20110629Petition for Reconsideration.pdf

Ronald L. Wiliams ISB No. 3034
Wiliams Bradbur, Attorneys at Law
1015 W. Hays Street
Boise,ID 83702
Phone: [phone]
Fax: [phone]
ron(£wiliamsbradbury.com
Lary F. Eisenstat
Michael R. Engleman
Dickstein Shapiro LLP
1825 Eye Street, NW
Washington, DC 20006-5403
Tel: [phone]
Fax: [phone]
eisenstatl(£dicksteinshapiro.com
engleman(£dicksteinshapiro.com
Counsel for Petitioner Cedar Creek Wind, LLC
RECEIVED
201' JUH 29 PM 12: 17
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
PACIFICORP DBA ROCKY MOUNTAIN )POWER FOR A DETERMINATION )
REGARDING A FIRM ENERGY SALES )
AGREEMENT BETWEEN ROCKY MOUNTAIN )
POWER AND CEDAR CREEK WIND, LLC )
(RTTLESNAKE CANYON PROJECT) )
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IN THE MATTER OF THE APPLICATION OF
PACIFICORP DBA ROCKY MOUNTAIN
POWER FOR A DETERMINATION
REGARING A FIRM ENERGY SALES
AGREEMENT BETWEEN ROCKY MOUNTAIN
POWER AND CEDAR CREEK WIND, LLC
(COYOTE HILL PROJECT)
IN THE MATTER OF THE APPLICATION OF
PACIFICORP DBA ROCKY MOUNTAIN
POWER FOR A DETERMINATION
REGARDING A FIRM ENERGY SALES
AGREEMENT BETWEEN ROCKY MOUNTAIN
POWER AND CEDAR CREEK WIND, LLC
(NORTH POINT PROJECT)
CASE NO. P AC-E-ll -01 ..
CASE NO. PAC-E-ll-02
CASE NO. PAC-E-ll-03
DSMDB-2948658
IN THE MATTER OF THE APPLICATION OF
PACIFICORP DBA ROCKY MOUNTAIN
POWER FOR A DETERMINATION
REGARING A FIRM ENERGY SALES
AGREEMENT BETWEEN ROCKY MOUNTAIN
POWER AND CEDAR CREEK WIND, LLC
(STEEP RIDGE PROJECT)
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) CASE NO PAC-E-ll-04
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CASE NO. PAC-E-ll-05
IN THE MATTER OF THE APPLICATION OF
PACIFICORP DBA ROCKY MOUNTAIN
POWER FOR A DETERMINATION
REGARDING A FIRM ENERGY SALES
AGREEMENT BETWEEN ROCKY MOUNTAIN
POWER AND CEDAR CREEK WIND, LLC
(FIVE PINE PROJECT)
CEDAR CREEK WIND, LLC'S PETITION FOR RECONSIDERATION OF
ORDER NO. 32260 AND REQUEST FOR EXPEDITED TREATMENT
Cedar Creek Wind, LLC, ("Cedar Creek") petitions the Commssion to reconsider its
Order No. 32260, issued June 8, 2011 (the "June 8 Order"), in which it disapproved five Firm
Energy Sales Agreements (the "Agreements") between Rocky Mountain Power and Cedar Creek
(collectively, the "Parties") with respect to Cedar Creek's Rattlesnake Canyon, Coyote Hil,
North Point, Steep Ridge and Five Pine projects (collectively, the "Projects"). The Projects are
qualifying facilities ("QFs") under the Public Utility Reguatory Policies Act of 1978
("PURP A"). Nevertheless, the Commission held that the Projects were not eligible to receive
avoided cost PURP A contracts using published rates because the Agreements were not signed by
both Paries prior to December 14,2010, after which time such published rates no longer were to
be made available to QFs exceeding 100 kW.
PURP A and its implementing reguations however are clear: it is the legally enforceable
obligation of the QF to sell and of the electric utilty to purchase from the QF at rates based on
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the electric utility's avoided costs "calculated at the time the obligation is incured."i Indeed, the
term "legally enforceable obligation" purosefully does not equate to a fuly executed contract,
precisely because this would rest the fate of PURP A in the hands of one par. Thus, insofar as
the June 8 Order is expressly predicated on the fact that both Paries had not signed the
Agreements prior to December 14,2010, it turs the law on its head. And, because prior to
December 14, 2010, a "legally enforceable obligation" did exist with respect to the Agreements
under both federal and Idaho law, the June 8 Order as applied to Cedar Creek is uneasonable,
unawfl, erroneous, and not in conformity with federal or Idaho law, and Cedar Creek therefore
respectfully requests that the Commission reverse its determination and expeditiously approve
the Agreements as submitted, without fuher briefmg or proceedings.
I. PETITION FOR RECONSIDERATION
A. The Commission Erred in Holding that the Agreements Had to be
Fully Executed by December 14,2010
1. The Commission's Fully Executed Contract Requirement is
Contrary to Federal Law as Applied to Cedar Creek
In the June 8 Order, the Commission concluded that the "primar issue to be determined
in these cases is whether the Agreements - which utilze the published avoided cost rate - were
executed before the eligibility cap for published rates was lowered to 100 kW on December 14,
2010, for wind and solar projects.,,2 In so doing, the Commission adopted "a bright line rule: a
Firm Energy Sales Agreement/ower Purchase Agreement must be executed, i.e., signed by both
paries to the agreement, prior to the effective date of the change in eligibilty criteria.,,3 As
18 C.F.R. § 292.304(d)(2)(ii).
2 June 8 Order at 9 (emphasis added).
June 8 Order at 10. The change in eligibilty criteria reduced from 10 aM to 100 kW the size
of wind and solar QFs eligible for so called "published" avoided cost rates. Projects in excess of 100 kW
3
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more fully explained below, Cedar Creek respectfully submits that the Commission's application
of ths bright line rule is contrar to federallaw, specifically, the Federal Energy Regulatory
Commission's ("FERC") reguations implementing PURPA, which expressly reject the notion
that a QF must have a fuly executed contract in hand to obtan its PUR A benefits.
Under PURP A, a QF's right to sell at avoided cost rates arises out of a legally
enforceable obligation - not solely from a fully executed contract.4 FERC has made clear that a
"legally enforceable obligation" and an "executed contract" are neither synonymous nor
interchangeable; while all contracts constitute legally enforceable obligations, not all legally
enforceable obligations are expressed only in fully executed contracts.5 And FERC has
repeatedly upheld this distinction: (i) a legally enforceable obligation can, and does, exist in the
absence of a contract; (ii) under PURP A, QFs have the right to obtan the benefits of PURP A
even where no contract is executed; and (iii) the phrase "legally enforceable obligation" was
adopted expressly to prevent a utility from being able to circumvent PURPA's requirements
simply by failing to sign a contract with the QF.6
would no longer have the option of selecting the published avoided cost rates but would be restricted to
using avoided cost rates determined via the Integrated Resource Plan Methodology.
4 18 C.F.R. § 292.304(d)(2). See also 18 C.F.R. § 292.304(b)(5); 18 C.F.R. § 292.304(e)(2)(iii)
(specifying "(tJhe terms of any contract or other legally enforceable obligation" as being among the
factors affecting how the avoided cost rates "(tJo provide energy or capacity pursuant to a legally
enforceable obligation for the deliver of energy or capacity over a specified term" are to be determined).
5 See, e.g., Midwest Renewable Energy Projects, LLC, 116 FERC ~ 61,017 at P 15 (2006)
(rejecting "the notion that the terms 'contract' and 'obligation' are synonymous"); JD Wind i, LLC, 129
FERC ~ 61,148 at P 25 (2009).
6 See, e.g., Small Power Production and Cogeneration Facilities; Regulations Implementing
Section 210 of the Public Utilty Regulatory Policies Act of 1978, Order No. 69, FERC Statutes and
Regulations, Regulations Preambles 2001-2005 ~ 30,128, at 30,880 (1980) (subsequent history omitted);
JD Wind i, LLC, 130 FERC ~ 61,127 at P 7 (2010) (order on reh'g) (explaining that a QF's commitment
to sell to a utilty, and the utilty's accompanying obligation to buy from the QF, "result either in contracts
or in non-contractual, but binding, legally enforceable obligations").
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The key consideration, then, in determining whether a PURP A obligation exists is not
whether an agreement is fuly executed, but whether, as was true here for Cedar Creek, the QF
has committed through a legally enforceable obligation to sell power to the utility or, as also was
the case here for Rocky Mountain Power, the utility is committed to entering into a legally
enforceable obligation to buy that power. Consequently, and contrary to the Commission's
formulation, the issue in this case is not when the purchasing utility signed the contract, but
rather when the QF was entitled to a contract, because the QF's entitlement to avoided cost rates
is set as of that date.7 To conclude otherwse and allow one pary's inaction to defie whether a
legally enforceable obligation existed would allow a QF's rights to be held hostage to a signatue
- precisely what the PURP A regulations are designed to prevent.
Indeed, under the June 8 Order, until both paries sign, a QF has no PURPA rights.8
Hence, by imposing a bright line "signatue" requirement the Commission's implementation of
PURP A could not be more contrar to the PURP A regulations that expressly require a legally
enforceable obligation, not a contract, precisely in order to prevent what has happened here; i.e.,
a QF being prevented from receiving the benefit of its PURP A rights simply because the
purchasing utilty had not signed the contract. It is not at all surrising, then, that having asked
the wrong question - namely, were the Agreements fully executed - and having applied the
wrong stadard, the Commission reached a legally infrm result.9
By substituting its "fully executed contract" standard for the "legally enforceable
obligation" stadard the Commission violated Cedar Creek's PURPA rights and by so doing
7 18 c.F.R. § 292.304(d)(2)(ii).
See June 8 Order at 9.8
9 The Commission's observation that other developers were able to submit fully executed
agreements by December 14, 2010 does not change the fact that the legal standard applied by the
Commission to disapprove the Cedar Creek Agreements was incorrect.
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committed reversible legal error. Accordingly, Cedar Creek respectfully requests that the
Commission reconsider its June 8 Order, apply the appropriate stadard (which would not
require any hearings or further factual development beyond that in the existing record, including
ths petition), and approve the Agreements without fuer proceedings.
2. The Commission's Imposition of an Executed Contract
Requirement is Also Contrary to Commission Precedent
Regarding QFs' Rights under PURP A
No doubt, FERC leaves it to the discretion of state commissions to establish the date on
which a legally enforceable PURP A obligation is created. But state commissions are not
authorized to define what a legally enforceable obligation is by ignoring the very distinction the
PURP A regulations sought to make. If a legally enforceable obligation arose only upon contract
execution, there would be nothing for state commissions to determine. 10 Prior to issuance of the
June 8 Order, this Commission itself had recognized this crucial distinction, namely that it is the
existence of a legally enforceable obligation - and not a signed contract - that first secures and
protects the rights of QFs under PURP A, and on this basis, the Commission previously rejected
the notion that a legally enforceable obligation is equivalent to a fully executed contract.
In fact, the Commission applied the correct legally enforceable obligation standard as
recently as last year,11 as well as in 2005 when the Commission last lowered the QF eligibilty
cap to 100 kW under virtually identical circumstances to those present here.
12 And strikingly, in
10 The Commission itself cited case law affiring this on page 9 of the June 8 Order, where the
Commission quotes from Rosebud Enterprises, Inc. v. Idaho Public Utilties Commission (itself citing
FERc precedent): "it is up to the States, not (FERCJ to determine the specific parameters of individual
QF power purchase agreements, including the date at which a legally enforceable obligation is incurred
under State law." Rosebud Enterprises, Inc. v. Idaho Public Utilities Commission, 128 Idaho 609, 780-
781,917 P.2d 766, 623-624 (1996) (emphasis added and citing West Penn Power Co., 71 FERc ~ 61,153
(1995)).
11 Order No. 32104 at 11-12 (2010).
12 E.g., Order No. 29839 at 9-10 (2005).
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its 2005 orders - Order Nos. 29839, 29851, and 29872 - the Commission likewise lowered the
posted rate eligibility cap from 10 aMW to 100 kW. But it did not impose a "fully executed
contract" requirement on wind projects seeking to be grandfathered under the prior 10 aMW cap.
Instead, relying on precedents it established in various complaints and grandfathering cases, the
Commission applied the correct PURP A stadard, namely a "legally enforceable obligation
standard for published rate entitlement.,,13
Hence, in its prior cases the Commission found that because a legally enforceable
obligation does not exclusively arse from the mere existence of a contract, the key date for
puroses of determining whether such an obligation arose is not when the utilty actually signed
the contract, but when the legally enforceable obligation itself arose, thereby entitling the QF and
obligating the utility to negotiate a contract with avoided cost rates effective as of the date the
obligation was incurred.
Moreover, when previously considering whether QFs were eligible to receive published
avoided cost rates, the Commission identified indicative criteria to determine whether such a
legally enforceable obligation existed prior to the effective date of its decision on the eligibilty
cap. Incases where such criteria were met, a QF's contract was grandfathered in the
Commission's decision. The Commission correctly recognized, there, that it did not matter that
the contract had not yet been fully executed, and a QF that met these criteria was entitled to the
published rates even if it did exceed the new eligibility cap (in 2005) or secure a fuly executed
agreement after the change in rates (in 2010). The Commission should have applied the same
analysis to the PURP A Agreements and avoided the cost rate entitlement questions here.
13 Order No. 29872 at 9 (quotations omitted).
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According to the Commission in these prior decisions, a QF is entitled to the posted QF
rates if, as of the applicable deadline, the QF had (i) submitted a signed power purchase
agreement to the utilty14 and (ii) demonstrated "other indicia of substatial progress and project
maturty," such as "(1) a wind study demonstrating a viable site for the project, (2) a signed
contract for wind turbines, (3) aranged financing for the project, and/or (4) (made) related
progress on the facility permitting and licensing path.,,15 The purose of the indicative criteria is
not to create a rigid checklist but to demonstrate that the QF had expended suffcient time and
resources on contract negotiations and project development so as to achieve a level of project
maturty on the basis of which it reasonably could be expected to be brought on line within a
reasonable period following contract execution.
16
As recently as November 2010, just one month before issuing Order No. 32131 (the
"December 3 Order") (ironically, in which order the Commission claims to have given "notice"
of its determination here), the Commission likewise approved requests for grandfathering
published avoided cost contracts, again recognizing that a QF could satisfy criteria other than by
showing that it has a fully executed contract in order to demonstrate its entitlement to the
previously-effective published avoided cost rates.
17 In fact, the Commission approved the
requests based solely on circumstantial evidence indicating the QF's reliance on the existence of
14 As an alternative to submitting an executed power purchase agreement, a QF also could qualify
for grandfathered treatment by submitting ''to the utilty (J a completed Application for Interconnection
Study and payment of fee," and satisfying the other criteria described below. Order No. 29872 at 9.
15 Id at 8 (quoting Order No. 29839 at 9-10).
Id at 10-11. The Commission did not require that the QF satisfy each of these indicia, but had
intended only to provide example "criteria that could be looked to to assess project maturity." Order No.
29951 at 5.
16
17
Order No. 32104 at 11-12.
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a contract and the paries' representations even though the QF did not proffer any written
documentation of such agreement prior to the March 16, 2010 effective date.
18
Similarly, and perhaps even more analogous to the circumstances here, in July 2010, the
Commission approved a QF contract between Idaho Power Company and Cargil, which, while
fully negotiated prior to the March 16, 2010 effective date for new published avoided cost rates,
was not actually signed until May 4,2010, due solely to the same reason that the Agreements
were not executed by December 14,2010: namely, the utility had to complete its "Sarbanes-
Oxley review process and () routine internal approval....,,19 The Commission approved the
contract which incorporated the prior published avoided cost rates, based on the utility's
representation - again, as Rocky Mountain Power has done here - that all outstanding contract
issues had been resolved by that date and, but for the utility's internal review process, the
contract would or could have been signed prior to the March 16, 2010 deadline.2o
In short, these and the 2005 eligibilty cap orders furer demonstrate that the
Commission's "fully executed contract" requirement in its June 8 Order is squaely at odds not
only with federal law but with the Commission's own precedent in virtually the exact
circumstaces as those present in this case.21 Inexplicably, though, in the June 8 Order, the
18 Id at 12.
Order No. 32024 at 3.
Id at 4.
19
20
21 The Commission argues in the June 8 Order that "(b Jecause published avoided cost rates remain
unchanged and only the eligibilty size has changed, grandfathering criteria applied to rate changes are not
applicable here." June 8 Order at 10. This assertion is belied by the Commission's treatment of
similarly-situated QFs when it last reduced the eligibilty cap in 2005. The Commission acknowledged in
2005 that the same criteria Cedar Creek argues are applicable here, were appropriate for the change in
eligibilty cap then. Furhermore, for the Commission to argue that changing the eligibilty cap, and thus
the rates that a QF is entitled to be paid for its power, does not constitute a "rate change" ignores the
reality of what the Commission, and the utilties, are doing to affected QFs. Were QFs that are deemed
ineligible for the published avoided cost rates able to obtain those same rates under the Commission's
Integrated Resource Planing avoided cost determinations, there would be no issue here. However, as
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Commission ignored its own history, and rejected the established "legally enforceable
obligation" standard in favor of the new bright line "fully executed contract" rule. And it did so
without explaining why it abruptly rejected and depared from its precedent, and changed how it
applied the PURPA regulations. Thus, the Commission's misapplication of its own law renders
the June 8 Order both uneasonable and unawfl insofar as it denied a QF its PURP A benefits,
and did so without explanation.22 Consequently, as the Commission already has ruled that the
aforementioned criteria are sufficient to establish a "legally enforceable obligation," any QF that
met those criteria prior to December 14, 2010 should similarly have been grandfathered and
entitled to receive the previously published rates.
3. Although the Commission Gave Notice ofthe December 14,2010
Effective Date, it Did Not Give Notice of its Intention to Require that
Affected QFs Have Fully Executed Contracts by that Date in Order
for them Stil to Use the Published Avoided Cost Rates
Contrar to the Commission's assertion in the June 8 Order, the Commission did not
previously hint at, much less state, the new bright line "executed contract" requirement in the
December 3 Order. Rather, the December 3 Order was a procedural order directing only (as
relevant here) "that the Commission's decision regarding whether to reduce the published
avoided cost eligibility cap (would) become effective on December 14,2010.,,23 No doubt, if
documented in Dana Zentz's affdavit submitted in this proceeding (the "Zentz Affidavit"), the prices
available to the Projects under that process are 35% lower than the published avoided cost rates that were
previously available. Zentz Affidavit at 9. By changing the eligibilty cap rules, the Commission is by
definition changing the rates that QFs are paid, and any grandfathering criteria that would appropriately
be applied to "rate changes" should also be applied here, just as the Commission has done in the past.
22 At a minimum, the Commission must provide a reasoned explanation of its depare from its
governing precedent. Absent such an explanation, the June 8 Order plainly is unreasonable and in
violation ofIdaho law. E.g., Intermountain Gas Co. v. Idaho Public Utilty Comm'n, 97 Idaho 113, 119,
540 P.2d 775, 781 (1975).
23 December 3 Order at 9 (emphasis added). On Februar 7, 2011, the Commission issued Order
No. 32176, which temporarily reduced the cap from 10 aMW to 100 kW, effectively rendering projects in
excess of 100 kW ineligible for the posted avoided cost rates as of December 14,2010. The Commission
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such a reduction were to occur, it would be effective on December 14,2010. But nowhere in the
December 3 Order does it state that such reduction would be applied to any QF purchase
agreement not fully executed by such date.
Nor did the December 3 Order specify any requirements or even milestones that a QF
would have had to meet by the December 14,2010 effective date in order for it not to lose the
right it otherwse would have had to receive the published avoided cost rates. In fact, it did not
state, imply, or otherwse lead one reasonably to conclude that the Commission would or even
might reject its own precedent, much less violate PURP A, by requiring that a QF have a fully-
executed contract in order to receive the published rates. In sum, although the June 8 Order by
reference to Rosebud Enterprises recognzes that the proper question under PURP A is, "when
was a legally enforceable obligation incured?", the Commission nevertheless chose to ignore
PURP A's requirement that a QF's right to an avoided cost based contract be honored as of such
time as a legally enforceable obligation first arose.24 Instead, it decided not to approve the
Agreements because insofar as they were not fully executed (i.e., signed by both paries) until
December 22, 2010, they were not effective prior to December 14, 2010, the date on which the
eligibilty cap was reduced to 100 kW.25
In so holding, though, the Commission erroneously asserted that because the December 3
Order clearly gave notice that any such change would be effective on December 14,2010, and
that the Order made it equally clear that the Commission would apply the "bright line rue" or,
presumably any such rule as the Commission otherwse might have come to adopt in the June 8
subsequently implemented the eligibility cap on a fmal basis in Order No. 32262, entered on June 8,
2011.
24 18 c.F.R. § 292.304(d)(2)(ii) (entitling a QF to rates based on "avoided costs calculated at the
time the obligation is incurred' (emphasis added)).
25 June 8 Order at 9. The Commission concluded that because the Projects all were larger than
100 kW, they were not entitled to receive the published avoided cost rates.
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Order as to what would happen in cases where both paries had not signed a purchase contract by
December 14,2010. Yet, the December 3 Order contans absolutely no notice of any such
possible requirement. And, as noted above, just one month earlier, the Commission reached the
directly opposite result, a result that was consistent with years of Commission precedent. What
is clear, then, is that the December 3 Order was, or only could have reasonably been interpreted
to be, purely a procedural order that did not reduce the eligibilty cap, nor specify how a
reduction not yet decided on its merits would be implemented.
Insofar as the December 3 Order certainly did not state or even imply that the
Commission would change its prior Orders and now require a QF to have a fully executed
contract to receive the published rates, the effect of the June 8 Order is to retroactively apply that
standard without notice or due process via an order issued more than 6 months after it anounced
the December 14,2010 deadline. Therefore, by failing to provide potentially affected QFs the
notice required under Idaho law, regardless of whether the appropriate notice period was simply
the 30-day notice required when the Commission is performing its legislative fuction of setting
rates,26 or the more extensive notice required under Idaho's Administrative Procedure Act,27 the
Commission has acted in an uneasonable and unlawfl maner that is not in conformity with the
requirements of Idaho law. The June 8 Order must therefore be reversed.
B. The Agreements Should be Approved Because a Legally Enforceable
Obligation Under Applicable Commission Precedent Existed Between
Cedar Creek and Rocky Mountain Power as of December 14, 2010
The Commission's precedents and criteria for determining a QF's eligibilty to receive
published avoided cost rates, together with the relevant undisputed record of ths proceeding,
26 IDAHO CODE ANN. § 61-307; see also A. W. Brown Co. Inc. v. Idaho Power Co., 121 Idaho 812,
819,828 P.2d 841, 848 (Idaho 1992).
27 IDAHO CODE ANN. § 67-5201 et seq.
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leave no doubt that the Paries were under a legally enforceable obligation prior to the
December 14,2010 deadline, and as such, the Agreements should have been allowed to be based
on the published rates available to QFs up to 10 aMW prior to that date, and should have been
approved.
As Rocky Mountan Power acknowledged, the Paries "had completed negotiation of all
terms of the Agreements for Cedar Creek's five projects prior to December 14,2010.,,28 Having
finished their negotiations and agreeing that neither pary had any additional substantive changes
to the Agreements' provisions, the paries agreed on Friday, December 10,2010, that the
documents were ready for execution. Cedar Creek therefore finalized the Agreements, executed
them, and delivered signed originals to Rocky Mountan Power on December 13,2010, one day
prior to the aforementioned effective date. It is also undisputed that when Cedar Creek executed
the Agreements and delivered them to Rocky Mountain Power on December 13,2010, the only
remaining task was for Rocky Mountain Power to complete its administrative processing.29
Regrettably, Rocky Mountain Power did not execute the Agreements until December 22,2010,
and did not fie them for Commission approval until Januar 10,2011, almost one month after
their having been tendered by Cedar Creek.
But negotiation history aside, FERC and Commission precedent is clear that the signature
history is irrelevant if a legally enforceable obligation existed. And it is undisputed that Cedar
Creek executed the Agreements and submitted them to Rocky Mountain Power prior to the
28 June 8 Order at 7.
29 See Order No. 32024 at 3-4 (approving grandfathered avoided cost rates for a QF where only the
utilty's administrative processing of its contract prevented that contract from being executed prior to the
change in rate eligibility). During the period of administrative processing, Rocky Mountain Power made
a number of undisputedly nonmaterial revisions to the Agreements, but this fact is not germane to the
determination of whether a "legally enforceable obligation" existed prior to the December 14, 2010 date
because it speaks to the wrong question, that is, when the Agreements were fully executed as opposed to
when a legally enforceable obligation first arose.
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Commission's December 14, 2010 deadline.3o Hence, this satisfies the first criterion previously
ariculated by the Commission in Order Nos. 29839, 29851, and 29872, namely that the QF had
submitted a signed power purchase agreement to the utility as of the anounced effective date.31
In addition to having delivered signed Agreements to Rocky Mountan Power
establishing its intent to be legally bound by such Agreements, by December 14,2010 the
Projects also had demonstrated many other "indicia of substatial progress and project
maturty.,,32 Specifically, by December 14,2010 Cedar Creek had completed, or made
substantial progress toward completing, virtally all of the critical path development milestones
for each of the Projects, including those specifically identified by the Commission as
demonstrating sufficient "substantial progress and project maturity" to establish a legally
enforceable obligation.
1. Cedar Creek had more than two years of wind data: By the end of September,
Cedar Creek had completed two years' wort of wind studies for the Projects and
provided such data to Rocky Mountain Power as par of its due dilgence efforts.
2. Cedar Creek had aranged a term sheet with a major turbine provider: By October
2010, Cedar Creek had commenced negotiations with Siemens and on that
substative basis received on December 3,2010 a proposed term sheet for the
wind turbines, the provisions of which are now largely reflected in the curent,
substatially complete Turbine Sale Agreement (which, consistent with curent
industry practice regarding tubine sales, would have been signed upon the
approval of the of the Agreements). Through its affliates, one of Cedar Creek's
30 Additionally, as set forth above, and wholly aside from these preexisting criteria, as of
December 13,2010, the Projects were obligated to sell to Rocky Mountain Power at the published
avoided cost rates available for QF projects of up to 10 aMW and Rocky Mountain Power plainly was
under a legally enforceable obligation to continue in good faith to negotiate and execute a contract with
the then published avoided cost rates.
31 E.g., Order No. 29839 at 9-10.
32 Order No. 29872 at 8.
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two owners had negotiated the Burchase of wind turbines from Siemens for a
number of other wind projects. 3
3. Cedar Creek had a verbal agreement with one lender to provide approximately
$240 milion in financing: In October 2010, Cedar Creek commenced discussions
with potential lenders as to the Project's financing. Following extensive due
diligence efforts, Cedar Creek continued serious discussions with three lenders.
Through this process, Cedar Creek negotiated two term sheets (as many lenders
require a co signed power purchase agreement for board approval of term sheet
issuance). By early December 2010, Cedar Creek reached verbal agreement with
a lender that provided a term sheet shortly after Rocky Mountain Power signed
the Agreements, on the basis of which Cedar Creek held execution-ready
agreements for financing (but for some minor changes stil to be made to a few
exhbits) at the time of the Commission's rejection of the Agreements.
4. Cedar Creek had already obtained two required Special Use Permits: By March
2010, Cedar Creek had obtained the two primary county Special Use Permits
("SUP") required to build and operate the Projects. Specifically, on August 25,
2008, Cedar Creek obtained the first SUP to install a total of 66 turbines. On
March 24,2010, Cedar Creek obtaned the second Special Use Permit from
Bingham County to build and operate an additional 33 wind tubines at the
Projects.
5. Cedar Creek had full site control: By November 12,2009, Cedar Creek had ful
control of the sites for the Projects through wind lease agreements with multiple
land owners.34
6. Cedar Creek had submitted interconnection requests, executed binding
agreements and made six figure deposits to maintain the required interconnect in-
service date: Cedar Creek submitted its interconnection request on December 19,
2008, and obtaned its Large Generator System Impact Studls and Facilties Study
reports on July 22,2009 and March 18,2010, respectively. 5 In addition, Cedar
33 Unlike 2005 when wind turbines were in short supply and early reservations were the norm, in
today's market the practice is not to consummate turbine sale agreements and incur substantial reservation
fees until the developer has an approved power purchase agreement in hand.
34 FERc defines "site control" by reference to the definition of that term in the Stadard Large
Generator Interconnection Procedures, which is as follows:
documentation reasonably demonstrating: (1) ownership of, a leasehold
interest in, or a right to develop a site for the purpose of constrcting the
Generating Facility; (2) an option to purchase or acquire a leasehold site
for such purposes; or (3) an exclusivity or other business relationship
between the Interconnection Customer and the entity having the right to
sell, lease or grant the Interconnection Customer the right to possess or
occupy a site for such purose.
35 See Zentz Affdavit, p. 5, 6.
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Creek executed an Engineering & Procurement Agreementwith Rocky Mountain
Power on September 15,2009, pursuat to which it tendered a $100,000 deposit.
Cedar Creek was provided with a draft large generator interconnection agreement
("LGIA") on April 15, 2010, although Rocky Mountan Power has since required
Cedar Creek to enter into a QF-specific LGIA. 36
7. Cedar Creek had submitted formal requests for and posted six figue deposits to
secure transmission: On Janua 11,2010 Cedar Creek submitted to PacifiCorp
an OASIS request for 99 MW of long term firm point-to-point transmission
service, and posted a security deposit of $200,475 roughy one week later. Cedar
Creek executed a Long Term Point to Point Transmission Service agreement with
PacifiCorp in May 2010.37
Lastly, as of December 14,2010, Cedar Creek had in total invested $1.2 milion to
support its obligations to deliver the Projects - fully permitted, constrcted and operating - by
the commercial operation dates specified in the Agreements. Cedar Creek's investment has since
grown to roughy $3.5 milion, and in order to meet an October 1,2012 commercial operation
date would have increased much more had the Agreements not been rejected. Collectively, then,
the Projects reflected the work of real, matue development efforts, significant financial
investments, and irrevocable commitments.
In short, there is no question that as of December 14,2010 the Projects were more than
sufficiently mature so as to require Rocky Mountain Power to negotiate and eventually execute a
contract pursuant to PURP A. Both FERC and Commission precedent required ths legally
enforceable obligation to be honored as of December 14, 2010 and Rocky Mountan Power
eventually to formally execute the Agreements. Thus, because a legally enforceable obligation
existed as of December 14,2010, Cedar Creek is entitled to receive the then published avoided
cost rates for projects up to 10 aMW, and the Agreements therefore should be accepted and
approved by the Commission without fuher hearngs or other proceedings.
36 Id.
Id. at p. 6, 7.
37
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II. REQUEST FOR EXPEDITED TREATMENT
The issue raised by this Petition is strictly one of law, there being no relevant factua
disputes and no need for fuher factul support. Cedar Creek, therefore, requests that the
Commission grant reconsideration and approve the Agreements without an evidentiar hearng
or fuher proceedings, as it has on other occasions when QFs sought and received grandfathered
published avoided cost rates in recognition of their PURPA rights.38
Cedar Creek also requests that the Commission issue its order on reconsideration on an
expedited basis but not later than August 5, 2011. As the Commission and the Paries are (and
have been) well aware, Cedar Creek must have the Projects on line by the end of2012 to receive
federal financial incentives. To do so, they must be able to accept back-feed power by mid-Fall
2012 at the latest. And as Cedar Creek has been informed by Rocky Mountain Power, for ths to
occur, Rocky Mountain Power must begin almost immediately to order various critical path
equipment and materials required for the Projects' interconnection. Hence, it certnly can be
said that time is now of the essence and that absent the Commission's expeditious
reconsideration and approval of the Agreements, the continued viabilty of the Projects will be in
very considerable jeopardy.
The process leading up to the Commssion's issuace of the June 8 Order already was
lengthy, and the matters presented in this petition are straight-forward; they do not require a
similar extended process. Again, though, and most importtly, for Cedar Creek to meet its
operational dates, the Commission must move promptly to reconsider and revise its June 8
38
E.g., Order No. 29951; Order No. 30246; Order No. 30268.
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Order. Accordingly, Cedar Creek respectfuly submits that expedited Commssion action by
August 5, 2011 is paricularly appropriate under the instat circumstances.39
III. CONCLUSION
For the reasons described herein, Cedar Creek respectfuly requests that the Commission
expeditiously grant this petition for reconsideration and, by August 5, 2011, approve the
Agreements without fuher briefing, hearng, or other proceedings.
DATED this 29th day of June, 2011.
R~lr)~
Larr F. Eisenstat
Michael R. Engleman
Dickstein Shapiro LLP
1825 Eye Street, NW
Washington, DC 20006-5403
Telephone: [phone]
Counsel for Petitioner Cedar Creek Wind, LLC
39 Finally, although Cedar Creek very much believes that its Petition is meritorious, and that it is
entitled to a positive decision by August 5th, Cedar Creek respectfully asks that should the Commission
be inclined to deny reconsideration, that it do so as promptly as possible in order that we might seek
judicial relief and in time to stil have a fighting chance of meeting its constrction and operation
schedule.
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CERTIFICATE OF MALING
I HEREBY CERTIFY that on this a G day of June, 2011, I caused to be served a tre and
correct copy of the foregoing document upon the following individuals in the manner indicated
below:
Ted Weston
Rocky Mountain Power
201 South Main, Suite 2300
Salt Lake City, UT 84111
E-Mail: ted.weston(fpacificorp.com
Daniel E. Solander
Rocky Mountain Power
201 South Main, Suite 2300
Salt Lake City, UT 84111
E-Mail: danieL.solander(fpacificorp.com
Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
E-Mail: datarequest(fpacificorp.com
Kristine Sasser
Idaho Public Utilities Commission
472 W. Washington (zip: 83702)
PO Box 83720
Boise,ID 83720-0074
E-Mail: kristine.sasser(fpuc.daho.gov
Kenneth E. Kaufiann
Lovinger Kaufian LLP
825 NE Multnomah, Suite 925
Portland, OR 97232-2150
E-Mail: kaufiann(£lklaw.com
D Hand Delivery
D US Mail (postage prepaid)
D Facsimile Transmission
D Federal Express
IZ Electronic Transmission
D Hand Delivery
D US Mail (postage prepaid)
D Facsimile Transmission
D Federal Express
IZ Electronic Transmission
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ÆaJ L1j~
Ronald L. Wiliams
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