20130417Comments.pdf

Peter J. Richardson ISB # 3195
Greg Adams ISB # 7454
RICHARDSON & O'LEARY PLLC
515 N. 27th Street
Boise, Idaho 83702
Telephone: [phone]
Fax: [phone]
[e-mail]
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Attorneys for the Industrial Customers of Idaho Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER IDAHO OF IDAHO ) CASE NO. IPC-E-13-04
POWER'S APPLICATION FOR )
APPROVAL OF ITS AGREEMENT WITH ) COMMENTS OF THE INDUSTRIAL
ENERNOC TO IMPLEMENT AND ) CUSTOMERS OF IDAHO POWER
OPERATE A VOLUNTARY )
COMMERCIAL DEMAND RESPONSE )
PROGRAM
COMES NOW, the Industrial Customers of Idaho Power ("ICIP") and pursuant to Order
No. 32777, issued by the Idaho Public Utilities Commission ("Commission") on April 2, 2013 in
the above captioned docket, and hereby provides its Comments on the Application by Idaho Power
Company ("Idaho Power" or the "Company") for approval of a second amendment of its
agreement with EnerNOC, Inc. ("EnerNOC").
In case No. IPC-E-09-02, Idaho Power proposed to institute a demand side response
("DSM") program that was to be administered by a commercial and industrial DSM aggregator. In
November 2008, Idaho Power issued a Request for Proposals ("RFP") that resulted in the selection
of EnerNOC to administer the program known as the FlexPeak Management Program
("FlexPeak"). Idaho Power and EnerNOC entered into a five-year agreement in February 2009,
I 1 —ICIP COMMENTS; IPC-E-13-04
which was subsequently approved by the Commission in May 2009.'
The original contract set lower and upper bands of peak reduction that EnerNOC was to
achieve each year of the five-year agreement. The bands began with a range from a low of 2 MW
to a high of 35 MW in 2009 and subsequently expand to a lower band of 35 MW with an upper
band of 65 MW by 2013. Idaho Power and EnerNOC also agreed to targets for each year from
2009 through 2013. The specific targeted demand reductions were 2 MW, 30 MW, 40 MW, 50
MW and 65 MW respectively for each of the five years.
The anticipated cost of the FlexPeak program over the five year period was approximately
$12.2 million which was based on the expected number and duration of peak shaving events during
the contract period. The estimated annual cost ranged from just under $315,000 in the first year to
nearly $3.5 million in the fifth year. During the term of the agreement the allocated shares of
program expenses were forecast to be 85% for capacity payments and 6% for energy payments.
Ninety-one percent of the incentive payments were to accrue to either the participants or EnerNOC
itself and Idaho Power was allocated 9% of the incentive payments for administrative expenses.
Over the past three full years of the FlexPeak Program, EnerNOC received 97% for total program
costs,2 but we do not know how those funds were allocated by EnerNOC to the program's
participants.
In early 2010, Idaho Power filed a petition with the Commission to approve an amendment
to the EnerNOC agreement. The changes requested were to clarify language regarding energy
payments, adjustments to the baseline calculations, and a correction of an error in EnerNoc's
penalty calculations. This first amendment also added language regarding a non-solicitation clause
Order No. 30805.
2 Idaho Power DSM Reports, 2010 —2012.
2 —ICIP COMMENTS; IPC-E-13-04
covering both companies. The Commission approved the first amendment in June 2010.
During the first four years of the program, Idaho Power had called for 8, 4, 14 and 4 peak
response events respectively. The average load reduction achieved in years three and four was 38
MW. Program participation has grown to 102 participants in 2012, with the highest hourly
reduction achieved in July at 47.0 MW of achieved demand side management.
Idaho Power is now essentially asking the Commission to freeze the FlexPeak program
through the end of the contract term, which is scheduled to terminate on February 2014. This
second amendment would cap the weekly nominated demand reduction at 35 MW and decrease the
dispatch hours available from 60 to 30 and reduce the event days from 20 to 10. In addition, this
second amendment reduces the level of per kilowatt payment to EnerNoc. Idaho Power states the
second amendment will save program expenses of approximately $500,000 in 2013. Idaho Power
indicates the future of the FlexPeak program and its relationship with EnerNOC after February
2014 will likely be determined based on the outcome of planned workshops this coming summer:
The determination of the future of the FlexPeak program, and subsequently the EnerNOC
contract, beyond the 2013 season is pending the outcome of Phase II of this case.4
In case IPC-E-09-02, the case that initiated the FlexPeak program, the ICIP submitted comments
supporting the program, albeit with certain modifications. The ICIP continues to support the
program, but also continues to believe that certain modifications are necessary.
The original comments filed by the ICIP relate to two major areas. First, was a
comparison of the demand side offers under FlexPeak versus the demand side offers under the
Irrigation Peak Rewards. The second major area of concern expressed by the ICIP dealt with the
transparency (or lack thereof) inherent in the FlexPeak program. In its IPC-09-02 comments the
ICIP stated:
Order No. 31098.
IPCo response to ICIP data request no. 7.
3 —ICIP COMMENTS; IPC-E-13-04
In its application Idaho Power is seeking Commission approval of an agreement
between it and EnerNOC under which EnerNOC, acting a third party aggregator,
will implement a commercial demand response program ("Program") that would be
made available to Idaho Power's commercial and industrial customers. Although
the Program is outlined in the application, the specific contracts and details of each
individual commercial or industrial participant's relationship with EnerNOC are not
included in the application. EnerNOC will be paid by Idaho Power for a target
number of MW reduction, which reduction will be guaranteed by EnerNOC.
EnerNOC will then individually contract with Idaho Power's commercial and
industrial customers and strike individual deals, presumably paying less than it is
receiving from Idaho Power, to meet its demand reduction target. The program's
costs do not equal what the commercial and industrial customers will receive in
exchange for participation. We do not know what EnerNOC will be paying for
acquiring its target demand reduction. Because the individual arrangements
between EnerNOC and the commercial and industrial participants are not public,
the specific terms and conditions of those relationships are not known at this time.5
Wei
The Application is silent on any details of the contractual relationship between
EnerNOC and the program participants. EnerNOC will negotiate contract terms
and rates individually with each potential participant. Those agreements will be
maintained confidentially between EnerNOC and each participant. The lack of
transparency as to how each participant will be treated is troubling. This is because
there will exist a large difference in the relative bargaining strengths between
EnerNOC and Idaho Power's customers. EnerNOC is a successful aggregator of
commercial and industrial demand response. It operates on a national scale. It is in
the business of buying demand reductions and aggregating them for bulk sale to
utilities. Idaho Power's commercial and industrial customers, on the other hand,
have no experience in selling their demand back to the power company. In
addition, EnerNOC 'S incentive, and profit, are tied [to] its striking a series of best
deals with individual participants. That said, more transparency - not less - is
called for.6
Idaho Power stated in Comments filed in the original docket that:
EnerNOC has publicly stated that participating customers who contract with
EnerNOC will likely receive between $25 and $35 per kW annually, depending on
the number of events called, frequency of events called, and the equipment and
installation costs EnerNOC must invest at the site of each participating customer.7
Both the Commission Staff and the ICIP have attempted to be allowed, under protective
ICIP Comments, Docket No. IPC-E-09-02 at p. 2.
6 Id at pp 3 —4. Emphasis in original.
Idaho Power Comments, Docket No. IPC-E-09-02 at pp 5 —6.
4 —ICIP COMMENTS; IPC-E-13-04
agreements, to verify that, in fact, the 100 plus commercial and industrial customers who
contract with EnerNOC are in fact receiving between $25 and $35 per kW annually.
However, the contract arrangement between EnerNOC and Idaho Power appear to dictate
that even Idaho Power is not allowed to know what EnerNOC is paying to the participating
industrial and commercial customers or what amounts EnerNOC is keeping as profit.
In Docket No. IPC-E-12-15 (the first amendment docket) in response to Staff's
Second Production Request, Idaho Power stated:
REQUEST NO. 10: Please quantify and explain the customer incentive structure
used in the FlexPeak Management Program and include the number of participants
in each incentive category.
RESPONSE TO REQUEST NO. 10: The incentives paid to participants in the
FlexPeak Management program are made by EnerNOC, Inc. based on agreements
with each participant. Idaho Power does not know the amount of these incentives.
At the end of the 2011 cycling season, there were 103 service locations participing
in the program.8
EnerNOC, itself, filed comments in that docket, stating:
Staff's recommendation that Idaho Power publicly disclose confidential terms of
EnerNOC's relationships with program participants has the potential to significantly
impact EnerNOC's ability to negotiate with participants and threatens to
substantially damage the aggregator business model that supports the effectiveness
of the FlexPeak program.
The customer payments generally consist of a capacity (availability) component and
an energy component (based on actual kWh reductions during events). The
customer incentives are not disclosed in the contract between EnerNOC and Idaho
Power. If this confidential information is publicly disclosed, current and potential
EnerNOC competitors and potential program participants would be able to gain
important insights into EnerNOC's unique pricing, business, and technical
strategies causing substantial harm to the competitive position of EnerNOC and,
consequently, adversely affecting the FlexPeak Program. EnerNOC respectfully
requests that the Commission not require EnerNOC to publicly disclose confidential
customer incentives.9
8Docket No. IPC-E-12-15. Idaho Power Response to Staffs second production request no. 10.
Docket No. IPC-E-12-15. EnerNOC comments, July 20, 2012.
5 —ICIP COMMENTS; IPC-E-13-04
Despite Staffs and the ICIP's objections, the Commission agreed with EnerNOC, stating:
Based on our review of the record, we find no need for the Company's future DSM
reports to disclose EnerNOC's incentive payment information so long as the
Company pays a reasonable price and the FlexPeak Managemetn Program is cost-
effective. We will continue to evaluate the FlexPeak Management Program based
on its cost-effective performance. 10
The ICIP appreciates that the Commission said it will continue to evaluate the program, based on
cost-effectiveness. However, it is difficult to imagine how a thorough cost effective evaluation can
take place in a vacuum. That is, the cost of the program is known, but the opportunity cost of the
program is not. The ratepayers are buying a product, demand reduction, the cost of which neither
the regulator nor the utility have any true idea as what it actually costs. Only EnerNOC knows the
true cost of the DSM it is procuring.
The ICIP does not agree with EnerNOC that disclosing the portion of incentive payments
received by the commercial and industrial participants in the FlexPeak Program would do damage
to EnerNOC's business model or would cause substantial harm to the competitive position of
EnerNOC. EnerNOC is engaged in providing a utility service to the public without having its
rates, terms or conditions of service approved by the Commission. But only the Commission is
charged with setting fair just and reasonable rates - EnerNOC does not have that authority. That
the service EnerNOC is providing is a utility service cannot be questioned. Payments are received
by participants enrolled in the FlexPeak Program for reducing their loads during peak periods,
when power to the grid is most valuable. EnerNOC is essentially setting the participants' retail
rates for power received from Idaho Power. In 2012 ratepayers paid approximately three million
dollars for the FlexPeak Program through the DSM rider. Those ratepayers, as well as the program
participants, have the right to be assured that these program costs are cost effective. The fact that
participation in the program is voluntary does not obviate the fact that EnerNOC is acting as a
'° Order No. 32667.
6 —ICIP COMMENTS; IPC-E-13-04
monopoly provider of demand response service in Idaho Power's service territory. Participants
have no other option if they want to sell peak reductions to Idaho Power -- EnerNOC is the sole
provider. This the classic rationale for rate regulation.
The ICIP is also concerned about the continued viability of the FlexPeak Program once the
contract with EnerNOC expires. The program appears popular with the participants, at least with
those participants who responded to an EnerNOC survey. Presumably if the program were
unpopular more would have responded. According to Idaho Power's 2012 DSM report:
EnerNOC sent a post-event survey via email after the first event in June 2011 to 195
participants representing all the sites enrolled in the event. Eighteen participants
responded, for a 9-percent response rate. When asked how prepared they felt for the
demand response event on a scale of 1 tO 10, 10 being "fully prepared." The average
response was 8.4. When asked how likely they were to recommend EnerNOC to a peer or
business partner on a scale of 1 to 10, 10 being "definitely will," the average response was
8. When asked how satisfied they were with how EnerNOC managed the demand response
event on a scale of 1 to 10, 10 being "very satisfied," the average response was 8.3.
Idaho Power states in its Application that the "amendments to the contract that would align
with both Idaho Power's needs and EnerNOC's current level of participation in the FlexPeak
Program." 2 Apparently Idaho Power's 'need' being addressed by the application is that it
forecasts a capacity surplus for the next three years -- despite the fact that the FlexPeak program
only fully ramped up just three years ago. The Commission should also take note of the fact that
Idaho Power's current summer peak is now forecast to grow by 40 MW a year for the 2013 - 2032
time period as compared to the historic growth of just 30 MW a year for the past decade. 13
The Commission recently approved a stipulation to temporarily suspend Idaho Power's
other two DSM programs in Case No. IPC-E-29-12. In that docket, the Commission suspended the
A/C Cool Credit and the Irrigation Peak Rewards programs, but allowed for token payments to be
Idaho Power 2012 DSM Report, p. 96.
12 at p. 9.
13 Idaho Power Integrated Resource Plan Advisory Council presentation November 15, 2012, slide 3.
7 —ICIP COMMENTS; IPC-E-13-04
made to the participants in those programs to avoid losing that resource altogether. Apparently the
Commission was concerned about the continuity and ongoing effectiveness of DSM programs if
the Company shuts them down only to find that it may be more difficult to restart them down the
road when Idaho Power is once again capacity deficit. The other problem identified by the
Commission was the inability of the Company to accurately predict the need for peak resources
over the three year period between 2013 and 2016:
We also appreciate the thoughtful comments offered by customers about encouraging and
maintaining participants in the A/C Cool and Peak Reward programs. When we initially
authorized the pilot A/C Cool program in 2003, we recognized that DSM programs are
powerful tools in managing peak loads and mitigating the impact of potential rate increases.
Order Nos. 29207 at 8. In particular, reducing the peak summer loads lessens the utility's
reliance upon purchasing power or constructing supply side generation. We are
disappointed that the Company proposed to discontinue their use completely.
We are concerned about implementing measures in the short-term that may reduce the
effectiveness of both programs. Valuable time and resources were used to develop
effective DSM programs, and we do not want to impair the effectiveness of these programs
in the future when the Company's peak loads surpass its supply resources. This is
especially true after the Company recently replaced most of the older A/C control devices.
For example, as one customer indicated, it may be cheaper for the Company to cycle the air
conditioning units than to purchase or generate power from its own supply resources. 14
Of course, the reason Idaho Power has a capacity surplus is that it just energized the 300
MW Langley Gulch gas plant in June of 2012. On July 12, 2012, Idaho Power issued a press
release observing that temperatures reached 108 degrees in Boise, and that as a result the Company
reached a near record peak of 3,198 MW on July 9, 2012. In that press release Idaho Power
disclosed a significantly higher customer growth rate than in the previous two years. It also
indicated that in the years 2009, 2010 and 2011 it was able to handle peak loads with their
"successful" demand response programs, along with milder weather and declining economic
activity. According to Idaho Power's press release of July 12:
"Langley Gulch has come online at a perfect time to help us meet some of the highest loads
14 Order No. 32776 pp. 7 —8.
8 —ICIP COMMENTS; IPC-E-13-04
we have seen in several years," said Mark Stokes, Idaho Power's Manager of Power Supply
Planning.
On Monday, July 9, temperatures in Boise reached 108 degrees. Idaho Power's overall
peak-hour average load topped out at 3, 177 MW and on Tuesday reached 3,198 MW, just
short of a new system peak record.
Idaho Power's all-time peak-hour average load reached 3,214 MW in June 2008. The
company's successful demand reduction programs, along with weather conditions and a
general decline in economic activity lowered Idaho Power' peak demand in 2009, 2010 and
2011.
Idaho Power experiences its highest demand during the summer months, when air
conditioners and irrigation pumps add to everyday electrical usage. An increase in
customer growth over the past year has added to that demand.
From the second quarater of 2011 to the second quarter of 2012, Idaho Power added 5,240
general business customers in its service area - roughly double the second-quarter growth
of the previous two years. Residential customers grew by 4,155 from the second quarter of
2011 to the second quarter of 2012 - also significantly higher than the growth seen in the
two previous years. 15
However, on July 9, 2012, Idaho Power also called on the FlexPeak program for power to help
meet its peak demand from 98 participants, for the 4 p.m. to 6 p.m. time period. The program
yielded 42.1 average MW and 84.2 MWh. Idaho Power also used the programs after the on-line
date of Langley Gulch in 2012 on July 12th and again on August 7 th, for a total of 74 average MW
and 276 MWh.'6 It is apparent there isn't a need to wait for an emergency to utilize the FlexPeak
Program, as presently constituted, to help meet system peak. With unknown weather conditions
and peak load growth on the increase, the program should be allowed to continue to grow.
One of the commenters the Commission was likely referring to is former Commission Staff
member Bill Eastlake. He shares the Commission's concerns about the Company's foresight in
projecting the need for peak power in 2013. Mr. Eastlake noted that Idaho Power is not a "self-
sufficient island." He stressed the importance of demand response programs to meet, not only the
15 Idaho Power press release "Langley Gulch Providing Needed Power," July 10, 2012.
16 No. IPC-E- 13-04. Idaho Power Response to ICIP's First Date Request No. 2.
9 —ICIP COMMENTS; IPC-E-13-04
Company's own needs, but to profitably help other utilities to meet their peak demands. Mr.
Eastlake provided the following comments in the A/C Cool Credits and Peak Rewards docket,
which are apropos to the Commission's decision in this docket:
I remain dismayed that the Company shows such a dismissive attitude toward programs
that it said were vital not so long ago. The Company says it now doesn't need such
programs and doesn't anticipate using them during 2013. Such an attitude assumes perfect
foresight as to demand and supply conditions for the summer of 2013 and seems to ignore
the fact that the Company is not a self-sufficient island but a player in an integrated
regional power system. Surely it is possible for some unforeseen peak load problem to
arise, either in the Company's own resources or in its ability to access regional resources.
And surely it is possible that, even if the Company doesn't have peak deficits of its own,
some other regional utility might have need for additional resources that could be profitably
supplied by the Company via demand response. Or, it may even be possible that it is
cheaper for the Company to turn off a kw than to supply it from its own available
resources. 17
It is hoped the Commission will take Mr. Eastlake's comments to heart in this docket as well as the
prior DSM dismantling docket.
Due to required lead times, economies of scale, efficiency, etc., utilities tend to add plant in
relatively large increments. This means in actual practice, generation capacity is periodically
added in a 'lumpy' fashion. The 300 MW Langley Gulch generation plant is one such 'lump.'
Given this practice, an actual electrical system will have either more or less than the optimum
amount of generating capacity. Because generating resources are typically added to systems in
moderately large MW increments (e.g. 100 MW or more), and even if units are carefully sized to
correspond to the system size, and expected rate of load growth, it is unrealistic to expect the mix
of different types of generating plants to be precisely optimum. Utilities add plant in increments
that exceed their short term needs to serve load. Therefore, unless it is due to some unforeseen
factor or under-forecasting, a utility will almost always be in a surplus capacity situation for the
foreseeable future.
17 Docket No. IPC-E-12-29. Comments by Bill Eastlake, March 4, 2013.
10 —ICIP COMMENTS; IPC-E-13-04
Demand response programs should not be ramped down because the utility is in a
temporary capacity surplus situation. As described above, the status of being capacity surplus is
typical - it is the rule rather than the exception. Under Idaho Power's logic, DSM programs
become the exception rather than the rule. DSM programs, like FlexPeak, allow the utility to meet
system demands in smaller increments and they smooth out the 'lumpy' nature of adding
generation plant like the Langley Gulch plant. Programs, such as FlexPeak, do not have an "on/off
switch" as the Commission noted in Order No. 32776. The FlexPeak contract between Idaho
Power and EnerNOC needed a full two year "ramp-up" period with fewer participants and lower
committed megawatts during its first two years.
In a presentation to the 2013 Integrated Resource Plan Advisory Council meeting on March
14, 2013, Idaho Power presented its preliminary portfolios to be analyzed in its 2013 IRP. In all
seven of the proposed resource portfolios, demand response will play a significant role. The ICIP
is concerned the paring back of the Company's three demand response programs at this time will
hamper the role DSM will be able to play in meeting future peak hour needs. Even during times of
surplus capacity, deploying DSM in order to delay future generating resources from being built has
positive economic value to the ratepayers. For example, PacifiCorp calculated investment deferral
credits in determining resource timing in a demand side management decrement study for its 2011
IRP.'8 In that study, PacifiCorp calculated the value of various DSM measures in order to
prioritize spending on such measures relative to investing in new resources or power purchase
agreements. PacifiCorp, using its PDDRR modeling calculated a $16.69/MWh benefit attributable
to deferred expenditures on new capacity. It also calculated a stochastic risk reduction benefit
(compared to fueled capacity resources) of $14.98/MWh, and deferred transmission and
distribution benefits ranging from $1.75 to $16.63/MWh.
18 PacifiCorp 2011 IRP, Chapter 2.
11 —ICIP COMMENTS; IPC-E-13-04
The ICIP urges the Commission to allow the FlexPeak Program to continue on its proven
path of success. As the Commission observed, along with Bill Eastlake, Idaho Power does not
have perfect foresight in forecasting peak needs. The effectiveness of the FlexPeak Program may
well be harmed by Idaho Power's proposal. Switching programs such as the FlexPeak Program on
and off again is surely to discourage future participation when such participation may be vital to
Idaho Power's needs. Further, even if Idaho Power finds that it doesn't need this peak resource to
meet its own needs in the short term, such a resource may be able to provide another regional
utility with peaking power on the market and at a profit. Smaller incremental resources, such as
those provided by the FlexPeak Program help level out the lumpiness caused by such large
additions as the Langley Gulch Plant. Even during times of capacity surplus, the FlexPeak
Program provides Idaho Power with cost effective peak hour reserves, and it is valued by the
participating commercial and industrial customers.
Going forward, however, the FlexPeak Program should be made more transparent -
regardless of whether EnerNOC continues on as the third party administrator.
The ICIP will constructively participate in workshops and collaborate with all parties to
insure that these and other programs are available to meet Idaho Power's energy and capacity
needs in a least cost manner
DATED this 17th day of April, 2013.
RICHARDSON & O'LEARY PLLC
By:
Peter J. Richardson, ISB #3195
Attorneys for the INDUSTRIAL
CUSTOMERS OF IDAHO POWER
12 -ICIP COMMENTS; IPC-E-13-04
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 17 0' day of April, 2013, a true and correct copy of the
within and foregoing COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO
POWER were served in the manner shown to:
Hand Delivery
U.S. Mail, postage pre-paid
Facsimile
Electronic Mail
Ms. Jean Jewell
Commission Secretary
Idaho Public Utilities Commission
472 W. Washington (83702)
P0 Box 83720
Boise, ID 83720-0074
Lisa Nordstrom
Donovan Walker
Idaho Power Company
P0 Box 70
Boise, Idaho 83707-0070
[e-mail]
[e-mail]
Hand Delivery
U.S. Mail, postage pre-paid
Facsimile
X Electronic Mail
Nina Curtis
Administrative Assistant
13 -ICIP COMMENTS; IPC-E-13-04