20220304Final_Order_No_35336.pdf

ORDER NO. 35336 1
Office of the Secretary
Service Date
March 4, 2022
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF IDAHO POWER
COMPANY’S APPLICATION FOR
APPROVAL TO MODIFY ITS DEMAND
RESPONSE PROGRAMS
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CASE NO. IPC-E-21-32

ORDER NO. 35336

On October 1, 2021, Idaho Power Company (“Company”) applied to the Commission
for an order authorizing it to: (1) modify its demand response (“DR”) programs; (2) implement
associated revised tariff schedules; and (3) establish a revised cost-effectiveness method to
evaluate DR. Application at 1. The Company sought a June 15, 2022, effective date and
requested the Commission issue an order by February 15, 2022. Id. at 19.
On November 2, 2021, the Commission issued Notice of Application, and Notice of
Intervention Deadline. Order No. 35214.
The Idaho Irrigation Pumpers Association, Inc. (“IIPA”), the Industrial Customers of
Idaho Power (“ICIP”), the Idaho Conservation League (“ICL”), Micron Technology, Inc.
(“Micron”), and the city of Boise City (“Boise City”) intervened. Order Nos. 35207, 35229, and
35231.
On December 12, 2021, the Commission issued Notice of Modified Procedure setting
a public comment deadline of February 10, 2022, and a Company reply deadline of February 17,
2022. Order No. 35266. Staff, the intervenors Boise City, ICL, and IIPA, and one public
commenter, John Hafen, on behalf of the King Hill Irrigation District, filed comments to which
the Company replied.
With this Order, we approve the Company’s Application as described herein.
BACKGROUND AND APPLICATION
The Company stated it offers three DR programs “designed to meet potential peak-
hour system capacity deficits that typically occur during low-hydro generation and high-load
events on [the Company’s] system.” Application at 2. These DR programs are the residential Air
Conditioner (“A/C’) Cool Credit Program, the Commercial and Industrial Flex Peak Program
(“Flex Peak Program”), and the Irrigation Peak Rewards Program (“IPRP”). Id. at 2-3.

ORDER NO. 35336 2
The Commission previously approved suspending two of the Company’s two DR
programs and modifying the third. See Order No. 32776 (Commission approval of a settlement
suspending the A/C Cool Credit and IPRP) and Order No. 32805 (Commission approval of
changes to the Flex Peak Program). In 2013, the Commission approved a settlement (“2013
Settlement”)1 between the Company and stakeholders that contained program specific
requirements, “including marketing limitations, the method for determining cost effectiveness,
and the Term of the Stipulation . . . .” Id. at 4 (citing Order No. 32923).
After evaluating the three DR programs, the Company determined they would be
ineffective in meeting system need over the 20-year planning horizon. As such, the Company
requested Commission approval to modify the terms of the DR programs as set forth in the 2013
Settlement. In its Application, the Company seeks Commission authority to modify the DR
programs’ season by one month, shift the available event times by two hours, increase the
weekly hours DR programs are currently available, from 15 hours to 16 hours, implement
associated tariffs, and establish a revised cost-effectiveness methodology to evaluate DR. Id. at
1. The Company stated that the proposed modifications, if approved, are intended to supersede
the terms of the 2013 Settlement entirely. Id.
STAFF COMMENTS
Staff reviewed the Company’s Application and its response to discovery requests, and
believed the Company should move forward with its proposal; however, Staff recommended the
Company utilize a continuous improvement approach—reanalyzing needs and making
adjustments and improvements as needs change. Staff Comments at 2. Due to changes in the
market, customer needs, reliability, and resource mix, Staff recommended the Commission
approve the terms of the Company’s proposal and declare that the design of the proposed
programs supersede the terms of the 2013 Settlement entirely. Id. at 2-3.
Staff formed its recommendation after analyzing: (1) the method to align the design
of DR programs to the capacity needs of the system; (2) changes in the method for determining
cost-effectiveness of the programs; (3) the method for determining the amount of DR potential
that is available in the Company’s system; (4) the frequency of impact evaluations; (5) the
removal of the marketing cost cap; and (6) how the programs are managed in the future. Id. at 3.

1 In the Matter of the Continuation of Idaho Power Company’s A/C Cool Credit, Irrigation Peak Rewards,
and FlexPeak Demand Response Programs for 2014 and Beyond, Case No. IPC-E-13-14, Order No.
32923 (Nov 12, 2013).

ORDER NO. 35336 3
1. Alignment of DR Program Design to System Capacity Needs
Staff explained that the Company demonstrated that extending the season and shifting
the hours of the DR programs could improve system reliability. Staff further explained that, due
to modifications to the methods it uses to measure DR programs’ reliability relative to critical
system need, the Company discovered that the DR programs—as currently structured—are
ineffective in maintaining system reliability. For example, the Effective Load Carrying
Capability (“ELCC”) of the Company’s current DR programs—17 percent—indicates that,
during the highest-risk Loss-of-Load Probability (“LOLP”) hours, the DR programs would only
reliably provide 17 percent of DR’s maximum capacity. Id.
Staff noted that the current DR programs operate between 1:00 p.m. to 9:00 p.m. from
June 15 through August 15. Id. But, as Staff observed, given the amount of solar generation
currently available in the market and likely to be installed in the Company’s service territory, the
most critical hours are no longer at peak load, but when loads are near peak and after the sun
goes down, when solar is no longer available. Id. at 4. Staff further mentioned that, due to hotter,
drier weather extending later into summer, the Company determined that the most critical hours
have also extended later into the season. Id.
Accordingly, Staff expected the Company’s proposal to extend the DR programs’
season one month later, from August 15 to September 15 and shift the available DR hours
later—from 3:00 p.m. to 11:00—would increase the ELCC to 56 percent and provide greater
reliability to the system during the highest-risk LOLP hours. Id.
Staff recommended that the Company regularly repeat its approach of first identifying
hours of greatest system need then designing its DR programs to fit the changing resource and
environmental needs and recommended that the Company analyze the role DR programs play in
satisfying system needs in every Integrated Resource Plan (“IRP”). Id.
2. Revised Cost-Effectiveness Methodology
Staff noted that the Company made two modifications to its cost-effectiveness
methodology to ensure the benefits and the level of reliability provided by DR and by the proxy
resource were equivalent. Id. The Company first quantified the benefits provided by a simple
cycle combustion turbine (“SCCT”) beyond what DR can provide then adjusted the avoided cost
by this amount. Id. The Company then determined the amount of DR nameplate capacity needed
to provide an equivalent level of capacity contribution from an SCCT. Id. The Company stated

ORDER NO. 35336 4
that it would perform a verification step to ensure that the amount of incremental DR included in
the IRP preferred portfolio was cost effective compared to the surrogate using both adjustments.
Id.
Staff concurred with the Company’s methodology and recommended it be repeated in
subsequent IRPs.
3. Assessment of Available Demand Response
Staff noted the Company’s estimate that there are 492 megawatts (“MW”) of
traditional DR potential for the Company’s service territory. Id. at 5. While Staff believed the
Company tried to accurately estimate the DR potential for its service territory based on a
Northwest Power and Conservation Council (“NWPCC”) assessment of the entire Northwest
Region, Staff noted that the best method for obtaining accurate results would have been to
conduct a DR potential study specific to the Company’s service territory—territory distinct from
that of the entire Northwest Region. Id. at 6.
Staff noted the Company selected a third-party contractor to conduct a DR potential
study specific to the Company’s service territory. Id. Staff asserted this study should indicate the
updated participation level of the current programs by June 2022. Id. Staff believed this study
would improve the accuracy of the Company’s assumptions and calculations for the DR
programs and in the IRP. Staff recommended the Company provide the results of the DR study
and update the calculations and assumptions in its DR programs as soon as these results have
been finalized and vetted for accuracy. Id.
4. Impact Evaluations
Staff noted the Company’s representation that it will conduct internal evaluations and
report results in its annual Demand Side Management (“DSM”) report and its plan to complete a
process evaluation in 2023 and third-party impact evaluations every five years thereafter. Id. at 7.
Staff recommended the Company complete an impact evaluation as soon as sufficient program
event data is available to conduct a meaningful evaluation.
5. Marketing Cost Cap
Staff believed that removing the budget cap on marketing expenses would help the
Company meet its near-term need for capacity and increase participation in the DR programs.
Staff recommended removing the cap so long as the Company ensured program costs were

ORDER NO. 35336 5
included in the cost-effectiveness calculations and that the programs remain prudent and cost-
effective on an annual basis. Id. at 7.
6. Program Management
Staff stated that the Company’s modification to the tariff language and establishment
of a new cost-effectiveness method supersedes the terms of the 2013 Settlement. Staff expected
the Company to actively manage its DR programs and ensure the programs remain cost effective.
Staff recommended that the Company continually monitor and update items including, but not
limited to, the variable and fixed incentive values, minimum and maximum number of events,
event window, event duration, program season, the proxy resource used, DR potential, and IRP
results, to ensure the program continually improves and is cost-effective on an annual basis. Id.
Staff further recommended the Company exercise one of the minimum events (if
available) during the 2022 season, between August 15 to September 15 and during the 9:00 p.m.
to 11:00 p.m. event window. Doing this, Staff believed, would ensure the changes to the DR
programs resulted in a significant amount of DR achieved and allow the Company to effectively
evaluate participant responses to accurately measure the potential for its DR programs during
critical periods. Staff further recommended that the Company include updated information, like
DR achieved, opt outs, and realization rates, in its annual DSM report to address the DR
programs’ effectiveness at satisfying system need during critical periods.
In summary, Staff recommended the Commission: (1) authorize the Company to
modify its DR programs as described in its Application; (2) approve Tariff No. 101 for Schedule
23 (Irrigation Peak Rewards Program), Schedule 81 (Residential Air Conditioner Cycling
Program), and Schedule 82 (Flex Peak Program), as filed; (3) authorize the Company’s revised
cost-effectiveness methodology to evaluate DR as described in its Application to supersede the
2013 Settlement; (4) order the Company to analyze the fit of its DR programs relative to system
needs and perform the cost-effectiveness equivalency analysis in every IRP; (4) direct the
Company to annually evaluate each of the DR programs to update key program characteristics to
ensure the programs meet the needs of the system and remains cost-effective on an annual basis
utilizing the needs analysis and cost-effectiveness equivalency analysis from the IRP; (6) direct
the Company to exercise one of the minimum events (if available) during the 2022 season
between August 15 to September 15 and during the 9:00 p.m. to 11:00 p.m. event window; and
(7) eliminate the marketing cost caps and allow marketing costs necessary to promote

ORDER NO. 35336 6
participation so long as the costs are included in the cost-effectiveness calculations and the
programs remain cost-effective.
INTERVENOR COMMENTS
A. Boise City
Overall, Boise City recommended the Commission approve the Company’s proposed
modifications to the DR programs. Boise City specifically recommended the Company: (1)
continue to interface with all IPRP participants to best understand how to make its DR programs
attractive and easy to participate in while continuing to make the programs cost-effective and
beneficial; (2) intentionally market the A/C Cool Credit program to customers who would
receive a significant financial benefit from the program, including high-energy burden
households, multi-family housing, and customers who recently received bill payment assistance;
and (3) identify and evaluate opportunities to leverage smart thermostats installed through the
Company’s residential heating and cooling efficiency program as a future strategy to expand DR
program participation and capacity without deploying additional load control devices. Boise City
Comments at 2-3.
B. ICL
ICL recommended approval of the Company’s Application—specifically, the
Company’s shift in its ELCC methodology, the proposed changes to the DR programs, and the
lifting of marketing bans on the DR programs. ICL Comments at 9. That said, ICL requested that
the Company reassess the calculations it used for determining DR capacity over the 20-year
planning period to ensure that its models accurately reflected the full amount of solar generation
that will come online over that period. Id. ICL further requested that the Company account for all
the benefits the DR programs confer, such as the deferred costs of transmission and distribution
lines, lower customer bills, and positive environmental impacts. Id. Finally, ICL requested that
the Company plan for a “robust suite of demand response programs” and market them to benefit
a “wide array of customers, including low income customers . . . .” Id.
C. IIPA
IIPA ultimately supported the Company’s Application to modify its existing DR
programs. However, IIPA noted that the proposed modifications would increase the burden of
the program on IPRP participants by: (1) shifting the time of curtailment later into the night; (2)
increasing the weekly limit to curtailed hours; (3) extending the season of curtailments; and (4)

ORDER NO. 35336 7
removing the variable incentive payment for the fourth curtailment of the season. IIPA
Comments at 1. Nonetheless, IIPA agreed that this burden appeared to be appropriately offset by
increased incentive payments and was warranted given the evolving nature of the Company’s
system demand needs. Id.
According to IIPA, the most significant change to the DR programs is the shift in the
time of curtailments. Id. at 2. IIPA asserted that many current IPRP participants face technical
and labor challenges associated with late day curtailments due to issues associated with restarting
their irrigation systems. Id. IIPA stated that it discussed these difficulties with the Company and
understood the Company’s intent to proactively minimize the negative impacts these late day
curtailments have on customers. Id. All in all, while it believed the modifications to the program
may cause some reduced participation from IPRP participants, IIPA stated its expectation that
the modified DR programs will continue to have material participation rates from existing
participants. Id. Accordingly, IIPA recommended the Commission approve the Company’s
Application as filed.
PUBLIC COMMENT
John Hafen (“Mr. Hafen”), on behalf of the King Hill Irrigation District (“King
Hill”), commented that the Company’s proposed modifications to the DR programs would be
deleterious to the irrigators in King Hill. Mr. Hafen expressed concern that having more than one
event a week would reduce the water available for valuable crops and therefore recommended
that the maximum events per week needs to be one rather than four and that the total number of
events over the duration of the DR programs’ season needed to be 13 rather than 15.
Mr. Hafen stated that King Hill would ideally prefer a total of six events over the
season due to the reality that after four events the costs to turn pumps off and on after four hours,
and employ people to watch water fill a canal, “is equal to the lower Peak Rewards pay out and
does not cover the opportunity cost of not shutting off and participating . . . .” Mr. Hafen further
explained that interrupting the King Hill irrigators’ system whereby water is pumped up from the
river in a 48-hour long process more than once a week would economically harm King Hill
irrigators.
COMPANY REPLY COMMENTS
The Company appreciated the comments of the Intervenors and Staff supporting
approval of its Application to modify its DR programs and agreed with Staff’s recommendation

ORDER NO. 35336 8
to use a “‘continuous improvement approach’ in evaluating how DR programs can cost-
effectively meet future system needs.” Company Reply at 1-2. In response to ICL’s comment that
it reassess how it estimated the total available amount of DR capacity, the Company clarified that
its conclusion that the DR programs could be relied on to provide approximately 300 MW of
load reduction during summer peak load periods was not a cap but “rather an estimate of
achievable load reduction from these existing programs that can be relied upon for planning
purposes.” Id. at 2. The Company further clarified that it would continue to assess the potential
for expanded DR resources “that, if identified as cost-effective and achievable, would be
presented for Commission approval as part of a future separate proceeding.” Id. at 2-3.
The Company explained that, based on customer surveys, it expected to see an initial
decrease in participation in the DR programs. Thus, the Company believed that 300 MW—rather
than the currently enrolled nameplate capacity of 380 MW—was a more reliable estimate for
planning purposes. Id. at 3. The Company further clarified that the 584 MW of DR potential was
a number compiled by NWPCC and did not reflect capacity that is actually “valuable and cost
effective[,]” but rather a technical potential that the Company used to establish an ELCC “that
could be used to help set a cost-effectiveness threshold for programs [and] as a modeling
constraint in the IRP analysis.” Id. at 4.
In response to ICL’s comment that the Company didn’t plan to expand DR capacity
sufficiently now or in future planning periods, the Company explained that it assessed expanding
the current program by an additional 280 MW of DR but determined that “DR’s operating
characteristics didn’t align with the need, there was a less costly resource available, or a
combination of those factors.” Id.
The Company clarified that it planned to complete a specific DR potential study by
fall 2022, per Staff’s recommendation, which it “commits to reviewing with interested parties
and the Company’s Energy Efficiency Advisory Group (“EEAG”) prior to recommending any
new or modified programs.” Id. at 5. The Company also stated this study will be included in the
Company’s following DSM report as well as in its 2023 IRP, providing an opportunity for the
Commission Staff, the Commission and other interested parties to review it. Id. The Company
stated that the above approach—rather than the approach of implementing new DR programs and
expanding its DR portfolio in the current proceeding, as ICL suggested—was the most

ORDER NO. 35336 9
appropriate way for it to expand its current DR portfolio and potentially develop new DR
programs. Id. at 4-5.
The Company stated that it considered the effect its program had on IPRP customers
and that it would work to decrease barriers to customer participation as well as balancing the
need to minimize curtailments and customer impact with the necessity to ensure the program
meets system needs. Id. at 5-6.
The Company agreed that Staff’s recommendation to conduct one of the minimum
events between August 15 to September 15 during 9:00 p.m. to 11:00 p.m. would provide the
Company valuable insight and stated that it will “endeavor to run an event in the stated window
if one of the three minimum events is available . . . .” Id. at 6.
In summary, the “Company agree[d] with Staff’s comments and recommendations on
the revised cost-effectiveness methodology and will repeat the analyses in future IRPs . . . . and
conduct an impact evaluation as soon as sufficient program event data is available to conduct a
meaningful evaluation for the DR program.” Id. at 7. The Company further “commit[ed] to
utilizing the DSM annual report and its annual prudence request to present the cost-effectiveness
results and impact evaluation recommendations” and marketing the DR programs to all qualified
customers. Id.
FINDINGS AND DISCUSSION
The Company is an electric utility subject to the Commission’s regulation 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, -502, and -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.
Pursuant to this authority, we have reviewed the record, including the Company’s
Application, the Parties’ comments, the public comment, and the Company’s reply comments.
Based on that review, we find the Company’s proposed modifications to its DR programs fair,
reasonable, and in the public interest.
We further find it reasonable to have the Company annually evaluate each DR

ORDER NO. 35336 10
program for need and cost-effectiveness using the needs analysis and cost-effectiveness analysis
from the IRP. It is reasonable that the Company analyze the fit of its DR programs relative to
system need and perform the cost-effectiveness equivalency analysis in every IRP. We also find
it reasonable for the Company to exercise one of the minimum events during the 2022 season
between August 15 to September 15 (if available) and during the 9:00 p.m. to 11:00 p.m. event
window.
We acknowledge the Intervenor comments and recommendations and direct the
Company to continue exploring the DR program opportunities and implementation
recommendations. The ongoing evaluation results should be reviewed with the EEAG and
interested parties.
We therefore approve the Company’s Application as filed and direct the Company to
implement the modifications to its DR programs as described in the Application and consistent
with Staff’s recommendations. We further find that the modifications to the terms of the DR
programs supersede the terms of the 2013 Settlement entirely.
O R D E R
IT IS HEREBY ORDERED that the Company’s proposed modifications to its DR
programs—the residential Air Conditioner Cool Credit Program, the Commercial and Industrial
Flex Peak Program, and the Irrigation Peak Rewards Program—are reasonable and approved,
effective June 15, 2022.
IT IS FURTHER ORDERED that the Company implement associated tariffs,
consistent with Staff’s recommendations and the Company’s reply comments.
IT IS FURTHER ORDERED that the modifications to the terms of the DR programs
supersede the terms of the 2013 Settlement approved by Commission Order No. 32923 entirely.
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. 35336 11
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 4th day
of March 2022.

ERIC ANDERSON, PRESIDENT

JOHN CHATBURN, COMMISSIONER

JOHN R. HAMMOND JR., COMMISSIONER

ATTEST:

Jan Noriyuki
Commission Secretary

I:\Legal\ELECTRIC\IPC-E-21-32 Demand Response\orders\IPC2132_finalorder_rn.doc