20130301Comments.pdf

KARL T. KLEIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
P0 BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 5156
PIE 0
PM 2:29
DAH
-t
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 PACIFICORP DBA
ROCKY MOUNTAIN POWER'S
APPLICATION FOR AUTHORITY TO
CANCEL ELECTRIC SERVICE SCHEDULE
NOS. 72 AND 72A IRRIGATION LOAD
CONTROL TARIFFS AND APPROVE A NEW
DEMAND SIDE MANAGEMENT CONTRACT
CASE NO. PAC-E-12-14
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission comments as follows on the
Application of PacifiCorp dba Rocky Mountain Power ("Company") to cancel Electric Service
Schedule Nos. 72 and 72A Irrigation Load Control tariffs and approve a new Demand Side
Management contract.
BACKGROUND
On December 7, 2012, PacifiCorp dba Rocky Mountain Power (the "Company") applied
to the Commission for an Order: 1) authorizing it to cancel Electric Service Schedule 72,
Irrigation Load Control Credit Rider, and Electric Service Schedule 72A, Dispatchable Irrigation
Load Control Credit Rider; and 2) approving a new demand-side management (DSM) agreement
(Contract) with third party aggregator, EnerNoc, Inc., for delivery of the irrigation load control
program. The Company initially asked for the changes to take effect on February 1, 2013,
STAFF COMMENTS 1 MARCH 1, 2013
Application at 1 and 12. Subsequently, the Company agreed that the proposed effective date
should be suspended during these proceedings. The intervening parties, Staff, and the Company
agreed that the case may be processed using Modified Procedure with a March 1, 2013 comment
deadline.
STAFF ANALYSIS
The Irrigation Load Control Program (ILCP) has been a valuable resource for the
Company, participants, and customers for the past decade, though recent growth in the program
has shed light on a number of issues detrimental to its effectiveness. Staff believes the
Company's proposal to operate the ILCP through a third party vendor mitigates the majority of
these issues, and provides long-term benefits to PacifiCorp's system. Staff supports cancelling
Schedules 72 and 72A and replacing the programs with the 10-year pay-for-performance contract
with EnerNoc.
Irrigation Load Control Program
The Company introduced the current timer-based irrigation load curtailment program in
2001 and added the dispatchable option as a pilot in 2007, limited to 45 MW of load under
contract. The dispatchable program became permanent the following year, with no limit on
overall participation. The curtailable load under contract has subsequently grown to over 270
MW. Schedule 72, the timer-based program, has accounted for a minimal amount of curtailable
load as most participants have opted for the dispatchable Schedule 72A option, which has a
higher incentive payment and provides more value to customers.
According to the Company's DSM Annual Reports, the ILCP has consistently been a
cost-effective demand response (DR) program based on post-year evaluations using an avoided
or delayed resource cost analysis. The table below shows the program's yearly results based on
the Company's annual Irrigation Load Control Program Final Reports and responses to Staff's
data requests. Notably, the Avoided MW in the table reflects the Company's calculations of
realized load reduction. With low average realization rates (64% for 2011 and 57% for 2012
seasons), the Company is paying for as much as 283 MW to provide the actual level of
curtailment represented below. Even after accounting for the relatively poor realization rates, the
ILCP has easily passed the traditional cost-effectiveness measures, namely the Total Resource
Cost Test and the Utility Cost Test.
STAFF COMMENTS 2 MARCH 1, 2013
Idaho Irrigation Load Control Program
Cost and Avoided Capacity
Incentives Other Costs Total Cost Avoided MW Cost per kW-yr
2008 $ 5,972,757 $ 2,870,914 $ 8,843,671 209 $ 42.31
2009 $ 7,298,531 $ 3,816,417 $ 11,114,948 205 $ 54.22
2010 $ 8,100,681 $ 4,283,393 $ 12,384,074 170 $ 72.85
2011 $ 6,074,644 $ 3,249,400 $ 9,324,044 168 $ 55.50
2012* N/A N/A $ 8,600,000 139 $ 61.87
* Rocky Mountain Power provided an estimate of program costs and average savings for 2013.
Finalized numbers are expected at the end of 2 nd quarter, 2013.
While it is debatable as to what extent a DR program actually delays the construction of a
new supply-side resource, the value of the ILCP to the Company and its ratepayers is apparent.
The Company's load and resource balance analysis for the upcoming 2013 IRP shows resource
deficits in each of the planning years, even after accounting for the addition of the 637 MW
Lakeside 2 CCCT in 2014. The Company relies on market transactions for filling short-term
gaps in its resource position. Because Rocky Mountain Power has routinely exercised its ability
to curtail participants, the JLCP has provided additional year-to-year power cost savings that may
not be fully captured in its cost effectiveness tests.
The EnerNoc Contract
The current filing seeks to replace the existing ILCP with a similar program administered
by a third party under a ten-year contract. The Contract, entered into with EnerNoc on
December 4, 2012, provides the program details and compensation level to be paid by Rocky
Mountain Power. The Contract with EnerNoc is a result of a request for proposal (RFP) issued
by the Company in 2012. The Company evaluated two options: a fully outsourced pay-for-
performance contract with a third party; and a third party equipment and service contract with
the Company continuing to administer the ILCP. The Company specified an average target
realized level for deliverable capacity of 145 MW for Idaho and 40 MW for Utah, which is on
par with the current level of actual reduction the Company receives from the program. The
Company's filing indicates that it received two pay-for-performance proposals and three
equipment and service proposals. EnerNoc's ten-year pay-for-performance proposal was
selected after considering price and risk.
STAFF COMMENTS 3 MARCH 1, 2013
Under the terms of the Contract, EnerNoc is responsible for all equipment installation,
operation and maintenance, customer service, recruitment, and participant payments, and
dispatch of load control devices as directed by the Company. In return, EnerNoc will receive an
average payment of [This section of Staff's comments contains confidential information] per
kW/year, and [This section of Staff's comments contains confidential information]/MWh for
(Company) mandated curtailment events. EnerNoc will receive a payment of [This section of
Staff's comments contains confidential information]/MWh for voluntary curtailment events,
which includes events outside of the defined program availability hours or for system
emergency. The program will run for ten weeks from June 15 through August 15, with
provisions to extend beyond these dates on a non-guaranteed basis. The current ILCP runs from
June 1 to August 31. The Company retains the maximum hours for curtailment of 52 hours, or
13 events, each season. Staff believes the ten week period in the contract aligns well with the
Company's summer capacity needs based on previous dispatch of the program where over 90%
of curtailment events since 2008 fell within this period.
Prior to each program week, EnerNoc will submit to the Company the amount of load
available for curtailment. If no curtailment event is called, EnerNoc is compensated for the
available load provided. If an event is called, EnerNoc would receive a variable payment as
well. Capacity payments will be adjusted based on EnerNoc's ability to provide the full level of
specified curtailment during a mandatory load control event. Payments made to EnerNoc are not
to exceed [This section of Staff's comments contains confidential information] annually for
the Idaho program. If the Company contracts for the average target load reduction of 145 MW
each week, the capacity payment would be approximately [This section of Staff's comments
contains confidential information]. Under that scenario, it would take 26 hours of actual
curtailment to reach the program cap. The Company has confirmed with Staff that it has the
right to the remaining available hours of curtailment at no variable expense once the cap is met.
Staff believes this is important since once the program is dispatched, the Company has an
incentive to maximize the number of hours it actually curtails in order to reduce the effective
variable cost by as much as half.
For each delivery week, EnerNoc must submit a level of available load between [This
section of Staff's comments contains confidential information] MW and [This section of
STAFF COMMENTS 4 MARCH 1, 2013
Staff's comments contains confidential information] MW.' The Contract specifies the
manner in which weekly capacity payments would be reduced if EnerNoc is unable to meet the
lower bound requirement. The weekly capacity payment rate would be [This section of Staff's
comments contains confidential information] reflects an incentive for EnerNoc to optimize
available load coincident with the Company's historical peak needs. Staff believes the use of
weekly bounds on available load will help the Company shape its demand reduction in a similar
manner as it has done in the past, which maximizes the benefit of the program to its customers.
Moreover, the Contract allows either party to request adjustment to the target load reduction at
any point during the ten-year term. If the parties agree to an adjustment, a written amendment
would be made to the Contract. Staff agrees that the parties should periodically review the
program performance and capabilities, and work toward expanding it if appropriate. Staff notes
that any Contract amendment should be filed with the Commission prior to instituting any
program modifications.
It is EnerNoc's responsibility to contract individually with irrigators in order to provide
curtailable capacity on a weekly basis. The Contract specifies how individual baseload demand
(Facility Baseline Demand) is calculated, which directly affects the credit paid to a participant.
Several discussions were held with interested parties in an attempt to clarify contract terms to
assure that the load available for curtailment (Available Load Reduction) provided by the
participant is accurately measured and fairly calculated. The product of the discussions was the
Stipulation signed by the Company and the Idaho Irrigation Pumpers Association (IIPA),
submitted to the Commission on February 8, 2013. Staff believes the Stipulation results in an
acceptable measure of capacity available for curtailment, is fair to the participant, and limits the
opportunity to "game" the system in order to receive payment for load not reasonably available
when called upon.
The Contract states that EnerNoc is responsible for addressing customer issues regarding
the program, and that it will notify the Company if such a problem arises. The Contract does not
identify any additional steps if the problem is not satisfactorily resolved. Rocky Mountain
Power and IIPA agreed to a process should this occur. See Section III, p. 5 of the Stipulation. If
the problem is unresolved, the participant may then contact Rocky Mountain Power to seek
'EnerNoc is not subject to the lower bound requirement for the 2013 program season, presumably to allow a
reasonable opportunity to recruit long-term participation.
STAFF COMMENTS 5 MARCH 1, 2013
resolution. If the issue remains unsettled, the participant may elect to contact the Commission to
address the dispute.
The Company anticipates program costs would be rolled into base rates in its next general
rate case. Currently $600,625 of ILCP costs are embedded in Idaho customers' base rates, which
is Idaho's jurisdictionally allocated program costs for 2011. The proposed Contract would
reduce the cost of the program by $176,950 for Idaho ratepayers and almost $3 million overall,
assuming the [This section of Staff's comments contains confidential information] annual cap
is reached. The Company would track yearly deviations in ILCP costs through its Energy Cost
Adjustment Mechanism (ECAM). Staff anticipates these deviations will be minor, as the
variable payment is a small fraction of the program cost. The Company estimates it will incur
approximately $175,000 in situs-allocated program management and reporting costs each year.
Staff does not believe this estimate or situs treatment is unreasonable, though it will review
actual incurred costs and prudency of those costs in the proper context, such as a general rate
case.
Staff has consistently supported the ILCP, recognizing the benefits it has provided to the
Company's customers for a number of years. Staff believes that moving to a third-party
aggregator is in the best interest of all customers going forward. Staff has identified three
distinct advantages with the Company's proposal: 1) the program costs are essentially fixed,
providing certainty for all parties; 2) administrative and equipment expenses are internalized by
the vendor; and 3) customers will pay for only deliverable capacity rather than contracted
capacity.
The program costs are almost completely known over the ten-year Contract term, and
remain constant over the ten-year term. The variable payments to EnerNoc constitute less than
5% of the overall program costs. Whether the Contract is included in rates at the level defined
by the cap or at the level of capacity payments for an assumed average of 145 MW, the year-to-
year fluctuations in cost that would be captured in the ECAM would be minimal, most likely less
than $20,000 a year for Idaho customers.
Although the Contract payments to EnerNoc remain constant for the next ten years, the
value of the Program may greatly increase going forward. It can be reasonably expected that
capital costs for new generation plant will escalate in the coming years. The realized cost per
kW of the proposed Contract is roughly 30% of the Company's current avoided cost based on a
methodology that utilizes data from the 2011 IRP. The Company can effectively reduce the
STAFF COMMENTS 6 MARCH 1, 2013
variable cost by as much as one-half simply by maximizing the number of called curtailment
events. This has been the Company's practice in the past, and Staff does not believe this will
change going forward. Staff also believes the variable energy payment compares favorably with
market price forecasts in the out years of the Contract even if the Company does not execute
curtailment up to the Contract limits. As with any long-term option contract, there is some
premium built into the price to reflect a reduction in risk. Staff believes it is probable that the
negotiated pricing terms will not only cover the risk premium, but provide Rocky Mountain
Power customers with tangible year-to-year power cost savings.
Other than the $175,000 cited by Staff above, all costs to deliver the program are
internalized by the vendor. Staff's table shows that roughly a third of the annual cost of the
current ILCP is attributable to non-incentive expenditures. Results from the Company's RFP
show that this would hold true going forward should the Company retain full operational
program control. Under the Contract, EnerNoc is responsible for all field equipment and
maintenance, which includes monitoring equipment necessary to accurately measure usage at the
service pump. EnerNoc is also responsible for the data collection, storage, and reporting, as well
as costs associated with program marketing and enrollment. The ILCP has been an expensive
program to administer, and Staff does not expect this to change in the future. Staff appreciates
that Rocky Mountain Power customers are insulated from the risk of cost overruns by virtue of a
cap on program-related expenses.
The greatest opportunity for savings from the proposal over the current ILCP is that
Rocky Mountain Power will only pay for delivered capacity rather than contracted capacity.
Due to the installation of monitoring equipment at the site, the Company will know with
certainty whether a participant is actually contributing to load reduction at the time of an event.
Based on past realization rates, the Company has been paying a premium of 40% or greater in
incentives in order to provide the historic level of load reduction. Because the Contract has
penalty provisions for non-performance, EnerNoc is incented to contract reliable load that can be
delivered when the Company calls for it. By decrementing the capacity payments for
undelivered available load, customers are ensured they will only pay for effective and reliable
curtailable load.
The Contract provides the right to terminate due to disallowance of program costs. If the
Company is unable to recover program costs from other jurisdictions, it will fall to the Idaho
Commission to determine whether any of the unrecovered costs will be the responsibility of
STAFF COMMENTS 7 MARCH 1, 2013
Idaho customers. If unrecovered program costs become an issue for the Company, it may
terminate the Contract, though it would pay a fee to EnerNoc based on the number of years the
program has been in service. Staff believes the termination clause provides additional incentive
for the Company to continue its support of the ILCP- and DR programs in general - as a system
resource.
Staff supports the Company's commitment to continue providing an annual performance
report for the ILCP. Staff views these reports as essential for ongoing program oversight and to
provide guidance for any beneficial program modifications in the future. The Company agreed
to provide the report concurrently with its annual demand-side management report, currently due
by April 30th of each year. Staff anticipates that the additional data available from EnerNoc's
monitoring equipment will add value to the annual performance reports.
STAFF RECOMMENDATION
Staff recommends the Commission approve the Company's Application, cancelling tariff
Schedule Nos. 72 and 72A, and approving the agreement between Rocky Mountain Power and
EnerNoc as modified by the Stipulation signed by the Company and the Idaho Irrigation
Pumpers Association. Staff believes the Contract will allow a successful program to continue
and provides enhanced benefits to Rocky Mountain Power's customers.
Respectfully submitted this day of March 2013.
KA T. Klein
Deputy Attorney General
Technical Staff: Bryan Lanspery
Nikki Karpavich
i:umisc:comments/pace 12.1 4kkblnk comments
STAFF COMMENTS 8 MARCH 1, 2013
CERTIFICATE OF SERVICE
HEREBY CERTIFY THAT I HAVE THIS 1ST DAY OF MARCH 2013.
SERVED THE FOREGOING NON-CONFIDENTIAL COMMENTS OF THE
COMMISSION STAFF, IN CASE NO. PAC-E-12-14, BY MAILING A COPY
THEREOF, POSTAGE PREPAID, TO THE FOLLOWING:
TED WESTON
ID REGULATORY AFFAIRS MANAGER
ROCKY MOUNTAIN POWER
201 S MAIN ST STE 2300
SALT LAKE CITY UT 84111
E-MAIL: [e-mail]
DATA REQUEST RESPONSE CENTER
E-MAIL ONLY:
datareguest(pacificorp.com
ANTHONY YANKEL
29814 LAKE ROAD
BAY VILLAGE OH 44140
E-MAIL: [e-mail]
RANDALL C BUDGE
RACINE OLSON NYE BUDGE
& BAILEY
P0 BOX 1391
POCATELLO ID 83204
E-MAIL: [e-mail]
ELECTRONIC ONLY
JAMES R SMITH
MONSANTO COMPANY
E-MAIL:
[e-mail]
DANIEL E SOLANDER
SENIOR COUNSEL
ROCKY MOUNTAIN POWER
201 SMA1N ST STE 2300
SALT LAKE CITY UT 84111
E-MAIL: [e-mail]
ERIC L OLSEN
RACINE OLSON NYE BUDGE
& BAILEY
P0 BOX 1391
POCATELLO ID 83204
E-MAIL: [e-mail]
BENJAMIN J OTTO
ID CONSERVATION LEAGUE
710 N 61H STREET
BOISE ID 83702
E-MAIL: botto(idahoconservation.org
BRUBAKER & ASSOCIATES
16690 SWINGLEY RIDGE RD
#140
CHESTERFIELD MO 63017
E-MAIL: [e-mail]
SECRETARY
CERTIFICATE OF SERVICE