20250903Staff Comments.pdf

JEFFREY R. LOLL
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 11675
Street Address for Express Mail:
11331 W CHINDEN BLVD, BLDG 8, SUITE 201-A
BOISE, ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF ROCKY MOUNTAIN )
POWER'S APPLICATION TO IMPLEMENT ) CASE NO. PAC-E-25-02
CHANGES TO NON-LEGACY CUSTOMER )
GENERATORS )
COMMENTS OF THE
COMMISSION STAFF
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission
("Commission"), by and through its attorney of record, Jeffrey R. Loll, Deputy Attorney
General, submits the following comments.
BACKGROUND
On June 14, 2019, Rocky Mountain Power, a division of PacifiCorp, ("Company") filed
an application with the Commission for authority to close electric service schedule 135-Net
Metering Service. In response to Commission Order Nos. 34509 & 34546 regarding similar net
metering issues for Idaho Power Company, the Company filed a supplemental application to
align the existing docket with the criteria set by the Commission in its Orders. On August 26,
2020, the Commission ordered the Company to conduct a study of on-site generation according
to the scope developed during the PAC-E-19-08 filing. Order No. 34753 at 9.
STAFF COMMENTS 1 SEPTEMBER 3, 2025

On June 29, 2023, in compliance with Commission Order No. 34753, the Company
requested that Commission approve the study review phase of the costs and benefits for on-site
customer generation. PAC-E-23-17. In Order No. 36286, the Commission acknowledged that the
Company's study and appendices complied with Order No. 34753 and directed the company to
file a new case requesting changes to the structure and design of its proposed Export Credit Rate
("ECR").
On February 7, 2025, the Company filed an application ("Application")with the
Commission requesting an order approving the Company's proposed changes to its on-site self-
generation Electric Service Schedule 136 ("Schedule 136")tariff beginning October 1, 2025, and
approving the Company's proposed export credit rate methodology. Application at 1.
On June 17, 2025, the Commission issued a Notice of Modified Procedure setting an
August 14, 2025, deadline for initial comments and a September 3, 2025, deadline for the
Company's reply comments. Order No. 36482 at 1-2. The Commission also issued a Notice of
Virtual Customer Hearing setting a customer hearing date of August 19, 2025. Id. at 4.
On July 30, 2025, the Company filed an amended application with the Commission
("Amended Application"). Within the Amended Application, the Company made changes to
inputs used to calculate the proposed ECR of the Company's Schedule 136 customers. Amended
Application at 2-3.
At the Commission's August 5, 2025, decision meeting, Staff recommended vacating and
resetting the comment deadlines to provide adequate time for public comments on the Amended
Application. Additionally, Staff recommended the Commission issue an Amended Notice of
Virtual Customer Hearing vacating the hearing previously scheduled for August 19, 2025, and
scheduling a new customer hearing at a date that would allow the hearing to be more practical
under the new comment deadlines.
Subsequently, at the Commission's August 12, 2025, decision meeting, Staff
recommended the Commission issue a Notice of Suspension suspending the Company's
proposed effective date for 30 days plus five months pursuant to the Commission's authority
under Idaho Code § 61-622(4).
On August 5, 2025, The Commission found it reasonable to grant additional time to file
comments and reply comments and to reset the previously scheduled customer hearing. On
STAFF COMMENTS 2 SEPTEMBER 3, 2025

August 12, 2025, the Commission found it reasonable to suspend the Company's proposed
effective date.
STAFF ANALYSIS
Staff reviewed the Company's Application, Amended Application, supporting
workpapers, and discovery responses. Based on its review, Staff believes that the Company's
amended ECR proposal is generally reasonable. However, Staff believes there is room for
incremental improvements. Based on its review, Staff recommends the Commission issue an
order that:
1. Approves the Company's Amended Application with the addition of a rate
stabilization mechanism;
2. Requires the Company to file annual updates by July each year;
3. Requires the Company to file update workpapers as publicly available exhibits;
4. Denies the Company's proposal to increase non-residential project cap;
5. Requires the Company to adjust its tariffs to explicitly state that the customer
requesting on-site generation service is responsible for all costs related to studies and
upgrades;
6. Approves Staff's recommendation to set the non-residential project cap at 100 kW or
maximum demand, whichever is greater; and
7. Directs the Company to submit a compliance filing containing updated tariffs that
reflect the Commission's Order.
The sections below describe Staff's analysis on each element of the proposed ECR as
well as the Company's other proposals.
Value of Avoided Energy
Staff agrees with each aspect of the Company's proposal for calculating the avoided
energy value.
The Company proposes determining the avoided energy value by using a weighted
average of the most recent year's energy prices. It proposes that the energy prices be determined
by averaging the locational marginal prices ("LMPs") of two generation nodes in the Idaho
STAFF COMMENTS 3 SEPTEMBER 3, 2025

service area. The proposed LMP nodes are "Meadow Creek Wind" and"Oneida Hydro."
Macneil Direct at 9-10.
Staff agrees that averaging the prices of these two nodes is a reasonable proxy for the
value of energy in the Idaho service area. Both locations reflect the price effects of supply and
demand, transmission congestion, and non-firm power. Averaging the two LMPs will account
for any differences between them, is a better approximation of the true energy value to the
service area and helps to smooth the result.
After determining the historic hourly energy values, the Company proposes to weight
each hourly price by the quantity of kilowatt-hours the on-site generators cumulatively exported
in that hour. MacNiel Direct at 27. This represents the cumulative avoided energy value for that
hour. The Company further proposes that the avoided energy value for each hour be assigned to
the season/peak group in which it occurred(i.e., Summer On-Peak or Winter Off-peak).Id. The
cumulative energy value in each season/peak group would then be averaged within that group,
ultimately yielding four different avoided energy values.Id.
Staff agrees with the Company that this weighted hourly value is an accurate method of
assigning a cumulative value to all the exports. Staff also agrees with the Company's proposal to
assign the energy value by the four season/peak groups and then average within each group.
This approach should typically assign more value to the season/peak groups when energy is more
expensive, which should send an aligned price signal to on-site generators.
Integration Costs
Staff agrees with each aspect of the Company's proposal for calculating the integration
costs for distributed solar exports.
The Company proposes using the solar integration values it officially calculates for small
Qualifying Facility ("QF") generators via a method approved in a separate case. MacNeil 12-14.
The Company argues that the aggregate export profile of on-site generators is analogous to the
typical profile of QF solar generators, so it is appropriate to assume that the integration costs are
approximately the same.Id.
Staff agrees with the Company's reasoning and concurs that the QF integration cost is a
reasonable proxy for the integration costs of exports from on-site generators.
STAFF COMMENTS 4 SEPTEMBER 3, 2025

Value of Avoided Line Losses
Staff agrees with the Company's proposals for determining line losses. The Company
proposes using line loss rates from its most current published study for Idaho. MacNiel Direct
14-16. This study measures line losses for transformers, the transmission system, and the
distribution system.Id. It further distinguishes between losses under peak load conditions
(demand losses), and losses under steady state load conditions (energy losses).Id. The Company
proposes to apply specific losses to each component of the ECR, depending on whether the ECR
component is energy-related or capacity-related.Id.
Staff agrees with this approach, finding the Company's application of energy losses to
energy components and capacity losses to capacity components to be reasonable.
Value of Avoided Generation Capacity
Staff agrees with the Company's proposed method to determine avoided generation
capacity value, with one important clarification. The Company proposes using the annualized
fixed costs for a simple-cycle combustion turbine ("SCCT") as a proxy cost of an avoided
capacity resource. MacNeil Direct at 16. The Company does not explicitly state why this type of
resource was chosen. Id. Staff believes the SCCT was the least-cost dispatchable capacity
resource in the 2023 Integrated Resource Plan("IRP"). For clarification purposes, Staff
recommends that the proxy cost be tied to the least-cost dispatchable capacity resource as
opposed to being permanently tied to the SCCT. This least-cost proxy should be determined in
each IRP.
The Company proposes three additional adjustments to the SCCT proxy cost: 1) an
adjustment for annual inflation; 2) an upward adjustment to account for the annual payment
factor; and 3) an upward adjustment to account for the less-than-perfect availability of the SCCT.
MacNiel Direct 16-20. Staff believes that these adjustments are appropriate to ensure an accurate
avoided cost leaving non-participating ratepayers indifferent as to whether they get their
electricity from a customer generator or from the Company's resources.
To assess the collective capacity contribution of onsite generators, the Company proposes
to use "the capacity factor methodology based on loss of load probability("LOLP") data for
calendar year 2024 derived from the 2021 IRP preferred portfolio." MacNeil Direct at 17.
STAFF COMMENTS 5 SEPTEMBER 3, 2025

Staff agrees with the Company's choice of using 2024 LOLP tables because that data
most closely aligns with historical data and the proposed rate-effective period. However, Staff
has concern that the Company selected the LOLP table from the 2021 IRP instead of the more
current 2023 IRP. Staff recommends that future updates draw from the most current IRP.
Value of Deferred Transmission Capacity
Staff agrees with the Company's proposed method of valuing the deferral of transmission
capacity. In each IRP, the Company calculates the average cost per kilowatt-year("kW-yr") for
capacity growth of transmission lines ("transmission capacity cost"). The Company assumes
that the capacity provided by on-site generators enables the Company to defer constructing an
equivalent amount of upgraded/new transmission infrastructure. Therefore, the Company
proposes to multiply the transmission capacity cost by the effective capacity contribution of on-
site generators to determine the deferred transmission capacity value. MacNiel Direct 20-22. The
Company proposes using the same capacity contribution value that it used for generation
capacity(12 percent). Id. This final value is then allocated to the four season/peak groups in
proportion to their capacity contributions. Id.
Staff agrees that the Company's proposal is reasonable. The method is reasonably
accurate, the various inputs are reviewable by the public, and the value is appropriately assigned
to the four season/peak groups.
Value of Avoided Transmission Capacity Costs
Staff agrees with the Company's proposed method of valuing avoided transmission costs.
The Company allocates the cost of its transmission system to its native load retail customers,
network customers (e.g.,: municipals and co-ops located within the Company's balancing area),
and to 3rd party transmission customers who wheel power through its transmission system based
on an Open Access Transmission Tariff("OATT") that is updated annually. The effective
capacity provided by on-site generators enables the Company to avoid some of the transmission
capacity cost allocated to its retail customers, which is then re-allocated to its network customers
and to 3rd party transmission customers through the OATT rate. Because OATT costs are
allocated by monthly coincident peaks, a proxy must be used for on-site generators. The
Company proposes to use the retail customer class as the proxy. MacNiel Direct at 22-23. The
STAFF COMMENTS 6 SEPTEMBER 3, 2025

end result is an annual avoided transmission value that the Company then allocates to the four
season/peak groups in proportion to their capacity contributions. Id.
Staff believes each aspect of the Company's value determination is logical and
reasonable. Furthermore, the value is appropriately assigned to the four season/peak groups.
Value of Deferred Distribution Capacity
Staff agrees with the Company's proposed method of valuing the deferral of distribution
capacity. In each IRP, the Company calculates the average cost per kW-yr for capacity growth of
distribution lines by state ("distribution capacity cost"). The Company assumes that the capacity
provided by on-site generators enables the Company to defer constructing an equivalent amount
of upgraded/new distribution infrastructure. Therefore, the Company proposes to multiply the
Idaho distribution capacity cost by the effective capacity contribution of on-site generators to
determine the deferred distribution capacity value. MacNiel Direct at 23-25. The Company
proposes using the same capacity contribution value that it used for generation capacity (12
percent).Id. This final value is then allocated to the four season/peak groups in proportion to
their capacity contributions.Id.
Staff agrees that the Company's proposal is reasonable. The method is reasonably
accurate, the various inputs are reviewable by the public, and the value is appropriately assigned
to the four season/peak groups.
Value of Avoided Environmental Costs
Staff agrees with the Company's determination of no avoided environmental costs. The
Company explains that Idaho does not have a renewable portfolio standard, which is a typical
source of avoided environmental cost. MacNiel Direct at 25-27. The Company also explains
why it is not practical to aggregate and sell renewable energy credits ("RECs")produced by on-
site generation.Id.
Staff notes that the Commission has previously restricted the avoidance of environmental
costs to actual costs avoided by ratepayers. Order No. 36048 at 15. Staff agrees with the
Company's determination that onsite generation will not avoid any environmentally related
ratepayer costs.
STAFF COMMENTS 7 SEPTEMBER 3, 2025

Furthermore, Staff agrees that the administration required to register, aggregate and sell
RECs from on-site generators would be prohibitively expensive.
Recommendation to Stabilize the ECR
Staff recommends an additional mechanism to smooth any changes to the ECR from year
to year. Idaho Power Company ("IPC") established an ECR for its on-site generators in 2024
and recently filed for its first annual ECR update. See Case Nos. IPC-E-23-14 and IPC-E-25-15.
The newly calculated value dropped dramatically, precipitating a strong reaction from customers.
The Non-Summer value dropped by 80 percent, from 4.84 cents per kWh to 0.95 cents per kWh
IPC-E-25-15, Staff Comments at 4. Because of the amount of ECR volatility and the impact to
customers, Staff recommended a smoothing mechanism to mitigate the change from year to year
in an effort to provide rate stability.
Accordingly, Staff recommends that a similar mechanism be applied to this case. Staff
recommends that a three-year rolling average be established for each of the four approved
Season/Peak rates. Table No.I provides a hypothetical example,using the Company's proposed
rates for year one, and hypothetical single-year results for years two and three. Because
Advanced Metering Infrastructure ("AMI") is a recent addition to the Company's service
territory, only one year of Idaho data is available. As more data comes available, the resulting
ECR values should be included in the averaging calculation until three years are available. At
that point, updates should begin a rolling average of the most recent 3 years of ECR values.
Table No.1 —Three-Year Rolling Average (cents/kWh)
Summer On-Peak Summer Off-Peak Winter On-Peak Winter Off-Peak
Year 1 14.67 3.66 5.60 1.23
Year 2 15.00 4.00 7.00 2.00
Year 3 12.00 2.00 3.00 1.00
Year 2 roll avg* 14.83 3.83 6.30 1.61
Year 3 roll avg 13.89 3.22 5.20 1.41
*This is an average of only years 1 and 2, because that is all that would be available.
To clarify the calculation sequence, Staff proposes that the four rates always be
calculated per the Commission-approved method for the most recent year. These Commission-
STAFF COMMENTS 8 SEPTEMBER 3, 2025

approved single-year results would then be averaged with the Commission-approved single-year
results from the preceding two filings to set the official three-year rolling average ECRs that
would be applied to customers.
Netting Period
The Company's proposed ECR does not have a netting period. Meredith Direct at 12.
The Company explains that exported and delivered energy would be tracked in real time,
sometimes referred to as real-time netting.Id. The Company explains that not netting exports
with delivered energy sends a price signal to encourage customer behavior, is simpler for
customers to understand, and is less burden on the Company.Id. at 12-14.
Staff agrees with this proposal. Consistent with the on-site generation study,real-time
netting provides increased accuracy and transparency when compared to a netting calculation.
Additionally, netting on any timescale would require reporting of base consumption and export
values in addition to the results of the netting calculation. This additional data and calculation
may complicate the information a customer would receive. Staff agrees with the Study's
observation that the increased accuracy of instantaneous netting may encourage participating
customers to align their consumption with their system's generation or with times that are more
valuable to the Company.
Export Credit Season and Time of Day
In its analysis, Staff reviewed the Company's proposal to vary export credit rates across
the year and its selected seasons and hours for differentiating rates. The Company asserts that
differentiating export credit values across different times "better reflects the costs and benefits of
distributed energy resources and encourages customers to build and operate their systems in
ways that are the most beneficial to the power grid."Meredith Direct at 8-12. Staff agrees that
differentiating credit rates provides customers with more accurate price signals regarding the
value of their exports to the grid, compared to a single year-round credit rate. A higher rate
during summer evening hours informs customers that their energy generation provides more
value to the grid than during low-value mid-day hours. This price signal may incentivize
customer generators to shift their consumption from high-value hours to lower value hours,
resulting in more customer generation exported to the grid during the higher value hours.
STAFF COMMENTS 9 SEPTEMBER 3, 2025

In its Application, the Company proposed to vary credit rates along identical seasons and
hours as those found in its Schedule 36 Optional Time of Day—Residential Service, citing
reduced customer confusion and administrative burden. MacNiel Direct at 12-19. This would
create four distinct rates during four distinct time periods. The Company's proposed time
periods are shown below in Table No. 2.
Table No. 2: Seasons and Hours of Export Credit Rates
Time Period Name Company Application
Summer On-Peak 3:00 pm— 11:00 pm
(June—October)
Summer Off-Peak 11:00 pm—3:00 pm
(June—October)
Winter On-Peak 6:00 am—9:00 am, and
(November—May) 6:00 pm— 11:00 pm
Winter Off-Peak 9:00 am—6:00 pm, and
(November—May) 11:00 pm—6:00 am
Staff agrees with the seasons and On-Peak and Off-Peak hours in the Company's
Application. In reviewing the Company's proposed definitions of seasons and hours, Staff
considered the Company's emphasis on simplicity and its report of LOLP distribution throughout
the year.1 Staff agrees that simplicity and understandability of rates is a valid principle to
consider in the ratemaking process. The Company's proposal to match Schedule No. 136 times
with those of its existing Schedule No. 36 supports this principle, especially for customer
generators currently taking service on Schedule No. 36.
Staff is concerned with the proposed Summer On-Peak hours based on aligning price
signals with hours of highest risk. Including an additional hour from 2:00pm-3:00pm would
capture additional LOLP and send a price signal to customer generators that exports during this
hour benefit the system more than the majority of Off-Peak hours.
' See Company Response to Staff Production Request No. 11,Attachment IPUC 11,tab"Capacity Contribution"for
LOLP distribution.
STAFF COMMENTS 10 SEPTEMBER 3, 2025

Despite its concerns regarding the alignment of Summer On-Peak hours with high LOLP
hours, Staff recommends that the Commission approve the time periods in the Company's
Application. Staff believes that in this instance, the benefits of simplicity are greater than the
benefits provided by modifying the Company's proposed seasons or peak hours. As shown in
further detail in the Billing Impacts section, including 2:00pm-3:00pm as a Summer On-Peak
hour changes bill amounts for the average customer generator by less than one dollar compared
to the Company's proposal.
Staff continues to emphasize the importance of aligning price signals with system critical
hours. These hours may change as the Company's generation portfolio and customer load
profile evolve in the future. Staff believes that changes to any defined seasons and peak hours
should be considered in a dedicated filing.
Export Credit Rate Impacts
The Company provided proposed rates in its Amended Application and are shown below
in Table No. 3. Amended Application at 4. Staff recommends that the Commission authorize the
rates presented in the Amended Application. Staff s recommendation represents a decrease in
value compared to the current Schedule No. 136 rates. Staff believes the recommended rates
represent an accurate value of energy exported to the system and reduce cost shifting between
customer generators and non-generators.
Table No. 3: Schedule No. 136 Export Credit Rates
Customer Summer Summer Winter Winter Annual
On-Peak Off-Peak On-Peak Off-Peak Average
Sch.l Standard Retail Rate
Sch.36 Standard Retail Rate
Present All other 85% of monthly weighted average of Mid-C ICE
Schedules Index.
Proposed All Schedules 14.6660 3.6640 5.597 ¢ 1.2280 4.2300
Bill Impacts
Table No.4 displays average monthly bill impacts for all residential customers using
Staff s recommended rates. Staff analyzed bill impacts under different On-Peak and Off-Peak
STAFF COMMENTS 11 SEPTEMBER 3, 2025

scenarios, such as shifting On-Peak hours and changing months from Summer to Winter. For
comparison, Table No. 4 includes bill impacts when adding 2pm-3pm to the Summer On-Peak
hours. The lack of any meaningful difference in bill impacts under different scenarios factored
heavily into Staff s recommendation to approve the Company's proposed seasons and hours for
ECR rates.
Table No. 4: Average Monthly Bill Impact for Residential Customers
Company Application Using Alternate: Add 2pm-3pm to
Net Monthly Current Corrected Rates Summer On-Peak hours
kWh Delivery Monthly Proposed Change Change Proposed Change Change
Range Bill Monthly $ % Monthly $ %
A: 0-500 $21.16 $56.86 $35.70 168.7% $56.90 $35.74 168.9%
B: 501-1,000 $71.03 $107.47 $36.44 51.3% $107.68 $36.65 51.6%
C: 1,001-1,500 $131.72 $164.58 $32.86 24.9% $164.98 $33.26 25.3%
D: 1,501-2,000 $184.41 $216.41 $31.99 17.4% $216.90 $32.48 17.6%
E: 2,001+ $297.08 $324.25 $27.17 9.1% $324.91 $27.83 9.4%
Grand Total $51.05 $86.39 $35.35 69.2% $86.52 $35.47 69.5%
Updates to ECR
Consistent with Staff comments in PAC-E-23-17, the Company proposes to update the
ECR annually. Application at 1. The Company proposes filing its updates on or around July Vt
each year. Id. at 7. These updates will incorporate the most recent historical results and approved
values from other rate schedules, with more comprehensive updates in the annual update
following the filing of the Company' s Integrated Resource Plan. Id. at 9. Table No. 5 below
summarizes the data source for each element of the ECR that will be updated. Staff agrees with
the Company's proposal to file annual updates to the ECR.
STAFF COMMENTS 12 SEPTEMBER 3, 2025

Table No. 5 - Summary of Company's Proposal for Updates to the ECR Components
Element Inputs
Avoided Energy Cost Historical energy price data, historical export data
Integration Cost Most recent integration study
Avoided Line Losses Most recent line loss study
Avoided Generation Capacity Most recent IRP, line loss study, and historical export
profile
Avoided Transmission Capacity Most recent IRP, line loss study, and historical export
Deferral profile
Avoided Transmission System Cost Most recent OATT tariff and historical export data
Avoided Distribution Capacity Most recent IRP, line loss study, and historical export
Deferral profile
Staff believes that annual updates can provide the opportunity for increased transparency
to customers. However, to do so, the information must be available to customers. In its response
to Production Request No. 11, the Company provides workpapers that detailed calculations of
the ECR values. These workpapers include hourly export data, market price data, and inputs
from relevant sources. These workpapers were made available to the public in this filing as part
of the Company's Amended Application as non-confidential workpapers. Staff recommends that
the Commission require the Company to file workpapers such as those filed with its Amended
Application as publicly available exhibits in future update filings.
Staff believes that annual updates are necessary to accurately reflect shifts in market
conditions and will contribute to the balance between the accuracy of the ECR and rate stability
within a year. Because the proposed updates are based primarily on historical data, there will be
a lag between actual market conditions and when those conditions are reflected in the ECR.
Through year-over-year updates, the export credit rate will follow actual market conditions;
which will true-up for ECR customers over time. However, export profiles and market prices
remain susceptible to yearly shifts that can cause rate swings. As described in more detail in the
section above, Staff believes that there is need for additional rate stability.
Staff s review of the Company's proposed method for filing updates suggests that the
method is similar to the Company's Energy Cost Adjustment Mechanism(`SCAM"). Because
STAFF COMMENTS 13 SEPTEMBER 3, 2025

those filings are generally limited to verifying the updates to data inputs and not due to
fundamental changes to the methodology, it is possible for these cases to operate on the
accelerated timeline. Similarly, because the proposed updates are limited to updating the
calculated ECR from relevant input data, Staff is comfortable with this timeline. Staff
recommends that any changes to the structure of the ECR(i.e., season length, hours, how credits
are applied, etc.) should trigger a new case with ample time for all parties to review and provide
input.
In its Application, the Company requests to file its annual update "on or around"July 1
each year. Application at 7. Staff believes that this time frame is ambiguous and could lead to
inconsistent filing dates. Staff recommends that the Commission require the Company to file by
July 1"each year. Should July fall on a weekend or holiday, the filing should fall on the first day
following that is not a weekend or holiday consistent with General Provisions Rule 17
(Computation of Time).
Modifications to Project Eligibility Cap
The Company proposed an eligibility cap increase for non-residential customers from
100 kW to 2,000 kW and to leave the residential customers' cap at the current 25 W.
Application at 9. Staff investigated the Company's proposal using the following criteria: (1)
whether the proposed cap compromises the safety and reliability of the Company's system; (2)
whether other customers are financially harmed by the increase in the cap; and(3)whether the
proposed cap is at odds with the intent of the program, which is to allow customers to offset their
energy usage behind the meter. Through its analysis, Staff has developed the following
recommendations summarized below.
1. The residential eligibility cap of 25 kW remain the same.
2. The Commission approve an eligibility cap for non-residential customers to be 100
kW or each customer's maximum demand, whichever is greater.
3. The Company explicitly state in its tariffs that the cost of any reliability study and
upgrades to its system as a result of a customer's on-site generation be recovered
from the customer causing the cost.
STAFF COMMENTS 14 SEPTEMBER 3, 2025

Reliability Studies
Regardless of the size of the eligibility cap, Staff believes that the safety and reliability of
the Company's system will be maintained as long as the Company performs an interconnection
study for each non-residential customer who generates and interconnects with the Company's
system. According to the Company, its engineers review the need for upgrades in the
Company's transmission and distribution system past the point of interconnection to ensure the
safety and reliability for each customer's interconnection. See the Company's response to Staff s
Production Request No. 5.
If upgrades are needed, the Company has stated that the cost of any upgrades is recovered
from the on-site generation customer through a Contribution in Aid of Construction("CIAC").
See the Company's response to Staff s Production Request No. 5 (B). Because a CIAC is not
included in rate base, the cost of the upgrades will not be included in customer base rates and the
cost will not be passed on to other customers. However, Staff is unsure whether the impact
studies to determine if upgrades are needed are also charged to customers who request on-site
generation service. Staff recommends that the Company's tariffs explicitly state all costs related
to performing the studies and for installing upgrades be charged to the customer requesting on-
site generation service. This will ensure the costs associated with such studies and upgrades
won't be shifted to the Company's other customers.
Eli ig bility Cap for Residential Customers
Staff believes that the eligibility cap for residential customers should remain at 25 kW. In
the Company's On-Site Generation Study on page 2, it states that the average size of a residential
customer's solar photovoltaic system is 8.1 kW as of December 31, 2022. The current cap is
greater than the 125 percent of demand considered in the On-Site Generation Study and is much
simpler to implement than a demand-based cap. Because the current 25 kW cap does not appear
to be limiting for the average residential customer generator, Staff agrees with the Company's
proposal to maintain the current cap for residential customers.
Eli-ig bility Cap for Non-residential Customers
Given that safety of the Company's system will be maintained and costs will not be
shifted to other customers, irrespective of the size of the eligibility cap, the only remaining
STAFF COMMENTS 15 SEPTEMBER 3, 2025

criterion left for Staff to consider in evaluating the size of the cap is based on the intent of the
program, which is to allow customers to offset their load behind the meter. Staff believes the
Company's proposed 2,000 kW cap could allow a large number of non-residential customers to
install generation well over their own load, thus violating the intent of the program.
Consistent with Staff s recommendation in PAC-E-23-17, the Company provided AMI
data for the non-residential customer loads. See Meredith Confidential Workpaper"CONF Idaho
NCP Non-Res Customer Analysis." Staffs analysis of this data showed that 91.07% of all non-
residential customers have non-coincident peaks less than the current 100 kW cap. In addition,
94% of non-residential customers in Idaho who have installed on-site generation have peak
demand less than 20 kW. See the Company's response to Staff s Production Request No. 3.
Thus, if a customer installed generation up to the 2,000 kW cap, they would generally be a net
exporter and should instead apply as a qualifying facility under the Public Utility Regulatory
Policy Act. Because of these reasons, Staff recommends that the Commission deny the
Company's proposed increase to the non-residential project eligibility cap.
However, setting a cap that is too low could also limit the ability of a small number of
customers to offset their own load. To ensure the cap isn't overly restrictive, Staff believes that
the non-residential cap should allow for customers to install on-site generation systems up to
their peak demand in order to be able to offset their own load. Staff recommends that the
Commission set the non-residential project eligibility cap at 100 kW or equal to the customers'
maximum demand, whichever is greater. The majority of customers have load under the current
fixed cap, making Staffs recommendation administratively efficient for the Company to manage
most applications. For customers with demand that exceeds the cap, the Company should use a
similar cap structure as what was approved for IPC in Order No. 36048 to allow customers to
offset demand above the 100 kW cap.
IPC Schedule 84 defines 100% of demand as the greatest monthly billing demand
established during the most recent 12-month period at the time of applying for interconnections,
which includes and ends with the most recent billing period. Subject to the Company's
discretion, when billing demand is not available or does not accurately reflect future operations,
the customer can provide evidence so that the proposed generation facility is sized appropriately.
This can include billing data from a previous customer on the same premise, billing data from
another customer account with similar electrical needs, a third-party analysis from a licensed
STAFF COMMENTS 16 SEPTEMBER 3, 2025

professional engineer detailing expected electrical load for the next 12 months, or, for customers
taking service under Schedule 10, documentation of the horsepower of irrigation equipment.
Other Implementation Considerations
Recovery mechanism
The Company proposes to recover exported energy credits paid as a purchased power
expense in its ECAM. Meredith Direct at 5. This proposal is consistent with the On-site
Generation Study presented in PAC-E-23-17. Study Supplement at 34.
Staff agrees with the Company's proposal. Staff believes that the energy purchased from
self-generators is "must-take" and as such should be recovered through the ECAM.
Treatment of Financial Credits
The Company proposes several recommendations for future use and transferability of
accumulated financial credits. Meredith Direct at 15-16. The Company proposes that financial
credits will never expire, will be able to offset all charges on a customer's bill, are transferable to
other accounts in the customer's name, and any remaining excess credits will be paid out if the
customer closes their account. Id. Staff believes such policies appropriately allow customers to
make full use of their financial credits.
STAKEHOLDER AND CUSTOMER COMMUNICATION
Customer Notice
The Company's customer notice and customized letters to legacy and non-legacy
customers were included along with its Application as Attachment No. 1. The customer notice
was included with bills mailed to customers beginning February 10, 2025 and ending March 10,
2025. The customized letters were mailed beginning on February 19, 2025 and ending February
24, 2025,providing a reasonable opportunity to file timely comments with the Commission by
the September 3, 2025, comment deadline.2 Additionally, when a new application is received for
solar generation, the Company sends an automated email to the applicant acknowledging receipt
2 The comment deadline was changed from August 14 to September 3,2025,Order No. 36716,due to the
Company's amended filing that occurred on July 30,2025.
STAFF COMMENTS 17 SEPTEMBER 3, 2025

of the application. This response includes a statement regarding the Company's proposal, the
case number, and how to file comments.3
Public Workshops
On July 2, 2025, the Commission issued a press release announcing a public
workshop for this case. The Commission held two virtual workshops on July 15, 2025, and
on July 16, 2025. The workshops were sparsely attended with eight customers in attendance
on July 15, 2025, and one customer in attendance on July 16, 2025. The Company's
Application was discussed and Staff addressed customers' comments and concerns
regarding the Application and Commission procedure. Customer concerns echoed those
presented in customer comments submitted to the case record.
Customer Comments
As of September 3, 2025, 158 public comments have been filed in this case. Of the
158 customers who made comments, 142 customers (92%4) oppose the proposed
changes to the ECR. Although only 110 customers (71%) identified themselves as non-
legacy, Staff believes the majority of those that offered comments are non-legacy on-site
generation customers due to the nature of the Company's proposal.
Some customers continued to express concerns regarding grandfathering with 23
customers (15%) stating that current non-legacy customers should be granted legacy
status. There were 23 customers (15%) who urged further consideration of
environmental benefits.
Compensation and Economics
Concerning any change to compensation,20 customers (13%) wanted to keep
monthly net metering (1:1) versus real time metering (ECR) and as previously stated,
142 customers (92%) opposed the proposed changes to the ECR.
3 Statement:"Please be aware that there is an active case with the Idaho Public Utilities Commission(IPUC)that
may impact the value of excess energy exported to the system through your customer generation system.We
encourage customers to follow the proceedings on the Idaho Public Utilities website(puc.idaho.gov).Written
comments regarding Rocky Mountain Power's application(PAC-E-25-02)may be filed with the IPUC at
(puc.idaho.gov/form/casecomrnent)."
4 Percentages are in reference to the total number of customers from the most recent comment count.
STAFF COMMENTS 18 SEPTEMBER 3, 2025

There were 65 customers (43%) who highlighted the large financial investment they
made in purchasing a net generation system. Some of these customers note that the
Company's proposals will result in a low ROI ("return on investment") for their system.
There were 30 customers (19%) who feel generators are subsidizing non-generation
customers. Additionally, I I customers (7%) objected to the recent increases in the monthly
service charge, and 12 customers (8%) citing the impact of multiple increases in rates in a
very short period. In addition, I I customers (7%) said they had no other choice of a provider
because the Company is a monopoly.
There were I I customers (7%) who felt the proposed compensation rate was unfair.
Customers pay the applicable retail rate but will not be compensated at the same rate when
they place electricity back onto the grid. Some customers felt the Company would be
profiting by paying them less than the applicable retail rate and then reselling the electricity
at the higher retail rate. Several of these customers discussed adding batteries to their systems
to save excess power for their own use.
Installers
Based on the customer comments, it appears that many of the solar installers are
not providing accurate or updated information regarding the possibility of future
changes. Many customers claimed they were not aware of possible changes to the
program at the time they purchased and installed their systems. The customers based
their decision on offsetting power costs. There were 24 customers (16%) who mentioned
the high cost of living/ fixed incomes and stated they would not have gone forward had
they known the rates would change.
Company Compensation
There were 24 customers (16%) who mention high company profits and
Company greed and unfair compensation.
STAFF COMMENTS 19 SEPTEMBER 3, 2025

Disencentives
There were 52 customers (34%) who felt the Company is penalizing and/or
discouraging customers for generation of clean energy after specifically advocating for
customers to "go green" and install solar.
STAFF RECOMMENDATION
Staff recommends the Commission issue an order that:
1. Approves the Company's Amended Application with the addition of a rate
stabilization mechanism;
2. Requires the Company to file annual updates by July each year;
3. Requires the Company to file update workpapers as publicly available exhibits;
4. Denies the Company's proposal to increase non-residential project cap;
5. Requires the Company to adjust its tariffs to explicitly state that the customer
requesting on-site generation service is responsible for all costs related to studies
and upgrades;
6. Approves Staff s recommendation to set the non-residential project cap at 100 kW
or each customer's maximum demand, whichever is greater; and
7. Directs the Company to file updated tariffs in a compliance filing that reflect the
Commission's Order.
Respectfully submitted this 3rd day of September 2025.
eY ff'eY . Loll
Deputy Attorney General
Technical Staff: Jason Talford
Matt Suess
Seungjae Lee
Michael Ott
Curtis Thaden
Jolene Bossard
I:\Utility\UMISC\COMMENTS\PAC-E-25-02 Comments.docx
STAFF COMMENTS 20 SEPTEMBER 3, 2025

CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS �(DAY OF SEPTEMBER 2025,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. PAC-E-25-02, BY E-MAILING A COPY THEREOF, TO THE
FOLLOWING:
MARK ALDER JOE DALLAS
PACIFICORP/dba ROCKY MOUNTAIN PACIFICORP/dba ROCKY MOUNTAIN
POWER POWER
1407 WEST NORTH TEMPLE STE 330 825 NE MULTNOMAH ST
SALT LAKE CITY UT 84116 STE 2000
E-MAIL: [e-mail] PORTLAND OR 97232
datarequest kpacificorp.com E-MAIL: [e-mail]
PATRICIA JORDAN, SECRETARY
CERTIFICATE OF SERVICE