20140930Demand Response Report.pdf

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An IDACORP Company
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Corporate Counsel
[e-mail]
September 30,2014
VIA HAND DELIVERY
Jean D. Jewell, Secretary
ldaho Public Utilities Commission
472 West Washington Street
Boise, ldaho 83702
Re: Case No. IPC-E-13-14
Continuation of Demand Response Programs - Demand Response as
Operating Reserves Feasibility Report
Dear Ms. Jewell:
In the Settlement Agreement signed by parties to Case No. IPC-E-13-14, ldaho
Power Company committed to investigating the feasibility of using demand response as
operating reserves and making a determination on feasibility bythe end of the 3rd quarter
in2014.
Enclosed for filing in the above matter are an original and three (3) copies of ldaho
Power Company's Demand Response as Operating Reserves Feasibility Report. The
study will be presented to the Energy Efficiency Advisory Group in an upcoming meeting.
Idaho Power Company is providing these informational copies for the ldaho Public
Utilities Commission's records and convenience. Please contact me at [phone] if
you have any questions.
JAH:kkt
Enclosures
cc: Service List
Very truly yours,
Julia A. Hilton
CERTIFICATE OF SERVICE
! HEREBY CERTIFY that on this 30th day of September 20141 served a true and
correct copy of IDAHO POWER COMPANY'S DEMAND RESPONSE AS OPERATING
RESERVES FEASIBILITY REPORT, upon the following named parties by the method
indicated below, and addressed to the following:
Gommission Staff
Karl Klein
Deputy Attorney General
ldaho Public Utilities Commission
472 West Washington (83702)
P.O. Box 83720
Boise, ldaho 83720-007 4
ldaho lrrigation Pumpers Association, lnc.
Eric L. Olsen
RACINE, OLSON, NYE, BUDGE &
BAILEY, CHARTERED
201 East Center
P.O. Box 1391
Pocatello, ldaho 83204-1 391
Anthony Yankel
29814 Lake Road
Bay Village, Ohio 44140
ldaho Conservation League
Benjamin J. Otto
ldaho Gonservation League
710 North Sixth Street
Boise, ldaho 83702
Snake River Alliance
Ken Miller, Clean Energy Program Director
Snake River Alliance
P.O. Box 1731
Boise, ldaho 83701
lndustrial Customerc of ldaho Power
Peter J. Richardson
RICHARDSON ADAMS, PLLC
515 North 27th Street (83702)
P.O. Box 7218
Boise, ldaho 83707
CERTIFICATE OF SERVICE - 1
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Dr. Don Reading
6070 Hill Road
Boise, ldaho 83703
EnerNOC, Inc.
Teresa A. Hall
K&L GATES, LLP
222Columbia Street, Suite 1400
Portland, Oregon 97201
Melanie Gillette, Director Regulatory Affairs
EnerNOC, lnc.
115 Hazelmere Drive
Folsom, California 95630
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CERTIFICATE OF SERVICE. 2
sEm.
An IDACORP Company
DEMAND RESPONSE
AS OPERATING RESERVES
FEASIBILITY REPORT
September 30, 2014
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TABLE OF CONTENTS
EXECUTTVE SUMMARY........ .............. 1
lntroduction .........2
Resulatory and Operational Overuiew ..............3
Operating Reserves ................. 3
CRO at ldaho Power ................4
Nofthwest Power Pool........ ..................... 5
Demand Response Programs at ldaho Power..... ..................6
Applicabilitv ........8
lmplementation Considerations ........8
Operation Systems Modification ............. ............... I
AlC Cool Credit ........ I
FlexPeak Management.......... ................ 10
lrrigation Peak Rewards ........ 10
Evaluation DR as CRO .....11
Gosfs...... ................. 11
Benefits.. .................12
Financial Analysis. ................. 13
Risks .......14
Companv Risk ...............14
DR Proqram and Participant Risk ................. 15
NC Cool Credit .................. 15
lnigation Peak Rewards ..... 16
RECOMMENDAT|ON............. ............ 16
EXECUTIVE SUMMARY
tn Settlement Agreements filed in both ldaho and Oregonl and approved by the ldaho
Public Utilities Commission ("|PUC") and the Public Utility Commission of Oregon
("OPUC") in Order Nos. 32923 and 13482, respectively, ldaho Power Company ("ldaho
Powe/' or "Company") agreed to investigate the feasibility of using Demand Response
(.DR') as operating reserves and to make a determination on the feasibility by the end
of the 3'd quarter of 2014.
The Demand Response as Operating Reserves Feasibility Report ("Report") provides a
background of the Company's operating reserves requirements, and identifies that DR
could only be used for the non-spinning portion of the Company's Contingency
Reserves Obligation ('CRO'). lt describes each of the DR programs the Company
currently operates, discusses the applicability of using DR as CRO from a compliance
perspective, and describes the implementation requirements for the Company to use its
DR programs as CRO. The Report then examines each of the DR programs and
discusses whether or not each one has potential to be used as CRO. The Report
concludes with the Company's financial analysis and recommendation.
Based on its analysis, ldaho Power concluded the risks outweigh the benefits to utilize
DR as CRO because: (1) the economic benefit of using DR as CRO is too small to
provide incentives at a leve! that would attract participation and provide for program
costs, (2) the risks for failure to meet North American Electric Reliability Corporation
("NERC") standards is far greater than the economic benefit that might be derived, (3)
the period of testing that would be required to provide operational certainty of
compliance with NERC and Western Electricity Coordinating Council ("WECC')
requirements would require carrying substantially more than the reserves actually
needed for contingency, at a cost to all customers, and (4) the number of CRO events
would put too heavy of a strain on the DR participants, thus risking participation in the
Company's DR programs.
As described in the Report, the economic benefit, excluding payments to participants
and program costs, of using DR as CRO is insignificant when compared to the capacity
benefit the current DR programs provide. While having a dual-purposed program may
be conceivable from a technical and compliance perspective, the Company believes
that it is not practical from an economic and DR program participant perspective. The
Company believes that the economic, DR program participation and other operational
risks identified in this Report, are too great to proceed with a pilot at this time.
'ldaho Case No. IPC-E-13-14 and Oregon Case No. UM-1653.
!ntroduction
ln late 2012 and early 2013, ldaho Power filed for changes to its A/C Cool Credit
program, Irrigation Peak Rewards program, and FlexPeak Management program
(collectively "DR Programs") in both its ldaho and Oregon jurisdictions.' These filings
were prompted by the lack of near-term peak-hour deficits identified in the Peak Load
and Resource Balance analysis prepared for the 2013 lntegrated Resource Plan
("lRP"), and ldaho Power's desire to take prompt and prudent steps to avoid some of
the expenses associated with the programs in years where the Peak Load and
Resource Balance analysis did not show a need.
ln Order No. 32823, the IPUC opened Case No. IPC-E-13-14, and set an informal
prehearing conference to be held on June 12,2013, to schedule workshops to evaluate
ldaho Power's DR Programs for the 2014 program season and beyond. The IPUC
ordered that the Idaho lrrigation Pumpers Association ("llPA"), the ldaho Conservation
League ('!CL"), and the Snake River Alliance ("SRq"; were designated as intervening
parties in this case. Additional petitions to intervene in this proceeding were filed by the
lndustrial Customers of ldaho Power ("lClP") and EnerNOC, Inc. ("EnerNOC").
ln the interest of administrative efficiency for the OPUC and for the Oregon customers
of ldaho Power, in May of 2013, the OPUC opened Docket No. UM 1653 to facilitate
participation by OPUC Staff and interested Oregon parties in the ldaho workshop
process.
Following the June 12,2013, prehearing conference, the parties set a schedule for four
workshops, which were held on July 10, July 23, August 7, and August 19. During the
August 19 workshop, the participants agreed to hold an additional workshop on August
27, 2013, which included confidential settlement discussions. An additional workshop
was held in Oregon for the benefit of interested Oregon parties on October 9, 2013,
where the results of the prior workshops were reviewed, questions were answered, and
parties held settlement discussions.
Based upon the ldaho proceedings, several parties, including ldaho Power, IPUC Staff,
llPA, lCL, SRA, EnerNOC, and non-party customer Mike Seaman agreed to resolve and
settle issues related to the reinstatement of ldaho Power's DR Programs for 2014 and
beyond. The signed Settlement Agreement was approved by the IPUC in Order No.
32923. The Company filed a similar Settlement Agreement with the OPUC in Docket
No. UM 1653, which was approved by Order No. 13482. Both Settlement Agreements
are working as envisioned and during the 2014 DR program season the Company had
enrolled DR participants to provide approximately 390 megawatts ("MW') of maximum
load reduction at generation level, which is near prior levels of DR capacity before the
programs were temporarily suspended in 2013.
'ldaho Docket Nos. IPC-E-12-29, IPC-E-13-04, Oregon Advice 13-04 and Docket No. UM-1653.
ln these Settlement Agreements, ldaho Power agreed to investigate the feasibility of
using DR as operating reserves and make a determination on the feasibility by the end
of the 3'd quarter of 2014.3
This Report presents the Company's feasibility review and recommendation not to use
DR as operating reserves. First, the Report wil! provide a regulatory and operational
overview of the Company's operating reserves requirements and will then describe
each of the DR Programs the Company currently operates. The Report will then
discuss the applicability of using DR as operating reserves from a compliance
perspective and describe the implementation requirements for the Company to use its
DR Programs as operating reserves. The Report will then examine each of the DR
Programs and discuss why the DR Programs should not be used as operating reserves.
Reoulatorv and Operational Overview
For operation of its Bulk Electric System (.BES"), ldaho Power is regulated by the
Federal Energy Regulatory Commission ("FERC") who oversees the NERC, as the
Electric Reliability Organization ("ERO") for North America, a requirement of the Federal
Power Act of 2006. NERC is the entity that develops and enforces the mandatory
Reliability Standards that ldaho Power must adhere to, governed by Section 215 of the
Federal Power Act. ln addition to adhering to NERC Standards, ldaho Power is a
member of the WECC, the Regional Entity responsible for coordinating and promoting
BES reliability in the Western lnterconnection.
Operating Resenres
NERC and WECC standards require that the Company hold a certain amount of
operating reserves to ensure reliable operation of the system. NERC defines operating
reserves as "that capability above firm system demand required to provide for
regulation, load forecasting error, equipment forced and scheduled outages and local
area protection,'4 or simply, the generation capacity required above the Company's Ioad
for possible contingency events, changes in load, and accommodation for variable
generation. Operating reserves are comprised of Contingency Reserves Obligations
("CRO") and Regulating Reserves.o
CRO is the amount of generation capacity generally held for use for events such as
generator trips resulting in loss of generation or transmission line trips resulting in loss
of import energy, while Regulating Reserve is the unloaded generation capacity
3 Demand Response Programs Settlement Agreement at 4.
o NERC's Glossary of Terms Used in NERC Reliability Standards: htto://www.nerc.com/files/glossarv of terms.odf
t NERC defines Contingency Reserve as "the provision of capacity deployed by the Balancing Authority to meet the
Disturbance Control Standard (DCS) and other NERC and Regional Reliability Organization contingency
requirements." ld.
t NERC defines Regulating Reserve as "an amount of reserve responsive to Automatic Generation Control, which is
sufficient to provide normal regulating margin." ld.
generally used for moment to moment changes in both load and variable generation.
Typically the Company's CRO must have at least 50 percent_ met by Spinning
Reserves,' with the remaining met with Non-Spinning Reserveso while Regulating
Reserves are comprised completely of Spinning Reserves. Spinning Reserves is
unloaded generation capacity that is online and synchronized to the electrical system
while Non-SpinninB Reserves is generation or load that can be dispatched and utilized
within 10 minutes.
ln terms of managing and maintaining its operating reserves, ldaho Power is required to
adhere to the following NERC and WECC standards: the Real Power Balancing Control
Standard (BAL-001), the Disturbance Control Performance Standard (BAL-002), the
Frequency Response and Frequency Bias Setting Standard (BAL-003), the
Contingency Reserve Standard (BAL-002-WECC-2), and the Northwest Power Poo!
Reserve Sharing Agreement. Ultimately, ldaho Power must be able to meet the Most
Severe Single Contingency ("MSSC) (BAL-002) with CRO, which for ldaho Power is
330 MWs, and equivalent to the loss of two units at the Jim Bridger Power Plant.
Because DR is not generation, it can only be used to satisfy the non-spinning portion of
the Company's CRO, and as such, the remainder of this Report will focus on the CRO
rather than total operating reserves, which are comprised of both CRO and Regulating
Reserves.
CRO at ldaho Power
Generally, the Company's CRO is met by utilizing hydro generators that have reservoir
storage available to provide the rapid response for the extended time needed, but other
' ufnC defines Spinning Reserve as "unloaded generation that is synchronized and ready to serve additional
demand." ld.
t rurRC defines Non-Spinning Reserve as "that generating reserve not connected to the system but capable of
serving demand within a specified time" or "interruptible load that can be removed from the system in a specified
time." Id.
'The 10 minute requirement is mandated by the Reserve Sharing Agreement ldaho Power adheres to as a member
of the Northwest Power Pool.
types of generation used for reserves include the Company's thermal fleet that has
demonstrated the ability to respond within the 10 minute timeframe. When used as
reserves, these hydro or thermal plants have their generation output reduced and held
in reserve to provide the capacity that can be activated when needed.
The number of times ldaho Power uses its CRO varies widely and is not predictable by
day, duration, or number of MWs. The Company called on its CRO 82,82,65, 76, and
63 times during the years 2009 through 2013, respectively. The events spanned all
seven days of the week, all 12 months of the year, and the number of MWs called on
ranged from as few as two to as many as 171 during a single event. The chart below
demonstrates how many times over the prior five years ldaho Power has called on its
cRo.
ldaho Power's Hktorlaal Usc of CRO
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70
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30
20
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Northwest Power Pool
ln addition to utilizing its own resources to meet its CRO, ldaho Power is a member of
the Northwest Power Pool ("NWPP'), which is registered with WECC as a Reserve
Sharing Group (.RSG') for compliance with the NERC Standard BAL-002 and the
WECC Regiona! Standard BAL-002-WECC-2. By participating in the NWPP RSG,
ldaho Power is able to reduce its overall Company-held CRO requirement to
approximately half of its 330 MW MSSC.lo As a member of a RSG, ldaho Power can
utilize the reserves of other members in the event that it has exhausted its CRO.
Conversely, other RSG members can request ldaho Power to deliver its CRO to assist
in the mitigation of contingency events. The energy requested by the other NWPP
members may not exceed ldaho Power's CRO. The operating agreements of the
NWPP RSG allow for the real-time sharing of energy assistance without prior
transmission reservations or payment for reserved generation capacity.
to ldaho Powe/s CRO is determined based on the following formula: 639 = (5% * Hydro Generation) + lTYo *
Thermal Generation). For the most recent 12 month period, the average CRO held was 113 MW.
NWPP RSG participants, like ldaho Power, differ from those entities that are bidding
into an organized market for energy and capacity because the ability to call on the
NWPP RSG allows the Company to reduce the amount of reserves it holds as capacity.
Conversely, entities who operate in a Regional Transmission Organization ("RTO") or
lndependent System Operator ('lSO") market bid into that market based on each utility's
relative costs of energy and capacity, and the market determines which resources are
utilized to supply the needs of the entire RTO/ISO balancing area. Those costs are
then spread across all participants in that balancing area.
The Company called on the NWPP RSG reserves 18, 32,5, 11, and 6 times during the
years 2009 through 2013, respectively. The events spanned all seven days of the
week, all 12 months of the year, and the number of megawatt-hours called ranged from
as few as one to as many as 599 during a single event. The chart below demonstrates
how many times over the prior five years ldaho Power has called on the NWPP RSG
(primary axis), and the annual dollars spent for all events (secondary axis). ln the event
that ldaho Power utilizes the NWPP RSG, it pays for that energy based on a market
valuell at the time of an event, so the Company is only paying for the market value of
the energy and is not paying to reserve generation capacity or for transmission.
ldaho Powcr's Use of NWPP Rcsorves
35
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20
15
10
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IE\rents {-AnnuelCost
Demand Response Programs at ldaho Power
ldaho Power has three DR programs available for and tailored to each of its Residential,
Large Commercial & lndustria! ("C&1"), and lrrigation customer classes.
A/C Cool Credit is a voluntary DR program available to the Company's residential
customers. Using communication hardware and software, ldaho Power cycles
participants' central air conditioners ("A/C") or heat pumps off and on via a direct-load
control device installed on the units. The program is available during summer peak
" For purposes of the Reserve Sharing Program, the settlement price will be the average of the Powerdex Mid-
Columbia hourly price for (1) the hour during which the participant first requests Assistance Reserve (the "Request
Hour") and (2) each of the two hours immediately following the Request Hour; provided, however, that in no event
will the settlement price be less than zero or greater than the price cap in effect for the WECC in accordance with
regulations and orders of FERC in effect as of the Request Hour.
periods between June 15 through August 15 with maximum event durations of four
hours, and maximum event hours during the season of 60.
FIexPeak Management is a voluntary DR program available to the Company's C&l
customers capable of reducing their electrical energy consumption for short periods of
time. The program is administered by ldaho Power through a third-par$ aggregator
and relies on customers voluntarily reducing use at their sites when they are notified of
an event. The program is available during summer peak periods between June 15
through August 15 with maximum event durations of four hours, maximum event hours
during a season of 60, and the maximum number of events called during a season of
20.
!rrigation Peak Rewards is a voluntary DR program that is availabb to the Company's
agricultural irrigation customers. The program pays irrigation customers a financial
incentive for the ability to turn off participating irrigation pumps at potential high system
demand periods. The program is available during summer peak periods between June
15 through August 15 with maximum event durations of four hours, maximum event
hours during a calendar week of 15, and maximum event hours during a season of 60.
Irrigation Peak Rewards has three options for customer participation: two that are
dispatched via direct-load control devices and a third manua! interruption option that
does not utilize a direct-load control device, but rather relies on participants to manually
interrupt their loads when notified of an event.
During the 2014 season, ldaho Power's DR Programs were all utilized, with each
program being dispatched three times. The chart below represents the estimated
demand reduction achieved on July 14,2014, when all three programs were dispatched
on the same day. The nighttime and daytime temperatures that day were 73 and 103
degrees, respectively. The estimated reduction was based on real-time forecasting of
the system loads, and based on that estimate, the DR Programs provided
approximately 375 MW of peak load reduction.
Systrm Loed
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Applicabilitv
ldaho Power's research indicates that NERC and WECC standards would allow the use
of DR as a non-spinning reserve. ln order to be compliant with the standards, ldaho
Power must ensure that it is able to: (1) accurately measure the amount of reserves
claimed, (2) guarantee all reserves are activated within 10 minutes, and (3) maintain
documentation to be provided during a NERCMECC audit.
ln order to ensure that the DR resource would perform as required when dispatched to
provide CRO, the Company would require that a program be designed and
implemented for a two-year period in order to ensure that the amount of CRO expected
to be provided by the DR resource can be achieved 100 percent of the time in the
required timeframes. The Company believes that for it to be able to depend on DR to
provide all or a portion of CRO when needed, sufficient testing must be done to ensure
deliverability of the load reduction that DR would provide under various system
conditions. As noted earlier, the average CRO required by ldaho Power over the most
recent 12 months was 113 MW, and for the Company to understand how it could use
DR to meet a portion of that requirement, it would need to gain enough data during that
two-year period to determine how much DR it could confidently integrate into the overall
CRO requirement.
Further, to ensure compliance with the above-mentioned standards, if it were to use DR
as part of its CRO, ldaho Power would require that its Real-Time Operators
("Operators") will have direct control over the resource. As system events occur, the
Operators are evaluating system conditions to determine the appropriate action to take,
and as the Operators execute these actions they are re-evaluating in real-time to ensure
that the expected results are accomplished. By having direct-load control over the
resource, the Operators can ensure that the expected load response occurs in time to
comply with the NERC regulations, and in the event the expected load response does
not occur, the Operator will immediately take additional actions to comply with the
regulations. All of the Operators' actions are critical to maintaining the reliability of the
electrical grid, and most importantly, all must be executed within a 10 minute period.
Lastly, ldaho Power is required to maintain auditable documentation to be provided to
NERCA /ECC, as requested at any time. At a minimum of once every three years,
audits of this documentation are conducted by WECC, NERC, and occasionally FERC.
lmplementation Gonsiderations
Based on the requirements discussed earlier, the Company evaluated its current
operations, systems and limitations to identify what modifications would need to be
made to use DR as CRO. The Company also analyzed each of its three DR programs
to determine the ability to use each as CRO and whether or not that program was a
possible "fit" for providing CRO. ln considering each program, the Company looked at
several factors, including: whether or not there was a direct-load control device
installed as a requirement of the DR program, the ease or difficulty of forecasting the
demand reduction achieved by the program, the number of hours/days the DR program
would be available as CRO, the size of the DR program in MWs and number of
participants, and program participant notification requirements.
Operation System Modifications
The Company's existing Load Serving Operations' ("LSO") systems would need to
undergo significant upgrades to be able to incorporate the use of DR as CRO. These
upgrades include integration of the dispatch system(s) for each program to the Energy
Management System ("EMS") and development of a fully integrated DR forecasting tool.
The EMS network consists of one or more control centers and Supervisory Control and
Data Acquisition ('SCADA') connections to many field locations, typically substations.
Field equipment takes measurements and sends data back to the control center to
provide situationa! awareness to Operators. Those Operators have the ability to control
field equipment through the SCADA network. Because the current EMS is not
integrated with the other communication systems necessary to dispatch any DR
resource, modifications would be required. !n order to respond within the required 10
minute period, the Operator needs a specific tool that presents the forecasted load for
any DR providing CRO. The current forecasting tools for all three of the Company's DR
programs do not provide day ahead or real-time components, only a weekly generalized
forecast. System modifications would be required to ensure that the forecast of DR on
the system is being constantly updated with the most current data available. The
updated systems would need to be able to quickly determine how much load reduction
is achieved from DR and to continually update the forecast that the Operators are
relying on for optimum accuracy.
NC Cool Credit
The A/C Cool Credit program provides approximately 33 MW of load reduction if
dispatched when temperatures are near 100 degrees throughout the program's season
of June 15 through August 15. The program requires the installation of direct-load
control devices as a provision of participation, which means the Company could utilize
existing infrastructure if it determined the program was viable to use as CRO. The
program currently uses one system to dispatch all events, so any necessary LSO
system modifications would only require integration with that one system.
The current program cycles A/C units off and on between June 15 and August 15, but
the Company believes that its A/C load could only provide substantial and reliable load
reduction during certain hours of certain days during that time period. The program
season could be expanded, but likely would not provide very much benefit due to the
reduced A/C load during much of the summer.
There are many factors that influence the amount of load reduction the Company may
experience during an event, including the temperature on the day of the event, the
daytime and nighttime temperatures of the days leading up to the event, the time of day
the event is called, and the amount of cycling (percent of time the unit is off) that is
utilized. Generally, the Company would anticipate receiving about one kilowatt ("kW")
per participant on a 100 degree or higher day, so long as those A/C units were on at the
time of the event. Based on these factors, the amount of load available for CRO from
the A/C Cool Credit program would be small and would vary dramatically hour by hour
and day by day.
ln addition, because customers have the ability to "opt out" of a single event, or the
entire program at anytime, the Company and its contractor must be staffed during
events to receive participant inquiries. Extending the program for its use as CRO would
likely increase the labor costs of the program because the program could be called as
CRO outside of normal business hours when the Company and its contractor currently
do not have adequate staff available.
FlexPeak Management
The FlexPeak Management program provides approximately 38 MW of load reduction
during events called throughout the program's season of June 15 through August 15.
While the third-party aggregator does have a handfu! of sites where there are direct-
load control devices installed, most customers are in control of curtailing their own load
at a participating site, and ldaho Power does not have direct control over any of the
devices. For this reason, it is not feasible to consider the FlexPeak Management
program for use as CRO, due to the requirement that Operators have direct control over
the resource and that the resource must be fully dispatched within 10 minutes of an
event starting.
I rrigation Peak Rewards
The lrrigation Peak Rewards program provides approximately 319 MW of load reduction
during events called throughout the program's season of June 15 through August 15.
lrrigation Peak Rewards has three options for customer participation: two that are
dispatched via direct-load control devices (approximately 240 MW) and a third manual
interruption option that does not utilize a direct-load control device, but relies on
participants to manually interrupt their loads (approximately 60 MW).
The program is currently structured to be used between June 15 and August 15, but the
Company believes that its irrigation load could provide potential load reduction from
mid-April through the end of September. lrrigation load typically runs at all hours of the
day, so the Company believes that logistically, it is reasonable to expect lrrigation Peak
Rewards could provide some Ievel of CRO at most all hours of the day during the
identified time period, (although this is difficult to predict based on the unpredictability of
weather and the variability of crop characteristics). The Company believes it would be
complicated to forecast the irrigation load available in the program for CRO each hour of
each day throughout the irrigation season, but with modifications to the existing systems
it could be done.
Lastly, because the Company would require that direct-load control devices are used to
curtail load, only the first two options would be viable for consideration of the program
as CRO. Based on current participation in the program, these two resources have the
ability to provide approximately 240 MW of load curtailment.
Evaluatins DR as a CRO
Cosfs
ln order to provide Operators with a tool to effectively and reliably use DR as CRO,
several modifications to the Company's existing technological infrastructure would be
required. The current system configuration is not set up to directly dispatch DR in the
timeframe necessary. The system modifications described below would enable the
Operators to dispatch the DR resource within 10 minutes, as required by the WECC
Reliability Standard BAL-002-WECC. The current system would also require a fully
integrated real-time forecasting component necessary to assist the Operators in
accurately determining the expected hourly DR load reduction.
o Modify the existing EMS to ensure the capability to dispatch the DR resources,
providing visibility to Operators of availabb DR resources and with the ability to
easily dispatch those resources in a timely manner. Estimated Cosf; $50,000o Develop or procure an application that accurately forecasts on an hourly basis
the currently available DR on the ldaho Power system. Estimated Cosf;
$300.000o Develop or procure an application that receives the request to dispatch DR
resources and determines the specific points of service to curtail. Estimated
Cosf: $75.000o Develop an application to enable the rapid and reliable dispatch of the
appropriate DR resources. Currently, the systems used to dispatch DR reside
on different networks and utilize different databasesldata structures. The
Company would need to ensure that information will be passed both securely
and reliably between these systems. Estimated Cosf; $90,000
Based on the required modifications, the total minimum upfront cost is estimated to be
$475,000;however, the cost associated with the forecasting application could be higher
depending on the specific DR programs that are selected. ln addition to the upfront
costs, there would be ongoing, annual costs associated with maintaining the upgraded
and new systems. The annual cost associated with software maintenance and support
is estimated to be $95,000, based on similar technology system projects that ldaho
Power has completed and currently maintains.
It is expected that the life of the application wi!! be approximately eight years before
technology changes would require that it would have to be replaced or upgraded. lt is
projected that the cost of replacement or upgrade in eight years will be $150,000.
The projected timeline for implementing the modifications outlined above would be
approximately six months to a year. This timeframe would provide for the ability to
develop and verify the forecast, as well as providing adequate time to develop, test, and
implement the other applications and integrations.
As discussed in the Applicability section above, in order to ensure that the DR resource
would perform as required when dispatched to provide CRO, the Company would
require that a program be designed and implemented for a two-year period of testing.
Because ldaho Power would continue to utilize the resources that it currently uses to
11
provide CRO during this testing period, the benefits of making these reserves available
does not occur until the third year.
Benefits
To identify the potential benefits associated with using DR as CRO, the Company
performed an analysis to quantify the dollar value of its CRO. The Company assumed
levels observed during the 2012 Water Year (October 2011 through September 2012)
for multiple system parameters, including system Ioad, Mid-C prices, and natural gas
prices. Water Year 2012 was selected for these parameters because the Snake River
basin observed median-type stream flow conditions during Water Year 2012. Based on
those assumptions, the Company conducted a study to determine the maximum dollar
value of its CRO during a time period that DR could conceivably provide CRO. The
time period utilized in the study assumes that DR could be available from mid-April
through the end of September and valued the CRO during this time period at three
different levels:
Results:
o Value of all of the non-spinning reserves. Estimated Value: $578,212o Value of half of the non-spinning reserves. Esfimated Value: $363.678. Value of all of the heavy load hours non-spinning reserves (Monday through
Saturday, 7 AM through 11 PM) Estimated Value: $518.979
The following chart represents the Company's total CRO during the time period studied.
The maximum non-spinning portion of CRO identified by the Company's analysis was
96 MW.
CRO Obligation
200
180
r"60
140
0 LzA
E roo
=80
60
40
20
o
""-f -tf ,-f '-g t-g "-g -.9 "-g .-g arf .-f "-gDate
Financial Analysis
The Company used the costs and benefits identified above to calculate an estimated
annual levelized benefit and net present value of using DR as CRO. The annual
levelized benefit amount is what the Company believes is the maximum incremental
amount it could incur on an annual basis to use DR as CRO (for example to pay
program incentives to participants or for program expenses), without financially harming
other customers. ln other words, if the annual levelized benefit amount was input in the
financial analysis as an annual expense, the resulting net present value would be zero.
The Company analyzed two scenarios for the lrrigation Peak Rewards program and a
third scenario for the A/C Cool Credit program, which are presented below.
Based on the financial analysis performed for this Report, if the lrrigation Peak Rewards
program were to provide all of the non-spinning reserves required from mid-April
through September 30th at a 90 percent availability level,l2 the maximum incremental
amount that Idaho Power could incur for participant incentives or program expenses
would be $385,900 on an annual levelized basis. lf the lrrigation Peak Rewards
program were to provide all of the non-spinning reserves required during only heavy
load hours from mid-April through September 30th at a 90 percent availability levet, the
maximum incremental amount that ldaho Power could incur for participant incentives or
program expenses would be $336,400 on an annual levelized basis.
A current participant in the lrrigation Peak Rewards program receives an annual
incentive of approximately $16 per kW of demand, which includes three dispatch events
per season. For dispatch events beyond the first three, participants receive an energy
payment based on the amount of demand reduction they are expected to provide during
each dispatch event. lf the Company were to design a program to be used as CRO, it
would propose paying participants only fixed payments. The fixed payment structure
would ensure that the Company does not make payments exceeding the annual
levelized benefit amount. Additionally, because the CRO program would have an
unknown and potentially unlimited number of events, the Company believes it would be
imprudent to structure a program with a variable payment that would have the potential
to exceed tota! benefits.
Using the scenario above where lrrigation Peak Rewards provides a!! of the non-
spinning reserves required from mid-April through September 30th at a 90 percent
availability level, the maximum amount the Company could design a program for is
$385,900 on an annual levelized basis. This program would seek to achieve up to 96
MW of CRO and translates to a maximum $3.00 per kW of potential incentive.l3 The
t'The Company does not believe it is reasonable to expect the lrrigation Peak Reward or AlCCool Credit programs
could provide 100 percent of the Non-Spinning reserves during the time studied. Ninety percent was selected to
account for times when the programs would not be available due to factors such as mild temperatures and
consecutive days of rain that would significantly impact whether participants would have irrigation pumps or NC
units turned on.
tt For purposes of this report, the Company did not estimate total program costs to run a new CRO program. The
actual amount available for participant incentives would be net of any program expenses incurred.
13
Company does not believe its irrigation customers would participate in a program that
would have unlimited dispatch events, during all hours of the day, for only 20 percent of
the incentive that the current lrrigation Peak Rewards participants are receiving from the
traditional DR program.
Similarly, based on the financial analysis performed for this Report, if the A/C Cool
Credit program were to provide approximately 35 percentla of the non-spinning.reserves
required during only heavy load hours" from mid-April through September 30th at a 90
percent availability level, the maximum incremental amount that ldaho Power could
incur for participant incentives or program expenses would be $54,600 on an annual
levelized basis. Under the current A/C Cool Credit program design, a participant
receives an incentive of $15 per season, for no more than 60 hours of potential A/C
cycling. Using the calculated annual levelized value of $54,600, the maximum ldaho
Power could offer a participant in a CRO program is approximately $1.80 per season.16
Here again, the Company does not believe its residential A/C customers would
participate in a program that would have unlimited dispatch events for only 12 percent of
the incentive that the current A/C Cool Credit participants are receiving from the
traditional DR program.
Rrsks
Company Risk
It is critical to Idaho Power and the reliability of the BES that any CRO it maintains will
undoubtedly perform as expected when it is dispatched, and the risks associated with
not having a resource perform as projected cannot be understated. ln the event that
CRO is not responsive when activated, the Company is exposed to FERC, NERC, and
WECC compliance violations as well as BES reliability issues that could negatively
impact the electrical interconnection.
Part of the Operators' responsibly is to maintain system reliability, which is
accomplished by various methods including the ability to shed firm load. The reliability
to all of ldaho Power's customers could be impacted if a CRO resource does not
perform when dispatched because the Operator may be required to activate the Load
Curtailment and lnterruption Procedure,lT which could negatively impact some or al! of
Idaho Power's customers.
'o The 35 percent was selected based on: (33 MWs of potential program load reduction / gO fuws maximum CRO
required during this time).
" Because approximately 83 percent of residential A/C use occurs during heavy load hours, the Company did not
calculate the annual levelized benefit derived from using an A/C program during all hours.
" For purposes of this report, the Company did not estimate total program costs to run a new CRO program. The
amount available for incentives would be net of any program expenses incurred.
" l.P.U.C. No. 29, Tariff No. 101, Rule J, Continuity, Curtailment and lnterruption of Electric Service, Original Sheet
No. J-1: "Load curtailment and interruption carried out in compliance with an order by governmental authority
shall follow the Company's plan entitled "Load Curtailment and lnterruption Procedure," as filed with and
approved by the Commission."
14
lf unable to adhere to the NERC BES reliability standards, the Company could be
exposed to significant fines, which could have a financial impact to the Company and its
customers, with the most severe fines of $1,000,000 per occurrence or violation, per
day.
DR Proqram and Participant Risk
Idaho Power's DR Programs provide both economic and operational benefits to the
Company and its customers, and continuation of these programs is important to
meeting one of the main objectives of the Company's Demand-Side Management
objectives of providing demand reduction as determined through the lRP planning
process. The DR Programs are identified in the IRP to help meet potential peak
demands caused by extreme conditions in the summer, and the programs are relied
upon to serve load and delay the need for building new peaking resources. The
Company believes that the risk of impacting its current DR program participation levels
is a critical component in the discussion of the overall feasibility of using DR as CRO.
As noted earlier in this Report, it should be emphasized that ldaho Power cannot predict
or forecast when it will call on its CRO. Based on the historical data, it is clear the
number of events can vary widely, with the number of times CRO was called on in the
years of 2009 through 2013 ranging from 63 to 82. However, while those events should
not be relied on to predict future events with any degree of certainty, the Company
believes it is reasonable to assume that DR participants participating in a reserve-type
program would be interrupted far more frequently that DR participants participating in a
traditional DR program.
NC Cool Credit
The Company believes that anytime it dispatches a DR event and cycles a participant's
A/C unit off and on, there is a risk that the temperature in the participant's home will
increase, creating discomfort and potentially some dissatisfaction with the program.ls
This effect would be amplified if an event were to be called twice on the same day, or
even on high temperature consecutive days, as the home's A/C unit may not have been
able to catch up from the first event. The Company believes that increasing the number
of events a participant is exposed to through the combination of traditional DR A/C Cool
Credit events and CRO events seems likely to decrease customer satisfaction, which
could inevitably lead to customers opting out of the program. Losing participants both
decreases the amount of DR the program is able to provide and places additional costs
on the Company as most participants who opt out of the program insist on having the
installed device removed.
tt On Monday, July L4,2OL4, the Company called an A/C Cool Credit cycling event lasting three hours between
4:00 PM and 7:00 PM. The high temperature that day was 103 degrees. The Company received 63 phone calls
from participants during the event and L27 calls from participants the day after the event. 117 participants
decided to "opt out" of the program, effectively ending their participation in the program.
15
lnigation Peak Rewards
Based on the number of times that ldaho Power calls on its CRO, the Company does
not believe its irrigation DR Program participants would be willing to accept the
unpredictability and number of interruptions that may occur in a given season. The
potential number of interruptions (past data shows 63-82 times per year) exceeds what
the Company believes an irrigation DR Program participants would tolerate without
becoming very frustrated. Manual restarts of the irrigation pumps are utilized for
roughly 50 percent of the systems currently enrolled in the program, and even for the
participants who have an automatic re-start, the Company believes several of these
participants manually check their irrigation systems for proper operation after any type
of interruption. As discussed more fully above, ldaho Power calls on its CRO all days of
the week at all hours of the day, which might mean that an irrigator would have an
interruption that would require a manua! restart or check in the middle of the night.
Further, because the number of events called per day and duration of those events is
unpredictable, participants could be negatively impacted. ln fact, several short events
are probably more disruptive to the typica! irrigation DR Program participant than a
single four hour event, as allowed under the current DR program parameters.
RECOMMENDATION
Based on its analysis, ldaho Power believes the operational and compliance risks
outweigh the benefits to utilize DR as CRO because: (1) the economic benefit of using
DR as CRO is too small to provide incentives at a level that would attract participation
and provide for program costs, (2) the risks for failure to meet NERC standards is far
greater than the economic benefit that might be derived, (3) the period of testing that
would be required to provide operational certainty of compliance with NERC and WECC
requirements would require carrying substantially more than the reserves actually
needed for contingency, at a cost to all customers, and (4) the number of CRO events
would put too heavy of a strain on the DR participants, thus risking participation in the
Company's DR Programs.
The economic benefits, excluding payments to participants, of using DR as CRO are
insignificant when compared to the capacity benefit the current DR Programs provide,
and while having a dual-purposed program may be conceivable from a technical and
compliance perspective, the Company believes that it is not practical from an economic
and program participant perspective. The Company believes that the economic, DR
program participation and other operational risks identified in this Report are too great to
proceed with a pilot at this time. Therefore, the Company believes that it is not feasible
to utilize its DR Programs for CRO.
16