20260416Staff Comments.pdf

RECEIVED
April 16, 2026
KELSEA E. ROSS IDAHO PUBLIC
DEPUTY ATTORNEY GENERAL UTILITIES COMMISSION
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83702
[phone]
IDAHO BAR NO. 12050
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY'S 2025 VARIABLE ENERGY ) CASE NO. IPC-E-25-36
RESOURCE INTEGRATION STUDY AND )
PROPOSED UPDATE TO SCHEDULE 87 )
COMMENTS OF THE
COMMISSION STAFF
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission
("Commission"),by and through its attorney of record,Kelsea E. Ross,Deputy Attorney General,
submits the following comments.
BACKGROUND
On December 26, 2025, Idaho Power Company ("Company") applied to the Commission
requesting approval of the updated Schedule 87 Intermittent Generation Integration Charges with
an effective date of February 1, 2026. The updated charges were determined based on the
Company's 2025 Variable Energy Resource Integration Study ("2025 VER Study"). The
Company also requested acknowledgement from the Commission that the Company has complied
with Order No. 36661.
STAFF ANALYSIS
Staff reviewed the Company's Application and believes that the Company has complied
with Order No. 36661. Therefore, Staff recommends that the Commission acknowledge the
Company's compliance with Order No. 36661.
STAFF COMMENTS 1 APRIL 16, 2026

For the proposed changes to Schedule 87, Staff recommends that the Commission direct
the Company to file an updated Schedule 87 through a compliance filing to reflect the following:
1. An effective date based on the date of the final Commission's order in this case;
2. Wording in Schedule 87 to reflect that the tiers of integration charges are based on
qualifying facilities' ("QF") incremental nameplate capacity, instead of capacity
penetration levels; and
3. Integration charges based on a discount rate of 7.41% and an escalation rate of 2%.
Lastly, Staff recommends that the Company work with Staff to study or address the
following issues in the next variable energy resource ("VER") study:
1. Whether it is reasonable to use weighted integration charges for wind and solar QFs
that cross the 100-megawatt("MW")threshold;
2. The relationship between reserve shortfalls and capacity inadequacy in terms of their
contributions to the unreliability of a system and whether the capital and fixed
Operation and Maintenance ("O&M") costs of incremental resources should be
allocated between the purpose of meeting reserve requirements versus the purpose of
meeting load requirements;
3. The amount of over and/or under-estimation of integration costs of on-site generation;
4. If and how on-site generation could be represented through a proxy;
5. Whether forecasted QFs should be included in the Base Portfolio;
6. Whether the Reliability and Capacity Assessment Tool ("RCAT") model and the
AURORA model should be calibrated for the amount of reserves;
7. Whether there are costs associated with downward reserves that should be included in
integration charges;
8. Whether contingency reserves should be treated as integration reserves;
9. Why the cost of following reserves is not zero and what impact it has on integration
charges; and
10. Whether the calculation method for the 100-200 MW rates is reasonable.
Compliance of Order No. 36661
Order No. 36661 required the Company to file a new VER study within six months after
the filing of each Integrated Resource Plan ("IRP"). If the Company believes that a new study is
STAFF COMMENTS 2 APRIL 16, 2026

unnecessary, the Company is required to file for a waiver of the study with evidence supporting
the Company's position within two months after the filing of the IRP. Order No. 36661. The
Company filed its 2025 IRP on June 27, 2025,in Case No. IPC-E-25-23, and within the six-month
window, the Company filed a new VER study in this case on December 26, 2025.
Order No. 36661 also required the Company to work with Staff prior to the next VER study
(i.e. this current case) to resolve six issues mentioned in Staffs comments in Case No. IPC-E-25-
07. The Company has met with Staff multiple times since Order No. 36661 was issued to address
Staffs recommendations in that case. Because the Company has attempted to resolve all of the
issues mentioned in Staff s comments, Staff believes that the Company has complied with Order
No. 36661. Staff will discuss each of the issues below.
1. How to Determine Capital and Fixed O&M Costs of Incremental Resources
The Company believes that when additional variable energy resources require incremental
reserve resources for integration purposes, it is reasonable to include the capital and fixed O&M
costs of the incremental resources in integration charges. 2025 VER Study at 10. The Company
presented a methodology to calculate these costs, when reserve shortfalls exceeded a specific
threshold. Id. at 10-12.
Although a methodology was explored to capture these costs,the Company did not explain
why the capital and fixed costs of incremental resources should all be assigned as reserve costs.
Staff recommends that the Company study the relationship between reserve shortfalls and capacity
inadequacy in terms of their contributions to the unreliability of a system and whether the capital
and fixed O&M costs of incremental resources should be allocated between the purpose of meeting
reserve requirements versus the purpose of meeting load requirements.
The Company believes that it is possible for a system to not meet its load due to lack of
capacity, even though all the reserve requirements are met (such as a one in 1000 temperature
event) and that it is possible for a system to meet its load with its capacity, even though reserve
requirements are not met (such as a time when the amount of reserves may momentarily violate
reserve requirements). Company's Response to Staff Production Request No. 33 (a) and(b). On
the other hand, there is a strong correlation between meeting load requirements and meeting
reserve requirements. Id. at 33 (c). Staff believes that understanding the relationship between the
two will inform the cost allocation of the incremental resources, if allocation of these resources is
needed to ensure accurate integration charges.
STAFF COMMENTS 3 APRIL 16, 2026

2. Whether it is Reasonable to Include an Analysis of Inter-Hour Integration Costs in the Next
Study and Whether Inter-Hour Integration Costs Should Be Incorporated into the
Integration Charges
According to the Company, inter-hour integration costs should be and are already
incorporated into the integration charges in the AURORA model used in the 2025 VER Study.
Application at 5. Thus, Staff believes that this issue has been sufficiently addressed. For example,
when AURORA foresees strong wind and solar generation within its foresight window of two
days, it may determine it is optimal to shut down Bridger units. Company's Response to Staff
Production Request No. 48. However, if wind and solar output declines, Bridger units already
idled cannot be readily dispatched. Id. As a result, AURORA must dispatch higher-cost
alternative resources to meet load, even though keeping the Bridger units online would have
resulted in a lower cost. Id. The cost difference between dispatching higher-cost alternative
resources and keeping less-costly Bridger units online is recorded by the AURORA model as inter-
hour integration costs. Id.
3. Whether Regulation Reserve Requirements Should Be Updated Before the Next VER Study
(i.e., this Current Case)
The Company stated that regulation reserve requirements had been updated through the
2025 IRP before the 2025 VER Study was filed. Application at 5. Therefore, Staff believes this
issue has been fully addressed.
4. How to Reconcile Differences in Wind and Solar Integration Cost for Export Credit Rates
The Company has stated that there is no need to develop wind Export Credit Rates("ECR")
based on wind integration costs and solar ECR based on solar integration costs, because "[t]here
are effectively no wind ECR customers for which a bifurcated rate would apply." Id. Staff agrees
that solar-based ECR alone is reasonable at this point given the current situation.
S. How to Address the Under Allocation Issue for the ECR
In response to Staff s production request in Case No. IPC-E-25-07, the Company believes
that the integration costs associated with on-site generation customers are under-allocated due to
four reasons. Company's Response to Staff Production Request No. 7 (b) in Case No. IPC-E-25-
07. First, the integration costs are incurred based on generation profiles, but they are recovered
based on export profiles. Id. Second, utility-scale solar typically has axis tracking that reduces
solar variability, whereas on-site solar generation does not. Id. Third, utility-scale solar projects
typically oversize the panel-to-inverter ratio, which further reduces solar variability. Id. Fourth,
STAFF COMMENTS 4 APRIL 16, 2026

exports occur more often in high-output, low-load hours, when the need for integrating resources
is greater. Id.
While Staff agrees that there is a basis for the Company's claims, Staff believes that the
Company's method may be insufficient for determining integration charges for on-site generation
customers and may over-estimate the amount. In general, to develop integration costs of variable
energy resources, the Company needs to isolate and separate the amount of reserves needed to
buffer variability of generation from the amount of reserves needed to buffer variability of load.
The cost of the amount of reserves needed to buffer variability of load is assumed to be recovered
through customer rates. Staff believes the Company's method works well when the data for both
load and generation is kept separate, as is the case for QFs and other variable energy resources;
however, on-site generators are both net consumers as a source of load as well as net generators of
energy. Due to lack of data and the Company's methods used in the 2025 VER Study, Staff
believes that variability of both load and generation are confounded (i.e., not kept separate); thus,
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.
The Company believes that the use of the integration charges should remain consistent with
the existing ECR methodology, which was approved in Order No. 36048,unless it is changed in a
future ECR case. Application at 6. The Company also believes this area is not an element of the
integration study. Id.
While Staff agrees that the application of the integration charges should remain consistent
with the existing ECR methodology for the time being, Staff believes that integration costs of on-
site generation customers should be examined in the integration study because they are a key
element in the study design and can affect the integration charges in Schedule 87 and potentially
future ECR rates. Therefore, Staff recommends that the Company work with Staff to quantify the
amount of over and/or under-estimation of integration costs of on-site generation in the next VER
study.
6. Whether On-Site Generation Can Be Incorporated in the Analysis Through Developing a
Proxy to Overcome the Issue of Data Granularity
Since the metering equipment of on-site generation customers cannot provide data with
sufficient scope or granularity,the Company believes that the current method of the VER study is
the best option available. Application at 6. However, Staff still believes it is important to examine
whether on-site generation could be represented through a proxy to be incorporated into utility-
STAFF COMMENTS 5 APRIL 16, 2026

scale variable energy resources, when reserve requirements are applied. Currently, the Company
does not apply reserve requirements to on-site generation due to lack of visibility in the Company's
Supervisory Control and Data Acquisition ("SCADA") system and due to lack of data in the
absence of a production meter. Company's Response to Staff Production Request No. 57 (b).
Staff believes that without an estimation of reserves needed for exports from on-site generation
customers,the integration charges may not be accurate. Thus,Staff recommends that the Company
work with Staff to study if and how on-site generation could be represented through a proxy in the
next VER study.
Proposed Schedule 87
The Company proposed an updated Schedule 87 in Attachment No. 2 of the Application.
Staff reviewed the proposed schedule and recommends that wording changes, rate changes, and
an update to the effective date should be made to the schedule. Staff also recommends that the
Company work with Staff to study whether it is reasonable to apply weighted integration charges
to wind and solar QFs that cross the 100-MW threshold in Schedule 87.
1. Wording Changes
Schedule 87 displays integration charges based on the capacity penetration level of
intermittent generation. Application Attachment No. 2. Schedule 87 charges apply only to QFs,
but capacity penetration levels can be affected by non-QF resources, such as Company-owned
solar. Staff recommends that relevant wording in Schedule 87 be updated to reflect that the tiers
of integration charges are based on QFs' incremental nameplate capacity instead of capacity
penetration levels.
2. Rate Changes
The Company provided workpapers showing the calculations of its proposed Schedule 87
integration charges. Company's Response to Staff Production Request No. 2. Except for the
discount rate used in the levelization process and the escalation rate used in the escalation process,
Staff believes the charges were calculated in a reasonable manner.
The Company applied a discount rate of 6.62% to calculate levelized integration charges,
based on the weighted average cost of capital in the Company's most recent IRP acknowledged
by the Commission. Company's Response to Staff Production Request No. 2. Staff recommends
that a discount rate of 7.41% be applied to calculate levelized integration charges, based on the
STAFF COMMENTS 6 APRIL 16, 2026

rate of return approved in the Company's most recent general rate case, IPC-E-25-16.1 Using the
rate of return approved in the Company's most recent general rate case is consistent with the
method approved in Order No. 36679 in Case No. IPC-E-25-07.2
The Company applied an escalation rate of 2.4% from the 2025 IRP in the escalation
process. Company's Response to Staff Production Request No. 2 Attachment. Staff recommends
that an escalation rate of 2% from the Company's SAR Model ("SAR Model") be applied to
calculate integration charges. Staff believes that it is reasonable to use a Commission-approved
escalation rate for rate-making purposes.
3. Update of Effective Date
The Company requested a February 1, 2026, effective date for its updated Schedule 87.
Application at 10. The Commission suspended the proposed updates"for thirty(30)days and five
(5)months or until the Commission enters an order accepting,rejecting,or modifying the proposed
rate increases." Order No. 36909 at 3. Staff recommends that the effective date be based on the
date the Commission issues its final order in this case.
Finally, Staff recommends that the Company work with Staff to study whether it is
reasonable to apply weighted integration charges to wind and solar QFs that cross the 100-MW
threshold in Schedule 87. There are two sets of integration charges in Schedule 87 (i.e. rates for
0-100 MW incremental QF nameplate capacity and rates for 100-200 MW incremental QF
nameplate capacity), but the schedule does not address wind and solar QFs whose incremental
nameplate capacity crosses the 100-MW threshold. In a situation where there is already 80 MW
of QF capacity in the queue and a 30-MW QF is added to the queue, the Company will charge the
30-MW QF the100-200 MW rate for all its capacity rather than a weighted rate between the 0-100
MW rate and the 100-200 MW rate. Company's Response to Staff Production Request No. 1.
Staff believes this situation merits further consideration as a weighted rate may more accurately
and more fairly reflect the associated integration costs.
1 Order No. 36892 at 3.
2 Order No.36661 approved Schedule 87 with Staff s proposed modifications. Order No.36661 at 2. Staff s proposed
discount rate was based on the discount rate used in the Company's SAR Model. The discount rate used in the SAR
Model was based on the Commission-approved rate of return from the Company's most recent general rate case.
STAFF COMMENTS 7 APRIL 16, 2026

Additional Issues
Staff identified several additional issues in the 2025 VER Study design, which includes
forecasted QFs in the Base Portfolio, the reserves in the RCAT model, downward reserves,
contingency reserves, following reserves in the Portfolio Cost without Ancillaries scenario, and
the calculation method for 100-200 MW rates. Staff will discuss each issue in more detail below.
1. Forecasted QFs in Base Portfolio'
The Base Portfolio used in the 2025 VER Study contains forecasted QFs under new and
replacement contracts. Company's Responses to Staff Production Request Nos. 15, 16, and 47.
For new contracts, the Base Portfolio includes a forecast of new solar QFs, but it does not include
any new wind QFs. Id. at No. 47. For replacement contracts, the portfolio assumes that 75% of
the capacity of expiring wind and solar QF contracts will seek to be renewed. Id. at Nos. 15 and
16. Staff is concerned about including forecasted QFs in the Base Portfolio. Staff believes that it
will result in inaccurate integration charges for QFs because of a discrepancy between the QF
position used to determine integration charges and the actual QF position in the Company's
system. Thus, Staff recommends that the Company work with Staff to determine whether
forecasted QFs should be included in the Base Portfolio in the next VER study.
Integration charges in Schedule 87 are developed for QFs above the baseline of the Base
Portfolio (i.e. 0-100 MW above the baseline and 100 MW-200 MW above the baseline). Minute
Order for Tariff Advice No. IPC-TAE-25-02. When the Base Portfolio includes forecasted QFs,
the QF seeking integration pricing will fill in the space of the forecasted QF capacity assumed in
the Base Portfolio, causing a discrepancy between the QF position used to determine integration
charges and the actual QF position in the Company's system. For example, assuming the Base
Portfolio has 500 MW of existing QFs and 100 MW of forecasted QFs, then when a 10-MW QF
seeking integration pricing, it will fall within the 600-700 MW range under the current
methodology and be priced at the integration charges for that range. In reality, the QF actually
occupies the position of 500-510 MW, which is outside the range of 600-700 MW.
2. Reserves in RCAT Model
Currently, there is no calibration effort for the amount of reserves between the RCAT
model and the AURORA model. Company's Response to Staff Production Request No. 58 (e).
3 Other portfolios in the 2025 VER Study derive from the Base Portfolio and thus have the same issue.
STAFF COMMENTS 8 APRIL 16, 2026

Staff recommends that the Company work with Staff to study whether the two models should be
calibrated for the amount of reserves in the next VER study.
When a portfolio is created through the AURORA Long-term Capacity Expansion
functionality, the Company then uses the RCAT model to calculate the annual capacity positions
of the AURORA-produced portfolio. This ensures that the 20-year load and resource buildouts
created by the AURORA model will result in a positive capacity position sufficient to achieve the
pre-determined reliability threshold of 0.1 event-days per year Loss of Load Expectation. If the
portfolio results in a capacity shortfall,the Company will recalibrate the seasonal Planning Reserve
Margin and the Effective Load Carrying Capability curve to re-run the AURORA model for a new
portfolio. 2025 IRP at 120. The calibration process continues until both the AURORA model and
the RCAT model converge on a similar capacity position. Id. at 100. However, the Company
does not calibrate the amount of reserves between the two models. Company's Response to Staff
Production Request No. 58 (e).
The RCAT model is a capacity model that does not currently consider economics and is
not able to incorporate reserve requirements as dynamically as the AURORA model. Id. at 30.
The Company incorporates reserves in the RCAT model by holding all the system reserves
(without specifying reserve types) at the Hells Canyon Complex. Id. at 30 and 58 (b) (d).
However, the relationship between the reserves in the RCAT model and the reserves in the
AURORA model is unclear to Staff. Therefore, Staff recommends that the Company work with
Staff to determine whether the two models should be calibrated for the amount of reserves in the
next VER study.
3. Downward Reserves
For regulating reserves and ramping reserves, the 2025 VER Study only uses upward
reserve requirements, such as reg-up and ramp-up reserve requirements. The study does not
include any downward reserve requirements, such as reg-down and ramp-down reserve
requirements. The Company did not include downward reserves because curtailment provisions
in wind and solar contracts typically allow these projects to be backed down, which removes the
need for downward reserves. Company's Response to Staff Production Request No. 47 0)in Case
No. IPC-E-25-23. Staff is concerned whether there are any costs associated with the curtailment
provisions and whether these costs should be reflected in the integration charges. Staff is also
concerned whether such curtailment provisions are applicable to all types of ownership of wind
STAFF COMMENTS 9 APRIL 16, 2026

and solar projects. Therefore, Staff recommends that the Company work with Staff to address
these issues associated with downward reserve in the next VER study.
4. Contingency Reserves
The 2025 VER Study calculates the costs of integration reserves based on the costs of
regulating reserves, ramping reserves, following reserves, and contingency reserves. Company's
Response to Staff Production Request No. 14(d). Staff is concerned about whether it is reasonable
to treat contingency reserves as a type of integration reserves, because it represents the system's
ability to quickly recover from unexpected outages of a generator or transmission line. 2025 IRP
Appendix D at 17. Staff does not believe that contingency reserves are deployed to address other
system fluctuations such as load or output of variable energy resources. For example, in
PacifiCorp's Flexible Reserve Study in Case No. PAC-E-26-01, contingency reserves are not used
to integrate wind or solar resources. Rocky Mountain Power's Response to Staff Production
Request No. 11 in Case No. PAC-E-26-01. Therefore, Staff recommends that the Company work
with Staff in the next VER study to determine whether contingency reserves should be treated as
integration reserves to integrate variable energy resources.
S. Following Reserves in "Portfolio Cost without Ancillaries"Scenario
In the 2025 VER Study, the costs of integration reserves for each portfolio are calculated
based on the cost difference between two scenarios: "Portfolio Cost with Ancillaries" and
"Portfolio Cost without Ancillaries". 2025 VER Study at 14. However, in the "Portfolio Cost
without Ancillaries" scenario, all types of reserves have zero cost except for following reserves.
Company's Response to Staff Production Request No. 43. Staff recommends that the Company
work with Staff to identify the reason why the cost of following reserves is not zero and what
impact it has on integration charges.
6. Calculation Method for 100-200 MW Rates
The Company represents the 100-200 MW rates are calculated based on the reserve cost
difference between the 200-MW portfolio and the Base Portfolio divided by the incremental
energy generation associated with the 200 MW of variable energy resources. 2025 VER Study at
14. However, Staff believes that the 100-200 MW rates should have been calculated based on the
reserve cost difference between the 200-MW portfolio and the 100-MW portfolio, instead of the
Base Portfolio, and divided by the incremental energy generation associated with the 100 MW,
instead of 200 MW, of variable energy resources. For solar QFs, the Company determines the 0-
STAFF COMMENTS 10 APRIL 16, 2026

100 MW rates based on the average integration charge of $1.58/MWh for the 100 MW solar
portfolio and determines the 100-200 MW rates based on the average integration charge of
$3.29/MWh for the 200 MW solar portfolio. Company's Response to Staff Production Request
No. 2 Attachment. However, the $3.29/MWh is calculated based on the range of 0-200 MW, not
the range of 100-200 MW. 2025 VER Study at 14. Staff believes that the first half of the 200
MW (i.e. 0-100 MW) should be charged at $1.58/MWh, which is lower than the average
integration charge of$3.29/MWh, and the second half of the 200 MW (i.e. 100-200 MW) should
be higher than the average integration charge of$3.29/MWh. Therefore, Staff recommends that
the Company work with Staff to examine whether the calculation method for the 100-200 MW
rates is reasonable.
STAFF RECOMMENDATION
First, Staff recommends that the Commission acknowledge compliance of Order No.
36661. Second, Staff recommends that the Commission direct the Company to file an updated
Schedule 87 through a compliance filing to reflect the following:
1. An effective date based on the date of final Commission's order in this case;
2. Wording in Schedule 87 to reflect that the tiers of integration charges are based on QFs'
incremental nameplate capacity, instead of capacity penetration levels; and
3. Integration charges based on a discount rate of 7.41% and an escalation rate of 2%.
Lastly, Staff recommends that the Company work with Staff to address or study the
following issues in the next VER study:
1. Whether it is reasonable to use weighted integration charges for wind and solar QFs
that cross the 100-MW threshold;
2. The relationship between reserve shortfalls and capacity inadequacy in terms of their
contributions to the unreliability of a system and whether the capital and fixed O&M
costs of incremental resources should be allocated between the purpose of meeting
reserve requirements versus the purpose of meeting load requirements;
3. The amount of over and/or under-estimation of integration costs of on-site generation;
4. If and how on-site generation could be represented through a proxy;
5. Whether forecasted QFs should be included in the Base Portfolio;
STAFF COMMENTS 11 APRIL 16, 2026

6. Whether the RCAT model and the AURORA model should be calibrated for the
amount of reserves;
7. Whether there are costs associated with downward reserves that should be included in
integration charges;
8. Whether contingency reserves should be treated as integration reserves;
9. Why the cost of following reserves is not zero and what impact it has on integration
charges; and
10. Whether the calculation method for the 100-200 MW rates is reasonable.
Respectfully submitted this 16th day of April 2026.
kdvx�—
Kelsea E. Ross
Deputy Attorney General
Technical Staff. Yao Yin
Michael Ott
I:\Utility\UMISC\COMMENTS\IPC-E-25-36 Comments.docx
STAFF COMMENTS 12 APRIL 16, 2026

CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 161h DAY OF APRIL 2026, SERVED
THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE NO.
IPC-E-25-36, BY E-MAILING A COPY THEREOF TO THE FOLLOWING:
Idaho Power Company:
DONOVAN WALKER
TIMOTHY E. TATUM
RILEY MALONEY
MARY ALICE TAYLOR
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707
E-MAIL:
dwalker(k idahopower.com
dockets(a,idahopower.com
ttatum&idahopower.com
rmaloney(a),idahopower.com
mtaylor(kidahopower.com
Intervenor,Idaho Winds:
Irion Sanger
Sanger Green, PC
4031 SE Hawthorne Blvd.
Portland, OR 97214
Tele: 503-756-7533
irion&sanger-law.com
dustin(cr�,sanger-law.com
Adam Rabin
Project Engineer
Idaho Winds LLC
5420 West Wicher Rd.
Glenns Ferry, ID 83623
arkpowerworks.com
PATRICIA JORD , SECRETARY
CERTIFICATE OF SERVICE