20220210Comments.pdf

RILEY NEWTON
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
(208) 334-03r8
IDAHO BAR NO. TI2O2
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Street Address for Express Mail:
I I33I W CHINDEN BLVD, BLDG 8, SUITE 2OI-A
BOISE, TD 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION FOR
APPROVAL TO MODIFY ITS DEMAND
RESPONSE PROGRAMS
CASE NO. IPC.8.21.32
COMMENTS OF THE
COMMISSION STAFF
STAFF OF the Idaho Public Utilities Commission, by and through its Attorney of
record, Riley Newton, Deputy Attorney General, submits the following comments.
BACKGROUND
On October l,2|2l,Idaho Power Company ("Company") applied to the Commission for
an order authorizing the Company to: (l) modi$ its demand response ("DR") programs; (2)
implement associated revised tariff schedules; and (3) establish a revised cost-effectiveness
method to evaluate its DR portfolio. The Company requested the Commission issue an order by
February 15,2022, to implement changes to the DR programs, which begin on June 15,2022.
On December 21,2021, the Commission provided notice of Modified Procedure, and set
a February 10,2022, public comment deadline and a February 17 ,2022, Company reply
deadline. Order No. 35266
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1STAFF COMMENTS FEBRUARY IO,2O22
The intent of the Company's DR programs is to minimize or delay the need to build a
new supply-side resource to meet potential peak-hour system capacity deficits. While the
potential deficits are expected to be significant, the Company believes they will be short in
duration. Thus, the Company believes it may be cost-effective to utilize DR programs rather than
building a new capacity supply-side resource that may only be required to operate for short
periods of time. The Company indicates the DR maximum load reduction in the current
programs represents l0 percent of the Company's system peak load.
The Company's DR portfolio uses three individual programs:
l. Residential Air Conditioner Cool Credit Program (Schedule 8l);
2. Commercial & Industrial Flex Peak Program (Schedule 82); and
3. Irrigation Peak Rewards Program (Schedule 23).
Each program focuses on a specific customer group. Participants are paid a fixed
incentive, and depending on the program, ffioy be paid an additional variable incentive amount
for the reduction in load during a DR called event.
The Company proposes to modifu the DR programs by extending the program season by
one month, from August 15 to September 15, and shifting the available DR event times by two
hours later in the evening to improve system reliability during the highest-risk hours.l These
changes, in addition to revisions to the DR programs' fixed and variable incentives, would be
updated in each of the respective program tariffs. The Company also proposes to revise the cost-
effectiveness methodology used as a benchmark in evaluating the economic benefit of the DR
programs.
STAFF ANALYSIS
After reviewing the Company's Application and its response to discovery requests, Staff
ultimately believes the Company should move forward with its proposal; however, Staff
recommends the Company utilize a continuous improvement approach,reanalyzing needs and
making adjustments and improvements as needs change. As electricity markets, the Company's
resource mix, and customer needs change, the risk to system reliability increases and the need for
modifications to the Company's DR programs becomes necessary. Given the near-term need to
increase dispatchable capacity, as opposed to a lack of needin2013, and a better understanding
I The Residential Air Conditioner Cool Credit program can be called during all hours of the day
2STAFF COMMENTS FEBRUARY IO,2O22
of the benefit of DR to system reliability, the terms of the 2013 Settlement Agreement approved
by the Commission in Order No. 32923 are no longer relevant. Staff recommends 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 Agreement entirely.
Staffls analysis as summarized in the following sections includes a review of: (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.
Alignment of DR Program Design to System Capacitv Needs
The Company has shown the need to improve system reliability by extending the DR
programs' season and shifting the hours later in the evening. During the development of the
Company's 2021Integrated Resource Plan ("IlU"';, the Company made major modifications to
the methods it uses to determines the load carrying capability of its resources and measure the
reliability of its system. Relevant to DR, the Company now has the capability to measure the
Loss-Of-Load Probability ("LOLP") for each hour over the IRP planning horizon, which allows
the Company to determine the critical hours that the system needs DR in order to operate. The
Company has also developed a method to determine the Effective Load Carrying Capability
("ELCC") of different DR program designs relative to the hours of most critical need. Through
these new capabilities, the Company has shown that the existing DR programs as currently
structured are no longer as effective in maintaining system reliability. Under current program
parameters, the ELCC of the Company's current DR program is only 17 yo, indicating that
during the highest-risk LOLP hours, the DR program would only reliably provide 17 0/o of DR's
maximum capacity.
The reason for the low ELCC is primarily due to the hours of the day and the length of
the season that the program currently operates, which doesn't align with the most critical hours
with the highest LOLP. The current programs operate between 1:00 pm and 9:00 pm and from
June 15 through August 15.
JSTAFF COMMENTS FEBRUARY IO,2O22
However, given the amount of solar generation already 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 rather when loads are near their peak and after the sun goes down, when solar is no
longer available. Additionally, the Company has found that the most critical hours have also
extended later into the season, primarily due to hotter, drier weather extending later into the
summer months.
To address these issues, the Company proposes to extend the DR programs' season from
August l5 to September 15 and shift the available DR hours later into the evening, to a 3:00 p.m.
to I l:00 p.m. range. By modiffing the DR programs in this way, the ELCC increases to 56 Yo,
providing greater reliability to the system during the highest-risk LOLP hours.
The Company's approach first identifies the hours of greatest system need for capacity
and then designs the DR programs to fit those needs, which Staff believes is a major
improvement. The Company operates in a dynamic environment. As the environment and
system needs change, the resources to supply those needs also need to change, thus Staffbelieves
this approach should be regularly repeated. Staff recommends that the Company reanalyze the
fit of its DR programs relative to system needs in every IRP.
Revised Cost-Effectiveness Methodology
The proposed cost-effectiveness methodology produces a value of DR relative to a least-
cost simple cycle combustion turbine ("SCCT") proxy resource so that the Company can
establish a cost threshold under which DR programs can measure cost-effectiveness within the
Company's system. To ensure the benefits and the level of reliability provided by DR and by the
proxy resource are equivalent, the Company made two modifications to its cost-effectiveness
methodology. First, the Company quantified the additional benefits provided by a SCCT beyond
what DR can provide then adjusted the avoided cost by this amount. Second, the Company
determined the amount of DR nameplate capacity needed to provide an equivalent level of
capacity contribution from a SCCT. The Company will perform a verification step to ensure that
the amount of incremental DR included in the IRP preferred portfolio is cost effective compared
to the surrogate using both adjustments. Ellsworth, DI at23. Staff concurs with the proposed
cost-effectiveness methodology and recommends this analysis be repeated in subsequent IRPs.
4STAFF COMMENTS FEBRUARY 10,2022
The SCCT proxy resource can provide benefits to the system beyond what DR can
provide. A SCCT can operate 24 hours a day and throughout the entire year as compared to the
redesigned DR programs, which are generally only dispatched from June 15 through September
15 and from the hours of 3 p.m. to 11 p.m. By running two Aurora simulations of the system,
one with DR and the other with a SCCT, the Company was able to determine the value
difference between the two resources. The Company determined that a SCCT provides
approximately $38.1I per kilowatt ("kW") per year over and above a492 megawatt ("MW") DR
portfolio. This value was used to adjust the avoided cost of the SCCT proxy when determining
the cost-effectiveness threshold. Staff believes the method used by the Company is robust and
that this adjustment is necessary to ensure that the avoided cost using a proxy is accurate.
The level of capacity contributing to system reliability (effective load carrying capability)
of the two resources, DR and a SCCT, are not equivalent for the same amount of nameplate
capacity. The Company was able to determine that272 MW of SCCT nameplate capacity is
necessary to provide an equivalent amount of load carrying capability of 492 MW of DR
nameplate capacity. These amounts were expressed as a ratio between the two amounts of
nameplate and were used to adjust the avoided cost based on the fixed cost of a SCCT. As in the
case of the benefit adjustment described above, this reliability adjustment is necessary to ensure
that the avoided cost ofthe proxy resource is accurate.
Since the avoided costs and design of the programs are used as a basis for determining
incremental amounts of DR to be included in the Company's IRP preferred portfolio, the
Company has proposed a verification step to ensure that the incremental amounts of DR are cost-
effective. The Company proposed an additional Aurora run replacing the DR programs in the
preferred portfolio with an effective-equivalent SCCT so that the total cost of each run can be
compared to ensure that the preferred portfolio reflects an equivalent or lower cost. Staff
recommends this analysis be performed and the results provided in a compliance filing or in the
next annual Demand-Side Management ("DSM") prudency filing. Staff also recommends that
the full cost-effectiveness analysis discussed above be repeated in future IRPs.
Assessment of Available Demand Response
The Company estimates there is 492 MW of traditional DR potential for the Company's
service territory based on the Northwest Power and Conservation Council ('NWPCC")
5STAFF COMMENTS FEBRUARY IO,2O22
assessment. The NWPCC assessment was conducted to determine the DR potential for the entire
Northwest region for use in the NWPCC 2021Power Plan. To derive the Company's DR
potential for its service territory from the NWPCC region, the Company created a ratio of its
system peak relative to the NWPCC region. Of the 31,125 MW system peak in the NWPCC
region, the Company has an 11.89 % share. The Company then applied this ratio to the sunrmer
achievable potential for DR in the NWPPC region to determine the Company's MW allocation
of DR potential for its service territory. The Company then adjusted its allocation of DR
potential to factor in its existing programs while removing overlapping DR programs, high-cost
programs, and programs with different ELCC's to achieve the 492 MW of DR potential specific
to the Company's service tenitory.
While the Company tried to achieve an accurate estimate of DR potential for its service
territory from this assessment, the best method for obtaining accurate results would have been to
conduct a DR potential study specific to the Company's service territory as the Company's
service territory is much different than that of the entire Northwest Region. For example, while
the Company is a summer peaking utility with many irrigators on its system, other utilities in the
Northwest are winter peaking utilities with service areas consisting of densely populated cities.
Also, geographical differences between the Company's service territory and other regions of the
Northwest could result in over or under estimating DR programs' potential for the Company's
territory.
In Response to StafPs Production Request No. 3, the Company indicated it has selected a
third-party contractor to conduct a DR potential study specific to the Company's service territory
and anticipates work will begin in February 2022 with an estimated completion date near late
surlmer or early fall. The contractor will consider any updated program parameters,
participation levels, and incentives within its analysis. The updated participation levels of the
current programs will be known in June. Staffbelieves this study will be beneficial and agrees
that the process should focus on the Company's service area, program participants, and
ratepayers. The Company's assumptions and calculations for the DR program and in the IRP
should improve with the results of the study. Staff recommends the Company provide the
Commission with results of the DR study and update calculations and assumptions in the
Company's DR program as soon as the results of the study have been finalized and vetted for
accuracy.
6STAFF COMMENTS FEBRUARY IO,2O22
Impact Evaluations
The Company will also conduct internal evaluations and report results in its annual DSM
report. The Company is planning to have a process evaluation completed in2023 and third-party
impact evaluations every five years thereafter. Staff interprets this response to indicate that five
years would pass before impact of the DR changes will be fully analyzed and known. Staff
recommends the Company conduct an impact evaluation as soon as sufficient program event
data is available to conduct a meaningful evaluation for the DR program.
Marketine Cost Cap
Staff understands the Company's need to remove marketing cost constraints of DR
programs. The 2013 Settlement was conducted in a much different planning environment than
current circumstances given the Company's near-term need for capacity. Furthermore, because
of the changes in hours and season that DR needs to operate, Staff agrees that it will be
challenging to find customers willing to participate. Staff recommends that the budget cap on
marketing expenses be removed, so long as the Company ensures that those costs are included in
the cost-effectiveness calculations and that the programs remain prudent and cost-effective.
Staff intends to closely monitor the Company's marketing expenses for the DR program
during the Company's annual DSM prudency filings. Marketing expenses should be limited and
closely managed by the Company to ensure the DR program is a least cost option while
remaining cost effective on a year-to-year basis.
Program Manaqement
The Company's modification to the tariff language and establishment of a new cost-
effectiveness method, supersedes the terms of the 2013 Settlement Agreement in Order No.
32923. It is Staff s expectation that the Company will actively manage its DR programs to
ensure they remain cost effective as it does its other DSM programs. Staff recommends 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, should all be actively managed and updated to ensure continuous
improvement of the program and that it remains cost-effective on a year-to-year basis. The
Company is expected to become capacity deficient in2023 and ensuring the DR program
7STAFF COMMENTS FEBRUARY IO,2O22
changes can meet the critical times and needs identified by the Company will be of the utmost
importance.
Staff recommends the Company exercise one of the minimum events (if available) during
the2022 season between August l5 to September 15 and during the 9:00 p.m. to 11:00 p.m.
event window to ensure the changes to the program can result in a significant amount of DR
achieved so the Company can effectively plan on using the program during these critical times.
In addition, Staff recommends the Company include in its annual DSM report updated
information addressing the DR programs' effectiveness at meeting these times. Information such
as DR achieved, opt outs, andrealization rates should be included for the August 15 to
September l5 period and during the 9:00 p.m. to 11:00 p.m. event windows.
STAFF RECOMMENDATIONS
Staff recommends the Commission:
l. Authorize the Company to modifr its DR programs as described in the
Application;
2. Approve Tariff No. l0l for Schedule 23 (Irrigation Peak Rewards Program),
Schedule 81 (Residential Air Conditioner Cycling Program), and Schedule 82
(Flex Peak Program) with an effective date of February 15, 2022, as filed;
3. Authorize the Company's revised cost-effectiveness methodology to evaluate
Demand Response as described in its Application to supersede the Settlement
Agreement approved by Commission Order No. 32923 in its entirety;
4. Order the Company to analyzethe fit of its DR programs relative to system needs
and perform the cost-effectiveness equivalency analysis in every IRP;
5. Utilizing the needs analysis and cost-effectiveness equivalency analysis from the
IRP, 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 a year-to-year basis;
6. Direct the Company to exercise one of the minimum events (if available) during
the 2022 season between August 15 to September l5 and during the 9:00 p.m. to
I 1:00 p.m. event window; and
8STAFF COMMENTS FEBRUARY IO,2O22
7. Eliminate the marketing cost caps and allow marketing cost necessary to promote
participation as long as the cost are included in the cost-effectiveness calculations
and the prograurs remain cost-effective.
Respectfully submitted this I Ofr day ofFebruary 2022.
Riley
Deputy Attorney General
Technical Staff: Rick Keller
KevinKeyJ
TaylorThomas
Travis Culbertson
i:umisdcommonts/ipce2l.32mrktktue oortrnents
9STAFF COMMENTS FEBRUARY TA,2A22
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS IOth DAY OF FEBRUARY 2021,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC-E-21-32, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
TO THE FOLLOWING:
LISA NORDSTROM
IDAHO POWER COMPANY
PO BOX 70
BOrSE ID 83707-0070
E-MAIL: [e-mail]
dockets@ idahopower.conr
ERIC L OLSEN
ECHO HAWK & OLSEN PLLC
PO BOX 6l 19
POCATELLO ID 83205
E-MAIL: [e-mail]
PETERJ RICHARDSON
RIC}IARDSON ADAMS PLLC
5I5 N 27TH ST
BOISE ID 83702
E-MAIL: [e-mail]
BENJAMIN J OTTO
EMMA E SPERRY
ID CONSERVATION LEAGUE
7IO N 6TH ST
BOISE ID 83702
E-MAIL: [e-mail]
esperr y@ idahoconservation.com
JIM SWIER
MICRON TECHNOLOGY INC
SOOO S FEDERAL WAY
BOISE ID 83707
E-MAIL: [e-mail]
ELECTRONIC ONLY
[e-mail]
gl garganoarnari@hol landlrart.com
CONNIE ASCHENBRENNER
RATE DESIGN SENIOR MGR
IDAHO POWER COMPANY
PO BOX 70
BOrSE rD 83707-0070
E-MAIL: [e-mail]
LANCE KAUFMAN
AEGIS INSIGHT
48OI W YALE AVE
DENVER CO 80219
E-MAIL: [e-mail]
DR DON READTNG
60T0HILL ROAD
BOISE ID 83703
E-MAIL: [e-mail]
ED JEWELL
DEPUTY CIry ATTORNEY
BOISE CITY ATTORNEY'S OFFICE
PO BOX 500
BOISE ID 83701-0500
E-MAIL: eien'ell6cityofboise.ors
bo i sec ityattomer"@c it_vofbo i se.org
AUSTIN RUESCHHOFF
THORVALD A NELSON
AUSTIN W JENSEN
HOLLAND & FIART LLP
555 ITTH ST STE 32OO
DENVER CO 80202
E-MAIL: darueschhoff@hol landhart.corn
tnelson@hol landhart.com
awj e n sen @ ho I lan d h art. com
Y
CERTIFICATE OF SERVICE