20230331Final_Order_No_35724.pdf

ORDER NO. 35724 1
Office of the Secretary
Service Date
March 31, 2023
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF ROCKY MOUNTAIN
POWER’S APPLICATION FOR
AUTHORITY TO IMPLEMENT A
COMMERCIAL AND INDUSTRIAL
DEMAND RESPONSE PROGRAM
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CASE NO. PAC-E-22-13

ORDER NO. 35724

On August 25, 2022, PacifiCorp dba Rocky Mountain Power (“Company”) applied for
authority to start a “Class 1 commercial and industrial demand response program (“Wattsmart
Business Demand Response” or “Program”) under the existing Schedule 114 load management
tariff within the demand side management (“DSM”) portfolio” to be effective January 1, 2023.
Application at 1.
On October 20, 2022, the Commission issued a Notice of Application, set an intervention
deadline, and suspended the proposed effective date until February 15, 2023. Order No. 35568 at
4. P4 Production, L.L.C., an affiliate of Bayer Corporation (“Bayer”), and the Idaho Irrigation
Pumpers Association, Inc. (“IIPA”) intervened. See Order No. 35598.
On December 8, 2022, the Commission issued a Notice of Modified Procedure establishing
public comment and Company reply deadlines. Order No. 35616.
At the Commission’s January 3, 2023, Decision Meeting, the Commission Staff (“Staff”)
conveyed to the Commission that, through discovery, the Company provided Staff new data—
specific to Idaho—which took Staff additional time to process. To give Staff adequate time to
review the Idaho-specific data, work with the Company to determine the relevant information
necessary, and make its subsequent recommendation, Staff recommended the Commission (1)
vacate the comment deadlines established in Order No. 35616 and issue new comment deadlines;
and (2) modify the suspension of proposed effective date.
On January 11, 2023, the Commission issued Order No. 35662 amending the comment
deadlines and extended the effective date to April 1, 2023.
Staff, Bayer, and IIPA filed comments to which the Company responded (collectively the
foregoing are referred to herein as the “Parties”). No other comments were received.
Having reviewed the record in this case, the Commission now issues this final Order
approving the implementation of the proposed Program with certain modifications, as discussed
below.
ORDER NO. 35724 2
THE APPLICATION
The Company represented its Schedule 114 – Load Management, was approved in Case
No. PAC-E-21-16 for implementation of load management programs. Application at 2. The
Company stated the Wattsmart Battery program was the only demand response program currently
approved under Schedule 114. The Company seeks to add the Wattsmart Business Demand
Response Program to Schedule 114. The Program is designed to provide “financial incentives to
customers who curtail load during Company initiated events.” Id. at 2. The Company stated that it
may utilize the Program “to provide peak load reduction, contingency reserves, frequency
response, and other grid services to assist with effectively managing the overall electric grid.” Id.
The Company represented:
The initial Program design will work with large commercial and industrial
customers who are served by the Company in the state of Idaho taking service under
the Company’s electric service schedules listed on Schedule 191 - Customer
Efficiency Services Rate Adjustment, with curtailable loads greater than 500 kW
that can be curtailed with no advance notice or limited advance notice (7-minutes).
Id.
The Company proposed that its Program will offer rates based upon whether the
curtailment is considered a “real-time event” or an “advanced notice event.” Id. The Company
differentiated these two different curtailment events by stating that “[a]n automated dispatch
without advanced notice and a total response time within 50 seconds is considered a real-time
event, and a dispatch event with an advanced notice and response within 7 minutes is considered
an advanced notice event.” Id. The Company stated that, if this proposal is approved, its
representatives will meet with large commercial and industrial customers and discuss site-specific
options for participation. Qualifying customers will have the option to participate in the real-time
program, the advanced notice program, or both programs.
Exhibits A and B of the Application proposed changes incorporating the Program to the
Schedule 114 and the proposed tariff. The Company stated that such changes, if approved, would
still accommodate the parameters set forth in Case No. PAC-E-21-16, and that the Program would
still be managed pursuant to the flexible tariff process.
The Company also provided its cost-effective analysis data in its Application. Id. at 7. The
Company asserted that the Program is expected to be cost effective. Id.

ORDER NO. 35724 3
COMMENTS
a. Staff’s Comments
Staff believed the Program should be cost-effective if the Company’s assumptions and
estimates were accurate. Staff recommended the Commission authorize implementation of the
Program; however, Staff was concerned that certain factors could impede the Program from being
maximally cost-effective. Staff believed that consideration of various issues (addressed below),
followed by continued monitoring, would be necessary to ensure the Program would be and remain
cost-effective.
Staff noted Demand Response (“DR”) programs are often less costly than traditional means
of meeting a system’s load and reliability requirements. “During called DR events, the proposed
Idaho . . . program would offset the need for local system demand and energy by way of load
reduction, which in turn reduces the need for energy deliveries into Idaho from other locations on
the system.” Staff Comments at 3. Staff noted that this “offsets the need for other [of PacifiCorp’s
East] resources to be held as operating reserves for its balancing area.” Id.
Staff noted that the Program could be less cost-effective than anticipated, or even cost
ineffective, if the incentives offered to the participants are above the value of the avoided cost.
Additionally, while Staff believed that the Program would be cost-effective under current
circumstances, Staff noted the Company’s planned implementation of large-scale utility batteries
should cause a reduction in the avoided cost once installed. Thus, while this Program should be
cost-effective now, it may be comparatively less cost-effective going forward. Therefore, Staff
recommended the Company be required to use the most current Integrated Resource Plan (“IRP”)
forecast data to periodically adjust incentive levels.
The Program would provide value to the Company through called events; however, the
Program’s greater cumulative value could be as a regulated reserve according to Staff. The
Company estimated that 27.5% of the Program’s value will be gained through implementation of
called events. However, the Company estimated that 72.5% of the value of the Program would
arise from the remaining hours in the year where the Program has the potential to operate as a
reserve. Thus, while less valuable per hour, the Company estimated that the sheer number of hours
where the Program can operate as a reserve is more valuable than the value added by called events.
Staff argued “the Company should limit the Maximum Incentive amount to a value
supported by the 5-year levelized avoided cost.” Id. at 5. To ensure cost-effective participation,
ORDER NO. 35724 4
Staff recommended the Company “(1) maintain an incentive amount necessary to retain continued
participation in the program over the long term; (2) offer an incentive amount adequate to
encourage new participants into the program; and (3) limit the incentive amount to a level that
keeps the program cost-effective as avoided cost fluctuate.” Id. Staff was concerned that the
Company’s “maximum incentives and initial offerings are the same amounts contained in the
existing Utah program and are not updated using Idaho specific values.” Id. at 6. The Company’s
Idaho specific five-year levelized avoided cost value is less than the proposed maximum and initial
incentive. Staff was concerned the methods the Company used to reach its proposed maximum
and initial incentives were not well supported, did not encourage a cost-effective Program, and
would not provide stable incentives to customers.
Relatedly, Staff noted that some qualifying participants would be willing to engage in the
Program at a lower incentive than others. Accordingly, Staff agreed with the Company that it was
important to offer an incentive up to the maximum—allowing for participants who are willing to
take a lower incentive to do so. Staff stated that “[b]y using avoided costs as a maximum incentive
‘up to’ limit for individual participants, the program should remain cost-effective at a program
level.” Id. at 7.
Staff noted the Company provided analysis regarding its proposed maximum incentive.
Staff reviewed of the Company’s analysis and believed the Company’s method would encourage
participation—but might also run a significant risk of overcompensating customers if a customer
realizes a higher capacity factor (proportion of the participant’s capacity that is curtailable) and
created a basis for a program that may not be cost-effective.
Staff noted that when calculating the cost-effectiveness of the Program using a maximum
incentive up to a five-year levelized avoided cost, the calculation “considers individual customer
capacity factors, varying incentive offerings by participant, and all non-incentive expenses. When
customers are signed up on a lower initial incentive or have lower capacity factors for a given year,
this would ensure the program remains cost-effective.” Id.
As the Company’s avoided costs decrease because resource mix changes, cost-effective
maximum incentives for the Program may need to decrease as well. To avoid unnecessary
dissatisfaction and discontinuation among participants, Staff believed the Company should set
“initial incentive offerings to customers that will provide stability in their incentive rate over
multiple years as the Company’s avoided cost declines. . . the Company should be able to explain
ORDER NO. 35724 5
how the incentives will promote required participation while balancing the risk of future reductions
in incentive rates.” Id.
Staff believed the Commission should grant the Company’s request for a flexible tariff, but
the tariff should only be adjusted annually. Staff believed annual adjustments will be frequent
enough to ensure that the incentive remains cost-effective and up to date while not being so
frequent to be considered unstable or unpredictable by participants—potentially discouraging
participation.
Staff also recommended the Company submit a compliance filing with an updated Exhibit
B for the following reasons:
During its analysis, Staff discovered different dispatch parameters in Table 6 of the
Application and in the proposed tariff shown in Exhibit B. . . the Company clarified
that the parameters shown in Exhibit B are the combined parameters of the Real-
Time and Advanced Notice options. . . Staff believes it is inappropriate to combine
the dispatch parameters of the Real-Time and Advanced Notice options in the
proposed tariff [as they are intended for different functions].
Id. at 8-9.
Staff also recommended the Company “identify the value of frequency response in their annual
DSM reports, IRP processes, and offer an appropriate incentive once a value has been identified
and vetted by Staff.” Id. at 9.
Staff was encouraged by the possibilities of the Program and recommended various reports
to allow the Commission to adequately monitor the Program. “In addition to all reporting items
required in an annual report, the Wattsmart Business [Commercial and Industrial Demand
Response] program section should include . . . performance metrics separated by the Real-Time
and Advanced Notice dispatch options.”1

1 (1) For each program event called during the year:
a. the date, time, duration, and reason for the called event (i.e. frequency response, peak load reduction, contingent
reserve, regulation reserve, or due to the economics);
b. the hourly aggregate amount of DR called, and separately each participant’s called amount;
c. both the hourly aggregate and individual participant amounts of DR received during the event;
d. the program’s designated hourly capacity factor both in aggregate and by individual participant;
e. both the hourly aggregate and individual participant amounts of DR received during the called event;
f. the value of energy for each hour during the event;
g. the hourly value of capacity for each hour during the event;
h. separately the value of reserve types for each hour during events;
i. the value of spinning reserve offset by load reduction for each hour of the event;
j. details of any participant opt outs;
(2) For all other hours outside of called events during the year:
a. the dates, and times when the Company used incremental contingent reserves or regulation from the program to
provide benefit to the system;
ORDER NO. 35724 6
b. Company’s Reply to Staff’s Comments
The Company indicated it was generally willing to follow Staff’s recommendations—some
of which were incorporated in Exhibit A of the Company’s reply. The Company condensed Staff’s
Comments and recommendations into the following points:

a. Limit the maximum incentive at the levelized 5-year avoided cost.
b. Regularly update the levelized 5-year avoided cost for determining the
maximum incentive.
c. Adjust the maximum incentive within the Flexible Tariff on an annual basis.
d. Set the offered incentive levels at amounts that will retain participation over
time, encourage new participants, and maintain cost effectiveness.
e. Update the Flexible Tariff with the dispatch parameters of the Program
separated by real-time and advance notice options.
f. Include various Program metrics and details in DSM annual reporting and
prudency filings.

Company’s Reply Comments at 4.
The Company agreed that limiting “the maximum incentive at or below the levelized 5-
year avoided cost” was acceptable. Id. The Company stated that a maximum incentive of $135/kW,
rather than $190/kW, was acceptable for both real-time and advanced notice participants. The
Company also stated it previously suggested a maximum of $125/kW for participants in those
programs.
The Company “agrees to regularly update the levelized 5-year avoided cost in tandem with
new [IRP] publications, and make annual adjustments to the maximum incentive levels, if
necessary.” Id. at 5.
The Company believed its proposed incentive levels were set appropriately to retain
participation. However, the Company agreed that it would seek to encourage participation with the
reduced maximum incentive suggested by Staff. The Company noted that is difficult to estimate
how much participation will be gained over the course of years for this new Program. Accordingly,
the Company stated that it will monitor the Program participation and coordinate with Staff

b. individually the value of contingent and regulation reserves for each hour the program provided benefit to the
system;
c. the hourly value to the system where a resource held in reserve was subsequently allowed to provide generation
into the market due to the programs ability to provide contingent reserves;
(3) All other trackable metrics relevant to supporting the programs performance and cost-effectiveness.
Staff Comments at 10-11.
ORDER NO. 35724 7
through the 45-day notice process if incentives need to be adjusted. The Company anticipated that
the Program and its preferred incentive structure would grow more predictable and stable over
time.
The Company updated the Flexible Tariff in Exhibit A. The Company noted this update
now has the maximum incentive level consistent with Staff’s recommendations. The Company
also noted that it updated separate “dispatch parameters by real-time and advance notice options.”
Id.
The Company stated it already includes its “DSM programs in its annual reporting and
prudence filings and will continue to do so” if the Program is approved. Id. However, the Company
argued that Staff’s other proposed reporting metrics are voluminous and impracticable and would
unduly burden the Company. The Company indicated that, when certain metrics are unfeasible to
provide as Staff requested, the requisite information necessary should be communicated to Staff
at regularly scheduled meetings.
c. Bayer’s Comments
Bayer did not oppose the Company’s proposed Program. Bayer sought clarity on “how
load aggregation would be effective considering the coordinated response time needed for different
load locations” and recommended the Commission require the Company provide additional
information on how the Program works with load reduction from several aggregated locations.
Additionally, Bayer recommended that Schedule No. 191 be closely monitored if adjusted. If the
Program is expanded as requested by the Company, Bayer requested that this expansion factor in
the economic and operating value of existing participants and current contracts where applicable.
d. Company’s Reply to Bayer’s Comments
In response to Bayer’s request for clarity, the Company stated that it does not matter
whether a participant participated in a real-time event or advance notice event or whether they
were participating from a single location or multiple locations in the aggregate because the
Company elaborated that the proposed incentive would only be offered based on what each
participant actually and successfully curtailed. Thus, if a participant only partially complied, or
failed to comply, with the Program the participant’s incentive would be appropriately and
automatically reduced based upon the existing structure of the proposed Program.

ORDER NO. 35724 8
e. IIPA’s Comments
IIPA “is concerned that the incentive and curtailment parameters are not clearly specified
[and] the cost responsibility for enabling equipment is not specified.” IIPA Comments at 1-2. IIPA
was concerned with the Company having sole discretion to change incentives without triggering
an update; IIPA suggested that the Company include cost effectiveness tests in its annual reports.
IIPA noted that it may alter its position with the availability of additional information.
f. Company’s Reply to IIPA’s Comments
The Company addressed IIPA’s “concerns regarding tariff updates, cost effectiveness, and
[requested clarity regarding who is responsible for] equipment installation and maintenance costs.”
Company Reply Comments at 2. The Company stated it did not have sole control regarding tariff
changes and “[a]ny changes to the Flexible Tariff would require approval” through existing and
established programs. Id. at 2-3. Regarding cost effectiveness, the Company stated the results for
cost effectiveness are already included in its annual reports. Regarding the cost of installation and
maintenance of equipment, the Company clarified that the participants will not be responsible for
these costs—as they are already incorporated into the Program—and that further details are
available in Table 4 of the Application.
COMMISSION DISCUSSION AND FINDINGS
The Company is an electric utility subject to the Commission’s regulatory authority under
the Public Utilities Law. Idaho Code §§ 61-119 and 61-129. The Company’s rates, charges,
classifications, and contracts for electric service in the State of Idaho are subject to the
Commission’s jurisdiction. The Commission has jurisdiction over this matter under Idaho Code
§§ 61-501, 61-502, and 61-503. The Commission is empowered to investigate rates, charges, rules,
regulations, practices, and contracts of public utilities and to determine whether they are just,
reasonable, preferential, discriminatory, or in violation of any provision of law, and to fix the same
by order. Idaho Code §§ 61-502 and 61-503.
We have reviewed the record, including the Company’s Application and all comments
submitted. Based on our review, we find the Company’s proposal to implement the Program is fair
and reasonable. Accordingly, we approve the Company’s Application for the proposed Program
with certain modifications. The Commission agrees with Staff that the Program needs to
incorporate Idaho specific data to best ensure it is offered in a cost-effective manner. The
ORDER NO. 35724 9
Commission appreciates the Company making this and other related adjustments in its reply
comments.
The Commission appreciates the Company’s willingness to regularly update the maximum
incentive levels based on its five-year levelized avoided costs using the Company’s most recent
filed IRP. To further ensure that the Program remains cost-effective, the Company shall submit
updates to the Program in its annual reports. Requests for a prudency determination for recovery
of Program expenses shall be part of the Company’s DSM prudency filing. The Commission
believes this, in tandem with allowing the Company to annually update the incentives offered
through its flexible tariff, will ensure that the Program remains both cost-effective and attractive
to participants.
The appropriate maximum incentive level for either real-time or advanced notice Program
offerings should be based on the Company’s most recent levelized five-year avoided costs, which
will be regularly updated based on the most recent IRP. We note this is the maximum amount and
the amount offered to various participants should be based on the value their individual real-time
or advanced notice DR resource(s) bring to the Company’s system. We understand each participant
is uniquely situated and will offer a different value, either based on the amount available or ability
to respond timely to the system and believe this may justify offering different participants different
incentive levels.
We agree the Company should update the incentive level offered on an annual basis to
maximize the Program’s value while maintaining appropriate expenditures. Adjusting the
incentive levels annually will ensure participants are being compensated at appropriate levels,
which means participants will be paid for the actual value of their DR product while also
maintaining appropriate levels of participation. When adjusting the incentive offerings, we direct
the Company to consider setting the initial incentive in a manner that ensures the Program can (1)
maintain continued participation; (2) encourage additional participation; and (3) remain cost-
effective. For special contracts, the Company should consider cost-effectiveness in relation to the
existing participants’ contracts.
We direct the Company to submit reporting metrics and updates to the Program, as
requested by Staff, in its annual reports. Although the Company disagreed with Staff’s
recommendation for reporting metrics, we agree with Staff that these are necessary to ensure the
Program’s costs and benefits and methods used for calculating incentive levels are being applied
ORDER NO. 35724 10
in a cost-effective manner and to protect other customers. Additionally, the Company is directed
to submit any updates to the Program with its annual reports. The Company should request
recovery of prudently incurred expenses incurred to fund the Program in its DSM prudency filing.
Finally, the Company is directed to file a compliance filing to include updates to the
incentives offered, Program equipment costs, and dispatch parameters in Schedule 114 and the
flexible tariff. Additionally, any materials promoting the Program must indicate the equipment
costs required for participation in the Program will be paid for by the Company in addition to being
listed on the Company’s website.
ORDER
IT IS HEREBY ORDERED the Commission approves the implementation of the proposed
Program, as described in this Order, effective April 1, 2023.
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. Idaho Code § 61-626.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 31st day of
March 2023.

__________________________________________
ERIC ANDERSON, PRESIDENT

__________________________________________
JOHN R. HAMMOND JR., COMMISSIONER

__________________________________________
EDWARD LODGE, COMMISSIONER
ATTEST:

Jan Noriyuki
Commission Secretary

I:\Legal\ELECTRIC\PAC-E-22-13 Bus Demand Resp\orders\PACE2213_Final_md.docx