20110210Comments.pdf

WELDON B. STUTZMAN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
(208) 334-03 1 8
IDAHO BAR NO. 3283
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Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY FOR APPROV AL )
OF REVISIONS TO THE IRRGATION PEAK )
REWARDS PROGRAM, SCHEDULE 23. )
)
)
)
CASE NO. IPC-E-IO-46
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission, by and through its Attorney of
Record, Weldon B. Stutzman, Deputy Attorney General, submits the following comments in
response to Order No. 32 1 58 issued on January 12, 2011.
BACKGROUND
On December 10, 2010, Idaho Power Company fied an Application requesting approval
of changes to its Irrigation Peak Rewards Program (Schedule 23). The program is a voluntar
load control program available to agricultual irrigation customers and is used to decrease the
Company's system summer peak by interrpting service to specified irrgation pumps during
June 15 through August 15. Under the program, the Company interrpts specified irrigation
pumps any Monday through Saturday between the hours of 1 :00 p.m. and 8:00 p.m. The
Company uses either dispatchable or timer-based load control devices to interrpt selected
STAFF COMMENTS 1 FEBRUARY 9, 2011
pumps for a limited number of hours. In exchange for allowing the Company to interrpt
electric service, paricipating customers receive a monthly monetar payment in the form of a
bil credit for usage that occurs during June, July and August.
Based on a Company review conducted during 2010, Idaho Power is proposing to:
(1) Change the incentive payment structue for Dispatchable Options 1,2, and 3 from a fixed
incentive payment to a combination of a fixed and variable incentive payment;
(2) Pay the variable portion of the incentive by check after the end of the Program season;
(3) Modify the Dispatchable Option 3 requirements to fit the proposed payment structure;
(4) Change the opt-out penalty to $1.00 per kW for Dispatchable Options 1,2, and 3;
(5) Extend the interrptible period from 8:00 p.m. to 9:00 p.m. on a voluntary basis;
(6) Implement one program test event per season that is not subject to a variable payment;
and,
(7) Add language specifying that Program paricipation may be limited based on the
Company's need for peak load reduction.
The Application states that the proposed program modifications reflect a collaborative
process between Idaho Power and the Idaho Irrigation Pumpers Association, the Commission
Staff, the Energy Effciency Advisory Group, and the Integrated Resource Plan Advisory
CounciL. The Company states that the program as revised would more closely align the program
incentives with the Company's need for demand response.
STAFF ANALYSIS
The following comments discuss Staffs long-term objectives for demand response
programs, and Idaho Power's proposal to align the design of the Irrigation Peak Rewards
Program (Schedule No. 23) with the Company's varing need for demand response programs.
Staff reviewed the Company's Application and corresponding testimony, and has serious
concerns with the proposaL.
Staff's Objectives for Demand Response
Demand Side Management (DSM) programs taget overall conservation and efficiencies
in energy usage, where demand response programs specifically target usage patterns during
system peak. Demand response programs are dispatchable in a short period of time, are reliable
as a firm load resource, and are inexpensive compared to the cost of an additional resource to
STAFF COMMENTS 2 FEBRUARY 9, 2011
meet peak loads. Staff believes cost-effective demand response is the best way to directly reduce
peak demand and defer additional investment in peaking resources. Without prudently
administered, cost-effective demand response during periods of system peak, utilties would have
to rely on expensive market purchases or invest in additional system generation to meet peak
load. According to the Company's testimony, "If not for the Program, growing sumer peak
loads would likely require the construction of additional simple cycle gas peaker capacity to
meet system peak a few hours each year." Pengily Direct, p. 4, L. 1-14. Staff believes that
similar to a simple cycle gas peaker, the Irrigation Peak Rewards Program should be viewed as a
reliable, long-term resource when planning future resources. This is consistent with the
Company's approach to valuing the Program in past Integrated Resource Plans (IRP). Staffs
objectives for the Program are that it be cost-effective, that anual paricipation remains stable,
that the incentives avoid unecessary complexity, and that the operational potential of the
Program be fully utilzed.
Company's Proposal
Every year Idaho Power evaluates the Irrigation Peak Rewards Program's cost-
effectiveness, operational efficiency and customer satisfaction. However in 2010, the Company
enhanced its anual review to assess the Program's design to insure it remains consistent with
the need for demand response identified in the Company's Integrated Resource Plan. The
proposed Program modifications are a direct result of that review. Pengily Direct, p. 6, L. 14-15.
Staff evaluated the Company's enhanced anual review and all of the Program modifications.
These are discussed in varying detail below.
Change the Incentive Payment Structure
Staff analyzed the Company's proposal and supports changing the incentive structure
from a fixed incentive payment to a combination of fixed and variable incentive payments. The
split incentive captures the Program's operational similarities to a peaking supply side resource.
However, Staff disagrees with the Company's proposal to base the fixed and variable incentive
payments on the short term variations in needed demand response. The Company should
consider designing the incentive payments with the objective of developing the Program into a
long-term reliable resource, with consistency from year to year so participation levels do not
drop.
STAFF COMMENTS 3 FEBRUARY 9, 2011
Staff is concerned about the Company's proposal given the potential magnitude of the
reduced incentive, the lack of justification for the new credit level, and the lack of research
completed to support the Company's anticipated impact on customer participation. When
compared to the curent structure, the proposed change in incentive structure adversely impacts
the economic decision to call an event.
Staff believes the Company has not demonstrated that it currently captures the economic
value of the Program. If this proposal had been in place during the 2010 season, the Company
would have only utilzed the test event, whereas under the current structure it actually called
three events. Idaho Power would have paid out $4.6 milion in incentives instead of $ 11.5
milion (Staff Production Request No.8). The Company stated that it "anticipates that the
proposed level of fixed incentive wil be adequate to retain current participants." Pengily
Direct, p. 17, L. 5-7. As par of Production Request No.6, Staff asked the Company to describe
its studies, reviews, or market research used to support this conclusion. The Company was
unable to provide any indication that the proposal will be adequate to retain current paricipants.
Idaho Power should proactively conduct studies to determine how changes might impact the
Program, so there is a better understanding of how Program participation wil change. The
Company should also consider setting the incentive level during the first year at a level that
minimizes the risk of losing participants. This would give the Company an opportunity to
gradually evaluate the impact of Program changes on paricipation levels.
In addition to the stated concern over future paricipation, Staff disagrees with the
Company's approach for determining the fixed incentive because it fails to value the Program as
a long-term resource. The Company's proposal was developed by comparing its forecasted load
duration curves to its existing and committed resource capacity during the highest 60 hours. The
results of the comparison showed a variation in needed anual capacity of 50% over the next five
years, primarily due to the addition of Langley Gulch Power Plant. In order to align the Program
with the forecasted variation in needed demand response, the Company allocated 40% of the
total incentive for paricipation, and 60% based on Program utilzation. A paricipant wil
receive 40% of the curent incentive if the Company has no demand response events, and will
receive 106% of the current incentive if the Company fully utilized the Program's 60 hours.
According to the Company's response to Staffs Production Request No.5, the Company plans
on making future decisions about the incentive structure after doing a demand response needs
assessment from upcoming IRPs. This short-term approach introduces volatilty in credit
STAFF COMMENTS 4 FEBRUARY 9, 2011
valuation and Program paricipation as the Company looks to make modifications bianually,
when each IRP is fied. Staff believes the Company should continue to use an avoided peaking
resource methodology to determine fixed incentives over the long-term, as it has in the
determination of cost effectiveness. The long-term investment in demand response is analogous
to the operational characteristics and investment in a simple cycle combustion turbine. The
proportion of fixed costs necessary to build and operate a simple cycle peaking plant would be a
more appropriate guideline for determining the proportion of fixed Program incentives.
Payment of the Variable Incentive
If variable incentive payments are established, Staff believes it is reasonable to pay at the
end of the season, but the Company may want to consider paying the variable portion as quickly
as possible following the end of the Program season. The Company curently pays a fixed
incentive amount regardless of how often the Program is used during the biling period or season.
With the Company's proposal to go from a fixed incentive payment to a combination of a fixed
and variable incentive payment, the Company proposes paying the variable portion no more than
60 days after the August 15th end date of the Program. It states that this wil "avoid issues with
its biling system" and "highlight to the paricipants that they are paid the fixed incentive through
the bil credit and that the variable portion of the payment is based on the amount of time the
Program operates." Pengily Direct, p. 23 & 24, L. 20-23 & L. 1 -2. Staff does not support the
Company's proposed levels of fixed and varable incentive payments.
Dispatchable Option 3 Modifcations
The Company is proposing three modifications to Dispatchable Option 3. The
modifications support its proposed incentive payment structure, and make the Program a more
reliable resource. Specifically, the Company's proposal:
(1) Requires paricipants to nominate their load reduction;
(2) Changes the opt-out policy; and
(3) Changes the baseline from which paricipants' load reduction is calculated.
STAFF COMMENTS 5 FEBRUARY 9, 2011
Assuming a fixed and variable incentive structure was appropriately established, Staff
would support the Company's proposal requiring paricipants to nominate their load reduction.
This makes calculating the fixed portion of the proposed incentive structure possible, and allows
the Company to better plan its capacity during interrptions. Dispatchable Option 3 paricipants
curently have the option to provide varying portions of curailment durng each particular event,
so determining the appropriate fixed incentive payment under the Company's proposed incentive
structure is impossible. The Company has proposed that participants nominate demand prior to
June 1 st of each year so it can determine the fixed incentive to pay participants. The Company
has also proposed that participants nominate demand because the current method of calculating
the Demand Credit absent any events, could result in a larger amount than if an event actually
occured. When there are no events during a billng period, the curent Demand Credit is
calculated based on maximum demand during the biling period, whereas when an event is
called, it is calculated based on maximum demand 24 hours prior to an event. When maximum
demand during a biling period is used to determine the Demand Credit instead of the period
immediately preceding an event, the Demand Credit potentially pays for more capacity than the
Company would receive during an event. Staff believes the Company's proposal to use
participants' nominated load reduction in the absence of an event would more accurately reflect
their contribution to the Program during an event. Similar to Dispatchable Options 1 and 2, it is
reasonable to have paricipants nominate demand prior to the Program season.
Staff also believes it is reasonable for paricipants to pay an opt-out penalty under an
appropriately established fixed and variable incentive structure. Given the proposed incentive
structure without an opt-out penalty, paricipants would receive a fixed payment for capacity
they may not provide. Idaho Power proposes changing the opt-out policy to support the
proposed incentive structure. Dispatchable Option 3 curently does not have an opt-out penalty
because paricipants provide varing curtailment amounts durng each paricular event. The
proposal applies an opt-out penalty to the difference between what was provided and what was
nominated. Absent an opt-out penalty, a paricipant may not completely curail what is
nominated during an event, but would stil receive the fixed incentive based on the nomination.
Staff recommends the Commission deny the Company's proposal to calculate the
baseline using the 1 2-hour night time period (l 0:00 p.m. and 11 :00 a.m.) prior to an event. The
Company's rationale behind the proposal is to limit gaming by participants in order to receive a
larger credit. However, since the Company provides paricipating customers notice of a pending
STAFF COMMENTS 6 FEBRUARY 9, 2011
load control event by 4:00 p.m. MDT on the day prior to each event, the Company's proposal
would inaccurately capture normal usage. If customers increase their overnight usage in
anticipation of being curailed the following day, the load reduction estimate might be too high.
However, if paricipants begin to shut down early in anticipation of being curtailed, the load
reduction estimate might be too low. Staff agrees with the Company that the curent way of
calculating paricipants' load reduction could overestimate normal usage because it is based on a
single spike in usage, but Staff disagrees that the proposal would result in a more accurate
estimate than the current method.
Paricipants' load reduction is curently calculated by subtracting the average demand
during an event from the baseline, defined as maximum demand 24 hours prior to an event. The
curent and proposed baseline is calculated using the period prior to an "event" and not prior to
the "event notification." Staff believes this may exacerbate the problem of paricipants spiking
usage following the "event notification" to receive a larger payment. In a future proposal, the
Company may want to consider using the day prior to the event notification, by averaging
paricipants' usages over the same period in which the actual event occurred. If two consecutive
event days were called, baseline could be calculated using the day prior to the first event
notification, by averaging usage over the full time period both events occurred.
Opt-out Penalty
After Staff analyzed the Company's proposal to change the opt-out penalty for
Dispatchable Options 1 and 2, Staff believes that it is reasonable given the objective of the
Program. As mentioned above, under an appropriately established fixed and variable incentive
structure, Staff believes it is reasonable for Option 3 participants to have an opt-out penalty
similar to Dispatchable Options 1 and 2. The proposed penalty wil also "make it easier for
customers to estimate what an opt-out is going to cost ahead of time, which could influence their
decision to opt-out." Pengily Direct, p. 19, L. 12-15. Staff compared the current $0.005 per
kWh opt-out penalty to the proposed $1.00 per kW opt-out penalty given a number of scenarios,
and found the proposed opt-out penalty is lower and easier to calculate. If Idaho Power called
the maximum number of hours during the Program Season and a participant did not provide the
entire nominated kW during five events (the total allowed per biling period), the penalty would
never exceed 100 percent of the credit.
STAFF COMMENTS 7 FEBRUARY 9,2011
Extending the Interruptible Period
Staff supports the Company's proposal to extend the interrptible period from 8:00 p.m.
to 9:00 p.m., however Staff proposes extending the interrptible period on a mandatory basis.
According to Staffs analysis of the Company's load duration study, to fully utilize the
operational impact of the Program, it is necessary for the Company to extend the interrptions
beyond 8:00 p.m. As explained in testimony, ideally a "flat load shape during the demand
response program operational period would indicate that 100 percent of the demand reduction
provided by the programs is avoiding the need for capacity rather than something less than 100
percent that would exist under the 'trough effect'." Pengily Direct, p. 7, L. 16-24.
The Company proposes paying the "Extended Interrption" customers $0.05 per kWh
more than the "Standard Interrption" during every interrption. The Company's additional
incentive for the "Extended Interrption" was determined based on its theoretical 201 1 dispatch
during the extended hour, and the estimated incentive necessary to encourage paricipation. Staff
asked the Company to provide supporting executable workpapers ilustrating how it arived at
the "Extended Interrption" amount, but it was unable to provide any information. Even though
the Company's theoretical 2011 dispatch during the extended hour is low, Staff believes that
absent any underlying data to estimate paricipation, the Company's proposal is merely a staring
point to evaluate paricipation.
If Staffs proposal to extend the interrptible period on a mandatory basis is adopted, the
Company should closely monitor paricipation. If the level of participation drops, and paying
more for an additional hour of interrption is cost-effective, the Company should consider
increasing the incentive. Staff believes to fully achieve the operational impact of the Program, it
is necessary for the Company to require that paricipants extend the interrptions to 9:00 p.m.
One Program Test Event
Staff supports the Company's proposal to include one Program test event per season.
The Company currently tests its dispatchable control device communication prior to each season,
but does not implement a full pre-season interrption to test every aspect of the Program. Staff
believes it is important for the Company to test the reliabilty and timeliness of interrptions.
This provides assurance that the capacity wil be available when needed. In this proposal, the
Company includes one Program test event per season that is not subject to a variable payment. If
variable incentive payments are established, Staff also believes it is reasonable that the test event
STAFF COMMENTS 8 FEBRUARY 9, 2011
not be subject to a variable payment. Testing the Irrigation Peak Rewards Program is different
than testing supply side resources where the Company may be able to capitalize on economic
benefits. Testing the Irrigation Peak Rewards Program must happen prior to the star of the
season when market prices for energy are typically low, and the Company is less likely to
capture economic benefits.
Limiting Program Participation
Staff recommends the Commission deny the Company's proposal to add language to the
"Availabilty" section of the proposed tariff limiting Program paricipation based on its need for
peak load reduction. Every year Idaho Power models the Program's cost effectiveness over a
20-year period by looking at future financial and Demand-Side Management alternative costs.
As reported in the Demand-Side Management 2009 Annual Report, the current Programs benefit
cost (B/C) ratio was 1.50 over a 20 year planing period. Even with the Company's proposed
changes, the Company tested numerous Program scenarios where the B/C ratios were greater
than one. As long as the Irrigation Peak Rewards Program has a B/C ratio greater than one, it is
not clear why paricipation should be limited, paricularly since it wil cost effectively help delay
future plant investment. Demand response is intended to avoid the next power plant. If the
Company has a short-term view of demand response and decides to limit the Program's growth
because of short term variations in its need for peak load reduction, rate payers wil be left
paying for more expensive generation earlier than they otherwise would. The Company should
not only accept, but promote paricipants in the Program in order to achieve peak load reduction
over the long term.
STAFF RECOMMENDATION
Staff believes that most of the Company's proposed Program changes may have merit,
but since Staff disagrees with the Company's proposed fixed and variable incentive levels that
propagated the changes, Staff can only support and recommend Program changes in the
following areas:
(1) Changing the opt-out penalty to $1.00 per kW for Dispatchable Options 1 and 2;
(2) Extending the interrptible period to 9:00 p.m. on a mandatory basis; and,
(3) Implementing one program test event per season.
STAFF COMMENTS 9 FEBRUARY 9,2011
Respectfully submitted this
Technical Staff: Matt Elam
i:umisc:commentsipc i 0.46wsme.doc
STAFF COMMENTS
day of February 2011.
~)(1:~4MA
.4 cl B~tutzman '"
JI Deputy Attorney General
10 FEBRUARY 9, 2011
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 9th DAY OF FEBRUARY 2011,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. IPC-E-I0-46, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
LISA D NORDSTROM
DONOV AN E WALKER
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: lnordstrom(fidahopower.com
dwalker(fidahopower.com
GREG SAID
SCOTT SPARKS
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: gsaid(fidahopower.com
ssparks(fidahopower .com
~.KM
SECRETARY
CERTIFICATE OF SERVICE