20251114Final_Order_No_36845.pdf

Office of the Secretary
Service Date
November 14,2025
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-25-02
OF ROCKY MOUNTAIN POWER FOR )
AUTHORITY TO IMPLEMENT CHANGES )
TO NON-LEGACY CUSTOMER ) ORDER NO. 36845
GENERATORS )
On February 7, 2025, Rocky Mountain Power, a division of PacifiCorp ("Company")
applied to the Idaho Public Utilities Commission ("Commission") requesting an order approving
the Company's proposed changes to its onsite self-generation Electric Service Schedule 136
("Schedule 136")tariff beginning October 1,2025, and approving the Company's proposed export
credit rate methodology("Application").
The Commission issued a Notice of Modified Procedure setting deadlines for public
comments and for the Company's reply comments. Order No. 36482 at 1-2. The Commission also
issued a Notice of Virtual Customer Hearing. Id. at 4. On July 30, 2025, the Company filed an
amended application with the Commission ("Amended Application"). The Amended Application
made changes to inputs used to calculate the export credit rate ("ECR") for the Company's
Schedule 136 customers. Amended Application at 2-3. Accordingly, the Commission granted
additional time to file public comments and reply comments, rescheduled the Customer Hearing,
and suspended the Company's proposed effective date. Order No. 36716 at 4-5.
Commission Staff ("Staff') filed comments. The Company filed reply comments. The
Commission also received 159 timely public comments and five late-filed public comments.
Additionally, eight Company customers testified at the September 11, 2025, customer hearing.
Based on our review of the record,the Commission now issues this Final Order approving
the Company's requests with modifications as described below.
BACKGROUND
Due to longstanding concerns about potential cost shifting from on-site customer
generators to non-participants under the structure of Schedule 135, Net Metering Service, on
August 26, 2020, the Commission issued Proposed Order No. 34752, proposing to allow the
Company to close Schedule 135 to new customers and to approve the Company's request to open
Schedule 136, Net Billing Service, as of October 1, 2020. Proposed Order No. 34752 at 8-10.
ORDER NO. 36845 1

Schedule 136 was to have no immediate changes from Schedule 135 except for a one-time $85
application fee.Id. at 10. However, Schedule 136 customers would be subject to program changes,
whereas the terms of Schedule 135 would be fixed for a period of 25 years. Id. The Commission
proposed granting grandfathered Schedule 135 customer status to metering sites for which an
application to the Company for interconnection had been made as of the date of the anticipated
order adopting Proposed Order No. 34752 and that were successfully interconnected within one
year of the service date of the adopting order. Id. at 9-10. The Commission adopted Order No.
34752 on October 2, 2020, changing only the effective date of Schedule 136 to November 1, 2020.
Order No. 34798 at 2.
The Commission also issued Order No. 34753 on August 26,2020, directing the Company
to perform a cost/benefit study of on-site customer generation. On August 8,2024,the Commission
confirmed the resulting study complied with the parameters provided in Order No. 34753. Order
No. 36286 at 6-7. The Commission ordered the Company to file a new application within six
months requesting changes to the structure and design of its proposed export credit rate for
customer generators under Schedule 136 based on the study's findings.Id. The Order also required
the Company's ECR filing to incorporate several items suggested in Staff's Comments in Case
No. PAC-E-23-17, including an analysis of the pros and cons of using a 100 kilowatt("kW")non-
residential customer cap. Id. at 6-7.
THE APPLICATION
The Company requested the Commission confirm its ECR filing complied with Order No.
36286 and approve the Company's proposed: (1) ECR for customers on Schedule 136; (2)
increased cap for non-residential customers to 2,000 kW; (3)annual updates to the proposed ECR;
and(4) revised Schedule 136 tariff. Application at 1.
The Company originally proposed to change the program to compensate customers on
Schedule 136 for all exported energy at specified prices listed in Table 1 below.
ORDER NO. 36845 2

Table 1: Export Credit Summary
Summer Summer Winter Winter
On-
Export Profile Annual Peak Off-Peak On-Peak Off-Peak
Volume (kWh per kW) 949 119 329 35 466
Capacity Contribution (%) 1 10.97% 8.69% 1.97% 0.03% 0.28%
Value by Element (cents/kWh)
Energy 2.415 4.007 3.063 2.934 1.513
- Integration (0.385) (0.638) (0.488) (0.467) (0.241)
+ Avoided Line Losses 0.184 0.304 0.233 0.223 0.115
Generation Capacity 1.488 9.408 0.770 0.121 0.078
Transmission Capacity Deferral 0.069 0.437 0.036 0.006 0.004
Transmission System Cost 0.297 1.707 0.023 1.878 0.011
Distribution Capacity Deferral 0.162 1.023 0.084 0.013 0.008
Total 4.230 16.248 3.721 4.708 1.489
(i)Annual values for information only and reflect seasonal weighting from the historical period.
Id. at 7-8. As demonstrated in Table 1, the proposed ECR varies significantly by season and time
of day according to definitions to be contained in the updated Schedule 136(Optional Time of Day
- Residential Service). Id. at 8. The Company represented that such variation would more
accurately reflect the timing value of exports than a static rate and would encourage customers to
use their own generation instead of exporting when ECR is lower than retail rates. Id. at 8-9.
Rather than discussing the pros and cons of a fixed cap on the size of individual non-
residential customer generation systems of 100 kW, as the Commission directed in Order No.
36286, the Company instead proposed increasing the cap to 2,000 kW. Id. at 9. The Company
stated that the cap would allow for administrative ease by aligning with the Company's tariffs in
Utah and Oregon. Id. The Company represented that according to its analysis using Advanced
Metering Infrastructure ("AMI") data, 99.95%of non-residential customer generators have a non-
coincident peak of less than 2,000 kW. Id. The Company did not plan to change the cap for
residential customers.Id.
According to the Company, the proposed changes were intended to correct the cross-
subsidy currently imposed on non-generating customers to the benefit of customer generators
under the existing Schedule 136. Id. The Company planned to make a filing on or about July 1,
ORDER NO. 36845 3

2026, and each following year, to revise the ECR for Schedule 136 customers as necessary, with
prices to take effect on October I of each year. Id. The Company sought to treat export credits as
a Purchased Power expense for ratemaking purposes. Id. at 7.
THE AMENDED APPLICATION
During the discovery phase of this case, the Company and Staff identified mistakes in the
Company's workpapers from which the proposed ECR was derived.Amended Application at 2-3.
Accordingly,the Company filed the Amended Application incorporating the necessary corrections,
which included classifying October as a summer month,rather than a winter month,in all instances
and rectifying time zone and hourly inconsistencies on the Company's ID Residential 136 Bill
Impact Workpaper.Id. at 2-4.
The Company represented that the corrections did not change the proposed average ECR
of 4.2 cents per kilowatt hour('kWh")but did impact the seasonal and hourly profile adjustments
as demonstrated in Tables 2 and 3 below.
Table 2: Amended Export Credit SummarN
Summer Summer Winter Winter
Export Profile Annual On-Peak Off-Peak On-Peak Off-Peak
Volume (kWh per kW) E94 136 387 18 409
Capacity Contribution (%) , 8.69% 1.97% 0.03% 0.28%
Value by Element (cents/kWh)
Energy 2.415 4.024 3.149 1.750 1.213
- Integration (0.385) (0.641) (0.502) (0.279) (0.193)
+Avoided Line Losses 0.184 0.306 0.239 0.133 0.092
Generation Capacity 1.488 8.212 0.655 0.240 0.089
Transmission Capacity Deferral 0.069 0.381 0.030 0.011 0.004
Transmission System Cost 0.297 1.490 0.020 3.716 0.013
Distribution Capacity Deferral 0.162 0.893 0.071 0.026 0.010
Total (as Amended) 4.230 11 14.666 1 3.664 1 5.597 1 1.228
(i)Annual values for information only and reflect seasonal weighting from the
historical period.
Total (Initial Application) 4.230 16.248 3.721 1 4.708 1.489
Change from Application ; L,,-:? _..�_;L�;'
ORDER NO. 36845 4

Table 3: Net Impact of Season & Hourly Profile Adjustment
As Filed
Current Proposed
Net Delivered kWh Customer 3*100thh :lionthh- Change Change
Range Count Average Bill Average Bill $ %
A: 0-500 k)X?h 610 S21.60 S59.48 S37.89 175.41-0
B: 501-1,000 kV61i 197 S72.52 S110.66 S38.15 52.61,0
C: 1.001-1,500 kWh 75 S133.68 S167.71 S34.04 25.51-0
D: 1,501-2,000 kWi 25 S186.19 S219.45 S33.25 17.9'0
E: 2,001 kWh+ 20 S298.86 S326.88 S28.02 9.4°o
Grand Total 927 $51.90 $39.19 $37.29 71.3%
Revised with Season & Hourly Profile Adjustment
Current Proposed
Net Delivered kMI Customer Monthh Xfouthh Change Change
Range Count Average Bill Average Bill $ %
A: 0-500 k)X1 610 S21.16 S56.86 $35.70 168.7%
B: 501-1,000 kWh 197 S71.03 S107.47 $36.44 51.3%
C: 1.001-1,500 kWh 75 S131.72 S164.58 S32.86 24.9%
D: 1,501-2,000 kWh 25 S184.41 S216.41 $31.99 17.4%
E: 2,001 kWh+ 20 S297.08 S324.25 $27.17 9.1%
Grand Total 927 $51.05 SM.39 S35.35 69.2%
STAFF COMMENTS
Staff reviewed the Company's Application,Amended Application, supporting workpapers,
and discovery responses. Staff Comments at 3. Staff believed the Company's ECR proposal was
generally reasonable but recommended the Commission reject certain aspects of the Company's
Amended Application and impose some additional requirements. Id. Staff recommended that the
Commission issue an order:
1. Approving the Company's proposed ECR with the addition of a rate stabilization
mechanism;
2. Requiring the Company to file annual ECR updates by July 1 st of each year;
3. Requiring the Company to file updated workpapers as publicly available exhibits;
4. Denying the Company's proposal to increase the non-residential project cap to 2,000
kW and set the non-residential project cap at 100 kW or maximum demand,whichever
is greater;
ORDER NO. 36845 5

5. Requiring 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. Requiring the Company to submit a compliance filing containing updated tariffs that
reflect the Commission's Order.
Id.
Staff explained that its suggested ECR stabilization mechanism intended to mitigate year-
to-year volatility.Id. at 8. Staff's proposal involved establishing a three-year rolling average of the
four approved Season/Peak rates for calculating ECR values.Id. at 8-9.
Staff agreed with the Company that the ECR should be updated annually with revised
calculations for its components using the most recent data. Id. at 13. However, Staff believed the
Company's representation that it would file ECR update cases"on or around"July 1 st of each year
was too non-committal. Id. at 14. Instead, Staff recommended the Commission expressly require
the Company to file its ECR update by July 1 st of each year. Id. Staff noted that in this case the
Company made public its pertinent workpapers, including hourly export data, market price data,
and inputs from relevant sources. Id. at 13. In the interest of transparency, Staff recommended the
Commission order the Company to continue to file such workpapers as publicly available exhibits
in future ECR cases.Id.
Rather than support the Company's proposed increase to the eligibility cap for non-
residential customers from 100 kW to 2,000 kW, Staff recommended the Commission approve an
eligibility cap for non-residential customers to be 100 kW or each customer's maximum demand
(defined as the customer's "greatest monthly billing demand established during the most recent
12-month period at the time of applying for interconnections"),whichever is greater.Id. at 14, 16.
Staff was concerned that the Company's proposed 2,000 kW cap could contradict the intent of the
program by allowing non-residential customers to install generation well over their own load
demand. Id. at 16. Staff noted that its analysis of the Company's AMI data revealed that 91.07%
of non-residential customers have non-coincident peaks lower than 100 kW. Id. Additionally,
according to Staff, 94% of non-residential Idaho customers have non-coincident peaks lower than
100 kW. Id. However, Staff supported the Company's proposal to leave the eligibility cap at 25
kW for residential customers.Id. at 15.
ORDER NO. 36845 6

Though Staff verified that the cost of any upgrades to an on-site generation customer's
interconnection is recovered from the customer rather than being included in the rate base, Staff
could not verify as much concerning the costs related to interconnection studies that identify
needed upgrades. Id. at 15. Therefore, to ensure costs are not unfairly passed to other customers,
Staff recommended the Commission require the Company's tariffs to expressly state that the
customer requesting on-site generation interconnection is responsible for all costs related to studies
and upgrades. Id.
Staff also addressed the items suggested in Staff's Comments in Case No. PAC-E-23-17
that Order No. 36286 required the Company's ECR filing to incorporate. Specifically, Staff agreed
with the Company's proposed methods for: (1) calculating avoided energy value; (2) calculating
integration costs for distributed solar exports; (3) determining line losses; (4) determining avoided
generation capacity value (with the clarifications that in future updates, the Company should
continue to use the annualized fixed cost of the least-cost dispatchable resource from its most
recent Integrated Resource Plan("IRP")to calculate the avoided generation capacity value, rather
than permanently using the costs of a simple cycle combustion turbine, and future updates should
draw loss of load probability data from the Company's most recent IRP); (5) valuing avoided
transmission costs; (6) valuing the deferral of transmission capacity; (7) determining there are
currently no avoided environmental costs for ratepayers; (8) real-time tracking of exported and
delivered energy (real-time netting); and (9) determining seasonal and hourly variations in the
ECR. Id. at 3-11.
Finally, Staff agreed with the Company's proposal to recover exported energy credits paid
out to self-generators as a purchased power expense and with the Company's proposed flexible
treatment of self-generators'accumulated financial credits.Id. at 17.
COMPANY REPLY COMMENTS
The Company agreed with Staff's recommendations concerning the ECR calculation, the
timing requirement for annual ECR update filings, and the use of a rate stability mechanism.
Company Reply Comments at 2.
The Company generally agreed with Staff's proposed non-residential customer project cap
of the greater of 100 kW or the customer's maximum demand. Id. at 4. However, the Company
was concerned about the lack of an upper limit on the cap.Id.According to the Company,customer
generator systems larger than 2 megawatts ("MW") should become qualifying facilities under the
ORDER NO. 36845 7

Public Utility Regulatory Policies Act of 1978, allowing such large facilities"to be integrated into
the Company's long-term resource planning while providing a regulatory framework more
appropriate for a large generation system."Id. Therefore, the Company proposed adopting a non-
residential project cap at the greater of 100 kW or the customer's peak demand(defined as the 15-
minute period of the customer's greatest use during the previous 12 months), but not to exceed 2
MW.
The Company believed Staff's recommendation to require 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 was largely unnecessary, as the Company contended the current
language of Schedule 136 makes the customer responsible for all costs related to interconnecting
their generation to the Company's system. Id. at 4-5. Nevertheless, the Company attached a new
proposed Schedule 136 to its Reply Comments, which expressly added the cost of reliability
studies as an expense for which the self-generation customer is responsible: "The Customer is
responsible for all costs associated with the Eligible Generating Plant and interconnection
facilities, including additional metering necessary for service under this schedule and the cost of
any reliability studies."Id. at 5;Attachment A to Company Reply Comments at 5.
Finally, the Company requested the Commission discontinue the annual net metering
reporting requirement imposed by Order No. 33511. According to the Company, the primary
purpose of the report—keeping the Commission apprised of any cost-shifting from on-site
generators to non-participating customers—should be satisfied in this case. Company Reply
Comments at 5.
PUBLIC COMMENTS AND CUSTOMER HEARING
The Commission received 159 timely public comments and five late-filed public
comments. Of the timely comments, 143 customers opposed the Company's proposed ECR
changes. The five late-filed comments were each critical of the proposed changes. The vast
majority of these customers were non-legacy self-generators. The comments generally expressed
frustration concerning the scope of the proposed rate changes, the cutoff date for granting
grandfathered Schedule 135 status, and the non-focus on environmental benefits realized from
incentivizing customer generation.
ORDER NO. 36845 8

Each of the eight Customer Hearing participants were opposed to the proposed ECR
changes. Their testimony reiterated many of the concerns expressed throughout the public
comments.
COMMISSION FINDINGS AND DECISION
The Commission has jurisdiction over the Company's Application and the issues in this
case under Title 61 of the Idaho Code including Idaho Code §§ 61-301 through 303. The
Commission is empowered to investigate rates, charges,rules,regulations,practices, and contracts
of all public utilities and to determine whether they are just, reasonable, preferential,
discriminatory, or in violation of any provisions of law, and to fix the same by order. Idaho Code
§§ 61-501 through 503.
The Commission has examined the comprehensive record in this matter, including all
comments submitted by the public, intervenors, and the Company. Based on its review of the
record, the Commission finds it fair, just, and reasonable to approve certain portions of the
Company's Application and Amended Application, as filed. We first confirm that the Company's
proposed changes to its on-site self-generation Schedule 136 tariff adhere to Order No. 36286. The
Commission also approves the Company's proposed ECR for customers on Schedule 136,
effective for customer billing cycles beginning on or after December 1, 2025. Additionally, we
approve of the proposed non-residential project cap of the greater of 100 kW or the customer's
peak demand (defined as the 15-minute period of the customer's greatest use during the previous
12 months) not to exceed 2 MW while maintaining a residential cap of 25 kW. Finally, the
Commission approves the language the Company included in the proposed Schedule 136 attached
to its Reply Comments, which expressly includes the cost of reliability studies as an expense for
which self-generation customers are responsible.
However, we also see fit to institute alterations to the Company's proposal. In recognition
of concerns about fluctuating ECR, the Company shall maintain the ECR at the rates set by this
Order until filing for an update on July 1, 2028. The proposed ECR in the Company's 2028 filing
shall be calculated using an average of data from the three prior years. The Company's filing shall
also include its updated workpapers from which the proposed ECR is calculated as publicly
available exhibits.
Furthermore, the Company shall submit a compliance filing with an updated tariff sheet
reflecting the conditions of this Order, and, as future ECR determinations will require the most
ORDER NO. 36845 9

accurate data available, we direct the Company to continue submitting annual reports, consistent
with Order No. 33511.
The Commission appreciates the public participation in this case. We will continue to
monitor the Company's ECR and evaluate its effects on customer generators and non-participants.
ORDER
IT IS HEREBY ORDERED that the Company's proposed ECR for customers on Schedule
136 is approved, subject to the modifications set forth in this Order, effective for customer billing
cycles beginning after December 1, 2025.
IT IS FURTHER ORDERED that the non-residential project cap shall be the greater of
100 kW or the customer's peak demand(defined as the 15-minute period of the customer's greatest
use during the previous 12 months)not to exceed 2 MW, while the residential cap shall remain 25
kW.
IT IS FURTHER ORDERED that the Company shall maintain the ECR at the rates set by
this Order until filing for an update on July 1, 2028. The proposed ECR in the Company's 2028
filing shall be calculated using an average of data from the three prior years. The Company's ECR
filing shall also include its updated workpapers from which the proposed ECR is calculated as
publicly available exhibits.
IT IS FURTHER ORDERED that the Company shall submit, as a compliance filing, a
corrected tariff sheet reflecting the updated ECR as modified by the Commission decision above
within 30 days of this Order.
IT IS FURTHER ORDERED that the Company shall continue to submit annual reports
pursuant to Order No. 33511.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one(21) days of the service date of this Order regarding any matter
decided in this Order. Within seven (7) days after any person has petitioned for reconsideration,
any other person may cross-petition for reconsideration. See Idaho Code § 61-626.
ORDER NO. 36845 10

DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 14ffi day of
November 2025.
G
Grp
EDWARD LODGE, PRE ENT
OHN R. HAMMOND JR., COMMISSIONER
DAYN HARDI , COMMISSIONER
ATTEST
La a Calderon Robles
Interim Commission Secretary
I:\Legal\ELECTRIC\PAC-E-25-02_NonLegacy\orders\PACE2502_finaljl.docx
ORDER NO. 36845 11