20260521Staff Comments.pdf

RECEIVED
May 21, 2026
ERIKA K. MELANSON IDAHO PUBLIC
DEPUTY ATTORNEY GENERAL UTILITIES COMMISSION
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83702
[phone]
IDAHO BAR NO. 11560
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF ROCKY MOUNTAIN )
POWER'S APPLICATION FOR ) CASE NO. PAC-E-26-01
AUTHORIZATION TO UPDATE THE WIND )
AND SOLAR INTEGRATION RATE FOR )
SMALL POWER GENERATION ) COMMENTS OF THE
QUALIFYING FACILITIES ) COMMISSION STAFF
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission
("Commission"), by and through its attorney of record, Erika K. Melanson, Deputy Attorney
General, submits the following comments.
BACKGROUND
On January 16, 2026, Rocky Mountain Power, a division of PacifiCorp ("Company")
applied to the Commission requesting authority to adjust the wind and solar integration rates
applicable to new power purchase agreements between the Company and wind and solar qualifying
facilities ("QFs") ("Application").
The proposed wind and solar integration rates are based on the modeling results of the 2025
Integrated Resource Plan("IRP")and are available in the form of levelized rates and non-levelized
rates.
STAFF ANALYSIS
Staff s review focused on several issues related to the Company's compliance, cost
methodology, and resource planning assumptions. Specifically, Staff examined whether the
STAFF COMMENTS 1 MAY 21, 2026

Company complied with Order No. 36243 and whether the proposed integration charges were
accurately calculated. Staff also evaluated whether integration charges should apply to IRP-based
avoided cost rates and whether those charges may be underestimated or overestimated for behind-
the-meter customers. In addition, Staff considered whether behind-the-meter generation should
be represented through a proxy resource, whether the assumed increased penetration levels of
variable renewable resources were reasonable,and whether QF renewals should be included in the
preferred portfolio. Finally, Staff reviewed whether the reliability targets for energy supply and
reserve shortfalls were appropriate and whether cost issues associated with downward regulation
reserves exist.
First, Staff recommends that the Commission approve the integration charges in
Attachment A, attached hereto, of Staff s comments to be applied to both published avoided cost
rates and IRP-based avoided cost rates. Second, Staff recommends that the Commission require
the Company to file a Flexible Reserve Study ("FRS") within six months after the filing of each
IRP moving forward. If the Company believes a new study is unnecessary, Staff recommends that
the Company file a request for waiver of the study, with evidence supporting its position within
two months after the filing of the IRP. Lastly, Staff recommends that the Commission direct the
Company to incorporate the following areas in the next FRS:
1. Provide evidence for any conclusions regarding the determination of new resources in
the preferred portfolio driven by either reserve or load requirements, and if by reserve
requirements, determine the capital and fixed operation and maintenance ("O&M")
costs to be incorporated into integration charges;
2. Use the most recent data, including the data from the California Independent System
Operator's ("CAISO") Extended Day-Ahead Market ("EDAM");
3. Provide clarity on whether the Company intends to determine integration charges for
IRP-based avoided cost rates in the same model run that determines the IRP-based
avoided cost rates and analyze the feasibility of meeting the timeline dictated by
Schedule 38 Qualifying Facility Avoided Cost Procedures, if both rates are determined
in the same case;
4. Examine whether underestimation and overestimation issues exist for behind-the-meter
customers and quantify the amount of underestimation and overestimation of
integration charges;
STAFF COMMENTS 2 MAY 21, 2026

5. Examine whether behind-the-meter generation should be represented through a proxy
resource to be subject to wind and solar reserve requirements and whether existing
behind-the-meter resources and increases in behind-the-meter resources should be
treated differently;
6. Determine reasonable penetration levels reflecting the actual trend on the Company's
system and explore whether a tiered structure of integration charges based on different
penetration ranges should be developed;
7. Determine whether QF renewals should be excluded from the preferred portfolio;
8. Determine whether the reliability targets for energy supply and reserve shortfalls
should be set at a level where the resulting total loss of load does not exceed the industry
threshold every year throughout the planning horizon; and
9. Address the cost issues associated with downward regulation reserves.
Compliance with Order No. 36243
Order No. 36243 required the Company to meet the following requirements in the FRS
study submitted in this case:
1. Consistently file a case to update integration charges after the acknowledgement of
each IRP to comply with Order Nos. 33937 and 34966;
2. Explain why the capital and fixed O&M costs of regulation reserves should not be
included in wind and solar integration costs supported by quantifiable evidence;
3. Use the most recent data that meets reasonably sufficient duration of operations;
4. Determine with quantifiable evidence whether hybrid wind or hybrid solar should be
treated differently than wind or solar alone;
5. Quantify the effect of holding load constant in scaling portfolio diversity benefits;
6. Work with Staff on modeling and obtaining sufficiently useful results to allow modeled
results for additional online years; and
7. Evaluate the usefulness of integration costs, including inter-hour integration costs and
whether such is justified.
Staff believes that the Company has sufficiently addressed each requirement and provides
additional details for each requirement below.
STAFF COMMENTS 3 MAY 21, 2026

1. Consistently file a case to update integration charges after the acknowledgement of each
IRP to comply with Order Nos. 33937 and 34966.
The Company's 2025 IRP was acknowledged on December 17, 2025,in Order No. 36868,
and the Company filed this case on January 16, 2026, after the acknowledgement. Therefore, the
Company has met the requirement in Order No. 36243.
Recently, the Commission required Idaho Power Company ("Idaho Power") to file its
integration study within six months after the filing of each IRP. Order No. 36661 at 4. If Idaho
Power believes that a new study is unnecessary, the Company shall file for a waiver of the study
with evidence supporting its position within two months after the filing of the IRP. Id. Staff
recommends that the Commission adopt the same treatment for the Company, because Staff
believes it is not necessary to wait until the acknowledgement of an IRP to file the integration
study, which only makes integration rates less accurate due to additional delay.
2. Explain why the capital and fixed O&M costs of regulation reserves should not be included
in wind and solar integration costs supported by quantifiable evidence.
The Company believes that the new resources in this study are not driven by reserve
requirements. Response to Staff Production Request No. 18. Therefore, the Company believes
that the capital and fixed O&M costs of the new resources should not be a component of the
proposed wind and solar integration charges. Although reserve requirements in this study may not
drive additional resource procurement in this study, Staff believes it is important to know when
new resources are driven by reserve requirements and how the capital and fixed O&M costs of the
new resource should be allocated to integration costs. Therefore, Staff recommends for the next
study that if the Company believes that new resources in the preferred portfolio are not driven by
reserve requirements,the Company should provide evidence to support its belief. If the Company
believes that new resources in the preferred portfolio are driven by reserve requirements, then the
Company should develop a method to determine the capital and O&M cost of the reserves and
incorporate the costs into integration charges.
Many indicators show that new resources in this study are not driven by reserve
requirements in the 2025 IRP. For example, the resources with operating reserve capability
significantly exceed the Company's reserve requirements throughout the study horizon.
Application Attachment No. 3 at 1. In addition, less than one percent of the hours each year from
STAFF COMMENTS 4 MAY 21, 2026

2027 and beyond have a marginal cost of operating reserves above $25 per megawatt hours
("MWh"), which indicates that significant reserve shortfalls are not happening. Id. Also, the
largest category of resource additions in the Utah/Idaho/Wyoming/California jurisdiction is energy
efficiency, which does not provide direct reserve capability. Application Attachment No. 3 at 3.
Lastly, the most common product in the Company's short-term market purchases is heavy-load-
hour blocks, which do not provide operating reserves. Id. and Response to Staff Production
Request No. 18. These phenomena indicate that resource additions are not driven by reserve
requirements, and thus the Company believes it is not reasonable to allocate the capital and fixed
O&M cost to integration costs. Application Attachment No. 3 at 2. Staff believes the Company
has met the requirement from Order No. 36243.
Resource additions can be driven by many reasons, such as Western Resource Adequacy
Program ("WRAP") capacity and planning reserve requirements, hourly reliability requirements
to avoid loss of load conditions, economic values of energy, or operating reserve requirements.
Response to Staff Production Request No. 20. The Company's 2025 IRP does not distinguish
these purposes behind resource additions. Id. However,for the purpose of determining integration
charges, Staff believes it is important to know when a new resource is driven by reserve
requirements and how the capital and fixed O&M costs of the new resource should be allocated to
integration costs.
3. Use the most recent data that meets a reasonably sufficient duration of operations.
Staff believes the Company did not use the most recent historical data with sufficient
duration in this case, as required by Order No. 36243 at 7. Thus, Staff recommends that the
Commission direct the Company to use the most recent data in the next study, including the data
from CAISO's EDAM.
In its current FRS,the Company continued to rely on the 2018-2019 historical operational
data to develop reserve requirements,which included the Company's base schedule data submitted
to the Western Imbalance Market("WEIM")and the actual data of the period. These datasets have
been used for multiple integration studies since the Company's 2021 IRP in Case No. PAC-E-21-
19. The Company stated that the current FRS did not use newer datasets because it would no
longer submit its base schedules to the WEIM after the Company starts its participation in EDAM
on May 1, 2026, and it anticipated the reserve requirements would evolve with its participation in
STAFF COMMENTS 5 MAY 21, 2026

CAISO's EDAM. Responses to Staff Production Request Nos. 3 and 34. In other words, since
the Company intends to develop a more comprehensive update based on the new operating
practices from EDAM and since the current method has limited relevance moving forward, the
Company decided not to update the data for this FRS. Response to Staff Production Request No.
3.
Although Staff believes the Company could have used the most recent data when preparing
for this FRS in late 2024, such as datasets of 2022 and 2023, Staff agrees with the Company's plan
to include more recent data moving forward. Therefore, Staff recommends that the Commission
direct the Company to use the most recent data for its next study, including the data from EDAM.
4. Determine with quantifiable evidence whether hybrid wind or hybrid solar should be treated
differently than wind or solar alone.
The Company states that whether hybrid resources are treated differently than resources
without batteries depends on the contract structure and how the resources interact with system
requirements. Application Attachment No. 3 at 3. Staff agrees with the Company's justifications
and believes the Company's treatment is reasonable.
Generally, there are two types of contracting options for the hybrid configurations. Id.
First is where a generator and a battery are contracted and dispatched independently at a single
interconnection point, with a shared interconnection limit. Id. The underlying generator can be
QFs or non-QFs,but the battery would be contracted as a non-QF facility. Application Attachment
No. 3 of at 4. That way,the Company can have full control and flexibility to charge and discharge
the battery in response to system needs in an optimized manner. Id. When the underlying
generator is a QF, the integration charges will apply and will apply to the output of its generation
without the output of the battery. This is because the battery is separately contracted and
economically dispatched in response to system needs, instead of being used to smooth the output
of the QF. Id.
The second type of contracting option for hybrid configurations is where a resource and a
battery are under a single QF contract, with the battery charging solely from the co-located
resource, not from the grid. Id. In other words, the resource and the battery are two components
of the same QF. The battery in this contracting option is typically not incentivized to smooth out
the output of the QF,but to maximize output during peak hours when avoided cost rates are high.
STAFF COMMENTS 6 MAY 21, 2026

Response to Staff Production Request No. 47. Therefore, the Company believes that the
integration charges should apply to the entire output of the QF (i.e. the output of the resource plus
the output of the battery). Application Attachment No. 3 at 5. Despite some developers' interest
in seeking this contracting option, no contracts have been executed under this structure. Id.
5. Quantify the effect of holding load constant in scaling portfolio diversity benefits.
The Company quantified the impact of holding load constant in this FRS,and Staff believes
that the Company has met the requirement of Order No. 36243. Under the current FRS
methodology, after stand-alone reserve requirements were developed for load, wind, solar, and
non-variable energy resources, the Company next calculated portfolio diversity benefits and
WEIM diversity benefits to lower the stand-alone reserve requirements. The portfolio diversity
benefits existed because the largest deviations in each class may not happen simultaneously, or
sometimes the deviations may even occur in offsetting directions. FRS at 131. The Company
assumed the portfolio diversity benefits would vary depending on the penetration levels of wind
and solar only, holding the load constant. Order No. 36243 required the Company to quantify the
effect of holding load constant when scaling portfolio diversity benefits for the entire planning
horizon from the original data in 2018 and 2019.
The Company examined the impact of load growth on portfolio diversity benefits and
determined that it would reduce the average integration costs for wind and solar by approximately
$0.01 per MWh over the entire planning horizon. Application Attachment No. 3 at 7. Given the
minimal impact, Staff believes it is reasonable to not include load as a variable when determining
the portfolio diversity benefits and that using a constant load is reasonable.
6. Work with Staff in modeling and obtaining sufficiently useful results to allow modeled
results for additional online years.
Although Order No. 36243 required the Company to work with Staff to develop modeled
results for additional years(instead of using a general inflation rate),the Company chose to use 20
years of modeled results(years 2026-2045)from its 2025 IRP and then extrapolated the rates using
a 2%approved general inflation rate for five additional years (2046-2050) in developing the wind
and solar integration rates. Workpaper"ID AC 25IRP Wind Solar Integration" in the Application
STAFF COMMENTS 7 MAY 21, 2026

and Response to Staff Production Request No. 46. Based on the Company's justifications, Staff
believes that the Company's approach is acceptable.
First, the Company stated that the modeling period in this case was tied to the 2025 IRP,
and both processes were modeled through 2045. Response to Staff Production Request No. 46.
Therefore,the Company believes changing the modeling period should be addressed as part of the
IRP process. Id. Second, modeling additional years in the IRP is at the expense of precision in
the near term, and the Company believes this is not necessarily a worthwhile tradeoff. Id. Third,
the Company does not anticipate dramatic changes in integration costs between modeled results
and extrapolated results after 2045. Id. Staff agrees with the Company and believes that the
Company's extrapolation of rates using the approved general inflation rate for five additional years
is reasonable.
7. Evaluate the usefulness of integration costs including inter-hour integration costs and
whether such is justified.
The Company has previously evaluated integration costs related to day-ahead uncertainty
in wind and solar forecasts. Response to Staff Production Request No. 28. For example,the 2017
IRP evaluated Day-Ahead System Balancing Costs,also known as inter-hour integration costs. Id.
However, the Company decided not to include these costs in this FRS. Staff believes that the
Company's justifications are reasonable and that the Company has met the requirement from Order
No. 36243.
Inter-hour integration costs are determined based on the resources needed to be available
to respond when the forecasted output for the next day differs from what actually happens.
Application Attachment No. 3 at 7. These costs typically include the costs of sub-optimal startup
decisions of natural gas plants (i.e. Too many natural gas plants may have been started on a day
when variable energy resources generate higher than expected, or too few natural gas plants may
have been started on a day when variable energy resources generate lower than expected.) Id. The
Company decided not to include the inter-hour integration costs in the proposed integration
charges for several reasons. First, natural gas plant startup costs are not as significant as in the
past due to low natural gas prices, increased diversity from geographically distributed wind and
solar,and increased flexibility from battery storage. Id. Second,with the Company's participation
STAFF COMMENTS 8 MAY 21, 2026

in the EDAM, variable energy resources and natural gas plant startups will be better coordinated
across a much larger footprint, which will lower the costs of sub-optimal decisions. Id. Third,
EDAM optimization feeds into the WEIM for real-time dispatch. Response to Staff Production
Request No. 45. The EIM's capability of absorbing excess energy supply and alleviating energy
shortfalls will further reduce the already small impact of inter-hour integration costs. Response to
Staff Production Request No. 28. Lastly, the 2017 IRP used two sets of data to determine inter-
hour integration costs: (1) the actual load, wind, and solar, and (2) a day-ahead forecast of load,
wind, and solar. Id. However, the Company does not have the same type of day-ahead forecast
in the 2025 IRP, because the day-ahead forecast information has changed with participation in
EDAM. Response to Staff Production Request No. 50.
Proposed Integration Charges
The Company included the proposed wind integration charges and solar integration charges
in Application Attachment No. 2. However, the individual years for the non-levelized solar
integration charges and the online years for the levelized solar integration charges are mislabeled.
Both the non-levelized rates and the levelized rates should begin in 2026 instead of 2024.
Response to Staff Production Request No. 32. The Company corrected the error through its
Response to Staff Production Request No. 32. Staff includes the updated integration charges' in
Attachment A to these comments and recommends that the Commission approve the updated rates.
Application of Proposed Integration Charges
The Company proposes applying integration charges to published avoided cost rates, not
IRP-based avoided cost rates,because the IRP used to determine avoided cost rates may not be the
same IRP that is used to determine integration charges. Response to Staff Production Request No.
33. Staff believes that the inconsistency issue will be significantly alleviated when the filing time
changes from after acknowledgement of an IRP to within six months after the filing of an IRP,
because both the IRP-based avoided cost rates and the integration charges will be based on the
most recently filed IRP. Therefore, Staff recommends that the Commission require the proposed
integration charges to apply to both published avoided cost rates and IRP-based avoided cost rates.
1 Staff includes both wind integration charges and solar integration charges in Attachment A of the comments.
STAFF COMMENTS 9 MAY 21, 2026

IRP-based avoided cost rates are based on the most recently filed IRP. Order No. 32697 at
22. Currently, the Company's integration charges are based on the most recently acknowledged
IRP. Order No. 33937 at 5 and Order No. 34966 at 5. As discussed above, Staff recommends that
the Commission approve changing the filing timeline for the Company from after
acknowledgement of an IRP to within six months after the filing of an IRP.
However, it is unclear whether the Company intends to determine integration charges on a
case-by-case basis and use the same model run to determine both IRP-based avoided cost rates and
integration charges. Staff recommends that the Commission direct the Company to provide more
clarity on whether the Company intends to determine integration charges for IRP-based avoided
cost rates in the same model run that determines the IRP-based avoided cost rates. If so, Staff
recommends that the Commission direct the Company to analyze the feasibility of meeting the
timeline dictated by Schedule 38 Qualifying Facility Avoided Cost Procedures, if both rates are
determined in one case.
Potential Underestimation and Overestimation of Integration Charges for Behind-the-Meter
Customers
In Idaho Power's most recent integration charge case (IPC-E-25-36), Staff identified
potential issues of underestimation and overestimation of integration charges for behind-the-meter
customers. Staff recommends that the Commission direct the Company to examine whether
similar issues exist in this case and if they do, quantify the amount of underestimation and
overestimation of integration charges in the next study.
There are four reasons why Idaho Power believes integration charges are underestimated
for behind-the-meter customers. First, the integration costs are incurred based on generation
profiles but are recovered based on export profiles. Response to Staff Production Request No. 7
(b)in Case No.IPC-E-25-07. Second,utility-scale solar typically has axis tracking,which reduces
solar variability, whereas on-site solar generation does not. Id. Third, utility-scale solar projects
typically use oversized panel-to-inverter ratio, which further reduces solar variability.Id. Fourth,
exports occur more often during high-output, low-load hours when the need for integrating
resources is greater. Id.
While Staff agrees that there is a basis for the Idaho Power's position, Staff also believes
that there is a possibility that integration charges are overestimated. In general, to develop
integration costs of variable energy resources,the analysis needs to isolate and separate the amount
STAFF COMMENTS 10 MAY 21, 2026

of reserves needed to buffer variability of generation from the amount of reserves needed to buffer
variability of load. The cost for the amount of reserves needed to buffer variability of load is
assumed to be recovered through customer rates. Staff believes the method will work well when
the data for both load and generation are kept separate. However,behind-the-meter customers are
both net consumers as a source of load, as well as net generators of energy when they export
energy. In other words, the total load and the total generation of these customers are not captured
separately. Therefore, Staff believes that variability of both load and generation are confounded,
and that there is a potential for overlap between the amount of reserves needed to balance their
load as consumers of energy and the amount of reserves needed to balance their generation. In
this case, the Company's net load of behind-the-meter customers is captured in the load forecast
just like Idaho Power's. Responses to Staff Production Request Nos. 4, 9, 10, and 35 (c).
Therefore, Staff believes there is a possibility of overestimation of integration charges.
Whether Behind-the-Meter Generation Should Be Presented Through a Proxy
Even though the Company does not have a specific hourly forecast of behind-the-meter
resources,the Company believes an adjustment could be made to determine the amount of reserves
based on the capacity of the behind-the-meter resources. Response to Staff Production Request
No. 38. In addition, the Company stated that since existing behind-the-meter resource capacity is
embedded in the load used to develop reserve requirements in the study, only increases in behind-
the-meter resources will need to be accounted for. Id.
Staff believes that: (1) the Company currently does not apply wind and solar reserve
requirements to behind-the-meter resources; (2) existing behind-the-meter resource capacity is
captured in the load and is subject to load reserve requirements; and (3) increases in behind-the-
meter resources can be subject to wind and solar reserve requirements (instead of load reserve
requirements)based on their capacity(instead of their hourly generation forecasts). Staff believes
more clarity is needed on this topic. Thus, Staff recommends that the Commission direct the
Company, in its next study, to examine whether behind-the-meter generation should be presented
through a proxy (due to lack of data) to be subject to wind and solar reserve requirements and
whether existing behind-the-meter resources and increases in behind-the-meter resources should
be treated differently.
STAFF COMMENTS 11 MAY 21, 2026

Penetration Levels
The study calculated wind and solar integration charges based on the incremental
regulation reserve costs associated with additional five megawatts ("MW") of wind and of solar
compared to the preferred portfolio for PacifiCorp East("PACE")and PacifiCorp West("PACW")
as reflected in Table No. 1 below. FRS at 138. This assumes an addition of five MW in the first
year, which is held in place for the entire planning horizon without other additions.
Table No. 1: Incremental Wind and Solar QFs Compared to Preferred Portfolio
Wind Capacity (MW) Solar Capacity(MW)
PACE 5 5
PACW 5 5
However, based on the actual data between 2022 through 2025, the average annual
incremental wind and solar QFs added to PACE and PACW, as reflected in Table No. 2 below, do
not align well with the assumed amounts. This data shows QFs are added each year incrementally
with various increments.
Table No. 2: Average Annual Incremental Wind and Solar QFs Added from 2022 through
2025
Wind Capacity(MW) Solar Capacity(MW)
PACE 0.03 0
PACW 2 22.23
Data Source: Response to Staff Production Request No. 39.
Therefore, Staff recommends that the Commission direct the Company to determine
reasonable penetration levels in the next study that reflects the actual trend on the Company's
system and explore whether a tiered structure of integration charges based on different penetration
ranges should be developed.
OF Renewals
Although the preferred portfolio in this study does not assume new QF developments, it
assumes that 75 percent of existing QF capacity will be renewed at the end of their current contract
term. Responses to Staff Production Request Nos. 7 and 40. Staff believes that the assumption of
STAFF COMMENTS 12 MAY 21, 2026

QF renewals will result in inaccurate integration charges because of a discrepancy between the QF
position used to determine integration charges (i.e. within the five-MW range above the preferred
portfolio for each balancing area) and the actual QF position in the Company's system (i.e.
potentially within the preferred portfolio because it may fill the space of assumed renewed QFs).
Therefore, Staff recommends that the Commission direct the Company to determine whether QF
renewals should be excluded from the preferred portfolio in the next study.
Reliability Targets for Energy Supply Shortfalls and Reserve Shortfalls
The preferred portfolio in the 2025 IRP is required to meet both the WRAP capacity
requirements and hourly reliability requirements. Response to Staff Production Request No. 14
(c). The reliability target used to develop reserve requirements is an additional 0.5 Loss of Load
Hour ("LOLH") per year. FRS at 124 and Response to Staff Production Request No. 43. Table
No. 3 below shows that Year 2028 and Year 2029 have exceeded 2.4 LOLH annually, which is
equal to the industry standard of 24 hours or one day in ten years. Therefore, Staff recommends
that the Commission direct the Company to determine, in the next study, whether the reliability
targets for energy supply shortfalls and reserve shortfalls should be set at a level where the resulting
total loss of load does not exceed the industry threshold every year throughout the planning
horizon.
{Remainder of page intentionally left blank}
STAFF COMMENTS 13 MAY 21, 2026

Table No. 3: Total LOLH of Preferred Portfolio
Energy Supply Shortfalls(LOLH) Reserve Shortfalls(LOLH) Total
2025 0.89 0.50 1.39
2026 0.56 0.50 1.06
2027 0.33 0.50 0.83
2028 3.72 0.50 4.22
2029 2.06 0.50 2.56
2030 0.00 0.50 0.50
2031 0.06 0.50 0.56
2032 0.00 0.50 0.50
2033 0.00 0.50 0.50
2034 0.00 0.50 0.50
2035 0.00 0.50 0.50
2036 0.00 0.50 0.50
2037 0.17 0.50 0.67
2038 0.61 0.50 1.11
2039 0.44 0.50 0.94
2040 0.28 0.50 0.78
2041 0.44 0.50 0.94
2042 0.44 0.50 0.94
2043 1.39 0.50 1.89
2044 0.44 0.50 0.94
2045 1 0.44 0.50 0.94
Data Source: Response to Staff Production Request No. 41 (c).
Downward Regulation Reserves
The proposed integration charges are determined based on upward regulation reserve
requirements only,without downward regulation reserve requirements,because the Company can
curtail non-QF wind and solar resources. Response to Staff Production Request No. 16. Staff is
concerned that there are costs associated with the curtailment provisions of the non-QF wind and
solar contracts and whether these costs should be reflected in the FRS study. Staff is also
concerned whether there are any costs of backing down other dispatchable resources for QF wind
and solar projects and whether these costs should be reflected in the FRS study. Therefore, Staff
recommends that the Commission direct the Company to address the cost issues associated with
downward reserves in the next study.
STAFF RECOMMENDATION
First, Staff recommends that the Commission approve the integration charges in
Attachment A of Staff s comments to be applied to both published avoided cost rates and IRP-
based avoided cost rates. Second, Staff recommends that the Commission require the Company
to file an FRS within six months after the filing of each IRP moving forward. If the Company
STAFF COMMENTS 14 MAY 21, 2026

believes a new study is unnecessary, Staff recommends that the Company file a request for waiver
of the study, with evidence supporting its position within two months after the filing of the IRP.
Lastly, Staff recommends that the Commission direct the Company to incorporate the following
areas in the next FRS:
1. Provide evidence for any conclusions regarding the determination of new resources in
the preferred portfolio driven by either reserve or load requirements, and if by reserve
requirements, determine the capital and fixed O&M cost to be incorporated into
integration charges;
2. Use the most recent data, including the data from CAISO's EDAM;
3. Provide clarity on whether the Company intends to determine integration charges for
IRP-based avoided cost rates in the same model run that determines the IRP-based
avoided cost rates and analyze the feasibility of meeting the timeline dictated by
Schedule 38 Qualifying Facility Avoided Cost Procedures,if both rates are determined
in the same case;
4. Examine whether underestimation and overestimation issues exist for behind-the-meter
customers and quantify the amount of underestimation and overestimation of
integration charges;
5. Examine whether behind-the-meter generation should be presented through a proxy to
be subject to wind and solar reserve requirements and whether existing behind-the-
meter resources and increases in behind-the-meter resources should be treated
differently;
6. Determine reasonable penetration levels reflecting the actual trend on the Company's
system and explore whether a tiered structure of integration charges based on different
penetration ranges should be developed;
7. Determine whether QF renewals should be excluded from the preferred portfolio;
8. Determine whether the reliability targets for energy supply and reserve shortfalls
should be set at a level where the resulting total loss of load does not exceed the industry
threshold every year throughout the planning horizon; and
9. Address the cost issues associated with downward regulation reserves.
STAFF COMMENTS 15 MAY 21, 2026

Respectfully submitted this 21 st day of May 2026.
t4 (�
Erika K. Melanson
Deputy Attorney General
Technical Staff. Yao Yin
Shubhra Deb Paul
I:\Utility\UMISC\COMMENTS\PAC-E-26-01 Comments.docx
STAFF COMMENTS 16 MAY 21, 2026

Attachment A
Wind Integration Charges
Non-Levelized Rates Levelized Rates Online Year
Year $/MWh Contract Length 2026 2027 2028 2029 2030 2031
2026 1.45 1 $1.45 $0.44 $0.19 $0.24 $0.28 $0.35
2027 0.44 2 $0.96 $0.32 $0.22 $0.26 $0.32 $0.31
2028 0.19 3 $0.72 $0.30 $0.24 $0.29 $0.30 $0.29
2029 0.24 4 $0.61 $0.29 $0.26 $0.28 $0.29 $0.29
2030 0.28 5 $0.56 $0.30 $0.26 $0.28 $0.29 $0.28
2031 0.35 6 $0.53 $0.30 $0.26 $0.28 $0.28 $0.27
2032 0.25 7 $0.50 $0.29 $0.26 $0.27 $0.28 $0.27
2033 0.27 8 $0.47 $0.29 $0.26 $0.27 $0.27 $0.27
2034 0.27 9 $0.46 $0.29 $0.26 $0.27 $0.28 $0.28
2035 0.23 10 $0.44 $0.28 $0.26 $0.27 $0.28 $0.28
2036 0.24 11 $0.43 $0.28 $0.26 $0.27 $0.28 $0.28
2037 0.23 12 $0.42 $0.28 $0.26 $0.28 $0.28 $0.27
2038 0.32 13 $0.41 $0.28 $0.27 $0.28 $0.27 $0.26
2039 0.33 14 $0.41 $0.29 $0.27 $0.27 $0.26 $0.25
2040 0.34 15 $0.41 $0.28 $0.26 $0.26 $0.25 $0.24
2041 0.23 16 $0.40 $0.28 $0.25 $0.25 $0.24 $0.23
2042 0.05 17 $0.39 $0.27 $0.24 $0.24 $0.24 $0.23
2043 0.07 18 $0.38 $0.26 $0.24 $0.24 $0.23 $0.22
2044 0.03 19 $0.37 $0.26 $0.23 $0.23 $0.23 $0.22
2045 0.03 20 $0.36 $0.25 $0.23 $0.23 $0.22 $0.21
2046 0.03 21
2047 0.03 22
2048 0.03 23
2049 0.03 24
2050 0.03 25
ATTACHMENT A
Case No. PAC-E-26-01
Staff Comments
May 21, 2026

Solar Integration Charges
Non-Levelized Rates Levelized Rates Online Year
Year $/MWh Contract Length 2026 2027 2028 2029 2030 2031
2026 1.61 1 $1.61 $0.53 $0.41 $0.45 $0.51 $0.77
2027 0.53 2 $1.09 $0.47 $0.43 $0.48 $0.64 $0.86
2028 0.41 3 $0.88 $0.46 $0.45 $0.57 $0.73 $0.80
2029 0.45 4 $0.78 $0.47 $0.53 $0.65 $0.72 $0.77
2030 0.51 5 $0.73 $0.53 $0.60 $0.66 $0.71 $0.71
2031 0.77 6 $0.74 $0.58 $0.61 $0.66 $0.67 $0.67
2032 0.95 7 $0.76 $0.59 $0.61 $0.63 $0.65 $0.64
2033 0.66 8 $0.75 $0.60 $0.60 $0.61 $0.62 $0.61
2034 0.66 9 $0.75 $0.59 $0.58 $0.59 $0.59 $0.59
2035 0.47 10 $0.73 $0.58 $0.57 $0.57 $0.58 $0.57
2036 0.42 11 $0.71 $0.56 $0.55 $0.56 $0.57 $0.56
2037 0.35 12 $0.69 $0.55 $0.54 $0.55 $0.55 $0.54
2038 0.34 13 $0.67 $0.54 $0.54 $0.54 $0.53 $0.52
2039 0.37 14 $0.66 $0.54 $0.53 $0.52 $0.52 $0.50
2040 0.40 15 $0.65 $0.53 $0.51 $0.51 $0.50 $0.48
2041 0.34 16 $0.64 $0.51 $0.50 $0.49 $0.48 $0.47
2042 0.13 17 $0.62 $0.50 $0.49 $0.48 $0.47 $0.46
2043 0.14 18 $0.61 $0.49 $0.47 $0.47 $0.46 $0.45
2044 0.09 19 $0.59 $0.48 $0.46 $0.46 $0.45 $0.44
2045 0.09 20 $0.58 $0.47 $0.46 $0.45 $0.44 $0.43
2046 0.09 21
2047 0.09 22
2048 0.09 23
2049 0.09 24
2050 0.10 25
ATTACHMENT A
Case No. PAC-E-26-01
Staff Comments
May 21, 2026

CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 21St DAY OF MAY 2026, SERVED
THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE NO.
PAC-E-26-01, BY E-MAILING A COPY THEREOF, TO THE FOLLOWING:
Rocky Mountain Power:
JANA SABA
JOE DALLAS
ROCKY MOUNTAIN POWER
1407 WEST NORTH TEMPLE STE 330
SALT LAKE CITY UT 84116
E-MAIL: [e-mail]
joseph.dallas(apacificorp.com
datarequestkpacificorp.com
PATRICIA JORDA9, SECRETARY
CERTIFICATE OF SERVICE