a
reduction in peak load. Id.
ICL argued that the VODER Study did not properly analyze avoided line losses from DER
development and generally undervalued the value of avoided line losses. The CBE study proposed
the Company use marginal line losses rather than average line losses which would result in a higher
avoided line loss value and a doubling of the total avoided line losses, from 5.8% to 11.6%. CBE
study at 8.

Greentech, Sunnova, Empowered Solar, the Climate Action Coalition of the Wood River Valley and the Idaho
Organization of Resource Councils.” Company Reply Comments fn. 2 at pg. 2.
ORDER NO. 35631 15
ICL believed that the reduction of carbon emissions, increased human health, economic
benefits, reliability and resiliency, and customer choice resulting from DER development are
known and measurable, environmental benefits which affect rates, but which were not discussed
in the VODER Study. ICL Initial Comments at 11-14. The CBE study claimed that carbon
emission costs are quantifiable and measurable and affect the Company’s rates. The CBE study
noted the Company’s 2021 IRP recognized the impact of carbon emissions and made clear climate
change would likely impose risks, and associated cost impacts, on the Company and its ratepayers.
CBE study at 12. The CBE study proposed a value for the benefit DER(s) have on reducing carbon,
air pollution, methane leakage, water use, land destruction, and increasing reliability, resiliency,
and customer choice.
Finally, ICL and the CBE study represented that the VODER Study’s estimate of
integration costs, which relied on an outdated study, did not properly account for the Company’s
planned resource mix or battery storage as identified in the Company’s 2021 IRP. ICL Initial
Comments at 8.
CEO
CEO’s initial comments touched on the calculation of the ECR, frequency of ECR updates,
CCOS, the project eligibility cap, and implementation considerations. CEO believed that, when
measuring the value of avoided energy, the IRP forecasts are inferior to the ICE Mid-C and ELAP.
CEO believed that the ECR value should consider market-based prices rather than the IRP
forecast, as these are more accurate measurements of energy values. CEO Initial Comments at 2,
5. CEO thus recommended that the Study examine the two market-based alternatives to the IRP.
Id. In addition, CEO recommended the Company acknowledge a “firmness” adjustment previously
discussed in Case No. IPC-E-18-15 and a fuel price hedge value in an amended Study. Id. at 3, 6.
CEO also recommended the VODER Study be amended to consider additional methods of
evaluating avoided T&D costs and better explain its analysis of avoided line losses. Id. at 3 and 9.
CEO believed the VODER Study did not accurately evaluate environmental benefits or consider
internal customers’ willingness to pay more for renewable energy options. Id. at 3-4. CEO also
believed that the Company’s implied position was that the goal of rate design is to align with the
Company’s cost structure. Id. at 5. CEO further argued that the VODER Study insufficiently
analyzed the project eligibility cap. CEO contended that the VODER Study should consider setting
the project eligibility cap based on additional considerations other than just a customer’s demand.
ORDER NO. 35631 16
Id. at 9. Finally, CEO recommended that the VODER Study discuss an implementation option that
included a transitional rate and consider the impact of delaying any implementation to the project
eligibility cap for Schedule 84 customers.
Boise City
Boise City’s initial comments focused on whether the VODER Study met “the
Commission’s direction in the Study Framework and is a ‘credible and fair study.’” Boise City
Initial Comments at 2. Boise City clarified that it would not focus on any proposed implementation
to the NEM Schedules until these were proposed by the Company or other parties. Id. Boise City
initially recommended that the VODER Study consider the value of avoided fuel price risks and
avoided T&D capacity costs which, as Boise City believed, could be “reasonably quantified and
applied to an ECR.” Id. Boise City also commented that the Commission needed to “ensure all
reasonable efforts to encourage public participation are pursued and that the public is properly
noticed.” Id. at 4-5.
The Company
The Company stated that it had received numerous public comments, and other valuable
input from the workshops and meetings that had occurred in this case. The Company explained
that it believed “Staff’s schedule” which the Commission adopted, would allow the Commission
adequate time to consider all comments on the Study before establishing “a process and schedule
for considering implementation recommendations on the Study.” Company’s Initial Comments at
3. The Company clarified that the “intent of the filed Study . . . was to provide illustrative, or
indicative, pricing based on various potential methods for evaluation during the present study
review phase[,]” and not to propose any specific method be implemented. Id. at 4-5. The Company
explained that it anticipated extensive feedback and input from the Parties and the public which it
could use to identify areas of the Study that could “benefit from refinement” and be incorporated
in an updated study filed on October 26, 2022. Id. at 6.
B. All Party Reply Comments
Staff
In its all-Party reply comments, Staff recommended the Company address how the ECR
section of the Study considers avoided energy value, avoided capacity value, avoided T&D
capacity costs, and avoided line losses. Staff also commented that it may be necessary for the
Company to meet with interested parties “to discuss how current and future customer-generators
ORDER NO. 35631 17
may be notified of future program changes.” Staff Final Comments at 8. Staff noted that the five
most popular topics in the public comments received by the Commission were: requests for public
hearing(s); the compensation and structure of the NEM program; environmental and societal costs
and benefits; requests to reject the Study or have a third party conduct it; and requests to expand
grandfathering beyond December 20, 2020. Id. at 9.
Staff recommended the Company amend the VODER Study “with an analysis of the cost
to move exports to the market during the timeframe that customer-generators export onto the
Company’s system” and consider the fuel-cost hedge benefit and the disadvantages of the Maine
method. Id. at 10. Although it did not entirely agree with some of the other Intervenor’s positions
with respect to the correct method of calculating avoided generation capacity, Staff recommended
the Company amend the VODER Study with an analysis and discussion of: (1) the strengths and
weaknesses for determining capacity contribution using several different methods, including ICL’s
CBE study’s PCAF method; (2) the Study’s use of the least-cost capacity resource, currently an
SCCT in the 2021 IRP, as a surrogate resource; and (3) how the PRM is irrelevant in valuing
capacity contributions. Id. Finally, Staff recommended that an updated Study provide additional
methods for valuing avoided T&D costs, and clarify concepts of marginal lines losses, average
line losses, and energy line losses within the avoided line losses topic. Id.
IIPA
IIPA’s reply comments expressed concern that “ICL’s comments would not lead to fair
and equitable rates.” IIPA Reply Comments at 2. IIPA recommended the Commission disregard
all aspects of the CBE Study and focus on accurate ECR pricing that results in fair rates to all
customers rather than incentivizing solar generation. Id. at 4. IIPA argued that the CBE’s study’s
methodology for valuing components of the ECR was, in many respects, inaccurate, based on
faulty or overestimated assumptions, and unreasonable. IIPA recommended the Commission not
consider non-quantifiable or unreasonable environmental benefits when calculating and ECR.
IIPA also modified its previous recommendation regarding the project eligibility cap, explaining
that “appropriate safeguards need to be implemented to ensure that, if the project eligibility cap is
“wholly divorced from the customer’s load,” PURPA solar developers do not circumvent PURPA
requirements by establishing projects using net generation tariffs. Id. at 4.

ORDER NO. 35631 18
ICL
ICL replied that it looked forward to receiving the Company’s revised study which it hoped
would address the public and the Parties’ critiques. ICL Reply Comments at 2. ICL stated its
concern with Staff’s comments that customer generators could engage in rate manipulation by
applying as QFs under PURPA. Id. at 2-3. ICL requested clarity on Staff’s assertion and responded
that this issue would be more properly addressed in a PURPA specific docket. Id. at 3-4.
ICL further requested clarity on the “anticipated proceedings and the scope of the Case No.
IPC-E-22-22 docket.” Id. at 4. ICL requested the Commission clarify the scope of the changes the
Company wishes to make to its NEM program. ICL requested an implementation proposal from
the Company and for a collaborative review of any such proposal. Id. at 6.
CEO
CEO’s reply comments focused on components within the ECR, CCOS, the Project
Eligibility Cap, and other areas, including the Company’s figure 10.3 and clarification for the next
phase of this case.
Regarding the energy price inputs used to calculate the avoided energy costs, CEO
recommended the Study be amended to provide a comparison of different market prices indices
and the tradeoffs between using historical averages and current market prices. CEO Reply
Comments at 4. CEO further recommended that the Company amend the Study to discuss the
problems “with asymmetrically imposing on-peak/off-peak rates for exports before customers
have access to on-peak/off-peak rates for consumption[,]” and to clarify a method “for determining
how ‘on-peak’ and ‘off-peak’ time periods could be developed and applied consistently to rates
for consumption and export credits.” Id. at 5. CEO maintained its recommendation that the
Company acknowledge a firmness value from the settlement in Case No. IPC-E-18-15, and further
recommended the Company consider fuel price hedge value in the ECR.
Regarding the avoided generation capacity component of the ECR, CEO supported Staff’s
request that the Parties be directed to discuss how seasonal and diurnal time periods affect capacity
contribution calculation methods. Id. at 7. CEO recommended the VODER Study be updated to
“clarify that contribution to peak can be used to accurately calculate ECR capacity value
components even in the event an hourly netting period is selected for billing purposes.” Id. CEO
replied that the Company present additional methods, in the amended Study, for valuing T&D
capacity contribution values. In addition, CEO supported additional analysis of marginal line
ORDER NO. 35631 19
losses in the amended Study and further meetings between the Parties to discuss pertinent issues
related to the Company’s evaluation of line losses. CEO also supported Staff’s recommendation
to the Company to amend the VODER Study to analyze RECs under the avoided environmental
costs section and ICL’s recommendation regarding the impact of battery storage on reducing
integration costs.
CEO replied that the CCOS study the Company used in the VODER Study was outdated
and inaccurate and that it is necessary to resolve CCOS issues, including a fair compensation rate,
in a general rate case. Id. at 11. However, CEO stated that “VODER related decisions, such as the
project eligibility cap, should not be held hostage by CCOS matters until that rate case occurs.” Id.
CEO requested the Company not include, in its amended Study, certain responses to Staff’s
production requests related to the project eligibility cap, and that that the Parties be directed to
discuss any remaining technical issues related to modifications of the Schedule 84 eligibility cap
and associated revisions to the controlling tariffs. Id. at 12. CEO also recommended that the
payback analysis of rooftop solar, figure 10.3, page 109, of the VODER Study should be deleted
because the Study should be “close to objective as possible.” Id. at 13.
CEO requested the Commission direct the Company to file recommendations to establish
“a comprehensive baseline informed by public and party input” which all Parties can then submit
initial and reply comments on. Id. at 13-14. CEO specifically suggested that all-party technical
meetings be scheduled consistent with the Parties’ recommendations, that the Commission issue
an order acknowledging, modifying, or rejecting the updated VODER Study, and that all Parties
meet after that order and prior to the Company’s submission of its recommendations. Once the
Company filed its recommendations for changes to its NEM program, CEO recommended there
be an all-Party reply comment period, one or more customer hearings, final all-party comments,
then a Commission order.
Boise City
Boise City believed that the Company should amend the VODER Study to “consider
additional approaches to quantifying the avoided . . . [T&D] . . . capacity costs; and 2) clarify how
avoided fuel price risks could be incorporated in an” ECR. Boise City Reply Comments at 2.
Boise City also recommended that the issue of “applying seasonal time-variant pricing to
exported energy but not allowing customer generators access to time-variant consumption
prices[,]” should be evaluated in any implementation proceedings. Id. at 4. Boise City reiterated
ORDER NO. 35631 20
that the amended VODER Study should evaluate fuel price risk, beyond market energy prices, and
consider Maine’s method for valuing fuel price hedges. Id. at 3. Although Boise City agreed with
Staff’s recommendations regarding amending the Study to explore the interconnection connection
requirements and safety and reliability considerations in evaluating projects, independent of the
project eligibility cap, Boise City did not believe the Study need be amended to discuss issues
related to potential PURPA developers gaming the system to receive more favorable rates under
the NEM program. Id. at 3-4.
Finally, Boise City suggested that the Commission issue an order on the study review phase
that “re-caption(s) the docket to reflect the change in scope to implementation” directs the
Company to file implementation proposals and directs Staff to work with Parties to develop
comment deadlines. Boise City Reply Comments at 5. Boise City recommended that customers
should also be “formally noticed of the Company’s proposed compensation structure or any
transition into an implementation phase of this proceeding.” Id.
The Company
The Company’s reply comments focused on ICL’s CBE study. Overall, the Company
claimed that the CBE study deviated from prior Commission orders, was not transparent, and did
not withstand expert scrutiny.
The Company replied that the CBE study incorrectly concluded that the VODER data
regarding avoided energy costs was “outdated and inaccurate.” Company Reply Comments at 4.
The Company explained that the VODER Study used reasonably current data for illustrative
purposes and emphasized the many options ultimately available to the Commission, including real-
time market pricing. Id. at 7-8.
The Company replied that the CBE study’s analysis of avoided generation capacity directly
conflicted with the Commission’s approved framework, was erroneous, did not select the lowest-
cost selectable resource, nor rely on “industry best practices or system-specific data.” Id. at 4-5.
The Company replied that the CBE study’s estimates of the Company’s avoided T&D
investments were “not accurate, were overstated, and are based on inappropriate implementation
of marginal costing techniques.” Id. at 5.
The Company replied that the CBE study’s “line loss assumptions erroneously and
arbitrarily double the line losses from Idaho Power’s most recent line loss study and are not based
on Idaho Power’s system data.” Id.
ORDER NO. 35631 21
The Company replied that the CBE study’s “assumptions are inherently flawed as it relates
to the applicability of the cases studied in Idaho Power’s most recent integration study . . . .” Id.
The Company replied that the analysis and conclusions reached by the CBE study
regarding fuel hedging practices demonstrated “a lack of understanding” of the Company’s
“hedging practices and conflict with the Commission-approved Study Framework by attributing
value to the energy consumed by the customer-generator behind the meter.” Id. at 5.
The Company replied that the CBE study included carbon emission costs, which are not
factored into rates, and societal benefits, which was not directed to be included in the Study. Id. at
5-6.
C. Company Reply Comments and the October VODER Study
I. Measurement Interval
In response to the comments received regarding the Study’s “Net Measurement Interval”
discussion, the Company included a discussion under Section 3 of the October Study “about the
impact of moving from NEM monthly measurement to a net billing hourly measurement for CI&I
customers.” Company Final Comments at 8. The Company “also developed two new appendices
which accompanied the October 2022 VODER Study, Appendix 3.5 and 3.6, the 2021
Measurement Interval and Bill Impact for Schedule 84 . . . [CI&I] . . . respectively.” Id.
II. ECR Components
The Company noted that much of the feedback it had received regarding the avoided energy
component of the ECR value concerned implementation recommendations. The Company stated
it updated Sections 3.1 and 5.1 of the Study in the October Study to clarify CEO’s concerns related
to different options for implementation and the tradeoffs between accuracy, stability, and
predictability for each option. Id. at 9. In addition, the Company included additional information
and data in the October Study “to support an energy-based differentiated ECR and the non-firm
adjustment in Sections 4.1.2.2 and 4.13, respectively . . . .” Id. at 9. However, the Company did
not include a value for the non-firm energy adjustment the parties agreed to in Case No. IPC-E-
18-15. Id. The Company also provided a discussion in Section 4.1.2.2. of the October Study
addressing Staff’s recommendation for “an analysis of the cost to move exports to the market
during the timeframe that customer-generators export onto the Company’s system.” Id. at 9-10. In
response to the Parties’ recommendations to include an analysis of fuel-price risk, the Company
put a Section 4.1.5 in the October Study. Id. at 10.
ORDER NO. 35631 22
In response to recommendations concerning avoided generation capacity component of the
ECR value, the Company put Sections 4.2.1.3, 4.2.2.1, and 4.2.3.1 in the October VODER Study
which it claimed provided an analysis and discussion of the Parties’ recommendations and
highlighted “several important considerations to be evaluated by policy makers who may consider
implementing a PCAF-type method for avoided capacity costs.” Id. at 11-12. The Company
declined to address CEO’s recommendation to amend the VODER Study to “‘clarify that the real-
time contribution to peak can be used to accurately calculate ECR capacity value components even
in the event an hourly netting period is selected for billing purposes.’” Id. at 12. The Company
stated that although it did not believe CEO’s recommendation should be “reasonably considered,”
it was an issue more properly raised in the “implementation phase” (that will follow the
Commission’s final order in this case). Id. at 13.
In response to the comments and recommendations concerning calculation of avoided T&D
capacity costs, the Company put a Section 4.3.3 in the October Study examining alternative
methods for evaluating T&D capacity costs. Id. at 15.
In response to the comments and recommendations regarding avoided line losses, the
Company updated and added additional material in Section 4.4 of the VODER Study, in the
October Study, to include “a discussion about transformer line losses and included Figure 4.20 to
demonstrate how the line losses applied against the avoided energy and capacity components of
the ECR were quantified.” Id. at 16.
In response to the comments and recommendations concerning avoided environmental
costs, the Company revised Section 4.5 of the Study to clarify the use of a carbon adder in its IRP
and provided additional “discussion regarding the intricacies and requirements to obtain and track
RECs.” Id. at 17.
The Company expanded Section 4.6.2 of the Study to explain why the integration study it
used in the VODER Study best aligns with its current system. Id. at 18.
III. Compensation Structure
The Company noted that it completed a bill impact analysis for CI&I customers taking
service under Schedule 84 and that the “discussion in Section 6.4 has been expanded to include
Schedule 84 customers and Appendix 3.5 and 3.6 have been added . . . . ” Id. at 19.

ORDER NO. 35631 23
IV. CCOS
The Company added an additional paragraph in Section 7 of the Study responding to Staff’s
Comments regarding CCOS. Id. at 19. The Company also modified the Study’s initial statement
that “opportunity exists to better align the pricing structure with the underlying cost structure” to
read: “ . . . the existing pricing structure does not align with the underlying cost structure[,]” (in
response to CEO’s comment). October Study at 109.
V. Project Eligibility Cap
In response to the Parties’ comments and recommendations concerning the project
eligibility cap, the Company stated that it included information in the October VODER Study that
“incorporates the information requested by Staff and CEO in their respective comments.”
Company Final Comments at 21. Specially, the Company noted that potential PUPRA gaming
“considerations should be evaluated as parties advocate for recommended changes to the project
eligibility cap.” October Study at 129.
In response to CEO’s recommendation that the Company forgo including certain
information provided through discovery relating to data about the number of service points
currently above or below the current cap, the Company included a discussion, in the October
VODER Study, of the “existing caps, how they are administered, and how the information should
not be interpreted to suggest a 1-1 relationship between service point and customer.” Company
Final Comments at 21.
VI. Other Areas of Study
The Company stated that it originally added the information contained in figure 10.3 of
the Study for transparency but, based on CEO’s recommendation, the Company removed figure
10.3 in the October Study. Id. at 23.
The Company did not specifically address the Parties’ comments regarding the frequency
of ECR updates, or recovery of ECR expenditures in the October Study but believed it would be
reasonably included in the implementation proposal it put forth. Id. at 25.
VII. Next Steps
The Company agreed that a Commission order directing further process following this case
would provide clarity to the Parties and public. Id. at 24. The Company proposed that the
Commission, in its final order acknowledging or rejecting the October VODER Study, direct the
Company to “file a proposal recommending modifications to the on-site generation offering by
ORDER NO. 35631 24
December 30, 2022, and [d]irect Staff to confer with the [P]arties to align on a procedural schedule
recommendation that can be presented to the Commission for . . . [its] . . . consideration as soon
as practicable.” Id. The Company requested the Commission further clarify the list of issues
“reasonabl[y] included in an implementation proposal put forth by the Company.” Id. at 25. The
Company believed, however, that additional meetings on the topic of the Company’s
implementation recommendations subsequent to its filing these recommendations would not be
productive. Id. at 26. The Company responded that it would provide notice to the public via bill
inserts to all customers and issue a press release once it filed its proposed changes “to the on-site
customer generation service offering.” Id. at 25-26.
In response to the views expressed in the public comments, the Company explained that it
extensively engaged and involved the public in designing and pursuing the VODER Study and
ensured all relevant information and the Study process was available to its customers clearly and
transparently. Id. at 28. The Company clarified that its October Study did not incorporate
implementation recommendations or considerations suggested by some public comments. The
Company explained that the Commission previously determined the framework for the Study in
Case No. IPC-E-21-21 and found that a third-party study should not serve as a basis for changes
to the Company’s NEM program. Id. at 29. The Company reiterated that any of its proposed
changes to the net-metering service offering should not be interpreted as discouraging customer
self-generation. Id. at 31. Ultimately, the Company explained that it supports customer choice in
on-site generation, but it wants to ensure “that rates paid for excess generation are fair and
equitable to both generating and non-generating customers.” Id.
PUBLIC TESTIMONY AND COMMENTS
The Commission received over 950 public comments. Over 400 commenters requested the
Commission hold public hearings. More than 80 total people provided live-testimony in the public
hearings held in Pocatello, Twin Falls, and Boise. The most common concern expressed in the
comments and during the hearings was potential changes to the compensation structure of the
Company’s NEM program. Members of the public who had legacy systems worried that lowering
the ECR would disincentivize additional customers from investing in solar generation. Others who
had invested in on-site solar generation for their homes, but did not qualify for grandfathering,
expressed concern that lowering the current ECR would prevent them from recovering their
investments in self-generation. A third group of commentors who have not yet invested in or
ORDER NO. 35631 25
installed solar expressed that changes to the compensation structure would likely disincentivize
them from future investment in solar.
Another common theme expressed by the public was the environmental, societal, and
economic benefits of on-site self-generation. In short, many commenters believed that on-site self-
generation limited the Company’s dependence on electricity generated with carbon-based inputs,
reduced carbon emissions, and preserved the environment for future generations. These
commenters also believe on-site generation benefits the Company, its system, and its customers
by freeing the public to generate its own power outside of the monopoly system, allowing on-site
self-generation to offset peak demands during the day and in the summer, and enabling customers
to offset their electric needs and choose their energy future. These benefits, commenters argued,
should be considered and quantified in an ECR.
A significant number of commenters recommended the Commission consider the
Company’s Study and the CBE study and/or another study or simply reject the Company’s Study.
Other commenters requested extension of the grandfathering period. The majority of comments
addressing specific topics within the Study focused on the ECR; however, comments and
testimony also addressed the measurement interval, on-site generation’s impact on reducing peak
demand, the billing structure, recovery and frequency of ECR updates, CCOS, the project
eligibility gap, and implementation considerations. Customers taking service under Schedule 84
testified and recommended, among other things, that the 100 kw cap under Schedule 84 be lifted
and that changes to the NEM program should be implemented by June 2023.
Individuals commented and testified on behalf of the Sierra Club, Idaho Organization of
Resource Councils, the Portneuf Resource Council, and other non-profit or environmental
advocacy groups. Some individuals testified or commented on behalf of municipalities. These
comments generally focused on the benefits of on-site solar generation that were not examined in
the Study and contended the VODER Study undervalued customer self-generation. In addition,
numerous individuals from the solar industry, commenting or testifying on behalf of themselves,
their companies, or the solar industry in Idaho generally, argued that the Company’s proposed
ECR value would be deleterious to them and their industry in Idaho.
COMMISSION FINDINGS
The Commission has jurisdiction over this matter under Idaho Code §§ 61-501, -502, and
-503. Idaho Code § 61-501 authorizes the Commission to “supervise and regulate every public
ORDER NO. 35631 26
utility in the state and to do all things necessary to carry out the spirit and intent of the [Public
Utilities Law].” Idaho Code §§ 61-502 and -503 empower the Commission to investigate rates,
charges, rules, regulations, practices, and contracts of public utilities and to determine whether
they are just, reasonable, preferential, discriminatory, or in violation of any provision of law, and
to fix the same by order. We have reviewed the entire record in this case, including the Parties’
comments and reply comments, the comments and testimony of the public, and the Company’s
filings, including the VODER Study and the October VODER Study. Our review of the record
focused on the ensuring compliance with our directive in Case No. IPC-E-18-15 to “file a credible
and fair study on the costs and benefits of distributed on-site generation to the Company’s system”
which we further defined in Case No. IPC-E-21-21. See Order No. 34046 at 9 and Order No.
35284. Based on our review, we find the evidence as a whole, supports acknowledgment of the
Company’s October VODER Study.
As we have stated numerous times, before the Company implements any changes to its
NEM program, it must complete a comprehensive study. In Case No. IPC-E-21-21, we outlined
what a comprehensive study should and should not include. In Order No. 35284 we directed the
Company to complete “the study design for its Comprehensive study on the costs and benefits of
on-site generation based on the Commission’s Study Framework findings and conclusions” as
defined and explained in that Order. Order No. 35284 at 32. In addition to following the
Commission-approved framework outlined in Order No. 35284, the Company’s study was
required to use data that was the most current possible, publicly available, and in the Commission’s
decision-making record. Id. at 9 (citing Order No. 34509 at 9-10). The Company’s study was also
required to be understandable to an average customer but put forth an analysis capable of
withstanding expert scrutiny. Order No. 34509 at 9.
Thus, the purpose of our review in this case is to determine: (1) whether the Company
sufficiently completed the study design phase for its Study; (2) whether the Study was based on
the Commission’s Study Framework findings and conclusions as described in Order No. 35284;
(3) whether the Study used data that was the most current possible, publicly available, and
contained in the Commission’s decision-making record; and (4) whether the Study was
understandable to an average customer but put forth an analysis capable of withstanding expert
scrutiny. Order No. 35284 at 9; Order No. 34509 at 9.
ORDER NO. 35631 27
We find that the Company sufficiently completed the study design phase for its Study. We
note the Company solicited public input and designed its Study in response to the feedback it
received from Intervenors, Staff, and members of the public. We further find that the scope and
content of the Company’s Study was based on the Commission’s directives set forth in Order No.
35284. The Company sufficiently evaluated all the topics we directed it to in Order No. 35284.
We find that the data supporting both iterations of the Company’s VODER Study (including the
June and October VODER Studies) was the most current possible, publicly available, and included
in the Commission’s decision-making record. We note the 66 appendices filed by the Company
provided data supplementing the June VODER and October VODER Studies. This data was made
publicly available and filed in the record—a requirement of Order No. 35284. Although it may be
true that some of the data was not the most current data as of the timing of Parties’ and publics’
comments on this case, we find that it was the most current data available to the Company when
it filed its Study in June 2022 and that the Company provided updated data in conjunction with the
filing of its October Study.16
There are concepts within the Company’s NEM program that are complex; however, we
find that the Study’s extensive use of figures, graphs, and charts, among other things, makes the
Study understandable to an average customer. We note that many of the Intervenor’s comments
concerned the ECR value and other implementation recommendations. A few comments
contended that the Study relied on outdated or incomplete data. And ICL and its CBE study argued
that the Study failed to consider certain issues including avoided environmental and other costs.
However, we find nothing in the record to support the conclusion that the Company’s October
VODER Study does not withstand expert scrutiny.
For the forgoing reasons, and based on the record developed in this case, we find that the
Company’s October VODER Study and the process undertaken to create it, was completed in
accordance with the Commission’s directives outlined in Order Nos. 34046, 34509, and 35284.
We note many of the public comments and testimony expressed concern with potential
changes to the Company’s NEM program. Similarly, significant portions of the Intervenors’
comments concerned which approach the Company should choose in valuing an ECR. For

16 We echo our previous finding that the directive to the Company to use “the most current data possible” in the
“Commission’s decision-making record” and “available to the public” did “not specifically dictate use of either the
2019 or the 2021 IRP for the study as, at the time Order No. 35284 was issued, the 2019 IRP may not have contained
the most current data while the 2021 IRP had yet to be acknowledged by the Commission.
ORDER NO. 35631 28
example, ICL and CEO both averred that the Study should not use IRP prices in determining a
value for avoided energy costs and many public commenters expressed concern that they would
not recoup their investment at the Company’s proposed 2-3 cent per kW value.
We want to make clear that our decision in this case is whether to acknowledge that the
Study complied with our previous directives. Our decision is not a determination that a specific
method or value within the Study is superior to another. We note the Company’s statement that
“intent of the filed Study . . . was to provide illustrative, or indicative, pricing based on various
potential methods for evaluation during the present study review phase[,]” and not to propose any
specific method be implemented. Company Reply Comments at 4-5; see also Order No. 35284 at
7 (noting that “the Company anticipated requesting to implement any potential changes to the net
metering rate design, compensation structure, or ECR after the Commission acknowledges a
study.”). However, we 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.
We appreciate the robust level of public participation in this case. We understand non-
legacy NEM customers’ desire for stability, predictability, and a resolution of the issues related to
the Company’s on-site generation tariffs. At the same time, we believe that any changes to
Company’s NEM program should be well-supported by a comprehensive study using robust,
relevant, and publicly available data and methods, which we believe the Company’s October
VODER Study provides.
We now direct the Company to request any changes to its NEM program in a separate,
implementation case by proposing specific methods or systems in support of changes to its on-site,
self-generation tariffs. In the implementation case, Intervenors, Staff, and the public will have the
opportunity to provide comments and arguments for or against the Company’s proposed methods
and implementation recommendations
The October VODER Study complies with our previous directives and should serve as a
basis for the Company’s implementation recommendations in a subsequent case. Although we do
not advocate for a specific method in the Company’s Study, to provide clarity to the Company and
ORDER NO. 35631 29
other parties going forward, we find it would be helpful to explain what should and should not be
considered in the implementation case.
We find that the data, methods, and discussion under the Measurement Interval, Frequency
of ECR Updates, Compensation Structure, CCOS, and Recovering ECR Expenditures, and Other
Areas of Study sections of the October VODER Study fully comply with the Commission’s
previous directives and provide a basis for the Company to make recommendations in its
subsequent implementation case.
We find the general discussion, data, and methods explicated in the ECR section of the
October VODER Study comply with our previous directives and provide a basis to support the
Company’s recommended changes to its on-site generation tariffs. However, we note the
importance of an avoided generation capacity value that accurately considers capacity costs
actually avoided. We believe that additional discussion between Staff, Intervenors, and the
Company on the topic of avoided line losses, during the implementation case, may be fruitful and
potentially resolve any remaining issues or confusion surrounding the Company’s calculation of
avoided line losses.
We reiterate that extraneous issues under the ECR section beyond those approved for the
Study Framework detailed in Order No. 35284 should not be considered or provided as a basis for
proposed changes to the Company’s NEM program. For example, we clarified in Order No. 35284
that the Company, rather than a third-party, was best positioned to understand and study the
impacts of NEM on Company’s system. Order No. 35284 at 11. Generic conclusions and
recommendations from third-party studies that do not fully reflect the environmental conditions
and legislative requirements in Idaho or the particulars of the Company’s system, should not be
considered by the Company in its implementation recommendations. Likewise, environmental
benefits or costs that cannot be quantified or shown to affect customers’ rates, should not be
considered in valuing an ECR.
We find that the general discussion, data, and methods within and associated with the
Project Eligibility section of the October VODER Study comply with our previous directives and
support relevant changes to the Company’s on-site, self-generation offerings. Going forward, we
find that any proposed changes to the project eligibility cap need to consider safety and reliability
in addition to cost of service principles. We also reiterate that any proposed modifications to the
project eligibility cap must be made in the Company’s subsequent implementation case.
ORDER NO. 35631 30
We find that the general discussion, data, and methods within and associated with the
Implementation Considerations section of the October VODER Study comply with our previous
directives and provide a basis for the Company to propose changes to its NEM program in the
implementation case. We decline to rule, at this juncture, on the appropriateness of a transitional
rate—this is a proposal more properly explored during the implementation case. However, we
recommend that our previous determinations and reasoning on legacy systems in Order Nos.
34509, 34546, and 34892 inform any implementation proposal brought before this Commission.
We decline to order the Parties to meet prior to the Company’s filing of its implementation
case. However, nothing in this Order should be construed to prevent the Parties from meeting
together informally if they choose. Once the Company files its implementation case, we anticipate
the Parties who intervene working together on a procedural schedule to process that case which
must be brought before the Commission for approval. There will be opportunity for additional
entities to intervene in the Company’s subsequent implementation case. We encourage the Parties
in this case and the implementation case to continue to meet, when feasible, to discuss relevant
topics and issues.
We understand customers’ desire to both offset their energy bills through on-site, self-
generation and help to reduce demand on the Company’s system. We are very concerned, though,
by the number of commenters expressing worry that they will be unable to pay off their solar panel
investments if the NEM program changes. 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.
ORDER NO. 35631 31
We believe that a transparent and robust public participation process aids the Commission
in its decisions. To that end, we expect the Company to clearly and transparently notify all of its
customers— particularly its current non-legacy NEM customers and potential NEM customers—
of any proposed changes to its NEM programs.
O R D E R
IT IS HEREBY ORDERED that the Company’s October VODER Study is acknowledged.
IT IS FURTHER ORDERED that the Company shall file a new case requesting to
implement changes to the structure and design of its NEM program.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date of this Order regarding any matter
decided in this Order. Within seven (7) days after any person has petitioned for reconsideration,
any other person may cross-petition for reconsideration. Idaho Code § 61-626.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 19th day of
December 2022.

__________________________________________
ERIC ANDERSON, PRESIDENT

__________________________________________
JOHN CHATBURN, COMMISSIONER

//ABSTAINED//
__________________________________________
JOHN R. HAMMOND JR., COMMISSIONER

ATTEST:

_________________________________
Jan Noriyuki
Commission Secretary

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