20080527DOE Comments.pdf

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Department of Energy
Washington, DC 20585
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May 20, 2008
Jean D. Jewell, Secretary
Idaho Public Utilties Commission
472 West Washington St.
P.O. Box 83720
Boise, Idaho 83720-0074
RE: Case No. IPC-E-08-07
Dear Ms. Jewell:
As per the Commission's requirement, the original and seven copies of The United
States Department of Energy's comments in the above-captioned proceeding are
enclosed herewith. An additional copy is also enclosed. Please date-stamp this
additional copy, and return it in the enclosed self-addressed postage paid envelope.
Thank you very much for your assistance.
Arthur Perry Br er
Office of the General Counsel
United States Department of Energy
1000 Independence Ave. SW
Washington, D.C. 20585
Arthur .Bruder~hq.doe.gov
[phone]
[phone] (FAX)
* Prnted with soy in on recycled paper
BEFORE THE IDAHO PUBLIC UTiliTIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR )
AUTHORITY TO IMPLEMENT POWER )
COST ADJUSTMENT (PCA) RATES FOR )
ELECTRIC SERVICE FROM JUNE 1, 2008 )
THROUGH MAY 31,2009 )
)
CASE NO. IPC-E-08-07
NOTICE OF APPLICATION '
NOTICE OF MODIFIED PROCEDURE
NOTICE OF PUBLIC WORKSH~S I'
ORDER NO. 30540 -l g
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oTHE UNITED STATES DEPARTMENT OF ENERGY'S
RESPONSE TO THE APPLICATION
COMES NOW the United States Department of Energy ("DOE") on behalf of its
Idaho Operations Offce and of other Federal Executive Agencies, all of whom are
customers of Idaho Power Company ("I PC"), and by and through counsel,
respectfully submits this response to the subject application herein.
I - INTRODUCTION - THE PROPOSED PCA RATE METHODOLOGY DEVIATION
Idaho Power Company (IPC) asks the Commission to allow a deviation from the
PCA rate methodology which was included in the Commission's most recent IPC
rate order. The deviation would allow IPC to pass through to customers 100%,
rather than the Commission-approved 90%, of the difference between its actual
and normalized power supply costs. The United States Department of Energy
(the Department) respectfully offers the following response to IPC's request.
II - A MOST STRINGENT STANDARD OF REVIEW MUST BE APPLIED TO IPC'S
REQUEST. UNDER THAT STANDARD, THE REQUEST SHOULD BE DENIED, OR
AT LEAST SUBJECTED TO FURTHER SCRUTlNY.
(a) In the present situation, this much at least is uncontested:
(1) IPC seeks a change in just one facet of one element of the Commission's
recent all-encompassing rate order. All of the elements that together comprise
that order are set out in a very recent stipulation, that was agreed to by IPC and
interested parties, and approved by the Commission. Each of the elements of the
stipulation was developed and adopted not by itself, but with in consideration of
all of the others. Those elements included the PCA methodology, and its
attendant proportionate 90% - 10% division of risk between customers and
shareholders. To change just this one facet of this.one element of the general
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rates which the Commission so recently approved would be contrary to the
longstanding prohibition of "one issue ratemaking";
(2) The change which IPC seeks could produce a very substantial financial impact
upon its customers, including the Federal Executive Agencies;
(3) A shift in risk from IPC to customers is of particular concern at this time given
the substantial volatilty currently being experienced in wholesale energy
markets;
(4) There is no allegation that denial of this deviation wil place IPC in jeopardy.
II - IPC'S PROFFERED REASONS FOR THE DEVIATION ARE UNPERSUASIVE.
(a) IPC proffers. three reasons in support of its request: (1) failure of a number of
qualifying facilties projects (QF) to come on-line at the times at which theCompany's very recent projections envisioned that they would; (2) lack of
inclusion of prescriptive hedging activities in the PCA forecast methodology; (3)
drought conditions. These reasons are discussed below.
(b) Discussion
(1) Failure of a number of QF's to come on-line at the times which the Company's
very recent projections envisioned - IPC points out that multiple wind projects
that it forecasted would be on-line by the end of 2007 are not yet operational and
wil not provide previously anticipated energy. To counterbalance this, IPC may
be required to increase its thermal generation or purchase replacement energy in
the wholesale market. IPC anticipates that payments to QF's wil be about $30
milion less than levels included in its base rates, and that replacement energy
costs wil exceed $40 milion. IPC's requested deviation would require ratepayers
to pay 100%, rather than the Commission-approved 90%, of that increase. Thus,
IPC seeks to burden its customers with at least $4 millon additional costs.
IPC has a long history of delayed wind projects. Almost none of its contracted-
for wind projects have achieved commercial operation at or near their projected
on-line dates. (Please see attched Table One, which is a summary of the
Company's recent power purchases from wind projects.) Thus, the extreme
inaccuracy of its projection of energy deliveries from wind projects cannot have
taken IPC by surprise. The Company certinly knew about it at the time it filed its
most recent general rate case. As of June 11, 2007, it had twelve wind projects
that were behind schedule by between one month and nearly a year and a half.
Sixteen of IPC's wind projects were apparently behind schedule by three months
to over two years as of April 16, 2008, the date that it made this application.
(Please see Table 2, which sets out the delayed projects.) Thus, at the time that
IPC signed the January 23, 2008 stipulation that mandated the PCA methodology
from which it now seeks to deviate, IPC already knew that its projection was likely
substantially wrong. Yet, it stuck by that projection.
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Certinly, the fact that the projection was extremely inaccurate is a major factor
underlying the Company's request. Moreover, the Company unquestionably
knew and understood the risk associated with the need to purchase replacement
energy in the event of delayed wind projects. It is therefore the Company's
responsibilty, not the ratepayers', to manage the uncertinty, the risk, that is
inevitably associated with QF on-line dates. All of this dictates that it would be
inequitable and unjust to burden ratepayers - or, rather, further burden
ratepayers, with that risk. By asking for a waiver of the 90%-10% division of this
risk, the Company is asking the Commission to relieve it of responsibilty for its
own wind project energy projection - a projection it agreed to just three months
prior to its application in this case. The Commission should not unburden the
Company from - and further burden ratepayers with - risks that the Company
voluntarily undertook when it stipulated to the adoption of its own projection.
(2) Lack of inclusion of prescriptive hedging activities - IPC argues that 100%
pass-through of power supply costs to its customers is appropriate because of
the prescriptive nature of its Commission-approved risk management policy.
(Testimony of Company witness Said, page 7, line 23) The Company indicates that
it has a net hedging position of nearly $51 milion, that is comprised of
previously executed wholesale market purchases and sales. All stakeholders
hope that this wil significantly mitigate whatever power supply cost increases
the Company may encounter. But the Department respectfully submits that the
Company has not presented anything which would indicate that the
Commission's approved risk management policy is so unsatisfactory as to justify
the one issue ratemaking that the requested waiver would demand.
(3) Drought conditions
The Departent respectfully submits that the Company has simply not provided
any material which establishes that the duration andlor magnitude of drought
which it now faces or likely may face is such as to justify the requested waiver.
v - CONCLUSIONS
Given all of this, the Department respectfully submits that any change in the
Commission-approved PCA methodology are best addressed in conjunction with
a general rate case, rather than "on the fly" in a "one issue" proceeding. In line
with this, the Department respectfully points out that:
(a) The risk to IPC's shareholders that results from variable levels of fuel
and purchased power cost recovery associated with the Commission-
approved PCA methodology is fully incorporated in IPC's authorized
general rates, which were recently approved by the Commission on
February 28, 2008, when the Commission approved a stipulation in IPC's .
most recent general rate case;
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(b) At the time that it agreed to the stipulation in its last rate case, IPC likely
was or should have been aware that energy from new QF projects would
not be available as previously anticipated. Therefore, IPC should not now
be permitted to change the balance of risk struck in that stipulation, in
which it agreed to a specific level for normalized qualifying facilties costs;
(c) Neither the Commission nor IPC's customers are in a position to
evaluate the full effect of IPC's requested deviation in PCA methodology on
customers or the Company without access to information regarding .IPC's
hedged and unhedged energy supply portolio positions.
v - RECOMMEDATIONS
(a)The Department respectfully recommends that:
(1) the Commission should deny the IPC request because the requestfails to state a
prima facie case for the relief that it seeks;
(b) if the Commission does not deny the request as set out above, it should:
(1) order that workshops be convened on the issue; and,
(2) mandate that the issue shall be addressed in the context of IPC's soon- to-be-
filed general rate case.
(c) in whatever context the request is heard, at least the following should be
addressed:
(1) the magnitude of the increased costs that the waiver would shift to customers.
Commodity energy prices have increased greatly since the Company agreed to
the stipulation in its last general rate case, and those prices are now of far greater
concern than they were just four months ago. (Please see Table Three, which is a
summary of the Henry Hub natural gas futures prices.) The Company's
prospective replacement power costs have likely increased significantly. The
Company's application does not address these increased costs. Some reasonable
measurement of the dollar amount or amounts of additional cost responsibilty that
the requested waiver would shift to IPC's customers is criticaL. At this point there
has been no such measurement, or even any presentation of the manner in which
such measurement would properly be carried out.
(2) the role of hedging. It is unclear from IPC's filing whether its discussion of
its $51 millon net hedging position is in any way related to its projection that
replacement energy costs resulting from delayed QF purchases wil exceed $40
millon. Therefore, it is unclear whether IPC's requested deviation may entail an
additional allocation to customers of hedging-related costs. Evaluation of this
must be based on information regarding IPC's hedged and unhedged energy
supply portolio forward positions;
(3) possible multi-year effect. It appears that problems caused by delayed wind
projects may extend over several years. The requested waiver may therefore be a
multi-year issue. The Company's March 3, 2008, cost projections to the
Bonnevile Power Administration includeprojected in-service dates for all of the
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its pending sixteen wind projects. (Please see Table One.) For twelve of these
projects, the Company's projected in-service dates are now December 2009, a full
two years after the anticipated in-service date of no later than December 31, 2007
that was included in the Company's stipulated PURPA expenses projection.
Company witness Said testified that an average of 62 megawatt of energy that
were included in the Company's projected PURPA expenses wil not be available
in 2008 because of the delayed wind projects. (Said testimony, page 5, line 6)
The Company's application did not provide the derivation of that number, but it
can be verified by review of the Company's pending wind projects. (Please see
attched Table Two.) For the PCA deferral period April 2008 through March 2009,
the average megawatt of energy that wil not be available from wind projects as
previously anticipated falls slightly to 57 average megawatt assuming two wind
projects come on-line as the Company now expects. For the following PCA
deferral period, April 2009 through March 2010, the average shortall in energy
deliveries from wind projects is over 41 megawatt, after two additional wind
projects come on-line. Clearly, if the Company's new projected wind project on-
line dates prove valid, the significant differences between actual and normalized
PURPA expenses wil extend well beyond the present year. These potential
effects of the requested waiver upon multiple PCA years require attention.
(4) the timing of certain of the Company's perceptions and actions. . The
relationship of the time when the Company determined that its projection of QF
on-line dates was inaccurate, and the time that it determined that it would be
necessary for it to implement its risk management policy and make additional
market purchases is worthy of further investigation.
ReÆ:Y~d,
Lot Cooke~.~...~
Arthur Perry Brud~r
Attorneys for
the United States
Department of Energy
1000 Independence Avenue SW
Washington, DC 20585
May 20,200
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Table One
Idaho Power Company's Recent Wind Project Purchases and a Comparison of
Schedule Operation Dates Versus Recently Estimated Target In-Service Dates(l)
Months
Idaho Name-Behind Estimated
PUC plate Annual Scheduled Schedule Target
Case No.Capacity Contract Operation As of In-Service
Wind Project IPC-E (MW)(2)(aMW)(2)Date(3)04/16/08 Date(2)
On-line Projects
Telocaset Wind Power Partners, LLcl4)06-31 100 34 03/21/08 12/28/07
Delayed Projects that May Be On-line
Hot Springs Windfarm LLC 06-34 19.8 5.7 12/31/07 3.5 Mar-08
Bennett Creek Windfarm LLC 06-35 19.8 5.7 12/31/07 3.5 Mar-08
Sub-Total 11.4
Delayed Projects Expected On-line Soon
Cassia Wind Farm LLC 06-10 10.5 3.4 12/31/06 15.5 Jul-08
Cassia Gultch Wind Park LLC 06-11 18.9 5.8 12/31/06 15.5 Jul-08
Sub-Total 9.2
Projects Delayed Two Years or More
Thousand Springs Wind Park LLC 05-06 10.5 3.3 01/15/06 27.0 Dec-09
Pilgram Stage Station Wind Park LLC 05-07 10.5 3.3 01/15/06 27.0 Dec-09
Oregon Trail Wind Park LLC 05-08 10.5 3.3 01/15/06 27.0 Dec-09
Tuana Gulch Wind Park LLC 05-09 10.5 3.3 01/15/06 27.0 Dec-09
Golden Valley Wind Park 05-17 10.5 3.3 06/01/06 22.5 Dec-09
Burley Butte Wind Park 05-18 10.5 3.3 12/31/05 27.5 Dec-09
Milner Dam Wind Park 05-30 18 5.9 May-07 10.6 Dec-09
Lava Beds Wind Park 05-31 18 6.3 May-07 10.6 Dec-09
Notch Butte Wind Park 05-32 18 6 May-07 10.6 Dec-09
Salmon Falls Wind Park 05-33 21 6.3 May-07 10.6 Dec-09
Magic Wind Park LLC 06-26 20 6.1 12/31/07 3.5 Dec-09
Alkali Wind Park 06-36 18 4.8 12/31/07 3.5 Dec-09
Sub-Total 55.2
(1) Applications for approval of purchases from wind projects for the years 2005 through the present, excluding
Arrow Rock Wind, which was terminated, and Fossil Gulch Wind Park, for which information on either an
in-service date or termination date could not be found.
(2) Idaho Power Company, Letter from Scott L Wright, Pricing Analyst, to Ms. Michelle Manary of the Bonnevile
Power Administration, March 3, 2008 (see the last page of the attachment to that letter). Available at:
http://www.bpa.gov/corporate/finance/ascm/Docs/2008-03-03 Idaho Power ASC. PDF
13) Taken from Idaho Power Company's applications for approval of sales agreements.
(4) The scheduled operation date was taken from direct testimoy of Idaho Power Company witness Celeste
Schwendiman in Case No. IPC-E-OG-31, p. 9, In. 17. Idaho Power Company reported that this facility became
commercially operational on December 28, 2007, in IdaCorp's 10-k, February 28, 2008, p. 61.
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Estimated Average Megawatts of Energy Associated with Delayed Wind Projects
for Idaho Power Company for calendar Year 2008, and Power Cost Adjustment
Years April 2008 through March 2009 and April 2009 through March 2010
Calendar Annual Calendar
2008 Percent of 2008
Annual Months the Year Weighted
Contract Not On Not On Contract
Wind Projects (aMW)Line Line (aMW)
Delayed Projects that Are On-Line 11.4 2 17%1.9
Delayed Projects Expected On-Line Soon 9.2 6 50%4.6
Projects Delayed Two Years or More 55.2 12 100%55.2
Total(l)75.8 61.7
Apr-08 Apr-08
to Annual to
Mar-09 Percent of Mar-09
Annual Months the Year Weighted
Contract Not On Not On Contract
Wind Projects (aMW)Line Line (aMW)
Delayed Projects that Are On-Line 11.4 0 0%0
Delayed Projects Expected On"line Soon 9.2 3 25%2.3
Projects Delayed Two Years or More 55.2 12 100%55.2
Total 75.8 57.5
Apr-09 Apr-09
to Annual to
Mar-10 Percent of Mar-10
Annual Months the Year Weighted
Contract Not On by Contract
Wind Projects (aMW)line 12 (aMW)
Delayed Projects that Are On-line 11.4 0 0%0
Delayed Projects Expected On-line Soon 9.2 0 0%0
Projects Delayed Two Years or More 55.2 9 75%41.4
Total 75.8 41.4
(1)The 61.7 aMW calculated above is in line with Idaho Power Company's testimony in this case.
See the direct testimony of Idaho Power Company witness, Gregory Said, p. 5, In. 6.
Table Two
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Comparison of NYMEX Henry Hub Natural Gas Futures Prices
IPC's
General General
Rate Rate IPC's
Case Case PCA
Application Stipulation Application
Month Days Hours 06/11/07 01/23/08 04/16/08 05/14/08
Apr.08 30 720 $8.340 $7.586 $9.580 $9.580
May-08 31 744 $8.250 $7.641 $10.433 $11.90
Jun-08 30 720 $8.337 $7.724 $10.532 $11.598
Jul-08 31 744 $8.440 $7.808 $10.639 $11.738
Aug-08 31 744 $8.515 $7.879 $10.698 $11.825
Sep-08 30 720 $8.555 $7.892 $10.716 $11850
Oct-08 31 744 $8.670 $7.971 $10.768 $11.912
Nov-08 30 721 $9.135 $8.226 $11.023 $12.162
Dec-08 31 744 $9.605 $8.511 $11.373 $12.527
Jan-09 31 744 $9.880 $8.736 $11.598 $12.737
Feb-09 28 672 $9.865 $8.741 $11558 $12.682
Mar-09 31 743 $9.605 $8.521 $11.283 $12.397
12-Months 365 8,760 $8.929 $8.100 $10.848 $11858
Percent Change from 6/11/07:-9%21%33%
Percent Change from 1/23/08:34%46%
Table 3
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