20090220Petition for Reconsideration.pdf

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Department of Energy
Washington, DC 20585 i~, "
2039 fEB 20 AM 10: I I
Febru 19, 2009
Via FedEx
Jea Jewell
Secetar
Idaho Pulic Utilties Commission
472 W. Washigton
Boise, Idah 83702
Re: IPC-E-08-10
Dea Ms. Jewell:
Enclosed for fiing are the original and seven (7) copies ofthe Petition for
Recnsideration of the United States Deparment of Energy in the above docket.
Sinceely,
~;t,14
Steven Porter
Assistant General Counel
For Elecricity and Power Marketing
United States Deparment of Energy
Enclosures
cc: serice list via e-mal
* Prnted with soy ink on recycled paper
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
')tli1to FEi.uu:J . B 2(/ Ill" 10.v t/¡l I: II
CE "1'.1
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR )
AUTHORITY TO INCREASE ITS RATES ) CASE NO. IPC-E-08-10
AND CHARGES FOR ELECTRIC SERVICE. )
)
U.S. DEPARTMENT OF ENERGY'S PETITION FOR RECONSIDERATION
The United States Department of Energy ("the Deparment" or "DOE"),
intervenor, pursuant to Idaho Public Utilities Commission Rule of Procedure 331.01, and Section
61-626 Idaho Code, respectfully petitions the Commission for reconsideration of Order No.
30722, dated Januar 29,2009, and issued on Januar 30,2009 in Case No. IPC-E-08-10 ("the
Order"). The Department requests reconsideration of Order No. 30722 because the cost
allocation methodology adopted by the Commission is unreasonable in that it disproportionately
allocates steam and hydro generation costs out ofIdaho Power's high cost summer months and
into low cost non-summer months. Specifically, the Departent excepts to the Commission's
determination that weighted demand allocators do not produce a reasonable result. Order, p. 35.
Upon reconsideration the Commission should adopt the weighted twelve coincident peak method
for allocating demand-related costs. This method is consistent with significant efforts by the
Company and Commission to reduce Idaho Power's costly summer peak. This Petition is based
on the following reasons and upon the following grounds:
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1.
A SCHEME ALLOCATING IDAHO POWER'S FIXED STEAM
AND HYDRO PRODUCTION PLA PREDOMINANTLY TO
NON-SUMMER, NON-PEAKNG, MONTHS SENDS THE
WRONG PRICE SIGNAL AND UNDOES THE
COMMISSION'S EFFORTS TO REDUCE IDAHO POWER'S
SUMMER PEAK
A.
Idaho Power's Capital Investments Are the Driving Force Behind
It's Need to File for Rate Increases
Idaho Power's President and Chief Executive Offcer, J. LaMont Keen,
summarizes the essence of this case when he states, "growing demand for electrcity is driving
the need to invest large amounts of capital to expand and improve electricity supply and
reliability." L. Keen Direct p. 13 at 17. Company witness John R. Gale emphasizes this point
when he says, "Idaho Power is experiencing a cycle of heavy infrastructure investment needed to
address reliabilty, customer growth, peak demand growth, and aging plant and equipment."
Gale Direct, p. 18 at 17.
B.
It is an Irrefutable Fact that Idaho Power Incurs Its Highest Costs
During Its Summer Peak Period
It is well recognized by Idaho Power representatives that its power supply
challenges are for the most part related to growing summer peak demands and high power supply
costs experienced in the summer months. The Company acknowledges in this case that it is the
sumer months of June though August that are ''the Company's most expensive time to provide
power." Company witness Darlene Nemnich, p. 5 at 18. This position is supported by Company
witness Timothy Tatum when he describes the recent success Idaho Power has achieved with its
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Irrigation Peak Rewards program by saying, "the Company has been successful in reducing load
during the summer afternoon hours when costs to provide energy are typically higher." Tatum
Direct, p. 12 at 13. That program allows the Company to interrupt irrigation pumps during
summer peak conditions in exchange for incentive payments.
It is unsurprising, then, that multiple experts in the current case testified on the
importance of focusing on summer peak demands for the purpose of allocating costs to the rate
classes. DOE witness Dr. Dennis W. Goins emphasizes this salient point when he said, "the key
driver underlying IPC's need for new production resources (both new capacity and expensive
purchased power) is peak demand in summer months." Goins Rebuttal, p. 5 at 9. Dr. Don
Reading, on behalf of industrial customers, recommends "changes to Idaho Power's COS that
brings cost assignents closer the Company's load profie as a capacity constrained utilty rather
than as an energy constrained utility." Reading Direct, p. 2 at 13. Micon's expert, Dr. Dennis
Peseau states that "(p leaking costs are now driving costs higher for everyone, to the detriment of
all," and he concludes that, "(wle should be looking to adapt our cost of service to recognize
these changes, rather than vice versa." Peseau Direct, p. 41 at 17. Anthony Yanel testifying on
behalf of the Irrigation class emphasized the importance of and cost savings associated with
reducing Idaho Power's sumer system peak:
The Irrigation Peak Rewards Program is about to undergo major
improvements that should greatly increase participation levels and
become a major resource for Idaho Power to use in controllng its
summer peak load. These changes should be in place for next
summer's Irrigation season and system peak loads. Any
consideration of cost of service and revenue responsibilty should
reflect the fact that there wil be major changes to the system peak
loads when these rates are in effect as well as the Irrigation
Contribution to those peak loads. Yankel Direct, p. 3 at 14.
Not only are Idaho Power's peak demand costs concentrated in the summer
months, its variable power supply costs are also heavily focused in these months. Idaho Power
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estimated its annual net power supply costs at $88,421,200. Exhibit No. 47, p. 1. Of this
amount, Idaho Power estimated that 64 percent of these costs would occur in the summer
months, given its estimates of $9,601,900, $26,792,500, and $19,817,00 for the months of June
through August, respectively. Id.
c.
It Is an Irrefutable Fact that Idaho Power's Proposed 3CP/12CP
Allocators Shift Costs Away from Idaho Power's High Cost
Summer Months
Idaho Power's recommended cost of service study abandoned the traditional
marginal cost weighted coincident peak allocators used by this Commission in every Idaho
Power general rate case over the past twenty-five years to allocate demand-related costs to the
rate classes. Dr. Peseau provides a history of marginal cost weighted allocators in his testimony
in this case. Peseau Direct, pp. 32-36. These allocators are developed by weighting Idaho
Power's monthly coincident peaks by Idaho Power's estimated monthly marginal generation
capacity costs and are referred to as weighted twelve coincident peak allocators (W12CP).
Instead, .Idaho Power recommended a cost allocation scheme that uses the twelve monthly
coincident peaks (12CP) without marginal cost weightings to allocate its demand-related steam
and hydro costs, which represent the large majority of its demand-related production costs, and
the three summer coincident peaks (3CP) to allocate the small portion of its demand-related
production costs associated with its combustion turbines. Idaho Power refers to its use of these
allocators as its 3CP/12CP study.
It goes without saying that Idaho Power and this Commission place significant
weight on determining the costs properly allocable to the summer months of June through
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August. Sending cost-based price signals to all classes of customers during summer months wil
result in lower long-term costs for all customers as a whole because price induced conservation
wil lead to lower fuel and capital costs. Cost-based price signals wil also lead to effciently
designed demand-side programs that compliment price induced conservation. Given that Idaho
Power's production plant represents the largest ofIdaho Power's fixed plant-related costs, the
selection of allocators for demand-related production costs is a major cost allocation and rate
design decision. It wil directly influence the success or failure ofthe Company's rate design in
sending cost-based price signals to customers and the success or failure of any demand-side
management programs focused primarily on summer consumption.
The different allocators at issue in this case place markedly different levels of
costs into the summer period. Idaho Power proposed to allocate 100 percent of demand-related
combustion turbine costs to the summer months using a 3CP allocator. Idaho Power's selection
of a 12CP allocator for its demand-related steam and hydro costs is at the opposite end of the
spectrum with only a 30 percent weight given to summer months. Also presented in this case
was a W12CP allocator that allocates over 58 percent of costs to the summer months. Exhibit
No. 59. Finally, a hybrid allocator calculated as the average of the W12CP and 12CP allocators
(hereinafter referred to as the half-weighted 12CP or "HW12CP" allocator) was presented and it
allocates 44 percent of costs to the summer months. Id.
Only the Irrigation class benefits from the Company's proposed 3CPI12CP
allocators; all other rate classes are negatively affected. The Irrgation class's cost-based revenue
requirement allocation decreases by 4.3 percent.! In stark contrast to this result, the Traffic
Control class receives a 10.5 percent increase in allocated costs. DOE's cost-based revenue
1 See Exhibit Nos. 66 and 61. As an example, the cost-based revenue requirement for the Irrigation class falls to
$99,033,080 (Exhibit No. 66) from $103,447,573 (Exhibit No. 61), or 4.3 percent.
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requirement allocation increases by 2.9 percent, and the other rate classes receive less significant
increases. A true understanding of the net result of these cost allocation changes can only be
gained by understanding the seasonal coincident peaks of the rate classes. The Irrgation class's
summer coincident peaks total 62 percent of the sum of its twelve coincident peaks, which is an
indication of the concentration of this class's peaks in Idaho Power's high cost sumer months.
Exhibit No. 59. This relative level of summer usage is extraordinary given the fact that the rate
class with next highest concentration of coincident peaks in the summer months, the General
Service rate class, has a concentration of less than 30 percent, or less than half that of the
Irrigation class. Id. Finally, this comparison of studies leads to an irrefutable conclusion: Idaho
Power's proposed 3CPIl2CP allocators shift costs away from Idaho Power's high cost sumer
months.
This same conclusion was independently reached by Dr. Peseau. He concludes
that:
(Tlhe 12CP method is completely inappropriate for a strongly
peaking utility like Idaho Power. Furthermore, it is disingenuous
for Mr. Tatum to lament the rapid growth in the spikiness of
summer peak demand, when his preferred cost of service study
maximizes the amount of summer peak costs pushed out of the
summer peak period into off peak seasons. We can see this very
clearly in the ultimate results of his 3CP/12CP study, which in fact
shifts more costs off peak than the flawed modified base case I
described earlier. In short, Mr. Tatum is headed in precisely the
wrong direction. Peseau Direct, p. 44 at 1.
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D.
The Company's and the Commission Stafs Arguments in Favor
of Using a 12CP Allocator for Idaho Power's Demand-Related
Steam and Hydro Costs Are Ilogical and Do Not Comport with
the Facts
The Company's justification for a significant change in cost allocation methods
from the 2003 Case is limited at best. Company witness Tatum states Idaho Power's position
that"( u ) sing an un-weighted 12CP allocator is more appropriate in this case given that fixed base
and intermediate generation costs do not vary greatly between the summer and non-summer
seasons." Tatum Direct, p. 20 at 19. These are the same generating units with the same general
cost profie as those before the Commission in the 2003 Case, so the material facts did not
change-just the Company's view of summer versus non-summer cost allocations for these
units. The Commission notes in its Order that "(tlhe Company asserted that the 3CP/12CP
method is an improvement over the prior W12CP method and that it wil more adequately assign
base and intermediate costs to the rate classes." Order, p. 32. As noted above, Idaho Power's
12CP allocation factor leads to a grossly inaccurate assignent of costs because there is no
recognition of high seasonal summer capacity costs, which would be the case with a W12CP
allocator. It is inconsistent with twenty-five years of precedent and absurdly encourages peak
usage!
In arguing for the use of a 12CP allocator to assign fixed production costs for
steam and hydro resources to the rate classes, Staff witness Hessing testifies that:
Capacity is required and has value in all months. Idaho Power is a
dual peaking utility with a summer and winter peak. The off peak,
spring and fall shoulder months, provide the opportunity for the
Company to take plants down for necessary scheduled .
maintenance. This circumstance can produce situations in shoulder
months where available capacity is as important as it is in peak
load months. Hessing Rebuttal, p. 14 at 10.
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Idaho Power is not a dual peaking utilty. Nor is available capacity in shoulder
months as important as it is in peak load months. It is and wil continue to be a summer peaking
utility, and the concentration of Idaho Power's marginal generation capacity costs in the summer
months confirms this. Furher, Staffs position is clearly inconsistent with Company, Staff, and
Commission positions taken in the Irrigation Peak Rewards program.
Company witness Tatum makes another attempt to justify using a 12CP allocator
for Idaho Power's demand-related steam and hydro plant in his testimony when he states:
Of the three studies, the 3CP /12CP study applies an approach that
results in the most equitable allocation of costs to customer classes.
Each study was prepared with the same goal of allocating costs to
customer classes according to the cost impact that each class
imposes on the utility system. However, the 3CP/12CP study
applies a cost-of-service methodology that best reflects the ways in
which costs are currently imposed on the Company's system. For
example, over the last six years, Idaho Power has added four
. combustion turbine generation units to serve summer peak loads.
Because the costs associated with these new units are driven
primarily by summer loads, it is appropriate to allocate the cost of
those new resources according to each class's contribution to the
summer peak loads. However, production plant costs associated
with serving the base and intermediate loads are driven more by
the monthly peaks throughout the entire year. By separating the
production plant into the two categories, the generation costs can
be allocated according to the most appropriate cost driver. Tatum
Direct, p. 51 at 8.
He is unequivocal that combustion turbines are used to meet peak loads and the
costs of combustion turbines should be allocated to each class's contribution to summer peak
loads. This was not the subject of any significant disagreement in this case. He is far from
unequivocal when he states that, "production plant costs associated with serving the base and
intermediate loads are driven more by the monthly peaks throughout the entire year." Id.
(Emphasis added.) For twenty-five years this Commission has concluded that production plant
costs associated with serving base and intermediate loads are driven more by coincident peaks in
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months with marginal capacity costs and, to a lesser extent, with coincident peaks in all other
months. Idaho Power's new found costing methodology conflcts with all prior Commission
rulings on this issue.
Mr. Tatum seems to imply that Idaho Power's recent additions of combustion
. turbines into its power supply portfolio has changed the nature of how it operates its steam and
hydro units compared with past general rate cases. This cannot possibly be true. Idaho Power's
estimated normalized net power supply indicates that combustion turbines wil combine to
produce only 1.3 percent ofIdaho Power's peak month energy supply in July, and less than one-
quarer of one percent ofIdaho Power's anual energy supply.2 The additions of these
combustion turbines could not therefore have had a material effect on Idaho Power's operation of
its steam and hydro units. Certainly not sufficient enough to conclude that cost allocators should
change dramatically for Idaho Power's steam and hydro units and in the direction of allocating
costs away from the summer months.
Company witness Said confirms that Idaho Power's steam and hydro units, and
purchased power, playa prominent if not the primar role in meeting Idaho Power's peak
demands when he states, "Danskin and Bennett Mountain, as peaking plants, operate
intermittently, but offer significant contribution at important times when resources and purchases
are inadequate to serve peak loads." Said Direct, p. 12 at 18. (Emphasis added.) Clearly, Mr.
Said is referring to Idaho Power's stear and hydro units when he is referring to its "resources."
Also, Mr. Said implies that peaking units are used only after steam and hydro units, and
purchases, are dispatched. This suggests that Idaho Power's combustion tubines act importantly
2 See Exhibit No. 47, p. 1. Danskin and Bennett Mountain combined for 21,504 MWh of generation compared with
1,639,561 MWh of total production and purchased power, excluding surplus sales. On an annual basis these
numbers are approximately 42,000 MWh of natural gas-fired generation versus 17,200,000 MWh of total generation
and purchased power, excluding surplus sales.
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as reserve capacity that can be called upon when needed, on extremely hot days or in the event of
forced outages, but that Idaho Power's steam and hydro units, and purchases, are the primar
resources used to meet peak demands, including peak demands during the summer months.
The Commission should reject the use of the 12CP allocator used by Idaho Power
to allocate Idaho Power's demand-related steam and hydro costs given the lack of empirical
support for this allocator in this case.
E.
Upon Reconsideration, The Commission Should Set Rates that Are
Consistent with the Commission's Efforts to Reduce Peak Demand
This Commission should set rates based on cost for two key reasons, fairness and
effciency, as described by Micron witness Peseau. He explains that fairness "basically refers to
the idea that customers should pay their own costs and not someone else's." Peseau Direct, p. 30
at 3. He explains the efficiency rationale as follows:
This is the idea that prices should promote the most effcient
possible use of the utility system. Thus, those who use the system
primarily when costs are high should pay a rate that reflects those
disproportionately high costs so they wil be encouraged to
conserve or find alternative means of meeting their needs. And
there is an important, but out of favor, counterpoint here as well.
Those who consume in low cost periods should receive an
appropriate price signal to do so when consumption is an economic
plus for all. Peseau Direct, p. 30 at 7.
Effcient use of Idaho Power's resources is of significant enough concern that its
chief executive addressed this issue in his testimony in this case. Mr. Keen explains Idaho
Power's strategy for addressing load growth trends when he says:
We are addressing them on both the supply-side and demand-side
of the equation. In addition to expanding our production delivery
systems, we are aggressively promoting demand-side management
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programs and services. These energy efficiency efforts serve to
slow the pace of growth in a cost-effective manner by delaying the
need for additional generating resources. Additionally, these
efforts educate our customers on wise, responsible use of our
precious resource. Keen Direct, p. 5 at 22.
The importance of efficient rate design was also emphasized by Company witness
Gale in his testimony where he says:
I have directed the three pricing analysts sponsoring testimony in
this case to design cost-based rate proposals that encourage
increased energy efficiency among the Company's Residential,
Large General Service, and Irrigation customer groups. Gale
Direct, p. 26 at 5.
The implications of artificially lowering summer rates through cost allocation are
many. First, demand side management programs espoused by Idaho Power's chief executive
wil fall short of their potential. Second, peak usage wil be higher than it otherwise would be,
leading to ever-increasing capital investments in infrastructure that are so prominently discussed
in this case.
Dr. Peseau explains the concerns:
In allocating summer peak capacity and energy costs to off peak
seasons, rates for summer usage wil be too low, and rates for non-
summer usage wil be too high. But this problem does not balance
out. The reason it does not balance out is that the underpricing of
summer usage wil promote more summer usage and require Idaho
Power to invest more heavily than otherwise in new peaking
facilities and DSM programs. The Company of course earns a
return on these programs but, as a result, all ratepayers' rates are
higher. Peseau Direct, p. 44 at 11.
Dr. Goins also emphasizes the negative consequences of reliance on costing
methodologies that produce a result that clearly is absurd when he states, "if you base your prices
on those ludicrous results.. . your peak pricing will be wrong, your development of off-peak loads
is wrong, is ineffective, and your encouragement of people to use electricity more effciently is
wrong." Tr. p. 986 at 6. Use ofIdaho Power's 3CP/12CP study produces the absurd result to
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which Dr. Goins refers. It clearly is a costing methodology that should not be adopted by this
Commission because it moves costs away from the periods that are of the greatest concern to the
Company and this Commission in terms of lowering Idaho Power's overall costs and capital
requirements, and maximizing the energy conservation benefits of demand-side management
programs and time-of-use pricing. If anything, the Commission needs to move in the opposite
direction of that suggested by the 3CP/12CP study.
Idaho Power's 3CP/12CP study will not, based on the record of evidence in this
case, produce rates that are consistent with the Commission's efforts to reduce peak demands. It
should therefore be rejected. In its place, the Commission should adopt changes to Idaho
Power's cost study that promote economically effcient use of Idaho Power's resources.
II.
NATURE AND EXTENT OF EVIDENCE AND ARGUMENT
TO BE OFFERED ON RECONSIDERATION
Commission Rule of Procedure 331.01 requires that DOE state the nature and
extent of evidence or argument it wil present or offer if reconsideration is granted. It is the
position of DOE that the evidentiary record before the Commission and the applicable law
requires that the Commission modify Order No. 30722 as set forth in this Petition For
Reconsideration. Additional evidence set out below, taken from sworn Company testimony from
prior cases, supports the foundation of this Petition:
1) Idaho Power is a summer peaking utilty, not a dual peaking utilty;
2) Idaho Power is capacity-constrained over the next several years,
particularly in the summer months;
3) Idaho Power's costs are the highest in the summer months; and
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4) the Commission and Company, along with Staff and other parties, are
. working together to save costs by lowering Idaho Power's sumer peak
demand.
A.
Idaho Power is A Summer Peaking Utilty, Not a Dual Peaking
Utility
The Commission has adopted the position that Idaho Power's costs are drven in
large part by summer peak demands in the Irrigation Peak Rewards program case, Case No. IPC-
E-08-23. In that case, the Commission relied upon Idaho Power representations that the
Company places great value on reducing peak demands. In its Order No. 30717, the
Commission describes a program change it approved that shortened the Irrigation Peak Rewards
program interruption period from June 1 through August 31, or three months, to a six-week
period of June 15 to July 31:
The time period was shortened because the value of the load
reduction capabilty of the program is its abilty to reduce loads
when the demand on the electrical system is at or near the annual
system peak. Idaho Power's witness testified that currently there is
a near zero probabilty that Idaho Power s electrical system wil
experience a annual system peak demand outside of the time
period of June 15 through July 31. Order No. 30717, pp. 3-4.
The full text of Company witness Tatu's testimony is as follows:
As part of the research and analysis process that led to the
proposed Program design, the internal Program design team at
Idaho Power held several discussions with subject matter experts
that work within the generation dispatch and power supply
planning functions of the Company. According to perspectives
shared by representatives from the generation dispatch and power
supply planning groups, the value of the load reduction capabilty
of the Program is in its abilty to reduce loads when the demand on
the electrical system is at or near the annual system peak.
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Furthermore, these discussions confirmed that currently there is a
near zero probabilty that Idaho Power's electrical system wil
experience a annual system peak demand outside of the time
period of June 15 through July 31. With that in mind, the Program
Season was revised to align with the June 15 through July 31
period. Tatum Direct, Case No. IPC-E-08-23, pp. 14-15.
The Company unequivocally stated that, "there is a near zero probabilty that
Idaho Power s electrical system wil experience a annual system peak demand outside of the time
period of June 15 through July 31." The Commission Staffwas a party to the stipulation
approved by the Commission in that case and did not voice any disagreement with the position
that Idaho Power's system peak demands are likely to occur durng a very short six-week period
in the summer. The Commission supported this decision. Clearly, this contradicts Staff witness
Hessing's statement that Idaho Power is a "dual peaking utility," which Mr. Hessing used to
justify his support for Idaho Power's use ofa 12CP allocator. Hessing Rebutt, p. 14 at 10.
B.
Idaho Power is Capacity-Constrained Over the Next Several Years,
Particularly in the Summer Months
Case No. IPC-E-08-21 is an application by Idaho Power for approval of a special
contractto supply power to Hoku Materials, Inc. ("Hoku"). Hoku is a new customer that
requires 82 megawatts ("MW") of capacity. Idaho Power has agreed to serve Hoku, but has not
agreed to provide the full 82 MW requested by the customer. Idaho Power's position was
explained by Company witness Gale when he states, "Because of supply and transmission
constraints, Idaho Power was unable to serve at this level during certain summer months prior to
2012." Gale Direct, p. 7 at 5. Idaho Power has only agreed to provide Hoku with 43 MW for the
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years 2010 and 2011 during the abbreviated summer period of June 16th and August 15th.3 This
contract provides additional evidence that Idaho Power is capacity-constrained in the summer
months, and not in other months of the year, which supports demand-related cost allocations
primarily in the summer months. It also highlights the importance of efforts to reduce Idaho
Power's peak demand in the coming years. Company witness Gale testifies that, ''tere is a
contingency provision that reduces the Company's 2012 capacity obligation in case Idaho Power
is not able to add additional generation and/or transmission as planed." Gale Direct, p. 7 at 15,
This statement confirms that Idaho Power must make capital investments to relieve its capacity-
constrained system, which again points to the need for proper cost allocation to the summer
months.
c.
Idaho Power's Cost Are the Highest in the Sumer Months
Idaho Power has consistently taken the position that its costs are the highest in the
summer months. However, its cost studies are in direct contradiction with these statements.
Testimony sponsored by the Company in the last case confirms the concentration of high costs in
the summer months. Brilz Direct, 2003 Case, p. 26 at 12. In that case, Ms. Brilz also stated that:
Besides being more costly during the summer months, energy is
more costly during certain hours of the day. The implementation
of time-of-use rates for Schedule 19 customers, who currently have
the metering in place to accommodate the hourly pricing, wil
provide the economic signal that energy is more costly during the
peak hours of the day and the peak months of the year. Again, like
strictly seasonal rates, it is hoped that time-of-use rates wil
encourage reduced consumption both during the summer months
as well as during the daily peak hours. Brilz Direct, 2003 Case, p.
27 at 9.
3 Section 6.1., "Scheduled Contract Demand," in the Electric Service Agreement included in Idaho Power's
application as Attachment 1.
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D.
The Commission and Company, Along with Staff and Other
Parties Are Working Together to Save Costs by Lowering Idaho
Power's Sumer Peak Demand
Case No. IPC-E-08-23, Idaho Power's Peak Rewards Program case is an excellent
example of the Commission and Company working together to increase Idaho Power's peak
shaving programs. In that case, Idaho Power explicitly linked the credits provided to irrigation
customers that reduce their peak demands to Idaho Power's rates for the Irrgation class. This
provides an indication of the important role rates have on the effectiveness of demand-side
programs. Company witness Tatu describes the Company's rationale for maintaining this
relationship:
Since the inception of the Program, the Company has maintained
that it is important that the Demand Credit .amount remain below
the Demand Charge under Schedule 24, Agricultural Irrigation
Service. This ensures that customers participating in the Program
are not incented to turn on a pump when they otherwise would not
simply to earn a bil credit. The proposed incentive structure
recognizes that notion by including an energy-based incentive
amount which allows for additional incentive dollars to be
provided to participating customers while maintaining a Demand
Credit at or below the current Demand Charge under Schedule 24.
Tatum Direct, Case No. IPC-E-08-23, p. 17 at 4.
111.
CONCLUSION AND REQUEST FOR RELIEF
The Commission, like other state regulatory bodies across the nation, faces
significant challenges as the country undergoes a transformation of the electric utilty system.
Clearly, the Commission understands the import of sending proper price signals to effect
customer behavior designed to lower peak demands and reduce the need for expensive
16
generation. Indeed, the Commission, as noted, has approved the irrigation peak reduction
program. In this case, it has adopted rate-design reflecting the higher cost of summer power.
And soon, the Commission wil consider approving collection of milions of ratepayer dollars for
DSM and energy effciency programs. States, utilties and private companies wil soon team-up
with the Department to invest bilions of dollars in smart grid activities. But DSM programs,
smart grid pricing information and energy efficiency efforts are ineffective if the value of
summer power is artificially lowered through cost allocation methods. It is essential that
regulatory price signals be consistent. It is ilogical to, on one hand, adopt policies and programs
designed to conserve energy and reduce summer peak usage while, at the same time, arbitrarily
reducing the cost of summer peak power.
The most logical and straightforward step this Commission could take based on
the record of evidence in this case to promote economically efficient rates, cost-effective
demand-side management programs, efficient capital investment, and lower overall costs for
Idaho Power's customers, is to order that a Wl2CP allocator be used in place of the L2CP
allocator proposed by the Company for the allocation of demand-related production costs. The
adoption of a W12CP allocator is logical because it provides a direct link between Idaho Power's
high summer marginal capacity costs and the allocation of costs to the customer classes,
particularly those classes that record high peak demands durng Idaho Power's high cost sumer
months. This change is straightforward because the W12CP allocator is easily calculated from
the record in this case and can easily be inserted into the Company's cost of service study.
DOE suggests that the Commission order the Company and Staff to hold cost-of-
service workshops to further investigate and discuss other cost-of-service issues raised by the
parties in this case. These issues were many and are important to the proper allocation of costs
17
to the summer and non-summer months. In addition, these workshops should simultaneously
address how cost of service methodologies can support effective demand-side programs,
particularly peak shaving programs.
Finally, DOE believes that it would be appropriate to employ the six percent cap
on rate increases adopted by the Commission in its Order. In so doing, the reconsideration of
these critical costing methodology issues can be undertaken without producing a result that wil
dramatically affect customer rates.
DATED at Washington, D.C., this 19th day of February, 2009.
Respectfully Submitted,
4/.;Z
Steven A. Porter
Assistant General Counsel
U.S. Department of Energy
1000 Independence Ave., SW
Washington, D.C. 20585
Telephone: [phone]
steven.porter(ghq .doe.gov
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Certificate of Service
I HEREBY CERTIFY that I have this day of February 19, 2009, served the foregoing
Petition for Reconsideration in Docket No. IPC-E-08-10 upon the Secretary of the
Commission by FedEx and on the following parties in this proceeding by electronic
filing.
Barton Kline
Lisa D. Nordstrom
Donovan E. Walker
Idaho Power Company
1221 W. Idaho St.
PO Box 70
Boise, ID 83707-0070
John R. Gale
Idaho Power Company
1221 W. Idaho St.
POBox 70
Boise, ID 83707-0070
Weldon Stutzman
Neil Price
Deputy Attorneys General
Idaho Public Utilties Commission
472 W. Washington
PO Box 83720
Boise, ID 83720-0074
Peter Richardson, Esq.
Richardson and O'Leary
515 N. 2ih St.
PO Box 7218
Boise, ID 83702
Dr. Don Reading
Ben Johnson Associates
6070 Hil Road
Boise, ID 83703
Randall C. Budge
Eric L. Olsen
Racine, Olson, Nye, Budge & Bailey, Chartered
201 E. Center
PO Box 1391
Pocatello, ID 83204-1391
Anthony Yankel
Yankel & Associates, Inc.
29814 Like Road
Bay Vilage, OH 44140
Michael Kurtz, Esq.
Kurt J. Boehm, Esq.
Boehm, Kurtz & Lowry
36 E. Seventh Street, Suite 1510
Cincinnati, OH 45202
Kevin Higgins
Energy Strategies, LLC
Parkside Towers
215 S. State Street, Suite 200
Salt Lake City, UT 84111
Conley E. Ward
Michael C. Creamer
Givens Pursley, LLP
601 West Bannock Street
POBox 2720
Boise, ID 83701-2720
Dennis E. Peseau, Ph.D.
Utility Resources Inc,
1500 Liberty Street, SE, Suite 250
Salem, OR 97302
Brad M. Purdy
Attorney at Law
2019 N. 17th St.
Boise, ID 83702
Ken Miler
Snake River Alliance
PO Box 1731
Boise, ID 83701
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Steven Porter
Assistant General Counsel
United States Department of Energy