20100913Comments.pdf

Peter J. Richardson
Gregory M. Adams
Richardson & O'Lear, PLE.C
515 N. 27th Street X~,:.
P.O. Box 7218
Boise, Idaho 83702
Telephone: [phone]
Fax: [phone]
peterrã¿richardsonandoleary. com
greg(irichardsonandoleary. com
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Attorneys for the Industral Customers of Idaho Power
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY'S APPLICATION FOR A )
PRUDENCY DETERMINATION OF ENERGY ~
EFFICIENCY RIDER FUNDS SPENT )DURG 2008-2009 )
CASE NO. IPC-E-10-09
COMMENTS OF THE INDUSTRIAL
CUSTOMERS OF IDAHO POWER
Pursuant to Rule 203 of the Rules of Procedure of the Idaho Public Utilties Commission
(the "Commission") and the Commission's Notice of Modified Procedure served July 28,2010,
the Industral Customers of Idaho Power ("ICIP") respectfuly submit the following comments
on Idaho Power Company's ("Idaho Power's" or the "Company's") request for a prudency
determination as to the $50.7 milion in energy effciency nder fuds ("EE nder" or "rider")
spent in 2008 and 2009. As set fort in detal below, ICIP requests that the Commssion
condition any finding of prudency of the expenditure of these fuds on the additional
requiement that Idaho Power abandon individual programs that fail to meet a total resource cost
benefit ratio ("TRC ratio") of 1.25 or greater once mature. ICIP additionally requests that the
Commssion order Idaho Power to abandon or modify the Holiday Lighting and AlC Cool
Credits programs, encourage Idaho Power to use the FlexPeak program as a model for other
programs which could be ru with third-pary aggregators, and order that Idao Power rely more
heavily on third-pary evaluations in the future or at least provide critena establishing when
third-pary evaluations are appropnate.
I
BACKGROUND
A. The recent EE rider prudency review case (lPC-E-09-09) included a fiing of a
Memorandum of Understanding that should inform but not replace prudency
reviews.
The present application is the second prudency review to be addressed by the
Commission this year. In Case No. IPC-E-09-09, the Company sought a prudency determination
for expenditue of approximately $14.6 milion in EE nder fuds spent from 2002 to 2007. i See
Application, Case No. IPC-E-09-09, irir 2-3 (Apnl 1, 2009). Staff initially concluded the
Company provided a lack of documentation regarding that expenditue, and then held private
workshops with the thee utilities to develop a Memorandum of Understanding ("MOU")
regarding future reviews. See Direct Testimony of Lyn Anderson, Idaho Public Utilities
Commission Staff, Case No. IPC-E-09-09, p. 4 (Febru 19,2010).
The utilties agreed in the MOU "to formally evaluate all of their programs on regular,
multi-year cycles and to report the results. . . ." ¡d. at pp. 4-5. "In exchange for the utility
commitments, Staff agreed that if the evaluation and reporting commitments are fufilled and if
there is no evidence of DSM imprudence, then, when requested by the utilties, Sta would
In the 2008 general rate case, the Company requested approval of approximately $29
milion of EE nder fud expenditues from 2002 to 2007. Ultimately, the Commission found
prudency as to the expenditure of $ i 4.3 milion per stipulation in Order No. 30740, but required
the Company to make a separate fiing to establish the prudency of the remainder of those
expenditures, which resulted in the Company initiating Case No. IPC-E-09-09.
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COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
CASE NO. IPC-E-10-09
recommend that DSM expenditures be found prudent by the Commission." ld. at p. 5. Staff and
the Company reached a settlement in Case No. IPC-E-09-09, and attached the MOU between
Staff and the three investor-owned-utilities to the settlement stipulation submitted for approval
by the Commission. See Stipulation, Case No. IPC-E-09-09, irir 3-4, and Attchment 1 (Januay
25,2010). No pary to that case challenged the prudency of expenditue of the remaining $14.6
milion in Case No. IPC-E-09-09. But ICIP requested the Commission not unconditionally
approve the MOU as a basis for future prudency findings by the Commission or as a basis by
which Staff would provide its support for a prudency determination. See Order No. 31093, at pp.
2_3.2
The Commission found expenditure of the remainder of the 2002 to 2007 rider
expenditues prudent, but the Commission itself did not approve the MOU. Specifically, the
Commission stated, "'even if a utility implements Staffs prudency guidelines and evaluation
framework in the Memorandum of Understanding, the utility wil stil need Commission
approval of the expenditues in a formal fiing, such as a general rate case.''' .Order No. 31039,
at p. 3 (quoting ieip's Comments and Protest). The Commission stated that "interested parties
wil have an opportunity in those proceedings to analyze and challenge the DSM evaluation at
issue, regardless whether the utility has evaluated and reported its programs consistent with the
2 The Stipulation stated, "The obligations of the Paries under this Stipulation are subject to
the Commission's approval of this Stipulation." Stipulation, Case No. IPC-E-09-09, at ir 10; see
also id. at ir 4 and Attachment 1. ICIP's comments opposing the MOU were therefore premised
on the assumption that the request for Commission approval of the reasonableness of the
stipulation included a request for approval of the reasonableness of the MOU attched to the
stipulation as par of the basis for Staff s agreement not challenge the prudency of the remaining
EE rider fud expenditures at issue. Staff and Idaho Power both filed reply comments, however,
asserting they had no intention of the Commission approving the MOU or of making it binding
on other paries.
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COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
CASE NO. IPC-E-1O-09
terms of the MOD." Jd. The Commission therefore merely "recognze(d) that the MOU has
potential in evaluating and reporting Idaho Power's DSM programs." Jd. Most importtly, the
Commission stated, "The Commission's futue review of paricular DSM programs should be
assisted, but will not be replaced by, Idaho Power's compliance with the terms of the MOU." Jd.
B. The Application in this case requests a prudency finding for rider funds expended in
2008 and 2009.
Although Idaho Power has not had suffcient time to fully comply with the procedural
requirements of the MOU in this case, this is the first prudency review assisted by the MOU. See
Application, ir 11. This is also the first case where the Commission is asked to approve the
prudency of expenditures collected under the recently-increased EE rider level of 4.75%, which
went into effect May 2009 and from which Idaho Power has projected it wil collect over $30
milion per year. See Order No. 30814, at p. 3. In ths case, the Company seeks prudency
determination as to the expenditue of $18.8 milion spent in 2008 and $ 31.8 millon spent in
2009. Application, at ir 6.
In support, the Company asserts that anual energy savings from efficiency activities
increased by 62% from 2007 to 2009, representing a savings of 140 Gigawatt hours ("GWh") in
2008 and an additional 148 GWh in 2009. Application, at ir 5. The Company also reported that
its demand-side management (DSM) programs reduced its load by 48 MW in 2007, 61 mega-
watts ("MW") in 2008, and 218 MW in 2009. Jd. The Company asserts that all but one of its
individual programs - the Holiday Lighting program - produced savings at a benefit/cost ratio of
1.0 or greater when evaluated at a total resource cost perspective ("TRC test"). Application, at ir
7. The Company has provided its 2008 and 2009 Demand-Side Management ("DSM") Anual
Reports, and asserts that the 2009 DSM Anual Report comports with many of the requirements
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COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
CASE NO. IPC-E-I0-09
of the MOU from Case No. IPC-E-09-09. Application, at ir 10-11. Specifically, Idaho Power
asserts it has conducted many cost-effectiveness measures, net-to-gross adjustments, and third-
pary program evaluations. ld.
II
COMMENTS
Cost-effectiveness should be the governing factor of Idaho Power's DSM programs to
ensure that ratepayer fuds achieve the greatest demand,.side reductions for ratepayer benefit.
Programs should focus on reducing electricity demand, and mature programs that fail to do so
with a reasonable assurance of cost-effectiveness should be abandoned. In a prudency review,
such as this case, Idaho Power must prove the prudency of its expenditue on its individual
programs. Imprudently spent EE nder fuds should be subject to a ratepayer refud. And where
the program proves to be less than cost-effective, but does not rise to the level of an imprudent
expenditure given reasonable expectations at the time of the expenditure, the Commission should
order the Company to improve or discontinue that program. In this prudency review, ICIP does
not advocate for disallowance of any paricular expenditure, but requests the Commission
condition its prudency determination by taking the steps described below to improve the
Company's overall DSM program and the quality of future prudency reviews.
A. The Commission should set a standard requiring that mature programs that fail to
meet a TRC ratio of 1.25 be improved or discontinued.
Idaho Power states that it taes steps to ensure cost-effectiveness, but its tests are not
sufficient to guarantee cost-effectiveness of each program. "Idaho Power's goal is that all
mature programs have a benefit/cost (B/C) ratio greater than 1.0 for both the total resource cost
(TRC), utilty cost (UC), and the paricipant cost (PCT) tests at the program level and the
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COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
CASE NO. IPC-E-1O-09
measure level, except in cases where there is interaction between measures." Idaho Power's
2009 DSM Annual Report, p. 15.3 Idaho Power states it wil re-examine implementation of
programs that fail to meet this minimum level of cost-effectiveness for these three measures. See
id. But that is not enough to ensure that EE rider fuds are prudently spent.
ICIP believes that the most meangfu test for evaluating the programs is the TRC test.
That test includes both the costs incured by the Company and the costs incured by program
paricipants. It therefore evaluates the true value of the program, considering all relevant
costs in analyzing whether the program is a cost effective means of using ratepayers'
financial resources to reduce demand. In contrast, the UC test does not consider the costs
DSM program paricipants wil incur to bring the program benefits to fruition, and therefore
overlooks additional costs of the programs that must be incurred by ratepayers in order to
achieve demand reductions on the system. Further, the PCT only analyzes the costs and
benefits to an individual paricipant of a given program. It may be a good "first cut" of the
desirabilty of the program to individual customers from a purely economical standpoint, but it is
not a very meaningful tool to evaluate the cost-effectiveness of the program after
implementation. The TRC test is therefore the most useful means for comparing the relative
value of demand and supply-side options from the ratepayers' perspective.
The Company should be able to achieve a TRC ratio of 1.25 for all programs. A TRC
ratio above 1.0 indicates the program has met the bare minimum level of cost-effectiveness
to the utilty and its ratepayers. But a review of the Company's filing in this case reveals
3 The Company does not appear to have provided the PCT calculation for all programs in
this fiing. See id. at p. 15 and Appendix 4; see also Idaho Power's 2008 DSM Annual Report,
pp. 11-12 (discussing the TRC and UC tests in more detail, but not discussing use of the PCT
test).
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COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
CASE NO. IPC-E-I0-09
that, at least under the curent methods of analysis, the successful programs far exceed the
bare minimum level of cost-effectiveness. See, e.g., 2009 DSM Annual Report, Supplement
1: Cost-Effectiveness, at pp. 27, 43 (April 16, 2010, Revised Edition) (containing the TRC
ratio of 3.69 for the Home Improvement program and 3.56 for the Custom Efficiency
program). The Commission and the Company should set a higher goal for all programs than
the bare minimum of cost-effectiveness when it is obvious programs can far exceed that
minimum. Requiring all mature programs to achieve a TRC test of 1.25 wil ensure that
programs that canot meet that test wil be improved, or replaced, so that beneficial use of
DSM fuds is maximized.
Additionally, setting a goal of only achieving the bare-minimum level of cost-
effectiveness overlooks that many of the assumptions that go into calculation of the TRC
ratio are just that - assumptions. And as such they are likely inaccurate. Setting a standard
for programs at a score of 1.25 on a TRC basis would therefore allow for some cushion
against modeling errors to ensure that all programs that remain in the Company's DSM
portfolio are indeed cost-effective.
In a prudency review for funds spent in a given year, therefore, the Commission
should require Idaho Power to prove that the funds spent on a program during the review
period were spent in a fashion so as to achieve a TRC ratio of 1.25. If the Company cannot
make such a showing for a mature program, the Commission should order that the Company
abandon the program or demonstrate that the program can be altered such that it wil achieve
a TRC ratio of 1.25 in the next review period. Continued failure to achieve a TRC ratio of
1.25 for a given program should result in a finding that the expenditures were not prudently
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COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
CASE NO. IPC-E-1O-09
incurred.
B. The Commission should require Idaho Power to abandon or improve
underpenorming programs in this case, such as the Holiday Lighting program and
the A/C Cool Credits program.
Although certain programs are clearly cost-effective, some mature DSM programs
appear to have failed to meet a TRC ratio of 1.25, or even 1.0, for the review period at issue
- 2008 and 2009. The Commission should order Idaho Power to stop funding such programs
with EE rider funds, or take substantial steps to improve the programs to a cost-effective
leveL.
For example, the Holiday Lighting program achieved at TRC ratio of only 0.85 in
2009. See 2009 DSM Annual Report, Supplement 1: Cost-Effectiveness, at p. 57. This
program provides an incentive for commercial customers to replace existing holiday lighting
with more efficient LED lights. See 2009 DSM Annual Report, at pp. 84-86. In its third
year, the program should be matue and achieving greater benefits. Yet the Company
appears to have no plans to abandon the program to use the fuds on more cost-effective
efforts, or to seriously modify the program to render it cost-effective. See id. at p. 86 (setting
forth no new strategies for 2010, and instead hypothesizing that the program may improve
"(a)s the market acceptance of LED lighting increases and if the economy improves,,).4
Another program that appears to be achieving less than a cost-effective result is the
AlC Cool Credits program - a peak reduction program on which ratepayers spent almost $3
4 The Heating and Cooling Efficiency Program also suffered from TRC ratio of less
than 1.0. See 2009 DSM Annual Report, at p. 38 (stating the program life TRC ratio is 0.91).
The Company appears, however, to have eliminated some wasteful elements of this program
to succeed in improving its cost-effectiveness in 2009. See 2009 DSM Annual Report,
Supplement 1: Cost-Effectiveness, at p. 23 (stating the TRC ratio for 2009 was 2.05).
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COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
CASE NO. IPC-E-10-09
milion in 2008 and over $3.4 milion in 2009. See 2009 DSM Annual Report, at p. 19. For
that amount of EE Rider expenditure, Idaho Power "assumed" it achieved a load reduction of
29 MW in 2009. See id. at p. 22. But this assumption is based on a detailed analysis of the
irrigation and commercial/industrial peak programs, not a detailed analysis of the AlC Cool
Credits program. Id. And Idaho Power has not conducted a TRC ratio calculation for this
program for 2008 and 2009, the period for which it seeks a prudency determination. Rather,
the Company has only calculated the cost-effectiveness of this program based on a "20-year
model that uses financial and DSM alternative costs assumptions from the 2006 Integrated
Resource Plan." See id. It is not clear from the Company's fiing why the Company cannot
calculate the cost-effectiveness of the AlC Cool Credits program in the two years at issue for
which it seeks a prudency determination. A model analyzing whether the program wil be
cost effective over a 20-year period is not an adequate basis upon which to compare its cost-
effectiveness to that of other DSM programs.
Nevertheless, even when calculated over 20 years into the futue, this program
achieves only a TRC ratio of 1.09, less than an ideal level of at least 1.25. See 2009 DSM
Annual Report, Supplement.i Cost-Effectiveness, at p. 5. The AlC Cool Credits program is
certainly now planned to achieve well below initial expectations. See Order No. 29702, at p.
3 (in authorizing expansion of the AlC cycling program, the Commission noted, "the Company
performed a benefit-cost analysis that showed a positive benefit-cost ratio of 1.42 over a 30-year
period").
Although Idaho Power has not provided a TRC ratio calculation for costs and benefits
of the AlC Cool Credits program in 2008 and 2009, fuher review of the Company's filing
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COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
CASE NO. IPC-E-10-09
reveals that this program may not have achieved even a bare minimum level of cost-
effectiveness in 2009. Idaho Power's filing states that the program cost $3,451,988 in 2009,
but only reduced peak loads by 38.5 MW which, based on ICIP's calculation, resulted in a
cost of $89,662 per MW of peak load reduction. See 2009 DSM Annual Report, at p. 19.
That is far higher than the cost per MW of peak load reduction for other DSM programs
targeting peak. See id. at p. 95 (stating the Irrigation Peak Rewards program cost $9,655,283
in 2009, but achieved 160 MW in peak load reduction, which based on ICIP's calculation
cost ratepayers only $60,345 per MW).5
The third-par evaluation of the program by Paragon Consulting identified a serious
free rider problem. The report concluded that "52% of the customers had an average natural
duty cycle below the enforced duty cycle of the curailment at the beginning of the event."
Idaho Power Demand Response Analysis Report, 2009 A/C Cool Credit Program, prepared
by Paragon Consulting Services, at p. 1 (included in the 2009 DSM Annual Report,
Supplement 2: Evaluations). "These customers are therefore free riders." Id. In other
words, the program did not reduce energy use whatsoever for over half of its participants.
But EE rider funds were paid to those free riders in the form of incentive payments, and EE
rider fuds were used to install equipment at those free riders' residences. The Paragon
report also concluded that the average demand reduction per curailment "was well below the
expected demand reduction. .. found in other utility studies." Id. The third-par
evaluation was far from a ringing endorsement of this program's cost-effectiveness. The
5 Although these calculations ignore customer/paricipant costs and would be analogous to
UC ratio analysis, the paricipants in the AlC Cool Credits and Irrigation Peak Rewards
programs incur no direct participation costs and thus the TRC ratio is the same as the UC ratio.
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COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
CASE NO. IPC-E-10-09
Company's DSM Report discusses plans to expand the program to reach 40,000 total
paricipants, but perhaps the goal should be to reduce paricipation to include only those
customers whose paricipation would reduce their energy use. See 2009 DSM Annual
Report, at p. 22. Or the Company should look to modify this program to target multi-unit
residential buildings and implement the program similar to the FlexPeak program, as
discussed below.
The pool of DSM funds is limited, and the Company's DSM programs demonstrate
that certain programs can achieve far greater than a TRC ratio of 1.0. The Company should
therefore abandon programs that are unable to achieve a TRC ratio of 1.25, and direct the
funds freed up from those unsuccessful programs to balancing its DSM budget and
supporting programs that can achieve a greater TRC ratio of 1.25.
C. ICIP commends Idaho Power for its successful implementation of the FlexPeak
program, and submits that the program's success warrants using this model in
other programs, such as the forthcoming distributed generation program, and for
other customer classes' DSM programs, such as in a multi-unit residential setting.
Although in Case No. IPC-E-09-02 ICIP took issue with some terms of the FlexPeak
program, such as transparency of individual EnerNOC contracts with customers and the notice
provided prior to curilments, ICIP remains generally supportive of the FlexPeak program.
ICIP submits that the huge success and cost-effectiveness of the program warrants using it as a
model the Commission should encourage Idaho Power to follow for other programs.
Idaho Power contracted with a third-pary, for-profit entity, EnerNOC, as the FlexPeak
program operator. EnerNOC has financial incentive to meet peak demand reduction tagets in its
contract with Idaho Power and, unike a utilty that also sells electricity, EnerNOC possesses no
disincentive to pursue demand reduction that wil reduce electricity sales and the future need to
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COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
CASE NO. IPC-E-10-09
build generation resources. Indeed, EnerNOC would pay a penalty under its contract with Idaho
Power if it were to fail to hit its target reductions. EnerNOC achieves peak demand reductions in
this program by directly contacting large commercial and industrial customers in an effort to
locate processes at the customer's facility that can be curiled durng peak hour curailment
events. See FlexPeak Management Demand Response Program Report, Case No. IPC-E-09-02,
p. 3 (Feb. 26, 2010). In 2009, EnerNOC was contractuly committed to 2 MW in demand
reduction for the peak season, but the program exceeded that taget by over eight times, reaching
a 17.1 MW reduction in July 2009. Id. at p. 4. The program achieved a TRC ratio of 1.60 in its
first year, over three times the projected TRC ratio of 0.51. Id. at p. 11. 6 The program only cost
$528,681 to reduce peak demand 17.1 MW. Id. at p. 11.
Idaho Power recognizes the reasons ths program is successfuL. "To penetrate the
medium to large commercial industry and to achieve moderate demand savings on an individual
customer basis is resource intensive in both personnel and technology. Demand response
aggregators have refined their marketing messages and have created audits and processes which
maximize individual demand reduction potential." Idaho Power Response to Commission
Staffs Production Request No. 1. Even Idaho Power recognzes that the requirement that
"EnerNOC pays a penalty to Idaho Power" for failure to meet reduction tagets is a large factor
"enhancing the reliability of its commitments." Id. ICIP agrees, and submits that this model
should be pursued in other programs.
For example, Idaho Power's 2009 IRP identified a distnbuted generation program that
6 The TRC ratio provided in the Company's DSM Report is 1.11, but that ratio is based on
a 10-year contract life based on assumptions made initially by the Company. See 2009 DSM
Annual Report, at p. 82; 2009 DSM Annual Report, Supplement 1: Cost-Effectiveness, at p. 7.
But these in initial assumptions underestimated the cost-effectiveness of this program in the
initial year, and wil likely do so as well for the 10-year contract life.
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COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
CASE NO. IPC-E-I0-09
ICIP believes would be an excellent program for a third-pary aggregator to implement and
operate. The IRP included a distributed generation program that would use the backup diesel or
natual gas generators of large power users as a peaking resource among the Company's
"Committed Supply-Side Resources." See 2009 IRP at pp. 38-39, 71-75. Although not trly a
DSM program, a stadby generator distributed generation program is similar to DSM because it
replaces the need to build new peakng generation resources. The availability of standby
generators provides a basis for obtaining substantial spinning reserves, and thereby saves capital
expenditures on peaking plants and offsets the need to purchase reserves elsewhere. The tre
value of this distnbuted generation program is its use as a reserve resource, not as a resource that
generates substantial amounts of electricity, and although permitted and authorized to generate
power up to 400 hours per year, under normal conditions the generators would rarely ru. ICIP's
position is that Idaho Power's program could easily reach 80 MW of backup peaking reserve
requirements in the near future, an amount well within tagets that Portland General Electric has
set for its backup generator program. Idaho Power disagrees, and calculates the costs as being
more expensive than other peaking resources. See id. The IRP states the Company has been
investigating the merits of this program since before 2006, see id. at p. 38, yet Idaho Power stil
appears to be unable to render it cost-effective.
Given Idaho Power's difficulty in implementing this program, ICIP submits that Idaho
Power should release a request for proposals similar to the EnerNOC/FlexPeak RFP to determine
if a third-pary entity with experience rung distributed generation programs could operate
Idaho Power's program more cost-effectively than Idaho Power states it could do so in its IRP.
ICIP is aware that an EnerNOC affiliate company rus a very similar diesel generator distributed
generation program for San Diego Gas and Electric, and the program, in addition to being a cost-
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COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
CASE NO. IPC-E-I0-09
effective alternative to new peaking resources, has garnered the support of environmental groups
such as the Sierra Club. ICIP has attched (as Attchment 1) the Sierra Club Californa's letter
to the California Public Utility Commission in support of expansion of the program to 50 MW,
which explains the benefits well. For many of the same reasons cited by Idaho Power regarding
the benefits of a third-par aggregator DSM program, a third-par ru distnbuted generation
program is likely to be successfuL. An aggregator such as EnerNOC wil hit the ground ruing
with experience, software, and marketing strategies from ruing similar programs elsewhere.
An RFP would allow Idaho Power to more seriously pursue this peaking resource.
Another potential third-pary aggregation program Idaho Power could pursue was
recently discussed in the New York Times. See "To Cut Demand for Electricity, Some
Customers Agree to Unplug,"New York Times (Aug.12,2010),
http://ww.nytimes.com/201O/08/13/nyregion/13peak.html?hpw (Attchment 2 to these
Comments). The aricle discusses the success of a third-pary aggregator program directed at
aparment buildings, and the parallels to the FlexPeak program are obvious. A thrd-pary
aggregator contacts the potential customer paricipants and helps them curail non-essential
electricity use at pre-determined times in exchange for payment from the utilty. The
Commission should encourage Idaho Power to implement the FlexPeak model in other customer
classes, such as the multi-dwelling residential setting discussed in the New York Times article.
D. Idaho Power should rely more heavily on third-part evaluations of its DSM
programs.
Third-party evaluations of the Company's programs provide an obvious benefit. Much
like contracting with third-pary aggregators, a well-chosen, third-pary evaluator will have
existing software, personnel, and experience in evaluating DSM programs, yet lack any incentive
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COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
CASE NO. IPC-E-10-09
to portay the Company's DSM programs in an unjustifiably favorable light. Yet Idaho Power
only uses "third-pary evaluators when appropriate for the specific studies or evaluations." See
Application, at ir 11 (c). It is not clear what makes one program appropriate for a third-pary
evaluation from Idaho Power's application. At a minimum, Idaho Power should provide some
set of criteria by which it wil determine when it engages a third-pary evaluator. As discussed
above, the third-pary evaluations have provided a candid review of the AlC Cool Credits
program, and that evaluation should be used to improve the use of EE rider fuds. Idaho Power
canot be expected to possess the motivation, let alone the expertise, to produce in-depth reviews
of the impact of its DSM programs for use in prudency reviews.
Thrd-par evaluations are instrental in determining which programs are succeeding,
and which programs are failng and need to be improved or abandoned. The Commission
should require Idaho Power to conduct more frequent third-pary evaluations for more programs,
or at a minimum require Idaho Power to set forth a standard set of criteria by which it wil
determine a given DSM program is not in need of third-pary evaluation.
III
CONCLUSION
ICIP appreciates the opportunity to comment on Idaho Power's request for a prudency
determination as to expenditue of EE rider fuds spent in 2008 and 2009. ICIP respectfully
requests that the Commission condition any finding of prudency of the expenditure of these
fuds on the additional requirements that Idaho Power abandon individual programs that fail to
meet a total resource cost benefit ratio of 1.25 or greater once matue. ICIP additionally requests
that the Commission order Idaho Power to abandon or modify the Holiday Lighting and AlC
Cool Credits programs, encourage Idaho Power to use the FlexPeak program as a model for other
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COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
CASE NO. IPC-E-1O-09
programs which could be ru with third-pary aggregators, and order that Idaho Power rely more
heavily on third-pary evaluations in the future or at least provide criteria establishing when
third-pary evaluations are appropriate.
DATED this 13th day of September 2010.
RICHARSON AND O'LEARY, PLLC
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COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
CASE NO. IPC-E-1O-09
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 13th day of September, 2010, a tre and correct copy of the
within and foregoing COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER,
was served in the maner shown to:
Ms. Jean Jewell
Commssion Secreta
Idao Public Utilties Commission
POBox 83720
Boise, il 83720-0074
Lisa D Nordstrom
Donovan E Walker
Idaho Power Company
POBox 70
Boise, Idaho 83707-0070
lnordstrom(iidahopower .com
dwalker(iidahopower.com
Darlene Nemich
Greg W. Said
Director State Regulation
Idaho Power Company
P.O. Box 70
Boise,ID 83707-0071
dnemnich(iidahopower.com
gsaid(iidahopower.com
Benjamin J. Otto
Idaho Conservation League
710 N. 6th St.
P.O. Box 844
Boise, Idaho 83702
botto(iidahoconservation.org
Eric L. Olsen
Racine, Olson, Nye, Budge &
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Nina M. Curtis
IPC- E-l 0-09
IN THE MATTER OF IDAHO POWER COMPANY'S
APPLICATION FOR A PRUDENCY DETERMINATION OF
ENERGY EFFICIENCY RIDER FUNDS SPENT DURIG
2008-2009
Comments of the Industrial Customers of Idaho Power
September 13, 2010
Attachment 1
Letter from Sierra Club California to California Public Utility
Commission Supporting Third-Part Distributed Generation
Contract
SIERRCWB
CALIFORNIA
August 17, 2009
Michal Peevey, Chair
Californa PubEc Utilities Commission
5th Floor
505 VanNess
San Francisco, CA 94102
RE: Proposed Decision in A.08-10..003, Application of San Diego Gas & Electric
Company (U902E) for Approval of the Celerity Distributed Generation Supply
Contract
Dear Chai Peevey:
Sierra Club Calìfomia objects to the Proposed Decision which would r~ect the San
Diego Ga & Electric contract with Celerity. The proposal by SDG&E and Celerity is to
retrofit diesel back..up genertors (BUGs) at customer facilities so that those facilities
could be used up toa maximum of 199 hour per year for grid reliability puroses.
It is our understanding that the project woiùd add 25 megawatts (MWs) of new peak
capacity, biinging the total San Diego BUGs program up to 50 megawatts. This new 25
megawatts of capacity would help meet the shortfall of 14 megawatts shown in the 201 0
CAISO Local Capacity Requirements tUlder operatig Category C. (Decision 0906028).
This decision noted:
The San Diego area LCR need increed partly because of load growth and partly because of the
new atay Mesa generatig facilty becomig the biggest single generation contingency in the
area. (hLtp:/ldocs.cpuc.cagov/PUBLISHED/FINAL DECISION/! 02155-02.htin)
The Proposed Decision in A. 08-10-003 rej eots SDG&E' s claim regarding need, statng
that:
By SDG&E's own assessment, the J-Power Grove project is expected to be in
service in October of2009, Wellhead Margarita is expected to be on-line in the
latter halfof2009, Otay Mesa is expected to be in service in the summer of 2009
and the Lake Hodges pump storage facility will be on-1îne in early 2010.
However, the statement in ths Proposed Decision about reduced need for new generation
resource in. San Diego due to Otay Mesa coming on line is inconsistent with the adopted
final decision of the commsion regarding resource adequacy cited above. In fact, as
pointed out in that earlier decision Otay Mesa becomes the largest generator, and thus is
discounted in G-IIN-J resource adequacy counting requirements. Otay Mesa does not
ti 801 K St., Suite 2700, Sacramento, CA 95814
[phone] · Fax [phone] · ww.SierraClubCalifornia.org .~26100 po-cns waste
contribute toward resource adequacy, but actually helps to create the CAISO projected
shoitfall under Category C.
In addition, the generators cited above cóuld be delayed, while the backup generators
alrefldyexist. In fact, rapid and scaled deployment is a major benefit of distribnted
generation resources. And in parcular it avoids the serious waste of capital resource on
large central power plants and major new transmIssion lines that then becoine
"discounted" under G-l/N-l reliabilty criteria.
Sien'a Club Califoinia Is concemed that, by rejecting this contract, the CoInmission Is
discouraging the use of existing distributed generation resources for the pLU-poses of
meeting peak requirements or reliabilty needs and therefore, el1couraging new, central-
station peaking resources. Sierra Club California believes that that the alternative of
building new central station pealång plants is. less efficient, more costly and, ultimately,
less beneficial for the environment. Sierra Club Califomia therefore encourages the
Commission to reconsider ths position, and to reverse the Proposed Decision. Reversing
the Proposed Decision will allow SDG&E to use BUGs, such as in the proposed Celerity
contract.
Throughout Calforna, over 3000 megawatts of back-up generators exist at custonier
sites, a valuable resource that is curently not utilized .fom the perspective of ptoviding
reliability and/or peakg benefits to the gnd. Sierr Club CalfornIa strongly supp.ort
the emissions restrctions that exist for imimproved back-up diesel generators. However,
those BUGs can be retrofitted with paiticulate filters and re-permitted by the local Air
Qualty Management District (AQMD) as was done for the first SDG&E - Celerty
agreement.
Reversing the Proposed Decision allows the local AQMD to permit increased hours of
operation by BUGs with a net anual reduction in the emissions which concern the local
AQMD. Specifically for the SDG&E - Celerity agreement, reversing the Proposed.
Decision, reduces annual pariculate emssions, a signficant environmental benefit
relative to the BUGs cuiTent emissions without modem particulate filters. Our analysis is
that under the líkely range of .operating condition, paiticulate emissions wil be reduced
compared to ning these generators without fiters for maintenance and occasional
emergency outages. While these plants are permtted to run up to 200 hours per year,
running over even i 00 hours per year would only happen under very extraordinar
circumstance.
TIie BUGs de not require new siting, construction and disturbance to a Greenfield site;
they are distrbuted so as to provide local benefits that may .obviate the need for costly
transmission and/or distrbution infrastrctue. And the new infrastrcture would likely
only operate at about 1 % annual capacity (100 hours/8760 hours), and in no case could
operte at morc than about 2% (200 hours/8760 hours). For resoiu'ces that are used so
little, far more carbon and other environiental impacts wil be attributable to the
infrastructure than to the fuel combustion itself. And while it is true that the diesel
generators have a higher heat rate than a gas peaker, the marginal difference becomes
insignificant when these are operated so few hours per year. Using existing backup
gienerators woitld encourage more effcient use of existing resources, and would greatly
reduce lifecycle emissions relative to the manufacture, transport, and construction of new
ccmtlalized peaers.
So, while we ar sympatetic with the Conissioils desire to reduce the use of
unimplQved, diesel BUGs, the Sierra Club California recommends that BUGs, improved
to meet the pemiit requirements ofthe local AQMD, be preferred to new central station
peaker capacity in Calif011ia when these would nonua1ly operate much less thå1 100
hours per year, and in no case caii operate more than 200 hours per year.
We are also sensitive to the issue of fuel conversion cited in the Proposed Decision.
However, we note that conversion to natural gas, while generally a much cleaner fuel
than diesel, may not meet the req1.rements of site owners. However, a failure by the
developer to convert fuels as origially proposed does not eliminate the benefits of
adding filters to diesel generators. And it is very unlikely that these generators would
switch to natural gas if the contrct is denied.
The Proposed Decision would create a bias toward long-term commitments to new, fossil
fuel, central-station peaking facilties, with associated costs, and environmental
degrtion. From a larger perspective, the use of existing, retrofitted, distrbuted
generators can provide a better environmental solution. . As such, Sierra Club Calfomia
requests tht the Commission reject the Proposed Decision as written and approve the
SDG&E request.
Respectfully,1~~.....
l~ MekpuJOs
Sierr Club Cal1fomIa
cc: Assigned Commssioner, John Bohn
Preident Michael Peevey
Conmissioner Rachelle Chong
Commssioner Timothy Simon
Commissioner Dian Greneich
Nancy Ryan, Deputy Executive Director
Mathew Deal, Advisor
Robert Kiosian, Advisor
Jamie Fordyce, Advisor
Andrew Campbell, Advisor
Kaen Shea, Advisor
IPC- E-l 0-09
IN THE MATTER OF IDAHO POWER COMPANY'S
APPLICATION FOR A PRUDENCY DETERMINATION OF
ENERGY EFFICIENCY RIDER FUNDS SPENT DURIG
2008-2009
Comments of the Industrial Customers of Idaho Power
September 13, 2010
Attachment 2
"To Cut Demand for Electricity, Some Customers Agree to
Unplug," New York Times (Aug. 12, 2010)
Some Ìn New York Agree to Unplug to Cut Energy Use - NYTimes.com Page 1 of3
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CAREY
MULLIGAN
August 1i, i010
To Cut Demand for Electricity, Some
Customers Agree to Unplug
By MATTHew .L. WAL.D
Electrcity use is up sharly this summer, but in a windowless room near Albany that is the
nerve center of New York State's grid, controllers have noticed that something else is not rising:
peak load.
Peak load is the single hour of highest use in the course of the year, a condition for which the
electric system is designed and which is the focus of utilties' operating strategies and,
sometimes, prayers. Driven by each new air-conditioner, computer and flat-screen television,
peak load grew inexorably from the 1980s until the recession.
But it has stopped its climb, and experts say more is at work here than the stalled economy.
Electrcity experts compare July 2010 to August 2006, when New York State set its all-time
peak demand, 33,939 megawatts. Energy consumption last month was 7.8 percent higher than
in August 2006. But the peak demand was 1.4 percent lower.
CLast summer was relatively cool and did not yield high numbers for energy consumption or
peak demand.)
There are several small reasons that consumption grows while peak load does not. One is
weather patterns, the ratio of very hot days, which drive consumption, to extemely hot days,
which drve peak. But another is man-made: "demand-side management," under which
customers agree to unplug when controllers need them to.
When balancing electricity supply with demand, demand-side management is a huge weight on
htt://ww.nytimes.com/201 0/08/13/nyregion/13peak.htm? ~r=2&hpw=&pagewanted=print 9/8/2010
Some in New York Agree to Unplug to Cut Energy Use - NYTimes.com Page 2 of3
the scale on critically hot days.
From the fountain at Lincoln Center to the laundi room and swimming pool at the Gotham
condominium building on East 87th Street to the elevators and loading dock lighting at 344
Hudson Street in Manhattan, things are being turned off when supply demands it.
The system controllers in Albany, at the New York Independent System Operator, now count
about 37,400 megawatts of generators statewide that can be turned on, and about 2,200
megawatts of consuming devices that can be turned off.
This is not an emergency procedure or an appeal to civic duty - although those can still be
invoked on occasion. Rather, it is a commercial transacton with a protocol planned long in
advance. On the afternoon before an anticipated surge in demand, e-mails, faxes and phone
calls go out alerting those who had already agreed that it is time for them to unplug.
''You get called a day ahead, and all hell breaks loose when they call," said Leo Cutone of Cutone
& Company Consultants, which recruits buildings and institutions to parcipate. Common
steps are adjusting air~conditioning thermostats, turning off some elevators, switching off lobby
lights or startng up emergency generators.
"If it's nice and sunny enough, then the lobby is bright enough without arificial lighting," said
Lewis Kwit of Energy Investment Systems, a company that serves as a "demand response
servce provider."
Mr. Kwit has lined up about 10 aparment buildings where superintendents will close the
laundi room and post signs asking tenants to delay using their dishwashers until the early
morning. "You can save 20 to 30 percent," he said.
Companies that recruit buildings or propert owners to partcipate are paid by the New York
Independent System Operator or by the local utilty. The prices have been running $12 to $13
per kilowatt of reduction.
Alfonse Amore, the senior vice president at Trinity Real Estate, a propert management
company, said it enrolled 13 offce buildings in the program this summer. Building personnel go
from door to door asking tenants to turn off nonessential equipment.
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Some in New York Agree to Unplug to Cut Energy Use - NYTimes.com Page 3 of3
"Tenants are fully aware of the problems with electrical distribution," he said. "They want to
continue in business without having a blackout or a brownout." And they understand
immediately when walking through a slightly darkened lobby, he said.
Trinitys buildings have a collective load of 16 megawatts and can cut that by 2 megawatts, said
Alec V. Salticov, the manager of engineering. Next summer, he will try for 3.5 megawatts, he
said. The procedure was invoked by the grid operators three times in July, Mr. Salticov said.
Participants have meters with modems or other communications devices that report to a local
utility four times an hour. For energy companies, demand-side management may help them
avoid building power plants that would be needed only a few hours a year or transmission and
distrbution lines that would seldom be used to capacity. Trimming the peak load by a few
percentage points means getting more use out of existing equipment.
In a place like New York, where getting permission to build a plant or power line is extemely
diffcult, energy experts say the strategy is especially valuable. And its effects are obvious at
Consolidated Edison, said Joseph Oates, vice president of energy management.
Con Ed's peak load growth had been 1.5 percent a year but will probably be only about 0.35
percent for the next few years, despite the proliferation of cheap air-conditioners and big-
screen televisions. "We think it's a permanent change," he said.
Apar from the proceeds flowing to the demand response servce providers and customers, the
technique may also ultimately cut costs for nonparicipants. Electricity is priced in an auction
system, and reducing demand reduces the price.
htt://ww.nytimes.com/20 1 0/08/13/nyregion/13peak.html? r=2&hpw=&pagewanted=print 9/8/2010