20101222Comments and Alternative Request.pdf

Peter J. Richardson ISB# 3195
Gregory M. Adams ISB# 7454
Richardson & O'Lear, PLLC
515 N. 27th Street
P.O. Box 7218
Boise, Idaho 83702
Telephone: [phone]
Fax: [phone]
peter(frichardsonandoleary.com
greg(frichardsonandoleary .com
¡~,
ZßlfDEC 22. ltî 2: 46
Attorneys for Northwest and Intermountain Power Producers Coalition
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE JOINT PETITION )
OF IDAHO POWER COMPANY, AVISTA ) CASE NO. GNR-E-IO-04
CORPORATION, AND PACIFICORP DBA )
ROCKY MOUNTAIN POWER TO ADDRESS ~ COMMENTS IN OPPOSITION BY THE
AVOIDED COST ISSUES AND TO ADJUST NORTHWEST AND
THE PUBLISHED AVOIDED COST RATE ~ INTERMOUNTAIN POWER
ELIGIBILITY CAP ) PRODUCERS COALITION AND
) ALTERNATIVE REQUEST FOR AN
) EVIDENTIARY HEARING
)
)
COMES NOW, the Northwest and Intermountain Power Producers Coalition ("NIPPC")
and pursuat to that Notice of Scheduling Order No. 32131 issued on December 3, 2010, by the
Idaho Public Utilities Commission (the "Commission") hereby provides its Comments in
Opposition to the requested reduction in the eligibilty cap for published avoided cost rates.
NIPPC respectfully requests that the Commission deny the request to reduce the published
avoided cost rate eligibility cap, and alternatively requests that the Commission hold an
evidentiar hearing prior to issuing any order reducing the cap.
COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS
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INTRODUCTION!
On Friday, November 5,2010, a Joint Motion ("Motion") and Joint Petition ("Petition"
or collectively the "Pleading") were lodged with the Commission by Idaho Power Company
("Idaho Power"), Avista Corporation ("Avista") and PacifiCorp, DBA Rocky Mountain Power
("Rocky Mountain" or collectively "the Utilities"). In their Petition, the Utilities asked the
Commission to initiate a docket to investigate various avoided cost and other related issues
regarding implementation of the mandatory purchase provisions of the Public Utility Regulatory
Policies Act of 1978 ("PURPA,,).2 In their Motion, the Utilties asked the Commission to
immediately adjust the published avoided cost eligibilty cap for qualifying facilities ("QFs")
from 1 0 average monthly megawatts ("MW") to 1 00 kilowatts ("kw") of nameplate capacity, on
less than 14 days notice if possible.
To justify the immediate eligibility cap reduction, the Utilities focused almost exclusively
on the number of wind QF contract requests being made to Idaho Power at the time of the filing.
The Utilities stated, "Idaho Power has over 570 MW of new QF wind contract requests, some of
which are significantly mature and close to having executed contracts." Joint Petition and Joint
Motion, at p. 4. They speculated that "Idaho Power could have over 1100 MW of wind powered
NIPPC provided additional factul and legal background in its Answer in Opposition to
the Joint Motion to Adjust the Published Eligibility Cap, which NIPPC fied on November 8,
2010 in this docket. NIPPC hereby incorporates that factual and legal background into these
Comments by reference.
2 The issues identified included: system reliability; operational control; ownership and
valuation of RECs; the lack of capacity provided by intermittent wind generation; the need to
build/acquire capacity on the system; the associated transmission infrastructure and upgrades
needed to bring additional wind generation to load; the interconnection and transmission service
request process; the mechancal availability guantee ("MAG") provision; the posting of
securty; liquidated damages; a standard contract template; the impact of QF generation on the
integrated resource planing (IRP) process; and the increased size and scale ofQF projects. See
Order No. 32131, at p. 1, n. 1.
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generation on its system in the near term, which exceeds the minimum loads experienced on
Idaho Power's system this year." Id The Joint Motion did not point out that the average mega-
watt generation ("aMW") for these proposed wind projects - even if they all were to achieve
commercial operation - would likely be approximately one-third (or less) of their nameplate
capacity, which would be no more than 367 aMW. Nor did it point out that Idaho Power's
average load forecasted for 2010 is 1797 aMW. See Idaho Power 2009 Integrated Resource
Plan (HIRP"), at p. 54.
The Joint Motion does not state that the avoided cost rates are too high, and it failed to
note that the avoided cost rate paid to each of the proposed wind projects would be reduced by
the Idaho Power's $6.50IMWh wind integration charge. Order No. 30488, at 8-9. The contracts
would also contan a Mechanical Availabilty Guarantee ("MAG"), which requires reduced
payment to the QF if its turbines are unavailable for inexcusable reasons. Id The wind QFs
would also need to agree to a Wind Forecasting cost sharing to defray the costs of integrating
wind. Id. Each of the projects that could eventully bring Idaho Power's cumulative wind
capacity up to 1100 MW would include all of these provisions to protect ratepayers from the
possibility of paying more than the avoided costs to Idaho Power. These provisions were all
arved upon in a compromise settlement that ended the last wind moratorium only a few years
ago. See id.
The Joint Motion appears to assert concerns regarding system reliability and costs of
integrating this level of proposed wind generation on Idaho Power's system as a basis to
immediately reduce the eligibilty cap for availability of the published avoided cost rates for all
three investor-owned utilities. Joint Petition and Joint Motion, at p. 4. Yet according to the
Joint Motion, Rocky Mountain Power has only 64 MW of executed wind QF contracts, and
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absolutely 0 MWonline. Id It also states Rocky Mountain Power has another 358 MW of
standard wind QF contracts proposed, but provides no real detals on the location of these
projects or how many of these inquies are likely to result in executed contracts. Id
The Joint Motion does not state that Avista has any wind QFs online whatsoever.
Although Avista has not fied for approval of any wind QF contracts, two wind QFs have fied
complaints against A vista alleging that A vista has failed to negotiate in good faith. See Case
Nos. AVU-E-I0-05, AVU-E-I0-06. Those two QFs, if successful in litigating against Avista,
would contract to sell a cumulative output of20 MW, and if successful in achieving commercial
operation would be the very first wind QF projects on Avista's system, and perhaps the only
wind projects whatsoever on the system that A vista would need to integrate at the time they
propose to come online.3
The Joint Motion makes no mention of other QF resources, and, most importtly,
nowhere does the Joint Motion state that the published avoided cost rates are too high. In short,
the Joint Motion states that the Commission should reduce the eligibility cap for published
avoided cost rates to 100 kw in order to "establish greater administrative control of contracts
during pendency of the Commission's and paries' investigation of the issues," which ru the
gamut from a proper delay security amount to cost-sharing on transmission upgrades. Joint
Petition and Joint Motion, at p. 6. From the Utilities' fiings to date, it is not even clear upon
what basis they would rely to support an argument that the curent avoided cost rates exceed
their actual avoided costs.
3 NIPPC relies upon Avista's 2009 Integrated Resource Plan, pages 2-15 to 2-21, which
lists the Stateline project as its only wind project and states Avista's contract with 35 MW from
that project expires in 2011. Although A vista has been planing to build the Reardon wind far,
for which it has purchased development rights, it is not clear that A vista is proceeding with its
plan to have that project online in 2012. See Avista 2009 Integrated Resource Plan, at p. 8-10.
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In response, in Order No. 32131, the Commission opened this docket. However, in doing
so, it refused to act on the Utilities' Joint Motion to immediately reduce the eligibility cap. In
refusing to immediately act on that request, the Commission stated:
The Petitioners also request that while the investigation is pending, the
Commission lower the published avoided cost rate eligibilty cap immediately "on
fewer than foureen days notice, if possible." Petition at 7. The Petitioners note
that a reduction in the eligibilty cap on an interim basis was previously
authorized in Case No. IPC-E-05-22. However, there is a signficant difference
between the Joint Petition in this case and Idaho Power's request to temporarily
lower the eligibilty cap in the 05-22 case. In the 05-22 case, Idaho Power's
petition was accompanied by supporting testimony. The Commission
subsequently conducted an evidentiar hearng and oral argument to develop the
record.
Order No. 32131 at p. 5. Although finding, by inference, that there is no record upon which to
base a decision on the requested reduction in the eligibility cap, the Commission did not ask for
testimony to be lodged, nor did it schedule evidentiar hearings. Rather, the Commission's order
requires only "comments in support or opposition" followed by an oral argument that is
scheduled for Januar 27, 2011. Order No. 32131 at p. 6. In addition to setting a schedule for
fiing comments (December 22), and reply comments (Januar 19), the Commission stated that it
was the Commission's "intent" that the effective date of its decision on the Utilities' requested
reduction in the eligibilty cap will be December 14,2010. Order No. 32121 at p. 5.
In addition to receiving comments on the requested reduction in the eligibility cap, the
Commission asked that the paries comment on whether such a reduction should apply to non-
wind QFs and the "consequences of dividing larger wind projects into 10 aMW projects to utilize
the published rate." Order No. 32121 at p. 5. Once the Commission decides the question
regarding the requested reduction in the QF eligibility cap, the Commission wil move to a new
phase of the case in order to explore the other PURPA issues raised in the Joint Petition.
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COMMENTS
A. REDUCING THE ELIGIBILITY CAP WOULD FRUSTRATE THE
FUNDAMENTAL PURPOSE OF PURPA, IN VIOLATION OF THAT
FEDERAL LAW
One of the primary reasons Congress passed the mandatory purchase provisions of
Section 210 ofPURPA was that Congress felt that ''taditional electricity utilities were reluctat
to purchase power from, and sell power to, the nontraditional facilities" and that this reluctance
"impeded the development of nontraditional generating facilities." FERC v. Mississippi, 465
U.S. 742, 750, 102 S.Ct. 2126, 2132-2133, 72 L.Ed.2d 532 (1982). "In order to overcome (this
problem) § 210(a) directs FERC, in consultation with state regulatory authorities, to promulgate
such rules as it determines necessar to encourage cogeneration and small power production,
including rules requiring utilties to offer to sell electrcity to, and purchase electricity from,
qualifying cogeneration and small power production facilties." Id, 456 U.S. at 751, 102 S.Ct. at
2133 (internal quotation omitted).
In the docket in which the Commission adopted the 10 average monthly megawatt cap for
entitlement to the published rates (consolidated docket nos. IPC-E-04-8 and IPC-E-04-10)
Commissioner Smith questioned the expert witnesses representing Idaho Power, U.S.
Geothermal and Mr. Lewandowski and Mr. Schroeder as to the purpose of PURPA.
Specifically she asked Mr. Runyan (U.S. Geothermal), Mr. Gale (Idaho Power) and Dr. Reading
(Lewandowski/Schroeder) the following questions:
Mr. Runyan, it occurs to me that ths is a good opportty for me to tae advantage of
your experience and a lot of times when you sit on a case like ths and you have engineers
talking to you about things that you really don't understad because you didn't take
physics, it occurs to you that the main purose of having a commission is to direct the
policy of what you're dealing with, and so with your experience with PURPA, what do
you think the purose, the public policy purpose of PURP A is?
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IPC-E-04-8 IPC-E-04-10 (consolidated) at Tr. 247
Dr. Reading, earlier today I had the opportity to ask Mr. Runyan his opinion about the
purose of PURP A and l d be interested in your thoughts on that as well.
Id at Tr. 300.
(To Mr. Gale) I just wanted to give you the opportunty even though you say you're new
to PURPA to answer the same question that I asked Dr. Reading and Mr. Runyan about
the policy behind PURP A, why we have PURP A and what the Commission needs to be
aware of so that we're implementing that policy.
Id at Tr. 483 - 484.
None of the witnesses explained, as the U.S. Supreme Cour did, that one of the fudamental
reasons for the mandatory purchase requirement is that the Utilities have been found to be
reluctant to purchase electricity from "nontraditional facilities." The result of that docket, the 10
average monthly MW eligibility cap, indicates that the Commission clearly understood its role in
implementing PURP A, even if the witnesses were unable to clearly ariculate that role. Excerpts
from the transcript containing the complete exchange are attched as Exhibit A to these
Comments.
In responding to Commissioner Smith's question, Mr. Gale on behalf of Idaho Power,
tred to avoid a direct answer by stating that by simply issuing Requests for Proposals via the
Utilities' IRP would serve "a lot of the same puroses. . . PURPA is tring to accomplish." Id at
Tr.484. In response, Commissioner Smith corrected Mr. Gale with the following exchange:
(Commssioner Smith)Q. But PURPA is stil the law; right?
(Ric Gale)A. Stil the law.
Id
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As the Commission considers its proper role in implementing PURP A in the context of
this case, it is importt to keep in mind both the Supreme Cour's finding that Utilities are
reluctant to purchase QF power and that PURP A is, indeed, stil the law.
B. THE COMMISSION'S PROCEDURA SCHEDULE VIOLATES THE FILED
RATE DOCTRINE AND THE PROHIBITION AGAINST RETROACTIVE
RATEMANG.
The effective date of the Commission's decision on the eligibility cap issue is purorted
to be December 14, 2010. While finding, impliedly, that there was no record upon which to base
its decision on that issue on the date of Order No. 32121, the Commission created a procedural
schedule and oral argument date that take place well after the proposed effective date. With oral
arguent scheduled for Janua 27, 2011, it is reasonable to not to expect to see the
Commission's order on this importt issue until early in Februar 2011. That this schedule is
problematic and unwieldy is discussed in detal below. The Commission's proposed schedule is
ilegal and violates fudamental ratemakng principles: namely, the fied rate doctrine and the
prohibition against retroactive ratemakng.
The sole reason the Commission made its "intent" to make the effective date of its
decision on the eligibilty cap retroactive is that it must anticipate that it may order a reduction in
that cap. The Commission canot simply make its orders retroactive by virtue of giving notice
that it may make a change in an existing rate or order at some indeterminate time in the futue.
Such regulatory practices would violate the filed rate doctrine.
The filed rate doctrine is a fudamental tenant of regulated utility law that has been
repeatedly and wholehearedly endorsed by this Commission. As the Commission recently
observed:
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The fied rate doctrine is a basic principle of utility regulation that was embodied
in Idaho Code §§ 61-313 and 61-315 shortly after the turn of the 20th centu
when our Public Utilty Laws were first adopted (1913). It also has a long history
and precedent with the federal regulatory system and the United States Supreme
Cour. Simply put, the filed rate doctrine states that a utility may charge only the
approved rates and charges it has on file with its regulatory body, i.e. its approved
taiff on fie with the Commission.
Order No. 30431 at p. 6. According to the fied rate doctrine, the Utilities are required to apply
curently effective tariffs and/or Commission orders and are prohibited from deviating from
those tarffs and/or orders until they are duly changed by the Commission. Id This doctrine
"embodies the policy which has been adopted by Congress in the regulation of interstate
commerce in order to prevent unjust discrimination." Id at p. 7 (quoting Maislin Industries,
u.s., Inc., v. Primary Steel, Inc. 497 U.S. 116, 127, 110 S.Ct. 2759, 2766 (1990)). Therefore the
Utilities are legally required to continue use of the 10 average monthly MW eligibilty cap for
published rates until or unless the Commission changes it. Between December 14, 2010 and
sometime in Februar 2011, should the utilties be offered PURPA contracts for projects larger
than 100 kw they wil be obligated to execute the same.
The prohibition against retroactive ratemakng requires commissions to set rates
prospectively and not reach back in time to alter a, heretofore, valid rate. Not only are utilities
bound by the filed rate doctrine, but reguatory commissions are as well. As the U.S. Supreme
Cour in Arkansas Louisiana Gas v. Hall 453 U.S. 571, 578, 101 S.Ct. 2925, 2930, 69 L.Ed 2d
856 (1981) declared:
Not only do the cours lack authority to impose a different rate than the one
approved by the Commission, but the Commission itself has no power to alter a
rate retroactively. When the Commission finds a rate uneasonable, it "shall
determine the just and reasonable rate. . . to be thereafter observed and in force."
§ 5(a), 52 Stat. 823, 15 U.S.C. § 717d(a) (emphasis added). See, e.g., FPC v.
Tennessee Gas Co., 371 U.S. 145, 152-153 (1962); FPC v. Sierra Pacifc Power
Co., 350 U.S. 348, 353 (1956). This rule bars "the Commission's retroactive
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substitution of an uneasonably high or low rate with a just and reasonable rate."
City of Piqua v. FERC, supra, at 12, 610 F.2d at 954.
Thus, this Commission, just like FERC, has no power to alter a rate retroactively. Should the
Commission find that the eligibility cap should be lowered based on a valid evidentiary record,
only then would be the Commission have the power to lower the cap on a prospective - going
forward - basis only.
The filed rate doctrne is applicable not only to the fixed rates charged by a utility. It is
also applicable to formulae, services, and methodologies. See In Re Universal Service Fund
Telephone Billng Practice Litigation 619 F.3rd 1188, 1198 (10th Cir. 2010) in whichthe Tenth
Circuit Cour addresses a line of cases in the telecommuncations context wherein the filed rate
doctrine was found to be applicable to "price, service, provisioning and biling of
telecommuncation services". See also Transwestern Pipeline Co. v FE.R.C. 897 F.2d 570,578
(D.C. Cir. 1990) in which the D.C. Circuit Cour notes that the filed rate doctrine does "not
confne rates to specific, absolute numbers but may approve a tariff containing a rate 'formula'
or a rate 'rule.'" Also instrctive is Occidental Chemical Corporation v. Louisiana Public
Service Corporation 494 F.Supp.2d 401 (M.D.La. 2007) which discusses applicability of the
filed rate doctrine to an "avoided cost methodology." Id at 417. Although the eligibility cap is
not a rate, per se, that fact does not exempt the application of the fied rate doctrine to it.
The eligibility cap is not a mere 'practice' or even a taff advice. The current eligibility
cap was adopted by this Commission in a contentious and vigorously litigated docket. (Order No.
29632 in consolidated docket nos. IPC-E-04 and IPC-E-04-1O.) That case took eight months to
prosecute and ended up with a transcript of almost seven hundred pages (not including exhibits).
The evidentiar hearing lasted two days. The Commission took testimony from expert witnesses
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offered by the Staff, all three of the Utilities as well as other paries. The Commission's decision
was well informed by a robust evidentiar record. The fact that the decision was well informed
is highlighted by the Commission's unusually detailed findings:
The Commission finds that the paries have persuasively established the
uneasonableness of using a simple 10 MW nameplate capacity rating to determine
posted rate eligibility. For QF projects with parasitic load requirements such as U.S.
Geothermal, such a standard would be inequitable. It is also uneasonable for low
capacity factor resources such as wind. The Commission finds that the Company
proposed meter energy test, a 10,000 kWh per hour limit is operationally too restrictive.
The Commission believes that QF generation should not be measured on an hourly, daily
or weekly basis, but rather on a monthly basis. It is on a monthly basis that QFs are paid.
We find that the 10 MW threshold limit, however, must have some import, some
significance if eligibility is to mean anyting. The Commission finds it reasonable to
define firmess as predictability on a monthly basis. By way of eligibility criteria, we
find it reasonable for the utility to make an initial capacity determination and require that
the QF demonstrate that under normal or average design conditions the project will
generate no more that 10 aMW in any given month. To provide fuher definition and
sideboards, we also find it reasonable to cap the maximum monthly generation that
qualifies for published rates at the tota number of hours in the month multiplied by 10
MW.
The time and effort that went into developing the criteria for eligibility to the published avoided
cost rates underscores the applicabilty of the filed rate doctrine to the criteria adopted by the
Commission in that docket. Any other constrction would eviscerate the very concept of the filed
rate doctrine. In addition, the Commission did not establish the curent rate mèthodology with a
"subject to refud"-like caveat that would have put QF developers, wind or otherwse, on notice
that the curent QF rate eligibility cap is subject to future change. Many developers have
reasonably relied on the curent methodology and are entitled to do so until it is changed
pursuant to a valid Commission order that is applied on a prospective basis.
C. THE COMMISSION'S PROCEDURAL SCHEDULE CREATES
UNCERTAINTY.
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In the time period between the effective date and the final order, QFs hoping to contract
with the utilities must decide whether to continue with their projects, and wil have no idea if the
published rates wil apply to their project. This creates a situation where the QFs would have to
be wiling to sign an agreement without certinty from the Commission as to whether the
published rates apply to their project. This will surely chill the market for QFs, and the
Commission should make its order effective on the date of its decision, not some point earlier.
Prospective QF developers must incur substatial time and expenses to progress to the point of
execution of a power purchase contract. A long term contract must provide certainty to the
developer that the rates within it will be enforceable. Without a long term contract with
enforceable rates financing the project will be impossible. The Commission's order creates
uncertinty with regard to the applicabilty of the published rate schedule, and will create a cloud
over all contract negotiations. The Commission should immediately clarfy that its ruling on the
eligibility cap issue wil be effective only after it issues an order on the issue to prevent
uncertainty in the market.
D. THE COMMISSION'S PROCEDURA SCHEDULE is NOT DESIGNED TO
CREATE AN EVIDENTIARY RECORD, AND THE COMMISSION SHOULD
HOLD AN EVIDENTIARY HEARNG PRIOR TO ANY ORDER REDUCING
THE ELIGIBILITY CAP.
As noted above, the Commission has found, by implication, that the Utilities have not
created a record for the Commission to rely on in deciding the requested reduction in the
eligibility cap. Ironically, the Commission's procedural schedule itself does not set up
procedures by which the Utilities can establish an evidentiary record. The curent schedule
allows only for initial comments, reply comments "addressing arguents and positions raised by
the initial comments," and oral argument. Order No. 32131, at p. 6. The procedure contains no
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opportity for filing of testimony or cross examination of witnesses on the eligibilty cap issues.
Without an evidentiar hearng, no fully developed evidentiar record will exist for this
important matter. That is entirely improper because the issues before the Commission are
essentially factual - the number of QF requests and the Utilities' ability to process and accept the
energy and capacity offered. NIPPC therefore requests that the Commission hold an evidentiary
hearing to address the eligibility cap issue raised by the Utilties. At such a hearing, the Utilities
wil have the burden to establish with their evidence that their requested reduction to 100 kw for
all QF resources is waranted and necessar to protect ratepayers and system reliabilty.
E. A DROP IN THE ELIGIBILITY CAP IS NOT WARRNTED BECAUSE THE
RECORD DOES NOT DEMONSTRATE THAT IDAHO POWER WILL BE
UNABLE TO INTEGRATE THE AMOUNT OF WIND PROPOSED, OR THAT
THE CURRNT WIND INTEGRATION CHARGE IS AN INACCURATE
REFLECTION OF THE INTEGRATION COSTS.
The Utilities' Pleading provides no basis to conclude that the curent wind integration
charge is inadequate to compensate each Utility for its integration costs, even at the level Idaho
Power states it may have on its system - 1100 MW of total nameplate capacity. The Joint
Motion omits the fact that Idaho Power's most-curent wind integration study - which it has not
seen fit to amend with an updated filing at the Commission since November 2007 - resulted in a
settlement setting the curent wind integration charge without setting a cap on the overall amount
of wind penetration. That study analyzed amounts up to 1200 MWs. See Enernex's Idaho
Power 2007 Wind Study, Case No. IPC-E-07-03, p. 5 (Februar 6,2007). Despite Idaho Power's
statements in the Joint Motion regarding 1100 MW being near Idaho Power's minimum loads,
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the Enernex study concluded that even at 1200 MW of wind capacity wind would reach only
80% loads and it would do so only for a few hours per year. See id at p. 35.4
Relying on that 2007 study, Idaho Power entered into, and the Commission approved, a
settlement of the long-standing dispute over wind integration charges. Idaho Power had proposed
that the availability ofthe published rates with a wind integration charge be limited to wind QFs
cumulatively amounting to only "up to 600 MWs." Application, Case No. IPC-E-07-03, at p. 12.
Thus, under Idaho Power's proposal, there would be an automatic cap at 600 MW, at which
point a new wind moratorium would presumably ensue while Idaho Power conducted studies of
penetration above that leveL. But the settlement and order provided for no 600 MW cap or
ensuing moratorium, and instead made the avoided cost rates available to wind developers at a
rate reduced by $6.50IMWh for projects coming online when Idaho Power's cumulative wind
power is "501 MWand above." See Order No. 30488, at p. 8. The settlement and the
Commission's order required Idaho Power to review its wind integration study in its IRP
processes and, if necessary, request that the Commission adjust the wind integration charge upon
that review. Order No. 30488, at p. 9. The Commission stated that it "expect(ed) annual review
by the Company and proposed adjustments when waranted." Id at p. 13.
Along those lines, Idaho Power stated in its 2009 IRP that, because it anticipated having
in excess of 600 MW of wind on its system, it planed "to update its wind integration study in
the first half of 20 1 0 . . . . The updated study will incorporate planed increases in wind
4
Idaho Power itself believed at that time that 1200 MW would overwhelm "the ability of system as
represented by the modeling software (Vista DSS) to consistently maintain the required amount of regulating
service." Idaho Power's Introduction to Enernex's Idaho Power 2007 Wind Study, Case No. IPC-E-07-03, p. 3
(February 6, 2007) (emphasis added); see also Addendum to Idaho Power's 2007 Wind Study, Case No. IPC-E-07-
03, p. 26 (Oct. 31,2007). But as discussed below, the modeling in the 2007 study did not take into account the
operating reserves that may be provided by the Company's gas-fired resources, including the Langley Gulch facilty
that wil soon be online.
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generation as well as the capability of the new Langley Gulch CCCT to provide additional
operating reserves." See Idaho Power 2009 IRP at p. 18. This statement in Idaho Power's IRP
indicates that Idaho Power must know that the addition of Langley Gulch wil expand its abilty
to integrate wind, and likely reduce the cost to do so. Indeed, the 2007 wind study focused
mainly on the Company's Hells Canyon complex as the wind balancing resource, and did not
consider the balancing capacity of the 300 MW Langley Gulch combined cycle gas plant, which
will be online in 2012. See Application, Case No. IPC-E-07-03, at p. 6; Addendum to Idaho
Power's 2007 Wind Study, at p. 1; Idaho Power 2009 IRP at p. 6; see also Enernex's Idaho
Power 2007 Wind Study, at p. 46 (listing the Company's hydropower and coal resources as
inputs to the model but not including any of the Company's gas-fired resources).
The use of the Company's curent and committed gas-fired resources as balancing
facilities for wind has never been taken into account in a wind study submitted to the
Commission. As early as 2004, Idaho Power estimated in its IRP that "in order to safely
integrate 1000 MW of intermittent wind generation, it would be necessar to contemporaneously
add 640 MW of combustion turbines to add capacity when the intermittent wind resources were
not operating." Order No. 29839, at p. 4. Today, Idaho Power has a 271 MW gas-combustion
facility at Danskin, a 173 MW gas-combustion facility at Bennett Mountain, and is constrcting
the 300 MW Langley Gulch plant for operation in 2012. Idaho Power 2009 IRP at pp. 6, 32.
That amounts to 744 MW of combustion tubine capacity in addition to the hydro firming
capacity studied in detail in the 2007 wind study! This is a critical point. Idaho Power's own
IRP declared that it would have no trouble integrating 1,000 MW of wind if it had 640 MW of
combustion tubines. In a few short months Idaho Power will have 744 MW of combustion
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PAGE-15
tubines on line - which should be suffcient to allow Idaho Power to accommodate all of the
wind projects it claims to be knocking on its door.
In the years since 2007, the Company has built and stared constructing new potential
wind-firming resources. Yet Idaho Power has not provided its updated wind integration study to
date, or proposed to increase the wind integration charge. An IRP cycle has come and passed,
and so has the time the Company set for release of its new wind integration study in the first half
of201O. The Company's decision not to update these studies demonstrates either negligence on
its par, or that the curent wind integration charge accurately reflects the costs to integrate the
wind. NIPPC submits that it would be foolish to assume Idaho Power has been negligent in its
efforts to make sure the wind integration charge is high enough. The Commission canot
conclude based on the record presented that Idaho Power is unable to integrate the proposed
wind projects, and there is no basis to make a reduction in the eligibilty cap for Idaho Power's
published rates effective December 14,2010.
As for Rocky Mountain Power and A vista, the filings to date have not even made the
case that either utility has any PURP A wind projects online, or that either is facing a large
amount of wind inquiries in Idaho. NIPPC will reserve its comments on the amount of wind
those utilities may be able to integrate until such time as they have provided some basis for the
proposition that they are anywhere near approaching such a leveL.
F. AGGREGATING SMALL WIND QFs BY THE SAME DEVELOPER IS
APPROPRIATE BECAUSE THE UTILITY is STILL PROVIDING A
CONTRACT AT THE AVOIDED COST RATE.
The Idaho Commission has essentially adopted the FERC one-mile-rule for use in
determining when QFs sharing a common owner are entitled to Idaho's published avoided cost
rates. The applicable FERC rule interprets a provision of the Federal Power Act, which limits
COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS
COALITION
PAGE-16
eligibility for QF status to facilities with "a power production capacity which, together with any
other facilities located at the same site (as determined by the (FERC)), is not greater than 80
megawatts." 16 U.S.C. § 796(l7)(A); see also 18 C.F.R. § 292.204(a).5 FERC's regulation
states that "the power production capacity for which qualification is sought, together with the
power production capacity of any other. . . small power production facilities that use the same
energy resource, are owned by the same person( s) or its afliates, and are located at the same
site, may not exceed 80 megawatts." 18 C.F.R. § 292.204(a)(I). "(F)acilties are considered to
be located at the same site as the facility for which qualification is sought if they are located
withn one mile of the facility for which quaification is sought." Id at § 292.204(a)(2)(i).
FERC adopted this one-mile separation rule with its initial PURP A regulations decades
ago, and has rejected attempts to alter since then. In FERC's most recent rule-making regarding
PURPA's mandatory purchase provisions, a large utility group requested that FERC "revisit the
'one-mile-rule' used to determine whether two facilities are par of the same QF for puroses of
§ 292.204(a)." Revision to Form, Procedures, and Criteriafor Certifcation ofQualifing
Facilty Status for a Small Power Production Facilty, 75 Fed. Reg. 15950, 15955 (March 30,
2010). The utility group asked "that the Commission adopt a rebuttable presumption that
facilities on sites located more than one mile apar are independent for puroses of QF
certification, but that utilities would be allowed to rebut this presumption upon a showing that
the facilities, although located more than one mile apar, are 'par of a common enterprise' and
5 PURP A imposes no size limitation to be a QF for projects which are an "eligible solar,
wind, waste, or geothermal facility" as defined in section 3 of the Federal Power Act, 16 U.S.C.
§ 796(l7)(E), but that section of the Federal Power Act only exempts facilities certified prior to
1994 and constructed prior to 1999. See 16 U.S.C. § 796(l7)(E).
COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS
COALITION
PAGE-17
should thus be considered as a single entity, not entitled to more separate certifications ofQF
status." Id
FERC rejected the utility proposal to undermine its one-mile-rue, observing that the one-
mile-rule has been par of its regulations since the inception of PURP A. Id. And the rule
remains today that two qualifying facilities up to 80 MW in capacity may be owned by the same
entity yet stil be PURP A "small power production facilties," so long as they are separated by
one mile. FERC's obvious intent is to promote development of relatively large renewable
energy facilities through PURPA. This intent is fuher evidenced by FERC's recent order
declaring that the Public Utility Commission of Texas must allow several QFs commonly owned
by John Deere Renewables to enter into long-term contracts at avoided cost rates calculated at
the time they incurred an obligation to deliver the output of their wind facilities to a utility. See
JD Wind 1, LLC, JD Wind 2, LLC, JD Wind 3, LLC, JD Wind 4, LLC, JD Wind 5, LLC, JD Wind
6, LLC, "Notice ofIntent Not to Act and Declaratory Order," 129 FERC ~ 61,148, at ~~ 24-29
(November 19,2009). FERC recognized that these projects were each "wholly-owned
subsidiaries ofthe John Deere Renewables, LLC," and that "(a)ll ofthe J.D. Wind QFs (we)re 10
MWs, except for J.D. Wind 4, LLC, which (wa)s 79.8 MW." Id at ~ 2, & n.4. FERC knew
these wind projects were developed by one large, sophisticated developer utilizing the one-mile-
rule to break up a 129.4 MW project into smaller projects to qualify below the 80 MW limit. But
FERC nevertheless ordered that these were entitled to PURP A contracts.
The Idaho Commission has essentially adopted FERC's one-mile-rule for determination
of QF size eligibility for entitlement to the published rates. In other words, commonly-owned
QFs using the same energy resource, and sized up to 10 aMW are entitled to the published rates
so long as they are separated by one mile. See Order Nos. 26772, 26966, 30415. The
COMMENTS IN OPPOSITION OF THE NORTHWEST AN INTERMOUNTAIN POWER PRODUCERS
COALITION
PAGE-18
Commission rejected attempts to require QFs tang the published rates to separate their projects
by five miles in Order No. 30415. The Utilities now renew their claim that QFs are "gaming"
the system and taking advantage of economies of scale by aggregating projects. But this is an
improper attempt to shift the focus of the debate away from the utilties' avoided costs and
instead focus on the cost to the QFs to build their projects. Ifthe published rates are a true
approximation of the utilities' avoided cost for the next incremental unit of generation, then there
is no reason to deny QFs the right to aggregate several small projects.
CONCLUSION
For the reasons set forth above, NIPPC respectfully requests that the Commission deny
the request to reduce the published avoided cost rate eligibility cap, and alternatively requests
that the Commission hold an evidentiar hearing prior to issuing any order reducing the cap.
) ,.(\Y
Respectfully submitted this _ day of December, 2010.
RICHARDSON AND O'LEARY, PLLCo/Æ~
Peter J. Richardson (ISB No: 3195)
Gregory M. Adams (lSB No. 7454)
Attorneys for the Northwest and
Intermountain Power Producers Coalition
COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS
COALITION
PAGE-19
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 22nd day of December, 2010, a true and correct copy
of the within and foregoing COMMENTS IN OPPOSITION BY THE NORTHWEST AND
INTERMOUNTAIN POWER PRODUCERS COALITION was served by ELECTRONIC
MAIL and US MAIL, to:
Donovan E. Walker
Lisa Nordstrom
Idaho Power Company
1221 West Idaho Street
Boise, Idaho 83707-0070
dwalker(fidahopower .com
lnordstrom(fidahopower .com
Don.sturtevant(fsimplot.com
Danel E. Solander
Rocky Mountain Power
201 South Main
Salt Lake City, UT 84111
Daniel.solander(fpacificorp.com
Ronald L. Wiliams
Wiliams Bradbur,P.C.
1015 W. Hays St.
Boise ID, 83702
ron(fwiliamsbradbury .com
Michael G. Andrea
A vista Corporation
1411 East Mission Avenue - MSC-23
Spokane, W A 99202
Michael.andrea(favistacorp.com
Scott Montgomery
President, Cedar Creek Wind, LLC
668 Rockwood Drive
North Salt Lake, Uta 84054
scott(fwesternenergy. us
Jean Jewell
Commission Secreta
Idaho Public Utilities Commission
472 West Washington
Boise, Idaho 83702
Jean. j ewellrmpuc.idaho. gov
Dana Zentz
Vice President, Sumit Power Group, Inc.
2006 E. Westminster
Spokane, W A 99223
dzentzrmsummitpower.com
Don Sturevant
Energy Director
J. R. Simplot Company
ONE CAPITAL CENTER
999 Main Street, P.O. Box 27
Boise, Idaho 83707-0027
Scott Woodbur
Idaho Public Utilities Commission
472 W. Washington (zip: 83702)
P.O. Box 83720
Boise, ID 83720-0074
Scott. Woodbur(fipuc.idaho.gov
Robert A. Paul
Grand View Solar
15960 Vista Circle
Desert Hot Springs, CA
COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS
COALITION
PAGE-20
robertpaul(ßgmail.com
Thomas H. Nelson
Renewable Energy Coalition
PO Box 1211
Welches, OR 97067
nelson(ßthnelson.com
R. Greg Ferney
Mimura Law Offces, PLLC
2176 E. Franlin Rd., Suite 120
Meridian, ID &3642
gre g(ßmimuralaw. com
James Carkulis
Managing Member
EXERGY DEVELOPMENT GROUP OF
IDAHO,LLC
802 West Banock Street, Ste. 1200
Boise, Idaho 83702
j carkulis(fexergydevelopment.com
Bil Piske, Manager
Interconnect Solar Development, LLC
1303 E. Carer
Boise, ID 83706
bil piske(fcab leone .net
Glenn Ikemoto
Margaret Flueger
Idaho Windfars, LLC
glennêEnvision Wind. com
Margaret(ßEnvision Wind. com
Dean J. Miler, Esq.
McDEVITT & MILLER LLP
P.O. BOX 2564-83701
Boise, Idaho 83702
ioe(fmcdevitt -miler .com
Paul Marin
Intermountain Wind LLC
P.O. Box 353
Boulder, Colorado
paulmarin(fintermountainwind.com
By:~\)ûu\rh)
Nina M. Curtis
COMMENTS IN OPPOSITION OF THE NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS
COALITION
PAGE-21
EXHIBIT A
COMMENTS IN OPPOSITION OF HE NORTHWEST AND INTERMOUNTAIN POWER PRODUCERS COALITION
EXHIBIT A
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1
2
3 WITNSS
I N D E X
EXAINATION BY
Mr. Ward (Direct)
Prefiled Direct Testimony
Mr. Kline (Cross)
Commissioner Kj ellander
Mr. Ward (Redirect)
Mr. Ward (Direct)
Prefiled Direct Testimony
Mr. Kline (Cross)
Mr. Woodbury (Cross)
Mr. Ward (Redirect)
Commissioner Kj ellander
Mr. Ward (Direct)
Prefiled Direct Testimony
Mr. Kline (Cross)
Mr. Woodbury (Cros s)
Mr. Fell (Cross)
Mr. Strong (Cross)
Commissioner Kj ellander
Commissioner Smith
Mr. Ward (Redirect)
Mr. Ward (Direct)
Prefiled Direct Testimony
Mr. Ward (Direct-Cont i d)
Prefiled Rebuttal Testimony
Mr. Kline (Cross)
Mr. Woodbury (Cross)
Mr. Fell (Cross)Mr. Strong (Cross)
Mr. Richardson (Cross)
Commissioner Smith
Mr. Ward (Redirect)
PAGE
9
11
30
35
38
39
42
49
58
59
60
61
63
111
117
120
130
132
135
137
142
144
187
189
228
237
238
241
245
247
250
4 Daniel Kunz
(U. S. Geothermal)
INDEX
5
6
7 Bill Sutherland
(u. S. Geothermal)
8
9
Kevin Kitz
(u. S. Geothermal)
Kip Runyan
(U. S. Geothermal)
CSB REPORTING
Wilder, Idaho 83676
.\
1
2
3 WITNSS
4 Don Reading
(Lewandowski &
5 Schroeder)
6
7
8
9 John R.Gale
(Idaho Power)
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
I N D E X
EXAINATION BY
Mr. Richardson (Direct)
Prefiled Direct Testimony
Prefiled Rebuttal Testimony
Mr. Kline (Cross)
Mr. Woodbury (Cross)
Mr. Fell (Cross)
Mr. Strong (Cross)
Commissioner Smith
Mr. Richardson (Redirect)
Mr. Kline (Direct)
Prefiled Direct Testimony
Mr. Kline (Direct-Cont' d)
Prefiled Rebuttal Testimony
Mr. Woodbury (Cross)
Mr. Strong (Cross)
Mr. Ward (Cross)
Mr. Richardson (Cross)
Commissioner Hansen
CommissionerSmi thMr. Kline (Redirect)
PAGE
253
256
277
291
298
298
299
300
302
305
307
359
361
388
389
392
428
477
480
485
CSB REPORTING
Wilder, Idaho 83676
INDEX
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1
2
3 WITNESS
I N D E X
EXAINATION BY PAGE
4 Laren J. Hale
(PacifiCorp)Mr. Fell (Direct)
Prefiled Direct Testimony
Mr. Woodbury (Cross)
Mr. Richardson (Cross)
Mr. Ward (Cross)
Mr. Fell (Redirect)
Commissioner Smith
491
494
515
516
518
525
528
5
6
7
8 Clint Kalich
(Avista Corp.)
Mr. Strong (Direct)
Prefiled Direct Testimony
Mr. Kline (Cross)
Mr. Richardson (Cross)
Mr. Ward (Cross)
Commissioner Kjellander
Mr. Strong (Redirect)
530
534
549
550
554
556
560
9
Kip Runyan
(U. S. Geothermal)
Rick Sterling
(Staff)
CSB REPORTING
Wilder, Idaho 83676
Mr. Ward (Direct-Reb)
Mr. Strong (Cross-Reb)
Commissioner Kjellander
Mr. Ward (Redirect-Reb)
564
569
570
572
Mr. Woodbury (Direct)
Prefiled Direct Testimony
Mr. Kline (Cross)Mr. Richardson (Cross)
Mr. Ward (Cross)
Commissioner Smith
Mr. Ward (Recross)
Mr. Woodbury (Redirect)
573
576
609
610
636
681
686
687
INDEX
1 a whole generated 70 percent, is it? Your testimony is
2 that that represents an Idaho Power specific number?
3 A Yes.
4 Q You're not testifying here today as to
5 what the experience may be with Avista or PacifiCorp or
6 somebody other than Idaho Power?
7 A No. I have not looked at them.
8 MR. STRONG: Thank you. That i s all I
9 have.
10 COMMISSIONER SMITH: Do we have questions
11 from the Commission?
12
13 EXAINATION
14
15 BY COMMISSIONER SMITH:
16 Q Dr. Reading, earlier today I had the
17 opportuni ty to ask Mr. Runyan his opinion about the
18 purpose of PURPA and I'd be interested in your thoughts
19 on that as well.
20 A Well, the purposes of PURPA in my mind,
21 Ilm thinking for a minute because there i s many purposes,
22 I think, for PURPA, certainly diversity is one that you
23 discussed. It i S also to try to install some measure of
24 competitiveness to the monopoly, electric industry at
25 least monopoly, at the time PURPA was passed. It is
CSB REPORTING
Wilder, Idaho 83676
300 REAPING (Com)
Lewandowski & Schroeder
1 aimed at - - boy, I could give you my economics lecture
2 here.
3 Q No lectures.
4 A That it's a check on the utility with the
5 Averich-Johnson effect where it's been shown that
6 monopolies tend to want to gold plate rate base because
7 that's where they get their rate of return, so in part it
8 was lobbied and passed because of that. I think PURPA is
9 a good law and I think what I didn i t realize at the time
10 is that it provides not only a good check for looking at
11 what a utility's resource is in building going forward, I
12 think it also provides a check to regulatory agencies on
13 what the value of conservation is and gives a measuring
14 stick so that regulatory commissions don't get too far
15 off the ranch either one way or the other.
16 I'm not sure I'm saying that very well,
17 but if you have an avoided cost rate and it goes through
18 a hearing process and it's established and it's thought
19 out, then you have a very good measuring stick about what
20 energy and electricity is worth, and when you do your
21 whole set of regulatory things, you can always look over
22 your shoulder and say we have that benchmark to look
23 at.
24 COMMISSIONER SMITH: Okay, thank you.
25 Do you have redirect, Mr. Richardson?
CSB REPORTING
Wilder, Idaho 83676
301 READING (Com)
Lewandowski & Schroeder
1 A There i S two angles to look at it. One is
2 to the extent that they can take measures, now there i s a
3 reason to take measures. To the extent that there are
4 things beyond their control, what it does do is now it
5 values the product we i re getting more correctly.
6 Q But if they don i t produce, then they don i t
7 get paid?
8 A Correct.
9 Q And if the Company has to go out and buy
10 power, for some reason it doesn i t have the resources on
11 its system or loads are more than you predicted and you
12 can't squeeze by, where do those costs go?
13 A Well, they i 11 go through the power cost
14 adjustment and, Commissioner Smith
15 Q I i m listening.
16 A ~ - if they don i t produce and the damages
i 7 are exacted, those will go through the power cost
18 adjustment as well, so the customers are expecting to get
19 that energy delivered from the QF. If it doesn't happen
20 and it i S to the customer's detriment, then the QF gets to
21 contribute to the PCA.
22 Q I want to go back to this volunteer issue
23 because I'm curious how can the Company be seen as a
24 volunteer as long as PURPA is the law and there i s a must
25 purchase requirement and this Commission approves
CSB REPORTING
Wilder, Idaho 83676 481 GALE (Com)
Idaho Power Company
1 contracts and you mentioned your experience in three
2 states in QF contracts at your own peril, so could you
3 please expand on that so I can understand how anybody,
4 especially given the history of your Company since 19
5 whatever, in the area of QF contracts could ever be seen
6 as a volunteer on these contracts.
7 A It's a particular aspect of it. When the
8 deregulation activity was going on, and the three states
9 I'm talking about was here in our own workshops and in
10 Oregon and in Nevada, the idea of stranded costs came up,
11 as you might recall, and along with the stranded costs
12 were the possibility of overpriced, arguably overpriced,
13 PURPA contracts, and in each state, as I recall, was not
14 the argument of those that you'd entered into up until
15 that time, but the mere fact that we had NEPA 92 and
16 deregulation on the horizon that any future contract that
17 a company might enter into in that environment, shame on
18 them if they didn't protect themselves contractually.
19 That i s what I'm referring to and that's what we i re trying
20 to provide here.
21 Q So was that a position of the Idaho
22 Commission?
23 A I don i t know that it was your position, in
24 fact, it probably wasn't your position, but it was a
25 discussion item in our deregulation workshops.
CSB REPORTING
Wilder, Idaho 83676
482 GALE (Com)
Idaho Power Company
1 Q So it was just a discussion item in
2 deregulation workshops that probably happened eight years
3 ago in a state where the legislative committee has
4 emphatically say we're not going there, not now, not
5 ever, no way?
6 A I hear what you're saying.
7 Q OkaYi so was it any more firm in Oregon?
8 A I think it was brought up in all the
9 states.
10 Q But was it any more firm? Is it a state
11 policy? Is it in their statute? Is it in a commission
12 order?
13 A I don't know if it's in their statute
14 because we're exempted from their part, but from my
15 aspect, if it i S an issue that is brought up in an open
16 discussion and if we don't take some action to mitigate
17 it, then it's just foolish from our end regardless of how
18 remote it is.
19 Q I understand. The other thing that
20 occurred to me that this incentive could be is a strategy
21 on the part of the Company to force these proj ects into
22 the RFP process so you pay prices lower than the QF rate.
23 A I don't know what the prices will bring in
24 the RFP process, but I i m eager to see.
25 Q Okay, and finally, I just wanted to give
CSB REPORTING
Wilder, Idaho 83676 483 GALE (Com)
Idaho Power COmpany
1 you the opportunity even though you say you i re new to
2 PURPA to answer the same question that I asked
3 Dr. Reading and Mr. Runyan about the policy behind PURPA,
4 why we have PURPA and what the Commission needs to be
5 aware of so that we're implementing that policy.
6 A Well, I i m not sure that I. m going to
7 differ much from Mr. Runyan i s answer. I think initially
8 it was put in to provide some other sources of
9 generation. To the extent it provides a discipline to
10 the Company's resOUrces like Dr. Reading said, that 1 s
11 fine, too. In today's age, I think an IRP that has teeth
12 in it with diverse portfolios that go out for RFPs could
13 serve a lot of the same purposes. The only place where I
14 see a disconnect is in the very small ones who wouldn 1 t
15 maybe be able to participate, but potentially even the
16 IRP RFPs could become the new avoided cost because we j 11
17 have a market test for those, but be that as it may, I
18 think an IRP process with teeth could do a lot of what
19 PURPA is trying to accomplish.
20 Q But PURPA is still the law; right?
21 A Still the law.
22 Q So the Commission still has the obligation
23 to calculate an avoided cost rate?
24 A And maybe costs could be based on IRP
25 results.
CSB REPORTING
Wilder i Idaho 83676
484 GALE (Com)
Idaho Power Company
20
1 Q So you think there i s flexibility there?
2 A Yes.
3 Q But you haven i t asked us to do that?
4 A No.
5 COMMISSIONER SMITH: All right, I think
6 that i s all I have.
7 Redirect, Mr. Kline?
8 MR. KLINE: I do have a couple. It looks
9 1 ike we r re going to be going tomorrow anyway or do you
10 have a feel for going late?
11 COMMISSIONER SMITH: Well, we can go off
12 the record for a minute.
13 (Off the record discussion.)
14 COMMISSIONER SMITH: We'll go back on the
15 record.
16
17 REDIRECT EXAINATION
18
19 BY MR. KLINE:
Q In a question to you from Mr. Richardson,
21 he stated that the Commission has not issued an order
22 that distinguishes QF resources between non-firm and
23 firm. Do you recall that question to you?
24
25
A Yes.
Q Isn i t it true that Idaho Power has filed
CSB REPORTING
Wilder, Idaho 83676 485 GALE (Di)
Idaho Power Company
1 COMMISSIONER SMITH: Are there questions
2 from the Commission?
3
4 EXAINATION
5
6 BY COMMISSIONER SMITH:
7 Q Mr. Runyan, it occurs to me that this is a
8 good opportunity for me to take advantage of your
9 experience and a lot of times when you sit on a case like
10 this and you have engineers talking to you about things
11 that you really don i t understand because you didn l t take
12 physics, it occurs to you that the main purpose of having
13 a commission is to direct the policy of what you i re
14 dealing with, and so with your experience with PURPA,
15 what do you think the purpose, the public policy purpose,
16 of PURPA is?
17 A Initially, and I think it still holds true
18 today, is to encourage a diverse supply of energy. It
19 was in response to the oil shortage, so a diversity in
20 supply of energy and the way it seems to me that the
21 state took it one step further is it said we like the
22 idea of diversity, but we only want to have the exposure
23 limited to so-called 10 megawatt plants.
24 Q Because part of our purpose is to protect
25 ratepayers from undue financial conditions or burdens;
CSB REPORTING
Wilder, idaho 83676
247 RUNAN (Com)
u. S. Geothermal
1 correct?
2 A Correct, and that i s why the Commission is
3 empowered to set the rates, the avoided cost rates, and
4 we i ve had those hearings and the SAR is now in place.
5 Q Do you think this goal of diversity in
6 supply is any less important today than it was when PURPA
7 was enacted?
8 A No, I think it i S more important.
9 Q And so in your opinion, if the Commission
10 is going to achieve this purpose of having diversity in
11 supply, recognizing that we've put appropriate safeguards
12 around it in terms of size and rate so that ratepayers
13 aren i t adversely impacted, what i s the right answer in
14 this case?
15 A The right answer in this case is to stick
16 with a well-proven contract methodology. The facts show
17 that the proj ect has consistently performed at levels
18 that are very acceptable and the Commission has gone
19 through over the years a capacity and energy payment
20 which was deemed too risky and in fact, was encouraged by
21 the utilities to go to an energy payment only for
22 delivered energy and with that change, we Ive had a very
23 stable situation that gets the performnce out of the
24 projects, that 1 s the desired performance, and does it in
25 a way that doesn i t burden the developer with a number of
CSB REPORTING
Wilder, Idaho 83676
248 RUNAN (Com)
u. S. Geothermal
1 very difficult risks that must be quantified in order to
2 finance and build a proj ect.
3 Q Now, with regard to these contracts and
4 some contracts maybe having different features or as
5 opposed to having just a standard contract that you sign
6 or you don i t sign, I guess I was trying to ponder whether
7 the purpose of having a standard contract was for the
8 benefit of QF developers or for the benefit of the
9 utility.
10 A Well, I think it i s to the benefit of both.
11 It i S always good for the developer to know what you i re
12 getting into on the front end. It i s to the benefit of
13 the utility because it takes less administrative burden
14 and I think it i s to the benefit of all the people
15 invol ved in it because you know what you have and you Ire
16 not going to get a lot of one-off type of deals.
17 Q Do you think there i s any room for
18 different features?
19 A Yes, I do. As Ilve stated, I think the
20 capacity limitation and the interpretation of the
21 Commission's intent is one that needs to be dealt with on
22 a project-by-project basis and it 1 s not an unreasonable
23 burden to consider what the resource type is and to make
24 a well-researched judgment on what i s an appropriate
25 determination of whether that meets the criteria or not
CSB REPORTING
Wilder, Idaho 83676
249 RUNYAN (Com)
u. S. Geothermal
1 and so.I think there does have to be flexibility.
2 Q And in terms of your discussion, I think,
3 with Mr. Strong and perhaps Mr. Fell about your goals for
4 the QF industry as a whole and the Commission's statewide
5 policy, would it be just enough for you if we approved
6 the contract terms that u. S. Geothermal desires in your
7 Idaho Power contract and didn't go for the full-blown,
8 statewide, three-utility, multi-project policy
9 position?
10 A That would be very adequate for my
11 client.
12 COMMISSIONER SMITH: Thanks. That i s all I
13 had.
14 Do you have redirect, Mr. Ward?
15 MR. WAR: Just one area.
16
17 REDIRECT EXAINATION
18
19
20 BY MR. WAR:
21 Q Mr. Runyan, Mr. Kline asked you some
22 questions regarding the ability of PURPA developers to
23 insist on a contract even if their capacity doesn't meet
24 the 10 megawatt limitation. Do you recall that
25 discussion generally?
CSB REPORTING
Wilder, Idaho 83676 250 RUNAN (Di)u. S. Geotherml