20131030Comments.pdf

KARL T. KLEIN .: i.] -
DEPUTY ATTORNEY GENERAL
rDAHO
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UTrLrrrES COMMTSSTON Sirir il:li 3I ,ri, ll: f 5
PO BOX 93720 _ : ,-BOISE, IDAHO 83720-0074 'r.., t, i:, ,,:-..
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[phone]
IDAHO BAR NO. 5156
Street Address for Express Mail:
472W. WASHINGTON
BOISE, IDAHO 83702-59I8
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE CONTINUATION )
oF IDAHO POWER COMPANY'S A/C COOL ) CASE NO. rPC-E-13-14
CREDIT, IRRIGATION PEAK REWARDS, )
AND FLEXPEAK DEMAND RESPONSE ) COMMENTS OF THE
PROGRAMS FOR 2014 AND BEYOND. ) COMMISSION STAFF
)
The Staff of the Idaho Public Utilities Commission comments as follows in support of the
Demand Response Programs Settlement Agreement filed in this case (the "Settlement"). Staff
believes the proposed Settlement is just, fair, and reasonable, in the public interest, and should be
accepted by the Commission.
BACKGROUND
Idaho Power Company has historically offered three voluntary demand response ("DR")
programs: A/C Cool Credit; Irrigation Peak Rewards; and FlexPeak Management programs. On
June 4, 2013, the Commission initiated this proceeding to examine whether the Company should
continue or modify these programs. See Order No. 32823.
A. Prior Proceedings
ln prior proceedings, the Commission "temporarily suspended" the A/C Cool Credit and
Irrigation Peak Rewards programs for 2013 and approved changes to the FlexPeak program. The
Commission suspended the first two DR programs and modified the third based on the
Company's assertion that it would not experience a peak-hour generation deficit from 2013
STAFF COMMENTS ocToBER 30,20t3
through July 2016. See Order Nos. 32776 and 32805. In summary, these two prior Orders
provided as follows.
1. Order No. 32776-AlC Cool Credit and Irrigation Peak Rewards
In Order No.32776, the Commission approved a proposed settlement agreement entered
into by the parties including the Idaho Irrigation Pumpers Association, Inc. (the "Irrigators");
Idaho Conservation League ("lCL"); Snake River Alliance ("SRA";; and Commission Staff.
The parties agreed to suspend the A/C Cool and Peak Rewards programs for 2013 based upon
Idaho Power's 2013 Integrated Resource Plan ("lRp";. More specifically, the 2013 IRP showed
that the peak-hour projected loads for the summer months of 2013, 2014, and 2015 did not show
a "peak-hour deficit until July 2016 and therefore [there was] no need [to employ] peak-hour
[DR] programs" like the A/C Cool and Peak Rewards programs. The Company relied on the
same rationale for amending the FlexPeak Management contract.
The settlement approved in Order No. 32776 also provided that residential customers
participating in the A/C Cool Credit program be provided a "continuity" payment of $1.00 per
month for the three summer months of 2013. The settlement also provided for continuity
payments for those inigation customers voluntarily participating in the four Peak Reward
options. In addition to continuity payments, the parties requested that the Commission schedule
an informal prehearing conference to set public workshops and develop a procedural schedule so
that the parties and other interested persons may evaluate changes to the DR programs for
calendar year 2014 and beyond. The Order approving the temporary suspension directed Staff to
convene an informal prehearing conference for the parties to develop a schedule for the public
workshops. Order No. 32776 at 8.
2. Order No. 32805-FlexPeak
In the FlexPeak Order, the Commission approved changes to the program which will
reduce the cost of the progrtrm by about $500,000 for 2013. Order No. 32805 at 3. As with the
A/C Cool and Peak Rewards programs, the Commission directed that the public workshops also
address "how to continue the FlexPeak program in the future." Id. at 4. In accordance with the
Orders mentioned above, an informal prehearing conference was scheduled to further evaluate
the three DR programs. The Commission also directed that those entities already granted
intervention would be parties in the new case. Order No. 32776 at 8.
STAFF COMMENTS ocToBER 30,201,3
B. Present Proceedings
As noted above, the prior Orders directed the parties to convene an informal prehearing
conference to schedule public workshops. The prehearing conference in this case occurred on
June 12, 2013. A series of five public workshops then occurred between July 10 and August 27,
2013. Workshop participants discussed how the Company includes DR in its IRP, how it
calculates cost-effectiveness, the purpose of DR, and DR programs and their operational design.
The last workshop also included settlement discussions that culminated in the proposed
Settlement. See Notice of Informal Prehearing Conference, and Notices of Public Workshops.
STAFF ANALYSIS
Staff participated in all five stakeholder workshops designed to determine how to
structure Idaho Power's DR programs for years when the IRP does not predict capacity deficits
or a corresponding need for DR. The workshops began by providing foundational information
on DR, including its intended purpose, how DR has historically been used by the Company, and
examples of DR programs around the country. Later workshops explored DR's monetized value,
including its value in years when the IRP does not identifu a capacity deficit. Several workshops
included breakout sessions in which DR program participants and other stakeholders examined
program details and recommended changes that would make each program more responsive to
the Company's resource needs, or lower costs. The final workshop focused on settlement
negotiations where the incentive levels for residential and irrigation participants were
established.
The Settlement provides for:
l) Continuing all three DR programs in 2014 and beyond, using existing participants
and equipment when possible.
Establishing a $16.7 million maximum annual value for the entire demand response
portfolio. This value was established using the cost of a single defened 170
megawatt ("MW") simple-cycle combustion turbine ("SCCT"), measured over the
2}-year IRP planning horizon, plus the corresponding deferred energy savings for 60
hours. This value is included beginning in2014 and shall be included in years when
the IRP shows no capacity deficit.
Modifying the DR Programs to align the cycling season for all three programs, reduce
the dispatch notification time for the irrigation program, reduce incentive payments to
2)
3)
STAFF COMMENTS ocToBER 30,2013
irrigation and residential participants, and add three mandatory dispatch events per
season for each program.
l. Continuing the DR Programs
Although the IRP does not show an immediate capacity deficit, Staff believes it is
important to continue the DR programs for the next two years to ensure there are sufficient,
reliable DR resources to meet anticipated deficits in2016 and2017. The workshops illustrated
that reliable DR depends on committed customer participation. While it is relatively easy for
residential customers to participate in DR programs, irrigation and commercial customers invest
considerable effort and expense-particularly start up costs-and incur significant risk to
participate in DR that will provide peak capacity to Idaho Power. Without an ongoing utility
commitment to DR, many of these customers would not find it worthwhile to participate.
Commercial and irrigation customers may be more likely than residential customers to stop
participating in DR without a continuous DR program, but even residential participation would
be negatively affected if Idaho Power changed its position on the value of DR every few years.
Staff also believes that using existing participants and equipment when possible makes
the best use of previous investments in DR programs. Staff believes it is generally less
expensive to use established participants and existing equipment than to recruit new participants,
remove existing equipment, and re-install equipment at new locations. All three programs
currently have equipment installed in the field, but Idaho Power only owns the equipment
installed through the irrigation and residential programs. Equipment deployed through the
FlexPeak program for commercial customers is owned by EnerNoc, the third-party aggregator.
Previous investments in that equipment will not be preserved unless Idaho Power renews its
contract with EnerNoc.
The proposed Settlement attempts to reduce costs and improve program responsiveness
by decreasing incentive payments to inigation and residential customers and increasing program
dispatch requirements. As a result, Staff anticipates that some customers may stop participating
in the programs. Since the current DR capacity of about 400 MW far exceeds the projected
capacity deficit for 2016 and2017, Staff believes the programs can absorb some attrition and still
meet the IRP-identified need.
2. Valuing the DR Programs
Determining the value of the DR portfolio centered on two issues: l) the size of the
deferred resource, and2) the number of years over which the value should accrue.
STAFF COMMENTS ocToBER 30,2013
The IRP forecasts an 89 MW capacity deficit in20l6 and a 139 MW deficitin2)l7.
Assuming the Boardman to Hemingway transmission line is completed on time in 2018, the IRP
does not forecast deficits again until 2024. In that year, the IRP forecasts a 39 MW capacity
deficit that steadily grows to a 400 MW deficitin2}33.
Without DR, Idaho Power would need to build a supply-side peaking resource to meet
demand in 2016 and 2017 and could use the same resource to meet excess demand until2027.
Building one, 170 MW SCCT would meet the Company's forecasted capacity deficit from 2016
through 2027 . Beyond 2027, the dehcits are projected to exceed the size of a single SCCT.
Staff believes that the compounding deficits forecasted after 2027 in the IRP planning
period are large enough and grow quickly enough that instead of rapidly building a series of
SCCTs, the Company is more likely to build a much larger resource. However, because that
larger resource is needed so far in the future (only in the last six years of the IRP planning
period), Staff does not believe it is reasonable to include it in the value of DR programs funded
today. Consequently, Staff agrees the current value of DR, based on the projected 2016-2017
deficits and four years of deficits after Boardman to Hemingway, is the deferred capacity of one
SCCT, plus the ancillary energy savings produced by maximum DR program dispatch.
The workshops also resolved another important issue: Over how many years should the
levelized value of DR be calculated? To be consistent with the IRP-planning time lines, the
workshop participants agreed to value DR over 20 years. Staff concurs that the deferred resource
cost should be used to value DR over the entire period even though a capacity deficit is not
identified by the IRP in some years. If a SCCT was built to meet load in six intermittent years,
the cost of the resource would not be reduced for years when the resource was not needed. The
Company would collect the full cost from ratepayers even though an IRP may show no capacity
deficits in some years. Staff believes that participation and reliability would decline if the DR
program was suspended further and therefore agrees it is reasonable to establish a2\-year
levelized program value beginning tn2014.
Staff suggested, and workshop participants agreed, to value DR as equivalent to the
lifecycle revenue requirement for a SCCT because that is what ratepayers would fund in the
absence of DR. Staff agrees that Idaho Power's current practice of decrementing the value of
DR by the effective load carrying capacity (ELCC) and including the value of deferred energy
savings correctly adjusts DR value to reflect its limitations and benefits as compared to a SCCT.
STAFF COMMENTS ocToBER 30,2013
Based on this methodology, the maximum annual levelized value of the DR portfolio is
calculated to be $ 16.7 million. In order for the portfolio to be cost-effective, annual program
expenses must not exceed this amount. Previously, cost-effectiveness was determined by
assuming that each MW of DR deferred a SCCT MW. While this was a reasonable approach
with consistent capacity deficits, it is not an appropriate valuation with intermittent deficits. The
Settlement bases the value of DR-and therefore its cost-effectiveness-on the actual size of the
resource being deferred throughout the planning period.
Importantly, the value of the DR shall be reevaluated as the IRP changes. Although the
Company's future IRP's will continue to be used to calculate the value of DR using the
Settlement methodology, the avoided cost of capacity, determination of capacity need, and other
financial inputs may change. Changes in any of these variables could significantly affect the
total value of DR, which would directly affect the appropriate amount of annual program
expenditures. Staff believes the Settlement provides a reasonable framework to value DR in the
future as conditions change.
3. Modifying the DR Progroms
The Settlement also makes several changes to the program design and incentive
payments. The residential and commercial programs were shortened by 15 days on either end of
the program season to match irrigation program dates. This will reduce costs, streamline
dispatch processes, and align the programs more closely with Idaho Power's projected capacity
deficits. The Company will dispatch each program at least three times ayear, regardless of need,
to ensure reliable participation and demand reduction. Idaho Power will not seek to actively
expand the capacity of its programs, but additional residential customers who wish to participate
will be allowed to enroll.
Incentive payments for each program were determined within the constraints of the total
annual value calculation. To determine the maximum level of incentives, Staff subtracted the
average annual administrative cost of the programs from the total annual value of the DR
portfolio, and then proposed using half of the remaining sum as the ceiling on incentives. From
that amount, workshop participants negotiated incentive levels designed to preserve committed
participation while keeping costs as low as possible.
Incentive payments to residential customers were decreased from $21lseason to
$ lSlseason which reflects the shorter program season. Incentive payments to irrigators were also
significantly reduced and retained the fixed/variable payment structure. Parties agreed that three
STAFF COMMENTS OCTOBER 3O,2OI3
dispatch events per year would be included in the fixed portion of the payment structure to
ensure DR reliability. The variable portion of irrigation incentives was structured so that even in
years when the programs are dispatched for the full 60 hours, the annual costs of the program
will not exceed the annual value of the resource. Incentive payments for the commercial
program were not specifically determined. However, the annual value calculation in
combination with the residential and inigation incentives prescribed in the Settlement gives the
Company a clear guide on total expenditures.
In addition to reduced incentives, irrigation participants also agreed to reduced advance
notification of intemrption from day-ahead to immediate dispatch for Option I and} participants
and to four-hour advance notification for Option 3 participants. Fully dispatchable DR with
shorter notification periods increases the resource value of DR.
Staff believes that the resource-based value calculation combined with cost savings and
program modification helps the Settlement preserve previous investments in a valuable DR
resource while limiting costs in years when it is not needed to meet load.
STAFF RECOMMENDATION
Staff recommends that the Commission accept the proposed Settlement as just, fair, and
reasonable and in the public interest.
Respecttully submitted this 3O+! day of October 2013.
),-r 1/L
KarlT. Klein
Deputy Attorney General
Technical Staff: Stacey Donohue
Bryan Lanspery
Nikki Karpavich
Donn English
i:umisc/comments/ipcel3. l4kkadnkdebl comments
STAFF COMMENTS ocroBER 30,2013
CERTIFICATE OF SERVICE
I HEREBy CERTIFY rHAT I HAVE THIS 30tH DAy oF ocroBER20l3,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. IPC-E-13-14, BY MAILING A COPY AND E-MAILING A COPY THEREOF,
POSTAGE PREPAID, TO THE FOLLOWING:
JULIA HILTON
LISA D NORDSTROM
REGULATORY DOCKETS
IDAHO POWER COMPANY
PO BOX 70
BOISE rD 83707-0070
[e-mail]
i hilton@ idahopower. com
CBearry@ idahopower. com
ERIC L OLSEN
RACINE OLSON NYE BUDGE
& BAILEY
PO BOX 1391
POCATELLO ID 83204-1391
[e-mail]
BENJAMIN J OTTO
ID CONSERVATION LEAGUE
710 N 6TH STREET
BOISE TD 83702
botto@ idahoconservation. org
PETER J RICHARDSON
RICHARDSON ADAMS PLLC
515 N 27TH ST
BOISE ID 836I6
peter@richardsonadams. com
MELANIE GILLETTE
DIR REGULATORY AFFAIRS
ENERNOC INC
II5 HAZELMERE DR
FOLSOM CA 95630
m [e-mail]
COURTNEY WAITES
TIM TATUM
IDAHO POWER COMPANY
PO BOX 70
BOrSE rD 83707-0070
cwaites@ idahopower. com
[e-mail]
ANTHONY YANKEL
29814 LAKE ROAD
BAY VILLAGE OH 44140
[e-mail]
KEN MILLER
SNAKE RIVER ALLIANCE
PO BOX l73l
BOISE ID 8370I
kmiller@ snakeriveralliance. org
DR DON READING
6070 HILL ROAD
BOISE ID 83703
[e-mail]
TERESA A HILL
K&L GATES LLP
222 COLUMBIA ST STE 14OO
PORTLAND OR 97201
SECRETARY
CERTIFICATE OF SERVICE