20231229Final_Order_No_36048.pdf

ORDER NO. 36048 1
Office of the Secretary
Service Date
December 29, 2023
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF IDAHO POWER
COMPANY’S APPLICATION FOR
AUTHORITY TO IMPLEMENT CHANGES
TO THE COMPENSATION STRUCTURE
APPLICABLE TO CUSTOMER ON-SITE
GENERATION UNDER SCHEDULES 6, 8,
AND 84 AND TO ESTABLISH AN EXPORT
CREDIT RATE
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CASE NO. IPC-E-23-14

ORDER NO. 36048

On May 1, 2023, Idaho Power Company (“Company”), filed an application
(“Application”) with the Idaho Public Utilities Commission (“Commission”) proposing changes
to the Company’s on-site and self-generation tariffs.
On May 23, 2023, the Commission issued a Notice of Application and Notice of
Intervention Deadline. Order No. 35790. The Commission granted intervention to: Idaho Irrigation
Pumpers Association, Inc. (“IIPA”); Idaho Conservation League (“ICL”); Idaho Hydroelectric
Power Producers Trust, d/b/a IdaHydro (“IdaHydro”); Clean Energy Opportunities for Idaho
(“CEO”); Micron Technology, Inc. (“Micron”); the city of Boise City (“Boise City”); and Vote
Solar. Order Nos. 35781; 35803; 35824. On June 27, 2023, the Commission issued a Notice of
Parties.
On August 10, 2023, the Commission issued a Notice of Modified Procedure and Notice
of Virtual Public Workshops. Order No. 35881. On October 10, 2023, the Commission issued a
Notice of Customer Hearings and Notice of Public Comment Deadline. Order No. 35955. On
October 24, 2023, the Commission held a customer hearing in Boise, and on November 8, 2023,
the Commission held a customer hearing in Twin Falls, Idaho.
THE APPLICATION
The Company requested that the Commission authorize: (1) real-time net billing with an
avoided cost-based financial credit rate for exported energy; (2) a methodology for determining
annual updates to the Export Credit Rate (“ECR”); (3) a modified project eligibility cap for
commercial, industrial, and irrigation (“CI&I”) customers; (4) related changes to the accounting
for and transferability of excess net energy financial credits, and (5) updated tariff schedules
necessary to administer the modified on-site generation offering. The Company requested a
January 1, 2024, effective date.
ORDER NO. 36048 2
The Company represented that its recommendations are guided by the following
objectives: (1) recommend a compensation structure that will accurately measure a customer-
generator’s use of the system – both in recording exported energy and usage; (2) apply methods
that will result in a fair and accurate valuation of customers’ exported energy; (3) implement a
repeatable method for updating the ECR that will ensure timely recognition of changing conditions
on the Company’s system and the broader power markets which may warrant changes to the ECR;
(4) balance accuracy with customer understandability. Application at 15-16.
The Company represented that the proposed changes to the on-site generation service
offerings would only apply to non-legacy1 customers taking service under Schedules 6, 8, and 84.
Customers with legacy systems would continue to take service under the rules of monthly net
energy metering (“NEM”) until legacy status terminates. Id. at 16.
The Company proposed real-time net billing with an avoided cost-based financial credit
rate for exported energy. Id. at 17. The Company stated that the customer-generator would first
consume any of their generation on-site, and any generation they are not consuming would be
metered and exported to the grid at a defined ECR. Id. The Company represented that customers
would generate financial credit, based on the product of measured exported energy and the ECR,
that could be monetized to offset current or future charges associated with utility-provided service.
Id. at 18.
The Company proposed a seasonal and time variant ECR to compensate for energy and
other elements associated with avoided capacity, line losses, and integration costs. Id. at 19-20.
The Company also sought a change in how the project eligibility cap was defined for
Schedule 84 customers. The Company proposed that the Schedule 84 project eligibility cap be set
at the greater of 100 kilowatts (“kW”) or 100% of demand at the service point for CI&I customers.
Id. at 20-21.
The Company represented that for the purpose of administering the cap, the Company
proposed using the maximum billing demand from the last twelve (12) months, measured when
the customer generation application was submitted. Id. at 22. The Company stated that for
irrigation customers without a full in-season billing history, a conversion factor related to the

1 “Legacy” systems for Schedules 6 and 8 are systems that were installed or purchased by December 20, 2019, and
that meet other eligibility requirements. Order Nos. 34509 and 34546. “Legacy” systems for Schedule 84 are systems
that were installed or purchased by December 1, 2020, and that meet other eligibility requirements. Order Nos. 34854
and 34892.
ORDER NO. 36048 3
horsepower of the customers’ pump(s) at the service point would determine the maximum demand.
Id.
The Company represented that for customers with non-legacy systems, the Company
would treat ECR expenditures as a net power supply expense (“NPSE”) subject to 100% recovery
through the Company’s Power Cost Adjustment (“PCA”). Id. at 23-24. The Company proposed
that financial credits may offset all billing components of the bill, not just the energy-related
portion of a customer bill. Id. at 24.
The Company represented that customers with non-legacy systems would be able to
transfer financial credits to another account held in their name for their own usage, which will be
administered similar to the Company’s current NEM service offering for customers transferring
kilowatt hour (“kWh”) credits; however, the Company did not propose to change the transferability
of kWh credits for legacy customers. Id.
The Company proposed that accumulated kWh credits held at service points with non-
legacy systems would be converted to financial credits one year after the effective date of a
Commission-authorized change in compensation structure. Id. at 25.
PUBLIC COMMENTS
A. Comments
As of December 13, 2023, eight hundred and forty-six (846) public comments have been
filed in this case. Of those comments, there were one hundred and twenty-seven (127) customers
who signed a single petition asking the Commission to support solar power; keep the program as
it currently exists, and to grant current customer-generators grandfathering. This petition was
recorded as a single customer comment and is not reflected in the breakdown of customer
comments below.
Aside from that petition, there have been seven hundred and nineteen (719) customer
comments representing individuals and interested parties in Idaho and out of state, including
customers of the Company, other utilities, non-profit organizations, and businesses within the solar
power industry. Of the seven hundred and nineteen (719) individual comments, one hundred and
eighty-three (183) customers (25%) identified themselves as non-legacy customers, while only
forty-nine (49) customers (7%) clearly identified themselves as legacy customers. Another one
hundred and fifty-five (155) customers (22%) indicated they have a net-generation system but did
not identify their status as legacy or non-legacy.
ORDER NO. 36048 4
1. Issues
i. Previous Orders
Customers expressed concerns regarding grandfathering with two hundred and sixty-seven
(267) customers (37%) stating that all current net generation customers should be granted legacy
status. Another seventy-four (74) customers (10%) claimed they were not aware of possible
changes to the program at the time they had their systems installed. Most of these customers stated
they would not have gone forward had they known the rates would change.
There were ninety-eight (98) customers (14%) who disagreed with the outcome of IPC-E-
22-22, including fifty-two (52) customers (7%) who challenged the objectivity of the Company’s
Value of Distributed Energy Resources study, and forty-one (41) customers (6%) who suggested
that the Commission failed to consider third-party studies and the concerns of interested parties.
There were one hundred and fifty-three (153) customers (21%) who urged further consideration
of environmental benefits.
ii. Structure and Compensation
Regarding any change to compensation, three hundred and fifty-three (353) customers
(49%) wanted no change to the structure of the program, and three hundred and twenty-nine (329)
customers (46%) wanted to keep monthly net metering versus real time metering.
Regarding the accrued kWh credits accumulated by both legacy and non-legacy customers,
forty-nine (49) customers (6%) expressed concern about the future value and traceability of
accumulated credits and advocated for customer options for the applicability of those credits.
Regarding financial credits under the proposed changes, forty-one (41) customers (6%) worried
about the accountability of those financial credits and the value of those credits.
Thirty-one (31) customers (4%) offered comments on the ECR, with seventeen (17)
customers (2%) wanting the ECR tied to retail rates, and fourteen (14) customers (2%) expressing
a desire for an unbiased annual review of ECR rates. One hundred and four (104) customers (14%)
offered comments regarding compensation for peak versus non-peak hours, time-of-day versus
peak and non-peak hours, seasonal demand versus customer peak hours, and use of a single rate
versus peak and non-peak hours. Customers expressed that compensation for peak hours extends
into the evening even as generation declines and suggested that compensation for peak hours
should start earlier in the day.

ORDER NO. 36048 5
iii. Incentives
One hundred and four (104) customers (14%) said the Company needs to provide more
incentives to customers to encourage net generation.
PARTY COMMENTS
On October 12, 2023, Staff, CEO, Boise City, ICL, IIPA, and Vote Solar all filed initial
comments on the Application. IdaHydro and Micron did not submit any comments. On November
2, 2023, Staff, CEO, Boise City, ICL, and Vote Solar all filed all-party reply comments. IdaHydro
and Micron did not submit any reply comments. On November 16, 2023, the Company filed final
comments.
INTERVENOR FUNDING
On November 30, 2023, Vote Solar filed a Petition for Intervenor Funding. Vote Solar
requested that the Commission grant Intervenor Funding in the amount of $8,880.00 for attorney
fees for the work of A. Germaine.
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 modify the compensation
structure for on-site generators under Schedules 6, 8, and 84. The Commission has reviewed the
long history of cases dealing with on-site generators, and the Commission recognizes the growing
availability and impact that solar self-generation has on electric customers in Idaho.
In making its decisions in this case, the Commission maintains 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.
The parties have presented differing sets of proposals related to the Company’s
Application, including among other things proposals for the measurement interval applied for
measuring energy, the valuation of the ECR, and various administrative items related to the
ORDER NO. 36048 6
implementation of an avoided cost-based ECR. In this Order, the Commission has striven 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. The Commission does not make these decisions lightly, and
the Commission recognizes that this Order does not put to rest the issues of on-site generation in
Idaho.
A. Summary of Decisions
The Commission approves the Company’s Application to implement a real-time net billing
ECR in accordance with the Application as modified by the Company’s revised proposal and the
provisions of this Order. The ECR shall be seasonal and time variant with avoided cost-based value
considerations. The ECR summer season shall be June 1 through September 30 and align with the
summer season in the Company’s general rate case (“GRC”) Case No. IPC-E-23-11. The ECR
summer On-Peak hours shall be 3 p.m. to 11 p.m., Monday through Saturday, excluding holidays,
during the summer season. Any future updates to the summer season or the hours of highest risk
shall be considered in a separate docket or in a GRC filing as appropriate.
The avoided energy value of the ECR shall be determined using twelve (12) months of
Energy Imbalance Market (“EIM”) Load Aggregation Point (“ELAP”) market prices ending
December 31, weighted for historical customer-generator exports, and the avoided energy value
shall be distributed in alignment with the summer and non-summer seasons.
For avoided generation capacity, the ECR shall use a 5-year rolling average of the Effective
Load Carrying Capability (“ELCC”) to determine the avoided capacity value, and the most current
levelized capacity cost for the least-cost dispatchable resource from the 2023 IRP. The ECR shall
include customer-generator exports for all hours in the calendar year in the calculation of the
rolling average ELCC and shall account for line losses for capacity by applying the line loss gross
up after the ELCC and avoided capacity values are determined.
With respect to avoided transmission and distribution capacity, the Commission approves
the proposed project deferral analysis with a 20-year project specific review. With respect to
avoided line losses, the ECR calculation shall apply the annual energy line losses to the energy
value, apply the peak hour line losses to the On-Peak hours, and apply the annual energy line losses
to all other hours of the capacity value. At this time the ECR shall not include any adjustments for
environmental costs or fuel cost risk.
ORDER NO. 36048 7
The Company is authorized to use the integration rates from the 2020 Variable Energy
Resource (“VER”) study as proposed and shall file an update to Schedule 87 rates and integration
costs from the 2020 VER study for Commission approval. The Company is directed to complete
an updated integration study as soon as possible, and to file the updated study for Commission
approval and inclusion for future ECR updates.
At this time the eligibility caps for Schedule 6 and Schedule 8 shall remain unchanged. The
eligibility cap for Schedule 84 customers shall be the greater of 100 kW or 100% of demand. The
Company is directed to include additional proposed interconnection requirements in Schedule 68
concurrent with the effective date of real-time net billing. The Company shall exclude energy
storage and only include the nameplate capacity of generation for purposes of the eligibility cap,
and the Company shall meet with Staff and interested parties on the feasibility of implementing a
surcharge to recover ongoing costs of system upgrades. The Company shall submit its findings to
the Commission within ninety (90) days of this Order.
The Company shall update all proposed components of the ECR except the season and
hours of highest risk in an annual filing beginning April 1, 2025. ECR expenditures shall be
recovered as a NPSE subject to 100% recovery through the PCA.
With respect to the use and transferability of accumulated financial credits, non-legacy
customers shall be allowed to transfer financial credits to other accounts held in their name for
their own usage, and financial credits may be applied to all billing components. Accumulated
financial credits may be transferred when a customer relocates within the Company’s service area.
At this time no time limit will be set for such a transfer. If a customer completely discontinues
service with the Company, any accumulated unused financial credits shall be paid out to the
customer. On December 31, 2024, all accumulated kilowatt-hour credits for non-legacy systems
shall be converted to financial credits using a blended average retail energy rate.
The Company shall submit a compliance filing with Schedules 6, 8, 68, and 84 conforming
with this Order.
B. Measurement Interval
The Company recommended that the Commission implement a real-time measurement
interval. Company Comments at 12. Boise City noted that an hourly measurement interval should
be considered for consistency with Clean Energy Your Way (“CEYW”)-Construction. Boise City
Comments at 6-7. Staff considered both a real-time, and hourly, netting interval, and based on its
ORDER NO. 36048 8
analysis, Staff believed that a real-time measurement interval was more accurate, more
understandable, and more malleable than a net hourly interval. Staff Comments at 12.
After considering the options presented, the Commission believes that a real-time netting
interval provides the most accurate value for the ECR calculation. While some raised concerns
about how understandable real-time calculation may be for customers, the accuracy provided by a
real-time measurement interval using the Company’s Automated Metering Infrastructure is
reasonable. In addition, the Commission believes that customer-generators will have access
through their My Account information on the Company’s website to data accounting for their
imports and exports for their meter.
C. ECR Rate Design
Staff recommended that the Company align the summer seasons of the ECR to match the
summer season of June l to September 30 presented in the concurrent GRC. Staff Comments at
16. Staff believed that a misalignment of the summer season for all Schedules in the GRC and the
ECR summer season would cause customer confusion. Id. The Company agreed with Staff’s
proposed modifications to the ECR rate design and updated the seasons in the Company’s revised
proposal. Company Comments at 16.
As part of its comments, IIPA suggested that irrigation and non-irrigation net export energy
have substantially different annual shapes and warrant separately calculated export credits. IIPA
Comments at 2. Staff disagreed with the IIPA’s proposal to adopt different ECRs based on export
shape, and Staff noted that the logic of a separate ECR for each unique export shape would lead to
multiple ECRs for each rate class and for each exporting technology type; would reduce
transparency; would increase confusion; and could lead to dissatisfaction among customers. Staff
Reply Comments at 3-4. The Company also disagreed with IIPA’s suggestions reasoning that the
intent of an ECR representative of avoided costs should be applicable to exported energy from
customer-generators irrespective of customer class or generation source. Company Comments at
17.
After considering the options presented, the Commission finds that aligning the summer
season for purpose of the ECR with the summer season presented in the GRC is the most
reasonable option to provide consistency and understandability to customers. With respect to
IIPA’s suggestion, the issue of separately calculated export credits by different usage shapes and
ORDER NO. 36048 9
classes is not the issue before the Commission in this case, and the record in front of the
Commission does not support any determination on that issue.
D. Avoided Energy
Staff agreed with the Company’s proposed method for valuing avoided energy based on
the EIM ELAP pricing. Staff Comments at 17. The value of avoided energy would be determined
by the hourly prices from the EIM using ELAP pricing. Id. The Company would use the twelve
(12) months of market data ending December 31 of each year, and the avoided energy component
of the ECR would be calculated by multiplying the ELAP hourly price of energy by the total MWhs
exported by customer-generators each hour. Id. However, Staff disagreed with the Company’s
proposed method to distribute the value of avoided energy, and Staff recommended that the value
of avoided energy be allocated between the Summer and Non-Summer seasons and the definition
of Summer and Non-Summer for the ECR be aligned with the Summer and Non-Summer seasons
for the corresponding consumptive tariffs proposed in the Company’s GRC. Id. at 18.
IIPA recommended that the Company develop a balancing account to track the difference
between the energy value paid to customers and the value received from customers and amortize
the balance in each ECR update. IIPA Comments at 10. Further, IIPA noted that the Company
expects market prices to decline over time during solar production hours, which means that the
export credit will also decline over time. Id. at 2. IIPA recommended that the Company provide
notice of this by including tariff language that informs customers of the expected decreases in the
net export credit over time. Id.
ICL strongly opposed IIPA’s request for tariff language relying on market predictions
because tariffs should present only verifiable, objective information on service offerings. ICL
Reply Comments at 7.
The Company was not opposed to IIPA’s proposal to create a balancing account to track
the differences in historical and average market prices; however, the Company believed that such
a mechanism would create an additional layer of complexity that the Commission might not wish
to adopt. Company Comments at 22.
After considering the options presented, the Commission finds that the Company’s
proposed method for valuing avoided energy under the revised proposal is reasonable. Currently,
the Commission does not believe that a balancing account is necessary as the trailing twelve (12)
month market data provides self-correction, albeit with some lag. With respect to tariff language,
ORDER NO. 36048 10
the Commission does not believe it is warranted to require language regarding potential effects of
future market prices.
E. Avoided Generation Capacity
Staff believed that the Company’s proposed method for valuing avoided generation
capacity of exports was reasonable. Staff Comments at 19. However, to increase the stability,
accuracy, and transparency of the proposals, Staff recommended that the Company: (1) use a 5-
year rolling window instead of a 3-year rolling window to estimate ELCC values; (2) modify the
method used to incorporate line losses in calculating capacity value by applying the line loss gross
up after the ELCC and avoided capacity values are determined; and (3) use all exports from
customer-generators in its calculation of the ELCC. Id. at 19-21. Staff also believed the Company’s
proposal to distribute all the generation capacity value to the On-Peak hours was reasonable. Id. at
21.
CEO believed that if the Commission were to accept a suggestion to reduce the generation
capacity valuation on the assumption that EIM market prices reflect capacity value, then the
“nonfirm” adjustment should be removed. CEO Comments at 4.
ICL recommended that the Commission: (1) adjust the Company’s ECR methodology to
include marginal line loss calculations and avoided cost figures based on battery storage as the
alternative dispatchable resource. ICL Comments at 2.
Vote Solar recommended that the Company’s methodology for calculating avoided
generation capacity costs be changed to: (1) update the value for avoided generation capacity costs
to more accurately reflect the cost of resources the Company plans to build; (2) use the capacity
factor method for calculating capacity value; and (3) include a line loss gross up. Vote Solar
Comments at 19. Vote Solar noted that the Company’s proposed generation capacity cost was
based on the capital cost of a simple cycle combustion turbine (“SCCT”) from the Company’s
2021 Integrated Resource Plan; however, Vote Solar reasoned that the Company’s 2021 Preferred
Portfolio does not include the addition of new gas resources, and Vote Solar believed it was more
appropriate to base avoided generation capacity costs on the capital costs of battery storage. Id. at
20.
Staff did not agree with the recommendations to change the generation capacity calculation
based on battery storage. Staff Reply Comments at 5. Staff believed there were two factors to
consider when choosing a surrogate dispatchable resource to establish a purely avoided cost of
ORDER NO. 36048 11
capacity: (1) the resource should have the lowest levelized fixed cost including capital cost and
fixed operation and maintenance cost; and (2) the resource should be reliably dispatchable
regardless of the time or duration needed. Id.
The Company generally aligned with Staff’s proposed avoided generation capacity value
modifications to: (1) update the dispatchable resource cost to $145.94 per kW-year as defined in
the 2023 IRP; (2) use a 5-year rolling average to calculate the ELCC value; and (3) exports for all
hours in a calendar year in its rolling average ELCC calculation. Company Comments at 28-29.
The Company indicated that if the Commission directed, the Company would adopt Staff’s
recommendation to apply the line losses after the ELCC calculation by instead modifying the
avoided generation capacity value equation to include the peak line loss factor. Id.
The Company disagreed with Vote Solar’s recommendation to use the capacity factor
method over the ELCC method as the Company reasoned that the capacity factor method is a less
accurate measurement, particularly considering recent widespread adoption of the ELCC as the
preferred method for measuring the resource adequacy contribution of intermittent and energy-
limited resources. Id. at 30-31. Further, the Company did not agree with the recommendation to
utilize battery storage as the alternative dispatchable resource as the Company believed it most
appropriate to utilize the lowest levelized cost of capacity resource, which was identified as an
SCCT in the 2023 IRP, for avoided capacity cost calculations. Id. at 33.
After considering the options presented, the Commission finds that using a trailing 5-year
average ELCC as proposed in the Company’s revised proposal is reasonable. However, the
Company is directed to account for line losses for capacity by applying the line loss gross up after
the ELCC and avoided capacity values are determined.
With respect to changing the Company’s methodology for calculating the ECR avoided
generation capacity costs to reflect the cost of battery storage resources the Company plans to
build; the Commission does not believe that is warranted at this time. The Commission has
expressed “the importance of an avoided generation capacity value that accurately considers
capacity costs actually avoided.” Order No. 35631 at 29. However, there are multiple factors taken
into consideration when the Company selects its IRP Preferred Portfolio, not simply avoided
generation capacity costs, and based on the record before it, the Commission cannot find that a
value based on the avoided capacity costs of battery storage provides the most accurate or
reasonable valuation.
ORDER NO. 36048 12
F. Avoided Transmission and Distribution (“T&D”) Capacity
Staff believed the Company’s proposed method of project-by-project deferral assessments
was reasonable and Staff agreed that assessing every T&D capacity project over a 20-year time
span was sufficiently comprehensive. Staff Comments at 22. Staff believed the Company’s
proposal to distribute all the T&D deferred capacity value to the On-Peak hours was also
reasonable. Id.
CEO requested that because new transmission lines like B2H, SWIP-north, and Gateway
West sections 8 & 9 will be used to access remote generation sources, in future ECR updates the
costs for those marginal transmission lines should be treated in the same fashion as other marginal
generation resources when quantifying the T&D capacity contribution of self-generation. CEO
Comments at 4.
Vote Solar recommended an avoided transmission cost value that is based on the current
FERC-approved transmission rate for the Company. Vote Solar Comments at 24-25. Boise City
also recommended an avoided transmission cost value that is based on the current FERC-approved
transmission rate. Boise City Comments at 3.
Staff did not agree with the recommendation to include a higher transmission and
distribution value because on-site generation export specific data and assumptions used to value
the ECR transmission and distribution deferral would result in a more accurate transmission and
distribution value specific to customer-generators. Staff Reply Comments at 5.
The Company recommended that the Commission approve its proposed project deferral
analysis for valuing the T&D capacity deferral component of the ECR and reasoned that the
proposal to use the FERC transmission rate or other marginal cost rate did not represent capacity
costs actually avoided, or deferred, as directed by the Commission. Company Comments at 38.
After considering the options presented, the Commission finds that the Company’s
proposal to use a project-by-project deferral assessment and that assessing every T&D capacity
project over a 20-year time span is reasonable.
G. Avoided Line Losses
Staff reviewed the Company’s data and report with the underlying calculations for overall
losses compared to the nationwide average. Staff Comments at 23. Staff believed that the
Company’s analysis was reasonably accurate but disagreed with the Company’s proposed
coefficients. Id. Staff recommended that the ECR utilize the industry-typical loss calculations, not
ORDER NO. 36048 13
the Company’s unique extrapolation of those losses, as Staff believed it more accurately aligns the
loss measurements with each of the avoided values and streamlines any future studies by only
using the industry-typical calculations. Id.
Vote Solar represented that line losses increase exponentially as system load increases, so
the line losses associated with marginal additions of load are substantially higher than the average
line losses used in the Company’s calculations. Vote Solar Comments at 16.
CEO requested that the value of the line loss coefficient be no lower than the 5.8% value
proposed by the Company in IPC-E-22-22, and that the Company be directed to hold a technical
workshop to review its methodology for line loss calculations prior to filing its next ECR update
recommendation. CEO Reply Comments at 2.
The Company recommended the Commission approve Staff’s proposal of applying the
annual energy loss coefficient to the avoided energy value. Company Comments at 42. The
Company also recommended the Commission approve the Company’s revised proposal of
applying the standard peak hour loss coefficient to the On-Peak hours and the annual energy loss
coefficient to all other hours for customer-generator exports in the ELCC calculation, which is
utilized to inform the avoided capacity value. Id.
The Company represented that Vote Solar’s claim of the proposed ECR including average
line losses was incorrect, as the Company calculated separate peak and average line losses in its
line loss study, and that if the Commission were to approve the use of marginal losses in the ECR
calculation, it would result in additional costs to account for the increase in line losses. Id. The
Company also stated that CEO’s proposal to utilize line loss coefficients from the Company’s 2012
line loss study does not rely on using the most recent data available to derive an accurate ECR
value. Id. at 43.
After considering the options presented, the Commission finds it reasonable to apply the
annual energy line losses to the energy value, apply the peak hour line losses to the On-Peak hours,
and apply the annual energy line losses to all other hours of the capacity value.
H. Avoided Environmental Costs
Staff considered a national carbon tax, an Idaho Renewable Portfolio Standard (“RPS”)
policy, social health, and Renewable Energy Credits (“RECs”) as options that could be used to
provide a value of an environmental benefit. Staff Comments at 24. Staff explained that there was
no mandated Carbon Tax, Idaho RPS policy, or other environmental costs to the Company on a
ORDER NO. 36048 14
state or federal level. Id. Staff believed that outside of a mandate there was no other identified
environmental benefit that has a direct and quantifiable impact on the Company’s rates. Id.
Regarding RECs, Staff reasoned that ownership remains with the owner of the on-site generation
system absent an RPS or other legislation, and until a state or federal legislation mandates a
quantifiable environmental cost or adder to the Company’s rates, Staff did not believe it was
appropriate to include any associated environmental benefits in the ECR. Id.
CEO recommended that Schedule 6 be modified such that customers transfer ownership of
the renewable energy attributes of their exports to the Company. CEO Comments at 6. CEO would
support that Schedule 6 allow customers to opt-out of this transfer if the interest in an opt-out
outweighs administrative matters associated with offering it. Id. CEO requested that as part of the
annual ECR update the Company report on opportunities to monetize the value of renewable
energy attributes of exports as well as opportunities for aggregation and/or certification of
customer-owned generation. Id. at 7. CEO asked that a placeholder be defined to ensure ongoing
evaluation of opportunities to monetize the value of renewable energy attributes of customer-
owned resources, and that the ECR methodology should retain an annual calculation of
environmental benefits. Id.
Boise City recommended that the Commission direct the Company to work with interested
stakeholders to evaluate the feasibility of implementing a method to compensate customers for
renewable energy attributes of exported energy. Boise City Comments at 9.
Vote Solar represented that although the Company does not have a requirement to comply
with a Renewable Portfolio Standard, the Company does have a goal to provide 100% clean power
to its customers by 2045, and without the clean power provided by on-site generation customers,
the Company would have to build or purchase an equivalent amount of clean power or purchase
an equivalent amount of RECs to meet its goal. Vote Solar Comments at 29. Vote Solar reasoned
that larger customers with on-site generation may be willing to transfer RECs to the Company
given sufficient financial motivation, and in fact some customers already transact in RECs with
the Company through the Green Power Prudency Program. Id. at 29-30. Vote Solar concluded that
the value of RECs purchased to meet customer needs through this program was $7.10 per MWh
in 2022, or 0.07 cents per kilowatt-hour. Id. at 30.
ICL also believed that the parties fully demonstrated that the environmental benefits of
non-carbon emitting resources are non-zero, and if the Commission was not satisfied with the
ORDER NO. 36048 15
analytic methods promoted by parties, ICL recommended any adopted ECR include a placeholder
value to be addressed in future proceedings. ICL Reply Comments at 8-9.
The Company maintained its recommendation that until state or federal legislation
mandates a quantifiable environmental cost or adder to the Company’s rates, it was not appropriate
to include any associated environmental benefits in the ECR. Company Comments at 45.
After considering the options presented, the Commission finds it reasonable not to include
any avoided environmental costs in the ECR calculation at this time. It is undisputed that there are
no state or federal legislative mandates that provide a quantifiable environmental cost or adder to
the Company’s rates, and the Commission is not persuaded by the arguments that groundwork
needs to be set to provide a future system for self-generators to monetize RECs. The Commission
maintains that the purpose of self-generation is to offset a generator’s own usage.
I. Fuel Cost Risk
CEO recommended that the ECR be updated to reflect a fuel price hedge value that was
not zero, and that ECR rates reflect a price risk benefit equal to 5% of avoided energy value
consistent with the E3 recommendation to PacifiCorp. CEO Comments at 3. CEO asked that at
minimum the energy value of customer exports be increased by 3.9% to reflect a fuel price hedge
value consistent with the analysis completed by Rocky Mountain Power for its Idaho on-site
generation customers. Id. at 3-4.
Boise City believed that the Commission should incorporate a value for avoided fuel price
risk and an increased transmission and distribution deferral value if an ECR is approved. Boise
City Comments at 8.
Vote Solar recommended the Commission acknowledge that on-site generation does
provide a hedge benefit and approve an avoided fuel cost risk value of 0.462 cents per kWh during
on-peak periods, 0.268 cents per kWh during off-peak periods, and 0.281 cents per kWh averaged
annually. Vote Solar Comments at 26-27.
ICL supported Vote Solar, Boise City, and CEO’s positions of a non-zero fuel hedge and
environmental value ECR components. ICL Reply Comments at 8-9. ICL reasoned that an adopted
ECR must fully and comprehensively compensate customers, and in lieu of an exact fuel hedge
value, a value equal to 5% of avoided energy costs was both reasonable and consistent with values
assigned in other jurisdictions. Id.
ORDER NO. 36048 16
The Company recommended the Commission not include a value for fuel cost risk in the
ECR as the ELAP price is directly impacted by natural gas market prices and to add a 5% premium
would result in double counting and over-inflate the value paid to customer-generators and
collected from all other customers. Company Comments at 48.
After considering the options presented, the Commission finds it reasonable not to include
any value for fuel cost risk based on the application of the ELAP price in valuing the ECR.
J. Integration Costs
Staff agreed with the Company’s 2020 VER basis for and inclusion of the $0.00293/kWh
integration cost in the ECR; however, Staff recommended that the Commission: (1) authorize the
integration rates for purposes of the ECR rates in this filing; (2) direct the Company to file the
2020 VER study for Commission authorization to update Schedule 87 and to be used in future
ratemaking that requires it, including future updates to CEYW and ECR-related rates; and (3)
direct the Company to file all future VER studies and integration costs for Commission
authorization, if integration cost have materially changed from those authorized. Staff Comments
at 25. Staff also recommended the Company conduct a new integration study as soon as possible,
file the study for Commission approval, and incorporate the results of the new integration study
into the next possible ECR adjustment filing. Staff Reply Comments at 6.
Both CEO and Vote Solar requested that the proposed ECR be updated to reflect the
integration costs of $.64/MWh associated with Case 9 in the 2020 VER Integration Study rather
than the $2.93/MWh the Company proposed. CEO Comments at 2; Vote Solar Comments at 18.
The Company maintained that Case 1 was the appropriate integration cost scenario because
it was most reflective of integration costs from distributed energy resource exports on the
Company’s system. Company Comments at 53. However, the Company was not opposed to Staff’s
proposal for the Commission to direct the Company to complete an updated integration study as
soon as possible and file for Commission approval and inclusion for future ECR updates. Id.
After considering the options presented, the Commission finds it reasonable to authorize
the Company to use the integration rates from the 2020 VER study as proposed; however, the
Company shall file an update to Schedule 87 rates and integration costs from the 2020 VER study
for Commission approval and the Company is directed to complete an updated integration study
as soon as possible, and to file the updated study for Commission approval and inclusion for future
ECR updates.
ORDER NO. 36048 17
K. Transition/Gradualism Considerations
Boise City recommended that the Commission ensure compensation changes were gradual,
easily understandable to all customers, promoted rate stability, and sent appropriate price signals
in this dynamic energy landscape. Boise City Comments at 6. Boise City believed that an ECR
should not be implemented for five months and then updated again on June 1, 2024, and that the
Commission should consider changes to the measurement interval and an ECR separately. Id.
Boise City also believed that the Commission should consider a transition period similar to what
was discussed in the Settlement Agreement in IPC-E-18-15. Id. at 7.
CEO believed that gradualism was a merited concern for Residential and Small General
Service Customers. CEO Comments at 2. CEO suggested that the Commission set the effective
date for the ECR of January 1, 2024, but set the next update of the ECR to occur in June 2025
rather than June 2024; however, if the Commission considered delaying implementation of the
ECR, CEO requested that non-ECR related changes to Schedule 84 be effective January 1, 2024,
in order not to impede the design, evaluation, application process, and installation of projects for
the irrigation season. Id.
Vote Solar represented that should the Commission implement the Company’s proposed
ECR, some non-legacy customers would be substantially worse off, especially when accounting
for changes to rates that have been proposed in the Company’s GRC. Vote Solar Comments at 45.
Vote Solar reasoned that the total impact of granting those customers legacy status was immaterial,
and given the substantial hardship experienced by nonlegacy customers if they were immediately
transitioned to an ECR, Vote Solar recommended that customers who had already applied to
interconnect solar or made a financial commitment to install solar before the date of the
Commission’s final order in this docket should be permitted to remain on the legacy rate for twenty
(20) years. Id.
Further, Vote Solar recommended that the Commission implement a measured transition,
or glide path, to the lower export rate by setting the initial export rate equal to the value of the
average volumetric retail rate for each customer class, to mitigate negative impacts on the market
for rooftop solar and provide a measure of parity for prospective solar customers. Id. at 48. Vote
Solar also recommended the rate decline by a maximum amount as the total capacity of on-site
generation installed in the Company’s service territory reached defined thresholds. Id.
ORDER NO. 36048 18
Staff did not recommend any transition period. Staff Comments at 40. Staff believed that
allowing current non-legacy customers to use accumulated kWh credits over the 2024 calendar
year would provide enough transition and opportunity for current NEM customers to learn the new
program. Id. However, Staff proposed that the first update to the ECR begin in 2025 rather than
2024. Id. Staff believed an acclimation period was necessary for customers to adjust to the ECR
billing structure without having the ECR billing rate change in the first six months of a new
program. Id. With respect to Grandfathering, Staff noted that the Commission has been clear
through Order Nos. 34509, 34546, and 34854, that established legacy status for Schedule 6, 8, and
84 customers would not be expanded. Staff Reply Comments at 7. Staff did not recommend
expanding grandfathering, or legacy status, and Staff believed that Commission Orders regarding
grandfathering were clear on that matter. Id.
The Company was not opposed to Staff’s recommendation to delay the first annual update
to be filed April 1, 2025, with an effective date of June 1, 2025; however, the Company opposed
all other recommended changes or proposed transition periods. Company Comments at 60-61.
After considering the options presented, the Commission does not believe that a transition
period is necessary; however, after the initial implementation of new ECR schedules consistent
with this Order on January 1, 2024, the Commission does find that a delay of the first annual update
to April 1, 2025, with an effective date of June 1, 2025, is reasonable. On the issue of
grandfathering, the Commission’s stance has clearly been stated in its prior orders.
L. Financial Credit Expiration
Staff disagreed with the Company’s proposal regarding the expiration of financial credits,
and Staff recommended that the Commission order the Company to transfer financial credits to a
customer’s new meter when a customer relocates within the Company’s system and refund the
amount of accumulated financial credits to the customer in the event the customer relocated outside
the Company’s system. Staff Comments at 39.
The Company recommended that the Commission reject the proposal to provide a financial
payment to a customer in any event. Company Comments at 69. The Company was not opposed
to Staff’s recommendation to transfer a financial credit to other service points or meters on the
customer’s account when they relocate within the Company’s service area; however, the Company
requested that the Commission limit the time period the Company must track the financial credit
ORDER NO. 36048 19
and find that the transfer of financial credits must occur within six months of the account being
closed or be forfeited if not transferred. Id. at 70.
After considering the options presented, the Commission finds it reasonable that
accumulated financial credits be transferrable when a customer relocates within the Company’s
service area. At this time no time limit will be set for such a transfer. Additionally, if a customer
completely discontinues service with the Company, any accumulated unused financial credits shall
be paid out to the customer. The Commission is cognizant of the potential behavior impacts
inherent in a system that pays out financial credits; however, the Commission believes that the
limited conditions under which a customer may receive a payout mitigates those impacts.
M. Intervenor Funding
Intervenor funding is available pursuant to Idaho Code § 61-617A and the Idaho Public
Utilities Commission Rules of Procedure 161-165. Idaho Code § 61-617A(1) provides that it is
the “policy of this state to encourage participation at all stages of all proceedings before the
commission so that all affected customers receive full and fair representation in those
proceedings.” The Commission may award a cumulative amount of intervenor funding not to
exceed $40,000 for all intervening parties in a single case. Idaho Code § 61-617A(2).
Commission Rule 162 provides the form and content of petitions for intervenor funding.
Each petition must contain: (1) an itemized list of expenses broken down into categories; (2) a
statement of the intervenor’s proposed findings or recommendation; (3) a statement showing that
the costs the intervenor wishes to recover are reasonable; (4) a statement explaining why the costs
constitute a significant financial hardship for the intervenor; (5) a statement showing how the
intervenor’s proposed recommendations differed materially from the testimony and exhibits of the
Staff; (6) a statement showing how the intervenor’s recommendation or position addressed issues
of concern to the general body of the utility users or consumers; and (7) a statement showing the
class of customer on whose behalf the intervenor appeared. IDAPA 31.01.01.162.
Vote Solar is a nonprofit organization. Based upon the Commission’s review of Vote
Solar’s petition, the Commission finds that the funding request complies with the procedural and
substantive requirements of the statute and the rules. The Commission finds that Vote Solar has
materially contributed to the Commission’s decision-making; Vote Solar’s participation added a
unique and well-informed perspective to the record; and it is fair, just, and reasonable to award
intervenor funding. The Commission finds it appropriate to award Vote Solar intervenor funding
ORDER NO. 36048 20
in the amount of $8,880.00. The award shall be chargeable to residential and small commercial
customer classes. Idaho Code § 61-617A(3).
ORDER
IT IS HEREBY ORDERED that the Company’s Application as modified by the
Company’s revised proposal and the provisions of this Order is approved.
IT IS FURTHER ORDERED that the Company shall submit a compliance filing with
Schedules 6, 8, 68, and 84 conforming with this Order.
IT IS FURTHER ORDERED that Vote Solar’s petition for intervenor funding is granted
in the amount of $8,880.00.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date upon 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 29th day of
December 2023.

__________________________________________
ERIC ANDERSON, PRESIDENT

__________________________________________
JOHN R. HAMMOND JR., COMMISSIONER

__________________________________________
EDWARD LODGE, COMMISSIONER

ATTEST:

_________________________________
Monica Barrios-Sanchez
Interim Commission Secretary
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