20250930Final_Order_No_36785.pdf

Office of the Secretary
Service Date
September 30,2025
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER ) CASE NO. IPC-E-25-15
COMPANY'S APPLICATION FOR ITS )
FIRST ANNUAL UPDATE TO THE EXPORT )
CREDIT RATE FOR NON-LEGACY ON- ) ORDER NO. 36785
SITE GENERATION CUSTOMERS FROM )
JUNE 1, 2025 THROUGH MAY 31, 2026, IN )
COMPLIANCE WITH ORDER NO. 36048 )
On April 1,2025,Idaho Power Company("Company")applied to the Idaho Public Utilities
Commission ("Commission") to update the Export Credit Rate ("ECR") for non-legacy on-site
generation customers from June 1, 2025 through May 31, 2026, and to approve the Company's
corresponding proposed changes to Schedule 6, Residential Service On-Site Generation
("Schedule 6"), Schedule 8, Small General Service On-Site Generation ("Schedule 8"), and
Schedule 84, Large General, Large Power, and Irrigation On-Site Generation Service ("Schedule
84").
On April 21, 2025, the Commission issued a Notice of Application,Notice of Suspension
of Proposed Effective Date,Notice of Public Workshop,Notice of Customer Hearing, and Notice
of Modified Procedure, establishing a May 15, 2025, deadline for public and Commission Staff
("Staff') comments, and a May 22, 2025, deadline for the Company to file reply comments. Order
No. 36558.
The Commission granted intervention to: Kevin Dickey ("Dickey"); Clean Energy
Opportunities for Idaho ("CEO"); Scott Pinizzotto ("Pinizzotto"); Sierra Club & Vote Solar
("Sierra"); Martha Bibb ("Bibb"); and the city of Boise City ("Boise City"). Order Nos. 36562;
36588; 36601.
On May 7, 2025, Staff held an in-person and telephonic public workshop in Boise, Idaho.
On May 20, 2025, the Commission held an in-person and telephonic customer hearing in Boise,
Idaho. Approximately 45 customers testified at the hearing.
Based on our review of the record, the Commission now issues this Final Order
acknowledging that the Company's filing complied with the Commission-approved annual ECR
update method outlined in Order No. 36048, suspending the annual update portion of Order No.
ORDER NO. 36785 1

36048 for a period of three years, authorizing the Company to implement the updated ECR for
non-legacy on-site generation customers as modified by this Order, and acknowledging the
Company's consolidation of the Distributed Energy Resources ("DER") status report into the
annual ECR as modified by this Order.
BACKGROUND
In 2021, the Company requested the Commission initiate a multi-phase process for a
comprehensive study of the costs and benefits of on-site customer generation in anticipation of
requesting potential changes to the net-metering rate design,compensation structure,or ECR. Case
No. IPC-E-21-21. The Commission found it fair, just, and reasonable to direct the Company to
complete a study in 2022, prior to implementing any changes to its net-metering program, using
parameters specifically defined and explained by the Commission. Order No. 35284 at 9.In setting
the parameters of the study, the Commission considered several iterations of comments provided
by the Company, numerous intervenors, and the public. Id.
In 2022,the Company filed the Value of Distributed Energy Resources ("VODER") study
and requested the Commission complete the review phase of the study of the costs and benefits of
on-site customer generation by establishing a formal process and timeline for Staff, intervenors,
and the public to review and comment on the VODER study. Case No. IPC-E-22-22. In its review,
the Commission found the Company sufficiently completed the study design phase for the VODER
study and that the VODER study was completed in accordance with the Commission's directives
outlined in Order No. 35284. Order No. 35631 at 27.
In 2023, the Company requested the Commission authorize real time net billing with an
avoided cost-based financial credit rate for exported energy,a methodology for determining annual
updates to the ECR, and other administrative modifications to the Company's on-site and self-
generation tariffs. Case No. IPC-E-23-14. The matter garnered significant public comments,
numerous proposals and feedback from intervening parties, and sustained Company involvement,
all of which the Commission thoroughly considered before issuing its Final Order. Order No.
36048.
In Order No. 36048,the Commission approved the Company's request to implement a real-
time net billing ECR, as modified and refined from the original application to incorporate changes
proposed by the Company and requirements outlined in the Commission's Final Order,which was
informed by a thorough review of the full case record, including party proposals and public
ORDER NO. 36785 2

comments. Id. at 6. The Commission approved a seasonal and time variant methodology for
determining the ECR, which included a detailed framework and annual updates to major data
inputs, including: the avoided energy value; avoided generation capacity; avoided transmission
and distribution capacity; avoided line losses; and integration rates. Id. at 6-7. The Commission
directed the Company to update all components of the ECR except for the seasons and hours of
highest risk in an annual filing beginning April 1, 2025.Id. at 7.
THE APPLICATION
The Company applied for authority to implement the updated ECR for non-legacy on-site
generation customers from June 1,2025,through May 31,2026, and approval of its corresponding
proposed changes to Schedules 6, 8, and 84. Application at 1-2. The Company asserted that the
proposed updates complied with the method outlined in Commission Order No. 36048. Id. at 1.
As of December 31, 2024,the Company reported a total of 13,825 active and pending non-
legacy Exporting Systems in its Idaho jurisdiction.' Id. at 13. The Company explained its retail
customers who installed their own electricity-generating equipment, generated their own
electricity, and sought to interconnect Exporting Systems were billed under Schedule 6, Schedule
8, or Schedule 84. Id. at 2.
The Company proposed an updated ECR for non-legacy on-site generation Schedule 6, 8,
and 84 customers of 14.0598 cents per kilowatt-hour("¢/kWh")for summer on-peak hours, 1.7682
0/kWh for summer-off peak hours, and 0.9540 0/kWh for all hours during the non-summer season.
Id.
Additionally, the Company requested Commission authorization to consolidate its annual
filings and submit its annual DER status report concurrently with its annual ECR update. Id. at 2.
The Company believed that submitting both reports together would increase transparency for the
Commission, Staff, customers, and other stakeholders. Id. at 15.
' "Exporting System" is defined in the Company's approved tariffs as "a Customer-owned DER under the terms of
Schedules 6, 8,or 84,which is designed to provide for the transfer of electric energy to the Company. An Exporting
System is interconnected to the Company's system under the applicable terms of Schedule 68." Schedule No. 6, at
pg.6-2(effective January 1,2024).
ORDER NO. 36785 3

PUBLIC COMMENTS
As of May 15, 2025, a total of 8502 public comments had been filed in this case. Of those,
751 individuals (88%3) expressed opposition to the proposed changes to the ECR. Additionally,
364 commentors (43%) identified themselves as non-legacy customers. Some individuals raised
concerns about grandfathering, with 53 commenters (6%) stating that current non-legacy
customers should be granted legacy status.
Previous Orders/Studies
A total of 40 individuals (5%) questioned the validity of the VODER study, while 42
individuals (5%) recommended the Commission either review the current study or conduct
additional studies. Further, 221 individuals (26%) urged the Commission to consider the
environmental benefits of solar generation.
Compensation and Economics
Regarding compensation, 61 commenters (7%) expressed a preference for monthly net
metering (1:1) over real time metering.
Regarding billing impacts, 108 individuals (13%) reported higher overall monthly energy
costs as solar customers—citing the cost of installed systems combined with the proposed
reduction in the ECR. Additionally, 139 individuals (16%) highlighted the significant financial
investment they had made in installing net generation systems.
Concerns were also raised regarding fixed charges: 187 commenters(22%) opposed recent
increases in the monthly service charge, while 184 individuals (22%) cited the cumulative effect
of multiple rate increases within a short timeframe. Another 186 individuals (22%) stated they
had no alternative provider options and believed the Company operated as a monopoly.
A total of 301 individuals (37%) stated that the compensation rate was unfair. These
commenters asserted that, while customers paid the full retail rate for electricity, they were not
compensated at the same rate for electricity exported to the grid. Several commenters believed the
Company profited by purchasing excess electricity at a lower rate and reselling it at a higher retail
rate.
2 An additional 63 public comments were submitted after the May 15,2025,public comment deadline established in
Order No. 36558. These late-filed comments were similar in content with the timely filed comments.
3 All percentages were calculated based on the public comments submitted as of the May 15,2025,public comment
deadline.
ORDER NO. 36785 4

Installers and Annual ECR
Many individuals stated they had not been informed that the ECR would be subject to
annual adjustments. Commenters also reported that they were unaware of potential program
changes at the time they purchased and installed their systems. Several noted that they would not
have proceeded with installation had they known the compensation rates could change.
Company Compensation
A total of 274 individuals (33%) expressed concerns about high Company profits, citing
what they perceived as excessive executive compensation and board member pay. Commenters
frequently used terms such as "greed" and"unfair compensation."
Disincentives
Comments from 309 individuals (36%) felt the Company was penalizing or discouraging
customers from generating clean energy, despite having previously promoted solar adoption and
encouraged customers to "go green."
PARTY COMMENTS
A. Staff Comments
Staff Analysis
Staff reviewed the Company's Application,the proposed tariff revisions,and the associated
inputs to the ECR calculation. Staff Comments at 3. Based on its review, Staff believed the
Company's Application complied with Order No. 36048. Id.
However, Staff identified several concerns related to the Company's 2024 Variable Energy
Resource ("VER") study. Id. at 5. Staff recommended that the Commission adopt the current
integration cost value of 0.293¢/kWh for this filing,rather than the increased value of 0.697¢/kWh
derived from the 2024 VER study. Id. Staff also recommended in Case No. IPC-E-25-07 that the
Company undertake a new VER study within six months following the filing of the 2025 Integrated
Resource Plan ("IRP"). Id. Staff believed this timeline would allow sufficient opportunity for the
Company and Staff to reconcile outstanding issues and ensure integration costs used in the 2026
ECR update are accurate and reliable. Id.
Staff stated that the updated ECR as proposed by the Company, would result in a
significant increase to the bills of on-site generators under Schedules 6, 8, and 84. Id. at 6. Staff
believed that the on-site generation classes (Schedules 6, 8, 84) have faced numerous increases
in their monthly bills over the past 18 months.Id. at 6. Staff stated that although billing increases
ORDER NO. 36785 5

existed for all three classes, Staff focused its analysis on Schedule 6 which applies to the majority
of on-site generation customers.Id.
Under the proposed ECR,Staff believed the average monthly bill for a Schedule 6 customer
would increase from $62.35 to $83.62, representing an average increase of approximately 34%.
Id. However,the impact would not be uniform across the class.Id. at 6-7. Staff s analysis indicated
that customers who import the least electricity from the utility (and therefore export the most)
could see bill increases of approximately 60%, while customers who import the most(and export
the least) would experience increases closer to 17%. Id. at 7.
Staff noted that Schedule 6 customers already experienced an average rate increase of
approximately 24% when the transition from net metering (1:1) to net billing (ECR) was
implemented on January 1,2024.Id. When combined with the proposed ECR updates,the average
Schedule 6 customer could face a cumulative rate increase of approximately 67% over an 18-
month period. Id. For customers who are high net exporters, the combined increase may exceed
100%. Id.
In addition to these ECR-related impacts, Staff stated that two general base rate increases
were approved and implemented during the same 18-month period: one in Case No. IPC-E-23-11,
effective January 1,2024, and a second in Case No. IPC-E-24-07, effective January 1, 2025.Id. at
8.
Mitigation Proposal
To mitigate the substantial increase in customer bills resulting from the proposed ECR
revisions, Staff proposed implementing a cap on the year-to-year change in the ECR. Id. Staff
believed that this mitigation measure would help reduce annual fluctuations in the ECR and
promote greater bill stability for on-site generation customers. Id.
Staff reasoned that rate stability was a critical regulatory objective intended to shield
customers from rate shock. Id. To achieve this, Staff suggested that the cap include both a ceiling
and a floor to limit the extent of annual changes in the ECR—both increase and decreases. Id. at
9. Staff proposed that the Commission apply this capping mechanism to the ECR, with the
understanding that it must be tailored to the specific methodology used in calculating the ECR.Id.
Staff noted that the ECR consisted of two components: (1) the value of avoided energy
costs and (2) the value of avoided capacity costs. Id. Staff proposed that the capping mechanism
be applied solely to the avoided energy value component for four primary reasons: (1) Staff
ORDER NO. 36785 6

believed that the avoided energy value was the most significant driver of the ECR and influenced
all its fluctuations, including the summer and non-summer rates, as well as the on-peak rates; (2)
Staff noted that the avoided energy value, which was based on market prices derived from one
year of historical data, was likely to exhibit significant year-to-year volatility due to external
factors such as weather conditions, hydroelectric availability, natural gas supply and pricing, and
changes in system load; (3) Staff asserted that the avoided capacity value applied only during a
limited number of critical hours in the summer and only affected on-peak exports and as such,
applying a cap to the capacity component would have a negligible financial impact on most on-
site generation customers and could reduce the incentive for those customers to export during
capacity-critical periods; and 4) Staff believed the calculation for the avoided cost of capacity
already contained some level of mitigation in the five-year rolling average of historical Effective
Load Carrying Capacity ("ELCC") values.Id.
Based on this reasoning, Staff proposed limiting the year-over-year change in the ECR
energy value to no more than 301/oeither upward or downward-relative to the current ECR
energy value. Id. Staff proposed this cap be applied separately to the Summer and Non-Summer
energy values. Id. at 10. To support this recommendation, Staff provided Table No. 4, which
presented a comparative analysis of this year's ECR under various capping scenarios, specifically
showing the impacts of 20%, 30%, and 40% caps. Id.
Table No. 4-Alternative ECRs if Cap is Applied
Export Credit Rate by Component(cents/kWh) Max Change current proposed 20% 30% 40%
Energy Summer 5.65330 1.76820 4.52260 3.95730 3.39200
Including integration and losses Non-Summer 4.83650 0.95400 3.86920 3.38560 2.90190
Annual* 5.15660 1.28520 4.13500 3.61810 3.10130
Generation Capacity On-Peak 11.58620 11.90170 11.90170 11.90170 11.90170
Off-Peak 0.00000 0.00000 0.00000 0.00000 0.00000
Annual* 0.78710 1.13600 1.13600 1.13600 1.13600
Transmission&Distribution Capacity On-Peak 0.24560 0.38990 0.38990 0.38990 0.38990
Off-Peak 0.00000 0.00000 0.00000 0.00000 0.00000
Annual* 0.01670 0.03720 0.03720 0.03720 0.03720
Total Summer On-Peak 17.48500 14.05980 16.8142¢ 16.24890 15.6836¢
Summer Off-Peak 5.6533 ¢ 1.76820 4.52260 3.95730 3.3920¢
Non-Summer 4.83650 0.95400 3.86920 3.38560 2.90190
Annual* 5.96030 2.45850 5.30830 4.79140 4.27450
Id.
Staff also provided Table No. 5, with an estimated average monthly bill increase (for
Schedule 6 customers) if the energy caps of 20, 30, or 40%were applied. Id.
ORDER NO. 36785 7

Table No. 5—Average Billing Impact(Schedule 6)
Export Credit Rate by Component(cents/kWh) Max Change current proposed 20% 30% 40%
Monthly Bill Increase (from current ECR) 34.1% 8.6% 13.3% 17.9%
Id. Staff believed an average monthly bill increase of approximately 13%was reasonable and
recommended a 30%year-to-year change limit.Id.
Staff acknowledged that if the Commission adopted the proposed 30% cap on year-over-
year changes to the ECR avoided energy cost value, customers who consumed energy from the
system would pay either more or less than the actual avoided cost for exported energy. Id. The
outcome would depend on whether the mitigated energy value included in the ECR was higher or
lower than the true avoided cost. Id. As a result, Staff noted that customers would no longer be
indifferent between receiving energy from on-site generators who export to the grid and receiving
energy from the Company's own system resources.Id. Staff estimated that its proposed mitigation
approach would increase total ECR-related credits by approximately $4 to $5 million over the
coming year.Id. at 11.
Staff further recommended that the ECR percentage cap remain in place on a permanent
basis, regardless of whether the avoided energy value increased or decreased in future years. Id.
Staff believed the cap would smooth out large energy price swings.Id. Staff believed the cap would
serve to buffer customers from significant swings in market-based avoided energy prices, thereby
enhancing rate stability.Id. Staff also observed that,if the weighted average energy price remained
relatively constant over multiple years, the ECR value—despite being capped—would eventually
converge with the uncapped or unmitigated avoided cost value within approximately two years.
Id.
B. Boise City Comments
Boise City stated that it had a direct interest in the Company's approach to compensation
for solar on-site generation, as the proposed changes to the ECR would materially impact the city's
municipal utility billing. Boise City Comments at 1. Boise City stated it manages multiple rooftop
solar accounts, which generated 109,494 kilowatt-hours ("kWh") in 2024. Id. Boise City stated it
represents, through its constituents, nearly 139,000 customers (residential as well as
commercial/industrial) as of 2024. Id. at 2. Accordingly, Boise City emphasized its responsibility
to ensure that rates remain not only fair but also affordable for its citizens. Id.
ORDER NO. 36785 8

Boise City stated that it had adopted a Climate Action Roadmap setting a goal of carbon
neutrality by 2050.Id. That roadmap included specific targets to increase energy efficiency,reduce
greenhouse gas emissions, and promote the deployment of clean energy—particularly rooftop
solar—on both municipal and community buildings. Id. Boise City asserted that lowering ECR
rates, even on a temporary basis, would disincentivize further investments in rooftop solar and
extend the payback period for those who had already made such investments. Id.
Boise City agreed with the Commission's established position that the fundamental
purpose of on-site generation is to offset a customer's own usage; that on-site generation should
not result in cost shifting between generators and non-generators; and that customers who generate
on-site should receive a fair value for their exports. Id. at 2 (citing Order No. 36048). However,
Boise City raised concerns that the current ECR update proposal lacked clarity in how"fair value"
was defined and calculated.Id.
Boise City stated that the proposed ECR rates were lower than the avoided cost rate under
the Public Utility Regulatory Policies Act of 1978.Id. Boise City expressed concern that although
the Company's proposal may comply with cost-of-service principles,the resulting rates could still
be unfair and misaligned with long-term affordability and risk mitigation goals. Id. Boise City
urged the Commission to evaluate the proposed ECR holistically and in the context of the
significant demand growth the Company anticipates over the next 20 years. Id. at 3.
Boise City believed that customers who installed rooftop solar systems under the current
(non-legacy) rate structure would face financial uncertainty under the proposed ECR. Id. Boise
City warned that extended payback periods could reduce the incentive for future solar investments.
Id. Boise City referenced data indicating that Schedule 6 customers could face an average monthly
bill increase of 71%, while an average residential customer using 900 kWh per month could
experience a 37-57%increase and argued that lowering the ECR under these conditions would run
counter to principles of affordability and fairness, particularly for customers who lack the
resources to invest in battery storage. Id.
In support of a more comprehensive approach, Boise City pointed to its prior
recommendation in Case No. IPC-E-22-22 that the Company incorporate fuel price risk—
especially for natural gas and coal-fired generation—into avoided cost of energy calculations. Id.
at 4-5. Boise City stated that the current ECR methodology failed to reflect such fuel cost risk, a
shortcoming it viewed as inconsistent with least-cost, least-risk planning principles.Id. at 5. Boise
ORDER NO. 36785 9

City believed omitting fuel cost risk is inconsistent with least-cost, least-risk planning principles
and underrepresents the long-term value of customer-generated solar and argued that excluding
fuel risk undervalued the long-term contribution of customer-sited solar and recommended that
the Commission direct the Company to explicitly include this consideration in future ECR filings.
Id.
Boise City further asserted that the Commission had the authority and the obligation to
ensure rate structures align with fair, forward-looking energy policy and contended that the
Commission was not bound by prior decisions where those decisions conflicted with evolving
policy objectives.Id. Boise City believed the Commission has broad authority to set rates that are
fair,just, and reasonable, emphasizing that while cost-of-service principles could serve as a useful
guideline, strict adherence to a rigid class cost-of-service methodology was neither required nor
always appropriate. Id.
Finally, Boise City cautioned that unless the Commission intended to review each ECR
calculation individually, the ECR would remain one possible outcome among many, heavily
influenced by input assumptions.Id. Boise City suggested that the Commission reserve the ability
to make post-facto adjustments to ECR values to ensure rooftop solar remains a viable means for
customers to offset their consumption and receive fair value for excess energy exported to the grid.
Id. at 6.
C. Clean Energy Opportunities for Idaho Comments
CEO expressed several concerns regarding the Company's proposed ECR update and the
method used in the VER and VODER studies. CEO Comments at 1. CEO challenged the
Company's assertion—based on its VER study—that utility-scale solar generation profiles were a
reasonable proxy for on-site solar generation. Id. at 2. CEO argued that the export patterns from
customers with behind-the-meter self-generation differed significantly from utility-scale
generation in terms of quantity, timing, and output variability. Id. As such, CEO contended that
increasing integration costs for on-site generators without conducting a separate evaluation
specific to distributed generation was inappropriate and inequitable. Id. at 3.
CEO also objected to the Company's reliance on forecasted market prices in the VODER
study. Id. at 4. CEO maintained that the use of a single year of forecasted prices introduced
instability in the energy value calculation. Id. Instead, CEO recommended adopting a rolling
ORDER NO. 36785 10

average of export-weighted market prices over multiple years, which it believed would reduce
volatility without sacrificing accuracy.Id.
CEO raised concerns regarding the treatment of negative market prices in the energy
component of the ECR. Id. Specifically, CEO noted that when market prices were negative, the
Company appeared to assume an incurred cost equivalent to the negative price, thereby reducing
the average ECR for customers. Id. CEO argued this approach was flawed, asserting that market
prices should reflect the opportunity cost of energy the Company would otherwise need to generate
or procure—not the cost to receive exported energy from customers.Id. at 5.
CEO also identified a misalignment between the price signals sent for energy consumption
and those sent for energy exports.Id. at 6. This disconnect, CEO argued, imposed undue financial
harm on customers, particularly Idaho farmers, who rely on predictable pricing signals for
operational planning.Id. CEO believed customers should not be penalized due to delays in aligning
consumption rates with hourly cost causation for both energy and capacity.Id.
Regarding rate design, CEO cautioned that any proposed reduction in the non-summer
ECR exceeding 50% would be unreasonable and inconsistent with the regulatory principle of
gradualism.Id. at 7. CEO urged the Commission to ensure that rate changes proceed in a measured,
incremental manner to avoid customer disruption and support long-term investment in distributed
energy resources.Id.
D. Kevin Dickey Comments
Dickey asserted that the Commission had allowed the Company to unilaterally determine
the ECR and that the resulting policy was neither fair,just, nor reasonable. Dickey Comments at
2. He believed the Company had a vested interest in maintaining a low ECR and faced a conflict
of interest in setting the rate. Id.
Dickey further contended that the Company supplied renewable energy to the grid through
its partnership with Micron, and that this renewable energy directly competed with Idaho's small-
capacity generators.Id. He cited recent blackouts in Spain as evidence that electrical systems have
a threshold for safely integrating renewable energy. Id. According to Dickey, the Company
promoted a low ECR to discourage small generator capacity,thereby preserving grid access for its
large generator partners to dominate the renewable energy market.Id.
Dickey maintained that the Company was conflicted when it presented the VODER study
to establish the ECR and argued that the Commission had permitted a conflicted party to determine
ORDER NO. 36785 11

the method for setting the ECR.Id. at 4. He believed that a third-party study would have provided
a more appropriate and impartial basis for determining the ECR. Id.
Dickey claimed that the use of negative values in the 2024 energy value calculations
demonstrated the Company's manipulation of the ECR in its favor. Id. at 5. He argued that the
Company's objections to his production requests effectively acknowledged that the pricing used
in the Energy Value portion of the VODER calculation was unrealistic and had been intentionally
selected to minimize the resulting ECR.Id.
Dickey concluded that the Company should be excluded from any future role in
determining the ECR and that an independent third party should be retained to help establish a fair,
just, and reasonable outcome. Id. at 6. He further asserted that "whoever determined that the
Legacy 1:1 system of remuneration needed to be replaced" and should bear the cost of such third-
party assistance. Id. Lastly, Dickey alleged that the Company had used funds saved by reducing
payouts to small generators to pay executive bonuses and argued that the Company should fund
an independent evaluation to prove that the Legacy 1:1 program was unfair.Id.
E. Martha Bibb Comments
Bibb stated that in 2021, the Commission directed the Company to quantify the
environmental and health benefits associated with solar power.Bibb Comments at 1. Bibb asserted
the Company's VODER study concluded that the quantified value of these benefits was 0 0/kWh.
Id. at 2. In contrast, Bibb noted that the Crossborder4 study determined the value of environmental
and health benefits from solar power to be between 3 ¢and 11.7 0/kWh.Id. Based on this disparity,
Bibb urged the Commission to reassess the Company's assumptions regarding the value of solar
to environmental and public health.Id. She believed that such a reassessment would align with the
Commission's mission to promote general safety, health, and public welfare.Id.
Bibb asserted that solar power displaces fossil fuel-based generation and helps mitigate
climate change, resulting in tangible health benefits and lower health-related costs for both
ratepayers and society at large. Id. at 3. She maintained that the Commission had a moral and
public duty to account for the value of health-related cost savings in its decision-making.Id.
4 In Case No. IPC-E-22-22, intervenor Idaho Conservation League co-commissioned the Crossborder Energy
("Crossborder")study to review and assess the Company's VODER study and ultimately believed the VODER study
undervalued distributed generation.
ORDER NO. 36785 12

Bibb further argued that solar energy reduces the Company's exposure to expenses related
to fossil fuel use and climate change, which could ultimately affect rates and ratepayers. Id. She
believed that the Company could leverage solar generation to avoid future costs such as carbon
taxes and indemnity bonds.Id. Bibb encouraged the Commission to revisit the Crossborder study,
which she claimed quantified avoided carbon costs.Id.
Bibb also stated that distributed solar helps mitigate the climate-related impacts on
hydropower generation and that these avoided costs should be reflected in the ECR calculations.
Id. at 4. She contended that the ECR should also account for avoided costs related to the reduction
of climate-driven natural disasters, which she attributed in part to the deployment of distributed
solar. Id.
Additionally, Bibb argued that solar generation reduces reliance on "distant, dirty power
generation,"thereby decreasing the Company's line losses,increasing grid resilience,and reducing
the need to build new methane gas plants.Id. She asserted that distributed solar lessens dependence
on long-distance transmission from centralized sources, which in turn decreases community
vulnerability during power outages. Id.
Bibb concluded by requesting that the Commission review the ECR methodology to ensure
it reflects the"full and true value that ratepayers receive, including any climate and environmental
benefits that ultimately tie back to system costs and customer rates."Id.
F. Scott Pinizzotto Comments
Pinizzotto stated that he was a solar homeowner who generated 21 megawatt-hours of solar
energy in 2024. Pinizzotto Comments at 1. He explained that for eight to nine months of the year,
his solar system produced more energy than his household consumed on a daily basis,resulting in
excess power being supplied to the grid. Id.
Pinizzotto expressed concern that the proposed ECR would be unfair to customers and
would disproportionately benefit the Company by allowing an excessive margin of profitability.
Id. He opposed the concept of varying the ECR throughout the day and argued that the rate the
Company pays for customer-supplied power should match the rate customers pay for energy
consumed from the Company.Id. at 2.
Pinizzotto further contended that the current methodology, as approved by the
Commission, did not prioritize fairness for customers. Id. Instead, he believed it enabled the
Company to achieve an excessive profit margin and failed to directly address the fixed costs
ORDER NO. 36785 13

associated with maintaining and distributing the infrastructure necessary for grid interconnection.
Id. at 3.
G. Sierra Club & Vote Solar Comments
Sierra stated that it believed the Company's Application contained errors and omissions
that undervalued solar exports from on-site generation customers, and that the existing record was
insufficient to determine whether the proposed ECR was accurate or appropriate. Sierra Comments
at 7. Sierra asserted that the proposed ECR would result in rate shock for on-site generation
customers and recommended that the Commission implement gradualism to mitigate sudden and
dramatic changes.Id.
Sierra noted that the proposed update would result in a 70-80% reduction in the avoided
energy cost component of the ECR compared to the current rate.Id. at 8. Sierra expressed concern
that basing the ECR on only 12 months of historical Energy Imbalance Market ("EIM") Load
Aggregation Point (`SLAP") prices would expose on-site generation customers to unacceptable
levels of financial risk and uncertainty—risks that would not be acceptable to other generation
resource owners. Id. Sierra argued that such volatility would make it difficult for customers to
assess the financial viability of investing in on-site generation. Id. at 8-9. To improve ECR
stability, Sierra recommended that avoided energy costs be calculated using a 36-month average
of ELAP market prices from January 2022 through December 2024. Id. at 9. Sierra further
recommended that the Commission direct the Company to revise its Application using this 36-
month ELAP market price average. Id.
Sierra also raised concerns regarding the VER study,which quantifies the cost of ancillary
services needed to integrate solar into the grid. Id. at 9-10. Sierra argued that increased battery
deployment should lower,not raise,integration costs.Id. at 10. Sierra further contended that using
a utility-scale solar generation profile to estimate integration costs for distributed on-site solar
generation was inaccurate and inappropriate; instead,the actual export profile of on-site generation
should be used. Id. at 12. Sierra urged the Commission to reject the Company's proposed
integration cost. Id.
Sierra also questioned the ELCC values the Company used in its calculations, citing
concerns about the continued use of a methodology that stakeholders and regulators could neither
review nor verify. Id. at 12-13. Sierra argued that on-site generation customers should be
compensated for updated ELCC calculations from 2020, 2021, and 2022, and claimed that the use
ORDER NO. 36785 14

of an incorrect ELCC average resulted in an underpayment of 1.503 0/kWh. Id. As a remedy,
Sierra recommended the Commission direct the Company to issue a one-time bill credit to each
on-site generation customer based on the energy exported during summer on-peak hours from
January 1, 2024, until the updated ECR is implemented.Id.
Sierra contended that the ELCC methodology produced unexpected and volatile results,
despite the predictable daily and seasonal patterns of on-site solar output. Id. at 14-15. Without
transparency in the ELCC calculations, Sierra stated that stakeholders could not determine whether
the low 2024 value was due to actual capacity changes or a methodological error. Id. at 14. Sierra
urged the Commission to approve a capacity contribution methodology that is both transparent and
verifiable.Id. at 18.
Regarding avoided transmission and distribution("T&D") costs, Sierra expressed concern
that the Company's approach relied on a short-term snapshot that identified only those T&D
projects that could be fully deferred by on-site generation.Id. at 19. Sierra argued that this standard
was inconsistent with how the Company treated other generation resources and failed to capture
the proportional value that on-site exports provide.Id. at 20. It recommended that the Commission
reject the Company's proposed avoided T&D cost value of$0 and direct the Company to quantify
the marginal value of avoided transmission costs due to on-site generation. Id. Sierra suggested
that this analysis could use the National Economic Research Associates regression method, the
avoided on-peak T&D capacity costs from the Company's 2023 IRP, or the Company's Open
Access Transmission Tariff rate. Id. at 21.
Finally, Sierra recommended that the Commission direct the Company to implement a
Virtual Power Plant ("VPP") program that would allow the Company to dispatch aggregated
customer battery systems. Id. at 24. Sierra proposed that the VPP program include a capacity
payment equal to the Company's cost for battery storage and stated that such a program could help
meet future energy needs in a manner that is affordable, reliable, flexible, and scalable.Id.
COMPANY REPLY COMMENTS
Company General Reply
The Company clarified that it believed the Application did not present a new proposal,but
rather, the Company filed an annual cost adjustment to the reimbursement rate for excess energy
generated by on-site generators based on the Commission approved methodology established in
2023. Company Reply at 1. The Company stated it recognized the proposed inaugural update
ORDER NO. 36785 15

would result in varying customer bill impacts, including large bill increases, and presented a"one-
time mitigation option for the Commission's consideration."Id. at 2.
The Company modified its request to the Commission, requesting the Commission issue
an order: (1) acknowledging the Company's original Application conformed with the
Commission-approved annual ECR update method outlined in Order No. 36048; (2) authorizing
the Company to implement the updated ECR for non-legacy on-site generation customers effective
June 1, 2025, as directed in Order No. 36048; (3) as needed, directing the Company to submit
corrected tariff sheets reflecting the incorporation of any mitigation measures ordered by the
Commission; and (4) acknowledging the Company's consolidation of the DER status report into
the annual ECR update.Id. at 2.
The Company stated its Application was initiated in compliance with Commission Order
No. 36048 issued in Case No. IPC-E-23-14. Id. at 3. The Company stated the Order approved
changes to its on-site generation service offerings including implementing, effective January 1,
2024, a seasonal and time-variant ECR with avoided cost-based value considerations for excess
energy exported to the Company's system by non-legacy customers as well as approving a method
to determine annual updates to the ECR. Id. The Company stated that in authorizing changes to
the Company's on-site generation offering, the Commission emphasized that the fundamental
purpose of on-site generation is to offset a customer's own usage, that on-site generation should
not create cost shifting between generators and non-generators, and that on-site generators should
be given a fair value for their exported energy. Id.
The Company stated the method approved in Order No. 36048 in Case No. IPC-E-23-14
was informed and refined by feedback from Staff and the parties in that case, including many of
the same parties who intervened in the current docket. Id. at 4. The Company stated the
Commission-approved method adopted in Order No. 36048 incorporated elements of the
Company's proposal in addition to proposed modifications recommended by Staff and the other
parties. Id. The Company stated it filed its first annual update of the ECR for non-legacy on-site
generation customers from June 1, 2025, through May 31, 2026, in compliance with the methods
prescribed by the Commission in Order No. 36048.Id. at 4-5. The Company believed no party had
taken the position that the Company's update failed to follow the Commission's direction from
Order No. 36048. Id. at 12. The Company suggested many commentors were unaware that the
ECR update proposed in this docket was an annual update based on the methodology that the
ORDER NO. 36785 16

Company believed to be "previously vetted, informed, and refined through a collaborative and
iterative process that represented the culmination of a multi-year effort to have the Commission
review and modify outdated net metering offerings to better align with the actual circumstances."
Id. at 5.
The Company stated that many of the comments overlooked the regulatory precedent and
that many of the issues raised were already addressed by the Commission or were otherwise
outside the scope of a compliance filing docket.Id. at 8-9.The Company reasoned that even though
many of the comments disagreed with the ECR methodology previously adopted by Order No.
36048, it was not appropriate for parties to now challenge the approved methods for calculating
the ECR components, or to seek to deviate from the annual update process directed by the
Commission.Id. at 9.The Company believed such challenges represent an impermissible collateral
attack on Order No. 36048, a violation of Idaho Code § 62-625, which provides: "[a]ll orders and
decisions of the commission which have become final and conclusive shall not be attacked
collaterally."Id. at 9-10. The Company stated Idaho Code §§ 62-626 and 61-624 direct that Final
Orders of the Commission should be challenged either by petition to the Commission or appeal to
the Idaho Supreme Court. Id. at 10. The Company believed the parties had not demonstrated that,
in the 18 months since the Commission issued its decision authorizing the ECR methodology,
conditions have changed such that the method needs to be re-evaluated. Id. at 10-11.
The Company believed many commentors misunderstood the role of the ECR, and the
Company emphasized previous Commission Orders where the Commission has stated the purpose
of establishing rates "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."Id. at 11 (quoting Order No. 35631).
The Company stated it did not address recommendations and considerations set forth in
the comments that were outside of the scope of these proceedings including proposals calling for
alternative compensation structure, modifications to the ECR methodology, or that otherwise
sought to relitigate issues that were already decided in a prior case. Id. at 12.
ORDER NO. 36785 17

Company Reply to Components of the ECR
A. Avoided Energy Costs
i. Energy and Avoided Line Losses
The Company rejected all recommendations and maintained that using actual historical
ELAP prices, weighted for customer exports, was an appropriate method for valuing the non-firm
energy provided by customer on-site generators as the Company believed it achieved timely
recognition of changing conditions on the Company's system and the broader power markets. Id.
at 14. The Company believed including negative ELAP market prices in the hours they may occur
when determining each year's ECR was appropriate and necessary to keep non-participating
customers indifferent.Id. at 16.
ii. Integration Costs
The Company found Staff s position that proposed integration costs are under-allocated
through the ECR contrary to CEO and Sierra, which both took the position the integration costs
proposed were too high.Id. at 18. The Company stated relying on the proposed integration charge
in this case reasonably assigns a portion of the costs associated with integration to on-site
generation exports. Id. at 19. The Company stated that to the extent future VER studies identify
methods to adjust for the under-allocation issue Staff raised, those results will impact future ECR
updates. Id. The Company stated it has agreed, in Case No. IPC-E-25-07, to work with Staff to
address the issues raised in Staff s comments, which include several aspects expected to impact
the integration costs assigned to the ECR in future updates.Id.
B. Avoided Generation Capacity
The Company disagreed with comments that claimed the ELCC is non-transparent or an
un-verifiable method. Id. at 20. The Company disagreed with claims about data manipulation to
exclude off-peak exports and believed the ELCC calculation incorporated all hours of the year,
including on-peak and off-peak exports, as adopted by the Commission in Order No. 36048.Id. at
20-21. The Company disagreed that the model did not account for the impact of avoided line losses
because line losses were not part of the ELCC calculation.Id. Line losses were accounted for after
the ELCC calculation was performed, as directed by Order No. 36048. Id.
The Company believed that Sierra overstated the significance of the proposed adjustments
to the ELCC values for 2021 and 2022 in the ECR update because the Company updated its
calculation of the ELCC for customer generator exports to reflect that the resource originates
ORDER NO. 36785 18

behind-the-meter. Id. at 23. The Company disagreed that it was appropriate or necessary to issue
a bill credit to customers to account for a corrected ELCC.Id. The Company reasoned the proposal
to apply a credit to customers based on a rate different than the Commission-approved tariff would
violate the filed-rate doctrine, codified in Idaho Code § 61-313, and was therefore not
inappropriate.Id.
C. Transmission and Distribution Capacity
The Company stated that it updated all values of the ECR, including the avoided T&D
capacity component, in accordance with Order No. 36048. Id. at 24. The Company reasoned that
the Commission had already considered several of the alternative methods presented in previous
ECR cases and the Commission declined to adopt those methods.Id.
Company Reply to Mitigation
The Company believed that the proposed ECR rates presented in this case complied with
the Commission's three primary principles that guided its decision in Order No. 36048: (1) the
fundamental purpose of on-site generation to offset a customer's own usage, (2) that on-site
generation should not create cost shifting between generators and non-generators, and (3) on-site
generators should be given a fair value to their exported energy.Id. at 26. The Company believed
the updated rates in this case complied with all three principles because: (1) the updated ECR
would have no impact to a customer's ability to generate and consume their own energy; (2)
implementing the updated ECR, as proposed, would help to ensure nonparticipating customers
remain indifferent to the source of their energy, whether it be from an on-site generator's exports
or another Company resource; and(3)the Commission recently found the approved methodology
results in a fair assignment of value to on-site generators.Id.
The Company did not agree with Staff s mitigation mechanism proposal, as described in
Staffs comments. Id. at 27. The Company stated it is concerned that in a future period where
market prices increase,thereby positively impacting the ECR, stakeholders would expect the ECR
to reflect that value and would be highly critical of the Company employing a mitigation measure
that restricted the value of exported energy from customer generators. Id. The Company also
disagreed with Staffs assessment of how long it would take the avoided energy component to
equalize to the unmitigated value under Staffs proposal.Id. While Staff stated that it believed the
unmitigated value would equalize in two to three cycles, the Company believed the equalization
would take four cycles to complete.Id. at 28.
ORDER NO. 36785 19

The Company believed a one-time 50% change limit, as proposed by CEO, would yield a
more favorable result than Staff s proposed methodology. Id. at 30. The Company stated that
should this mitigation proposal be adopted,the application of a 50%mitigation to both the summer
and non-summer avoided energy components would be appropriate, contrary to CEO's approach
to only apply the mitigation to the non-summer months. Id.
The Company requested the Commission reject Staffs recommendation to implement an
ongoing mitigation mechanism. Id. The Company believed an ongoing mitigation mechanism
would be unnecessary and would ultimately impact the rates of non-participating customers.Id. at
32.
Finally, the Company requested the Commission consider the reasonableness of
implementing mitigation, when the Company believed any mitigation measure implemented
would inevitably perpetuate inaccurate price signals to customers. Id. The Company believed
updating the ECR consistent with the previously established methodology would be the best way
to ensure customers receive an accurate price signal to inform decision making and to ensure non-
participating customers remain indifferent.Id.
DER Report
The Company acknowledged Sierra's suggestion that the Company make past copies of
the DER report available on the Company's website, and the Company stated that it intends to
continue making three years of past reports available, which the Company believed is consistent
with how it maintains other Commission-required reports. Id. at 33. The Company also stated it
intended to name the report based on the reporting year, rather than the month of submission so it
is titled consistent with the reporting period.Id.
Public Comments
In response to customer comments regarding the impact the proposed ECR changes would
have on the payback period for customers, customers' unawareness that the rates could change,
and/or calls for expanded legacy treatment, the Company stated that it was not within its purview
to ensure the bilateral transaction between the sellers or installers of on-site generation systems
and their customers was equitable and economically supportable. Id. at 34-35. The Company
believes it is legally obligated to consider the collective interests of all its customers and to develop
mechanisms based on an economically supportable analysis that result in fair,just, and reasonable
rates for customers,rather than simply as a means to achieve particular policy goals.Id. at 35. The
ORDER NO. 36785 20

Company believed the Commission had been clear in previous orders that the Commission's
objective was to ensure that customers are paid fair, just, and reasonable rates for their exports,
and that non-self-generating customers are not subsidizing the rates for self-generating customers.
Id. The Company stated its objective was not to ensure that customers who have installed self-
generation facilities are able to recoup their investment in a specific period of time or earn a return
on investment.Id.
The Company stated that the procedural schedule in Case No. IPC-E-23-14, and the series
of on-site generation dockets that preceded it provided ample opportunities for comment and
customer participation, and the Company believed public and party involvement had been robust
and instrumental throughout the underlying process. Id. at 37. The Company stated it has been,
and will continue to be, committed to clearly and transparently notifying potential and existing on-
site generation customers that on-site generation rates and program structure are subject to change.
Id.
The Company provided a summary of the communications it sent to its customers to notify
them of the potential change to rates,information on Commission Orders,and information required
to be provided by solar retailers. Id. at 38-40. The Company also provided the customer
acknowledgement the Company requires all generation applicants to sign, acknowledging they
understand the program fundamentals and that compensation for excess energy is subject to
change.Id. at 41.
COMMISSION FINDINGS AND DECISION
The Commission has jurisdiction over the Company's Application and the issues in this
case under Title 61 of the Idaho Code including Idaho Code §§ 61-301 through 303. The
Commission is empowered to investigate rates, charges,rules,regulations,practices, and contracts
of all public utilities and to determine whether they are just, reasonable, preferential,
discriminatory, or in violation of any provisions of law, and to fix the same by order. Idaho Code
§§ 61-501 through 503.
The Commission now considers the Company's request to update the ECR for non-legacy
on-site generation customers and the Company's corresponding proposed changes to Schedules 6,
8, and 84. The Commission has examined the comprehensive record in this matter, including all
comments submitted by the public, intervenors, and the Company. The Commission appreciates
ORDER NO. 36785 21

the robust public engagement—through both written comments and live testimony—and extends
its gratitude to everyone for the thoughtful participation and valuable insights.
Issues Raised in Prior Orders
Several parties and public commenters raised concerns regarding specific components of
the proposed ECR update. Sierra challenged the avoided cost of energy and integration cost
components,arguing the use of 12 months of ELAP pricing was too volatile and that the integration
cost methodology failed to reflect reduced costs due to increased battery deployment. Sierra also
questioned the transparency and accuracy of the Company's ELCC capacity calculations and the
assignment of a $0 value to avoided transmission and distribution costs. Bibb and other public
commenters emphasized the failure to quantify environmental and health benefits, contrasting the
Company's $0 valuation with other studies assigning significant societal benefits to these
components. Public commenters also expressed concern over increased payback periods, lack of
awareness about ECR variability; several requested extended legacy treatment beyond the
grandfathering that was approved in Order No. 34509, in Case No. IPC-E-18-15. The Company
argued that the proposed ECR update adhered to the Commission-approved method, opined that
broader changes would constitute an improper collateral attack on prior Commission orders, and
reiterated that its responsibility is to ensure fair and non-subsidizing rates—not to guarantee
customer investment returns.
The Commission has previously and continues to maintain that "the fundamental purpose
of on-site generation is to offset a customer's own usage; that on-site generation should not create
cost shifting between generators and non-generators, and that on-site generators should be given a
fair value for their exported energy." Order No. 36048 at 5. Additionally, in Order No. 35284,the
Commission reiterated that"tariffs are not contracts and the prices and terms of service for the net-
metering program are subject to change."Order No. 35284 at 10.5 Further,the Commission stated
that "[a] utility's rate schedules, including net-metering program fundamentals, are subject to
change. As such, there is no guaranteed return on investment."Id.
In the same spirit, the Commission has emphasized the importance of efforts to notify
potential customers that rates are subject to change and could affect the projected repayment period
5 The Commission has repeatedly stated over the years that tariffs are not contracts and that prices and terms of service
for the net metering program are subject to change.See Order No.30227 at 7;Order No.32280 at 4;Order No.34046
at 19;and Order No. 34335 at 2.
ORDER NO. 36785 22

of the customer's investment. Order No. 34509 at 13. The Commission noted the statutory
provisions in Title 48 and stated "[a]s of October 1, 2019, the Residential Solar Energy System
Disclosure Act, Idaho Code §§ 48-1801 - §48-1809, requires a written statement be provided to
potential customers that states, in capital letters, among many other warnings, that
`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.'Idaho Code §48-
1804(c)(ii)."Id.
In Case No. IPC-E-23-14, the Commission directed 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" and to submit proposed updates to the corresponding schedules reflecting the
updated ECR. Order No. 36048 at 7. The Commission provided a comprehensive review of each
component of the ECR calculation in its decision, seeking "to accurately assign the appropriate
share of fixed costs and unquantified benefits of on-site customer generation, and to provide a
reasonable balance between the interests of customers with on-site generation, and customers
without."Id. at 6.
In formulating the ECR, the Commission considered the long history of cases dealing with
on-site generation, public comments and testimony, and proposals offered by all parties. Many of
the proposals and concerns offered and addressed in Case No. IPC-E-23-14 are similar in nature
to the recommendations and concerns offered in this matter. As such,to the extent these proposals
and concerns fall outside the scope of this proceeding, they will not be discussed further.
VER Study Concerns
Staff, CEO, and Sierra raised concerns regarding the integration rates from the VER study
used in the calculation of the ECR. While the Commission acknowledges these concerns and
recommendations, those issues were addressed by Order No. 3661 in Case No. IPC-E-25-07. In
that case, Staff recognized the impact of the VER study on the ECR and recommended working
with the Company to resolve various issues including inter-hour integration costs, differences in
wind and solar integration costs, under-allocation, and incorporating on-site generation in the
analysis. Order No. 36661 at 2-3. Order No. 36661 directed the Company to work with Staff prior
to the next VER study and attempt to resolve Staff s outstanding concerns. Id. at 4. Additionally,
ORDER NO. 36785 23

the Commission ordered the Company to file a new VER study within six months after the filing
of each IRP. Id.
Present Issues
The Commission has reviewed the Company's Application to update the ECR, along with
the proposed updates to Schedules 6, 8, and 84, in accordance with the directives of Order
No. 36048. Based on our review, the Commission finds the Company's filing is in conformance
with the Commission-approved annual ECR update methodology outlined in Order No. 36048.
While the Company has complied with Order No. 36048,the Commission is keenly aware
that all customers—including non-legacy on-site generation customers—have faced increases to
their average monthly bills over the past 18 months. The Commission recognizes that the updates
to the ECR proposed in the Company's Application would further affect customers in Schedule 6,
8, and 84. As demonstrated in the record, if the proposed updates to the ECR were approved as
filed, some Schedule 6 customers' monthly bills would increase by up to 100%in a relatively short
period (factoring in the multiple changes to the ECR compounded with the recent general rate
increases).
To reduce the impact of the recent rate changes,the Commission finds that some mitigation
is reasonable in the updated ECR. After considering the options presented, an ECR update where
the change in the avoided energy value is limited to a 40% decrease from the current ECR's
avoided energy value, applied to both the summer and non-summer months, is reasonable.
We find that the annual update to the ECR as required by Order No. 36048 is difficult for
non-legacy on-site generation customers to adjust to and complicates investment decisions by
potential on-site generation customers. Therefore, we have determined that suspension of the
annual update requirement is appropriate for now. The annual update requirement of Order No.
36048 shall remain suspended and the mitigated ECR shall remain in effect until 2028, at which
time the Company shall update all components of the ECR except the season and hours of highest
risk in an annual filing by April 1,2028, in compliance with Order No. 36048. The Company shall
submit a compliance filing with Schedules 6, 8, and 84 conforming with this Order.
The Commission acknowledges and accepts the Company's decision to consolidate the
DER status report into this year's annual ECR update. However, for the period the ECR is set by
this Order, the Company shall annually submit the DER status report in a separate filing. When
ORDER NO. 36785 24

the annual ECR update resumes in 2028, the Company may once again combine the DER status
report with the ECR update.
ORDER
IT IS HEREBY ORDERED that the Company's Application to update the ECR for non-
legacy on-site generation customers is approved, subject to the mitigation and modifications set
forth in this Order, effective October 1, 2025.
IT IS FURTHER ORDERED that the annual update requirement of Order No. 36048 is
suspended until 2028.
IT IS FURTHER ORDERED that the Company shall maintain the ECR at the rates set by
this Order until it is updated based on the Company's April 1, 2028, filing, which shall be in
compliance with Order No. 36048.
IT IS FURTHER ORDERED that the Company shall submit, as a compliance filing,
corrected tariff sheets reflecting the updated ECR as modified by the Commission decision above
within 30 days of this Order.
IT IS FURTHER ORDERED that for 2026 and 2027, the Company shall file a standalone
DER status report. In 2028 the Company is permitted to file its DER report with the annual ECR
update.
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. See Idaho Code § 61-626.
ORDER NO. 36785 25

DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 30ffi day of
September 2025.
G
Grp
DWARD LODGE, RE I ENT
R. HAMMOND JR., COMMISSIONER
DAYN HARDIE, COMMISSIONER
ATTEST:
Laura Calderon Robles
Interim Commission Secretary
I:\LegahELECTRICUPC-E-25-15_EMordersUPCE2515_final_em.docx
ORDER NO. 36785 26