20120625Comments.pdf

ATTORNEYS AT LAW
Peter Richardson
Tel [phone] Fax: [phone]
[e-mail]
ID P.O. Box 7218 Boise, ID 83707 - 515 N. 27th St. Boise, 83702 rn
C)..._ UI I'll
25 June 2012
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55 na
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Ms Jean Jewell
Commission Secretary
Idaho Public Utilities Commission
P 0 Box 83720
Boise ID 83720-0074
RE Case No IPC-E-12-15
Dear Ms Jewell
Enclosed please find an original and 7 (seven) copies of the COMMENTS
OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER in the above case.
I have also enclosed an extra copy to be service-dated and returned to us for
our files. Thank you.
Sincerely,
Nina Curtis
Administrative Assistant
encl.
P : f) Peter J. Richardson (ISB # 3195)
Gregory M Adams (ISB # 7454) jji 25 PM 2 58
Richardson & O'Leary PLLC
515 N 27th Street
LIT, LH CO 510
P.O. Box 7218
Boise, Idaho 83702
Telephone: [phone]
Fax [phone]
peter@,dchardsonandolega.com
[e-mail]
Attorneys for the Industrial Customers of Idaho Power
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF ) CASE NO IPC-E-12-15
IDAHO POWER COMPANY FOR A )
DETERMINATION OF 2011 DEMAND-SIDE ) COMMENTS OF THE INDUSTRIAL
MANAGEMENT ("DSM") EXPENDITURES ) CUSTOMERS OF IDAHO POWER
AS PRUDENTLY INCURRED )
INTRODUCTION
COMES NOW, the Industrial Customers of Idaho Power ("ICIP") and pursuant to Order
Nos 32512 and 32569 issued April, 10 and June 7, 2012 in the above captioned docket and hereby
respectfully submits the following Comments on Idaho Power Company's ("Idaho Power" or
"Company") Application for a Determination of 2011 Demand-Side Management ("DSM")
Expenditures as Prudently Incurred As explained below, the ICIP's comments focus on the need
to consistently evaluate cost effectiveness by applying the same test to all resources for both the
demand- and the supply-side of the equation.
IPC-E-12-15
COMMENTS OF INDUSTRIAL CUSTOMERS OF IDAHO POWER
PAGE 1
1. MEASURE OF DEMAND-SIDE MANAGEMENT COST EFFECTIVENESS
According to Idaho Power, and consistent with the Commission's directives, its goals
regarding DSM and energy conservation are:
Through DSM programs, Idaho Power seeks to provide customers with programs
and information to help them manage their energy usage and to achieve prudent
cost effective energy efficiency and demand response resources [collectively,
"DSM"] to meet its electrical system's energy and demand needs.'
Meeting the "electrical system's energy and demand needs" through DSM has the effect of
reducing the need to build new electric generation facilities and/or purchases in the relatively
volatile wholesale market. The test of "prudent cost effective energy efficiency and demand
response resources" must be whether the cost of a kWh or kW saved is equal to or less than the
cost of Company generation and or market purchases of the same amount of energy. According to
the Company, the alternative energy costs used to measure the cost effectiveness of DSM
programs are defined as follows:
• The alternative energy costs are based on both the projected fuel costs of a
peaking unit and forward electricity prices as determined by Idaho
Power's power supply model, AURORAxmp® Electric Market Model.
• The avoided capital cost of capacity is based on a gas fired simple cycle
turbine.2
In the Company's 2011 IRP, the annual avoided capacity cost is $94.00/kW. When multiplied by
the effective load carrying capacity (to reduce the avoided capacity cost), the annual avoided
capacity cost is $87.80/kW. In addition, it is noteworthy that the avoided capacity cost of a simple
1 Idaho Power Application, p. 2, IPC-E-12-15.
2 Demand-Side Management 2011 Annual Report, Supplement 1: Cost-Effectiveness, p. 3, IPC-E-
12-15. Emphasis provided.
IPC-E-12-15
COMMENTS OF INDUSTRIAL CUSTOMERS OF IDAHO POWER
PAGE 2
cycle turbine in the DSM calculation in 2009 was $63.00fkW, an increase of 49% over this two
year period.3
The alternative energy costs used by the Company in determining the cost/benefit ratios for
the various DSM programs are divided into five different pricing periods. The five pricing periods
are:
• Summer On-Peak (SONP)-Average of variable energy and operating costs of a 170 MW
SCCT, which is the marginal resource for peak hour load deficits during summertime
heavy load hours;
• Summer Mid-Peak (SMP)-Average of heavy load prices from June-August;
• Summer Off-Peak (SOFP)-Average of light load prices from June-August;
• Non-Summer Mid-Peak (NSMP)-Average of heavy load prices in January-May and
September-December; and
• Non-Summer Off-Peak (NSOFP)-Average of light load prices in January-May and
September-December.4
The values used for these five pricing periods - as shown below in Table 1 - were derived
from financial assumptions including Idaho Power's discount rate and cost escalation rate as inputs
to the AURORA model. As explained in Idaho Power's current Integrated Resource Plan:
The prices of avoided energy throughout the 20-year planning period were
simulated using the Preferred Portfolio module with the AURORA model. The
Preferred Portfolio module considers the energy capacity and resource costs of the
current preferred mix of IRP resources along with regional transmission resources
in the Western Electricity Coordinating Council (WECC) region to project
forward electric market prices. The forward prices are placed into five
homogenous pricing categories that follow the pattern of heavy- and light-load
pricing [see above] throughout each year of the planning period.5
The Company uses three common cost/benefit ratios to determine the cost effectiveness of its
DSM programs. These ratios are aimed at equating demand-side programs with supply-side
Idaho Power's 2009 Integrated Resource Plan, Appendix C, p. 98, IPC-E-09-33.
Idaho Power's 2011 Integrated Resource Plan, Appendix C, p. 67, IPC-E-1 1-11.
5
IPC-E-12-15
COMMENTS OF INDUSTRIAL CUSTOMERS OF IDAHO POWER
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resources. "Specific programs or potential energy measures are screened using a static economic
analysis to determine if these programs or measures are potentially more cost-effective than the
next best supply-side resource alternative."6 The ratios are also used to provide information about
the costs and benefits of a given program from a variety of perspectives, including that of the
Company, all of the Company's customers in its service area (participating and non-participating),
and the Company's average participating customers (those participating in the relevant
conservation program).7
Idaho Power tests the cost effectiveness of its Demand Response Programs (A/C Cool
Credits, FlexPeak Management, and Irrigation Peak Rewards) over a 20-year period.
The goal of demand response programs is to minimize or delay the need to build
new supply-side resources. Unlike energy efficiency programs, demand response
programs must acquire and retain participants each year to maintain a level of
demand reduction capacity for the company. Demand response programs are
expensive and generally have a higher initial investment than energy efficiency
programs. As such, demand response programs are analyzed over the program life
in which historical program demand reduction and expenses are combined with
forecasted program activity to better compare the program to a supply-side
resource. 8
Hence, cost-effective DSM measures are not assured over the twenty year planning
horizon; they must be recalculated every year to ensure there is sufficient participation.
2. AVOIDED COST RATE REDUCTION IN CURRENT CASE GNR-E-11-03
The question of the value of avoiding future construction and/or market purchases is
currently being addressed in another docket before this Commission. In the generic avoided cost
6 Direct testimony of Idaho Power witness Darlene Nenmich, p. 14, IPC-E-12-15.
7 Id. atpp. 13-14.
8 Idaho Power's Demand-Side Management 2011 Annual Report, Supplement 1, p. 2, IPC-E-12-
15.
IPC-E-12-15
COMMENTS OF INDUSTRIAL CUSTOMERS OF IDAHO POWER
PAGE
docket,9 all three utilities are proposing that their actual energy and capacity needs be taken into
account in determining the costs the utilities will avoid if they purchase power from PURPA
qualifying facilities. The reason the utilities are advocating for such a change in calculating their
avoided costs is that during a time of energy or capacity surplus QF purchases arguably do not
displace or defer new resources. The standard rate offered QFs under PURPA contracts is based on
the costs the utility avoids by not having to generate or purchase power itself. Energy efficiency
works in the same way, in that it reduces a utility's energy as well as capacity needs. A utility thus
avoids generation and purchase costs when it implements energy efficiency.
The Commission is re-examining the calculation of QF avoided cost rates in light of
reduced natural gas forecasts, reduced load forecasts and least-cost model forecasts in the
Company's IRP.'° The Company's primary concern in that case is that it will be required under
PURPA regulations to enter into contracts for energy it does not need at prices that are too high,
unduly inflating customer rates. Assuming this argument is valid in the context of avoided cost
rates for QFs, this same argument ought to instruct the validity of the current method for
evaluating future energy efficiency and demand-side management expenditures.
The evaluation of system costs used by the Company for DSM in this docket is
significantly different from that used in the determination of QF rates currently and separately
being advocated before the Commission in case GNR-E-11-03. Table 1 below demonstrates the
vast difference in the alternative costs used in the cost/benefit analysis to determine the cost
effectiveness of DSM programs as compared to those avoided costs proposed for QFs. With the
decrease in forecasted costs, the difference between the DSM methodologies and, the QF avoided
9 Case No. GNR-E-11-03.
10
IPC-E-12-15
COMMENTS OF INDUSTRIAL CUSTOMERS OF IDAHO POWER
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cost methodologies (that the Company is currently advocating in GNR-E-1 1-03) will become so
disparate as to warrant modifying the measurement of cost effectiveness for energy efficiency and
DSM programs
Table 1, below, is a graphic illustration of the cost effectiveness hurdle for the various
DSM programs and energy efficiency as compared to the forecast avoided cost rates.
Table 1
As Table 1 shows, each of the five pricing period costs used as alternative costs for testing DSM
programs is significantly higher than the levelized avoided costs for generic QFs. It might be
argued that QF's are not dispatchable and rather are 'must takes' that are therefore not directly
comparable However majority (56%) of expenditures Company's conservation programs are for
'1 Idaho Power 2011 Integrated Resource Plan, Appendix C, p. 69, IPC-E-1 1-11; see also
Memorandum in Support of Temporary Stay, p. 15, GNR-E-1 1-03.
IPC-E-12-15
COMMENTS OF INDUSTRIAL CUSTOMERS OF IDAHO POWER
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energy efficiency programs that are also 'must take.' 12 There are several reasons for this significant
difference. One is the use of a slightly lower gas forecast in each year over the next 20 years.
However, by far the two most significant drivers in the low avoided costs in the QF context as
compared to the avoided costs in the DSM context are that; (1) Idaho Power is proposing to
eliminate QF's capacity payments during periods of declared surplus; and (2) the Company is
proposing to define QF avoided costs in very short-run terms. According to Idaho Power this short
run approach includes times when the Company states its avoidable incremental costs are either
zero or negative. If it costs the Company very little or nothing for its incremental supply, then that
factor should be recognized whether the company is looking to purchase energy, reduce demand or
promote energy efficiency. Idaho Power is currently taking the position in the generic avoided
cost docket that near term avoided cost rates are potentially negative. According to Idaho Power
witness Karl Bokencamp:
Q. Are there times when the avoidable incremental costs calculated with Idaho Power's
proposed methodology are zero?
A. Yes, and this is not unrealistic. Considering the minimum load levels established for the
thermal generating resources, and the amount of non-dispatchable QF generation on Idaho
Power's system, there may be hours during low load periods when Idaho Power's avoidable
incremental costs are zero. In fact, there could be times when Idaho Power's avoided
incremental costs would be negative (i.e. an increased incremental cost would be imposed).
For example, if loads are low and a thermal unit is shutdown in order to accept additional
QF generation and then the output of the intermittent QF generation drops off, additional
costs could be incurred if the previously shutdown thermal unit is unavailable to replace
the QF output. A more expensive unit may have to be started or more expensive market
purchases may be required. In either situation, additional costs are incurred. 13
12 Direct Testimony of Idaho Power witness Darlene Nemnich, Exhibit 1, IPC-E-12-15.
13 Direct Testimony of Idaho Power witness Karl Bokenkamp, pp. 14-15, GNR-E-1 1-03.
IPC-E-12-15
COMMENTS OF INDUSTRIAL CUSTOMERS OF IDAHO POWER
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The implications for avoided cost rates, if the Company's position is adopted by the
Commission, are nothing short of a dramatic reduction which will surely mothball the QF industry.
The implications for the demand-side management must likewise be considered in this docket.
3.EFFECT OF A SHORT-RUN, REDUCED AVOIDED COST RATE FOR QFs
The new, short-run avoided cost rates as advocated in GNR-E-1 1-03 could in fact disallow
those energy efficiency expenditures which fail to meet the Company's own test for cost
effectiveness as applied to PURPA projects. If an energy or capacity surplus affects the value of
QF energy, then it follows that at a time of surplus, many heretofore cost-effective energy
efficiency measures will be 'out of the money.' Because the avoided cost rates are only now being
questioned, the 2011 DSM expenditures are not therefore per se imprudent. However, if the
methods advanced in GNR-E-1 1-03 are meant to reflect a more holistic approach in ascertaining
what the Company has avoided by not having to generate or buy power itself, then that same
approach should be applied across the board to all aspects of the Company's cost effectiveness
evaluations generally. Ultimately, both considerations serve the same purpose for a utility and its
customers alike - to provide the means for the utility to meet its service area's energy and demand
with resources relatively less expensive than generation or purchases.
4.ALTERNATIVE AND AVOIDED COSTS SERVE THE SAME PURPOSE, AND THUS
SHOULD BE APPLIED FOR COST EFFECTIVENESS ON THE SAME BASIS
Idaho Power's approach in the QF docket incorrectly assumes avoided costs should be
based on a very short-run hourly basis. 14 In Dr. Reading's direct testimony filed in GNR-E-1 1-03
he advocated that the correct avoided costs for an electric system should be based on the long-run
costs of the utility. That said, if Commission rejects Dr. Reading's argument that avoided costs are
14 Direct Testimony of Don Reading, p. 29, GNR-E-1 1-03.
IPC-E-12-15
COMMENTS OF INDUSTRIAL CUSTOMERS OF IDAHO POWER
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properly calculated on a long-run basis and if the Commission agrees with Idaho Power that there
are public-interest and 'lust & reasonable" concerns over current QF avoided costs, the result will
simply eliminate virtually all of Idaho Power's energy efficiency measures. If the Commission
buys Idaho Power's avoided cost arguments and finds that customers are being forced to pay for
inflated resources before energy is actually needed by the utility to serve its customers, those
concerns do not simply disappear when energy efficiency measures are being evaluated. This
means that a short-run application would wipe out almost all energy efficiency and DSM
measures.
Without looking in detail at the various cost/benefit ratios employed for each conservation
program, the basic approach is to compare the costs of each program with the energy saved (priced
at the alternative costs found in each of the above referenced five pricing periods). Therefore, the
measuring stick for "prudent cost effective energy" savings equals the costs the Company can
avoid by implementing DSM programs rather than building additional generation capacity to meet
the system needs. Stated another way, the savings equal the cost of the electric energy which, but
for the energy efficiency measures, the Company would have had to produce itself or purchase
from another source. This formulation of a "but-for" analysis for alternative costs has its basis in
the avoided costs determination in Section 210 of PURPA to offer to purchase Qualifying
Facilities. In GNR-E-1 1-03 Idaho Power witness Hieronymus provided a definition of avoided
costs, quoting Section 210 of PURPA:
"For purposes of this section, the term 'incremental cost of alternative electric
energy' means, with respect to electric energy purchased from a qualifying
cogenerator or qualifying small power producer, the cost to the electric utility of the
IPC-E-12-15
COMMENTS OF INDUSTRIAL CUSTOMERS OF IDAHO POWER
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electric energy which, but for the purchase from such Co generator or small power
producer, such utility would produce or purchase from another source."5
As can be seen by the above definitions of alternative and avoided costs that are used by
Idaho Power, the cost effectiveness of DSM programs and the avoided cost required in Section 210
of PURPA to be offered to QFs are essentially the same. Whether it is "but-for" the energy
efficiency implemented by the Company or "but for" the QF generation supply, the end result is
that the Company has avoided having to produce or purchase energy to meet the demand in its
electricity service area. Therefore, the measuring stick of determining the cost effectiveness of
either alternative or avoided costs should likewise be the same.
If the costs of additional power to the system are, as the Company states, at times zero for
the purpose of determining avoided cost rates for independent power producers, then it also means
the value of conservation programs the ratepayers are being charged for would at those times also
be zero. This cost to the Company serves as a starting point to determine what economically
viable alternatives are available to it, be they energy efficiency and demand-side resources, or
alternative energy generators offering supply-side resources. The Commission has stated
repeatedly that it favors all cost-effective conservation.
The Commission has consistently stated that cost-effective DSM programs are in the public
interest and has admonished electric utilities operating in the State of Idaho to develop and
implement DSM programs in order to promote energy efficiency. See Order Nos. 29784,
29952.16
The key element in the Commission's directive is the phrase "cost-effective DSM programs."
"Cost-effective" is, of course, a function of the cost the utility assigns the estimated power savings
" Direct Testimony of Idaho Power witness William Hieronymus, p. 19, GNR-E-1 1-03.
16 Idaho Public Commission Order 32113, p. 8, Case No. IPC-E-10-09.
IPC-E-12-15
COMMENTS OF INDUSTRIAL CUSTOMERS OF IDAHO POWER
PAGE 10
of its DSM programs. If those costs do not reflect realistic costs of the power system, then the
cost/benefits of the program will not be accurately calculated.
If the system costs used in the evaluation of DSM programs were equivalent to those
proposed for the determination of QFs' avoided cost rates, it would mean the majority - if not all -
of those DSM programs would be deemed cost-ineffective. This result would effectively mean the
end of conservation efforts by Idaho Power (just as the proposed avoided costs by Idaho Power
will mean an end of PURPA projects for QFs for the foreseeable future). That result will have to
be applied to DSM as well as PURPA. While the ICIP is not a party to the avoided cost docket, it
does expect consistent application of cost-effective tests. Should the Commission determine that
Dr. Reading's testimony in that docket is incorrect and should the Commission adopt Idaho
Power's short-run avoided costs test, then in order to avoid discriminatory treatment of similar
resources and to avoid massive subsidies of DSM measures, the Commission will have to
eliminate most, if not all, DSM programs. This would not be a desirable result or one advocated
by the ICIP. We agree with the Commission that when all cost-effective DSM are undertaken by
the utilities it is good for the power system and ratepayers. The correct measure is the long-run
approach akin to the method offered by Dr. Reading in GNR-E- 11-03. This approach, as pointed
out in Dr. Reading's testimony in that docket, is a realistic approach in determining alternative
costs of a power system.
CONCLUSION
If the Commission determines the proper avoided costs for determining cost effectiveness
are consistent with those proposed by the Company in GNR-E-1 1-03, then the ICIP recommends
that the Commission find that Idaho Power's expenditures for all DSM programs in the future be
IPC-E-12-15
COMMENTS OF INDUSTRIAL CUSTOMERS OF IDAHO POWER
PAGE 11
assessed in the same manner for determining prudence. The measuring stick for alternative or
avoided costs rationally must be equal, and equally applied. Therefore, if avoided costs are
measured based on short-run projections, then so too must DSM expenditures be measured against
short-run projections. Otherwise, a short-run perspective on QF avoided costs with disparate long-
run views on DSM/energy efficiency would result in disparate treatment between the various
"resources" the Company will employ to ensure it uses the least-cost alternative to meet the energy
and demand needs of its service area. If the reduced natural gas prices affect the Company's
avoided cost as to QF purchases, then they must logically also affect (and thus lower) the costs
against which DSM/energy efficiency is to be measured.
Using a short-run benchmark for determining the cost effectiveness of DSM will likely
mean that all or most of the Company's current DSM programs will be above the avoided cost
rates the Company itself is currently advocating (based on its short-term natural gas price
projections). Setting the benchmark for all marginal avoided costs over the long term is the only
way to ensure not only that the utility values these various resources equally, but that some of the
DSM programs will still be economically viable.
Respectfully submitted this 25th day of June, 2012
Peter
Rich son & 0 Leary, PLLC
Attorney for the Industrial Customers
of Idaho Power
1PC-E-12-15
COMMENTS OF INDUSTRIAL CUSTOMERS OF IDAHO POWER
PAGE 12
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 25th day of June, 2012, a true and correct copy of the
within and foregoing COMMENTS OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
N CASE NO.IPC-E-12-15 was served in the manner shown to:
Ms Jean Jewell X Hand Delivery
Commission Secretary U.S. Mail, postage pre-paid
Idaho Public Utilities Commission - Facsimile
P 0 Box 83720 - Electronic Mail
Boise, ID 83720-0074
Lisa D Nordstrom - Hand Delivery
Julia A Hilton X U S Mail, postage pre-paid
Idaho Power Company - Facsimile
P0 Box 70 X Electronic Mail
Boise, Idaho 83707-0070
[e-mail]
[e-mail]
Darlene Nemnich - Hand Delivery
Greg Said LU.S. Mail, postage pre-paid
Idaho Power Company - Facsimile
P0 Box 70 X Electronic Mail
Boise, Idaho 83707-0070
[e-mail]
gsaidl)idahoiower com
Ken Miller - Hand Delivery
Snake River Alliance XU.S. Mail, postage pre-paid
P0 Box 1731 - Facsimile
Boise ID 83701 X Electronic Mail
kmiller@snakeriveralhance org
Benjamin Otto - Hand Delivery
Idaho Conservation League XU.S. Mail, postage pre-paid
710 N 6th Street - Facsimile
Boise ID 83702 X Electronic Mail
botto(idahoconservation.org
Nina Curtis