20260701Final_Order_No_37086.pdf

Office of the Secretary
Service Date
July 1,2026
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF ROCKY MOUNTAIN ) CASE NO. PAC-E-26-01
POWER'S APPLICATION FOR )
AUTHORIZATION TO UPDATE THE WIND )
AND SOLAR INTEGRATION RATE FOR ) ORDER NO. 37086
SMALL POWER GENERATION )
QUALIFYING FACILITIES )
On January 16, 2026, Rocky Mountain Power, a division of PacifiCorp ("Company")
applied to the Idaho Public Utilities Commission ("Commission") requesting authority to adjust
the wind and solar integration rates applicable to new power purchase agreements ("PPA")
between the Company and wind and solar qualifying facilities ("QFs") ("Application").
On February 9, 2026, the Commission issued a Notice of Application and Notice of
Modified Procedure, establishing deadlines for public comments and Company reply comments.
Order No. 36931. No public comments were received.
Based on our review of the record, the Commission issues this Final Order approving the
wind and solar integration rates proposed by the Company and reflected in Attachment A to
Commission Staff s ("Staff') Comments and requiring the Company to file a Flexible Reserve
Study("FRS")within six months following each Integrated Resource Plan("IRP")going forward.
BACKGROUND
In 2007,the Company requested approval of a utility-specific wind integration adjustment
to the published avoided cost rates. See Case No. PAC-E-07-07. The Commission approved a
stipulation by the parties and determined "that a utility-specific wind integration cost adjustment
to a utility's published avoided costs, among other adjustments, was appropriate." Application at
2 citing Order No. 30497 at 12. Additionally, the Commission ordered the Company to file any
changes to its wind integration charge as reflected in future Integrated Resource Plans("IRP").Id.
citing Order No. 30497 at 13.
THE APPLICATION
The Company's proposed an integration rate for electricity purchased from wind-powered
QFs of$1.45 per megawatt-hour("MWh") for 2026, with a corresponding 20-year levelized rate
of$0.36 per MWh for contracts beginning that year.Application at 1.The proposed rate represents
ORDER NO. 37086 1

a decrease from the current wind integration charge of$3.51 per MWh, or $0.83 per MWh on a
20-year levelized basis.Id.
For solar-powered QFs, the Company proposed an integration rate of$1.61 per MWh for
2026, with a levelized price of$0.58 per MWh for a 20-year contract commencing in 2026. Id.
These proposed solar rates are also lower than existing integration charges—currently $4.80 per
MWh, or $1.35 per MWh when levelized over 20 years. Id.
The Commission approved the Company's 2025 IRP on December 17, 2025. Order No.
36868. The Company believed that the proposed wind and solar integration rates reflect the
variability and outcomes identified in the 2025 IRP and would be available in levelized form for
multiple contract durations and in-service years. Id. at 1-2. The Company further explained that
the proposed integration charges were designed to recover the costs associated with integrating
wind and solar generation into the electric system and would be deducted from the Company's
published avoided cost rates. Id. at 2. An exception would apply where a QF elects, through its
PPAs, to deliver energy to the Company on an hourly scheduled basis.Id. at 2.
STAFF COMMENTS
Staff reviewed the Company's proposed wind and solar integration charges, focusing on
compliance with Order No. 36243, the accuracy of the integration charge methodology, and key
assumptions underlying the Company's resource planning and reserve requirements. Staff
Comments at 1-2. Staff believed the Company substantially satisfied the requirements established
in Order No. 36243, including timely filing its FRS following acknowledgment of the 2025 IRP,
evaluating hybrid resource treatment, quantifying the effects of load assumptions on portfolio
diversity benefits, and assessing the relevance of inter-hour integration costs.Id. at 3-4. Staff also
believed that the Company's rationale for excluding capital and fixed operation and maintenance
costs associated with reserve-driven resource additions from the current integration charges were
reasonable, given the evidence indicating that resource additions in the 2025 IRP were not driven
by reserve requirements.Id. at 4-5.
Staff did express concern about the Company's continued reliance on historical operational
data from 2018-2019 to develop its reserve requirements, despite the availability of more recent
datasets.Id. at 5. Staff noted that the Company did not fully satisfy the requirement to use the most
current data and recommended that the Company's future FRS incorporate the latest available
operational information,including data associated with participation in the California Independent
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System Operator's ("CAISO") Extended Day-Ahead Market ("EDAM"). Id. Staff also observed
that the Company's IRP does not distinguish whether new resource additions are prompted by
reserve requirements, capacity requirements, reliability needs, or economic considerations. Id. at
4-5. Because integration charges are intended to recover costs associated with reserve
requirements, Staff recommended that future studies clearly identify when resource additions are
driven by reserve needs and, if so, determine how the associated capital and fixed operation and
maintenance costs should be allocated to integration charges.Id. at 5.
Staff further raised concerns regarding the application of integration charges to IRP-based
avoided cost rates and recommended that such charges apply to both published and IRP-based
avoided cost rates. Id. at 9-10. While acknowledging the Company's concern that integration
charges and avoided cost rates could be based on different IRPs, Staff believed that this
inconsistency would be largely resolved if integration studies were filed within six months of each
IRP filing rather than after IRP acknowledgment.Id. at 10.
In addition, Staff reviewed the treatment of behind-the-meter generation and the potential
for integration charges to be either underestimated or overestimated for these resources. Id. Staff
noted that integration costs are currently calculated based on generation profiles but recovered
based on export profiles,creating a potential mismatch that may understate actual integration costs.
Id. Staff also recognized that behind-the-meter solar facilities generally lack the tracking
technology and optimized panel-to-inverter configurations commonly found in utility-scale
projects, resulting in greater variability and potentially higher integration costs. Id. At the same
time, Staff identified the possibility that integration charges could be overstated because behind-
the-meter customers function simultaneously as electric load and generation resources, making it
difficult to separate load variability from generation variability when determining reserve
requirements.Id. at 11. As a result, Staff recommended that future studies evaluate both potential
underestimation and overestimation of integration charges, quantify the magnitude of any
discrepancies, and examine whether behind-the-meter resources should be represented through
proxy resources subject to wind and solar reserve requirements. Id. Staff further recommended
that the Company assess whether existing behind-the-meter resources and future additions should
be treated differently for integration charge purposes.Id.
Staff also questioned whether the assumptions used to develop integration charges
accurately reflect actual renewable resource development trends on the Company's system. Id. at
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12.The current study calculated integration costs based on incremental additions of five megawatts
("MW") of wind or solar generation above the preferred portfolio and assumed those additions
remained constant throughout the planning horizon. Id. Staff believed that these assumptions did
not align well with actual qualifying facility development patterns, which have occurred
incrementally over time and at varying levels. Id. Consequently, Staff recommended that future
studies evaluate renewable penetration levels that more closely reflect observed system trends and
consider whether a tiered integration charge structure based on different penetration ranges would
produce more accurate results. Id. Staff additionally expressed concern that including assumed
renewals of existing qualifying facility contracts in the preferred portfolio could distort integration
charge calculations by affecting the baseline resource mix against which incremental renewable
additions are measured. Id. at 12-13. Accordingly, Staff recommended that the Company analyze
whether QF renewals should be excluded from the preferred portfolio in future studies.Id. at 13.
Finally, Staff expressed its concerns regarding reliability assumptions and reserve-related
costs. Id. Although the preferred portfolio was designed to satisfy both Western Resource
Adequacy Program ("WRAP") capacity requirements and hourly reliability requirements, Staff
noted that projected loss-of-load hours in certain years exceeded industry standards. Id. Staff
recommended that future studies evaluate whether reliability targets for both energy supply and
reserve shortfalls should be adjusted to ensure that total loss-of-load metrics remain within
accepted industry thresholds throughout the planning horizon. Id. Staff also observed that the
proposed integration charges account only for upward regulation reserve requirements and exclude
downward regulation reserves because the Company can curtail non-QF wind and solar resources.
Id. at 14.However, Staff questioned whether costs associated with curtailment provisions,backing
down dispatchable resources, and other operational impacts of managing excess generation are
being adequately captured. Id. Likewise, Staff recommended that the Company evaluate and
address the costs associated with downward regulation reserves in future studies to ensure that
integration charges more accurately reflect the full cost of integrating variable renewable
resources.Id.
Based on its review, Staff recommended that the Commission approve the updated wind
and solar integration charges and apply them to both published avoided cost rates and IRP-based
avoided cost rates.Id. Staff further recommended that the Company be required to file an updated
FRS within six months of each IRP filing, rather than waiting for IRP acknowledgment, with any
ORDER NO. 37086 4

request for waiver supported by evidence and submitted within two months of the IRP filing. Id.
Finally, Staff recommended that future FRS filings provide additional analysis and documentation
regarding reserve-driven resource additions, use of current operational data, coordination of
integration charge and IRP-based avoided cost rate development, treatment of behind-the-meter
resources, renewable penetration assumptions, QF renewal treatment, reliability target selection,
and the costs associated with downward regulation reserves. Id. at 15. Staff believed that these
recommendations would improve the accuracy, transparency, and consistency of integration
charge calculations and ensure that future studies best reflect evolving system conditions and
market operations.Id.
COMPANY REPLY
In response to Staff s recommendation to file a case to update the integration charges
within six months of filing each IRP, the Company stated that its integration cost filings have
historically relied on analysis already completed as part of the IRP, requiring little additional
preparation. Company Reply at 2. The Company believed IRP integration cost results would be
generally sufficient for QF pricing and that additional analysis would provide limited value given
the relatively small impact of integration costs. Id. at 2-3. However, if additional analysis was
required, the Company agreed that a six-month filing window after each IRP would provide
adequate time to complete and submit an updated integration cost case.Id. at 3.
In response to Staff s recommendation that the Company provide evidence to support its
position that the new resources in the preferred portfolio are not driven by reserve requirements,
or alternatively, develop a method to account for reserve-related costs, the Company explained
that its 2025 IRP modeled integration service through regulation reserves held on dispatchable
resources.Id. at 3-4.Under stressed conditions,all available resources would be deployed to serve
load, meaning integration reserves would not create an incremental need for new resources or
associated fixed costs. Id. at 4. The Company also noted that operational practices, forecasting
improvements, and participation in the Western Energy Imbalance Market ("WEIM") further
reduce reserve shortfall risks.Id.
However, the Company stated that it is evaluating changes for its 2027 IRP to reflect
participation in CAISO's EDAM, which includes resource sufficiency requirements and penalties
for reserve shortfalls. Id. at 5. Under the proposed 2027 approach, reserve shortfalls would be
treated similarly to energy shortfalls, potentially creating an incremental need for resources and
ORDER NO. 37086 5

associated fixed costs. Id. The Company indicated that any resulting changes to how integration
costs are reflected in planning, including possible adjustments to wind and solar capacity
contributions, should also be applied consistently to Idaho QFs. Id. at 6.
Regarding Staff s recommendation that the Company use more historical data, including
data from CAISO's EDAM, the Company explained that it did not use more recent data in this
case because EDAM was not implemented until May 1, 2026, and it intends to develop a more
comprehensive update reflecting EDAM operating practices. Id. The Company stated that, for its
2027 IRP, it plans to incorporate available EDAM data, including Imbalance Reserve Up
requirements, although CAISO has only produced these values for PacifiCorp's balancing
authority areas since parallel EDAM operations began in February 2026.Id.
In response to Staffs recommendation that the Company clarify if it intends to determine
integration charges for IRP-based avoided cost rates in the same model that determines the IRP-
based avoided cost rates and review the feasibility of meeting the timelines in Electric Service
Schedule No. 38—Qualifying Facility Avoided Cost Procedures if both rates are determined in the
same case, the Company believed that integration costs should be based on the most recently filed
IRP and that a separate approval process is unnecessary. Id. at 7. The Company believed that this
approach would be most consistent with the current IRP methodology, while noting that future
IRPs may require a different approach if integration requirements are modeled dynamically.Id.
In response to Staffs recommendation that the Company review potential overestimation
and underestimation of integration charges for behind-the-meter generation, the Company stated
that it is open to further evaluation as part of its next export credit rate update due in July 2028.Id.
at 7-8. The Company explained that behind-the-meter generation cannot be analyzed using the
same forecasting methods as utility-scale resources, but preliminary information suggests
customer exports may exhibit greater volatility and could warrant slightly higher integration costs.
Id. at 8. However, the Company believed a comprehensive analysis is not currently necessary
because integration costs are relatively low, expected to decline over time, and will be updated
through the export credit rate process.Id.
In response to Staff s recommendation 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, the
ORDER NO. 37086 6

Company believed that behind-the-meter wind resources are too limited to justify separate
analysis. Id. at 9. The Company explained that while the growing amount of behind-the-meter
solar may warrant additional review, the Company would recommend conducting that analysis as
part of its next export credit update in July 2028 rather than the 2027 IRP.Id. at 9-10.The Company
noted that upcoming EDAM data will be limited and evolving, and that waiting until the next
export credit proceeding would allow for a more meaningful evaluation of customer export impacts
and integration requirements.Id. at 10.
In response to Staff s recommendation that the Commission direct the Company to
determine reasonable penetration levels in its next FRS 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, the Company stated that penetration-based tiers are
unlikely to meaningfully improve the accuracy of avoided costs.Id. The Company explained that
wind and solar penetration is driven by all system resources, not just Idaho QFs, and can be
significantly affected by non-QF resource additions, contract renewals, and developments in other
states. Id. The Company also emphasized that small QFs have minimal impact on integration
requirements and that larger QFs priced under the IRP methodology already receive updated
pricing every two years.Id. at 11. While the Company was not opposed to using tiered integration
costs if future IRPs adopt them, it does not support developing Idaho-specific integration cost tiers
now.Id.
In response to Staff s recommendation that the Commission direct the Company to
determine whether QF renewals should be excluded from the preferred portfolio in the next FRS,
the Company believed that the treatment of QFs in IRP modeling should be addressed through the
IRP public input and review process rather than in an integration cost proceeding.Id. at 11-12. The
Company also believed that excluding assumed QF renewals may not materially change
integration requirements because similar proxy wind or solar resources could have been selected
instead,resulting in comparable renewable penetration and integration needs.Id. at 12.
In response to Staffs recommendation that the Commission direct the Company to
determine, in the next FRS, 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, the Company explained that improving
EDAM-based modeling may better align energy and reserve shortfall treatment in the 2027 IRP.
ORDER NO. 37086 7

Id. The Company believed that its 2025 IRP could not precisely target loss-of-load reliability levels
due to the timing of stochastic analysis and the difficulty of adjusting portfolios afterward,
especially given the sensitivity of results to small resource changes and the complexity of high
wind, solar, and storage portfolios. Id. at 13. The Company also believed that while portfolios
should be reasonably close to reliability targets, exact calibration is limited by modeling
constraints and the tradeoff between precision and timely IRP completion.Id.
In response to Staff s recommendation that the Commission direct the Company to address
the cost issues associated with downward reserves in the next study, the Company believed that it
generally has sufficient downward ramping capability within its existing resource portfolio and
does not need to explicitly procure additional downward reserves.Id. The Company explained that
wind and solar resources, including owned assets and PPAs, can rapidly reduce output and are
efficiently dispatched through the WEIM, which prioritizes the most cost-effective backdown
order based on market bids and production tax credit impacts. Id. at 14. The Company further
believed that,unlike upward reserves that withhold capacity from generation, downward ramping
does not prevent resources from producing unless needed,reinforcing its view that additional cost
allocation for downward reserves is unnecessary. Id.
COMMISSION FINDINGS AND DECISION
The Commission has jurisdiction over the Company's Filing and the issues in this case
under Title 61 of the Idaho Code including, Idaho Code §§ 61-501, -502, and -503. 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, -502, and-503.
The Commission has reviewed the Company's Application including all submitted
materials, Staff Comments, and the Company's Reply Comments. Based on our review of the
record, we find it fair, just, and reasonable to approve the wind and solar integration charges
proposed by the Company and reflected in Attachment A to Staff s Comments.
The record demonstrates that the Company's proposed wind and solar integration charges
are based on the results of its 2025 IRP and are consistent with prior Commission directives
regarding the development and updating of wind and solar integration costs.
ORDER NO. 37086 8

We further find Staff s recommendations are reasonable and supported by the record. Staff
identified several areas where future filings may be improved—or certain information would be
useful for Staff s analysis—including the use of more recent operational data, consideration of
evolving market structures, treatment of behind-the-meter resources, renewable penetration
assumptions, reserve requirements, and the timing of future integration cost filings. We agree that
continued review of these issues will improve the accuracy,transparency,and consistency of future
integration cost studies.
At the same time, we recognize the Company's concerns. The Company explained that
many of Staffs recommendations involve issues currently under evaluation as part of its ongoing
resource planning processes and the implementation of the CAISO's EDAM is expected to
significantly affect future modeling assumptions and methodologies. We find the Company's
reasoning reasonable and acknowledge that some of Staff s recommendations may be more
appropriately addressed as additional EDAM operational experience and data become available.
To ensure timely review of future wind and solar integration costs and consistency with
the Company's IRP process, we direct the Company to submit subsequent FRS filings within six
months of filing each future IRP. If the Company believes compliance with this timeline is not
feasible or warranted under the circumstances, it may request a waiver from the Commission. Any
waiver request shall explain the basis for the request and identify the proposed alternative filing
schedule.
We also find that future wind and solar integration cost studies should incorporate the most
recent operational data available, including data associated with CAISO's EDAM, as such
information becomes available and sufficiently developed for analytical use. The Commission
agrees with Staff that the use of current operational data will improve the accuracy and relevance
of future wind and solar integration cost calculations.
To facilitate review of the transition to EDAM-based methodologies, we direct the
Company, in its next wind and solar integration cost filing, to provide results using both the
EDAM-based data and methodology and the historical data and methodology utilized in this
proceeding. Providing both analyses will allow Staff and the Commission to compare results,
evaluate the effects of EDAM participation on wind and solar integration costs, and maintain an
appropriate baseline for future proceedings, as the Company begins to rely more heavily on
EDAM-based data for its wind and solar integration cost filing.
ORDER NO. 37086 9

Finally,we find that continued collaboration between the Company and Staff is necessary
to address the issues identified in this case. Therefore, prior to its next wind and solar integration
cost filing, we direct the Company to meet with Staff to discuss Staff s recommendations and
concerns, the Company's planned methodology and assumptions, the incorporation of EDAM-
based data, and any questions or concerns the Company may have regarding future compliance
obligations. We believe such collaboration will help narrow issues, improve transparency, and
facilitate a more efficient review of future filings.
ORDER
IT IS HEREBY ORDERED that the wind and solar integration charges proposed by the
Company and reflected in Attachment A to Staffs Comments, are approved.
IT IS FURTHER ORDERED that the Company shall submit subsequent FRS filings within
six months of filing each future IRP.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within 21 days of the service date of this Order regarding any matter decided in
this Order.Within 7 days after any person has petitioned for reconsideration, any other person may
cross-petition for reconsideration.Idaho Code § 61-626.
ORDER NO. 37086 10

DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 1" day of
July, 2026.
G
EDWARD LODGE, PR IDENT
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J R. HAMMOND JR., COMMISSIONER
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ORDER NO. 37086 11