20110826Staff Answer.PDF

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
CEDAR CREEK WIND,LLC )
)DOCKET NO.EL1 1-59-000
)
_____________________________________________________________________________________
)
ANSWER OF THE IDAHO PUBLIC UTILITIES COMMISSION
The Idaho Public Utilities Commission (“Idaho PUC”)hereby submits this Answer,
pursuant to Rules 206 and 213 of the Commission’s Rules of Practice and Procedure (18 C.F.R.
§385.206,385.2 13 and the Commission’s Notice of Petition for Enforcement issued August 8,
2011(76 Fed.Reg.50212 (August 12,2011)),to the Petition for Enforcement of the Public
Utility Regulatory Policies Act of 1978 filed August 5,2011 by Cedar Creek Wind,LLC
(“Cedar Creek”).As the respondent to Cedar Creek’s Petition,the Idaho PUC is a party to this
proceeding and need not separately move to intervene.Pacific Gas &Electric Co.v.Sunnyside
Cogeneration Partners,L.P.,97 FERC ¶61,378 at 62,726 (2001).
I.SUMMARY AND OVERVIEW
Cedar Creek’s Petition fails to make out a case for enforcement under PURPA
Section 210(h)(16 U.S.C.§824a-3(h)(2))even if this Commission were to accept Cedar Creek’s
mischaracterization of the proceedings before the Idaho PUC.Reduced to its essence,Cedar
Creek’s claim is that the Idaho PUC acted unreasonably in declining to find that,notwithstanding
contractual language demonstrating a contrary intent on the part of both parties,Cedar Creek had
somehow established a “legally enforceable obligation”to sell the project’s output at published
avoided cost rates to the utilities.Even if Cedar Creek’s contention had some merit (and it does
IDAHO PUC ANSWER 1
not),that contention is properly decided by the Idaho Supreme Court on review of the PUC’s
Orders,and not by this Commission in the context of a Section 210(h)petition to enforce
PURPA.Having failed to preserve its right to seek review of the Idaho PUC’s adjustment of the
eligibility cap for published avoided cost rates in the Idaho Supreme Court,Cedar Creek cannot
now resurrect its claim by wrapping it in hyperbole and throwing itself on the mercy of this
Commission.
Cedar Creek’s Petition is equally devoid of substantive merit.The Petition
mischaracterizes and conflates two separate but related Idaho PUC proceedings that generally
addressed PURPA issues.in the first proceeding’(the “Eligibility Cap Case”),Avista
Corporation,Idaho Power Company,and PacifiCorp dba Rocky Mountain Power (collectively
the “Utilities”)petitioned the Idaho PUC on November 5,2010,to initiate a generic investigation
to address various avoided cost issues.The Utilities also requested that while the investigation
was underway,the PUC “immediately”reduce the eligibility standard for the “published”
avoided cost rates available to all qualifying facilities (“QFs’).The Utilities proposed that the
“eligibility cap”2 for the “published”avoided cost rates for the three utilities be reduced from 10
average megawatts (“aMW”)3 per month to 100 kilowatts (“kW”).Exhibit 1 at 1.Cedar Creek
was a party in this case.Id.at 3,5.On December 3,2010,the Idaho PUC issued a public Notice
and Order,soliciting initial and reply written comments,and convened an oral argument to
‘Idaho PUC Case No.GNR-E-10-04;Order No.32131 at 9 (Dec.3,2010),2010 WL 4948925 (Idaho PUC)
(attached as Exhibit 1).
218 C.F.R.§292.304(c)(1)provides that State regulatory commissions “shall”establish published or “standard rates
for purchases from {QF5I with a design capacity of 100 {kW]or less.”However,the Commission’s regulation also
declares that State commissions “may”set standard or published rates “for purchases from {QFsI with a design
capacity of more than 100 [kW.”18 C.F,R.§292.304(c)(2)(emphasis added).
In February 2008.the Idaho PUC had raised the eligibility cap to 10 aMW.IPUC Order No.30488 at 17 (Feb 20,
2008),2008 WL 562949*13 (Idaho PUC);see also Exhibit 2 at I.
IDAHO PUC ANSWER 2
address the request to reduce the eligibility cap from 10 aMW to 100 kW.Id.at 6-7.Although
the Idaho PUC declined in its initial Order to immediately reduce the eligibility cap,the Idaho
PUC declared that its decision on the request to reduce the published avoided cost eligibility
cap shall become effective on December 14,2010.”Exhibit 1 at 6 (emphasis added).4
Based upon the developed record,the Idaho PUC found that the Utilities made a
convincing case”to temporarily •‘reduce the eligibility cap for published avoided cost rates
from 10 aMW to 100 kW for wind and solar [QFsl only while the PUC further investigates”the
other avoided cost issues.5 Exhibit 2 at 9 (emphasis original).Consistent with the Order opening
the docket,the Idaho PUC ordered that the eligibility cap for published avoided cost rates be
reduced “from 10 aMW to 100 kW for wind and solar resources only,effective December 14,
2010.”Exhibit 2 at 10,11-12.Cedar Creek did not petition for reconsideration (Idaho Code §
61-626)and the decision to reduce the cap to 100 kW effective December 14,2010 was affirmed
on reconsideration.6 No party,including Cedar Creek,sought judicial review from the Idaho
Supreme Court.Idaho Code §61-627.
In the second PURPA proceeding initiated on January 10,2011 (the ‘Contracts
Case”),Rocky Mountain filed five 20-year Firm Energy Sales Agreements (“Agreements”or
“Contracts”)entered into by itself and Cedar Creek.These five Agreements are the subject of
Cedar Creek’s present Petition before the Commission.The five wind projects self-certified as
The Idaho PUC’s Order No.32131 also stated in the “Order Section”that:“IT IS FURTHER ORDERED that the
[PUC’s]decision regarding whether to reduce the published avoided cost eligibility cap become[sj effective on
December 14,2010.”Exhibit I at 9 (capitals original).
Idaho PUC Order No.32176 at 9 (Feb.7,2011),287 P.U.R.4th 316,2011 WL 490884 (Idaho PUC)(attached as
Exhibit 2).
6 Idaho PUC Order No.32212 at 15-16 (March 28,2011),2011 WL 1210463 (Idaho PUC)(attached as Exhibit 3).
IDAHO PUC ANSWER 3
“qualifying facilities”(QFs)under PURPA,7 Each of the five Agreements was executed by both
Cedar Creek and Rocky Mountain and submitted to the Idaho PUC for review.
The five Agreements are nearly identical and each Agreement requests the published
avoided cost rates applicable to Rocky Mountain.8 Each Agreement expressly states that the
‘Effective Date’S of the Agreement is “after execution by both Parties and after approval by the
Commission.”Exhibit 4 at ¶f 1.13,2.1.It is undisputed that Cedar Creek signed the
Agreements on December 13,2010,and Rocky Mountain signed on December 22,2010.
Petition at 6;Exhibit 7 at 9.
After Rocky Mountain filed the five Agreements,the Idaho PUC issued a
consolidated public Notice and Order requesting written comments on the Agreements.9 In
Cedar Creek’s initial comments,it urged the Idaho PUC to approve the Agreements.Exhibit 6 at
1,6,11.Rocky Mountain urged the Idaho PUC to either accept or reject the Agreements,while
the Idaho PUC Staff recommended that the Idaho PUC not approve the Agreements.Exhibit 7 at
1,5-6.The Idaho PUC in final Order No.3 2260 declared that “the primary issue to be
determined in these cases is whether the Agreements ...were executed before the eligibility cap
for published rates was lowered to 100 kW on December 14,2010,for wind and solar projects.”
Exhibit 7 at 9 (emphasis added).Based upon the record,the Idaho PUC issued final Order No.
32260 on June 8,2011,declining to approve the five Agreements because the 10 aMW published
avoided cost rate contained in the Agreements was no longer available because the published rate
Petition at n.6.
8 The substantive terms of the five Agreements are nearly identical except for nameplate capacity but each of thefiveprojectsiscontractuallyobligatedtooperateat“10 aMW/Month or less.”Because the Agreements arevoluminousandnearlyidentical,the Idaho PUC has attached the first of the five Agreements as Exhibit 4 asrepresentativeofeachAgreement.See Exhibit 7 at 3-5.
Idaho PUC Order No.32192)(Feb.24,2011)(Case No.PAC-E-l 1-01),2011 WL 696922 (Idaho PUC)(attached
as Exhibit 5)see also Idaho PUC Order No.32260 at 3,2011 WL 2686552 (Idaho PUC)(attached as Exhibit 7).
IDAHO PUC ANSWER 4
eligibility cap had been reduced to 100 kW as of December 14,2010.Id.at 9-10.On July 27,
2011,the Idaho PUC on reconsideration affirmed its prior decision not to approve the
Agreements.IPUC Order No.32302 (attached as Exhibit 8).
The Idaho PUC Orders that are the subject of Cedar Creek Wind’s Petition —Idaho
PUC’s Order No.32260 (issued June 8.2011)and its denial of reconsideration in Order No.
32302 (issued July 27,2011)—determine the application of Idaho’s adjusted eligibility cap for
published avoided cost rates,as to which no party sought judicial review,to five specific
contracts.Each of those contracts specifically provides that it becomes effective only after
execution by both parties and after approval by the Idaho PUC.Exhibit 4 at ¶f 1.13,2.1
(emphasis added).The Commission has consistently held that the determination as to when and
under what circumstances a legally enforceable obligation arises for purposes of Section
304(d)(2)of the PURPA regulations (18 C.F.R.§292.304(d)(2))is the province of state
regulation,and does not implicate the Commission’s enforcement authority under PURPA
Section 210(h).’°Cedar Creek Wind’s Petition provides no reason for the Commission to
deviate from that long-settled position.
0 New PURPA Section 2 10(m)Regulations Applicable to Small Power Production and Cogeneration Facilities,
Order No.688,FERC Stats.&Regs.¶31,233 at P 212 (2006)(“Accordingly,the Commission views the term
“obligation”as a “legally enforceable obligation”which is established through a state’s implementation ofPURPA”),order on rehg,Order No.688-A,FERC Stats.&Regs.¶31,250 at P 137 (2007)(“The Commission
clarifies that the date on which an ‘obligation’under PURPA is established is the date such obligation is established
by each state regulatory authority”),afj’d sub nom.American Forest and Paper Association i’.FERC,550 F.3d
1179,384 U.S.App.D.C.73 (D.C.Cir.2008);Jersey Central Power &Light Co.,73 FERC ¶61,092 at pp.61,297-61,298 (1995)(“It is up to the States,not this Commission,to determine the specific parameters of individual QFpowerpurchaseagreements,including the date at which a legally enforceable obligation is incurred under State law.
Similarly.whether the particular facts applicable to an individual QF necessitate modifications of other terms andconditionsoftheQF’s contract with the purchasing utility is a matter for the States to determine.This Commission
does not intend to adjudicate the specific provisions o1indiidual QF contracts,
IDAHO PUC ANSWER 5
II.CORRESPONDENCE AND COMMUNICATIONS
All correspondence and communications concerning the above-captioned proceeding
should be addressed to the following persons:11
Donald L.Howell,II (ISB #3366)John P.Coyle
Kristine A.Sasser (ISB #6618)Special Deputy Attorney General
Deputy Attorneys General Duncan &Allen
Idaho Public Utilities Commission 1575 Eye Street,N,W.,Suite 300
472 West Washington (83702-5918)Washington,DC 20005-1175
P0 Box 83720 Telephone:[phone]
Boise,Idaho 83720-0074 Fax:[phone]
Telephone:[phone] E-mail:jpc(duncana1len.corn
[phone]
Fax:[phone]
E-mail:don.howell(dpuc,idaho.gov
[e-mail]
III.BACKGROUND
A.The Idaho PUC
The Idaho PUC is the state regulatory agency empowered pursuant to state law to
regulate public utilities operating within Idaho.Idaho Code §61-129,61-501.Rocky
Mountain,Cedar Creek’s counterpartv in connection with the five contracts involved in Cedar
Creek’s Petition,is an electric public utility subject to the regulatory jurisdiction of the Idaho
PUC.Idaho Code §61-1 19.The Idaho PUC has been granted authority to implement PURPA
and is the appropriate state forum to review contracts and resolve disputes between QFs and
electric utilities.Idaho Code §61-502,61-503;AW Brown v.Idaho Power,121 Idaho 812,
816,828 P.2d 841,845 (1992);Empire Lumber Co.v.Washington Water Power Co.,114 Idaho
191,755 P.2d 1229 (1987).The Idaho PUC has the authority to engage in case-by-case analysis
in setting out its standards and requirements for implementation of PURPA.Power Resources
The Idaho PUC requests waiver of Procedural Rule 203(b)(3),18 C.F.R.§385.203(b)(3),to the extent necessary
to permit more than two persons to be included on the official service list on its behalf in this proceeding.
IDAHO PUC ANSWER 6
Group v.PUC of Texas,422 F.3d 231,237 (5th Cir.2005)citing Policy Statement Regarding the
Commission’s Enforcement Role Under Section 210 of [PURPA],23 FERC ¶61,304,1983 WL
39627 (May 31,1983);Rosebud Enterprises v.Idaho PUC,128 Idaho 609,917 P.2d 766 (1996).
The PUC establishes avoided cost rates,sets eligibility standards/caps for the
published avoided cost rates,and resolves disputes between QFs and electric utilities.A.W.
Brown v.Idaho Power Co.,121 Idaho 812,816,828 P.2d 841,845 (1992);AJion Energy v.
Idaho Power Co.,107 Idaho 781,785,693 P.2d 427,431 (1984);Rosebud Enterprises v.Idaho
PUC,128 Idaho 624,627-28,917 P.2d 781,784-85 (1996);18 C.F.R.§292.401(a)(1980).The
Idaho PUC recognizes that a QF can lock-in an avoided cost rate by either of two methods:(1)
entering into a signed contract with the utility;or (2)filing a meritorious complaint with the
Idaho PUC alleging that a “legally enforceable obligation”has arisen and but for the conduct of
the utility,there would be a contract.Rosebud Enterprises v.Idaho PUC,131 Idaho 1,951 P.2d
521 (1997).
B.The Eligibility Cap Case
As noted above,the Eligibility Cap Case was the first of two PURPA proceedings
before the Idaho PUC.In IPUC Case No.GNR-E-10-04,the three Utilities filed a Joint Petition
on November 5,2010,requesting the Idaho PUC to initiate a generic investigation to address
various avoided cost issues.Exhibits 1-3.While the avoided cost investigation is underway,the
Utilities also requested that the Idaho PUC “lower the published avoided cost rate eligibility cap
[for all QFsI from 10 aMW to 100 kW to be effective immediately...“Id.
On December 3,2010,the Idaho PUC issued its Order and Notice initiating the
investigation.Exhibit 1.The Idaho PUC observed that Idaho Power asserted that it could have
1,100 MW of wind power generation on its system in the near-term that would exceed the
IDAHO PUC ANSWER 7
minimum load experienced on Idaho Power’s system [in 2010].”Id.at 2.12 In addition,Idaho
Power maintained that it had over 80 MW of QF wind generation pending approval at the Idaho
PUC and more than 507 MW of new QF wind contracts requested.Exhibit 9 at 3-4.Likewise,
Rocky Mountain claimed that it had 64 MW of wind contracts executed (although none have
achieved commercial operation)and another 358 MW of proposed standard wind QF contracts
pending.Id.at 4;Exhibit 2 at 2.The Idaho PUC noted the Utilities insisted in their Joint
Petition that many Idaho wind QF projects are “large,utility-scale wind farms that are broken up
into 10 aMW increments in order to qualify for the published [avoided]cost rates.”Exhibit 1 at
2.The Utilities further asserted that it is “commonplace”for wind developers to aggregate six or
more projects totaling 100 to 150 MW of nameplate rating,with the projects all sharing
interconnected facilities to one common utility delivery point.Exhibit 9 at 5;Exhibit 2 at 2.On
November 10,2010 (five days after the Utilities filed their Joint Petition),Cedar Creek
petitioned and was subsequently granted intervention in the Eligibility Cap Case.Exhibit 8 at
14;Exhibit I at 5,8-9.
In granting the Utilities’request to initiate an investigation of avoided cost issues,the
Idaho PUC said it would first take up the issue of whether to reduce the eligibility cap for the
published avoided cost rates.Exhibit 1 at 5.When the Idaho PUC initiated its eligibility cap
investigation,the eligibility cap for the published avoided cost rates was set at 10 aMW.’3
Avoided cost rates for purchases from QFs generating more than the eligibility cap for the
published avoided cost rates must be individually negotiated by the QF and the utility.In a
2 In calculating its potential wind generation,Idaho Power calculated that it currently has more than 208 MW
nameplate capacity of wind generation on its system and an additional 264 MW nameplate capacity of PUC
approved QF wind contracts.Exhibit 2 at 2.
3 Supra note 4.
IDAHO PUC ANSWER 8
negotiated QF contract,the utility’s published avoided cost rates are the starting point for rate
negotiations.Exhibit 2 at 1,9.
Although it initiated the generic investigation,the Idaho PUC declined the Utilities’
request to immediately reduce the eligibility cap to 100 kW.Instead,the Idaho PUC requested
that interested persons and parties file written comments and written reply comments.Id,at 7;
Exhibit I at 5-6.’In addition,the Idaho PUC conducted an oral argument on January 27,2011.
Id at 7.The Idaho PUC expressly stated that its decision regarding the reduction in the
published avoided cost eligibility cap “shall become effective on December 14,2010.”Jd.at 5-
6,9.
Based upon an extensive written record and the oral argument,the Idaho PUC issued
its final Order No.32176 in the Eligibility Cap Case on February 7,2011.In its final Order,the
Idaho PUC found:
a convincing case has been made to temporarily reduce the eligibility cap for
published avoided cost rates from 10 aMW to 100 kW for wind and solar only
while the [Idaho PUC]further investigates the implications of disaggregating
QF projects.We maintain the eligibility cap at 10 aMW for QF projects other
than wind and solar (including but not limited to biomass,small hydro,
cogeneration,geothermal,waste-to-energy).
Wind and solar resources present unique characteristics that differentiate them
from other PURPA QFs.Wind and solar generation,integration,capacity and
ability to disaggregate provides a basis for distinguishing the eligibility cap
for wind and solar from other resources.Furthermore,these intermittent
resources must be “firmed”by ancillary services to assure system reliability.
Temporarily reducing the eligibility cap for wind and solar [QFsJ while we
continue our investigation,will still allow wind and solar projects larger than
100 kW to negotiate avoided cost rates using the [established Integrated
Resource Plan (IRP)]Methodology.
‘The Idaho PUC requested written comments regarding three issues:(I)the advisability of reducing the published
avoided cost eligibility cap;(2)if the cap is reduced,the appropriateness of exempting non-wind QF projects from
the reduced eligibility cap;and (3)the consequences of dividing large wind projects into 10 aMW projects to utilize
the published rate.Exhibit I at 5.
IDAHO PUC ANSWER 9
Lowering the cap to 100 kW does not change the published avoided cost rates
established in Order No.31025 (March 16,2010).The published rate for
wind and solar QFs will still be available for projects 100 kW or smaller and
as we have previously stated,will be the starting point for negotiating an
avoided cost rate for larger wind and solar projects.
Exhibit 2 at 9 (emphasis original and footnote omitted).The Idaho PUC recognized that the
Commission granted it the discretion to set the published rate eligibility cap at a level higher than
100 kW.Id.citing 18 C.F.R.§292.304(c).Because Cedar Creek was a party to the case it had
actual notice that the eligibility cap was subject to change and that any change would become
effective on December 14,2010.Exhibit I at 8-9;see also Exhibit 8 at 13.
Cedar Creek neither petitioned the idaho PUC to reconsider its final Eligibility Cap
Case Order,nor appealed the reduction in the eligibility cap to the Idaho Supreme Court.
C.The Five Cedar Creek Contracts Case
On January 10,2011,Rocky Mountain filed the five Cedar Creek Agreements for the
Idaho PUC’s review.Under the terms of the Agreements,each wind project agrees to sell
electric energy to Rocky Mountain for a 20-year term using the 10 aMW non-levelized published
avoided cost rates.Exhibit 5 at 20.’Rocky Mountain declared that the Agreements comport
with the terms and conditions of the various Idaho PUC Orders applicable to PURPA agreements
forawind resource.Exhibit 7 at 3-4 citing IPUC Order Nos.30415,30488,30738 and 31025.
In the Agreements,Oct ober 1,2012 was selected as the Scheduled Commercial
Operation Date.Exhibit 7 at 4.Rocky Mountain asserted that various requirements have been
placed in the Agreements regarding Rocky Mountain’s acceptance of the projects’energy
deliveries.Rocky Mountain asserted that it has advised each project of the project’s
5 Three of the projects each have a maximum nameplate capacity of 27.6 MW,while the remaining two have a
maximum nameplate capacity of 25.2 MW,or a cumulative total of 133.2 MW.Exhibit 7 at 3.Under normal
and/or average conditions,each project will not generate more than 10 aMW on a monthly basis.Exhibit 5 at 2;
Exhibit 7 at 3.
IDAHO PUC ANSWER 10
responsibility to work with Rocky Mountain’s transmission unit to ensure that sufficient time
and resources will be available for delivery to construct the interconnection facilities,and
transmission upgrades if required,in time to allow each project to achieve its October 1,2012,
Scheduled Commercial Operation Date.Id.
The Agreements provide that delays in the interconnection or transmission process do
not constitute excusable delays and if a project fails to achieve its Scheduled Commercial
Operation Date delay damages will be assessed.Exhibit 7 at 4.The parties to the Agreements
each agreed to delay liquidated damages and security provisions.Exhibit 4 at ¶J 2.5.1,11.1.2.
By their own terms,the Agreements were not to become effective until “fi
execution by both Parties and after”the Idaho PUC has approved all of the terms and conditions.
Exhibit 4 at ¶2.1 (emphasis added).Paragraph 2.1 further provided that all payments made by
Rocky Mountain to the projects for purchases of energy “are just and reasonable,in the public
interest,and that the costs incurred by [Rocky Mountain]for purchases of capacity and energy
from [Cedar Creek]are legitimate expenses,all of which the Commission will allow [Rocky
Mountain]to recover in rates in Idaho in the event other jurisdictions deny recovery of their
proportionate share of said expenses.”Exhibit 4 at ¶}1.13,2.1;Exhibit 7 at 4.
On February 24,2011,the Idaho PUC issued a public Notice and Order requesting
initial and reply written comments.Exhibit 5.Comments were filed by the Idaho PUC Staff,
Rocky Mountain,Cedar Creek and other interested persons.Cedar Creek urged the Idaho PUC
in its initial comments to approve the Agreements.Exhibit 6 at 1.In its comments,the Idaho
PUC Staff calculated that the five projects collectively are expected to generate 375,503 MWb
annually.Under the published non-levelized rates in the Agreements,PUC Staff calculated that
IDAHO PUC ANSWER 11
the annual energy payments by Rocky Mountain to Cedar Creek will total approximately $685.4
million over the 20-year term of the Agreements.Exhibit 7 at 5.
In its final Order No.32260,the Idaho PUC declared that “a thorough review is
appropriate and necessary prior to signing QF Agreements that obligate ratepayers to payments
in excess of $685 million over the 20-year term of these Agreements.Exhibit 7 at 8.Indeed,the
Commission has directed the utilities to assist the Commission in its gatekeeping role when
reviewing QF contracts.”Id.
The Idaho PUC found that the Agreements were not fully-executed (signed by both
parties)prior to December 14,2010.Exhibit 7 at 9•16 The Idaho PUC made specific note of the
fact that each Agreement stated that “the ‘effective date’of the Agreement is ‘after execution by
both parties and after approval by the Commission.”Id.citing Exhibit 4 at ¶J 1.13,2.1
(emphasis added).The Idaho PUC also observed that the opening paragraph of each Agreement
states that the Agreement is “entered into this 22n day of December,2010.”Id.citing Exhibit 4
at 1.“Thus,on the date the five Agreements became effective [i.e.,December 22,20101,
published avoided cost rates were available only to wind and solar projects with the design
capacity of 100 kW or less.”Exhibit 7 at 9.Because the size of each Cedar Creek project
exceeds 100 kW,the Idaho PUC found that the terms of the Agreements did not comply with
Order No.32176.Consequently,the Idaho PUC disapproved the contracts.
The Idaho PUC concluded that “it is not in the public interest to allow parties with
contracts executed on or after December 14,2010,to avail themselves of an eligibility cap that is
6 Rocky Mountain also stated in its reply comments that when Cedar Creek delivered the signed Agreements to
Rocky Mountain’s Portland,Oregon office “late on the afternoon of December 13,2010[,j Cedar Creek Wind did
not deliver final conformed exhibits for each [Agreementj until December 14,2010.”Exhibit 10 at 3-4.After the
Agreements were delivered,Rocky Mountain “identified discrepancies in several of the [Agreements’exhibits
which were corrected and confirmed by Cedar Creek Wind on December 16,2010.”Id.at 4.
IDAHO PUC ANSWER 12
no longer applicable.”Exhibit 7 at 917 The PUC also observed that wind QF projects larger
than 100 kW are still entitled to PURPA contracts using the Integrated Resource Plan (IRP)
Methodology to derive the utility’s avoided costs.Id.at 10.The IRP Methodology ‘recognizes
the individual/generation characteristics of each [QF]project by assessing when the QF is
capable of delivering its resource against when the utility is most in need of such resources.The
resultant pricing is reflective of the value of QF energy to the utility.”Id.at 3.
On June 29,2011,Cedar Creek filed a Petition for Reconsideration.Cedar Creek
alleged that the Idaho PUC’s Order No.32260 (Exhibit 7)was erroneous,departed from past
precedent and violated both federal and state law.Cedar Creek alleged that its Agreements
should be approved because a legally enforceable obligation existed prior to December 14,2010.
Consequently,Cedar Creek urged the Idaho PUC to reverse its final Order No.32260 “and
expeditiously approve the Agreements as submitted.”Cedar Creek Petition,Exhibit 7 at 3.
On July 27,2010,the Idaho PUC issued its Order No.32302 denying Cedar Creek’s
Petition for Reconsideration.Exhibit 8.The Idaho PUC specifically noted that “[aiccording to
the FERC.‘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.”Exhibit 8 at 8 citing Rosebud Enterprises v.Idaho PUC,128 Idaho
609,623-624,917 P.2d 766,780-781 (1996)citing West Penn Power Co.,71 FERC ¶61,153
(1995).The Idaho PUC determined that the parties’Agreements themselves specified the date
upon which the legally enforceable obligation began —the date that the Agreements were
Attached to its Petition as “Exhibit 9”is Cedar Creek’s reply to Rocky Mountain’s answer on reconsideration in
the Agreements proceeding before the Idaho PUC.Petition at 8,n.16.The PUC ruled that Cedar Creek submitted
its reply (Exhibit 9)after the close of the PUC record,Moreover,the Idaho PVC’s Procedural Rule 331 does not
provide for parties to reply to answers.Idaho APA 31.01.01.331.The Idaho PVC did not consider Cedar Creek’s
arguments in its reply to Rocky Mountain’s answer.Exhibit 8 at 2-3.Consequently,the Commission should
likewise disregard Cedar Creek’s Exhibit 9.Rule 213,18 C.F.R.§385.213(a)(2).
IDAHO PUC ANSWER 13
executed by both parties —December 22,2010.Exhibit 8 at 4.6,8-9,16.The Idaho PUC also
declared that its findings were in the public interest.Exhibit 8 at 9.Specifically,“[a]llowing a
project to avail itself of an eligibility cap (and therefore published rates)that is no longer
applicable could cause ratepayers to pay more than the utility’s avoided cost....“Id.at 12.The
Idaho PUC noted that this result would be a direct violation of PURPA.
The Idaho PUC further explained that Rocky Mountain’s comprehensive review of
the terms of the Agreements prior to signing “is consistent with [the PUC’s]directive to utilities
that they assist the [PUC1 in its gatekeeper role when reviewing QF contracts.”Exhibit 8 at 10.
The public interest requires that each party have a full and final review of the contract before
signing and obligating the utility and its ratepayers to hundreds of millions of dollars in
payments.Id The Idaho PUC determined that the time each party took to review the
Agreements prior to signing was reasonable.
The Idaho PUC rejected Cedar Creek’s argument that it met grandfathering criteria
and should,therefore,be eligible for published avoided cost rates despite the fact that its projects
were expected to generate more than 100 kW each.The Idaho PUC reasoned that each
grandfathering case presents a specific set of facts and ‘“we look at the totality of the facts’in
assessing entitlement to grandfathering status.”Exhibit 8 at 11 citing Idaho PUC Order No.
29954.Moreover,the Idaho PUC held that it is “not so rigorously bound by the doctrine of stare
decisis that [itj must decide all future cases in the same way as [itj has decided similar cases in
the past.”Id.at 11 citing Rosebud Enterprises,128 Idaho at 618,917 P.2d at 775.As long as
the Idaho PUC enters sufficient findings to show that its actions are not arbitrary and capricious,
the Idaho PUC may alter its decisions.id.at 12 citing Washington Water Power v,Idaho PUC,
101 Idaho 567,579,617 P.2d 1242,1254 (1980).
IDAHO PUC ANSWER 14
The Idaho PUC also rejected Cedar Creek’s argument regarding notice of the change
in the eligibility cap and application of the 100 kW standard for QF wind and solar projects.The
Idaho PUC found that Cedar Creek,as a party to the Eligibility Cap Case,was provided actual
notice that the eligibility cap was subject to change and that any change would become effective
on December 14,2010.Exhibit 8 at 13-14.Finally,because Cedar Creek did not seek
reconsideration or otherwise appeal the Idaho PUC’s final decision to reduce the eligibility cap
for published avoided cost rates effective December 14,2010,the Idaho PUC found that Cedar
Creek was prohibited from raising the notice issue again.Id.at 14-15.Cedar Creek’s notice
arguments represent an impermissible collateral attack of the Idaho PUC’s final Order.Idaho
Code §61-625;Utah-Idaho Sugar Co.v.Intermountain Gas Co..100 Idaho 368,373.597 P.2d
1028,1063 (1979).
IV.ARGUMENT
A.Cedar Creek ‘s Petition attempts an impermissible collateral attack on the Idaho
PUC ‘s eligibility cap Orders.
In its Petition,Cedar Creek correctly notes that the Idaho PUC issued its Notice and
Order in the Eligibility Cap Case (GNR-E-l0-04)on December 3,2010.Petition at 5.Cedar
Creek also notes that the Idaho PUC in its Order No.32131 (Exhibit 1)put parties on notice that
“our decision regarding the [Utilities’request]to reduce the published avoided cost eligibility
cap [from 10 aMW to 100 kW]shall become effective on December 14,2010.”Exhibit I at 5.
However,Cedar Creek argues it took six months for the Idaho PUC to announce that the
reduction in the eligibility cap from 10 aMW to 100 kW was applicable to wind and solar QFs on
December 14,2010.Petition at 5 (emphasis original).Cedar Creek goes on to state in footnote
10 that the Idaho PUC “implemented the eligibility cap [reduction]on a final basis on June 8,
IDAHO PUC ANSWER 15
2011.”Citing Idaho PUC Order No.32262,Case No.GNR-E-1 1-01.This is a gross distortion
of the facts.In fact,the Idaho PUC’s final Order No.32176 in the Eligibility Cap Case was
issued about two months later on February 7.2011.after receiving written comments and
conducting oral argument.Based upon its review of the written comments and oral argument,
the Idaho PUC declared that it was temporarily reducing the eligibility cap for published
avoided cost rates from 10 aMW to 100 kW for wind and solar resources only,effective
December 14,2010.”Exhibit 2 at 9,10,11-12.See also Exhibit 1 at 6,9;Exhibit 3 at 15,16;
Exhibit 8 at 12-15.This finding is unambiguous.
Cedar Creek further maintains that the eligibility cap became final in yet a third Idaho
PUC PURPA case,IPUC Case No.GNR-E-11-01.Petition at n.10.This assertion is without
merit and contrary to the facts.IPUC Case No.GNR-E-11-0I was the second phase of the Idaho
PUC’s generic investigation into avoided cost issues.More specifically,this phase of the Idaho
PUC’s inquiry was intended “to investigate the disaggregation of large wind projects into smaller
projects in order to obtain published avoided cost rates that exceed a utility’s actual avoided
cost.”The Idaho PUC described the GNR-E-1 1-01 case as “phase two of the generic PURPA
investigation.”Order No.32262 at 3 (June 8,2011),2011 WL 2286336*2 (Idaho PVC).In the
GNR-E-11-01 case,the Idaho PUC concluded that it was appropriate to continue the 100 kW
eligibility cap for wind QFs already established in the GNR-E-10-04 case (Exhibits 1-3).Id.at
1,2011 WL 2286336 at *1.Cedar Creek did not petition for reconsideration or otherwise appeal
the Idaho PUC’s final Order in the GNR-E-ll-01 case.
Cedar Creek did not seek reconsideration about the reduction of the eligibility cap.’8
Under Idaho law,which applies the same preclusion principle found in Section 313(b)of the
8 Although another party did seek reconsideration and requested the Idaho PUC to reinstate the eligibility cap at 10
aMW,the Idaho PUC rejected that request.Exhibit 3 at 15.
IDAHO PUC ANSWER 16
Federal Power Act (16 U.S.C.§8251(b)),Cedar Creek is barred from seeking judicial review of
the Idaho PUC’s decision to lower the eligibility cap.Idaho Code §61-625;Eagle Water Co.v.
Idaho PUC,130 Idaho 314,940 P.2d 1133 (1997)(“Issues not raised in a petition for
reconsideration will not be considered by [the Idaho Supreme Court].”);see also McNeal v.
Idaho PUC,142 Idaho 685,132 P.3d 442 (2006).Because no party appealed the Idaho PUC’s
100 kW decision to the Idaho Supreme Court,the Idaho PUC’s decision to implement the change
in eligibility cap on December 14,2010,became final and conclusive and not subject to
collateral attack.See Idaho Code §61-625.Cedar Creek’s arguments regarding notice of a
change to the eligibility cap and application of that standard are a belated collateral attack on the
final Orders issued by the Idaho PUC in the Eligibility Cap Case (GNR-E-10-04).Cedar Creek
cannot revive its attack on the Idaho PUC’s decision to reduce the eligibility cap by disputing it,
either in subsequent PUC cases or before this Commission.Public Serv.Co.of New Hampshire
v.New Hampshire Elec.Coop.,Inc.(“PSNH”),83 FERC ¶61,224 at 62,001 (1998)(“In
essence,PSNH is requesting that this Commission bring an action in federal district court
pursuant to Section 21 0(h)(2)of PURPA against the New Hampshire Commission for violating
PURPA.We decline to do so.”);New York State Electric &Gas Corp.,71 FERC ¶61,027 at
61,117 (1995)(FERC relief not available where purchasing utility “chose not to appeal the New
York Commission’s orders mandating the agreements.”).
B.The Idaho PUC correctly treated contracts as legally enforceable obligations.
Cedar Creek maintains that the Idaho PUC’s “substitution of a ‘fully executed
contract’standard for a ‘legally enforceable obligation’in implementing PURPA is prohibited
both by the plain language of the regulations,and the Commission’s interpretation of those
regulations.”Petition at 10.Cedar Creek cites JD Wind],129 FERC ¶61,148 (Nov.19,2009),
IDAHO PUC ANSWER 17
in support of its argument that the phrase “legally enforceable obligation’was adopted expressly
to prevent a utility from being able to circumvent PURPA’s requirements simply by failing or
refusing to sign a contract with the QF.”Petition at 10-11 (emphasis added).
Cedar Creek’s overwrought argument manages to ignore that this is precisely the
point in the present proceedings.A contract existed between Cedar Creek and Rocky Mountain.
Cedar Creek initially urged the Idaho PUC to approve the Agreements and did so again on
reconsideration.Exhibit 6 at 1;Cedar Creek Exhibit 7 at 3 (the PUC should “expeditiously
approve the Agreements as submitted.”).Within the terms of the Agreements,an effective date
was specified.Each of the five Agreements state that the “Effective Date”of the Agreement is
“after execution by both Parties and after approval by the Commission.”Exhibit 4 atf 1.13,2.1
(emphasis added).The Commission’s regulations provide and Cedar Creek does not dispute that
the avoided costs are “calculated at the time the obligation is incurred.”18 C.F.R.§
292.304(d)(2)(ii).By the terms of the Agreements,the obligation was incurred when the
Agreements were signed by both parties.Exhibit 4 at ¶J 1.13,2.1.
Cedar Creek’s argument that “if a legally enforceable obligation arose only upon the
signature of the utility,there would be nothing for state commissions to determine as to the issue
and nothing for the Commission to have deferred to the state commissions in the first instance”
misses the point entirely.The Commission stated it succinctly in JD Wind 1:
Thus,under our regulations,a QF has the option to commit itself to sell all or
part of its electric output to an electric utility.While this may be done through
a contract,if the electric utility refuses to sign a contract,the QF may seek
state regulatory authority assistance to enforce the PURPA-imposed
obligation on the electric utility to purchase from the QF,and a non-
contractual,but still legally enforceable,obligation will be created pursuant
to the state ‘s implementation of PURPA.Accordingly,a QF,by committing
itself to sell to an electric utility,also commits the electric utility to buy from
the QF;these commitments result either in contracts or in non-contractual,
but binding,legally enforceable obligations.
IDAHO PUC ANSWER 18
JD Wind 1.129 FERC ¶61,148 at 61,633 (emphases added).The Commission determined that,
regardless of whether the energy offered was firm or non-firm power,the QF was entitled to a
legally enforceable obligation in that case.Because the utility in JD Wind was refusing to enter
into a contract with the QF.the Commission determined that the QF was entitled to a non-
contractual,but binding,legally enforceable obligation to sell power to the utility.The
Commission reiterated its conclusions on reconsideration.JD Wind 1,130 FERC ¶61,127 at
61,628.
In contrast to the situation presented in the JD Wind case,the five Cedar Creek
projects all had Agreements with the utility.The Idaho PUC did not substitute a “fully executed
contract”standard in place of a “legally enforceable obligation.”The Commission specifically
created the distinction between the concepts.The Commission’s regulations,18 C.F.R.§
292.304(d),allow QFs to provide energy to utilities either by entering into a contract or pursuant
to a non-contractual,but nevertheless binding,legally enforceable obligation if the utility is
refusing to contract.JD Wind],129 FERC ¶61,148.
Given that the five contracts exist,there is no need for a determination of when or
whether a legally enforceable obligation arises.The contracts themselves are evidence of the
legally enforceable obligation.The terms of the obligation are spelled out in detail in the
Agreements.Cedar Creek and Rocky Mountain agreed that the effective date of the Agreements
would be after execution by both parties and after approval by the Idaho PUC.Exhibit 4 at ¶J
.13,2.1 (“this Agreement shall become effective after execution by both Parties and after
approval by the [Idaho PUC].”).It is undisputed that Cedar Creek signed on December 13,
20l0.’Rocky Mountain signed on December 22,2010.20 Exhibit 7 at 7,9,10;Exhibit 8 at 6,8-
°Supra n.i 6 see also Exhibit 7 at 7.
IDAHO PUC ANSWER 19
9.11,16.The Idaho PUC did not approve the Agreements.2’The Idaho PUC’s finding as to the
contracts’effective date is consistent with the express terms of the Agreements.Cedar Creek
cannot now argue against terms that are included in its contracts simply because those terms do
not provide it with a favorable outcome.
The Idaho PUC’s decision that a legally enforceable obligation was incurred upon the
execution of the Agreements between the parties is consistent with its authority delegated by
PURPA and the Commission’s regulations.Because the contracts exist,the Idaho PUC made its
findings based on the express terms of the Agreements.This determination was made pursuant
to the authority granted to the Idaho PUC by the Commission:
It is up to the States,not this Commission,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.Similarly,
whether the particular facts applicable to an individual QF necessitate
modifications of other terms and conditions of the QF’s contract with the
purchasing utility is a matter for the States to determine.This Commission
does not intend to adjudicate the specific provisions of individual QF
contracts.
West Penn Power Co.,71 FERC ¶61,153 at 61,495 (1995).Accord:Jersey Central Power &
Light Co.,73 FERC ¶61,092 at 61,297-61,298 (1995);Metropolitan Edison Co..72 FERC ¶
61,015 at 61,050 (1995).Moreover,the Idaho PUC determined that it was not in the public
interest to approve the Agreements.Specifically,the Idaho PUC found that “allowing a project
to avail itself of an eligibility cap (and therefore published rates)that is no longer applicable
could cause ratepayers to pay more than the utility’s avoided cost.”Exhibit 8 at 9.For the Idaho
PUC to approve a rate in excess of the utility’s avoided cost would clearly be a violation of
20 Rocky Mountain explained its QF contract review process in its reply comments filed April 12,2011 (attached as
Exhibit 10).Rocky Mountain asserted that it acted with “reasonable speed to execute the [Agreements]given the
number of documents and complexity of review of the multiple transactions requested by Cedar Creek Wind.”
Exhibit 10 at 2-3.
21 Pursuant to the express terms of the Power Purchase Agreements,it can be argued that the Agreements were never
effective because they never received Idaho PVC approval.
IDAHO PUC ANSWER 20
PURPA and the Commission’s implementing regulations.A.W Brown,121 Idaho 812,818,828
P.2d 841,847 (1992).
C.The PUC appropriately declined grandfathering in this case.
Cedar Creek notes the Idaho PUC had,in earlier and fact-specific situations,relied on
grandfathering criteria to allow QFs to avail themselves of vintage published avoided cost rates.
As the Idaho PUC explained in its final Order on Reconsideration No.32302,Cedar Creek’s
reliance on grandfathering criteria is misplaced.Exhibit 8 at 11-12.The Idaho PUC observed
that the Idaho Supreme Court has stated that ‘[c]onferment of grandfathered status on [a]
qualifying facility is essentially an IPUC finding that a legally enforceable obligation to sell
power existed by a given date.Such a finding is within the discretion of the stale regulatory
agency.”Id.at 11 (emphasis in Order)quoting Rosebud Enterprises v.idaho PUC,128 Idaho
609,624,917 P.2d 766,781 (1996).The Idaho PVC previously found that the Agreements
between Cedar Creek and Rocky Mountain were executed,and therefore a legally enforceable
obligation was incurred,on December 22,2010.Consequently,there was no reason to resort to
the use of grandfathering criteria.Id at 11.Moreover,the Idaho PUC found that allowing
Cedar Creek to utilize an eligibility cap that is no longer effective would be contrary to the
public interest.Exhibit 8 at 12;18 C.F.R.§292.304(a)(1)(i)(“Rates for purchase shall:(i)Be
just and reasonable to the electric customer of the electric utility and in the public interest..
The Commission has acknowledged that “the QF industry is now a developed
industry and the need for integration of policy objectives under PURPA and other federal electric
regulatory policies is pronounced.”Southern Cal.Edison Co.,San Diego Gas &Electric,70
FERC ¶61,215 at 61,675 (1995).The Commission further stated that
as the electric utility industry becomes increasingly competitive,the need to
ensure that the States are using procedures which ensure that QF rates do not
IDAHO PUC ANSWER 21
exceed avoided cost becomes more critical.This is because QF rates that
exceed avoided cost will,by definition,give QFs an unfair advantage over
other market participants (non-QFs).This,in turn,will hinder the
development of competitive markets and hurt ratepayers.a result clearly at
odds with ensuring the just and reasonable rates required by PURPA section
210(b).
Id.at 61,675-61,676.These considerations by the Commission are situations that the Idaho
PUC is currently being faced with in Idaho.The Idaho PUC’s decision to not utilize
grandfathering criteria was a reasonable exercise of its discretion.Rosebud Enterprises,128
Idaho at 624,917 P.2d at 781.The Idaho PUC determined that wind and solar resources could
be disaggregated in such a way as to inappropriately gain access to published avoided cost rates
that could exceed the utility’s true avoided cost.Exhibit 2 at 9-11.As a result,the PUC lowered
the eligibility cap for published avoided cost rates for wind and solar resources to 100 kW —
consistent with PURPA and FERC regulations.18 C.F.R.§292.304(c)(1).Allowing Cedar
Creek to utilize the superseded 10 aMW eligibility cap after the Idaho PUC had determined that
the same eligibility cap permitted wind and solar QFs to obtain rates in excess of the utility’s
avoided cost,would be a clear violation of PURPA,A.W.Brown,121 Idaho at 818,828 P.2d at
847;18 C.F.R.§292.304(a)(l)&(2).Moreover,the exercise of a state commission’s discretion
in the application of PURPA standards to particular contracts has long been recognized as
outside the scope of this Commission’s Section 210(h)enforcement authority.Policy Statement
Regarding the Commission’s Enforcement Role Under Section 210 of the Public Utility
Regulatoiy Policies Act of 1978,23 FERC ¶61,304 at 61,645 (1983)(“...the Commission’s
role is limited regarding questions of the proper application of these rules on a case-by-case
basis”).See Power Resource Group,Inc.v.Pub.Utils.Comm ‘n of Texas,422 F.3d 231,238 (5th
Cir.2005);Mass.Inst.Tech.v Mass.Dept.ofPub.Utils.,941 F.Supp.233,236-237 (D.Mass.
1996).
IDAHO PUC ANSWER 22
With absolutely no citation to authority,Cedar Creek states in its Petition that using
the IRP methodology ‘historically,has produced rates that were dramatically lower than the
published rates.”Petition at 4.However,the Idaho PUC explained in final Order No.32260 in
the Contracts Case that
the purpose of utilizing the IRP Methodology for large QF projects is to more
precisely value the energy being delivered.The IRP Methodology recognizes
the individual generation characteristics of each project by assessing when the
QF is capable of delivering its resources against when the utility is most in
need of such resources.The resultant pricing is reflective of the value of QF
energy to the utility.
Exhibit 7 at 3.If,as Cedar Creek contends,the IRP methodology has resulted in lower pricing
for particular projects,the Idaho PUC asserts that such pricing is reflective of the value of energy
being generated by the QF.Cedar Creek’s assertion that the IRP ethodology produces lower
rates only serves to underscore the Idaho PUC’s decision to reduce the eligibility cap for specific
resources while it investigates other avoided cost issues.Avoided cost rates and their underlying
methodologies should be reflective of the utility’s actual avoided cost.PURPA and FERC
regulations require no less.
V.CONCLUSION
PURPA requires an electric utility to purchase power from a QF,but only if the
QF sells at a price no higher than the cost the utility would have incurred for the power if it had
not purchased the QF’s energy and/or capacity,i.e.would have generated itself or purchased
from another source.The intention was to make ratepayers indifferent as to whether the utility
used more traditional sources of power or the newly-encouraged alternatives.”Southern Cal.
Edison Co.,San Diego Gas &Electric,Order on Requests for Reconsideration,71 FERC ¶1
6 1,269 at 62,079-62,080 (1995).The Idaho PUC’s decision to lower the eligibility cap for wind
and solar QFs was based on evidence that the published rate for such resources was not an
IDAHO PUC ANSWER 23
accurate reflection of the utility’s avoided cost.The Idaho PUC’s findings were intended to
ensure that ratepayers are,in fact,indifferent as to whether the utility or a renewable resource is
generating the power.
The Idaho PUC provided actual notice to Cedar Creek of its intent to make the
change in the eligibility cap effective December 14,2010.Based upon substantial evidence in
the record,the Idaho PUC found that Cedar Creek and Rocky Mountain did not execute their
contract until December 22,2010.Because the size of Cedar Creek’s projects exceeded 100 kW,
the Idaho PUC found them to be ineligible for published rate contracts.Consequently,the Idaho
PUC disapproved the Agreements.None of the Idaho PUC’s actions are inconsistent with
PURPA or FERC regulations.Indeed,the intent and consequence of the Idaho PUC’s
determinations are consistent with both the express intent and spirit of the federal mandates.
For the reasons set forth above,the Idaho PUC respectfully requests the Commission
to dismiss Cedar Creek’s Petition to Institute an Enforcement Action against the Idaho PUC
under PURPA Section 210(h)in its entirety.
IDAHO PUC ANSWER 24
Respectfully submitted this 26th day of August 2011.
FOR THE IDAHO PUBLIC UTILITIES COMMISSION
LAWRENCE G.WASDEN
IDAHO ATTORNEY GENERAL
/5/
Kristine A.Sasser
Donald L.Howell,II
Deputy Attorneys General
Idaho Public Utilities Commission
P0 Box 83720
Boise,ID 83720-0074
Tele:[phone]
[phone]
E-mail:kris.sasser(puc.idaho.gov
don.howeILpuc.idaho.gov
John P.Coyle
Special Deputy Attorney General
Duncan &Allen,LLP
1575 Eye Street,NW,Suite 300
Washington,DC 20005
Tele:[phone]
Fax:[phone]
E-mail:j [e-mail]
Attorneys for the Idaho Public Utilities Commission
N:FERC :ELI I 59-OOO_Answerdhksjpc
IDAHO PUC ANSWER 25
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that I have this 26th day of August 2011,served the foregoingAnsweroftheIdahoPublicUtilitiesCommission,in FERC Docket No.EL11-59-000,uponeachpersondesignatedontheofficeservicelistcompiledbytheSecretaryoftheFederalEnergyRegulatoryCommission.
Larry Eisenstat
Attorney
Dickstein Shapiro LLP
1825 Eye Street NW
Washington,DC 20006-5403
E-mail:eisenstatl(ädicksteinshapiro.com
Michael R.Engleman
Counsel
Dickstein Shapiro LLP
1825 Eye Street NW
Washington,DC 20006-5403
E-mail:eng1emanm(Zdicksteinshapiro.com
Donald Gelinas
Dickstein Shapiro LLP
1825 Eye Street NW
Washington,DC 20006-5403
E-mail:elinasddicksteinshapiro.com
Kelly Goodman
2026 Northeast Mason Street
Portland,OR 97211
E-mail:kgoodman(surnmitpower.com
Tom Cameron
E-mail:tcarneronsummitpower.com
Dana Zentz
E-mail:[e-mail]
Scott Montgomery
E-mail:scottwesternenergy.us
Ron Williams
Williams &Bradbury
1015 W.Hays Street
Boise,ID 83702
E-mail:pwijabd1ry.c_o
Karen Hill
Vice President Fed Regulatory
Exelon Corporation
101 Constitution Avenue.Suite 400 E
Washington,D.C.20001
E-mail:Karen.hil [e-mail]
John A.Harvey
Manager,Regulatory and Market
Exelon Generation Company,LLC
4601 Westown Parkway
West Des Moines,IA 50266
E-mail:john.harveyexeloncorp.com
M.Andrew McLain
208 N.Montana Avenue,Suite 205
Helena,MT 59601
E-mail:Andrew.rnclain’northwestern.com
Al Brogan Jason Williams
Corporate Counsel Corporate Counsel
Northwestern Corporation Idaho Power Company
P0 Box 202601 P0 Box 70
Helena,MT 59620-2601 Boise,ID 83707-0070
E-mail:aLbrogan(northwestern.com E-mail:jwil1iams(idahopower,com
Donovan E.Walker U.S.MAIL ONLY:
Idaho Power Company
P0 Box 70 Randy Aliphin
Boise,ID 83707-0070 Idaho Power Company
E-mail:dwalker(idahopower.com P0 Box 70
Boise,ID 83 707-0070
Lisa Grow
Idaho Power Company
P0 Box 70
Boise,ID 83707-0070
Kristine A.Sasser
Deputy Attorney General
INDEX OF EXHIBITS
Exhibit I IPUC Order No.32131 (Dec.3,2010)(Case No.GNR-E-10-04)
Exhibit 2 IPUC Order No.32176 (Feb.7,2011)(Case No.GNR-E-10-04)
Exhibit 3 IPUC Order No.32212 (March 28,2011)(Case No.GNR-E-10-04)
Exhibit 4 Power Purchase Agreement between Cedar Creek Wind and PacifiCorp
(Rocky Mountain)relating to “Rattlesnake Canyon”(filed Jan.10,2011)
(Case No.PAC-E-11-01)(Agreement Exhibits excluded)
Exhibit 5 IPUC Order No.32192 (Feb.24,2011)(Case Nos.PAC-E-1 1-01 thru -05)
Exhibit 6 Cedar Creek Initial Comments (filed Jan.26,2011)
Exhibit 7 IPUC Order No.32260 (June 8,2011)(Case Nos.PAC-E-1 1-01 thru -05
plus Errata)
Exhibit 8 IPUC Order No.32302 (July 27,2011)(Case Nos.PAC-E-1 1-01 thru -05)
Exhibit 9 Joint Petition of Utilities (filed Nov.5,2010)(Case No.GNR-E-10-04)
Exhibit 10 Rocky Mountain Power Reply Comments (filed April 12,2011)(Case No.
PAC-E.-1 1-01 thru -05)
CERTIFICATE
STATE OF IDAHO,)
)
COUNTY OF ADA.)
I hereby certify that the foregoing is a full,true and correct copy of original Order
Nos.32131,32176,32192,32212,32260,32302,PacifiCorp/Cedar Creek Wind Power Purchase
Agreement,Cedar Creek Initial Comments,Utilities Joint Petition,and Rocky Mountain Power’s
Reply Comments in the foregoing entitled matter,now on file in the office of the Idaho Public
Utilities Commission.
IN WITNESS WHEREOF,I have hereto set my hand and affixed the seal of the
Idaho Public Utilities Commission this 25th day of August ,2011.
7tU
cØMMISSIo SECRETARY
(SEAL)
EXHIBIT 1
IDAHO PUC ORDER NO.32131
Office of the Secretary
Service Date
December 3,2010
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE JOINT )PETITION OF IDAHO POWER )CASE NO.GNR-E-1O-04COMPANY,AVISTA CORPORATION,)AND PACIFICORP DBA ROCKY )NOTICE OF JOINT PETITIONMOUNTAINPOWERTOADDRESS)AVOIDED COST ISSUES AND TO ADJUST )NOTICE OFTHEPUBLISHEDAVOIDEDCOSTRATE)MODIFIED PROCEDUREELIGIBILITYCAP.)
)NOTICE OF
)INTERVENTION DEADLINE
)
)NOTICE OF
)ORAL ARGUMENT
)
___________________________
)ORDER NO.32131
On November 5,2010,Idaho Power Company,Avista Corporation,and PacifiCorp
dba Rocky Mountain Power filed a Joint Petition requesting that the Commission initiate an
investigation to address various avoided cost issues’related to the Public Utility Regulatory
Policies Act of 1978 (PURPA).While the investigation is underway,the Petitioners also
requested that the Commission “lower the published avoided cost rate eligibility cap from 10
aMW to 100 kW [tol be effective immediately....“Petition at 7.
NOTICE OF JOINT PETITION
YOU ARE HEREBY NOTIFIED that the Joint Petition was filed following a public
workshop in Case No.GNR-E-09-03 convened for the purpose of discussing a surrogate avoided
resource (SAR)methodology for wind-specific qualifying facilities (QFs).The Joint Petition
asserts that both Idaho Power and Rocky Mountain Power are projected to add large quantities of
wind generation to their systems.The Joint Petition asserts that there was a discussion at the
The Petition identified the following issues to examine:system reliability;operational control;ownership andvaluationofRECs;the lack of capacity provided by intermittent wind generation;the need to build/acquire capacityonthesystem;the associated transmission infrastructure and upgrades needed to bring additional wind generation toload;the interconnection and transmission service request process;the mechanical availability guarantee (MAG)provision;the posting of security;liquidated damages;a standard contract template;the impact of QF generation ontheintegratedresourceplanning(IRP)process;and the increased size and scale of QF projects.
NOTICE OF JOINT PETITION
NOTICE OF MODIFIED PROCEDURE
NOTICE OF INTERVENTION DEADLINE
NOTICE OF ORAL ARGUMENT
ORDERNO.32131 1
November 3,2010 workshop regarding the need to temporarily reduce the eligibility cap for the
published avoided cost rates from 10 aMW to 100 kW.Petition at 2.
YOU ARE FURTHER NOTIFIED the Petition requests that the Commission reduce
the eligibility cap “on an interim basis during the pendency of this investigation and docket.”fri
at 2.The Petitioners maintain that the Commission has made similar reductions in the past on an
interim basis,citing to Commission Order Nos,29872 in Case No.IPC-E-05-22,
YOU ARE FURTHER NOTIFIED that the Joint Petition asserts that many of the
same reasons that justified the Commission’s action to lower the eligibility cap to 100 kW in the
05-22 case are present in this case.The Petitioners stress that the reasons and justifications are
amplified in the present situation because “the number of projects,their combined MWs,the
dollar impacts,and the potential consequences to the system and to customers are much larger
and much more pronounced than even those that existed [in 20051.”Id.at 3.
YOU ARE FURTHER NOTIFIED that the Petition states that Idaho Power currently
has more than 208 MW of wind generation and an additional 264 MW of Commission-approved
QF wind contracts (many of which are scheduled to be online by December 31,2010).The
Petition asserts that Idaho Power could have 1100 MW of wind powered generation on its
system in the near term that would exceed the minimum loads experienced on Idaho Power’s
system this year.“Cumulatively,this amount of generation would exceed any other single
source of generation —hydro,coal,natural gas,or renewables —that exists on Idaho Power’s
system.”Id.at 4.
YOU ARE FURTHER NOTIFIED that Rocky Mountain asserts that it is in a similar
situation.The Petition declares that in 2005,Rocky Mountain had a single 20 MW wind QF
contract and less than 50 MW of wind QF requests in Idaho.“As of today,[Rocky Mountain)
has 64 MW of wind QF contracts executed;however,none have achieved commercial operation,
and another 358 MW of standard wind QF contracts are proposed.”Rocky Mountain maintains
that the majority of these proposed standard wind QF contracts are configured to use the Goshen
Idaho electrical system “where integration of the QF resource as a Network Resource for serving
load could be impacted by transmission constraints across Path C if the wind power is exported
to RMP’s northern Utah load.”Id,at 4.
NOTICE OF JOINT PETITION
NOTICE OF MODIFIED PROCEDURE
NOTICE OF INTERVENTION DEADLINE
NOTICE OF ORAL ARGUMENT
ORDERNO.32131 2
YOU ARE FURTHER NOTIFIED that the Petition states that many current QF
projects are “large,utility-scale wind farms that are broken up into 10 aMW increments in order
to qualify for the published [avoided cost]rates.”Id.at 5.The Petition maintains that the typical
wind developer is no longer “unsophisticated”about the QF process and small projects (.5-1.5
MW)“are no longer the norm.”Id.The Petitioners assert that it is “commonplace”for wind
developers seeking QF contracts with Idaho Power and Rocky Mountain to aggregate “six or
more ‘projects’totaling 100 to 150 MW of nameplate rating,and the multiple projects to all
share interconnection facilities to one common utility delivery point.”Id.
YOU ARE FURTHER NOTIFIED that the Petitioners request that the Commission
take immediate action on its request to lower the eligibility cap immediately “on fewer than
fourteen days notice,if possible,See,RP 256.”The Petitioners’request for an immediate
reduction in the eligibility cap is meant to mitigate the typical “race’to the door of the utilities
with projects attempting to position themselves for a claim to ‘grandfathering’and entitlement to
the previously effective rates,terms,conditions,etc.”Petition at 7.The Petitioners further assert
that it is important that the eligibility cap be reduced for all three utilities.This would prevent a
situation where a utility not granted a reduction in its eligibility cap could disproportionately
attract a greater number of project proposals.Id.
PETITIONS TO INTERVENE AND ANSWERS
YOU ARE FURTHER NOTIFIED that,after the filing of the Joint Petition,the
Commission received several petitions to intervene.Petitions to intervene have been filed by:
Cedar Creek Wind,LLC;Exergy Development Group of Idaho;Grandview Solar II;Idaho
Windfarms,LLC;Interconnect Solar Development,LLC;the Northwest and Intermountain
Power Producers Coalition (NIPPC);Renewable Energy Coalition (the “Coalition”)2;
Intermountain Wind,LLC;and J.R.Simplot Company.All of the Petitioners allege a direct and
substantial interest in the Joint Petition.No party timely opposed the petitions to intervene.
YOU ARE FURTHER NOTIFIED that,in addition to the petitions to intervene,the
Commission also received four Answers to the Joint Petition.Answers were filed by NIPPC,the
2 The Coalition is an Oregon-based consortium of existing base load hydroelectric and biomass QFs located in the
Northwest.
NOTICE OF JOINT PETITION
NOTICE OF MODIFIED PROCEDURE
NOTICE OF INTERVENTION DEADLINE
NOTICE OF ORAL ARGUMENT
ORDERNO.32131 3
Coalition,Simplot,and the Milk Producers of Idaho.3 The Answers raise both procedural and
substantive objections to the Petitioners’request to lower the eligibility cap for the published
avoided cost rate to 100 kW nameplate capacity.More specifically,NIPPC urges the
Commission to take no action regarding the eligibility cap until interested parties have been
allowed reasonable time to respond to the Petitioners’request regarding the 100 kW cap.NIPPC
Answer at 9-10.NIPPC also argues that the Petitioners have not served “all adverse parties”and
the Petitioners have not provided evidence to support the request for immediate relief.Id.at 5-9.
Simplot also adopted NIPPC’s Answer.
YOU ARE FURTHER NOTIFIED that the Milk Producers,Simplot and the
Coalition also argue in their Answers that the lowering of the eligibility cap should not apply to
non-wind QFs.Simplot asserts that the Joint Petition does not refer to any “problems associated
with biomass,cogeneration,solar,small hydro,waste-to-energy projects or any other type of
PURPA eligible QF resource.These other types of [QF]resources have very different
generating characteristics from wind and should therefore not be caught in the overly broad
sweep of the Joint Motion.”Simplot Answer at 3.
YOU ARE FURTHER NOTIFIED that in evaluating the Joint Petition,Staff
recommended the Commission develop a record in this matter through the use of Modified
Procedure,Rule 202.Specifically,Staff recommended that the Commission first take up the
issue of the Petitioners’request to reduce the eligibility cap.Staff further recommended that the
Commission set a deadline for intervention,approve the petitions to intervene already filed,and
issue a Notice of Parties in this case.Finally,Staff recommended that the Commission note in
its Notice of Petition!Notice of Modified Procedure that the Commission’s ultimate decision
regarding the Petitioners’request to reduce the published avoided cost eligibility cap become
effective seven days after the Commission issues its Notice in this case.
DISCUSSION
As set out above,the Joint Petition asks the Commission to initiate an investigation to
examine a host of issues pertaining to the avoided costs for QF projects.The Petitioners also
The Milk Producers did not file a Petition to Intervene and its “Answer”was a “letter in opposition.”The MilkProducersletterwillbetreatedasacomment.If the Milk Producers desire to intervene in this matter as a party,it
must file a Petition to Intervene.
NOTICE OF JOINT PETITION
NOTICE OF MODIFIED PROCEDURE
NOTICE OF INTERVENTION DEADLINE
NOTICE OF ORAL ARGUMENT
ORDERNO.32131 4
request that while the investigation is pending,the Commission lower the published avoided cost
rate eligibility cap immediately “on fewer than fourteen days notice,if possible.”Petition at 7.
The Petitioners note that a reduction in the eligibility cap on an interim basis was previously
authorized in Case No.IPC-E-05-22.However,there is a significant difference between the
Joint Petition in this case and Idaho Power’s request to temporarily lower the eligibility 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 evidentiary hearing and oral argument
to develop the record.Order No.29872 at 1,10.Consequently,we decline at this time to
immediately reduce the published avoided cost rate eligibility cap.
After reviewing the Joint Petition and the Answers,the Commission will first take up
the request to reduce the eligibility cap.As set out in the schedule below,the Commission will
process the Petitioners’request to reduce the eligibility cap via Modified Procedure and schedule
an oral argument.In particular,the Commission is interested in receiving comments regarding:
(1)the advisability of reducing the published avoided cost eligibility cap;(2)if the eligibility cap
is reduced,the appropriateness of exempting non-wind QF projects from the reduced eligibility
cap;and (3)the consequences of dividing larger wind projects into 10 aMW projects to utilize
the published rate.4
We next turn to the Petitions to Intervene.The Commission finds based upon the
Petitions and the lack of any objection,the Petitions to Intervene shall be granted.Intervention
by these parties will serve the purpose of intervention as described by Rule 74 of the
Commission’s Rules of Procedure.We also set a deadline for intervention for other persons
interested in this proceeding.Once the intervention deadline has passed,the Commission
Secretary shall prepare a Notice of Parties to include the e-mail addresses of parties.The parties
shall subsequently utilize the e-mail addresses to serve their comments on all other parties.
After the Commission issues its Order in the first phase in this case,we will take up
the other avoided cost issues raised by the Joint Petition and other interested parties.Finally,it is
‘The Joint Petition argued that many current QF projects are “large,utility-scale wind farms that are broken up into
10 aMW increments in order to qualif’for the published [avoided)cost rates.”Petition at 5.
NOTICE OF JOINT PETITION
NOTICE OF MODIFIED PROCEDURE
NOTICE OF INTERVENTION DEADLINE
NOTICE OF ORAL ARGUMENT
ORDERNO.32131 5
our intent that our decision regarding the “Joint Motion”to reduce the published avoided cost
eligibility cap shall become effective on December 14,2010.
NOTICE OF MODIFIED PROCEDURE
YOU ARE FURTHER NOTIFIED that the Commission has determined that the
public interest may not require a formal hearing in this matter and will proceed under Modified
Procedure pursuant to Rules 201 through 204 of the Idaho Public Utilities Commission’s Rules
of Procedure,IDAPA 31.01.01.201 through .204.The Commission notes that Modified
Procedure and written comments have proven to be an effective means for obtaining public input
and participation.The Commission further finds that it is appropriate to schedule an oral
argument for parties to present their case.
YOU ARE FURTHER NOTIFIED that the Petition and the Answers have been filed
with the Commission and are available for public inspection during regular business hours at the
Commission offices.The Petition and Answers are also available on the Commission’s web site
at www.puc.idaho.gov by clicking on “File Room”and then “Electric Cases.”
YOU ARE FURTHER NOTIFIED that any person desiring to state a position on this
Petition may file a written comment in support or opposition with the Commission no later
than December 22,2010.The comment must contain a statement of reasons supporting the
comment.Written reply comments addressing arguments and positions raised by the initial
comments may be filed no later than January 19,2011.Persons desiring a hearing must
specifically request a hearing in their written comments.Written comments concerning this
Petition shall be mailed to the Commission and served on all other parties via e-mail.The
Commission’s address is reflected below:
Commission Secretary
Idaho Public Utilities Commission
P0 Box 83720
Boise,ID 83720-0074
Street Address for Express Mail:
472 W.Washington Street
Boise,ID 83702-5918
NOTICE OF JOINT PETITION
NOTICE OF MODIFIED PROCEDURE
NOTICE OF INTERVENTION DEADLINE
NOTICE OF ORAL ARGUMENT
ORDERNO.32131 6
These comments should contain the case caption and case number showr on the first page of this
document.Persons (not parties)desiring to submit comments via e-mail may do so by accessing
the Commission’s home page located at www.puc.idaho.gov.Click the “Comments and
Questions”icon and complete the comment form using the case number as it appears on the front
of this document.
YOU ARE FURTHER NOTIFIED that if no written comments or protests are
received within the time limit set,the Commission will consider this matter on its merits and
enter its Order without a formal hearing.If written comments are received within the time limit
set,the Commission will consider them and,in its discretion,may set the same for formal
hearing.
DEADLINE FOR INTERVENTION
YOU ARE FURTHER NOTIFIED that any additional persons desiring to intervene
in this matter for the purpose of presenting comments or oral argument must file a Petition to
Intervene with the Commission pursuant to the Commission’s Rules of Procedure 72 and 73,
IDAPA 31.01.01.072 and .073.Additional persons intending to participate as parties must file a
Petition to Intervene no later than 14 days from the service date of this Order.Persons
seeking intervenor status shall also provide the Commission Secretary with an electronic mail
address to facilitate service in this matter.
YOU ARE FURTHER NOTIFIED that persons desiring to present their views
without parties’rights of participation are not required to intervene and may present their
comments without prior notification to the Commission or to other parties.
YOU ARE FURTHER NOTIFIED that once the deadline for intervention has
passed,the Commission Secretary shall issue a Notice of Parties.The Notice of Parties shall
assign exhibit numbers to each party in this proceeding.
NOTICE OF ORAL ARGUMENT
YOU ARE HEREBY NOTIFIED that the Commission will convene a hearing for
oral argument in this case on THURSDAY,JANUARY 27,2011,AT 9:30 AM.
(MOUNTAIN STANDARD TIME)IN THE COMMISSION HEARING ROOM,472
WEST WASHINGTON STREET,BOISE,IDAHO.The issues addressed through oral
argument should be directed at the Joint Petition’s request to temporarily reduce the eligibility
NOTICE OF JOINT PETITION
NOTICE OF MODIFIED PROCEDURE
NOTICE OF INTERVENTION DEADLINE
NOTICE OF ORAL ARGUMENT
ORDER NO.32131 7
cap for the published avoided cost rates from 10 aMW to 100 kW.Parties may also address the
other questions set out in the “Discussion”section above.The broader avoided cost issues cited
by the Petitioners will be taken up in subsequent proceedings.
YOU ARE FURTHER NOTIFIED that all proceedings in this case will be held
pursuant to the Commission’s jurisdiction under Title 61 of the Idaho Code and the Public Utility
Regulatory Policies Act of 1978 (PURPA).The Commission has authority under PURPA and
the implementing regulations of the Federal Energy Regulatory Commission (FERC)to set
avoided costs,to order electric utilities to enter into fixed-term obligations for the purchase of
energy from qualified facilities and to implement FERC rules.The Commission may enter any
final Order consistent with its authority under Title 61 and PURPA.
YOU ARE FURTHER NOTIFIED that all proceedings in this matter will be
conducted pursuant to the Commission’s Rules of Procedure,IDAPA 31.01.01.000,et seq.
YOU ARE FURTHER NOTIFIED that all hearings and oral arguments in this matter
will be held in facilities meeting the accessibility requirements of the Americans with
Disabilities Act (ADA).Persons needing the help of a sign language interpreter or other
assistance in order to participate in or to understand testimony and argument at a public hearing
may ask the Commission to provide a sign language interpreter or other assistance at the hearing.
The request for assistance must be received at least five (5)working days before the hearing by
contacting the Commission Secretary at:
IDAHO PUBLIC UTILITIES COMMISSION
P0 BOX 83720
BOISE,IDAHO 83720-0074
[phone] (Telephone)
[phone] (FAX)
E-Mail:secretary(puc.idaho.gov
ORDER
IT IS HEREBY ORDERED that this case be processed under Modified Procedure.
Persons intending to participate as parties must file a Petition to Intervene no later than 14 days
from the service date of this Order.The Petitions to Intervene filed by Cedar Creek Wind,LLC;
Exergy Development Group of Idaho;Grandview Solar II;Idaho Windfarms,LLC;Interconnect
NOTICE OF JOINT PETITION
NOTICE OF MODIFIED PROCEDURE
NOTICE OF I1’TERVENTION DEADLINE
NOTICE OF ORAL ARGUMENT
ORDERNO.32131 8
Solar Development,LLC;the Northwest and Intermountain Power Producers Coalition;
Renewable Energy Coalition;Intermountain Wind,LLC;and J.R.Simplot Company are granted.
IT IS FURTHER ORDERED that interested persons and the parties file written
comments no later than December 22,2010.Reply comments addressing arguments and
positions raised by any initial comments must be filed no later than January 19,2011.
IT IS FURTHER ORDERED that parties file their initial and reply comments on
other parties via electronic mail.
IT IS FURTHER ORDERED that the Commission’s decision regarding whether to
reduce the published avoided cost eligibility cap become effective on December 14,2010.
IT IS FURTHER ORDERED that the Commission convene a hearing for oral
argument on Thursday,January 27,2011,at 9:30 a.m.in the Commission Hearing Room.
DONE by Order of the Idaho Public Utilities Commission at Boise,Idaho this 3
day of December 2010.
MARSHA H.SMITH,COMMISSIONER
MDFCOEE’
ATTEST:
Jeji D.JewelU
Commission Secretary
O:GNR-E-I OO4ksdh
NOTICE OF JOINT PETITION
NOTICE OF MODIFIED PROCEDURE
NOTICE OF INTERVENTION DEADLINE
NOTICE OF ORAL ARGUMENT
ORDERiO.32131
IDENT
9
EXHIBIT 2
IDAHO PUC ORDER NO.32176
Office of the Secretary
Service Date
February 7,2011
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE JOINT )PETITION OF IDAHO POWER COMPANY,)CASE NO.GNR-E-1O-04AVISTACORPORATION,AND )PACIFICORP DBA ROCKY MOUNTAIN )POWER TO ADDRESS AVOIDED COST )ORDER NO.32176ISSUESANDTOADJUSTTHEPUBLISHED)AVOIDED COST RATE ELIGIBILITY CAP.)
On November 5,2010,Idaho Power Company,Avista Corporation,and PaeifiCorp
dba Rocky Mountain Power filed a Joint Petition requesting that the Commission initiate an
investigation to address various avoided cost issues related to the Commission’s implementation
of the Public Utility Regulatory Policies Act of 1978 (PURPA).PURPA was intended to
encourage the development of renewable energy technologies as alternatives to the use of fossil
fuels and the construction of new generating facilities by electric utilities.Section 210 of
PURPA generally requires electric utilities to purchase power produced by qualifying facilities
(QFs)at “avoided cost”rates set by the Commission.“Avoided costs”are those costs which a
public utility would otherwise incur for electric power,whether that power was purchased from
another source or generated by the utility itself.18 C.F.R.§292.101 (b)(6).
While the investigation is underway,the Petitioners also moved the Commission to
“lower the published avoided cost rate eligibility cap from 10 aMW to 100 kW [to]be effective
immediately....“Petition at 7.Pursuant to PURPA regulations issued by the Federal Energy
Regulatory Commission (FERC),this Commission must publish avoided cost rates for small QFs
with a design capacity of 100 kW or less.However,the Commission has the discretion to set the
published avoided cost rate at a higher capacity amount —commonly referred to as the
“eligibility cap.”18 C.F.R.§292.304(c)(l)and (2).When this case was initiated,the eligibility
cap for the published avoided cost rate was set at 10 aMW.Order No.30488.The avoided cost
rates for purchases from QFs larger than the eligibility cap (10 aMW)must be individually
negotiated by the QF and the public utility.In a negotiated contract,the utility’s avoided cost is
the starting point for rate negotiations.
As set out in greater detail below,the Commission grants in part and denies in part
the Petitioners’Motion to reduce the eligibility cap.The Commission temporarily reduces the
ORDERNO.32176 1
eligibility cap for published avoided cost rates from 10 aMW to 100 kW for wind and solar QFs
only.
BACKGROUND
A.The Joint Petition
The Petition states that Idaho Power currently has more than 208 MW of wind
generation and an additional 264 MW of Commission-approved QF wind contracts (many of
which are scheduled to be online by December 31,2010).The Petition asserts that Idaho Power
could have 1,100 MW of wind-powered generation on its system in the near term that would
exceed the minimum loads experienced on Idaho Power’s system this year.“Cumulatively,this
amount of generation would exceed any other single source of generation —hydro,coal,natural
gas,or renewables —that exists on Idaho Power’s system.”Id.at 4.
Rocky Mountain asserts that it is in a similar situation.The Petition declares that in
2005,Rocky Mountain had a single 20 MW wind QF contract and less than 50 MW of wind QF
requests in Idaho.‘As of today,[Rocky Mountainj has 64 MW of wind QF contracts executed;
however,none have achieved commercial operation,and another 358 MW of standard wind QF
contracts are proposed.”Rocky Mountain maintains that the majority of these proposed standard
wind QF contracts are configured to interconnect with the utility’s Goshen substation “where
integration of the QF resource as a Network Resource for serving load could be impacted by
transmission constraints across Path C if the wind power is exported to RMP’s northern Utah
load.”Id.at 4.
The Petition states that many current QF projects are “large,utility-scale wind farms
that are broken up into 10 aMW increments in order to qualify for the published [avoided costj
rates.”Id.at 5.The Petition maintains that the typical wind developer is no longer
“unsophisticated”about the QF process and small projects (0.5-1.5 MW)“are no longer the
norm.”Id.The Petitioners assert that it is “commonplace”for wind developers seeking QF
contracts with Idaho Power and Rocky Mountain to aggregate ‘six or more ‘projects’totaling
100 to 150 MW of nameplate rating,and the multiple projects to all share interconnection
facilities to one common utility delivery point.”JcL
B.Procedural History
After the filing of the Joint Petition,the Commission received several Petitions to
Intervene.The following parties requested,and were granted,intervenor status:Cedar Creek
ORDERNO.32176 2
Wind,LLC;Exergy Development Group of Idaho;Grandview Solar 11;Idaho Windfarms,LLC;
Interconnect Solar Development,LLC;the Northwest and Intermountain Power Producers
Coalition (NIPPC);Renewable Energy Coalition (Coalition);’Intermountain Wind,LLC;J.R.
Simplot Company;Board of Commissioners of Adams County (Adams County);Birch Power
Company;Dynamis Energy,LLC;North Side and Twin Falls Canal Companies (Canal
Companies);and Blue Ribbon Energy,LLC.
In addition to the Petitions to Intervene,the Commission also received four answers
to the Joint Petition,Answers were tiled by NIPPC,the Coalition,Simplot,and the Milk
Producers of Idaho.2 The answers raise both procedural and substantive objections to the
Petitioners’request to lower the eligibility cap for the published avoided cost rate to 100 kW
nameplate capacity.The Milk Producers,Simplot and the Coalition also argue in their answers
that the lowering of the eligibility cap should not apply to non-wind QFs.Simplot asserts that
the Joint Petition does not refer to any “problems associated with biomass,cogeneration,solar,
small hydro,waste-to-energy projects or any other type of PURPA eligible QF resource.These
other types of [QFI resources have very different generating characteristics from wind and
should therefore not be caught in the overly broad sweep of the Joint Motion.”Simplot Answer
at 3.
C.The Commission Notice ofPetition
On December 3,2010,the Commission issued an Order and Notice of Joint Petition.
After reviewing the Joint Petition and the answers,the Commission declined the Motion to
immediately reduce the eligibility cap.Instead,the Commission determined that it would
expeditiously consider the Petitioners’request to reduce the eligibility cap through the use of
Modified Procedure (written comments)and oral arguments.The Notice established an
intervention deadline of December 17,2010;set deadlines for initial comments and reply
comments of December 22,2010,and January 19,2011,respectively;and scheduled an oral
argument for January 27,2011.Order No.32131.
The Commission specifically requested comment and argument regarding:(1)the
advisability of reducing the published avoided cost eligibility cap;(2)if the eligibility cap is
The Coalition is an Oregon-based consortium of existing base load hydroelectric and biomass QFs located in the
Northwest.
2 The Milk Producers did not file a Petition to Intervene and its “Answer”was a “letter in opposition.”The Milk
Producers letter,therefore,will been treated as a comment.
ORDERNO.32176 3
reduced,the appropriateness of exempting non-wind QF projects from the reduced eligibility
cap;and (3)the consequences of dividing larger wind projects into 10 aMW projects to utilize
the published rate.3 The Commission also determined that its decision regarding the Joint
Petitioners’Motion to reduce the published avoided cost eligibility cap would become effective
on December 14,2010.
PROCEDURAL AND SUBSTANTIVE MOTIONS
Before and at the January 27,2011 oral argument,several parties made various
motions.The motions are addressed in greater detail below.
A.Motion to Strike
With its reply comments filed on January 19,2011,Rocky Mountain Power prefiled
the direct testimony of Bruce Griswold.On January 21,2011,NIPPC filed a Motion to Strike
Griswold’s testimony.NIPPC renewed its Motion to Strike at oral argument.Given NIPPC’s
Motion,Rocky Mountain Power withdrew Mr.Griswold’s testimony.Tr.at 11.
B.Motionfor a Technical Hearing
In their initial comments and reply comments,both NIPPC and Adams County
requested that the Commission conduct a technical hearing in order to allow the parties to
present witnesses.Several times during oral argument N1PPC and Adams County referenced the
need for a technical hearing,but did not renew their Motion.
The Commission finds that the parties’positions have been adequately presented
through initial comments,reply comments and oral argument,and that a technical hearing is not
necessary to resolve the question of whether the eligibility cap should be reduced.We also find
that conducting a technical hearing would unnecessarily delay the decision making process.
Consequently,the Commission denies the parties’requests for a technical hearing.We find that
the comments and oral argument provide sufficient information to resolve the policy question of
temporarily reducing the eligibility cap.
C.Request to Take Official Notice
At oral argument,NIPPC distributed a document entitled “Request for Official
Notice”and asked the Commission to take official notice of a host of documents listed in the
“Request”including approximately 14 PUC Orders,several FERC orders,and the “Filings,
The Conm3ission intends to consider the other avoided cost issues identified by the Petitioners and other interested
parties in subsequent proceedings.
ORDER NO.32176 4
Testimony,Exhibits and Orders”in 24 different PUC dockets.In addition,NIPPC orally asked
that the Commission take official notice of “three documents related to coal costs that support
our comments”:a settlement agreement of the Environmental Protection Agency;an Oregon
State Senate Natural Resources Committee report on greenhouse gas emissions;and
MidAmerican Holdings Company’s comments from a coal combustion residual rulemaking.Tr.
at 7-8.The Commission acknowledged official notice of its own notices and orders.Id.at 9.
Pursuant to our Procedure Rule 263.01,the Commission may take official notice at
hearing and in its Orders of:
a.(1)Its own orders,notices,rules,certificates and permits,and (2)those of
any other regulatory agency,state or federal;
b.(1)matters of common knowledge,(2)technical,financial,or scientific
facts established and published in accepted authorities or in the
Commission’s specialized knowledge,and (3)matters judicially
noticeable;and
c.Data contained in periodic reports of regulated utilities filed with the
Commission or federal regulatory agencies.
However,“[u]nless otherwise agreed to by the parties and approved by the presiding officer,
parties requesting the Commission to take official notice of documents must submit those
documents to the Commission in the manner prescribed for documents in Rule 262.”Rule
263.02 (emphasis added).Although NIPPC presented the Commission with a list of citations to
documents,it did not actually provide copies of the requested documents to the Commission or
to the parties.NIPPC also advised the Commission that all of its requested documents met the
parameters of Rule 263.01.Tr.at 10,However,Rule 263.01 pertains to matters that the
Commission may officially note.Parties requesting official notice must comply with Rule
263.02 and provide copies of the documents for which it seeks official notice.The purpose of
providing copies to parties is to afford the parties an opportunity to review,and if necessary,
contest the offered material.id.Moreover,the majority of the “filings,testimonies and
exhibits”from the 24 PUC dockets are not documents or information subject to official notice
per Rule 263.Notwithstanding the Commission’s acknowledgement of taking official notice of
its own notices and orders,the Commission denies NIPPC’s request to take official notice of the
remainder of its listed documents,including the three additional documents regarding coal costs.
ORDER NO.32176 5
D.Motion to Dismiss
During oral argument,Blue Ribbon Energy asked the Commission to dismiss the
utilities’Joint Petition.Blue Ribbon articulated three bases upon which the Commission should
dismiss the Petition:(1)the utilities’failed to file the Petition in good faith;(2)the utilities have
not presented a basis upon which relief can be granted;and (3)the utilities’Joint Petition
constitutes an effort by the utilities to terminate their obligations to enter into PURPA contracts.
Tr.at 74.The utilities responded that their Joint Petition was made in good faith and based on
verifiable evidence that large QF projects are receiving an avoided cost rate in excess of the
utility’s true avoided cost.Id.at 82.Rocky Mountain Power specifically pointed out that the
costs of QF contracts are borne by ratepayers and that the utilities were acting in the ratepayers’
interest.Id.at 83.
The Commission denied Blue Ribbon’s request for dismissal of the Petition.The
Commission stated that the utilities’Petition was based on the Commission’s authority to set the
eligibility cap for QF projects.Id.at 87.We reject Blue Ribbon’s argument that a reduction in
the eligibility cap relieves utilities of their obligation to purchase QF power.Tr.at 76-77,81.
Finally,Blue Ribbon’s argument regarding the 80 MW maximum of a QF is not relevant to
the cap size of the standard published rate.Cf 18 C.F.R.§292.204(a)and 292.304(c).
COMMENTS AND ORAL ARGUMENT
Comments and arguments were presented by developers of QF facilities,Staff,each
of the Petitioners,and other interested persons.Idaho Power,Avista,and Rocky Mountain
Power all propose lowering the threshold for PURPA published avoided cost rates from 10 aMW
to 100 kW for all QF resources.The utilities argue that the number of QFs currently requesting
contracts under the published 10 aMW avoided cost rate is excessive and the utilities’ability to
continue to accept the QF energy without negatively impacting the electric system and the
utilities’customers is at risk.Specifically,the utilities cite large wind QFs as the source of their
current predicament.
Idaho Power stated that “the current application of the [published rate]methodology,
including the 10 average megawatt cap,has several problems associated with it that have
potentially huge ramifications or implications for our customers....“Tr.at 13.Avista
maintained that reducing the eligibility cap to 100 kW “is the most practical,simplest,most
easily implemented and enforced solution to the issues”that the utilities are facing.Id at 31.
ORDER NO.32176 6
When addressing the disaggregation issue raised by the Petition,Rocky Mountain
Power argued that a disaggregated wind project “looks a lot like a large wind QF project.Except
for additional [electric]meters,the differences are almost purely legal.”Id at 33.Rocky
Mountain Power explained that “the large QFs have an option and this option is valuable and that
value comes at the expense of ratepayers.”Id at 36.The Petitioners also maintain that it is
important that any change in the eligibility cap be applied equally for all three utilities in order to
prevent a utility not granted a reduction from disproportionately attracting a greater number of
QF project proposals.
Without exception,the Intervenors oppose reduction of the published avoided cost
rate eligibility cap.The Intervenors generally contend that lowering the threshold is an
imposition on legally permissible QF projects that cannot absorb the costs of negotiating with a
utility and the increased difficulty of obtaining financing created by the uncertainty of the
payments they will receive under PURPA contracts negotiated through use of the Integrated
Resource Plan (IRP)Methodology.
Dynamis,Adams County,Birch Power,Interconnect Solar,the Canal Companies,the
Coalition and Commission Staff urge the Commission to narrowly apply any reduction in
eligibility cap to the resource identified by the utilities as causing the immediate problem:wind
QFs.Interconnect Solar distinguishes its resource from wind by arguing that “[s]olar power is
not ‘intermittent’and instead has a firm nature to its production that directly matches a utility’s
need for energy and capacity during heavy load hours.”Interconnect Solar Comments at 2.
Even Intermountain Wind,a self-professed family operation,maintains that “[am overly broad
eligibility reduction would harm projects that are legitimately entitled access to PURPA
published avoided cost rates and would adversely affect the development of renewable energy in
Idaho.”Intermountain Wind Comments at 5.Intermountain Wind also argues that,“[w]hether
PURPA published rates should be available to commercial scale projects may be fairly
debatable.Whether those rates should be available to parties such as Intermountain is not.”Id.
at4.
NIPPC maintains that a reduction in the published avoided cost rate eligibility cap is
not warranted for any resource because the utilities have not demonstrated that the published
avoided cost rate is too high.NIPPC further argues that,although the utilities have identified
large wind projects as the immediate source of the problem,the utilities do not claim that they
ORDER NO.32176 7
would be unable to integrate the amount of wind currently in the queue.NIPPC and Adams
County claim that disaggregation “is irrelevant and a non-issue,because if the avoided cost rates
are accurately set,the rates for an IRP methodology avoided cost project would be essentially the
same as the rates for a non-IRP methodology avoided cost project.”Tr.at 49.They go on to
assert that “[nb developer is going to go in for the IRP methodology knowing that it sets the
avoided cost rate under actual avoided cost rates if they’re able to take advantage of the true
avoided cost rate....“Id at 51.
NIPPC and Intermountain Wind also oppose the Commission’s decision to implement
a December 14,2010,effective date,Intermountain Wind argues that the Commission “does not
have authority to look back in time and rearrange legal rights that existed on a certain day in the
past.”Intermountain Wind Reply at 4.NIPPC contends that a December 14 effective date
“violates the filed rate doctrine and the prohibition against retroactive ratemaking.”NIPPC
Comments at 8.
Commission Staff asserts that,although large wind projects are not inherently
undesirable,the disaggregation of multiple,affiliated QFs seeking to qualify for published rate
contracts raises concerns.Staff contends that “considering each 10 aMW QF individually for
purposes of eligibility for [publishedi avoided cost rates creates an artificial mismatch between
the method used to establish a project’s avoided cost rates and the collective size of the project.”
Staff Comments at 4.Staff emphasizes that,“[w]hen large QFs are added to a utility’s
renewable portfolio,but the QFs disaggregate in order to qualify for the published rate,the
avoided cost paid to the QF becomes inaccurate,because under the published rate methodology,
there’s no mechanism to reflect the utility’s reduced avoided cost.”Tr.at 88.Staff further
maintains that obligating utilities to accept generation that they do not need unnecessarily
increases the rates paid by the utilities’customers.Staff Comments at 5.Staff insists that the
problem described by the utilities is real and requires immediate attention.
DISCUSSION AND FINDINGS
The Idaho Public Utilities Commission has jurisdiction over this matter pursuant to
the authority and power granted it under Title 61 of the Idaho Code and the Public Utility
Regulatory Policies Act of 1978 (PURPA).The Commission has authority under PURPA and its
implementing regulations of FERC to set avoided costs,to establish standard published avoided
ORDER NO.32176 8
cost rates,to order electric utilities to enter into fixed-term obligations for the purchase of energy
from QFs,and to implement FERC regulations.
Based upon the record,the Commission finds that a convincing case has been made
to temporarily reduce the eligibility cap for published avoided cost rates from 10 aMW to 100
kW for wind and solar only while the Commission further investigates the implications of
disaggregated QF projects.4 We maintain the eligibility cap at 10 aMW for QF projects other
than wind and solar (including but not limited to biomass,small hydro,cogeneration,
geothermal,and waste-to-energy).The Petitioners have not convinced us that lowering the
eligibility cap for these other QF technologies is necessary or in the public interest.
Wind and solar resources present unique characteristics that differentiate them from
other PURPA QFs.Wind and solar generation,integration,capacity and ability to disaggregate
provide a basis for distinguishing the eligibility cap for wind and solar from other resources.
Furthermore,these intermittent resources must be “firmed”by ancillary services to assure system
reliability.Temporarily reducing the eligibility cap for wind and solar while we continue our
investigation,will still allow wind and solar projects larger than 100 kW to negotiate avoided
cost rates using the IRP Methodology.
Lowering the cap to 100 kW does not change the published avoided cost rates
established in Order No.31025 (March 16,2010).The published rate for wind and solar QFs
will still be available for projects 100 kW or smaller and as we have stated previously,will be
the starting point for negotiating an avoided cost rate for larger wind and solar QF projects.
At a minimum,FERC regulations require that standard or published rates be set for
purchases from QFs with a design capacity of 100 kW or less,These regulations also grant the
Commission the discretion to set the published rate eligibility cap at a higher level.18 C.F.R.§
292.304(c).Whether it is a published rate or a rate for a larger QF,FERC requires that the
avoided cost rates for all QF purchases be just and reasonable to utility customers and in the
public interest;and not discriminate against qualifying cogeneration and small power production
facilities.18 C.F.R.§292.304(a)(l).In establishing a published rate,the Commission may
differentiate among QFs using various technologies on the basis of supply characteristics of the
different technologies;the availability of capacity and energy during daily and seasonal peaks;
“Other avoided cost issues identified in the Joint Petition,including utilization and/or modification of the JRP
Methodology,will be considered after a determination regarding disaggregation.
ORDERNO.32176 9
dispatchability;reliability;and other factors.18 C.F.R.§292.304(c)(3);In re California FUC,
Order Granting Clar/Ication and Dismissing Rehearing,133 FERC ¶61,059 (October 21,2010)
at ¶23.Contrary to NIPPC’s assertions,FERC rules insist that rates for purchases from QFs be
just and reasonable to ratepayers and in the public interest —not in the interest of the QFs.
This Commission established a clear and reasoned distinction between small and
large QFs in 1995 when it adopted the use of the IRP methodology for larger QFs.Order Nos.
25882,25883,25884.The Commission explained that requiring larger QF projects “to prove
their viability by market standards ensures that utilities will not be required to acquire resources
priced higher than would result from a least cost planning [RFPJ process.Ratepayers will not be
disadvantaged and QFs will be treated fairly and consistently with the requirements and goals of
PURPA.”Id.at 6.The purpose,then and now,of distinguishing between small and large QFs
with the application of the IRP methodology for large QF projects is to more precisely value the
energy being delivered —not encourage or discourage QF resources.
We note that parties have challenged the accuracy of the IRP Methodology.We
believe that the IRP Methodology appropriately assesses when the QF is capable of delivering its
resources against when the utility is most in need of such resources.The resultant pricing is
reflective of the value of QF energy to the utility.Unfortunately,the IRP Methodology is being
under-utilized because our Orders do not currently prevent QF developers from breaking up what
is truly a single,large project into several small QF projects in order to avail themselves of what
may sometimes be more favorable,published avoided cost rates.
Based on the foregoing,the Commission temporarily reduces the eligibility cap for
published avoided cost rates from 10 aMW to 100 kW for wind and solar resources only,
effective December 14,2010.Arguments that the Commission is without authority to implement
its eligibility cap reduction on December 14 are unpersuasive for several reasons.First,the filed
rate doctrine and rule against retroactive ratemaking do not extend “to cases in which Iparties]
are on adequate notice that resolution of some specific issue may cause a later adjustment to the
rate being collected at the time of service.”Natural Gas Clearinghouse v.FERC,965 F.2d
1066,1075 (D.C.Cir.1992).“The goals of equity and predictability are not undermined when the
Commission warns all parties involved that a change in rates is only tentative and might be
disallowed.”OXY USA,Inc.v.FERC,64 F.3d 679,699 (D.C.Cir.1995).The Commission
provided notice on December 3,2010,that its decision regarding the published avoided cost rate
ORDERNO.32176 10
eligibility cap would become effective December 14,2010.One need look no further than the
abundance of firm energy sales agreements filed with the Commission within that time frame to
realize that the parties took the Commission’s notice of its effective date seriously.
Consequently,adequate notice was provided to all parties that the eligibility cap was subject to
change.
Second,as previously mentioned,the published avoided cost rates established in
Order No.31025 have not changed.What has temporarily changed is the availability of
published rates to wind and solar QFs.Wind and solar projects larger than 100 kW are still
entitled to PURPA contracts and avoided cost rates that reflect the unique characteristics of their
resource.
This Commission is supportive of all small power producers contemplated by
PURPA,including wind and solar,and it is not the Commission’s intent to push small wind and
solar QF projects out of the market.With this goal in mind,the Commission is initiating
additional proceedings to investigate and determine in a finite timeframe requirements by which
wind and solar QFs can obtain a published avoided cost rate without allowing large QFs to
obtain a rate that is not an accurate reflection of a utility’s avoided cost for such projects.It is
just and reasonable and in compliance with the intent and mandate of PURPA that large QF
projects avail themselves of economies of scale.Such an approach will assist the Commission in
fulfilling its obligations under PURPA.
The Commission directs the parties to meet informally within 10 days of the issuance
of this Order to establish an expedited schedule,including dates for discovery,prefiled direct
testimony and rebuttal that will accommodate a technical hearing during the week of May 9,
2011.Specifically,the Commission solicits information and investigation of a published
avoided cost rate eligibility cap structure that:(1)allows small wind and solar QFs to avail
themselves of published rates for projects producing 10 aMW or less;and (2)prevents large QFs
from disaggregating in order to obtain a published avoided cost rate that exceeds a utility’s
avoided cost.
ORDER
IT IS HEREBY ORDERED that the Petitioners’Motion to reduce the eligibility cap
for published avoided cost rates is granted in part and denied in part.The Commission
temporarily reduces the eligibility cap for published avoided cost rates from 10 aMW to 100 kW
ORDERNO.32176 11
for wind and solar QFs only,effective December 14,2010.The Petitioners’Motion to reduce
the published eligibility cap for other QFs is denied.
IT IS FURTHER ORDERED that NIPPC’s request for the Commission to take
official notice of our Notices and Orders is granted and the request regarding the other
documents is denied as set out above.
IT IS FURTHER ORDERED that the parties meet informally within 10 days of the
issuance of this Order to establish a schedule consistent with a technical hearing to occur during
the week ofMay 9,2011.The Commission directs the parties to address disaggregation,as more
fully described above.
THIS IS A FINAL ORDER.Any person interested in this Order may petition for
reconsideration within twenty-one (21)days of the service date of this Order.Within seven (7)
days after any person has petitioned for reconsideration,any other person may cross-petition for
reconsideration.See Idaho Code §6 1-626.
DONE by Order of the Idaho Public Utilities Commission at Boise,Idaho this
day of February 2011.
6OPEN
6L2 tfS5ZL
MARSHA H.SMITH,COMMISSIONER
AEFEST:
Jh D.JeweJAJ
Commission Secretary
O:GNR-E-I 0-04_ks_Final
MACK A.
ORDER NO.32176 12
EXHIBIT 3
IDAHO PUC ORDER NO.32212
Office of the Secretary
Service Date
March 28,2011
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE JOINT )
PETITION OF IDAHO POWER COMPANY,)CASE NO.GNRE-1O-04
AVISTA CORPORATION,AND )
PACIFICORP DBA ROCKY MOUNTAIN )
POWER TO ADDRESS AVOIDED COST )ORDER NO.32212
ISSUES AND TO ADJUST THE PUBLISHED )
AVOIDED COST RATE ELIGIBILITY CAP.)
________________________________________________________________________________
)
On February 7,2011,the Commission issued final Order No.32176 temporarily
reducing the eligibility cap for published avoided cost rates from 10 average megawatts (aMW)
to 100 kilowatts (kW).On February 28,2011,the Northwest and Intermountain Power
Producers Coalition (NIPPC or Coalition)filed a timely Petition for Reconsideration.
NIPPC requests that the Commission issue an order granting reconsideration of Order
No.32176 by:(1)taking official notice of the documents and records cited by NIPPC during oral
argument and in its petition;(2)holding an evidentiary hearing on the issues addressed in Order
No.32176;(3)requiring the utilities to immediately implement changes to the Integrated
Resource Planning (IRP)Methodology and calculate new avoided cost rates;and (4)reinstating
the 10 aMW eligibility cap for the published avoided cost rates for wind and solar qualifying
facilities (QFs).
Idaho Power Company,Avista Corporation,and PacifiCorp dba Rocky Mountain
Power all filed timely Answers urging the Commissin to deny reconsideration on the latter three
issues.They did not address the official notice issue.Based upon our review of the Petition for
Reconsideration,the Answers and our record,we partially grant reconsideration and partially
deny reconsideration as set out in greater detail below.
BACKGROUND
On November 5,2010,the three utilities filed a Joint Petition requesting that the
Commission initiate an investigation to address various avoided cost issues related to the
Commission’s implementation of the Public Utility Regulatory Policies Act of 1978 (PURPA).
While the investigation is under way,the Petitioners also moved the Commission to “lower the
published avoided cost rate eligibility cap from 10 aMW to 100 kW [to]be effective
immediately....“Petition at 7.
ORDER NO.32212
After reviewing the Joint Petition and the Answers,the Commission declined the
Motion to immediately reduce the eligibility cap for the published avoided cost rates.Instead,
the Commission determined that it would expeditiously consider the Petitioners’request to
reduce the eligibility cap through the use of “Modified Procedure”(written comments)’and oral
argument.The Notice established an intervention deadline of December 17,2010;set deadlines
for initial comments and reply comments of December 22,2010,and January 19,2011,
respectively;and scheduled an oral argument for January 27,2011.Order No.32131.
The Commission specifically requested written comments and oral argument
regarding three issues:(1)the advisability of reducing the published avoided cost eligibility cap;
(2)if the eligibility cap is reduced,the appropriateness of exempting non-wind qualifying facility
(QF)projects from the reduced eligibility cap;and (3)the consequences of dividing larger wind
projects into 10 aMW projects to utilize the published rate.The Commission also communicated
its intent to consider the other avoided cost issues identified by the Petitioners and other
interested parties in subsequent proceedings.Id.at 5.
Written comments and reply comments were submitted by numerous parties.Oral
argument was held on January 27,2011.Based upon the record,the Commission found that a
convincing case had been made to temporarily reduce the eligibility cap for published avoided
cost rates from 10 aMW to 100 kW but only for wind and solar QFs.The Commission also
decided to open a new investigation into the implications of disaggregated QF projects.See Case
No.GNR-E-1 1-01;Order No.32176 at 11.NIPPC requests reconsideration from final Order
No.32176.
ISSUES ON RECONSIDERATION
A.Legal Standards
Reconsideration provides an opportunity for a party to bring to the Commission’s
attention any question previously determined and thereby affords the Commission with an
opportunity to rectify any mistake or omission.Washington Water Power Co.v.Kootenai
Environmental Alliance,99 Idaho 875,879,591 P.2d 122,126 (1979).The Commission may
grant reconsideration by reviewing the existing record,by written briefs,or by evidentiary
hearing.IDAPA 31.01.01.332.If reconsideration is granted,the Commission must complete its
In instances where the public interest may not require a formal hearing to consider the presented issues,“the
proceeding may be processed under modified procedure,i.e.,by written submissions rather than by hearing.”Rule
201,IDAPA 3 1.01.01.201.
ORDER NO.32212 2
reconsideration within 13 weeks after the deadline for filing petitions for reconsideration.Idaho
Code §61-626(2).
Consistent with the purpose of reconsideration,the Commission’s Procedural Rules
require that petitions for reconsideration “set forth specifically the ground or grounds why the
petitioner contends that the order or any issue decided in the order is unreasonable,unlawful,
erroneous or not in conformity with the law.”Rule 331.01,IDAPA 31.01.01.331.01.Rule 331
further requires that the petitioner provide a “statement of the nature and quantity of evidence or
argument the petitioner will offer if reconsideration is granted.”Id.
B..Taking Official Notice
At oral argument,NIPPC distributed a document entitled “Request for Official
Notice”and asked the Commission to take official notice of a host of documents listed in the
“Request”including approximately 14 PUC Orders,several FERC orders and notices,and the
“Filings,Testimony,Exhibits and Orders”in 24 different PUC dockets.The case caption or title
(i.e.,the case description)of each PUC Order and PUC case was not provided.In addition,
NIPPC orally asked the Commission to take official notice of “three documents related to coal
costs that support our comments.”Tr.at 7.NIPPC’s counsel described the three documents as
follows:
One is the settlement agreement that the Environmental Protection Agency
reached with the parties in the final rulemaking.The other is the Oregon
Senate Natural Resources Committee report on greenhouse gas emissions,and
the final is Rocky Mountain Power’s parent corporation’s the MidAmerican
Holdings Company,comments in the Coal Combustion Residual Rulemaking,
all of which support our comments related to the ability of renewable energy
projects to allow the utilities to reduce generation from coal-fired power
plants allowing them to —actually,it impacts the avoided cost rate and the
cost of renewable energy.
Tr.at 7-8 (emphasis added).In response,the Chairperson of the hearing then asked:
Commissioner Smith:Well,Mr.Richardson,I’m getting confused because
this is not a proceeding today to argue about the cost.I mean,the
Commission clearly outlined in its Order that we wanted comments on three
things:the advisability of reducing the eligibility cap;if the eligibility cap is
reduced,the appropriateness of exempting non-wind QF projects from that
reduced eligibility cap;and the consequences of dividing larger wind projects
into 10 average megawatt projects in order to take advantage of the published
avoided cost rate.
ORDER NO.32212 3
Mr.Richardson:...As pointed out in our comments,the advisability of
reducing the eligibility cap is crucial to understanding what happens when the
eligibility cap is reduced,meaning the integrated resource procedure,process
is used by all three utilities and that process does not calculate an accurate or
even nearly accurate avoided cost rate.
Commissioner Smith:On your motion for the Commission to take official
notice,I will note that I believe,...We can take official notice afier giving
parties appropriate opportunity to respond,so I think your passing this
[Request]out gives people notice of what you want us to take notice of and
certainly we can take notice of [(1)1 our own orders and those of any other
regulatory agency,state or federal,[(2)]matters of common knowledge,
technical,financial or scientific facts,matters judicially noticeable and[,(3)]
data contained in periodic reports of regulated utilities filed with the
Commission or federal agencies.So as long as they fall within one of those
categories,there’s no problem with us taking notice.
Mr.Richardson:Thank you,Madam Chairman,and I believe all of the points
that have been cited in our motion fall into those categories.
Tr.at 8-10 (scattered,emphasis added).No party voiced objection to NIPPC’s request.
In final Order No.32176,the Commission acknowledged taking official notice of its
own Notices and Orders,but the Commission denied “NIPPC’s request to take official notice of
the remainder of its listed documents,including the three additional documents regarding coal
costs.”Order No,32176 at 5,2 The Commission noted that its Rule 263 (IDAPA 3 1.01.01.263)
distinguishes between when it takes official notice on its own motion,and when parties request
that the Commission take official notice.Rule 263.02.The Commission explained that when
parties seek official notice they “must submit those documents to the Commission in the manner
prescribed for documents in Rule 262.”The Commission declined to take judicial notice of the
requested documents (other than the Commission’s own Notices and Orders)primarily for two
reasons.First,NIPPC did not actually provide copies of the requested documents to the
Commission or parties as required by Rule 263.02.Order No.32176 at 5.Second,the
2 The presiding officer’s ruling on motions presented at hearing “may be reviewed by the full Commission in
determining the matter on its merits.”Rule 253,IDAPA 3101.01.253.
Rule 262 generally provides that documentary evidence is to be submitted in the form of copies or excerpts.
“When a party offers in evidence any portion of a transcript,exhibit,or other record from any other proceeding
before the Commission,the portion offered must be specifically described..“IDAPA 31.01.01.262.
ORDER NO.32212 4
Commission found that the majority of the “filings,testimonies and exhibits”in the PUC cases
listed in NIPPC’s Request were not “documents or information subject to official notice per Rule
263.”Id.
In its Petition for Reconsideration,NIPPC requests that the Commission take official
notice of all the items listed in its request as well as the “three documents related to coal costs.”
Tr.at 7;Petition at 5-6.Citing Idaho Rule of Evidence 201,NIPPC asserts that “filings in the
Commission dockets are judicially noticeable,and therefore fall within the confines of Rule
263.”NIPPC maintains that because a court may take judicial notice of records in cases before
the trial court,“there is no reason the Commission may not do the same for records in its own
proceedings.”Id.at 6;citing Larson v.State,91 Idaho 908,909,435 P.2d 248,249 (1967).The
Coalition also argues that failing to take official notice of the requested documents is particularly
unfair in this case because NIPPC was precluded from calling a witness to introduce these
documents.“At a minimum,therefore,the Commission should reconsider its decision,and take
official notice of the FERC orders.”Petition at 5.
Commission Findings:After reviewing NIPPC’s Petition and our record,we grant
reconsideration in part and deny reconsideration in part.We grant the Coalition’s request to take
official notice of those FERC filings,rules,and orders listed in its “Request”that was handed out
at the oral argument.Although NIPPC did not comply with that provision of Rule 263 that
requires the party requesting official notice to supply copies of the documents to the Commission
and other parties,we note that most of the FERC documents were cited in NIPPC’s comments.
Taking official notice of documents in our proceedings is an exercise of discretion.
When reviewing an exercise of discretion,our Supreme Court considers whether the
Commission:(1)correctly perceived the issue as one of discretion;(2)acted within the
boundaries of such discretion and consistently with applicable legal standards;and (3)reached
its decision by an exercise of reason,Sun Valley Shopping Ctr.v.Idaho Power Co.,119 Idaho
87,94,803 P.2d 993,1000 (1991);Newman v.State,149 Idaho 225,233 P.3d 156 (Ct.App.
2010).
We deny reconsideration regarding the request to take official notice of the “Filings,
Testimony,[and]Exhibits”that pertain to the 24 PUC cases identified only by case number.
Despite NIPPC’s declaration to the contrary,all the “Filings,Testimony,and Exhibits”of the 24
PUC cases are not admissible for two reasons.First,all filings,testimony and exhibits in the
ORDERNO.32212 5
PUC cases are not the types of facts that are subject to official or judicial notice.Our Rule 263 is
similar to Idaho Rule of Evidence 201 (“Judicial Notice of Adjudicatory Facts”).Although the
Idaho Rules of Evidence do not apply to Commission proceedings,Idaho Code §6 1-601,the
concepts of taking notice are similar.I.R.E.201 provides that a “judicially noticed fact must be
(1)not subject to reasonable dispute in that it is either (1)generally known within the territorial
jurisdiction of the trial court or (2)capable of accurate and ready determination by resort to
sources whose accuracy cannot reasonably be questioned.”I.R.E.201(b)(emphasis added).
Similar to our Procedural Rule 263.02,LR.E.201(d)provides that the party seeking the court to
take judicial notice of “records,exhibits or transcripts from the court file in the same or a
separate case,...shall identify the specific document or item ...and serve on all parties copies
of such documents or items.”We find the purpose behind the requirement of providing copies of
the documents for which a party seeks official notice is to provide the Commission with all
relevant information of the documents.This includes the actual documents themselves.
In examining NIPPC’s reconsideration request,we need look no further to determine
whether it was appropriate to take official notice of the filings,testimony and exhibits in the
PUC cases,than the recent Rocky Mountain rate case No.PAC-E-10-07.This case contains
nearly 3,000 pages of transcript from 47 technical witnesses and approximately 100 public
witnesses.There were about 240 public comments (“filings”)in the case.The subject of these
documents and the testimony range from:simple opposition to the proposed rate increase to
keeping Monsanto’s rates low;from the weatherization program for low-income customers to the
appropriate return on equity;and from a conservation program for irrigators to calculating the
value of”interruptibility”for Monsanto.
After reviewing the filings,testimony and exhibits of the PacifiCorp rate case,we
find the one thing that these documents and testimony have in common is that they are disputed
facts.We find that many of the documents and testimony are subject to reasonable dispute and
do not contain the types of facts that are undisputed matters of common knowledge or facts
capable of accurate and ready determination by resort to sources whose accuracy cannot
reasonably be questioned.Rule 263.01(b)and I.R.E.201(b);Martin v.Camas County,
Idaho ,—P.3d —,2011 WL 538750 (Idaho 2011);Santa Monica Food Not Bombs v.City
ofSanta Monica,450 F.3d 1022,1025 n.2 (9th Cir.2006).
ORDER NO.32212 6
The second reason to deny reconsideration is that NIPPC failed to show how the
“filings,testimony and exhibits”of the 24 PUC cases were relevant to our inquiry in this case.
Although the Commission may officially notice a variety of documents and adjudicatory facts,
only relevant material may be noticed and admitted into evidence.In other words,for us to take
official notice of documents and other facts,the evidence must be relevant to be admissible.
State v.Van Sickle,120 Idaho 99,103,813 P.2d 910,914 (Ct.App.1991);I.R.E.401.Even “if
taking judicial notice of the [documents]is otherwise proper,the question remains whether the
[documents]noticed were relevant”to the inquiries before the Commission.Caflfornia v,
Superior Court of California,482 U.S.400,408,107 S.Ct.2433,2439 (1987);see Cuellar v.
Joyce,596 F.3d 505,512 (9th Cir.2010);Santa Monica,450 F.3d at 1025 n.2;Flick v.Liberty
Mut.Ins.Co.,205 F.3d 386,393 (9th Cir.2000).
Again examining the filing,testimony and exhibits in the Rocky Mountain rate case,
we find many if not all of the requested documents and testimony have no bearing or relevancy
to the avoided cost issues in this proceeding.Consequently,we find that NIPPC has failed to
meet its burden of demonstrating that the filings,testimony and exhibits of the 24 PUC cases are
noticed facts appropriate for official notice and relevant to the matters in this case.Our findings
are consistent with the applicable legal standards for admission of judicially noticeable facts
under Idaho law.Newman,149 Idaho at 227,233 P.3d at 158;I.R.E.201(b).4
We next turn to the three coal cost documents.Even though these documents may
properly be the subject of official notice,5 they are not relevant to the three questions posed by
the Commission in this proceeding.As Commissioner Smith noted at the hearing,“This is not a
proceeding today to argue about the [avoided]cost.I mean,the Commission clearly outlined in
its order that we wanted comments on three things:the advisability of reducing the eligibility
cap;...the appropriateness of exempting nonwind QF projects from the reduced eligibility cap;
and the consequences of dividing larger wind projects into 10 average megawatt projects...
In its official notice request,NIPPC lists 16 PUC cases that are Firm Energy Sales Agreements between Idaho
Power and various QFs.NJPPC references the 16 PUC cases in a footnote in its reply comments.Reply at 17,n.9,
The footnote pertains to NIPPC comments regarding the calculation or comparison of avoided cost rates.While we
take official notice of the Orders and Notices in these cases,we find that the Coalition failed to demonstrate the
relevancy of the “flies,testimony and exhibits”in these cases.Moreover,the footnote containing the reference to
these cases relates to avoided costs —an issue we find that is beyond the scope of this docket
Two were issued by regulatory agencies and the “Settlement”was entered into by a regulatory agency (EPA)and
various States.
ORDER NO.32212 7
Tr.at 8.Mr.Richardson described them as “three documents related to coal costs that support
our comments.”Tr.at 7.
In NIPPC’s reply comments,the Coalition links the coal documents to alleged
shortcomings of the IRP Methodology in accurately reflecting avoided costs.Reply Comments
at 8,2 1-25.However,the alleged impact of coal costs on the use of the JRP Methodology in
calculating avoided costs was not part of the GNR-E-10-04 case.In Order No.32176,we stated
that we are not changing the avoided cost rates:lowering the eligibility cap “does not change the
published avoided cost rates established in Order No.31025 (March 16,2010).”Order No.
32176 at 9.To put it simply,we find that the issues of coal costs and their relationship to the
IRP Methodology is beyond the subject matter of this case.Our final Order No.32176 states the
issues concerning “the IRP Methodology will be considered after a determination regarding
disaggregation”in the GNR-E-1 1-01 case.Order No.32176 at n.4 (emphasis added);see also
n.3.
In the disaggregation case (GNR-E-l 1-01)we recently issued a Bench Order
regarding a party’s discovery dispute with NTPPC.In our Bench Order we found that the issue
of using the IRP Methodology to calculate avoided costs “is specifically reserved for a
subsequent proceeding.”“Thus,we find that evidence regarding the IRP Methodology is beyond
the scope of the [GNR-E-1 1-011 case and thus not relevant Bench Order at 1-2 (March 23,
2011).As explained more fully below,the issues of the IRP Methodology will be examined in a
subsequent case.
Thus,we find that the three coal documents are not relevant to our inquiry in this
case.In addition,we further find that NIPPC has failed to meet its burden of showing that
MidAmerican’s comments (the holding company of PacifiCorp)is not subject to reasonable
dispute.Martin,201 WL 538750;I.R.E.20 1(b);Santa Monica,450 F.3d at 1025 n.2.
In summary,we grant reconsideration and take official notice of those FERC filings,
rulings and orders set out in NIPPC’s request.We deny reconsideration regarding the “Filings,
Testimony,[and)Exhibits”for the 24 PUC cases cited in the request.Finally,we deny
reconsideration to take official notice of the three coal cost documents as not relevant and
beyond the scope of this proceeding.
ORDER NO.32212 8
C.The Requestfor a Technical Hearing
NIPPC next contends that,by denying its request for a “technical”hearing to present
witnesses,the Commission did not allow NIPPC to establish an evidentiary record.NIPPC
further argues that,because the Commission’s decision was based on factual findings,“the
Commission must hold an evidentiary hearing.”Petition at 7.NIPPC alleges that due process
would require the Commission to conduct an evidentiary hearing and that “the Commission’s
order is indefensible without at least some evidence supporting the relief granted to the Utilities.”
Id.at 8-9.
Utilities ‘Answers
Idaho Power argues that NIPPC received notice and had an opportunity to be heard.
Idaho Power further states that a technical hearing is not required for the Commission to make
factual findings.Rule of Procedure 201,IDAPA 31.01.01.201.Idaho Power argues that “[tjhe
standard of review as to whether the Commission has made valid findings of fact is not whether
a technical/evidentiary hearing was held.The standard of review is whether those findings of
fact are supported by substantial and competent evidence in the record.”Answer at 5.The
utility observed that discovery was available to all parties and that NIPPC propounded extensive
discovery of the Joint Petitioners.Answer at 3.All parties were able to file direct and rebuttal
comments and participate at oral argument.Ultimately,Idaho Power argues that the
Commission’s decision was a proper exercise of its discretion in its implementation of PURPA.
Id.at 19.
Avista maintains that NIPPC’s request for an evidentiary hearing should be denied as
moot.Avista notes that Case No.GNR-E-11-01,the subsequent (or second)phase of the
Commission’s avoided cost investigation,provides for a technical hearing.Because,
presumably,the GNR-E-1 1-01 technical hearing will provide an opportunity for NIPPC to
present witnesses and testimony,its request for a technical hearing during reconsideration of the
first phase is moot.Answer at 4.
Rocky Mountain Power asserts that the Commission was not required to conduct a
technical hearing prior to reducing the eligibility cap for published avoided cost rates.Rocky
Mountain further notes that in a similar case the California PUC supports the Idaho
Commission’s decision to reduce the eligibility cap without an evidentiary hearing.Answer at 4
citing 1996 Cal.PUC LEX1S 1016*4445.
ORDER NO.32212 9
Commission Findings:NIPPC cites Intermountain Gas Co.v.Idaho PUC,97 Idaho
I 13,540 P.2d 775,for its proposition that a hearing is required.However,the Intermountain
Gas case expressly approved the use of written comments (i.e.,submissions)in gathering
evidence.The Court states,“[tjhe procedure chosen by the Commission must of course give the
parties fair notice of exactly what the Commission proposes to do,together with an opportunity
to comment,to object,and to make written submissions;and the final order of the Commission
must be based upon substantial evidence.”Intermountain Gas,97 Idaho at 129,540 P.2d at 791
(1975)(emphasis added),citing,American Public Gas Asso.v.Federal Power Comm.,162
U.S.App.D,C.176,498 F.2d 718,722 (1974).
In American Public Gas the D.C.Circuit held that the Federal Power Commission
(FPC)6 is not required to process all cases coming before it with formal hearings,to include
witnesses and cross examination.“Evidentiary submissions in written form may be sufficient.”
498 F.2d at 180.The Circuit Court further explained that:
The ability [of the FPCJ to choose with relative freedom the procedure it
will use to acquire relevant information gives the Commission power to
realistically tailor the proceedings to fit the issues before it,the information it
needs to illuminate those issues and the manner of presentation which,in its
judgment,will bring before it the relevant information in the most efficient
manner.
The procedure chosen by the Commission must of course give the parties
fair notice of exactly what the Commission proposes to do,together with an
opportunity to comment,to object,and to make written submissions;and the
final order of the Commission must be based upon substantial evidence.
Id at 723 (emphasis added),citing City of Chicago v.FPC,458 F.2d 731,743-44 (D.C.Cir.
1971),cert denied,405 U.S.1074,92 S.Ct.1495 (1972).
In this case,the Commission provided notice to NIPPC and other interested persons
by publishing its Notice of Joint Petition and by personally serving NIPPC with the Notice.
NIPPC submitted both initial comments and reply comments in this case.NIPPC also actively
participated at oral argument.NIPPC’s comments and exhibits,along with those of the
numerous other parties to the case,make up the evidentiary record considered by the
Commission prior to issuing its final Order.
6 The FPC is now the Federal Energy Regulatory Commission (FERC).
ORDER NO.32212 10
A Ninth Circuit case reviewing a decision by the Interstate Commerce Commission
(ICC)is also instructive.In Amador Stage Lines,Inc.v.United States and Interstate Commerce
Comm.,685 F.2d 333 (9 Cir.1982),the ICC utilized modified procedure to consider an
application filed by Quality Coach Lines,to operate as a carrier of passengers within the United
States.Amador and other carriers opposed Quality’s application and requested oral hearing on
their objections.Amador argued that “where material facts are in dispute principles of
administrative due process and fundamental fairness require that the Commission hold a
hearing.”685 F.2d at 335.The Ninth Circuit reasoned that the Commission “in its discretion
may deny an oral hearing even where material facts are disputed so long as the disputes may be
adequately resolved by the written submissions.”Id.(emphasis added).
The Commission’s Rules of Procedure allow for the use of Modified Procedure,i.e.,
the consideration of issues based on written submissions (i.e.,comments)rather than by hearing.
Rule 201,IDAPA 3 1.01.01.201.Even if a hearing is requested,the Commission “may decide
the matter and issue its order on the basis of the written positions before it.”Rule 204,IDAPA
31.01.01.204 (emphasis added).Here the Commission acted within its discretion when it
determined to gather evidence by written submissions.
The Commission did not issue its decision regarding QF eligibility to published
avoided cost rates without a thorough review of the evidentiary record established in this case
through the use of Modified Procedure,All parties had an opportunity to submit comments,
reply to comments,and assert and defend a position at oral argument.Based upon the
evidentiary record provided by the parties,the Commission determined “that a convincing case
has been made to temporarily reduce the eligibility cap for published avoided cost rates from 10
aMW to 100 kW for wind and solar only while the Commission further investigates the
implications of disaggregated QF projects.”Order No.32176 at 9;American Public Gas.
Sufficient notice of exactly what the Commission was considering was provided to
allow all interested parties an opportunity to participate.Ample opportunity was given for the
parties to provide evidence in support of their positions.The Commission utilizes Modified
Procedure for the majority of cases that it considers.Modified Procedure has proven to be an
effective means for obtaining public input and participation in cases.NIPPC has failed to
demonstrate that the Commission’s decision to process the issues presented in GNR-E-10-04
through the use of Modified Procedure was unreasonable or unlawful.There is substantial and
ORDER NO.32212 11
competent evidence in the record to support the Commission’s findings.In re Ryder,141 Idaho
918,120 P.3d 736 (2005).Moreover,NIPPC has not proven that its position could not be
adequately presented in writing.Consequently,we deny reconsideration on this issue.
D.The Issue ofthe IRP Methodology
NIPPC argues that federal law requires that the utilities contract with each QF at the
“full avoided cost rates.”Petition at 13.NIPPC states that the IRP Methodology violates federal
law by dramatically understating actual avoided costs and producing “wildly inaccurate results.”
Id at 11.NIPPC maintains that the Commission’s failure to address NIPPC’s assertions “is
nothing short of arbitrary....“Id NIPPC further argues that the utilities “have not provided
enough data for QFs to properly vet the individually provided [IRP Methodology]results,and
are hence in violation of the 18 C.F,R.292.302(b)by failing to provide for public inspection of
basic system cost data listed in the regulation.”Id.at 12.Finally,NIPPC claims that “{i]f the
rates for the IRP Methodology were accurate and verifiable to the QFs,there would be no need
to disaggregate an otherwise larger project into smaller projects to obtain the fair rate at which
the project would be financially viable.”Id.at 13.
Utilities ‘Answers
Idaho Power maintains that NIPPC’s assertions regarding the flaws of the IRP
Methodology are erroneous.IRP calculations do take into account both capacity and energy.
Idaho Power also asserts that NIPPC’s representations regarding “full avoided costs”are
illusory.PURPA and FERC make no reference to a QF’s entitlement to “full”avoided costs.
Moreover,Idaho Power argues there is “nothing in the regulations to suggest that the IRP
methodology does not comport with FERC rules.”Answer at 16.
Avista argues that NIPPC’s request for immediate changes to the IRP Methodology is
beyond the scope of this proceeding.Avista notes that NIPPC claims “the record in this docket
contains no evidence whatsoever”but then goes on to claim that it has proven that the IRP
Methodology produces wildly inaccurate results.Answer at 5.“Simply stated,NIPPC cannot
have it both ways.”Id.
Rocky Mountain Power states that NIPPC’s request to review the IRP Methodology
should be denied as beyond the scope of these proceedings.Answer at 5.“If NIPPC wishes to
challenge the adequacy of the IRP Methodology,the proper avenue for doing so is to file a
separate petition with the Commission.Such action is not necessary here,however,because the
ORDERNO.32212 12
Commission has already stated that it will address concerns over the IRP Methodology after the
Commission has an opportunity to investigate and make a determination regarding
disaggregation.”Id.
Commission Findings:Use of an IRP methodology was first proposed by the
utilities for QF projects in excess of the Commission’s stated eligibility for published rates in
1995.As originally proposed,
the utility would determine through its least cost planning model [IRP
process]the cost of meeting load over the next 20 years.Whenever a
proposed QF project were [sic]offered to the utility,it would insert the
generation and capacity of that project into the model and determine what
costs would be avoided over the 20 year period,That avoided cost would be
the rate available to the developer.
Order No.25882 at 6.The intervenors to the 1995 case opposed the IRP Methodology for
calculation of QF avoided cost rates “contending that it places too much control over the avoided
cost process into the hands of the utilities.”Id.Nevertheless,the Commissin determined that
adoption of the [IRP Methodology]is consistent with our goal of maintaining
a regulatory climate that allows our electric utilities to retain their
advantageous posture in a marketplace that is likely to become increasingly
competitive.This will ultimately work to the advantage of ratepayers in the
form of rates lower than they would otherwise be in effect.By treating QFs in
the same manner as utility acquired resources,we are further removing the
shelter that has been constructed around the QF industry.Requiring those
projects to prove their viability by market standards ensures that utilities will
not be required to acquire resources priced higher than would result from a
least cost planning [IRPI process.Ratepayers will not be disadvantaged and
QFs will be treated fairly and consistently with the requirements and goals of
PURPA.
Id.at 7.The Commission concluded that the least cost planning [IRP]process will provide the
most logical,consistent and frequent review of the avoided cost rates and the issues that are
raised in setting those rates.”Id.
This GNR -E-lO-04 docket began with the utilities’request that the Commission
reduce QF eligibility to the published rates.From the outset,NIPPC has argued that the IRP
Methodology is flawed and in violation of federal law.NJPPC asserts on reconsideration that
that the Commission must recalculate the avoided costs rates in this case.However,as
mentioned previously,the Commission has expressly stated that other avoided cost issues,
“including utilization and/or modification of the IRP Methodology will be considered after a
ORDERNO,32212 13
determination regarding disaggregation.”Order No.32176 n.4 (emphasis added).The GNR-E
10-04 docket was limited to the three issues set out in the initial Notice:(1)the advisability of
reducing the published avoided cost eligibility cap;(2)if the eligibility cap is reduced,the
appropriateness of exempting non-wind qualifying facility (QF)projects from the reduced
eligibility cap;and (3)the consequences of dividing larger wind projects into 10 aMW projects
to utilize the published rate.Order No.32131 at 5.
While the IRP Methodology is one of many avoided cost issues raised by the parties,
it is not at issue in the present docket.Attacking the IRP Methodology approved by the
Commission in 1995 and utilized for the past 16 years in an effort to stop the Commission from
reducing the eligibility cap for wind and solar QFs represents a collateral attack of the
Commission’s final Order adopting the IRP Methodology.See Order No.25882;Idaho Code §
61-625.If NIPPC desired to challenge the viability of the IRP Methodology,it could have
petitioned the Commission to open an investigation to evaluate the presently approved IRP
Methodology.Idaho Code §61-612;Asso.PacUic Movers,Housemovers,Inc.v.Rowley,97
Idaho 663,664,551 P.2d 618,620 (1976)(an application requesting that the Commission
rescind,alter or amend an order pursuant to Idaho Code §6 1-624 does constitute a collateral
attack of a Commission order).While the Commission acknowledged NIPPC’s challenge to the
IRP Methodology,we specifically stated that “the IRP Methodology appropriately assesses when
the QF is capable of delivering its resources against when the utility is most in need of such
resources.”Order No.32176 at 10.Moreover,the Commission intends to examine and address
NIPPC’s concerns in a subsequent case.Id.at 9.The Commission’s decision to examine the
various avoided cost issues raised by the parties in an orderly manner and on a case-by-case basis
is reasonable and within the Commission’s discretion.
Final Orders of the Commission are final and conclusive and not subject to collateral
attack.Idaho Code §61-625.“A different rule would lead to endless consideration of matters
previously presented to the Commission and confusion about the effectiveness of Commission
orders.”Utah-Idaho Sugar Co.v.Intermountain Gas Co.,100 Idaho 368,373,597 P.2d 1028,
1063 (1979).
NIPPC’s arguments regarding the IRP Methodology are outside the scope of this
docket and amount to an impermissible collateral attack of Commission Order No.25882.Until
such time as we initiate a proceeding to investigate the IRP Methodology and possibly set new
ORDERNO.32212 14
avoided cost rates,the current methodologies and the rates are in effect.Idaho Code §61-502.
Based on the foregoing,NIPPC’s request for reconsideration of a determination regarding the
IRP Methodology is denied.
E.Reinstate the 10 aMWPublishedAvoided Cost Rate
NIPPC argues that “[b]ecause the IRP Methodology,as currently implemented,
produces rates below the full avoided cost rates,the Commission should reconsider its decision
and raise the eligibility cap to 10 aMW so that it will be properly implementing PURPA for at
least some larger wind and solar QFs.”Id at 14.The utilities generally oppose NIPPC’s request
on reconsideration to reinstate the JO aMW published avoided cost rate for wind and solar.
Commission Findings:The Commission denies NIPPC’s request to reconsider the
Commission’s decision to temporarily reduce the eligibility cap for published avoided cost rates
from 10 aMW to 100 kW for wind and solar QFs.NIPPC’s request is based entirely on the
proposition that the IRP Methodology is unworkable and unreasonable.As noted above,the
Commission finds that the use of IRP Methodology is:(1)beyond the scope of this docket;(2)a
subject for a subsequent avoided cost proceeding after disaggregation;and (3)represents a
collateral attack on the Commission’s prior Order approving the use of the IRP Methodology in
setting avoided cost rates.
In final Order No.32176,the Commission clearly conveyed its intent that the reduced
eligibility cap be temporary,until issues regarding disaggregation could be resolved.We
directed parties to establish an expedited schedule for subsequent proceedings,culminating with
a technical hearing to be held the week of May 9,2011.Order No.32176 at 11.The
Commission specifically noted that other avoided cost issues,“including utilization andlor
modification of the IRP Methodology,will be considered a determination regarding
disaggregation.”Id.at 9 (emphasis added).
In addition,the Commission recently issued a Bench Order on March 23,2011,in
Case No.GNR-E-11-01 (the second phase of the avoided cost investigation)reiterating that
“evidence regarding the IRP Methodology is beyond the scope of the present case and thus is not
relevant to the subject matter of the pending case.”The Commission ordered that discovery
regarding the IRP Methodology be stayed,“but may be renewed in a subsequent case when the
Commission investigates the challenges to the IRP Methodology.”Bench Order at 2.There is
ORDERNO.32212 15
substantial and competent evidence to support the Commission’s decision to temporarily reduce
the eligibility cap for the published avoided cost rates.
ORDER
IT IS HEREBY ORDERED that Northwest and Intermountain Power Producers
Coalition’s Petition for Reconsideration is granted in part and denied in part.The Commission
partially grants reconsideration on the issue of official notice.We take official notice of FERC
filings,rules and orders as more fully set out in the body of this Order.We deny reconsideration
on the issue of taking official notice of the three coal documents and the filings,testimony,and
exhibits of the 24 PUC cases.
IT IS FURTHER ORDERED that Order No.32176 is amended to reflect that the
Commission takes official notice of the FERC documents pursuant to Idaho Code §6 1-624.
IT IS FURTHER ORDERED that reconsideration regarding NIPPC’s remaining
issues of a request for a technical hearing,the IRP Methodology issue,and reinstatement of the
10 aMW published avoided cost rate eligibility cap for wind and solar are denied.
THIS IS A FINAL ORDER ON RECONSIDERATION.Any party aggrieved by this
Order or other final or interlocutory Order previously issued in this Case No,GNR-E-10-04 may
appeal to the Supreme Court of Idaho pursuant to the Public Utilities Law and the Idaho
Appellate Rules.See Idaho Code §61-627.
ORDERNO.32212 16
DONE by Order of the Idaho Public Utilities Commission at Boise,Idaho this c2
day of March 2011.
JIM .KEMPTON,PRESI ENT
7A4Z4 1SLL
MARSHA H.SMITH,COMMISSIONER
MACK A.REDF ,MMISSIONER
ATTEST:
JAnD.Jewel{J
Commission Secretary
O:GNR-E-I O-O4ks Reconsideration
ORDERNO.32212 17
EXHIBIT 4
POWER PURCHASE AGREEMENT BETWEEN
CEDAR CREEK WIND AND PACIFICORP
ROCKY MOUNTAIN 201 South Main.Suite 2300
POWER Salt Lake Cftc Utah 84111
A1VIS4QNOf%O1
?IflIJ4NJ0 9:39
January8,2011
VIA OVERNIGHTDELIVERY
pi4 (—O(
Idaho Public Service Commission
472 W.Washington Street
P.O.Box 83720
Boise,Idaho 83720-0074
Attention:Jean D.Jewel!
Commission Secretary
RE:In the Matter of the Applications of Rocky Mountain Power for Approval of Power Purchase
Agreements Between Rocky Mountain Power and Cedar Creek Wind
Please fmd enclosed the original and seven (7)copies each of five separate Applications and
Power Purchase Agreements between Rocky Mountain Power under which Cedar Creek would
sell and Rocky Mountain Power would purchase electric energy generated from each of the five
Cedar Creek Wind projects (“Projects”)located in Bingham County,Idaho:
Nameplate Capacity Monthly Average MW
,Project Name Megawatt (MW)Delivery
v’Rattlesnake Canyon 27.6 9.4
Coyote Hill 27.6 9.4
North Point 27.6 9.8
Steep Ridge 25.2 9.8
Five Pine 25.2 9.4
Inquiries may be directed to Ted Weston,Idaho Regulatory Manager at [phone],or
Daniel Solander,Senior Counsel,at [phone].
V,cry Truly Yours,
MM/
Jeffrey K.Larsen
Vice President,Regulation
Enclosures
7ff!JAN10
IDAhC
UTiL1TPS
PROJECT
RATTLESNAKE CANYON
POWER PURCHASE AGREEMENT
BETWEEN
CEDAR CREEK WIND,LLC
Relating to RATTLESNAKE CANYON,a Wind Turbine Generation Project
a non-fueled,on-system,Intermittent Resource with Mechanical Availability Guarantee,
Idaho Qualifying Facility—1OaMW/Month or less
AND
PACIFICORP
Section 1:Definitions 1
Section 2:Term,Commercial Operation Date 9
Section 3:Representations and Warranties 13
Section 4:Delivery of Power;Availability Guaranty 15
Section 5:Purchase Prices 17
Section 6:Operation and Control 20
Section 7:Motive Force 23
Section 8:Generation Forecasting Costs 23
Section 9:Metering;Reports and Records 24
Section 10:Billings,Computations and Payments 26
Section 11:Security 27
Section 12:Defaults and Remedies 28
Section 13:Indemnification;Liability 31
Section 14:Insurance 32
Section 15:Force Majeure 33
Section 16:Several Obligations 34
Section 17:Choice of Law 34
Section 18:Partial Invalidity 34
Section 19:Waiver 34
Section 20:Governmental Jurisdiction and Authorizations 34
Section 21:Successors and Assigns 35
Section 22:Entire Agreement 35
Section 23:Notices 35
Cedar Creek Wind,LLC—Rattlesnake Canyon
POWER PURCHASE AGREEMENT
THIS POWER PURCHASE AGREEMENT,rel ting to 144flLESNAKE CANYON,a wind
turbine generation project entered into this
_______
day of 2C,is between Cedar
Creek Wind,LLC,a Delaware limited liability company (the “Seller”)and PacifiCorp,an
Oregon corporation acting in its merchant function capacity (“PacifiCorp”).Seller and
PacifiCorp are referred to collectively as the “Parties”and individually as a “Party”.
RECITALS
A.Seller intends to construct,own,operate and maintain a wind facility,including
Seller’s Interconnection Facilities,for the generation of electric power located in Bingham,
County with an expected Facility Capacity Rating of 27,600-kilowatts (kW)as further described
in Exhibit A and Exhibit B (“Facility”).
B.Seller has secured rights to deliver output.from its Facility to PaciflCorp across
interconnection facilities shared by five Qualifying Facilities (Coyote Hill,Five Pine,Steep
Ridge,North Point,and Rattlesnake Canyon);the five Qualifying Facilities have agreed to
allocate comingled line losses on those interconnection facilities as set forth.in Addendum L.
C.Seller intends to operate the Facility as a Qualifying Facility,as such term is
defined in Section 1.55 below,and to sell Net Output to PacifiCorp in Idaho.
D.Seller estimates that the average annual Net Output to be delivered by the Facility
to PaciflCorp is 73,115,137 kilowatt-hours (kWh)(“Average Annual Net Output”)pursuant to
the Initial Year Energy Delivery Schedule in Section 4.3.1,which amount of energy PaciflCorp
will include in its resource planning.
B.Seller intends to sell and PaciflCorp intends to purchase all the Net Output from
the Facility in accordance with the terms and conditions of this Agreement.
F.PacifiCorp intends to designate Seller’s Facility as a Network Resource for the
purposes of serving Network Load.
G.This Agreement is a “New QF Contract”under the PaciflCorp Inter-Jurisdictional
Cost Allocation Revised Protocol.
H.Seller [S]has [J has not authorized Transmission Provider to release generation
data to PaciflCorp.If yes,the authorization is attached as Exhibit H.
NOW,THEREFORE,the Parties mutually agree as follows:
SECTION 1:DEFINITIONS
When used in this Agreement,the following terms shall have the following meanings:
1.1 “As-built Supplement”shall be a supplement to Exhibit A,provided by Seller
following completion of construction of the Facility,accurately describing the completed
Facility.
1
Cedar Creek Wind,LLC—Rattlesnake Canyon
1.2 “Availability”means,for any Billing Period,the ratio,expressed as a
percentage,of (x)the aggregate sum of the turbine-minutes in which each of the Wind
Turbines at the Facility was available to generate at the Maximum Facility Delivery Rate
during the Billing Period over (y)the product of the number of Wind Turbines that comprise
the Facility Capacity Rating as of Commercial Operation multiplied by the number of minutes
in such Billing Period.A Wind Turbine shall be deemed not available to operate during
minutes in which it is (a)in an emergency,stop,service mode or pause state;(b)in “run”
status and faulted;or (c)otherwise not operational or capable of delivering at the Maximum
Facility Delivery Rate to the Point of Delivery;unless if unavailable due solely to (i)a default
by PacitiCorp;(ii)to the extent not caused by Seller’s actions,a curtailment in accordance
with Section 6.3 or (iii)insufficient wind (including the normal amount of time required by the
generating equipment to resume operations following a period when wind speed is below the
Cut-In Wind Speed).
1.3 “Billing Period”means the time period between PacifiCorp’s reading of its
power purchase meter at the Facility and for this Agreement shall coincide with calendar
months.
1.4 “Commercial Operation”means that not less than the 90%of the expected
Facility Capacity Rating is fully operational and reliable and the Facility is fully
interconnected,fully integrated,and synchronized with the System,all of which shall be
Seller’s responsibility to receive or obtain,and which occurs when all of the following events
(i)have occurred,and (ii)remain simultaneously true and accurate as of the date and moment
on which Seller gives PacifiCorp notice that Commercial Operation has occurred:
1.4.1 PacifiCorp has received a certificate addressed to PacifiCorp from a
Licensed Professional Engineer (a)stating the Facility Capacity Rating of the Facility
at the anticipated time of Commercial Operation and (b)stating that the Facility is able
to generate electric power reliably in amounts required by this Agreement and in
accordance with all other terms and conditions of this Agreement.
1.4.2 Start-Up Testing of the Facility has been completed in accordance with
Exhibit E.
1.4.3 PacifiCorp has received a certificate addressed to PacifiCorp from a
Licensed Professional Engineer,an attorney in good standing in Idaho,or a letter from
Transmission Provider,stating that,in accordance with the Generation Interconnection
Agreement,all required interconnection facilities have been constructed,all required
interconnection tests have been completed and the Facility is physically interconnected
with the System in conformance with the Generation Interconnection Agreement and
able to deliver energy consistent with the terms of this Agreement,and the Facility is
fully integrated and synchronized with the System.
1.4.4 PacifiCorp has received a certificate addressed to PacifiCorp from a
Licensed Professional Engineer,or an attorney in good standing in Idaho,stating that
Seller has obtained all Required Facility Documents and,if requested by PacifiCorp in
2
Cedar Creek Wind,LLC—Rattlesnake Canyon
writing,Seller shall have provided copies of any or all such requested Required
Facility Documents.
1.4.5 Seller has complied with the security requirements of Section 11.
1.4.6 Network Resource Designation and Transmission Service Request.(i)
PaciflCorp has received confirmation from the Transmission Provider that the Facility
has been designated as a Network Resource and (ii)PacifiCorp has received
confirmation from the Transmission Provider that the transmission service request has
been granted in sufficient capacity to meet or exceed the Maximum Facility Delivery
Rate and the Seller has paid all costs associated with any requirements of the
transmission service request.
1.5 “Commercial Operation Date”means the date,as designated by PacifiCorp
pursuant to Section 2.4,the Facility first achieves Commercial Operation.
1.6 “Commission”means the Idaho Public Utilities Commission.
1.7 “Conforming Energy”means all Net Energy except Non-Conforming Energy.
1.8 “Conforming Energy Purchase Price”means the applicable price for
Conforming Energy and capacity,specified in Section 5.1.
1.9 “Contract Year”.means a twelve (12)month period commencing at 00:00
hours Pacific Prevailing Time (“PPT”)on January 1 and ending on 24:00 hours PPT on
December 31;provided,however,that the first Contract Year shall commence on the
Commercial Operation Date and end on the next succeeding December 31,and the last
Contract Year shall end on the Expiration Date,unless earlier terminated as provided herein.
1 .10 “Cut-in Wind Speed”means the wind speed at which a stationary wind turbine
begins producing Net Energy,as specified by the turbine manufacturer and set forth in
Exhibit A.
1.11 “Delay Liquidated Damages”,“Delay Daily Minimum”,“Delay Period”,
“Delay Price”and “Delay Volume”shall have the meanings set forth in Section 2.5 of this
Agreement.“Delay Security”shall have the meaning set forth in Section 11.1.1 of this
Agreement.
1.12 “Default Security”shall have the meaning set forth in Section 11.2 of this
Agreement.
1.13 “Effective Date”shall have the meaning set forth in Section 2.1 of this
Agreement.
1.14 “Energy Delivery Schedule”shall have the meaning set forth in Section 4.3 of
this Agreement.
3
Cedar Creek Wind,LLC—Rattlesnake Canyon
1.15 “Environmental Attributes”means any and all claims,credits,benefits,
emissions reductions,offsets,and allowances,howsoever entitled,resulting from the
avoidance of the emission of any gas,chemical,or other substance to the air,soil or water,
which are deemed of value by PaciflCorp.Environmental Attributes include but are not
limited to:(1)any avoided emissions of pollutants to the air,soil,or water such as (subject to
the foregoing)sulfur oxides (SOx),nitrogen oxides (NOx),carbon monoxide (CO),and other
pollutants;and (2)any avoided emissions of carbon dioxide (C02),methane (CH4),and other
greenhouse gases (GHGs)that have been determined by the United Nations Intergovernmental
Panel on Climate Change to contribute to the actual or potential threat of altering the Earth’s
climate by trapping heat in the atmosphere.Environmental Attributes do not include (i)
Production Tax Credits or certain other tax incentives existing now or in the future associated
with the construction,ownership or operation of the Facility,(ii)matters designated by
PacifiCorp as sources of liability,or (iii)adverse wildlife or environmental impacts.
1.16 “Environmental Contamination”means the introduction or presence of
Hazardous Materials at such levels,quantities or location,or of such form or character,as to
constitute a violation of federal,state or local laws or regulations,and present a material risk
under federal,state or local laws and regulations that the Premises will not be available or
usable for the purposes contemplated by this Agreement.
1.17 “Expiration Date”shall have the meaning set forth in Section 2.1 of this
Agreement.
1.18 “Facility”is defined in Recital A of this Agreement.
1.19 “Facility Capacity Rating”means the sum of the Nameplate Capacity Ratings
for all generators comprising the Facility.
1.20 “Force Majeure”has the meaning set forth in Section 15.1.
1.21 “Forced Outage”means an outage that requires removal of one or more Wind
Turbines from service,another outage state or a reserve shutdown state before the end of the
next weekend.Maintenance Outages and Planned Outages are not Forced Outages.
1.22 “Generation Interconnection Agreement”means the generation
interconnection agreement entered into separately between Seller and Transmission Provider,
as applicable,specifying the Point of Delivery and providing for the construction and
operation of the Interconnection Facilities.
1.23 “Governmental Authority”means any supranational,federal,state or other
political subdivision thereof,having jurisdiction over Seller,PacifiCorp or this Agreement,
including any municipality,township or county,and any entity or body exercising executive,
legislative,judicial,regulatory or administrative functions of or pertaining to government,
including any corporation or other entity owned or controlled by any of the foregoing.
4
Cedar Creek Wind,LLC—Rattlesnake Canyon
1.24 “Hazardous Materials”means any waste or other substance that is listed,
defined,designated or classified as or determined to be hazardous under or pursuant to any
environmental law or regulation.
1.25 “Inadvertent Energy”means:(1)energy delivered to the Point of Delivery in
excess of the Maximum Monthly Purchase Obligation;and (2)energy delivered to the Point of
Delivery at a rate exceeding the Maximum Facility Delivery Rate on an hour-averaged basis.
Inadvertent Energy is not included in Net Energy.
1.26 “Index Price”,for each day,shall mean the weighted average of the average
Peak and Off-Peak firm energy market prices,as published in the Intercontinental Exchange
(ICE)Day Ahead Power Price Report for the Palo Verde Hub.For Sunday and NERC
holidays,the 24-Hour Index Price shall be used,unless ICE shall publish a Firm On-Peak and
Firm Off-Peak Price for such days for Palo Verde,in which event such indices shall be
utilized for such days.If the ICE index or any replacement of that index ceases to be
published during the term of this Agreement,PaciflCorp shall select as a replacement a
substantially equivalent index that,after any appropriate or necessary adjustments,provides
the most reasonable substitute for the index in question.PacifiCorp’s selection shall be subject
to Seller’s consent,which Seller shall not unreasonably withhold,condition or delay.
1.27 “Initial Year Energy Delivery Schedule”shall have the meaning set forth in
Section 4.3.1.
1.28 “Interconnection Facilities”means all the facilities and ancillary equipment
used to interconnect the Facility to the System,as defined in the Generation Interconnection
Agreement.
1.29 “Letter of Credit”means an irrevocable standby letter of credit in a form
reasonably acceptable to PacifiCorp,naming PaciflCorp as the party entitled to demand
payment and present draw requests thereunder.Such letter of credit shall be provided by an
institution that is a United States office of a commercial bank or trust company organized
under the laws of the United States of America or a political subdivision thereof,with a credit
rating on its long-term senior unsecured debt of at least “A”from Standard &Poor’s and
“A2”from Moody’s Investor Services,and (unless otherwise agreed)having assets of at least
$10,000,000,000 (net of reserves).
1.30 “Licensed Professional Engineer”means a person acceptable to PacifiCorp in
its reasonable judgment who is licensed to practice engineering in the state of Idaho,who has
training and experience in the engineering discipline(s)relevant to the matters with respect to
which such person is called to provide a certification,evaluation and/or opinion,who has no
economic relationship,association,or nexus with the Seller,and who is not a representative of
a consulting engineer,contractor,designer or other individual involved in the development of
the Facility,or of a manufacturer or supplier of any equipment installed in the Facility.Such
Licensed Professional Engineer shall be licensed in an appropriate engineering discipline for
the required certification being made.The engagement and payment of a Licensed
Professional Engineer solely to provide the certifications,evaluations and opinions required by
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Cedar Creek Wind,LLC—Rattlesnake Canyon
this Agreement shall not constitute a prohibited economic relationship,association or nexus
with the Seller,so long as such engineer has no other economic relationship,association or
nexus with the Seller.
1.31 “Maintenance Outage”means any outage of one or more Wind Turbines that
is not a Forced Outage or a Planned Outage.A Maintenance Outage is an outage that can be
deferred until after the end of the next weekend,but that requires that the Wind Turbine(s)be
removed from service before the next Planned Outage.A Maintenance Outage may occur any
time during the year and must have a flexible start date.
1.32 “Material Adverse Change”shall mean,with respect to the Seller,if the
Seller has experienced a change in facts or circumstances related to development or operation
of the Facility that materially and adversely impact Seller’s ability to fulfill its obligations
under this Agreement.
1.33 “Maximum Facility Delivery Rate”means the maximum instantaneous rate
(kW)at which the Facility is capable of delivering Net Output at the Point of Delivery,as
specified in Exhibit A,and in compliance with the Generation Interconnection Agreement.
1.34 “Maximum GIA Delivery Rate”means the maximum rate (kW)at which the
Generator Interconnection Agreement allows the Facility to deliver energy to the Point of
Delivery and is set forth in Exhibit A.
1.35 “Maximum Monthly Purchase Obligation”means the maximum amount of
energy PacifiCorp is obligated to purchase under this Agreement in a calendar month.In
accordance with Commission Order No.29632,the Maximum Monthly Purchase Obligation
for a given month,in kWh,shall equal 10,000 kW multiplied by the total number of hours in
that month and prorated for any partial month;provided however that,subsequent to the
Effective Date of this Agreement,any change by the Commission to the Maximum Monthly
Purchase Obligation established by Order No.29632 shall have no affect on the obligations of
the Parties pursuant to this Agreement.
1.36 “Nameplate Capacity Rating”means the maximum instantaneous generating
capacity of any qualifying small power or cogeneration generating unit supplying all or part of
the energy sold by the Facility,expressed in MW or kW,when operated consistent with the
manufacturer’s recommended power factor and operating parameters,as set forth in a notice
from Seller to PacifiCorp delivered before the Commercial Operation Date and,if applicable,
updated in the As-built Supplement.
1.37 “NERC”means the North American Electric Reliability Corporation.
1.38 “Net Energy”means the energy component,in kWh,of Net Output.Net
Energy does not include Inadvertent Energy.
1.39 “Net Output”means all energy and capacity produced by the Facility,less
station use and less transformation and transmission losses and other adjustments,if any.For
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Cedar Creek Wind,LLC—Rattlesnake Canyon
purposes of calculating payment under this Agreement,Net Output of energy shall be
calculated as set forth in Addendum L.Net Output does not include Inadvertent Energy.
1.40 “Network Resource”shall have the meaning set forth in the Tariff.
1.41 “Network Service Provider”means PacifiCorp Transmission,as a provider of
network service to PacifiCorp under the Tariff.
1.42 “Non-Conforming Energy”means Net Output produced by the Facility prior
to the Commercial Operation Date.
1.43 “Non-Conforming Energy Purchase Price”means the applicable price for
Non-Conforming Energy and capacity,specified in Section 5.1.
1.44 “Off-Peak Hours”means all hours of the week that are not On-Peak Hours.
1.45 “On-Peak Hours”means hours from 6:00 a.m.to 10:00 p.m.Pacific
Prevailing Time,Monday through Saturday,excluding Western Electricity Coordinating
Council (WECC)and North American Electric Reliability Corporation (NERC)holidays.
1.46 “Output Shortfall”and “Output Shortfall Damages”shall have the meanings
set forth in Section 4.5 of this Agreement.
1.47 “PacifiCorp”is defined in the first paragraph of this Agreement,and excludes
PacifiCorp Transmission.
1.48 “PacifiCorp Transmission”means PacifiCorp,an Oregon corporation,acting
in its interconnection and transmission function capacity.
1.49 “Planned Outage”means an outage of predetermined duration that is scheduled
in Seller’s Energy Delivery Schedule.Boiler overhauls,turbine overhauls or inspections are
typical planned outages.Maintenance Outages and Forced Outages are not Planned Outages.
1.50 “Point of Delivery”means the point of interconnection between the Facility
and the System,as specified in the Generation Interconnection Agreement and in Exhibit B.
1.51 “Premises”means the real property on which the Facility is or will be located,
as more fully described on Exbibit A.
1.52 “Prime Rate”means the rate per annum equal to the publicly announced prime
rate or reference rate for commercial loans to large businesses in effect from time to time
quoted by WMorgan Chase &Co.If a JPMorgan Chase &Co.prime rate is not available,
the applicable Prime Rate shall be the announced prime rate or reference rate for commercial
loans in effect from time to time quoted by a bank with $10 billion or more in assets in New
York City,N.Y.,selected by the Party to whom interest based on the prime rate is being paid.
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Cedar Creek Wind,LLC—Rattlesnake Canyon
1.53 “Production Tax Credits”means production tax credits under Section 45 of
the Internal Revenue Code as in effect from time to time during the term hereof or any
successor or other provision providing for a federal tax credit determined by reference to
renewable electric energy produced from wind resources and any correlative state tax credit
determined by reference to renewable electric energy produced from wind resources for which
the Facility is eligible.Production Tax Credits do not include any tax credit determined by
reference to investment.
1.54 “Prudent Electrical Practices”means any of the practices,methods and acts
engaged in or approved by a significant portion of the electrical utility industry or any of the
practices,methods or acts,which,in the exercise of reasonable judgment in the light of the
facts known at the time a decision is made,could have been expected to accomplish the
desired result at the lowest reasonable cost consistent with reliability,safety and expedition.
Prudent Electrical Practices is not intended to be limited to the optimum practice,method or
act to the exclusion of all others,but rather to be a spectrum of possible practices,methods or
acts.
1.55 “QF”means “Qualifying Facility”,as that term is defined in the version of
FERC Regulations (codified at 18 CFR Part 292)in effect on the date of this Agreement.
1.56 “Required Facility Documents”means all deeds,titles,leases (including Wind
Leases),licenses,permits,authorizations,and agreements demonstrating that seller controls
the necessary property rights and government authorizations to construct,operate,and
maintain the Facility,including without limitation those set forth in Exhibit C.
1.57 “Requirements of Law”means any applicable and mandatory (but not merely
advisory)federal,state and local law,statute,regulation,rule,code or ordinance enacted,
adopted,issued or promulgated by any federal,state,local or other Governmental Authority
or regulatory body (including those pertaining to electrical,building,zoning,environmental
and occupational safety and health requirements).
1.58 “Scheduled Commercial Operation Date”means the date by which Seller
promises to achieve Commercial Operation,as specified in Section 2.2.7.
1.59 “Scheduled Monthly Energy Delivery”means the Net Energy scheduled to be
delivered during a given calendar month,as specified by Seller in the Energy Delivery
Schedule.
1.60 “Shared Interconnection Facilities”means that portion of the Interconnection
Facilities used by the Facility and one or more other Qualifying Facilities.
1.61 “Seller’s Forecast-Cost Share”and “Seller’s Capped Forecast-Cost Share”
shall have the meanings set forth in Sections 8.2 and 8.3 respectively.
1.62 “Subsequent Energy Delivery Schedule”shall have the meaning set forth in
Section 4.3.3.
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Cedar Creek Wind,LLC—Rattlesnake Canyon
1.63 “System”means the electric transmission substation and transmission or
distribution facilities owned,operated or maintained by Transmission Provider,which shall
include,after construction and installation of the Facility,the circuit reinforcements,
extensions,and associated terminal facility reinforcements or additions required to
interconnect the Facility,all as set forth in the Generation Interconnection Agreement.
1.64 “Tariff”means the PacifiCorp Transmission FERC Electric Tariff Seventh
Revised Volume No.11 Pro Forma Open Access Transmission Tariff or the Transmission
Provider’s corresponding FERC tariff or both,as revised from time to time.
1.65 “Transmission Provider”means PacifiCorp Transmission or a successor,
including any regional transmission organization (“RTO”).
1.66 “Wind Leases”means the memoranda of wind lease and redacted wind leases
recorded in the county in which the Facility is located in connection with the development of
the Facility,as the same may be supplemented,amended,extended,restated,or replaced from
time to time.
1.67 “Wind Turbine”means a type SWT-2.3-101 Siemens 2,300 kilowatt wind
turbine.At its full Facility Capacity Rating,the Facility will consist of 12 Wind Turbines.
SECTION 2:TERM.COMMERCIAL OPERATION DATE
2.1 This Agreement shall become effective after execution by both Parties and after
approval by the Commission (“Effective Date”);provided,however,this Agreement shall not
become effective until the Commission has determined,pursuant to a final and non-appealable
order,that the prices to be paid for energy and ca,acity are just and reasonable,in the public
interest,and that the costs incurred by PacifiCoip for purchases of capacity and energy from
Seller are legitimate expenses,all of which the Commission will allow PacifiCorp to recover
in rates in Idaho in the event other jurisdictions deny recovery of their proportionate share of
said expenses.
Unless earlier terminated as provided herein,the Agreement shall remain in effect until
24:00 PPT September 30,2032 (“Expiration Date”).
2.2 Time is of the essence of this Agreement,and Seller’s ability to meet certain
requirements prior to the Commercial Operation Date and to achieve Commercial Operation
by the Scheduled Commercial Operation Date is critically important.Therefore,
2.2.1 By September 30,2011,Seller shall obtain and provide to PacifiCorp
copies of all governmental permits and authorizations listed in Exhibit C.
2.2.2 By the date 30 calendar days after the Effective Date,Seller shall
provide Delay Security required under Section 11.1.1,as applicable.
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Cedar Creek Wind,LLC—Rattlesnake Canyon
2.23 By June 30,2011,Seller:(i)has provided all information and paid all
fees the Transmission Provider requires to designate the Facility as a Network
Resource in accordance with the Tariff (OATT);and (ii)has provided all information
reasonably required by PaciflCorp to submit a transmission service request for the
Facility to the Transmission Provider pursuant to the Tariff.
2.2.4 At least ten business days prior to delivery of any energy from the
Facility to PacifiCorp,Seller shall provide PacifiCorp with an executed Generation
Interconnection Agreement.
2.2.5 Prior to Commercial Operation Date,Seller shall provide Default
Security required under Section 11.2,as applicable.
2.2.6 Prior to Commercial Operation Date,Seller shall provide PaciflCorp
with an As-built Supplement reasonably acceptable to PacifiCorp.
2.2.7 By 00:00 PPT October 1,2012,Seller shall achieve Commercial
Operation (“Scheduled Commercial Operation Date”).
2.3 Beginning October 1,2011,Seller shall provide PaciflCorp a one-page monthly
update by e-mail on the progress of the milestones in Section 2.2.
2.4 Establishing Commercial Operation.Seller shall provide written notice to
PacifiCorp stating when Seller believes that the Facility has achieved Commercial Operation.
PacifiCorp shall have ten (10)business days after receipt either to confirm to Seller that all of
the conditions to Commercial Operation have been satisfied or have occurred,or to state with
specificity what PacifiCorp reasonably believes has not been satisfied.If,within such ten (10)
business day period,PacifiCorp either does not respond or else confirms that the Facility has
achieved Commercial Operation,the original date of receipt of Seller’s notice shall be the
Commercial Operation Date.If PacifiCorp notifies Seller within such ten (10)business day
period that PacifiCorp reasonably believes the Facility has not achieved Commercial
Operation,Seller may,if it has a good faith belief that Commercial Operation has been
achieved,submit a Technical Dispute Notice,or else Seller shall address the concerns stated in
PacifiCorp’s notice to the mutual satisfaction of both Parties.If Seller submits a Technical
Dispute Notice and the Technical Expert determines that Commercial Operation has been
achieved,then the Commercial Operation Date shall be the date,as determined by the
Technical Expert,that the Facility first met all the requirements of Commercial Operation;
otherwise the date upon which Seller has addressed the concerns stated in PacifiCorp’s notice
to PacifiCorp’s reasonable satisfaction,as specified in a notice from PaciflCorp to Seller,shall
be the Commercial Operation Date.If Commercial Operation is achieved at less than one
hundred percent (100%)of the expected Facility Capacity Rating and Seller informs
PacifiCorp that Seller intends to bring the Facility to one hundred percent (100%)of the
expected Facility Capacity Rating,Seller shall provide PacifiCorp with a list of all items to be
completed in order to achieve the expected Facility Capacity Rating.
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Cedar Creek Wind,LLC—Rattlesnake Canyon
2.4.1 Technical Expert.If,and only if,a dispute regards (i)whether or not
Commercial Operation has been achieved,and/or (ii)the date when Commercial
Operation was achieved,the Parties may have such dispute,and only such dispute,
resolved pursuant to this Section 2.4.1.Any such dispute will be determined by an
independent technical expert,who shall be a mutually acceptable third party with
training and experience in the disciplines relevant to the matters with respect to which
such person is called upon to provide a certification,evaluation or opinion (the
“Technical Expert”),which determination shall be (X)made (subject to the terms in
this Section 2.4)in accordance with the Construction Industry Arbitration Rules and
Mediation Procedures (Including Procedures for Large,Complex Construction
Disputes)of the AAA,as amended and effective on October 1,2009 (the “Technical
Dispute Procedures”),notwithstanding any dollar amounts or dollar limitations
contained therein,and (Y)binding upon the Parties.
(a)Either Party may commence the dispute process as to the matters
set forth in paragraph 2.4.1,abbve,with the American Arbitration Association
(“AAA”)by notifying AAA and the other Party in writing (“Technical Dispute
Notice”)of such Party’s desire that the dispute be resolved through a
determination by a Technical Expert.
(b)The determination shall be conducted by a sole Technical Expert.
The Parties may select any mutually acceptable Technical Expert.If the Parties
cannot agree on a Technical Expert within five (5)days afler the date of the
Technical Dispute Notice,then the AAA’s Arbitration Administrator shall send a
list and resumes of three (3)available technical experts meeting the qualifications
set forth in Section 2.4.1 to the Parties,each of whom shall strike one name,and
the remaining person shall be appointed as the Technical Expert.If more than
one name remains,either because one or both Parties have failed to respond to the
AAA’s Arbitration Administrator within five (5)days after receiving the list or
because one or both Parties have failed to strike a name from the list or because
both Parties strike the same name,the AAA’s Arbitration Administrator will
choose the Technical Expert from the remaining names.If the designated
Technical Expert shall die,become incapable or,unwilling to,or unable to serve
or proceed with the determination,a substitute Technical Expert shall be
appointed in accordance with the selection procedure described above,and such
substitute Technical Expert shall have all such powers as if he or she has been
originally appointed herein.
(c)Within thirty (30)days of the appointment of the Technical Expert
pursuant to the foregoing sub-section,each Party shall submit to the Technical
Expert (and copy the other Party)a written report containing its position with
respect to the dispute,and arguments therefor together with supporting
documentation and calculations.Discovery shall be limited to Facility documen
tation relating to the disputed matter.Within sixty (60)days from receipt of such
submissions,the Technical Expert shall select one or the other Party’s position
with respect to the disputed,arbitrate-able issues set forth in paragraph 2.4.1
above,whereupon such selection shall be a binding determination upon the
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Cedar Creek Wind,LLC—Rattlesnake Canyon
Parties for all purposes hereof.The costs of the Technical Expert,including his or
her fees and expenses,shall be borne by the Party whose position was not selected
by the Technical Expert;each Party shall otherwise bear its own expenses.If the
Technical Expert fails to render a decision within ninety (90)days from receipt of
each Party’s submissions,either Party may,prior to the Technical Expert’s final
decision,initiate litigation,in which case the Technical Expert’s final decision
shall not be binding on the Parties unless otherwise agreed.
2.4.2 All verbal and written communications between the Parties and issued or
prepared in connection with this Section 2.4.1 shall be deemed prepared and
communicated in furtherance,and in the context,of dispute settlement,and shall be
exempt from discovery and production,and shall not be admissible in evidence
(whether as admission or otherwise)in any litigation or other proceedings for the
resolution of the dispute./
2.4.3 All deadlines specified in this Section 2.4 may be extended by mutual
agreement of the Parties.
2.5 Delay Damages.Seller shall cause the Facility to achieve Commercial
Operation on or before the Scheduled Commercial Operation Date.If Commercial Operation
occurs after the Scheduled Commercial Operation Date,Seller shall be liable to pay
PacifiCorp delay damages for the number of days (“Delay Period”)the Commercial
Operation Date occurs after the Scheduled Commercial Operation Date,until the earlier of
occurrence of the Commercial Operation Date or the termination of this Agreement (“Delay
Liquidated Damages”),provided that Seller shall not accrue any Delay Liquidated Damages
after:(i)Seller has timely achieved the milestone in Section 2.2.3;and (ii)Seller has satisfied
all requirements of Commercial Operation except for one or more requirements in Section
1.4.6.Billings and payments for Delay Liquidated Damages shall be made in accordance with
Section 11.1.
2.5.1 Delay Liquidated Damages.Delay Liquidated Damages equals the sum
of:for each day in the Delay Period,the greater of (1)the Delay Daily Minimum or
(2)the Delay Price times the Delay Volume
Where:
“Delay Daily Minimum”equals (a)for the first forty-five (45)calendar days
following the Scheduled Commercial Operation Date:one-ninetieth (1/90th)of
forty-five dollars ($45)multiplied by the Maximum Facility Delivery Rate with
the Maximum Facility Delivery Rate being measured in kW;(b)after the forty
fiffl (45th)calendar day following the Scheduled Commercial Operation date:the
Delay Price times the Delay Volume.
“Delay Price”equals the positive difference,if any,of the Index Price minus the
weighted average of the On-Peak and Off-Peak monthly Conforming Energy
Purchase Prices;and
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Cedar Creek Wind,LLC—Rattlesnake Canyon
“Delay Volume”equals the applicable Scheduled Monthly Energy Delivery
divided by the number of days in that month.
2.5.2 Appropriateness of Damages.The Parties agree that the damages
PacifiCoip would incur due to delay in the Facility achieving Commercial Operation on
or before the Scheduled Commercial Operation Date would be difficult or impossible to
predict with certainty,and that the Delay Liquidated Damages are an appropriate
approximation of such damages.
SECTION 3:REPRESENTATIONS AND WARRANTIES
3.1 PacifiCorp represents,covenants,and warrants to Seller that:
3.1.1 PacifiCorp is duly organized and validly existing under the laws of the
State of Oregon.
3.1.2 PacifiCorp has the requisite corporate power and authority to enter into
this Agreement and to perform according to the terms of this Agreement.
3.1.3 PacifiCorp has taken all corporate actions required to be taken by it to
authorize the execution,delivery and performance of this Agreement and the
consummation of the transactions contemplated hereby.
3.1.4 Subject to Commission approval,the execution and delivery of this
Agreement does not contravene any provision of,or constitute a default under,any
indenture,mortgage,or other material agreement binding on PacifiCorp or any valid
order of any court,or any regulatory agency or other body having authority to which
PacifiCorp is subject.
3.1.5 Subject to Commission approval,this Agreement is a valid and legally
binding obligation of PacifiCorp,enforceable against PacifiCorp in accordance with its
terms (except as the enforceability of this Agreement may be limited by bankruptcy,
insolvency,bank moratorium or similar laws affecting creditors’rights generally and
laws restricting the availability of equitable remedies and except as the enforceability of
this Agreement may be subject to general principles of equity,whether or not such
enforceability is considered in a proceeding at equity or in law).
3.2 Seller represents,covenants,and warrants to PacifiCorp that:
3.2.1 Seller is a limited liability company duly organized and validly existing
under the laws of Delaware.
3.2.2 Seller has the requisite power and authority to enter into this Agreement
and has,or will have at the date of Commercial Operation of the Facility,all requisite
power and authority to perform according to the terms hereof,including all required
regulatory authority to make wholesale sales from the Facility.
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Cedar Creek Wind,LLC—Rattlesnake Canyon
3.2.3 Seller’s shareholders,directors,and officers have taken all actions
required to authorize the execution,delivery and performance of this Agreement and
the consummation of the transactions contemplated hereby.
3.2.4 The execution and delivery of this Agreement does not contravene any
provision of,or constitute a default under,any indenture,mortgage,or other material
agreement binding on Seller or any valid order of any court,or any regulatory agency
or other body having authority to which Seller is subject.
3.2.5 This Agreement is a valid and legally binding obligation of Seller,
enforceable against Seller in accordance with its terms (except as the enforceability of
this Agreement may be limited by bankruptcy,insolvency,bank moratorium or similar
laws affecting creditors’rights generally and laws restricting the availability of
equitable remedies and except as the enforceability of this Agreement may be subject to
general principles of equity,whether or not such enforceability is considered in a
proceeding at equity or in law).
3.2.6 The Facility is and shall for the term of this Agreement continue to be a
QF.Seller has provided the appropriate QF certification,which may include a Federal
Energy Regulatory Commission self-certification to PacifiCorp prior to PacifiCorp’s
execution of this Agreement.At any time PacifiCorp has reason to believe during the
term of this Agreement that Seller’s status as a QF is in question,PaciflCorp may
require Seller to provide PacifiCorp with a written legal opinion from an attorney in
good standing in the state ofIdaho and who has no economic relationship,association
or nexus with the Seller or the Facility,stating that the Facility is a QF and providing
sufficient proof (including copies of all documents and data as PacifiCorp may request)
demonstrating that Seller has maintained and will continue to maintain the Facility as a
QF.
3.2.7 Neither the Seller nor any of its principal equity owners is or has within
the past two (2)years been the debtor in any bankruptcy proceeding,is unable to pay
its bills in the ordinary course of its business,or is the subject of any legal or
regulatory action,the result of which could reasonably be expected to impair Seller’s
ability to own and operate the Facility in accordance with the terms of this Agreement.
3.2.8 Seller has not at any time defaulted in any of its payment obligations for
electricity purchased from PacifiCorp.
3.2.9 Seller is not in default under any of its other material agreements that
would result in Seller’s failure to perform its material obligations hereunder.
3.2.10 Seller owns all right,title and interest in and to the Facility,free and
clear of all liens and encumbrances other than liens and encumbrances related to third
party financing of the Facility,and Seller (or its successor in interest)will continue to
own for the term of this Agreement,all right,title and interest in and to the Facility,
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Cedar Creek Wind,LLC—Rattlesnake Canyon
free and clear of all liens and encumbrances other than liens and encumbrances related
to third-party financing of the Facility.
3.2.11 In entering into this Agreement and the undertaking by Seller of the
obligations set forth herein,Seller has investigated and determined that it is capable of
performing hereunder and has not relied upon the advice,experience or expertise of
PacifiCorp in connection with the transactions contemplated by this Agreement.
3.2.12 All professionals or experts including,but not limited to,engineers,
attorneys or accountants,that Seller may have consulted or relied on in undertaking the
transactions contemplated by this Agreement have been solely those of Seller.
3.2.13 All leases of real property required for the operation of the Facility or
the performance of any obligations of Seller hereunder are set forth and accurately
described in Exhibit C.Upon request by PacifiCorp,Seller shall provide copies of the
Wind Leases to PacifiCorp.
3.2.14 All information about the Facility set forth in Exhibit A,Exhibit B,and
Exhibit C has been verified by Seller and is accurate to the best of its knowledge.
3.3 Notice.If at any time during this Agreement,any Party obtains actual
knowledge of any event or information which would have caused any of the representations
and warranties in this Section 3 to have been materially untrue or misleading when made,such
Party shall provide the other Party with written notice of the event or information,the
representations and warranties affected,and the action,if any,which such Party intends to
take to make the representations and warranties true and correct.The notice required pursuant
to this Section shall be given as soon as practicable after the occurrence of each such event.
SECTION 4:DELWERY OF POWER;AVAJLABJLITY GUARANTY
4.1 Delivery and Acceptance of Net Output.Except for any curtailment specified
in Section 6.3,unless otherwise provided herein,PacifiCorp will purchase and Seller will sell
all Net Output from the Facility.
4.2 No Sales to Third Parties.During the term of this Agreement,Seller shall not
sell any Net Output from the Facility to any entity other than PacifiCorp.
4.3 Energy Delivery Schedule.Seller shall prepare and provide to PacifiCorp,on
an ongoing basis,a written schedule of Net Energy expected to be delivered by the Facility
(“Energy Delivery Schedule”),in accordance with the following:
4.3.1 During the first twelve full calendar months following the Commercial
Operation Date,Seller predicts that the Facility will produce and deliver the following
monthly amounts (“Initial Year Energy Delivery Schedule”):
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Cedar Creek Wind LLC—Rattlesnake Canyon
Month Energy Delivery (kWh)Avg.kW
January 6,285,415 8,448
February 5,669,415 8,437
March 6,236,024 8,382
April 5,700,174 7,917
May 5,553,040 7,464
June 5,796,677 8,051
July 5,716,795 7,684
August 6,333199 8,512
September 6,112,516 8,490
October 6,163,807 8,285
November 6,753,219 9,379
December 6,794,856 9,133
TOTAL:73,115,137 8,346
4.3.2 Seller may revise the Initial Year Energy Delivery Schedule any time
prior to the Commercial Operation Date.
4.3.3 Beginning at the end of the ninth full calendar month of operation,and at
the end of every third month thereafter,Seller shall supplement the Energy Delivery
Schedule with three additional months of forward estimates (which shall be appended to
this Agreement using the format specified in Exhibit D)(“Subsequent Energy
Delivery Schedule”),such that the Energy Delivery Schedule will provide at least
three months of scheduled energy estimates at all times.Seller shall provide
Subsequent Energy Delivery Schedules no later than 5:00 pm PPT of the 5th day after
the due date.If Seller does not provide a Subsequent Energy Delivery Schedule by the
above deadline,scheduled energy for the omitted period shall equal the amounts
scheduled by Seller for the same three-month period during the previous year.
4.3.4 Upon and after the Commercial Operation Date,Seller may no longer
revise the Energy Delivery Schedule for the first six full calendar months of
Commercial Operation.After 5:00 p.m.PPT of the fifth business day following the
end of the third full calendar month of Commercial Operation and the end of each third
calendar month thereafter,Seller may no longer revise the Energy Delivery Schedule
for the six calendar months immediately following such third month.Subject to the
foregoing restrictions in this Section 4.3.4,Seller may revise the Energy Delivery
Schedule for any unrestricted month by providing written notice to PacifiCorp.Failure
to provide timely written notice of changed amounts will be deemed to be an election
of no change.
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Cedar Creek Wind,LLC—Rattlesnake Canyon
4.4 Minimum Availability Obligation.Seller shall cause the Facility to achieve an
Availability of at least 85 %during each month (“Guaranteed Availability”).
4.5 Lijj’idated Damages for Output Shortfall.If the Availability in any given
month falls below the Guaranteed Availability,the resulting shortfall shall be expressed in
kWh as the “Output Shortfall.”The Output Shortfall shall be calculated in accordance with
the following formula:
Output Shortfall =(Guaranteed Availability —Availability)*
Scheduled Monthly Energy Delivery
Seller shall pay PacifiCorp for any Output Shortfall at the lower of (1)the positive difference,
if any,of the Index Price minus the weighted average of the On-Peak and Off-Peak monthly
Conforming Energy Purchase Prices;or (2)the weighted average of the On-Peak and Off-
Peak monthly Confonning Energy Purchase Prices (“Output Shortfall Damages”).
Output Shortfall Damages =Output Shortfall *Output Shortfall Price
Where:
Output Shortfall Price =(Index Price —Weighted Average CEPP),except
that if Output Shortfall Price <0,then Output
Shortfall Price =0,and except that if Output
Shortfall Price >Weighted Average CEPP,then
Output Shortfall Price =Weighted Average CEPP
Weighted Average CEPP =the weighted average On-Peak and Off-Peak
Conforming Energy Purchase Prices for the month
of Output Shortfall
If an Output Shortfall occurs in any given month,Seller may owe PacifiCorp liquidated
damages.Each Party agrees and acknowledges that (a)the damages that PacifiCorp would
incur due to the Facility’s failure to achieve the Guaranteed Availability would be difficult or
impossible to predict with certainty,and (b)the liquidated damages contemplated in this
Section 4.5 are a fair and reasonable calculation of such damages.
4.6 Audit Rights.In addition to data provided under Sections 9.3 and 9.4,
PacifiCorp shall have the right,but not the obligation,to audit the Facility’s compliance with
its Guaranteed Availability using any reasonable methods.Seller agrees to retain all
performance related data for the Facility for a minimum of three years,and to cooperate with
PaciflCorp in the event PacifiCorp decides to audit such data.
SECTION 5:PURCHASE PRICES
5.1 Energy Purchase Price.Except as provided in Section 5.3,PacifiCorp will pay
Seller Conforming Energy or Non-Conforming Energy Purchase Prices for Net Output
17
Cedar Creek Wind LLC—Rattlesnake Canyon
adjusted for the month and On-Peak Hours or Off-Peak Hours and the wind integration cost
using the following formulae,in accordance with Commission Order Nos.30423,31025,and
31021:
Conforming Energy Purchase Price =(ARee *MPM)-WIC
Non-Conforming Energy Purchase Price =(ARne *MPM)-WIC
Where:
AR(,=Conforming Energy annual rate from Table 1,below,for the year
of the Net Output.
ARnce =the lower ofi
85%of the Conforming Energy annual rate from Table 1
below,for the year of Net Output
or
85%of average of the daily Index Price for each day of
the month,or portion of month,of Net Output.
MPM =monthly On-Peak or Off-Peak multiplier from Table 2,below,that
corresponds to the month of the Net Output and whether the Net
Output occurred during On-Peak Hours or OffPeak Hours.
WIC $6.50/MWh,the wind integration cost prescribed in Commission
Order No.31021.
Example calculations are provided in Exhibit G.
Table 1:Conforming Energy Annual Rates (from Commission Order No.31025)
Conforming Energy
Annual Rate (ARce)
Year $/MWh
2012 63.97
2013 67.51
2014 71.32
2015 75.40
2016 77.76
2017 80.07
2018 82.58
2019 85.05
2020 87.61
2021 90.63
2022 93.78
2023 97.05
2024 100.44
2025 103.98
2026 106.98
2027 110.07
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Cedar Creek Wind,LLC—Ratt!esnake Canyon
2028 113.26
2029 116.56
2030 119.95
2031 124.51
2032 128.50
Table 2:Monthly On-Peak/Off-Peak Multipliers
On-Peak Off-PeakMonthHoursHours
January 103%94%
February 105%97%
March 95%80%
April 95%76%
May 92%63%
June 94%65%
July 121%92%
August 121%106%
September 109%99%
October 115%105%
November 110%96%
December 129%120%
5.2 Payment.
For each Billing Period in each Contract Year,PacifiCorp shall pay Seller as follows:
For delivery of Conforming Energy:
Payment (CEnergy().*CEPPrice>,I 1000)+
(CEnergy0 *CEPPrice I 1000)
For delivery ofNon-Conforming Energy:
Payment =(NCEnergy *NCEPPrice /1000)+
(NCEnergy)*NCEPPrice I 1000)
Where:
CEnergy =Conforming Energy in kWh
CEPPrice =Conforming Energy Purchase Price in $/MWh
NCEnergy =Non-Conforming Energy in kWh
NCEPPrice =Non-Conforming Energy Purchase Price in $/MWh
On-Peak =the corresponding value for On-Peak Hours
Off-Peak =the corresponding value for Off-Peak Hours
5.3 Inadvertent Energy.So long as acceptance of Inadvertent Energy does not
cause PacifiCorp to violate the terms of its Network Transmission Service and is consistent
19
Cedar Creek Wind,LLC—Rattlesnake Canyon
with Prudent Electrical Practices,PacifiCorp will accept Inadvertent Energy,but will not
purchase or pay for Inadvertent Energy.
SECTION 6:OPERATION AND CONTROL
6.1 As-Built Supplement.Upon completion of any construction affecting the
Facility,Seller shall provide PacifiCorp an As-built Supplement bearing the stamp of a
Licensed Professional Engineer that accurately depicts the Facility as built.The As-built
Supplement must be reviewed and approved by PacifiCorp,which approval shall not
unreasonably be withheld,conditioned or delayed.
6.2 Operation.Seller shall operate and maintain the Facility in a safe manner in
accordance with the Generation Interconnection Agreement,Prudent Electrical Practices and
in accordance with the requirements of all applicable federal,state and local laws and the
National Electric Safety Code as such laws and code may be amended from time to time.
PacifiCorp shall have no obligation to purchase Net Output from the Facility to the extent the
interconnection between the Facility and PacifiCorp’s electric system is disconnected,
suspended or interrupted,in whole or in part,pursuant to the Generation Interconnection
Agreement,or to the extent generation curtailment is required as a result of Seller’s non
compliance with the Generation Interconnection Agreement.PacifiCorp shall have the right to
inspect the Facility to confirm that Seller is operating the Facility in accordance with the
provisions of this Section 6 upon reasonable notice to Seller.Seller is solely responsible for
the operation and maintenance of the Facility.PacifiCorp shall not,by reason of its decision
to inspect or not to inspect the Facility,or by any action or inaction taken with respect to any
such inspection,assume or be held responsible for any liability or occurrence arising from the
operation and maintenance by Seller of the Facility.
6.3 Curtailment.PacifiCorp shall not be obligated to purchase,receive,pay for,or
pay any damages associated with,Net Output (or associated Production Tax Credits or
Environmental Attributes)if such Net Output (or associated Production Tax Credits or
Environmental Attributes)is not delivered to the System or Point of Delivery due to any of the
following:(a)the interconnection between the Facility and the System is disconnected,
suspended or interrupted,in whole or in part,consistent with the terms of the Generation
Interconnection Agreement,(b)the Transmission Provider or Network Service Provider
directs a general curtailment,reduction,or redispatch of generation in the area,(which would
include the Net Output)for any reason,even if such curtailment or redispatch directive is
carried out by PacifiCorp,which may fulfill such directive by acting in its sole discretion;or if
PacifiCorp curtails or otherwise reduces the Net Output in order to meet its obligations to the
Transmission Provider or Network Service Provider to operate within system limitations,(c)
the Facility’s Output is not received because the Facility is not fully integrated or synchronized
with the System,or (d)an event of Force Majeure prevents either Party from delivering or
receiving Net Output.Seller shall reasonably determine the MWh amount of Net Output
curtailed pursuant to this Section 6.3 after the fact based on the amount of energy that could
have been generated at the Facility and delivered to PacifiCorp as Net Output but that was not
generated and delivered because of the curtailment.Seller shall determine the quantity of such
20
Cedar Creek Wind,LLC—Rattlesnake Canyon
curtailed energy based on (x)the time and duration of the curtailment period and (y)wind
conditions recorded at the Facility during the period of curtailment and the power curve
specified for the for the Wind Turbines as shown in Exhibit A.Seller shall promptly provide
PacifiCorp with access to such information and data as PacifiCorp may reasonably require to
confirm to its reasonable satisfaction the amount of energy that was not generated or delivered
because of a curtailment described in this Section 6.3.
6.4 PacifiCorp as Merchant.Seller acknowledges that PacifiCorp,acting in its
merchant capacity function as purchaser under this Agreement,has no responsibility for or
control over PacifiCorp Transmission or any successor Transmission Provider.
6.5 Outages.
6.5 .1 Planned Outages.Except as otherwise provided herein,Seller shall not
schedule Planned Outage during any portion of the months of November,December,
January,February,June,July,and August,except to the extent a Planned Outage is
reasonably required to enable a vendor to satisfy a guarantee requirement in a situation
in which the vendor is not otherwise able to perform the guarantee work at a time other
than during one of the months specified above.Seller shall,in Exhibit D,provide
PacifiCorp with an annual forecast of Planned Outages for each Contract Year at least
one (1)month,but no more that three (3)months,before the first day of that Contract
Year,and shall promptly update such schedule,or otherwise change it only,to the
extent that Seller is reasonably required to change it in order to comply with Prudent
Electrical Practices.Seller shall not schedule more than one hundred fifty (150)hours
of Planned Outages for each calendar year.Seller shall notify PacifiCorp of any
deviation to the annual Planned Outage schedule,above,on the Monday preceding the
scheduling week in which the sooner of the following will occur:(a)the outage as
predicted in the Planned Outage schedule;or (b)the outage per Seller’s revised plans.
Such notice shall consist of a Monday-Sunday,hourly spreadsheet showing the revised
total Facility curtailment (MW)for that scheduling week.Seller shall not schedule any
maintenance of Shared Interconnection Facilities during November,December,
January,February,June,July,or August,without the prior written approval of
PaciflCorp,which approval may be reasonably withheld by PacifiCorp.
6.5.2 Maintenance Outages.If Seller reasonably determines that it is
necessary to schedule a Maintenance Outage,Seller shall notify PacifiCorp of the
proposed Maintenance Outage as soon as practicable but in any event at least five (5)
days before the outage begins (or such shorter period to which PacifiCorp may
reasonably consent in light of then existing wind conditions).Upon such notice,the
Parties shall plan the Maintenance Outage to mutually accommodate the reasonable
requirements of Seller and the service obligations of PacifiCorp.Seller shall take all
reasonable measures and use commercially reasonable efforts consistent with Prudent
Electrical Practices to not schedule any Maintenance Outage during the following
periods:June 15 through June 30,July,August,and September 1 through September
15.Seller shall include in such notice of a proposed Maintenance Outage the expected
21
Cedar Creek Wind,LLC—Rattlesnake Canyon
start date and time of the outage,the amount of generation capacity of the Facility that
will not be available,and the expected completion date and time of the outage.Seller
may provide notices under this Section 6.5.2 orally.Seller shall confirm any such oral
notification in writing as soon as practicable.PacifiCorp shall promptly respond to
such notice and may request reasonable modifications in the schedule for the outage.
Seller shall use all reasonable efforts to comply with PaciflCorp’s request to modify the
schedule for a Maintenance Outage if such modification has no substantial impact on
Seller.Seller shall notify PacifiCorp of any subsequent changes in generation capacity
of the Facility during such Maintenance Outage and any changes in the Maintenance
Outage completion date and time.Seller shall take all reasonable measures and exercise
its best efforts consistent with Prudent Electrical Practices to minimize the frequency
and duration of Maintenance Outages.
6.5.3 Forced Outages.Seller shall promptly provide to PaciflCorp an oral
report,via telephone to a number specified by PacifiCorp,of any Forced Outage of the
Facility.Such report shall include the amount of generation capacity of the Facility
that will not be available because of the Forced Outage and the expected return date
and time of such generation capacity.Seller shall promptly update the report as
necessary to advise PacifiCorp of changed circumstances.If the Forced Outage
resulted in more than 15%of the Facility Capacity Rating of the Facility being
unavailable,Seller shall confIrm the oral report in writing as soon as practicable.
Seller shall take all reasonable measures and exercise its best efforts consistent with
Prudent Electrical Practices to avoid Forced Outages and to minimize their duration.
6.5.4 Notice of Deratings and Outages.Without limiting other notice
requirements,Seller shall notify PacifiCorp,via telephone or via electronic mail,to a
number or email address specified by PacifiCorp,of any limitation,restriction,
derating or outage known to Seller that affects the generation capacity of the Facility in
an amount greater than five percent (5%)of the Facility Capacity Rating for the
following day.Seller shall promptly update such notice to reflect any material changes
to the information in such notice.
6.5.5 Effect of Outages on Estimated Output.Seller shall factor Planned
Outages and Maintenance Outages that Seller reasonably expects to encounter in the
ordinary course of operating the Facility into the Scheduled Monthly Energy Delivery
amounts in the Energy Delivery Schedule set forth in Exhibit D.
6.6 Scheduling.
6.6.1 Cooperation and Standards.With respect to any and all scheduling
requirements in this Agreement,(a)Seller shall cooperate with PacifiCorp with respect
to scheduling Net Output,and (b)each Party shall designate authorized representatives
to communicate with regard to scheduling and related matters arising hereunder.
6.6.2 Schedule Coordination.If,as a result of this Agreement,PaciflCorp is
deemed by an RTO to be financially responsible for Seller’s performance under the
22
Cedar Creek Wind,LLC—Rattlesnake Canyon
Generation Interconnection Agreement due to Seller’s lack of standing as a “scheduling
coordinator”or other RTO recognized designation,qualification or otherwise,then (a)
Seller shall acquire such RTO recognized standing (or shall contract with a third party
who has such RTO recognized standing)such that PacifiCorp is no longer responsible
for Seller’s performance under the Generation Interconnection Agreement,and (b)
Seller shall defend,indemnify and hold PacifiCorp harmless against any liability
arising due to Seller’s performance or failure to perform under the Generation
Interconnection Agreement or RTO requirement.
6.7 Delivery Exceeding the Maximum GIA Delivery Rate.Seller shall not deliver
energy from the Facility to the Point of Delivery at a rate that exceeds the Maximum GIA
Delivery Rate.Seller’s failure to limit such deliveries to the Maximum GIA Delivery Rate
shall be a breach of a material obligation subject to Section 12.1.8.
6.8 Access Rights.Upon reasonable prior notice and subject to the prudent safety
requirements of Seller,and Requirements of Law relating to workplace health and safety,
Seller shall provide PaciflCorp and its authorized agents,employees and inspectors
(“PacifiCorp Representatives”)with reasonable access to the Facility:(a)for the purpose of
reading or testing metering equipment,(b)as necessary to witness any acceptance tests,(c)for
purposes of implementing Section 4.6,and (d)for other reasonable purposes at the reasonable
request of PacifiCorp.PacifiCorp shall release Seller against and from any and all any and all
loss,fines,penalties,claims,actions or suits,including costs and attorney’s fees,both at trial
and on appeal resulting from actions or omissions by any of the PacifiCorp Representatives in
connection with their access to the Facility,except to the extent that such damages are caused
or by the intentional or grossly negligent act or omission of Seller.
SECTION 7:MOTIVE FORCE
Prior to the execution of this Agreement,Seller provided to PaciflCorp Wind Leases and
a motive force plan including an hourly wind profile acceptable to PacifiCorp in its reasonable
discretion and attached hereto as Exhibit F-i,together with a certification from a Licensed
Professional Engineer to PacifiCorp attached hereto as Exhibit F-2,certifying that the
implementation of the fuel or motive force plan can reasonably be expected to provide fuel or
motive force to the Facility for the duration of this Agreement adequate to generate power and
energy in quantities necessary to deliver the Average Annual Net Output.
SECTION 8:GENERATION FORECASTING COSTS
8.1 Forecast Service Election.PacifiCorp may,in its discretion,add forecasting
services for Seller’s Facility to PacifiCorp’s existing contract with a qualified wind-energy-
production forecasting vendor,which contract and vendor may change during the term of this
Agreement.
23
Cedar Creek Wind,LLC—Rattlesnake Canyon
8.2 Seller’s Forecast-Cost Share.Pursuant to Commission Order No.30497,Seller
shall be responsible for 50%of PacifiCorp’s cost of adding such forecasting services
(“Seller’s Forecast-Cost Share”)up to Seller’s Capped Forecast-Cost Share.
8.3 Cap on Seller’s Forecast-Cost Share.Seller’s Forecast-Cost Share for a given
Contract Year is capped at 0.1 %of total payments made by PaeiflCorp to Seller for Net
Output during the previous Contract Year (“Seller’s Capped Forecast-Cost Share”).If the
last Contract Year of this Agreement is shorter than a full calendar year,the cap will be
prorated for that shortened year.For the year(s)prior to the second Contract Year of this
agreement that equals a full calendar year,Seller’s Forecast-Cost Share is capped at 0.1 %of
estimated payments for Net Output based on the Energy Delivery Schedule.
8.4 Payment.Seller shall pay to PacifiCorp Seller’s Forecast-Cost Share uncapped
by Section 8.3 for each Contract Year in equal payments for each month of such year except
the last month of such year.(For example,in a Contract Year equaling a full calendar year,
Seller would pay 1/11th of Seller’s Forecast-Cost Share during each of the first 11 months.)
In the last month of each Contract Year,PaciflCorp shall refund to Seller the amount paid by
Seller under this Section in excess,if any,of Seller’s Capped Forecast-Cost Share.For a
Contract Year encompassed by just one calendar month,Seller’s payment to PaciflCorp and
PacifiCorp’s refund to Seller shall be calculated and paid simultaneously.To the extent
practicable,payments and refunds under this Section shall be included in monthly payments
and invoices under Section 10.
SECTION 9:METERING;REPORTS AN])RECORDS
9.1 Metering Adjustment.Metering will be performed at the location specified in
Exhibit B and in the marmer specified in the Generator Interconnection Agreement.All
quantities of energy purchased hereunder shall be adjusted in accordance with Addendum L,
so that the purchased amount reflects the net amount of power flowing into the System at the
Point of Delivery.1
9.2 Metering Errors.If any inspections or tests made pursuant to the Generator
Interconnection Agreement discloses an error exceeding two percent (2%),either fast or slow,
proper correction,based upon the inaccuracy found,shall be made of previous readings for the
actual period during which the metering equipment rendered inaccurate measurements if that
period can be ascertained.If the actual period cannot be ascertained,the proper correction
shall be made to the measurements taken during the time the metering equipment was in
service since last tested,but not exceeding three Billing Periods,in the amount the metering
equipment shall have been shown to be in error by such test.Any correction itt billings or
payments resulting from a correction in the meter records shall be made in the next monthly
billing or payment rendered.
‘If station service is supplied via separate facilities,PacifiCorp will deduct station service from the metered facility
output to calculate Net Output.
24
Cedar Creek Wind,LLC—Rattlesnake Canyon
9.3 Telemetering.In accordance with the Generation Interconnection Agreement,
Seller shall provide telemetering equipment and facilities capable of transmitting to
Transmission Provider (who will share it with PacifiCorp as authorized by Exhibit H,“Seller
Authorization to Release Generation Data to PacifiCorp”)the following information
concerning the Facility on a real-time basis,and will operate such equipment when requested
by PacifiCorp to indicate:
(a)instantaneous MW output at the Point ofDelivery;
(b)Net Output;
(c)the Facility’s total instantaneous generation capacity;and
(d)wind velocity at turbine hub height.
Seller shall also transmit to PacifiCorp any other data from the Facility that Seller receives on a
real-time basis,including meteorological data,wind speed data,wind direction data and gross
output data.Seller shall provide such real-time data to PacifiCorp in the same detail that Seller
receives the data (e.g.,if Seller receives the data in four second intervals,PacifiCorp shall also
receive the data in four second intervals).PacifiCorp shall have the right from time to time to
require Seller to provide additional telemetering equipment and facilities to the extent necessary
and reasonable.
9.4 Monthly Reports and Logs and Other Information.
9.4.1 Reports.Within thirty (30)calendar days after the end of each Billing
Period,Seller shall provide to PacifiCorp a report in electronic format,which report
shall include (a)summaries of the Facility’s wind and output data for the Billing Period
in intervals not to exceed one hour (or such shorter period as is reasonably possible
with commercially available technology),including information from the Facility’s
computer monitoring system;(b)summaries of any other significant events related to
the construction or operation of the Facility for the Billing Period;(c)details of
Availability of the Facility for the Billing Period sufficient to calculate Availability and
including hourly average wind velocity measured at turbine hub height and ambient air
temperature;and (d)any supporting information that PacifiCorp may from time to time
reasonably request (including historical wind data for the Facility).
9.4.2 Electronic Fault Log.Seller shall maintain an electronic fault log of
operations of the Facility during each hour of the term of this Agreement commencing
on the Conunercial Operation Date.Seller shall provide PacifiCorp with a copy of the
electronic fault log within thirty (30)calendar days after the end of the Billing Period to
which thç fault log applies.
9.4.3 Upon the request of PacifiCorp,Seller shall provide PacifiCorp the
manufacturers’guidelines and recommendations for maintenance of the Facility
equipment.
25
Cedar Creek Wind,LLC—Rattlesnake Canyon
9.44 By each January 10 following the Conimerciai Operation Date,Seller
shall provide to PacifiCorp written certification that Seller has completed all the
manufacturers’guidelines and recommendations for maintenance of the Facility
equipment applicable to the previous calendar year.
9.45 At any time from the Effective Date,one (1)year’s advance notice of
the termination or expiration of any agreement,including Wind Leases,pursuant to
which the Facility or any equipment relating thereto is upon the Facility site;provided
that the foregoing does not authorize any early termination of any land lease.
9.4.6 As soon as it is known to Seller,Seller shall disclose to PaciflCorp,the
extent of any material violation of any environmental laws or regulations arising out of
the construction or operation of the Facility,or the presence of Environmental
Contamination at the Facility or on the Premises,alleged to exist by any Governmental
Authority having jurisdiction over the Premises,or the present existence of,or the
occurrence during Seller’s occupancy of the Premises of,any enforcement,legal,or
regulatory action or proceeding relating to such alleged violation or alleged presence of
Environmental Contamination presently occurring or having occurred during the period
of time that Seller has occupied the Premises.
9.5 Maintenance of Metering Equipment.To the extent not otherwise provided in
the Generator Interconnection Agreement,PacifiCorp shall inspect,test,repair and replace the
metering equipment periodically,or at the request of Seller if Seller has reason to believe
metering may be off and requests an inspection in writing.To the extent not otherwise
provided in the Generator Interconnection Agreement,all PacifiCorp’s costs relating to
designing,installing,maintaining,and repairing metering equipment installed to accommodate
Seller’s Facility shall be borne by Seller.
SECTION 10:BILLINGS,COMPUTATIONS AND PAYMENTS
10.1 Payment for Net Output.On or before the thirtieth (30th)day following the end
of each Billing Period,PacifiCorp shall send to Seller payment for Seller’s deliveries of Net
Output to PacifiCorp,together with computations supporting such payment.PaciflCorp may
offset any such payment to reflect amounts owing from Seller to PaciflCorp pursuant to this
Agreement or the Generation Interconnection Agreement .Any such offsets shall be
separately itemized on the statement accompanying each payment to Seller.
10.2 Annual Invoicing for Output Shortfall.Thirty calendar days after the end of
each Contract Year,PacifiCorp shall deliver to Seller an invoice showing PacifiCorp’s
computation of Output Shortfall,if any,for all Billing Periods in the prior Contract Year and
Output Shortfall Damages,if any.In preparing such invoices,PacifiCorp shall utilize the
meter data provided to PacifiCorp for the Contract Year in question,but may also rely on
historical averages and such other information as may be available to PacifiCorp at the time of
invoice preparation if the meter data for such Contract Year is then incomplete or otherwise
not available.To the extent required,PacifiCorp shall prepare any such invoice as promptly
26
Cedar Creek WInd,LLC’—Rattlesnake Canyon
as practicable following its receipt of actual results for the relevant Contract Year.Seller shall
pay to PacifiCorp,by wire transfer of immediately available funds to an account specified in
writing by PacifiCorp or by any other means agreed to by the Parties in writing from time to
time,the amount set forth as due in such invoice,and shall within thirty (30)days after
receiving the invoice raise any objections regarding any disputed portion of the invoice.
Objections not made by Seller within the thirty-day period shall be deemed waived,
10.3 Interest on Overdue Amounts.Any amounts owing after the due date thereof
shall bear interest at the Prime Rate on the date the amount became due,plus two percent
(2%),from the date due until paid;provided,however,that the interest rate shall at no time
exceed the maximum rate allowed by applicable law.
10.4 Disputed Amounts.If either Party,in good faith,disputes any amount due
pursuant to an invoice rendered hereunder,such Party shall notify the other Party of the
specific basis for the dispute and,if the invoice shows an amount due,shall pay that portion of
the statement that is undisputed,Ofi or before the due date.Any such notice shall be provided
within two (2)years of the date of the invoice in which the error first occurred.If any amount
disputed by such Party is determined to be due to the other Party,or if the Parties resolve the
payment dispute,the amount due shall be paid within five (5)days after such determination or
resolution,along with interest in accordance with Section 10.3.
SECTION 11:SECURITY
11.1 Delay Security:
11.1.1 Duty to Post Security.By the date provided in Section 2,2.2,Seller
shall post a Letter of Credit,cash or a parental guaranty,each in a form acceptable to
PacifiCorp,in the amount of $1,429,585 as calculated pursuant to Section 11.1.2
(“Delay Security”).To the extent PacifiCorp receives payment from the Delay
Security,Seller shall,within fifteen (15)calendar days,restore the Delay Security as if
no such deduction had occurred.
11.1.2 Calculation of Delay Securj4y.The dollar value of Delay Security shall
equal the greater of:(1)forty-five dollars ($45)multiplied by the Maximum Facility
Delivery Rate with the Maximum Facility Delivery Rate being measured in kW;or (2)
the sum of the products,for each of the first three calendar months after the Scheduled
Commercial Operation Date,of:
the energy in the Initial Year Energy Delivery Schedule for the month (lcWh)
multiplied by the monthly weighted average On-Peak and Off-Peak Conforming
Energy Purchase Price for the months ($/MWh)divided by 1000.
Such amount shall be fixed upon execution of this Agreement.
11.1.3 Right to Draw on Security.PacifiCorp shall have the right to draw on
the Delay Security to collect Delay Liquidated Damages.Commencing on or about
27
Cedar Creek Wind,LLC—Rattlesnake Canyon
first of each month,PacifiCorp will invoice Seller for Delay Liquidated Damages
incurred,if any,during the preceding month.If insufficient Delay Security is
available,Seller shall pay PacifiCorp for invoiced Delay Liquidated Damages no later
than five business days after receiving such invoice.The Parties will make billings and
payments for Delay Liquidated Damages in accordance with Section 100
11.1.4 Partial Release of Delay Security.Provided that Seller has maintained
Delay Security in accordance with Section 11.1.1,PacifiCorp shall release one-third of
the original amount of Delay Security stated in Section 11.1.1 each time Seller
accomplishes a milestone (a)or (b),below:
(a)Seller has (i)executed the Generation Interconnection Agreement
with Transmission Provider;and (ii)paid in full any interconnection and/or
system upgrade costs Seller is obligated to pay in advance of interconnection
construction0
(b)Seller has poured the concrete foundation at each of its planned
individual Wind Turbine locations.
PacifiCorp shall make the partial refund of Delay Security required above within ten
business days of the date Seller provides PacifiCorp written notice (along with
satisfactory documentation thereof)that it has accomplished milestone (a)or (b).
11.1.5 Full Release of Delay Security.Unless PacifiCorp disputes whether
Seller has paid all Delay Liquidated Damages,PacifiCorp shall release all remaining
Delay Security upon the earlier of the 30th calendar day following commencement of
Commercial Operation or the 60th calendar day following PacifiCorp’s termination of
this Agreement.
11.1.6 Default.Seller’s failure to post and maintain Delay Security in
accordance with Section 11.1 will constitute an event of default,unless cured in
accordance with Section 12.1.1 of this Agreement.
11.2 Default Security (Levelized Pricing Only).
Reserved.
SECTION 12:DEFAULTS AND REMEDIES
12.1 The following events shall constitute defaults under this Agreement:
12.1.1 Non-Payment.Seller’s failure to make a payment when due under this
Agreement or post and maintain security in conformance with the requirements of
Section ii or maintain insurance in conformance with the requirements of Section 14
of this Agreement,if the failure is not cured within ten (10)business days after the
non-defaulting Party gives the defaulting Party a notice of the default.
28
Cedar Creek Wind,LLC—Rattlesnake Canyon
12.1.2 Breach of Representation.Breach by a Party of a representation or
warranty set forth in this Agreement,if such failure or breach is not cured within thirty
(30)days following written notice.
12.1.3 Default on Other Agreements.Seller’s failure to cure any default under
the Generation Interconnection Agreement or any other agreement between the parties
related to this Agreement,the Generation Interconnection Agreement,or the Facility
within the time allowed for a cure under such agreement or instrument.
12.1.4 Insolvency.A Party (a)makes an assignment for the benefit of its
creditors;(b)files a petition or otherwise commences,authorizes or acquiesces in the
commencement of a proceeding or cause of action under any bankruptcy or similar law
for the protection of creditors,or has such a petition filed against it and such petition is
not withdrawn or dismissed within sixty (60)days after such filing;(c)becomes
insolvent;or (d)is unable to pay its debts when due.
12.1.5 Material Adverse Change.A Material Adverse Change has occurred
with respect to Seller and Seller fails to provide such performance assurances as are
reasonably requested by PaciflCorp,within thirty (30)days from the date of such
request.
12.1.6 Sale to Third-Party.Seller’s sale of Net Output to an entity other than
PacifiCorp,as prohibited by Section 4.2.
12.1.7 Non-Delivery.Unless excused by an event of Force Majeure,Seller’s
failure to deliver any Net Energy for three consecutive calendar months.
12.1.8 A Party otherwise fails to perform any material obligation (including but
not limited to failure by Seller to meet any deadline set forth in Section 2.2.1 through
2.2.6)imposed upon that Party by this Agreement if the failure is not cured within
thirty (30)days after the non-defaulting Party gives the defaulting Party notice of the
default.
12.1.9 Seller fails to achieve the Commercial Online Date by the 91’day
following the Scheduled Commercial Online Date,provided,however,that,upon
written notice from the defaulting Party delivered prior to the 9151 day of delay,this
ninety (90)day period shall be extended by an additional one hundred and fifty (150)
days if (a)Seller has poured the concrete foundation at each of its planned individual
wind turbine locations;and (b)Seller replenishes Delay Default Security in accordance
with Section 11.1.1.Seller shall continue to accrue Delay Liquidated Damages in
accordance with Section 2.5 (Delay Price times the Delay Value)until the Project
achieves Commercial Operation or this Agreement is terminated.
12.2 In the event of any default hereunder,the non-defaulting Party must notify the
defaulting Party in writing of the circumstances indicating the default and outlining the
requirements to cure the default.If the default has not been cured within the prescribed time,
29
Cedar Creek Wind,LLC—Rattlesnake Canyon
above,the non-defaulting Party may terminate this Agreement at its sole discretion by
delivering written notice to the other Party and may pursue any and all legal or equitable
remedies provided by law or pursuant to this Agreement.The rights provided in this Section
12 are cumulative such that the exercise of one or more rights shall not constitute a waiver of
any other rights.
12.3 In the event this Agreement is terminated because of Seller’s default and Seller
wishes to again sell Net Output from the facility using the same motive force to PacifiCorp
following such termination,PacifiCorp in its sole discretion may require that Seller do so
subject to the terms of this Agreement,including but not limited to the purchase prices as set
forth in (Section 5),until the Expiration Date (as set forth in Section 2.1).At such time Seller
and PacifiCorp agree to execute a written document ratifying the ternis of this Agreement.
12.4 If this Agreement is terminated as a result of Seller’s default,in addition to and
not in limitation of any other right or remedy under this Agreement or applicable law
(including any right to set-off,counterclaim,or otherwise withhold payment),Seller shall pay
PacifiCorp Output Shortfall Damages for a period of eighteen (18)months from the date of
termination plus the estimated administrative cost to acquire the replacement power.The
Parties agree that the damages PacifiCorp would incur due to termination resulting from
Seller’s default would be difficult or impossible to predict with certainty,and that the damages
in this Section 12.4 are an appropriate approximation of such damages.
12.5 Recoupment of Damages.
(a)Default Security Available.If Seller has posted Default Security,
PacifiCorp may draw upon that security to satisfy any damages,above.
(b)Default Security Unavailable,If Seller has not posted Default Security,or
if PacifiCorp has exhausted the Default Security,PacifiCorp may collect
any remaining amount owing by partially withholding future payments to
Seller over a reasonable period of time.PacifiCorp and Seller shall work
together in good faith to establish the period,and monthly amounts,of
such withholding so as to avoid Seller’s default on its commercial or
financing agreements necessary for its continued operation of the Facility.
12.6 Upon an event of default or termination event resulting from default under this
Agreement,in addition to and not in limitation of any other right or remedy under this
Agreement or applicable law (including any right to set-off,counterclaim,or otherwise
withhold payment),the non-defaulting Party may at its option set-off,against any amounts
owed to the defaulting Party,any amounts owed by the defaulting Party under any contract(s)
or agreement(s)between the Parties.The obligations of the Parties shall be deemed satisfied
and discharged to the extent of any such set-off.The non-defaulting Party shall give the
defaulting Party written notice of any set-off,but failure to give such notice shall not affect the
validity of the set-off.
12.7 Amounts owed by Seller pursuant to this Section 12 shall be due within five (5)
business days after any invoice from PacifiCorp for the same.
30
Cedar Creek Wind,LLC—Rattlesnake Canyon
SECTION 13:INDEMNIFICATION;LIABILITY
13.1 Indemnities.
13.1.1 Indemnity by Seller.Seller shall release,indemnify and hold harmless
PacifiCorp,its directors,officers,agents,and representatives against and from any and
all loss,fines,penalties,claims,actions or suits,including costs and attorney’s fees,
both at trial and on appeal,resulting from,or arising out of or in any way connected
with (a)the energy delivered by Seller under this Agreement to and at the Point of
Delivery,(b)any facilities on Seller’s side of the Point of Delivery,(c)Seller’s
operation and/or maintenance of the Facility,or (d)arising from Seller’s breach of this
Agreement,including without limitation any loss,claim,action or suit,for or on
account of injury,bodily or otherwise,to,or death of,persons,or for damage to,or
destruction or economic loss of property belonging to PacifiCorp,Seller or others,
excepting only such loss,claim,action or suit as may be caused solely by the fault or
gross negligence of PacifiCorp,its directors,officers,employees,agents or
representatives.
13.1.2 Indemnity by PacifiCorp.PacifiCorp shall release,indemnify and hold
harmless Seller,its directors,officers,agents,lenders and representatives against and
from any and all loss,fmes,penalties,claims,actions or suits,including costs and
attorney’s fees,both at trial and on appeal,resulting from,or arising out of or in any
way connected with the energy delivered by Seller under this Agreement after the Point
of Delivery,including without limitation any loss,claim,action or suit,for or on
account of injury,bodily or otherwise,to,or death of,persons,or for damage to,or
destruction or economic loss of property,excepting only such loss,claim,action or suit
as may be caused solely by the fault or gross negligence of Seller,its directors,
officers,employees,agents,lenders or representatives.
13.2 No Dedication.Nothing in this Agreement shall be construed to create any
duty to,any standard of care with reference to,or any liability to any person not a Party to
this Agreement.No undertaking by one Party to the other under any provision of this
Agreement shall constitute the dedication of that Party’s system or any portion thereof to the
other Party or to the public,nor affect the status of PacifiCorp as an independent public utility
corporation or Seller as an independent individual or entity.
13.3 No Warranty.Any review,acceptance or failure to review Seller’s design,
specifications,equipment or facilities shall not be an endorsement or a confirmation by
PaciflCorp and PacifiCorp makes no warranties,expressed or implied,regarding any aspect of
Seller’s design,specifications,equipment or facilities,including,but not limited to,safety,
durability,reliability,strength,capacity,adequacy or economic feasibility.
13.4 CONSEQUENTiAL DAMAGES.EXCEPT TO THE EXTENT SUCH
DAMAGES ARE INCLUDED IN THE LIQUIDATED DAMAGES,DELAY DAMAGES,
OR OTHER SPECIFIED MEASURE OF DAMAGES EXPRESSLY PROVIDED FOR IN
THIS AGREEMENT,NEITHER PARTY SHALL BE LIABLE TO THE OTHER PARTY
31
Cedar Creek Wind,LLC—Rattlesnake Canyon
FOR SPECIAL,PUNITIVE,INDIRECT,EXEMPLARY OR CONSEQUENTIAL
DAMAGES,WHETHER SUCH DAMAGES ARE ALLOWED OR PROVIDED BY
CONTRACT,TORT (INCLUDING NEGLIGENCE),STRICT LIABILITY,STATUTE OR
OTHERWISE.
SECTION 14:INSURANCE
14.1 Certificates.Prior to connection of the Facility to the System,Seller shall
secure and continuously carry insurance in compliance with the requirements of this Section.
Seller shall provide PacifiCorp insurance certificate(s)(of “ACORD Form”or the equivalent)
certifying Seller’s compliance with the insurance requirements hereunder.Commercial
General Liability coverage written on a “claims-made”basis,if any,shall be specifically
identified on the certificate.If requested by PacifiCorp,a copy of each insurance policy,
certified as a true copy by an authorized representative of the issuing insurance company,shall
be furnished to PacifiCorp.
14.2 Required Policies and Coveraes.Without limiting any liabilities or any other
obligations of Seller under this Agreement,Seller shall secure and continuously carry with an
insurance company or companies rated not lower than “A-:VII”by the A.M.Insurance
Reports the insurance coverage specified below:
14.2.1 Commercial General Liability insurance,to include contractual liability,
with a minimum single limit of $1,000,000 per occurrence to protect against and from
all loss by reason of injury to persons or damage to property based upon and arising
out of the activity under this Agreement.
14.2.2 All Risk Property insurance providing coverage in an amount at least
equal to 80%of the replacement value of the Facility against “all risks”of physical loss
or damage,including coverage for earth movement,flood,and boiler and machinery.
The Property policy may contain separate sub-limits and deductibles subject to
insurance company underwriting guidelines.The Risk Policy will be maintained in
accordance with terms available in the insurance market for similar facilities.
14.3 The Commercial General Liability policy required herein shall include (i)
provisions or endorsements naming PacifiCorp,its Board of Directors,Officers and
employees as additional insureds,and (ii)cross liability coverage so that the insurance applies
separately to each insured against whom claim is made or suit is brought,even in instances
where one insured claims against or sues another insured.
14.4 All liability policies required by this Agreement shall include provisions that
such insurance is primary insurance with respect to the interests of PacifiCorp and that any
other insurance maintained by PaciflCorp is excess and not contributory insurance with the
insurance required hereunder,and provisions that such policies shall not be canceled or their
limits of liability reduced without (i)ten (10)business days prior written notice to PaciflCorp
32
Cedar Creek Wind LLC—Rattlesnake Canyon
if canceled for nonpayment of premium,or (ii)thirty (30)business days prior written notice to
PacifiCorp if canceled for any other reason.
14.5 Connnercial General Liability insurance coverage provided on a “claims-made
basis shall be maintained by Seller for a minimum period of five (5)years after the completion
of this Agreement and for such other length of time necessary to cover liabilities arising out of
the activities under this Agreement.
SECTION 15:FORCE MAJEURE
15.1 As used in this Agreement,“Force Majeure”or “an event of Force Ma.jeure”
means any cause beyond the reasonable control of the Seller or of PacifiCorp which,despite
the exercise of due diligence,such Party is unable to prevent or overcome.By way of
example,Force Majeure may include but is not limited to acts of God,flood,storms,wars,
hostilities,civil strife,strikes,and other labor disturbances,earthquakes,fires,lightning,
epidemics,sabotage,restraint by court order or other delay or failure in the performance as a
result of any action or inaction on behalf of a public authority which is in each case (i)beyond
the reasonable control of such Party,(ii)by the exercise of reasonable foresight such Party
could not reasonably have been expected to avoid and (iii)by the exercise of due diligence,
such Party shall be unable to prevent or overcome.Force Majeure,however,specifically
excludes the cost or availability of fuel or motive force to operate the Facility or changes in
market conditions that affect the price of energy or transmission.If either Party is rendered
wholly or in part unable to perform its obligation under this Agreement because of an event of
Force Majeure,both Parties shall be excused from whatever performance is affected by the
event of Force Majeure,provided that:
15.1.1 the non-performing Party,shall,within two (2)weeks after the
occurrence of the Force Majeure,give the other Party written notice describing the
particulars of the occurrence,including the start date of the Force Majeure,the cause
of Force Majeure,whether the Facility remains partially operational and the expected
end date of the Force Majeure;
15.1.2 the suspension of performance shall be of no greater scope and of no
longer duration than is required by the Force Majeure;
15.1.3 the non-performing Party uses its best efforts to remedy its inability to
perform;and
15.1.4 the non-performing Party shall provide prompt written notice to the
other Party at the end of the Force Majeure event detailing the end date,cause there of,
damage caused there by and any repairs that were required as a result of the Force
Majeure event,and the end date of the Force Majeure.
15.2 No obligations of either Party which arose before the Force Majeure causing the
suspension of performance shall be excused as a result of the Force Majeure.
33
Cedar Creek Wind,LLC—Rattlesnake Canyon
153 Neither Party shall be required to settle any strike,walkout,lockout or other
labor dispute on terms which,in the sole judgment of the Party involved in the dispute,are
contrary to the Party s best interests.
SECTION 16:SEVERAL OBLIGATIONS
Nothing contained in this Agreement shall ever be construed to create an association,trust,
partnership or joint venture or to impose a trust or partnership duty,obligation or liability
between the Parties.If Seller includes two or more parties,each such party shall be jointly and
severally liable for Seller’s obligations under this Agreement.
SECTION 17:CHOICE OF LAW
This Agreement shall be interpreted and enforced in accordance with the laws of the state of
Idaho,excluding any choice of law rules which may direct the application of the laws of another
jurisdiction.
SECTION 18:PARTIAL INVALIDITY
It is not the intention of the Parties to violate any laws governing the subject matter of this
Agreement.If any of the terms of the Agreement are finally held or determined to be invalid,
illegal or void as being contrary to any applicable law or public policy,all other terms of the
Agreement shall remain in effect.If any terms are finally held or determined to be invalid,
illegal or void,the Parties shall enter into negotiations concerning the terms affected by such
decision for the purpose of achieving conformity with requirements of any applicable law and
the intent of the Parties to this Agreement.
SECTION 19:WAIVER
Any waiver at any time by either Party of its rights with respect to a default under this
Agreement or with respect to any other matters arising in connection with this Agreement must
be in writing,and such waiver shall not be deemed a waiver with respect to any subsequent
default or other matter.
SECTION 20:GOVERNMENTAL JURISDICTION AND AUTHORIZATIONS
PacifiCorp’s compliance with the terms of this Agreement is conditioned on Seller’s submission
to PacifiCorp prior to the Commercial Operation Date of copies of all local,state and federal
licenses,permits and other approvals as then may be required by law for the construction,
operation and maintenance of the Facility.Failure to maintain such lawful status after the
Commercial Operation Date shall be an event of default,subject to Section 12.
34
Cedar Creek Wind,LLC—Rattlesnake Canyon
SECTION 21:SUCCESSORS AND ASSIGNS
This Agreement and all of the terms and provisions hereof shail be binding upon and inure to the
benefit of the respective successors and assigns of the Parties hereto,except that no assignment
hereof by either Party shall become effective without the written consent of both Parties being
first obtained.Such consent shall not be unreasonably withheld.Notwithstanding the foregoing,
any entity with which PacifiCorp may consolidate,or into which it may merge,or to which it
may convey or transfer substantially all of its electric utility assets,shall automatically,without
further act,and without need of consent or approval by the Seller,succeed to all of PacifiCorp’s
rights,obligations,and interests under this Agreement.This article shall not prevent a financing
entity with recorded or secured rights from exercising all rights and remedies available to it
under law or contract.PacifiCorp shall have the right to be notified by the financing entity that it
is exercising such rights or remedies.
SECTION 22:ENTifiE AGREEMENT
22.1 This Agreement supersedes all prior agreements,proposals,representations,
negotiations,discussions or letters,whether oral or in writing,regarding PacifiCorp’s
purchase of Net Output from the Facility.No modification of this Agreement shall be
effective unless it is in writing and signed by both Parties.
22.2 By executing this Agreement,each Party releases the other from any
claims,known or unknown,that may have arisen prior to the execution date of this Agreement
with respect to the Facility and any predecessor facility proposed to have been constructed on
the site of the Facility.
SECTION 23:NOTICES
All notices except as otherwise provided in this Agreement shall be in writing,shall be
directed as follows and shall be considered delivered if delivered in person or when deposited
in the U.S.Mail,postage prepaid by certified or registered mail and return receipt requested.
Notices PacifiCorp Seller
All Notices PacifiCorp Cedar Creek Wind,LLC
825 NE Muitnomab Street Portland,7OlB Winslow Way E
OR 97232 Bambridge Island,WA 981 10
Attn:Contract Administration,Attn:Richard W.Burkhardt
Suite 600 Phone:[phone]
Phone:[phone] Facsimile:(206)780 -3571
Facsimile:(503)813 —6291
E-mail:E-mail:
[e-mail]
Dims:00-790-9013 Duns:83-297-9483
Federal Tax ID Number:93-0246090 Federal Tax ID Number:80-0326531
35
Cedar Creek Wind,LLC—Ratttesnake Canyon
Notices PacifiCorp Seller
All Invoices:Attn:Back Office,Suite 700 Attn:(accounting(dsurnmitpower.cornj
Phone:[phone] Vici Hall,General Accounting
Facsimile:(503)813 —5580 Manager ([e-mail])
Phone:[phone]
Scheduling:Attn:Resource Planning,Suite 600 Attn:(tcameron@,smnniitpower.com)
Phone:[phone] Thomas Cameron
Facsimile:(503)813 —6265 [phone]
Payments:Attn:Back Office,Suite 700 Atth:(accounfing(summitpower.com)
Phone:[phone] Vici Hall,General Accounting
Facsimile:(503)813 —5580 Manager (vhall(sumrnitpower.coir)
Phone:[phone]
Wire Transfer:Bank One N.A.BNK:Wells Fargo
To be provided in separate letter from To be provided in separate letter from
PaciflCorp to Seller Seller to PaciflCorp
Credit and Attn:Credit Manager,Suite 700 Attn:Richard W.Burkhardt
Collections:Phone:[phone] (rburkhardt@,summitpower.com)
Facsimile:[phone] Chief Financial Officer
Phone:[phone]
With Additional Attn:PaciflCorp General Counsel Attn:Richard W.Burkhardt
Notices of an Phone:[phone] ([e-mail])
Event of Default Facsimile:[phone] ChiefFinancial Officer
.Phone:[phone]
or Potential
Event of Default Davis Wright Tremaine LLP
to:1201 Third Avenue,Suite 2200
Seattle,WA 98101
Attention:Scott MacCormack
Facsimile No.:[phone]
The Parties may change the person to whom such notices are addressed,or their addresses,by
providing written notices thereof in accordance with this Section.
J WITNESS WHEREOF,the Parties hereto have caused this Agreement to be executed
in thgr re ectiv ames as ofthe date first above written.
Pac C Seller (Cedar reek Wind.LLC)
Nara:cc s old
Title:Dir ,Short Term Origination Title:President
and QF Contracts
36
EXHIBIT 5
IDAHO PUC ORDER NO.32192
Office of the Secretary
Service Date
February 24,2011
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )PACIFICORP DBA ROCKY MOUNTAIN )CASE NO.PAC-E-11-O1
POWER FOR A DETERMINATION )
REGARDING A FIRM ENERGY SALES )AGREEMENT BETWEEN ROCKY )MOUNTAIN POWER AND CEDAR CREEK )WIND,LLC (RATTLESNAKE CANYON )PROJECT))
____________________________________________________________________________________
)IN THE MATTER OF THE APPLICATION OF )PACIFICORP DBA ROCKY MOUNTAIN )CASE NO.PAC-E-1 1-02POWERFORADETERMINATION)REGARDING 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 )CASE NO.PAC-E-11-03
POWER FOR A DETERMINATION )
REGARDING A FIRM ENERGY SALES )AGREEMENT BETWEEN ROCKY )MOUNTAIN POWER AND CEDAR CREEK )WIND,LLC (NORTH POINT PROJECT))
_______________________________________________________________________________
)IN THE MATTER OF THE APPLICATION OF )PACIFICORP DBA ROCKY MOUNTAIN )CASE NO.PAC-E-11-04
POWER FOR A DETERMINATION )REGARDING A FIRM ENERGY SALES )AGREEMENT BETWEEN ROCKY )MOUNTAIN POWER AND CEDAR CREEK )WIND,LLC (STEEP RIDGE PROJECT))
____________________________________________________________________________________________
)IN THE MATTER OF THE APPLICATION OF )PACWICORP DBA ROCKY MOUNTAIN )CASE NO.PAC-E-11-05POWERFORADETERMINATION)REGARDING A FIRM ENERGY SALES )NOTICE OF APPLICATIONS
AGREEMENT BETWEEN ROCKY )MOUNTAIN POWER AND CEDAR CREEK )NOTICE OF
WIND,LLC (FIVE PINE PROJECT))MODIFIED PROCEDURE
)
__________________________
ORDERNO.32192
NOTICE OF APPLICATIONS
NOTICE OF MODIFIED PROCEDURE
ORDERNO.32192 1
On January 10,2011,PacifiCorp dba Rocky Mountain Power filed Applications
requesting acceptance or rejection of five 20-year Firm Energy Sales Agreements (Agreements)
between Rocky Mountain Power and Cedar Creek Wind,LLC for its Rattlesnake Canyon,
Coyote Hill,North Point,Steep Ridge and Five Pine wind projects.All five projects (Facilities)
are located near Bingham County,Idaho.The projects will all be “qualifying facilities”(QFs)
under the applicable provisions of the federal PURPA.
NOTICE OF APPLICATIONS
YOU ARE HEREBY NOTIFIED that,on December 22,2010,Rocky Mountain
Power and each of the five wind projects entered into their respective Agreements.Under the
terms of the Agreements,the wind projects each agree to sell electric energy to Rocky Mountain
Power for a 20-year term using the current non-levelized published avoided cost rates as
currently established by the Commission in Order No.31025 for energy deliveries of less than 10
aMW.Applications at 8-9.The nameplate rating of Rattlesnake Canyon,Coyote Hill and North
Point is 27.6 MW each.The nameplate rating of Steep Ridge and Five Pine is 25.2 MW each.
Under normal and/or average conditions,each Facility will not exceed 10 aMW on a monthly
basis.Rocky Mountain Power warrants that the Agreements comport with the terms and
conditions of the various Commission Orders applicable to PURPA agreements for wind
resources.Order Nos.30415,30488,30738 and 31025.
A.The Agreements
YOU ARE FURTHER NOTIFIED that each Facility has selected October 1,2012,as
its Scheduled Commercial Operation Date.Applications at 9.Rocky Mountain Power asserts
that various requirements have been placed upon the Facilities in order for Rocky Mountain
Power to accept the Facilities’energy deliveries.Rocky Mountain Power states that it will
monitor the Facilities’compliance with initial and ongoing requirements through the term of the
Agreements.Rocky Mountain Power asserts that it has advised each Facility of the Facility’s
responsibility to work with Rocky Mountain Power’s transmission unit to ensure that sufficient
time and resources will be available for delivery to construct the interconnection facilities,and
transmission upgrades if required,in time to allow each Facility to achieve its October 1,2012,
Scheduled Commercial Operation Date.
YOU ARE FURTHER NOTIFIED that Rocky Mountain Power asserts that each
Facility has been advised that delays in the interconnection or transmission process do not
NOTICE OF APPLICATIONS
NOTICE OF MODIFIED PROCEDURE
ORDER NO.32192 2
constitute excusable delays and if a Facility fails to achieve its Scheduled Commercial Operation
Date delay damages will be assessed.Id.at 11.The Applications further maintain that each
Facility has acknowledged and accepted the risk inherent in proceeding with its Agreement
without knowledge of the requirements of interconnection and possible transmission upgrades.
Id.The parties have each agreed to delay liquidated damages and security provisions.
Agreement ¶j 2.5.1,11.1.2.Rocky Mountain Power states that each Facility has also been made
aware of and accepted the provisions in each Agreement regarding curtailment or disconnection
of its Facility should certain operating conditions develop on Rocky Mountain Power’s system.
Agreement ¶6.3.
YOU ARE FURTHER NOTIFIED that,by their own terms,the Agreements will not
become effective until the Commission has approved all of the terms and conditions and declares
that all payments made by Rocky Mountain Power to the Facilities for purchases of energy “are
just and reasonable,in the public interest,and that the costs incurred by [Rocky Mountain
Power]for purchases of capacity and energy from [Cedar Creek]are legitimate expenses,all of
which the Commission will allow [Rocky Mountain Power]to recover in rates in Idaho in the
event other jurisdictions deny recovery of their proportionate share of said expenses.”
Agreement ¶2.1.
YOU ARE FURTHER NOTIFIED that Rocky Mountain Power’s Applications
specifically note the Joint Petition it filed with the Commission on November 5,2010,requesting
an immediate reduction in the published avoided cost rate eligibility cap from 10 aMW to 100
kW.Applications at 3.Rocky Mountain Power states that it is aware of and in compliance with
its ongoing obligation under federal law,FERC regulations,and Commission Orders to enter
into power purchase agreements with PURPA QFs.Id.at 4.However,Rocky Mountain Power
“is concerned with the increase in power supply costs,and the resulting increase in rates to its
customers,that the current published SAR-methodology avoided cost prices causes as compared
to applying the IRP-methodology or the results from a competitive request for proposal
solicitation.”Id.at 5.Rocky Mountain Power points out that published rate purchases “result in
an inherent overpayment to the extent that the project does not offer the same delivery attributes
as the proxy resource on which the avoided costs are calculated....Because a contract under
the published QF rate has minimal flexibility to adjust pricing or the terms and conditions in the
contract based on the project’s characteristics,wind resources have found the QF path more
NOTICE OF APPLICATIONS
NOTICE OF MODIFIED PROCEDURE
ORDER NO.32192 3
conducive to gaining a long term power purchase agreement without the project specific
adjustments they would encounter through the IRP-methodology or a competitive request for
proposal solicitation’Id at 6.
NOTICE OF MODIFIED PROCEDURE
YOU ARE FURTHER NOTIFIED that the Commission has determined that the
public interest may not require a formal hearing for these five Applications and will proceed
under Modified Procedure pursuant to Rules 201 through 204 of the Idaho Public Utilities
Commissions Rules of Procedure,IDAPA 31.01.01.201 through .204.The Commission notes
that Modified Procedure and written comments have proven to be an effective means for
obtaining public input and participation.
YOU ARE FURTHER NOTIFIED that any person desiring to state a position on
these Applications or any individual Application may file a written comment in support or
opposition with the Commission no later than March 24,2011.The comment must contain a
statement of reasons supporting the comment.Persons desiring a hearing must specifically
request a hearing in their written comments.Written comments concerning any of these
Applications shall be mailed to the Commission and Rocky Mountain Power at the addresses
reflected below:
Commission Secretary Daniel E.Solander
Idaho Public Utilities Commission Rocky Mountain Power
P0 Box 83720 201 South Main,Suite 2300
Boise,ID 83 720-0074 Salt Lake City,UT 84111
E-Mail:[e-mail]
Street Address for Express Mail:
Ted Weston
472 W.Washington Street Rocky Mountain Power
Boise,ID 83702-5918 201 South Main,Suite 2300
Salt Lake City,UT 84111
E-Mail:[e-mail]
Comments should contain the case captions and case numbers shown on the first page of this
document.Persons desiring to submit comments via e-mail may do so by accessing the
Commissions home page located at www.puc.idaho.gov.Click the ‘comments and Question’
icon and complete the comment form using the case numbers as they appear on the front of this
document.These comments must also be sent to Rocky Mountain Power at the e-mail addresses
listed above.
NOTICE OF APPLICATIONS
NOTICE OF MODIFIED PROCEDURE
ORDERNO.32192 4
YOU ARE FURTHER NOTIFIED that Rocky Mountain Power may file reply
comments (if necessary)no later than March 31,2011.
YOU ARE FURTHER NOTIFIED that if no written comments or protests are
received within the time limit set,the Commission will consider each Application on its merits
and enter Orders without a formal hearing.If written comments are received within the time
limit set,the Commission will consider them and,in its discretion,may set the same for formal
hearing.
YOU ARE FURTHER NOTIFIED that the five Applications have been filed with the
Commission and are available for public inspection during regular business hours at the
Commission offices.The Applications are also available on the Commission’s web site at
www.puc.idaho.gov by clicking on “File Room”and then “Electric Cases.”
YOU ARE FURTHER NOTIFIED that all proceedings in these cases will be held
pursuant to the Commission’s jurisdiction under Title 61 of the Idaho Code and the Public Utility
Regulatory Policies Act of 1978 (PURPA).The Commission has authority under PURPA and
the implementing regulations of the Federal Energy Regulatory Commission (FERC)to set
avoided costs,to order electric utilities to enter into fixed-term obligations for the purchase of
energy from qualified facilities and to implement FERC rules.
YOU ARE FURTHER NOTIFIED that all proceedings regarding these Applications
will be conducted pursuant to the Commission’s Rules of Procedure,IDAPA 31.01.01.000,et
seq.
ORDER
IT IS HEREBY ORDERED that these cases be processed under Modified Procedure.
Interested persons and the parties may file written comments no later than March 24,2011.
IT IS FURTHER ORDERED that Rocky Mountain Power may file reply comments
no later than March 31,2011.
NOTICE OF APPLICATIONS
NOTICE OF MODIFIED PROCEDURE
ORDER NO.32192 5
DONE by Order of the Idaho Public Utilities Commission at Boise,Idaho this Z’/’”
day of February 2011.
J .KEMPTON P SIDENT
L1tL LL
MARSHA H.SMITH,COMMISSIONER
MACK A.REDFORD,COMMISSIONER
ATTEST:
JD.Jew
Commission Secretary
O:PAC-E-11-0 IPAC-E-J I -02 PAC.-E.I I -03 PAC-E-1 1-04 PAC-E-.I I -O5ks
NOTICE OF APPLICATIONS
NOTICE OF MODIFIED PROCEDURE
ORDER NO.32192 6
EXHIBIT 6
CEDAR CREEK WIND INITIAL COMMENTS
WILLIAMS •BRADBURY
AT TORN Y S AT LAW
r’!
ZOiiN26 t1U:26
January26,20l1
1Lé-Idaho Pub1ic-Seis4.Commission
472 W.Washington Street
Boise,ID 83702
ATTN:Jean D.Jewell
Commission Secretary
Re:In the Matter of the Application of Rocky Mountain Power for Approval of PowerPurchaseAgreementsBetweenRockyMountainPowerandCedarCreekWind
Dear Jean:
Please find enclosed the original and seven (7)copies of Comments of Cedar CreekWindLLCinSupportofRockyMountainPower’s Application for Approval of a PowerPurchaseAgreement,together with Affidavit of Dana Zentz,in each of the following actions:
Rattlesnake Canyon PAC-E-1 1-01CoyoteHillPAC-E-11-02NorthPointPAC-E-11-03SteepRidgePAC-E-11-04FivePinePAC-E-1 1-05
Sincerely,
Ronald L.Williams
RLW/jr
Enclosures
1015 W.Hays Street -Boise,ID 83702Phone:[phone] -Fax:[phone] -www.williamsbradbuxy.com
Ronald L.Williams,ISB No.3034
Williams Bradbury,P.C.
1015 W.Hays St.ZDII 25 i i 27BoiseID,83702
Telephone [phone]
Fax:[phone] TlLi
ronwi1liamsbradbury.com
Attorneys for Cedar Creek Wind,LLC
BEFORE THE IDAHO PUBLIC UTILITES COMMISSION
IN THE MATI’ER OF THE APPLICATION )Case No.PAC-E-l 1-01OFROCKYMOUNTAiNPOWERFOR)APPROVAL OF POWER PURCHASE )COMMENTS OF CEDAR CREEKAGREEMENTSBETWEENRMPAND)WIND LLC TN SUPPORT OF ROCKYCEDARCREEKWINDLLC)MOUNTAIN POWER’S APPLICATION
)FOR APPROVAL OF A POWER
___________________________)
PURCHASE AGREEMENT
Cedar Creek Wind,LLC (“Cedar Creek”or “CCW”)files these comments
in support of the Application in this case by Rocky Mountain Power (“RMP”or
“PacifiCorp”)for approval of the Power Purchase Agreement (“PPA”)between RMP and
Cedar Creek for the Rattlesnake Canyon Wind Project (the “Project”),For the reasons
stated below,Cedar Creek requests that the Commission approve the PPA.
STATEMENT OF FACT
For a full and complete statement of the facts in this case please see the
accompanying affidavit of Dana Zentz.
The electrical interconnection study process for this Project and the other four
CCW wind projects commenced in 2008 and is now at a very mature stage.Zentz
Affidavit,¶6.System impact studies for this Project were completed by RMP in 2009,a
final facilities study report was issued by RMP in March of 2010 and CCW paid in April
Cedar Creek Wind,LLC Comments in Support of PPA Approval Page 1
2010 a $100,000 deposit for RMP to commence detailed interconnection engineering and
procurement of interconnection parts.Id All other material milestones needed for
electrical interconnection,short of actual facilities construction,have been met.In total,
Cedar Creek has paid over $475,000 to RMP for interconnection and PTP application,
along with cost studies,transmission system impact studies and for project specific
engineering and procurement.id.
Cedar Creek Wind was an unsuccessful bidder of approximately 150 MW of wind
generation in PacifiCorp’s 2008/2009 Requests for Proposals for renewable energy.
Instead,PacifiCorp selected Wyoming based wind generation in that RFP process.As a
result,in late 2009,CCW began negotiations with RMP for the sale of power from two
78 MW wind Qualify Facilities.In early 2010 Cedar Creek asked RMP to run its
integrated resource (IR)model to calculate the PURPA rate for two 78 MW wind
projects.In late April 2010,RMP responded with IR model results showing a first year
(2012)non-leveljzed PURPA rate of $37.0l/MWh (which included the $6.50/MWh wind
integration charge).This “calculated”avoided cost rate was 35%below the 2012 non
levelized net avoided cost rate of $57.47/MWh established by the Commission on March
16,2010 for PaciiICorp.Id.,¶5.More importantly,the non-negotiable rate offered by
RMP to CCW was uneconomic and un-financeable for purposes of developing the Cedar
Creek wind project.
At this point in the spring of2010 CCW had two choices:(i)contest before the
Commission the accuracy of RMP’s modeling of its avoided cost,or (ii)reduce the
amount of gross generation and sacrifice the economies of scale associated with two 78
MW wind projects and reconfigure into five separate PURPA projects not greater than 10
Cedar Creek Wind,LLC Comments in Support of PPA Approval Page 2
aMW,in order to qualify for Surrogate Avoided Resource (“SAR”)based avoided cost
rates.Cedar Creek chose the latter option,as a contested case before the Commission
challenging PacifiCorp’s IR model would have been extremely expensive and involved
delay likely fatal to the Project.Id.,¶J 2-5.
Starting in early May 2010,RMP and CCW were in almost constant
communication and then negotiations concerning PPAs for the five Cedar Creek 10 aMW
wind projects.Much of the data and detail concerning the CCW projects requested by
PacifiCorp was beyond the scope considered reasonable and necessary for a PURPA
PPA,but CCW complied with all of PacifiCorp’s requests fully,even though doing so
further delayed the eventual delivery of a first draft PPA from PacifiCorp.Zentz Affidavit,
¶J 14,15 While PacifiCorp’s motive for these requests may or may not have been to
delay the execution of the PPAs,the facts of the case are that the PPAs would have been
ready for execution several months before the end of 2010,but for these requests.
Likewise,contract negotiations concerning ownership of renewable energy credits
further stalled a final PPA.Nonetheless,Cedar Creek and PacifiCorp still came to a
meeting of the minds and agreed to final terms and conditions of a PPA for this Project
by November 29,2010.On that date,PacifiCorp transmitted to CCW a “proposed final
redline”PPA,and on that same date Cedar Creek responded “we have nothing further.”
1d,J 16.
While the PPA for this Project should have been signed the first week of
December,PacifiCorp started to slow the process down again,by failing to deliver an
executable PPA to CCW,based on a newly announced need for additional credit,legal
and management review of this Project’s PPA and the other four Cedar Creek PPAs.
Cedar Creek Wind,LLC Comments in Support of PPA Approval Page 3
This “new”review was focused on standard form contract language created by
PacifiCorp and on parts of those standard agreements which had not changed materially
if at all,since negotiations began.At that time CCW argued,to no avail,that the
standard contract language was well vetted with PacifiCorp management in advance of
the completion of the negotiations in November.Id.,¶J 17.
While CCW can not know why PacifiCorp inserted these new requirements at the
11th hour of the contracting process,the fact remains that the PPA for this Project was
ready to execute the first week of December,2010,and CCW was assured that
PacifiCorp was ready to execute,prior to the introduction of these new review
requirements.A final form,executable PPA for the Project was eventually delivered
from PacifiCorp to CCW on December 9,2010 with the statement from RMP that RMP
would be prepared to execute the Project’s PPA on Monday,December 13,2010.Id,¶
20.Cedar Creek executed the PPA for this Project on Monday,December 13,2010 and
hand-delivered the same to PacifiCorp at its office in Portland Oregon.PacifiCorp did not
execute this Project’s PPA until December 22,2010,twenty-three days after
acknowledging that the PPA was “in final form”and ready for execution and receiving
CCW’s execution of the same.
PacifiCorp acknowledges in three separate pleadings before this Commission that
this Project’s PPA,and the other four like them,were mature contracts with a meeting of
the minds reached between the parties before December 14,2010.First,in its Application
for contract approval in this case,PacifiCorp states:“The five [CCWJ projects..
complied with all PURPA’s regulation including the 1-mile separation requirement,
met all Idaho rules and Commission Orders.”Application ofRocky Mountain Power,
Cedar Creek Wind,LLC Comments in Support of PPA Approval Page 4
Case No.PAC-E-11-0I through 05,p.p.5,6.PacifiCorp’s Application further
acknowledges that this Project’s PPA was prepared by PacifiCorp,was executed by
CCW on December 13,2010,and complied with relevant Commission Order Nos.
29632,30423,31021,and 31025.Jd,p.8.
Further,Bruce Griswold,in his affidavit filed on January 19,2010,in Case No.
GNR-E-1-04,states:“Because Rocky Mountain Power and Cedar Creek Wind LLC
reached agreement on all terms of their power purchase agreements including price prior
to December 14,2010,Rocky Mountain Power executed final power purchase
agreements and,on January 10,2010,filed them with the Commission.”Case No.GNR
E-10-4,Griswola’B.,(Di),p.5.’
As a final acknowledgement that this PPA was agreed to and effectively entered
into by PacifiCorp and CCW prior to December 14,2010,PacifiCorp states in its Joint
Utility Docket Reply Comments of January 19,2011 that:“If Rocky Mountain Power
and the QF (under 10 aMW)both executed the power purchase agreement or reached
agreement on all final terms of a PPA prior to December 14,2010,Rocky Mountain
Power will pay Seller the published avoided cost prices.”Reply Comments ofRMP,pp
5-6.A footnote immediately following specifically references Cedar Creek:“An example
is the Cedar Creek Wind LLC QF development consisting of five separate and distinct
facilities each sized 10 aMW or less....[wherein]...Rocky Mountain Power and Cedar
Creek finished negotiations of all terms prior to December 14,2010.”IcL,Fn.10.
matters contained in parenthesis are omitted
Cedar Creek Wind,LLC Comments in Support of PPA Approval Page 5
STATEMENT OF LAW
In the Notice ofJoint Petition,Order No.321312,the Commission ordered that the
Commission’s decision regarding whether or not to reduce the published avoided cost
eligibility cap would become effective on December 14,2010.PacifiCorp,in its
Application in this case,asks the Commission for an Order “accepting or rejecting”this
Project’s PPA between Cedar Creek and RMP.However,RMP provides no guidance to
the Commission or evidence to support either of the two recommendations and instead
uses the Application to continue ‘pleading its case’in the Joint Utilities Docket for a
reduction in the published avoided cost rate eligibility cap.3 Unfortunately,the
Application is virtually void of any representations or proof as to whether this Project’s
PPA was “ripe”before December 14,2010.Consequently,Cedar Creek is compelled to
explain and document the facts that warrant approval of this Project’s PPA.To that effect
please refer to the accompanying affidavit of Dana Zentz and attachments thereto.
It is clear from the record,as supplemented by this filing,as well as excerpts of
the record from the Joint Utilities Docket,that this Project’s PPA should be approved by
the Commission and that CCW is entitled to the rates,terms and conditions contained
therein and that existed before December 14,2010.Specifically,Cedar Creek is entitled
to a contract with rates established by this Commission on March 16,2010 in Order No.
31025,for a PURPA QF wind project that contracts with PacifiCorp and does not
generate in excess of 10 aMW in any given month,in compliance with IPUC order No.
2See Joint Petition ofIdaho Power Company,Avista Utilities and Pacfficorp,GNR-E-10-04.
Cedar Creek Wind,LLC Comments in Support of PPA Approval Page 6
30497.This entitlement is due to Cedar Creek and PacifiCorp having resolved and
agreed to all material outstanding contract issues prior to December 14,2010.As
discussed below,both the Idaho Supreme Court and the Commission have previously
reviewed the question of maturity needed for a QF project to be entitled to vintage rates
or terms applicable before a certain date.
The Supreme Court first stated that a project must be “a QF”and “ready willing
and able to sign a contract”with a utility in order to be entitled to standardized PURPA
rates.Empire Lumber Co.v.Wash.Water Power Co.,114 Idaho 191,755 P.2d 1229,
1232 (1987).The Court in a later case also approved of the Commission’s establishment
of a more detailed set of requirements for QF contracts seeking vintage QF rates where it
agreed with the Commission that:“The QF must be able to exhibit that is has laid a
proper foundation entitling it to contract consideration”and that a “CSPP [QFJ is not
entitled to contract rates until it is ready,willing and able to sign a contract.”A.W.Brown
Co.,Inc.,v.Idaho Power Company,121 Idaho 812,817;828 P.2d 841 (1992).The Court
in A.W.Brown Co.went on to further affirm the Commission’s decision that the “ready,
willing and able”standard of “substantive negotiation”will “entail making a
comprehensive binding offer showing with reasonable specificity,design and size
characterizes and indicating a willingness to rely on proposed contract terms and proceed
thereunder.”Id.
Two recent QF contract approvals by the Commission continue a long line of
decisions wherein the Commission reviews the relevant facts and circumstances to
determine whether a QF is entitled to vintage rates or terms.Some of the factors recently
Case No.PAC-E-07-07:In the Matter of the Petition ofRocky Mountain Power for an Order Revising
Certain Obligations to Enter Into Contracts to Purchase Energy Generated by Wind-Powered Small Power
Generation Qualifying Facilities.
Cedar Creek Wind,LLC Comments in Support of PPA Approval Page 7
noted by the Commission as determinative,when taken together,include:(i)whether a
QF developer is materially down the path of facility interconnection with the utility,(ii)
whether the developer obtained QF status from the FERC,(iii)whether the parties had
exchanged contract drafts and project specific information,and (iv)whether the parties
reached a meeting of the minds as to the material contract terms and conditions.Order
No.32104 5;See also Order No.32068 6 In both of these instances —Yellowstone Power
and Grand View Solar —the Commission approved contracts that were executed
substantially after March 16,2010,but contained the higher vintage PURPA avoided cost
rate applicable to pre-March 16,2010 contracts.In both of these cases it was Idaho
Power’s assertion that it and the developer “had resolved all material outstanding contract
issues prior to March 16,2010.”Order No.32068,p.2.The Commission also found in
Grand View Solar the representations of Idaho Power “that all outstanding contract issues
had been resolved prior to March 16,2010”to be a convincing and accurate portrayal of
the parties having come to a meeting of the minds.Id alp.5.
The affidavit of Dana Zentz similarly demonstrates that “all outstanding contract
issues”were resolved between PacjfiCorp and Cedar Creek prior to December 14,2010.
PacifiCorp is in agreement with this statement of fact;although it could not apparently
admit so directly in this case and instead made such statements in the Joint Utilities
Docket.
Case No.IPC-E-10-22;In the Matter of the Application of Idaho Power Company for Approval of a Finn
Energy Sales Agreement with Yellowstone Power Inc.6 Case No.IPC-E-10-19;In the Matter ofthe Application of Idaho Power Company for Approval of a Firm
Energy Sales Agreement with Grand View Solar PV 1.‘The contract between Yellowstone Power Inc.and Idaho Power was dated July 28,1020,more than four
months after the change in rates.Idaho Power and Grand View Solar executed their contract on June 8,
2010,not quite three months after the change in rates.
Cedar Creek Wind,LLC Comments in Support of PPA Approval Page 8
PacifiCorp’s Application to Commission for approval or rejection of this Project’s
PPA presents the Commission three policy reasons favoring the latter:(i)that the five
CCW projects are a significant part (e.g.,30%)of the inundation of Idaho wind power
onto PacifiCorp8;(ii)that the five CCW projects will create system instability or
unreliability9,and (iii)the cost of energy from CCW is in excess of RMP’s avoided cost
and will have adverse impacts on RMP’s retail rates in Idaho.’°None of these reasons
are relevant to the Commission’s determination in this case.Nor are the statements in
PacifiCorp’s Application accurate.
From 2005 to date,only eight wind contracts between developers and PacifiCorp
(including the five CCW PPAs)have been submitted to this Commission for approval.
None of these eight have yet commenced construction and none are yet delivering energy
to RMP.Whether or not an additional two or three hundred MW of wind capacity is
about to be contracted for by PacifiCorp,subject to pre or post December 14,2010 rates,
terms and conditions is simply a matter of speculation.Furthermore,a PacifiCorp system
perspective must also be kept in mind.Energy needed by PacifiCorp in 2011 is projected
to be slightly over 61 million MWhs.1’If PacifiCorp were to absorb an additional 350
MWs of Idaho based wind nameplate generation into its system,it would amount to
approximately 3.5 percent of PacifiCorp’s projected 2011 coincident system peak.More
relevant,energy provided by 350 MWs of nameplate wind would equal approximately
1.5%of PacifiCorp’s projected energy needed in 2011.
Application of RMP,¶6.
9IdT 8.
10Id,J1J6-8.
See PacfICorp 2011 IRP Public Meeting Handout,October 5,2010,P.16,
at:http:!/www.pacificorp.corn/contentldam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/20 11
IRP/PacifiCorp2011IRPPIM4 10-05-1 0.pdf
Cedar Creek Wind,LLC Comments in Support of PPA Approval Page 9
Nor do the five CCW wind projects adversely impact RMP’s “electrical system
and reliability”in eastern Idaho.PacifiCorp has been very clear that CCW will pay,and
CCW has agreed to pay,for all electrical system impacts related to the projects.Cedar
Creek has also paid for all RMP studies that have,in great detail,determined the extent to
which CCW will pay RMP for any and all reliability impacts on the electrical system.
Finally,as inappropriate as it is in this case,the argument that the SAR calculated
avoided cost rate is significantly above an IR calculated rate is simply a wrong and
misleading comparison.As discussed in the Zentz affidavit’2,the PacifiCorp JR model
appears heavily biased against independent wind projects,in that it produces a first year
average rate of $37.05/MWh.Instead,that JR modeled rate should be compared to the
recent Idaho Power JR modeled rate for Rockland Wind Project,or to the $/kWh incurred
by PacifiCorp in developing 480 MW of Company owned wind generation in Wyoming
or in acquiring an additional 400 MW of independently owned Wyoming wind.While
confidential,Wyoming wind purchase or development costs can be reviewed by the
Commission in the most recent PacifiCorp Idaho ratecase.13 All will show costs/kWh
significantly greater than $37.05/MWh.
SUMMARY
Prior to December 14,2010 Cedar Creek had fully perfected its right for a less
than 10 aMW SAR avoided cost PPA with PacifiCorp for this Project.Significant
milestone compliance events are summarized as follows:(1)By May of 2010 CCW and
RMP had reached a mature point in studying and understanding the interconnection and
transmission system impacts caused by the Project and CCW had paid PaciCorp in
12116
IPUC Case No,PAC-E-I0-07
Cedar Creek Wind,LLC Comments in Support of PPA Approval Page 10
excess of $475,000 for such studies.(2)Qualifying Facility status was perfected with the
FERC for this Project on June 23,2010.(3)PacifiCorp provided the first draft PPA to
CCW in July,2010 and multiple drafts were exchanged between the parties over the
course of the next several months.(4)In September CCW presented PacifiCorp with
detailed Project specific notebooks with equipment specifications,wind data,site layout,
electrical diagrams,etc.and which were acknowledged by RMP as being “complete.”(5)
On November 29,2010 Cedar Creek and RMP had reached full agreement as to the
“final”rates,terms and conditions of a PPA for this Project,with “nothing further”to
negotiate,add or discuss.(6)PacifiCorp prepared the final draft of this PPA for execution
by the parties and Cedar Creek signed and delivered the PPA to PacifiCorp on December
13,2010.
For the reasons stated above and in accordance with previous decisions,Cedar
Creek respectfully asks that the Commission approve the PPA for the Rattlesnake
Canyon Wind Project.
Dated this 26th day of January,2011.
Respectfully submitted,
Ronald L.Williams
Williams Bradbury,P.C.
1015 W.Hays St.
Boise ID,83702
Telephone:[phone]
ronwilliamsbradbury.com
of Attorneys for Cedar Creek Wind
Cedar Creek Wind,LLC Comments in Support of PPA Approval Page 11
EXHIBIT 7
IDAHO PUC ORDER NO.32260
OfOce of the Secretary
Service Date
June 8,2011
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )PACIF1CORP DBA ROCKY MOUNTAIN )CASE NO.PAC-E-I1-01POWERFORADETERMINATION)
REGARDING A FIRM ENERGY SALES )AGREEMENT BETWEEN ROCKY MOUNTAIN )POWER AND CEDAR CREEK WIND,LLC )
(RATTLESNAKE CANYON PROJECT))
)IN THE MATTER OF THE APPLICATION OF )PACIFICORP DBA ROCKY MOUNTAIN )CASE NO.PAC-E-1 1-02POWERFORADETERMINATION)REGARDING A FIRM ENERGY SALES )AGREEMENT BETWEEN ROCKY MOUNTAIN )POWER AND CEDAR CREEK WIND,LLC )(COYOTE HILL PROJECT))
______________________________________________________________________________________________
)IN THE MATTEROFTHE APPLICATION OF )PACIFICORP DBA ROCKY MOUNTAIN )CASE NO.PAC-E-1 1-03POWERFORADETERMINATION)REGARDING A FIRM ENERGY SALES )AGREEMENT BETWEEN ROCKY MOUNTAIN )POWER AND CEDAR CREEK WIND,LLC )(NORTH POINT PROJECT))
______________________________________________________________________________________________
)IN THE MATTER OF THE APPLICATION OF )PACIFICORP DBA ROCKY MOUNTAIN )CASE NO.PAC-E-1I-04POWERFORADETERMINATION)REGARDING A FIRM ENERGY SALES )AGREEMENT BETWEEN ROCKY MOUNTAIN )POWER AND CEDAR CREEK WIND,LLC )(STEEP RIDGE PROJECT))
______________________________________________________________________________________________
)IN THE MATTER OF THE APPLICATION OF )PACIFICORP DBA ROCKY MOUNTAIN )CASE NO.PAC-E-1 1-05POWERFORADETERMINATION)REGARDING A FIRM ENERGY SALES )AGREEMENT BETWEEN ROCKY MOUNTAIN )ORDER NO.32260POWERANDCEDARCREEKWIND,LLC )(FIVE PINE PROJECT))
On January 10,2011,PacifiCorp dba Rocky Mountain Power filed five Applications
each requesting acceptance or rejection of a 20-year Firm Energy Sales Agreement
ORDER NO.32260 1
(‘Agreements”)between Rocky Mountain Power and Cedar Creek Wind,LLC for its
Rattlesnake Canyon,Coyote Hill,North Point,Steep Ridge and Five Pine wind projects.All
five projects are located near Bingham County.Idaho,and are managed by Cedar Creek Wind.
LLC.The Projects have self-certified as “qualifying facilities”(QFs)under the applicable
provisions of the federal Public Utility Regulatory Policies Act of 1978 (PURPA).Rocky
Mountain Power requested that its Applications be processed by Modified Procedure.
On February 24,2011,the Commission issued a Notice of Application and Notice of
Modified Procedure setting a March 24,2011,comment deadline and a March 31,2011,deadline
for reply comments.Comments were filed by the Commission Staff,the Company,and Cedar
Creek Wind on behalf of the five projects.!Numerous public comments were also received by
the Commission,As set out in greater detail below,the Commission declines to approve the
Firm Energy Sales Agreements.
BACKGROUND
On November 5,2010,Idaho Power,Avista Corporation,and PacifiCorp dba Rocky
Mountain Power filed a Joint Petition requesting that the Commission initiate an investigation to
address various avoided cost issues related to the Commission’s implementation of PURPA.
Section 210 of PURPA generally requires electric utilities to purchase power produced by QFs at
“avoided cost”rates set by the Commission.“Avoided costs”are those costs which a public
utility would otherwise incur for electric power,whether that power was purchased from another
source or generated by the utility itself.”18 C.F.R.§292.101(b)(6).Order No.32176 at 1.
While the Commission pursues its investigation,the utilities also moved the
Commission to “lower the published avoided cost rate eligibility cap from 10 aMW to 100 kW
[to]be effective immediately....“Id citing Joint Petition at 7.Under PURPA regulations
issued by the Federal Energy Regulatory Commission (FERC),the Commission must “publish”
avoided cost rates for small QFs with a design capacity of 100 kW or less.Order No.321 76 at I.
However,the Commission has the discretion to set the published avoided cost rate at a higher
capacity amount —commonly referred to as the “eligibility cap.”18 C.F.R.§292.304(c)(1-2).
When a QF project is larger than the published eligibility cap the avoided cost rate for the project
The parties in these five cases have all filed consolidated comments because the relevant facts for each of these
five projects are substantially similar.Consequently,the Commission finds it reasonable and appropriate toconsolidatethesecasesandissuethisconsolidatedfinalOrder.Rule 247,IDAPA 3101.01.247.
ORDER NO.32260 2
must be individually negotiated by the QF and the utility using the Integrated Resource Plan
(IRP)Methodology.Order No.32176.
The purpose of utilizing the IRP Methodology for large QF projects is to more
precisely value the energy being delivered.Id.at 10.The IRP Methodology recognizes the
individual generation characteristics of each project by assessing when the QF is capabJe of
delivering its resources against when the utility is most in need of such resources.The resultant
pricing is reflective of the value of QF energy to the utility,Utilization of the IRP Methodology
does not negate the requirement under PURPA that the utility purchase the QF energy.
On December 3,2010,the Commission issued Order No.32131 declining the
utilities’motion to immediately reduce the published avoided cost rate eligibility cap from 10
aMW to 100 kW.Order No.32131 at 5.However,the Order did notify parties that the
Commission’s decision regarding the motion to reduce the published avoided cost eligibility cap
would become effective on December 14,2010.Id.at 5-6,9.
Based upon the record in the GNR-E-1 0-04 case,the Commission subsequently found
that a “convincing case has been made to temporarily reduce the eligibility cap for published
avoided cost rates from 10 aMW to 100 kW for wind and solar only while the Commission
further investigates”other avoided cost issues,Order No.32176 at 9 (emphasis original).On
reconsideration,the Commission affirmed its decision to temporarily reduce the eligibility cap
for published avoided cost rates from 10 aMW to 100 kW.Order No.32212.Thus,the
eligibility cap for the published avoided cost rate for wind and solar QF projects was set at 100
kW effective December 14,2010.
THE AGREEMENTS
On December 22,2010,Rocky Mountain Power and each of the five wind projects
entered into their respective Agreements.Under the terms of the Agreements,each wind project
agrees to sell electric energy to Rocky Mountain Power for a 20-year term using the 10 aMW
non-levelized published avoided cost rates.Applications at 8-9.The Applications recite that
Rattlesnake Canyon,Coyote Hill and North Point will each have a maximum capacity amount of
27.6 MW,and Steep Ridge and Five Pine will each have a maximum capacity of 25.2 MW.
Under normal and/or average conditions,each QF will not generate more than 10 aMW on a
monthly basis.Rocky Mountain Power warrants that the Agreements comport with the terms
ORDER NO.32260 3
and conditions of the various Commission Orders applicable to PURPA agreements for a wind
resource.Id.ati 6 citing Order Nos.30415,30488,30738 and 31025.
The projects have all selected October 1,2012,as the Scheduled Commercial
Operation Date,Applications at 9.Rocky Mountain Power asserts that various requirements
have been placed upon the Facilities in order for Rocky Mountain Power to accept the Facilities’
energy deliveries.Rocky Mountain Power states that it will monitor each Facilitys compliance
with initial and ongoing requirements through the term of the Agreements.Rocky Mountain
Power asserts that it has advised each Facility of the Facility’s responsibility to work with Rocky
Mountain Power’s transmission unit to ensure that sufficient time and resources will be available
for delivery to construct the interconnection facilities,and transmission upgrades if required,in
time to allow each Facility to achieve its October 1,2012,Scheduled Commercial Operation
Date.
Rocky Mountain Power asserts that each Facility has been advised that delays in the
interconnection or transmission process do not constitute excusable delays and if a Facility fails
to achieve its Scheduled Commercial Operation Date delay damages will be assessed.Id.at 11.
The Applications further maintain that each Facility has acknowledged and accepted the risk
inherent in proceeding with its Agreement without knowledge of the requirements of
interconnection and possible transmission upgrades.Id.The parties have each agreed to delay
liquidated damages and security provisions.Agreements ¶J 2.5.1,11.1.2.Rocky Mountain
Power states that each Facility has also been made aware of and accepted the provisions in each
Agreement regarding curtailment or disconnection of its Facility should certain operating
conditions develop on Rocky Mountain Power’s system.Agreements ¶6.3.
By their own terms,the Agreements will not become effective until the Commission
has approved all of the terms and conditions and declares that all payments made by Rocky
Mountain Power to the Facilities for purchases of energy are just and reasonable,in the public
interest,and that the costs incurred by [Rocky Mountain Powerj for purchases of capacity and
energy from [Cedar Creek]are legitimate expenses,all of which the Commission will allow
[Rocky Mountain Power]to recover in rates in Idaho in the event other jurisdictions deny
recovery of their proportionate share of said expenses.”Agreements ¶2.1.
ORDER NO.32260 4
THE COMMENTS
A.Staff comments
Staff observed that the five Agreements are nearly identical.All five of the projects
are proposed to be built in the same general vicinity.Staff calculated that the five projects
collectively are expected to generate 375,503 MWh annually.Under the non-levelized rates in
the Agreements,the annual energy payments by Rocky Mountain Power for the expected
generation will be approximately $23.6 million in 2013 increasing to approximately $45.2
million in 2031,or a cumulative total of $685.4 million over the 20-year term of the Agreements.
The collective net present value of the energy payments over the life of the Agreements will be
approximately $265.2 million.
The five Agreements were signed by the project developer on December 13,2010,
and signed by Rocky Mountain Power on December 22,2010.The Agreements were filed with
the Commission on January 10,2011.The Agreements contain the published avoided cost rates
from Order No.31025.However,Staff observed that Order No.32176 lowered the availability
of published avoided cost rates for wind and solar QF projects to 100 kW,effective December
14.2010.As a matter of law,Staff considers the effective date of the contract to be the date
upon which both parties signed the agreement.A signature by only one party,Staff believes,
does not create an enforceable contract nor establish the effective date of the Agreement.
Consequently,Staff considers the effective date for the five Agreements to be December 22,
2010.
Staff acknowledged the comments submitted by Cedar Creek in support of the
Agreements,as well as the affidavit of Dana Zentz,filed with the Commission on January 26,
201 1.The comments and affidavit allege that the parties had reached full agreement as to the
rates,terms and conditions of a PPA for the projects on November 29,2010,and that Cedar
Creek signed and delivered copies of the Agreements to Rocky Mountain Power on December
13,2010.Nevertheless,the effective date of each Agreement is shown as December 22,2010,
on page 1 of each Agreement,clearly after the December 14,2010,effective date established by
Order No.32176.
Because the Agreements were executed after the date upon which the 100 kW
eligibility cap became effective for wind and solar projects and because the size of each
proposed wind project clearly exceeds 1 00 kW,Staff maintains that approval of the Agreements
ORDER NO.32260 5
is prohibited by Order No.321 76.Staff believes that the avoided cost rate for these Agreements
must be negotiated using the IRP methodology.Consequently,Staff recommended denial of the
Agreements as submitted.
B.Cedar Creek Wind Comments and Reply
Cedar Creek states that after it unsuccessfully bid in Rocky Mountain Power’s
2008/2009 Request for Proposal (RFP),Cedar Creek and Rocky Mountain Power discussed the
possibility of two 78 MW PURPA wind projects.Cedar Creek determined that the avoided cost
calculated by Rocky Mountain Power’s integrated resource model was “uneconomic and un
financeable for purposes of developing the Cedar Creek”wind projects.Comments at 2.Cedar
Creek subsequently decided to reduce the amount of gross generation and sacrifice the
economies of scale associated with two 78 MW wind projects and reconfigure into five separate
PURPA projects not greater than 10 aMW,in order to qualify for Surrogate Avoided Resource
(“SAR”)based avoided cost rates.”Id.at 2,3.
Cedar Creek argued that each of its five Agreements were mature contracts with a
meeting of the minds between the parties prior to December 14,2010.The Projects maintain
that they had fully perfected their right to a published avoided cost rate power purchase
agreement with Rocky Mountain Power prior to the Commission’s reduction of the eligibility
threshold for wind and solar projects.
On April 5,2011,Cedar Creek filed reply comments,2 Cedar Creek asserted that
“[t]he standard articulated by Staff—that December 14,2010 is an absolute’cut-off date —is
both a misreading of the Commission Order 32176 in Case No.GNR-E-10-4 and is contrary to
established law regarding PURPA rates and contract requirements.”Reply at 4.Cedar Creek
argues that the Commission does not require,or even speak to,December 14 as the date by
which both counterparties must have signed an agreement.Id.Cedar Creek maintained that,
because Rocky Mountain Power and Cedar Creek agreed that the five projects were eligible for
published rates prior to December 14,2010,and both parties agreed that all contract terms and
conditions,including price,had been agreed to prior to that date,Cedar Creek has proven
entitlement to published avoided cost rates.id.
Cedar Creek states that Staff’s recommendation is wrong,misguided,bad public
policy and “contrary to PURPA’s federal mandate that utilities execute power purchase
2 Pursuant to Commission Order No.32192,reply comments were to be filed no later than March 31.2011.
ORDER NO.32260 6
agreements with QF projects that are mature and are ready,willing and able to deliver qualifying
power to the utility at the avoided cost applicable at that time.”Id.at 6.
C Rocky Mountain Power Reply
Rocky Mountain Power filed reply comments on April 11,2011,Rocky Mountain
Power acknowledged that it had completed negotiation of all terms of the Agreements for Cedar
Creek’s five projects prior to December 14,2010.Reply at 2.Rocky Mountain explained that
the Company’s review and execution procedures must comply with Sarbanes Oxley (SOX’)
regulatory requirements.“Once the parties agree to a final draft,the final draft then undergoes a
detailed review and sign-off by management,merchant transmission,accounting,financial
reporting (FAS 133,Fin 46,etc.),credit,legal,billing,and delegation of signing authority by the
appropriate Company executive for execution of the agreement.”Id.at 3.Rocky Mountain
Power asserted that it acted “with reasonable speed to execute the PPAs given the number of
documents and complexity of review of the multiple transactions requested by Cedar Creek
Wind.”Id.
Rocky Mountain Power stated that Cedar Creek returned signed Agreements to
Rocky Mountain’s Portland office “late on the afternoon of December 13,2010.Cedar Creek
did not deliver final conformed exhibits for each PPA until December 14,2010 During the
review,the Company identified discrepancies in several of the PPA exhibits which were
corrected and confirmed by Cedar Creek Wind on December 16,2010.”Id.at 3,4.Rocky
Mountain completed its final review and received executive approval of the Agreements on
December 22,2010.Id.“It is unlikely that Rocky Mountain Power could have completed its
review in a timelier maimer and in no event could the Company have been diligent and still
executed the contracts prior to December 14,having received signed PPAs with no conformed
exhibits from Cedar Creek Wind at the end of the business day on December 13,2010.”Id.
Rocky Mountain notes that,by their own terms,the Agreements are not effective
until approved by the Commission.Id.at 6.Rocky Mountain also maintains that,although
Cedar Creek argues for “grandfathering”treatment,the Projects do not meet the bright line rule
for grandfathering —a fully executed PPA by December 14 or a meritorious complaint filed with
Rocky Mountain acknowledged that its reply,as well as Cedar Creek’s reply,was untimely.As a result,RockyMountainrequestedthattheCommissioneitherstrikebothrepliesoracceptbothreplies.
ORDER NO.32260 7
the Commission by December 14,Id at 7.Rocky Mountain concedes that the parties reached
agreement on all terms of their Agreements prior to December 14,2010.“This fact alone does
not,however,compel the Commission to approve those contracts.”Id.at 8.
D.Public Comments
vi ore than 40 public comments were received regarding the Cedar Creek projects.
Approximately 36 comments supported approval of the 5 wind projects.The majority of
commenters who support approval believe that the projects would stimulate the local economy
and provide economic growth at a time when jobs and industry is greatly needed.Several
commenters stressed the need for Idaho to capture and develop its natural resources.A few
commenters believed that utilizing wind energy would reduce the cost of electricity to Idahoans.
Approximately seven comments opposed the five wind projects.Commenters in
opposition stated that utility customers cannot afford another increase in electricity rates.
Several commenters cited the intermittent nature of wind as being an unreliable resource that is
heavily subsidized to make it economically feasible.
DISCUSSION AND FINDINGS
The Commission has jurisdiction over Rocky Mountain Power,an electric utility,and
the issues raised in this matter pursuant to the authority and power granted it under Title 61 of
the Idaho Code and the Public Utility Regulatory Policies Act of 1978 (PURPA).The
Commission has authority under PURPA and the implementing regulations of the Federal
Energy Regulatory Commission (FERC)to set avoided cost rates,to order electric utilities to
enter into fixed-term obligations for the purchase of energy from qualified facilities (QFs)and to
implement FERC rules.Rosebud Enterprises,Inc.,v.Idaho Public Utilities Commission,128
Idaho 609,612,917 P.2d 766,769 (1996).
The Commission has reviewed the record in this case,including the Applications,the
Firm Energy Sales Agreements,and the comments of Commission Staff,Rocky Mountain
Power,the wind projects,and the public.It is clear from the record that extensive review of
PPAs is conducted by both parties prior to signing an agreement.From the Commission’s
perspective,a thorough review is appropriate and necessary prior to signing Agreements that
obligate ratepayers to payments in excess of $685 million over the 20-year term of these
Agreements.Indeed,the Commission has directed the utilities to assist the Commission in its
gatekeeper role when reviewing QF contracts.
ORDER NO.32260 8
The primary issue to be determined in these cases is whether the Agreements —which
utilize 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.“According to
the FERC,it is up to the States,not [FERCI 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,128 Idaho at 780-781,917 P,2d at 623-624,
citing West Penn Power Co.,71 FERC ¶61,153 (1995).We find that the Agreements were not
fully executed (signed by both parties)prior to December 14,2010.More specifically,each
Firm Energy Sales Agreement states that the “Effective Date”of the Agreement is “after
execution by both Parties and after approval by the Commission.”Agreements ¶1 .13,2.1.The
opening paragraph is dated “this 22 day of December,2010.”Agreements at I.It is not
disputed that the projects signed the Agreements on December 13,and Rocky Mountain Power
signed on December 22,2010.Thus,on the date the five Agreements became effective,
published avoided cost rates were available only to wind and solar projects with a design
capacity of 100 kW or less.
The proposed change in the eligibility cap was clearly noticed in our Order No.
32131 issued on December 3,2010.As we observed in Order No.32176:“One need look no
further than the abundance of firm energy sales agreements filed with the Commission [between
the notice and December 14]to realize that the parties took the Commission’s notice of its
effective date seriously.”Order No.32176 at 11.The Commission does not consider a utility
and its ratepayers obligated until both parties have completed their final reviews and signed the
agreement.In other words,in order for the 10 aMW eligibility cap to be available to wind and
solar QFs,the agreement must have been effective prior to December 14,2010.The Idaho
Supreme Court has recognized that “a balance must be struck between the local public interest of
a utility’s electric consumers and the national public interest in development of alternative
energy sources.”Rosebud Enterprises,128 Idaho at 613,917 P.2d at 770.We find that it is not
in the public interest to allow parties with contracts executed on or after December 14,2010,to
avail themselves of an eligibility cap that is no longer applicable.
The published avoided cost rates established in Order No.31025 have not changed.
What has changed is the size at which wind and solar projects can avail themselves of the
published avoided cost rates.Consistent with FERC regulations,and as set out in Order No.
ORDER NO.32260 9
32176,published rates are available to wind and solar QFs with a design capacity of 100 kW or
less.18 C.F.R.§292.304(c)(l-2).Wind and solar projects larger than 100kW are still entitled
to PURPA contracts at avoided cost rates calculated using the IRP Methodology.Because
published avoided cost rates remain unchanged and only the eligibility size has changed,
grandfathering criteria applied to changes are not applicable here.Regarding the application
of a change in the eligibility cap,we adopt a bright line rule:a Firm Energy Sales
Agreement/Power Purchase Agreement must be executed,i.e.,signed by both parties to the
agreement,prior to the effective date of the change in eligibility criteria.
The Firm Energy Sales Agreements between Rocky Mountain Power and the five
projects were executed on December 22,2010.The Agreements recite that Rattlesnake Canyon,
Coyote Hill and North Point will each have a maximum capacity amount of 27.6 MW,and Steep
Ridge and Five Pine will each have a maximum capacity of 25.2 MW.Because the size of each
of these wind projects exceeds 100 kW,they are not eligible to receive published rate contracts.
Simply put,the rates contained in the Agreements do not comply with Order No.32176.
Therefore,we disapprove the five Firm Energy Sales Agreements.
ORDER
IT IS HEREBY ORDERED that the five December 22,2010,Firm Energy Sales
Agreements between Idaho Power and Cedar Creek Wind,LLC (for its Rattlesnake Canyon,
Coyote Hill,North Point,Steep Ridge and Five Pine projects)are disapproved.
THIS IS A FINAL ORDER.Any person interested in this Order may petition for
reconsideration within twenty-one (21)days of the service date of this Order.Within seven (7)
days after any person has petitioned for reconsideration,any other person may cross-petition for
reconsideration.See Idaho Code §6 1-626.
ORDER NO.32260 10
DONE by Order of the Idaho Public Utilities Commission at Boise,Idaho this
day of June 2011.
PAUL KJELLAN ,PRESIDENT
MACK A.RDFO.COMMISSIONER
MARSHA H.SMITH,COMMISSIONER
ATTEST:
/J4 L
Jn D.JewdU
Commission secretary
O:PAC-E-l 1-01 PAC-E-I 1-O2PAC-E-l 1-O3PAC-E-I I-O4PAC-E-I 1-05ks2
ORDER NO,32260 11
Office of the Secretary
Service Date
June 14,20]I
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
PACIFICORP DBA ROCKY MOUNTAIN )CASE NO.PAC-E-11-OI
POWER FOR A DETERMINATION )
REGARDING A FIRM ENERGY SALES )
AGREEMENT BETWEEN ROCKY MOUNTAIN )
POWER AND CEDAR CREEK WIND,LLC )
(RATTLESNAKE CANYON PROJECT))
______________________________________________________________________________________
)
IN THE MATTER OF THE APPLICATION OF )
PACIFICORP DBA ROCKY MOUNTAIN )CASE NO.PAC-E-1I-02
POWER FOR A DETERMINATION )
REGARDING 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 )CASE NO.PAC-E-11-03
POWER FOR A DETERMINATION )
REGARDING A FIRM ENERGY SALES )
AGREEMENT BETWEEN ROCKY MOUNTAIN )
POWER AND CEDAR CREEK WIND,LLC )
(NORTH POINT PROJECT))
____________________________________________________________________________
)
IN THE MATTER OF THE APPLICATION OF )
PACIFICORP DBA ROCKY MOUNTAIN )CASE NO.PAC-E-1 1-04
POWER FOR A DETERMINATION )
REGARDING A FIRM ENERGY SALES )
AGREEMENT BETWEEN ROCKY MOUNTAIN )
POWER AND CEDAR CREEK WIND,LLC )
(STEEP RIDGE PROJECT))
_______________________________________________________________________________________________
)
IN THE MATTER OF THE APPLICATION OF )
PACIFICORP DBA ROCKY MOUNTAIN )CASE NO.PAC-E-11-05
POWER FOR A DETERMINATION )
REGARDING A FIRM ENERGY SALES )ERRATA TO
AGREEMENT BETWEEN ROCKY MOUNTAIN )ORDER NO.32260
POWER AND CEDAR CREEK WIND,LLC )
(FIVE PINE PROJECT))
ERRATA TO
ORDERNO.32260 1
On June 8,2011,IPUC Order No,32260 was issued by this Commission.The
following change should be made to that Order:
Page 10,Order Section,Paragraph I
READS:
IT IS HEREBY ORDERED that the five December 22,2010.Firm Energy
Sales Agreements between Idaho Power and Cedar Creek Wind,LLC (for its
Rattlesnake Canyon,Coyote Hill,North Point,Steep Ridge and Five Pine
projects)are disapproved.”
SHOULD READ:
“IT IS HEREBY ORDERED that the five December 22,2010,Firm Energy
Sales Agreements between PacifiCorp dba Rocky Mountain Power and Cedar
Creek Wind,LLC (for its Rattlesnake Canyon,Coyote Hill,North Point,
Steep Ridge and Five Pine projects)are disapproved.”
DATED at Boise,Idaho this day of June 2011.
i ,2
Jn D.Jewefl/
Commission Secretary
bis/O:PAC.E-l I -01 PAC-E-I I -02 PAC-E-II -03 PAC-E-I I -04 PAC-E-I 1 -05 ks2 Errata
ERRATA TO
ORDER NO.32260
EXHIBIT 8
IDAHO PUC ORDER NO.32302
Office of the Secretary
Service Date
July 27.2011BEFORETHEIDAHOPUBLICUTILiTIESCOMMISSiON
IN THE MATTER OF THE APPLICATION OF )PACIFICORP DBA ROCKY MOUNTAIN POWER )CASE NO.PAC-E-I1-01FORADETERMINATIONREGARDINGA)FIRM ENERGY SALES AGREEMENT )BETWEEN ROCKY MOUNTAIN POWER AND )CEDAR CREEK WIND,LLC (RATTLESNAKE )CANYON PROJECT))
__________________________________________________________________________________
_
_
_
_
_
_
_
_
)IN THE MATTER OF THE APPLICATION OF )PACIFICORP DBA ROCKY MOUNTAIN POWER )CASE NO.PAC-E-1 1-02FORADETERMINATIONREGARDINGA)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 )CASE NO.PAC-E-11-03FORADETERMINATIONREGARDINGA)FIRM ENERGY SALES AGREEMENT )BETWEEN ROCKY MOUNTAIN POWER AND )CEDAR CREEK WIND,LLC (NORTH POINT )PROJECT))
__________________________________________________________________________________________
)IN THE MATTER OF THE APPLICATION OF )PACIFICORP DBA ROCKY MOUNTAIN POWER )CASE NO.PAC-E-1 1-04FORADETERMINATIONREGARDINGA)FIRM ENERGY SALES AGREEMENT )BETWEEN ROCKY MOUNTAIN POWER AND )CEDAR CREEK WIND,LLC (STEEP RIDGE )PROJECT))
)IN THE MATTER OF THE APPLICATION OF )PACIFICORP DBA ROCKY MOUNTAIN POWER )CASE NO.PAC-E-11-05FORADETERMINATIONREGARDINGA)FIRM ENERGY SALES AGREEMENT )BETWEEN ROCKY MOUNTAIN POWER AND )ORDER NO.32302CEDARCREEKWIND,LLC (FIVE PINE )PROJECT))
On January 10,2011,PacifiCorp dba Rocky Mountain Power filed five Applicationseachrequestingacceptanceorrejectionofa20-year Firm Energy Sales Agreement
ORDER NO.32302 1
(“Agreements”)between Rocky Mountain Power and Cedar Creek Wind,LLC,for its
Rattlesnake Canyon,Coyote Hill,North Point,Steep Ridge and Five Pine wind projects
(collectively “the Projects”).On February 24,201 1,the Commission issued a consolidated
Notice of Application and Notice of Modified Procedure for the five Applications.Timely
comments in response to the i’otice of Modified Procedure were filed by the Commission Staff
and the Projects.On March 31,2011,Rocky Mountain Power filed reply comments.On June 8,
2011,the Commission issued a consolidated final Order disapproving each of the five
Agreements.The Commission found that the Agreements “were not fully executed (signed by
both parties)prior to December 14,2010”—the date that the Commission lowered the eligibility
cap for the published avoided cost rate from 10 aMW to 100 kW.Order No.32260 at 10.Thus,
the Agreements contained an essential term that was no longer available to the Projects.Id.
On June 29,2011,the Projects timely filed a Joint Petition for Reconsideration of the
Commission’s final Order.The Projects allege that the Commission’s final Order is erroneous
and is not in conformity with the law because a legally enforceable obligation existed between
Rocky Mountain Power and the Cedar Creek projects prior to December 14,2010.As a result,
Cedar Creek maintains that they are entitled to published avoided cost rates under the previous
10 aMW eligibility cap.The Projects further argue that not considering grandfathering criteria is
a departure from the Commission’s past precedent and the Commission did not give proper
notice to the parties regarding its intent to depart from precedent.
On July 6,2011,Rocky Mountain Power filed an answer to the Projects’Petition.
Rocky Mountain Power maintains that the Commission’s final Order is consistent with federal
and state law.Rocky Mountain Power contends that the Commission had good cause to act as it
did.Further,the Commission was acting within its discretion and,therefore,reconsideration
should be denied.
This matter was fully submitted for the Commission’s consideration on the July 11,
2011,decision meeting agenda.On July 12,2011,the Projects filed a reply to Rocky Mountain
Power’s answer.On July 21,2011,Rocky Mountain Power filed a sur-reply to the Projects’
reply.The Commission finds that the record in this case closed on July 11,2011,when the
matter became fully submitted.Furthermore,Commission Rule 331 does not provide parties the
opportunity for a reply and sur-reply to the initial petition for reconsideration and answer.
ORDER NO.32302 2
Therefore,the Commission will not consider the arguments addressed in the Projects’July 12
reply or Rocky Mountain Power’s July 21 sur-reply.
BACKGROUND
A.The Agreements
On December 22,2010,Rocky Mountain Power and the five wind projects entered
into their respective Agreements.Under the terms of the Agreements,each wind project agrees
to sell electric energy to Rocky Mountain Power for a 20-year term using the 10 aMW non
levelized published avoided cost rates.Applications at 8-9.The Applications recite that
Rattlesnake Canyon,Coyote Hill and North Point will each have a maximum capacity of 27.6
MW,and Steep Ridge and Five Pine will each have a maximum capacity of 25.2 MW.Under
normal and/or average conditions,each QF will not generate more than 10 aMW on a monthly
basis.Rocky Mountain Power warrants that the Agreements comport with the terms and
conditions of the various Commission Orders applicable to PURPA agreements for a wind
resource.Id.at ¶6 citing Order Nos.30415,30488,30738 and 3 1025.
The projects all selected October 1,2012,as the Scheduled Commercial Operation
Date.Applications at 9.Rocky Mountain Power asserts that various requirements have been
placed upon the projects in order for Rocky Mountain Power to accept the project’s energy
deliveries.Rocky Mountain Power states that it will monitor each project’s compliance with
initial and ongoing requirements through the term of the Agreement.The parties have each
agreed to liquidated damage and security provisions.Agreements ¶J 2.5.1,11.1 .2.
Rocky Mountain Power asserts that it advised each project of the project’s
responsibility to work with Rocky Mountain Power’s delivery transmission unit to ensure that
sufficient time and resources will be available for the delivery unit to construct the
interconnection facilities,and transmission upgrades if required,in time to allow the projects to
achieve their October 1,2012,Scheduled Commercial Operation Date.The Applications state
that the projects have been advised that delays in the interconnection or transmission process do
not constitute excusable delays and if a project fails to achieve its Scheduled Commercial
Operation Date,delay damages will be assessed.Applications at 11.The Applications further
maintain that each project has acknowledged and accepted the risk inherent in proceeding with
its Agreement without knowledge of the requirements of interconnection and possible
transmission upgrades.Id.
ORDER NO.32302 3
Rocky Mountain Power states that each project has also been made aware of and
accepted the provisions in each Agreement regarding curtailment or disconnection of its facility
should certain operating conditions develop on Rocky Mountain Power’s system.Agreements ¶
0.).
By their own terms,the “effective date”of each agreement is ‘after execution by both
parties and after approval by the Commission”Agreement ¶2.1;1.13.The Agreements are
dated December 22,2010.id.at p.1.The Agreements further provide that the Agreements will
not become effective until the Commission has approved all of the terms and conditions and
declares that all payments made by Rocky Mountain Power to each project for purchases of
energy “are just and reasonable,in the public interest,and that the costs incurred by [Rocky
Mountain Power]for purchases of capacity and energy from [Cedar Creek]are legitimate
expenses,all of which the Commission will allow [Rocky Mountain Power]to recover in rates in
Idaho in the event other jurisdictions deny recovery of their proportionate share of said
expenses.”Agreements ¶2.1.
B.The Utilities’Joint Petition
On November 5,2010,prior to the date that Rocky Mountain Power and the Projects
entered into their Agreements,Idaho Power,Avista Corporation,and PacifiCorp dba Rocky
Mountain Power filed a Joint Petition requesting that the Commission initiate an investigation to
address various avoided cost issues related to the Commission’s implementation of PURPA.
Case No.GNR-E-10-04.On December 3,2010,the Commission issued Order No.32131
declining a motion made by the utilities to immediately reduce the published avoided cost rate
eligibility cap from 10 aMW to 100 kW.Order No.32131 at 5.However,the Order did notify
parties that the Commission’s decision regarding whether to reduce the published avoided cost
eligibility cap would become effective on December 14,2010.Id.at 5-6,9.
Section 210 of PURPA generally requires electric utilities to purchase power
produced by QFs at “avoided cost”rates set by the Commission.“Avoided costs”are those costs
which a public utility would otherwise incur for electric power,whether that power was
purchased from another source or generated by the utility itself.”1 8 C.F.R.§292.101 (b)(6).
Order No.32176 at 1.Under PURPA regulations issued by the Federal Energy Regulatory
Commission (FERC),the Commission must “publish”avoided cost rates for small QFs with a
design capacity of 100 kW or less.Order No.32176 at 1.However,the Commission has the
ORDER NO.32302 4
discretion to set eligibility for the published avoided cost rate at a higher capacity amount —
commonly referred to as the ‘eligibility cap.”18 C.F.R.§292.304(c)(l-2).When a QF project
is larger than the Commission-established eligibility cap the avoided cost rate for the project
must be individually negotiated by the QF and the utility using the Integrated Resource Plan
(IRP)Methodology.Order No.32176.
The purpose of utilizing the IRP Methodology for large QF projects is to more
precisely value the energy being delivered.Id at 10.The IRP Methodology recognizes the
individual generation characteristics of each project by assessing when the QF is capable of
delivering its resources against when the utility is most in need of such resources.The resultant
pricing is reflective of the value of QF energy to the utility.Utilization of the IRP Methodology
does not negate the requirement under PURPA that the utility purchase the QF energy.
Based upon the record in the GNR-E-10-04 case,the Commission subsequently
found that a “convincing case has been made to temporarily reduce the eligibility cap for
published avoided cost rates from 10 aMW to 100 kW for wind and solar only while the
Commission further investigates”other avoided cost issues.Order No.32176 at 9 (emphasis
original).On reconsideration,the Commission affirmed its decision to temporarily reduce the
eligibility cap for published avoided cost rates from 10 aMW to 100 kW.Order No.32212.
Thus,the eligibility cap for the published avoided cost rate for wind and solar QF projects was
set at 100 kW effective December 14,2010.No party appealed from the Orders in Case No.
GNR-E-10-04.
C.The Prior Final Order in this Case
On June 8,2011,the Commission issued Order No.32260 disapproving the
Agreements between Rocky Mountain Power and each of the five wind projects —Rattlesnake
Canyon,Coyote Hill,North Point,Steep Ridge and Five Pine.’The Commission determined
that the Agreements were not fully executed (signed by both parties)prior to December 14,
2010,the date upon which the eligibility for published avoided cost rates changed from 10 aMW
to 100 kW for wind and solar projects.Consequently,the Commission found that the rates
contained in the Agreements did not comply with Order No.32176 because each of the projects
The five projects had previously filed consolidated comments because the relevant facts for each of these fiveprojectsaresubstantiallysimilar.Consequently,the Commission found it reasonable and appropriate to consolidatethecasesandissueaconsolidatedfinalOrder.Order No.32260 n.1.
ORDER NO.32302 5
requesting published avoided cost rates is in excess of 100 kW.Order No.32260 at 10.The
“old”10 aMW published rate is available only to non-wind and non-solar QFs.
The Projects signed the Agreements on December 13,2010,and Rocky Mountain
Power signed on December 22,2010.The Commission noted that the Agreements contain
language regarding the effective date.The terms of the Agreements unequivocally state that the
“Effective Date”of the Agreements is “after execution by both Parties and after approval by the
Commission.”Agreements ¶1 .1 3,2.1 (emphasis added).The Agreement is dated “this 22’
day of December,2010”and Rocky Mountain Power stated that it executed the Agreements on
December 22,2010.Applications at ¶9;Reply Comments at 4.We stated that “[t}he
Commission does not consider a utility and its ratepayers obligated until both parties have
completed their final reviews and signed the agreement.”Order No.32260 at 9.We found that
“a thorough review is appropriate and necessary prior to signing Agreements that obligate
ratepayers to payments in excess of $685 million”over the 20-year term of the Agreements.id.
at 8.The Commission established a bright line rule that for a wind or solar QF larger than 100
kW to be eligible for published avoided cost rates,a Firm Energy Sales Agreement/Power
Purchase Agreement must have been executed,i.e.,signed by both parties,prior to the December
14,2010,effective date oft he change in eligibility criteria.Id.at 10.The Commission
additionally found that it was “not in the public interest to allow parties with contracts executed
on or after December 14,2010,to avail themselves of an eligibility cap that is no longer
applicable.”Id.at 9.
PETITION FOR RECONSIDERATION
On June 29,2011,the Projects filed a timely Joint Petition for Reconsideration.
Idaho Code §61-626.The Projects allege that the Commission’s Order is erroneous and violates
federal and state law.Specifically,the Projects argue that (I)the Commission’s bright line rule
requiring an executed contract in order for a wind facility to qualify for a 1 0 aMW eligibility cap
violates federal law;(2)the Commission arbitrarily departed from past precedent by not utilizing
grandfathering criteria to allow projects an opportunity to qualify under the 10 aMW eligibility
cap;and (3)the Commission did not give proper notice prior to deviating from past precedent
with regard to grandfathering.Ultimately,the Projects contend that their Agreements should be
approved because a legally enforceable obligation existed prior to December 14,2010.The
Projects request that the Commission “expeditiously grant this petition for reconsideration and,
ORDER NO.32302 6
by August 5,2011,approve the Agreements without further briefing,hearing,or other
proceedings.”Reconsideration at 18.
Rocky Mountain Power filed an answer to the Projects’Petition for Reconsideration.
Rocky Nountain Power states that the Commission properly applied the controlling legal
standard for determining when a legally enforceable obligation arises under Idaho and federal
law.Rocky Mountain Power asserts that ‘there is no contract until Rocky Mountain Power has
completed its internal review,and signilied its acceptance by executing the Agreement.”
Answer at 16.The Company maintains that it executed the Agreement after the eligibility cap
was reduced to 100 kW —i.e.,on December 22,2010.Jd.at 15.The Company further argues
that the Commission may,in its discretion,determine whether to utilize grandfathering criteria.
Finally,Rocky Mountain Power maintains that the Projects have failed to demonstrate that the
Commission’s Order is legally flawed.
ISSUES ON RECONSIDERATION
A.Legal Standards
Reconsideration provides an opportunity for a party to bring to the Commission’s
attention any question previously determined and thereby affords the Commission an opportunity
to rectify any mistake or omission.Washington Water Power Co.v.Kootenai Environmental
Alliance,99 Idaho 875,879,591 P.2d 122,126 (1979).The Commission may grant
reconsideration by reviewing the existing record,by written briefs,or by evidentiary hearing.
IDAPA 31,01.01.311.03.If reconsideration is granted,the Commission must complete its
reconsideration within 13 weeks after the deadline for filing petitions for reconsideration.Idaho
Code §6 1-626(2).
Consistent with the purpose of reconsideration,the Commission’s Rules of Procedure
require that petitions for reconsideration “set forth specifically the ground or grounds why the
petitioner contends that the order or any issue decided in the order is unreasonable,unlawful,
erroneous or not in conformity with the law.”Rule 331.01,IDAPA 31.01.01.331.01.Rule 331
further requires that the petitioner provide a “statement of the nature and quantity of evidence or
argument the petitioner will offer if reconsideration is granted.”Id.
B.Legally Enforceable Obligation
The Projects argue that,pursuant to 1 8 C.F.R.§292.304(d)(2),a QF is entitled to the
rates that are in effect on the date the QF incurred a legally enforceable obligation to provide
ORDER NO.32302 7
energy.The Projects maintain that the key consideration is ‘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.”Reconsideration Petition at 5,The Projects
argue that the Commission committed reversible error by requiring a fully executed contract to
establish a legally enforceable obligation.
Commission Findings:The Idaho Supreme Court has held that “[tjhe
implementation of PURPA as it relates to cogeneration and small power producers,and the
regulations promulgated by FERC,have been largely left to the regulatory authorities of the
individual states.”AW,Brown Company,Inc.v.Idaho Power Company,121 Idaho 812,816,
828 P.2d 841,845 (1992).‘FERC regulations grant the states latitude in implementing the
regulation of sales and purchases between QFs and electric utilities.”Order No.32262 citing
Federal Energy Regulatory Commission v.Mississippi,456 U.S.742,102 S.Ct.2126,72
L.Ed.2d 532 (1982).As we stated in our final Order,“[ajccording to the FERC,‘it is up to the
States,not [FERC]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.”Order No.32260 at 9 citing Rosebud Enterprises v,Idaho PUC,128 Idaho 609,623-624,
917 P.2d 766,780-781 (1996)citing West Penn Power Co.,71 FERC j 61,153 (1995).
The premise of the Projects’argument is correct:QFs have the right to choose to
have rates calculated at the time that a legally enforceable obligation is incurred.
Reconsideration at 5.However,this Commission determined that the parties entered into a
legally enforceable obligation at the time that both parties executed the power purchase
agreement.We find that,for each of these five projects,a legally enforceable obligation was
incurred on December 22,2010—the date that Rocky Mountain Power executed the Agreements.
By their very terms the Agreements were not effective until December 22,2010,and after
approval by this Commission.Agreements ¶1.13,2.1.On December 14,2010,wind projects
larger than 100 kW were no longer entitled to the 10 MW published avoided cost rate.In
determining when the parties incurred a legally enforceable obligation,we properly exercised the
authority granted us by FERC.“For purposes of [FERCJ regulations,the critical date is the date
on which a legally enforceable obligation is incurred,and choosing that date for a specific QF is
ORDER NO.32302 8
the responsibility of the States,not of [FERC].”West Penn Power Co.,71 FERC ¶61153,
61495 (1995).
In their Petition for Reconsideration,the Projects reference FERC regulations and JD
Wind I,LLC,130 FERC ¶61,127 (2010),in support of their proposition that an executed
contract is not necessarily required in order for a legally enforceable obligation to exist.In JD
Wind,six separate QFs developed by John Deere Renewables petitioned FERC to overturn a
Texas PUC decision denying the projects long-term contracts at avoided cost rates calculated at
the beginning of the contract.The Texas PUC found that wind QFs were not entitled to long-
term legally enforceable obligations because of the intermittent,or non-firm,nature of the
resource.FERC concluded that the Texas PUC’s Order,limiting the award of a legally
enforceable obligation to only those QFs that provide firm power,was inconsistent with FERC
regulations implementing PURPA.ID Wind does not consider or analyze when a legally
enforceable obligation is incurred under PURPA.The Projects’use of this FERC case as
instructive on the issues of contract formation and timing of a legally enforceable obligation is
misleading and without merit.ID Wind contemplates whether a legally enforceable obligation
must be entered into by a utility for intermittent/non-firm resources —nothing more.
Nothing cited by the Projects demonstrates that the Commission’s Order is erroneous
or inconsistent with federal law.On the contrary,the Projects admit.“[njo doubt,FERC leaves
it to the discretion of state commissions to establish the dale on which a legally enforceable
PURPA obligation is created.”Reconsideration at 6 (emphasis in original).We find that,in this
case,a legally enforceable obligation was incurred when the contracts were fully executed —
upon obtaining the signature of both parties -December 22,2010.Rocky Mountain Power
executed the Agreements on December 22,2010.Applications at ¶9;Reply Comments at 4;
Answer at 16.This finding is based on substantial and competent evidence and supported by the
record.The Commission’s finding is also in the public interest and strikes a balance between
“the local public interest of a utility’s electric consumers and the national public interest in
development of alternative energy sources.”Rosebud Enterprises,128 Idaho at 613,917 P.2d at
770.Allowing a project to avail itself of an eligibility cap (and therefore published rates)that is
no longer applicable could cause ratepayers to pay more than the utility’s avoided cost which
“would be in direct violation of PURPA policies.”A.W.Brown Company v,Idaho Power
ORDER NO.32302 9
Company,121 Idaho 812,818,828 P.2d 841,847 (1992).Based on the foregoing,the Projects’
request for reconsideration on this issue is denied.
Prior to signing,Rocky Mountain Power performs a thorough review of the terms of
the contract.As we stated in our final Order,a comprehensive review of a power purchase
agreement is consistent with this Commission’s directive to utilities that they assist the
Commission in its gatekeeper role when reviewing QF contracts.Order No.32260 at 8.We find
that it is reasonable and consistent with the authority granted us under PURPA,and that the
public interest requires that each party have a full and final review of the contract before signing
and obligating the utility and its ratepayers to hundreds of millions of dollars in energy payments
over the 20-year life of the Agreements.The Projects were given unrestricted time to adequately
review the contracts before signing.Rocky Mountain Power is obligated to be as diligent in its
review prior to asking the Commission to commit ratepayer dollars.
We further note that,unlike standard offer and acceptance contracts,PURPA
agreements are subject to review and approval by this Commission pursuant to Idaho statutes.
Idaho Code §61-502 and 6 1-503.“The Commission,as part of its statutory duties,determines
reasonable rates and investigates and reviews contracts.”A.W.Brown Company v Idaho Power
Company,121 Idaho 812,816,828 P.2d 841,845 (1992).The Agreements acknowledge this
statutory duty of the Commission by providing that each Agreement will not become effective
until the Commission has approved all of the terms and conditions and declares that all payments
made by Rocky Mountain Power to the Projects for purchases of energy are just and reasonable
and in the public interest.Agreements ¶2.1.An effective date based on Commission approval
of the Agreement has been supported on Idaho Supreme Court review.2 Here,no one has argued
that the legally enforceable obligation arises only after the Commission has approved the
Agreements.Therefore,based upon this record and pursuant to the discretion granted us by
PURPA and FERC regulations,we find that a legally enforceable obligation was incurred
between Rocky Mountain Power and the Projects on the date that the parties executed the
Agreements and agreed to be bound by the terms contained therein.Our Order presented
2 “Rosebud is not entitled to a lock-in of an avoided cost rate until it has entered into a legally enforceable andIPUCapprovedobligationforthedeliveryofenergyandcapacity.”Rosebud Enterprises,128 Idaho at 620,917P.2d at 777 (emphasis added).
ORDER NO.32302 10
sufficient facts to show that we did not act arbitrarily.Furthermore,the Projects have failed to
demonstrate that we were not regularly pursuing our authority.
C.Application of Grandfathering Criteria
The Projects also argue that the Commission’s decision to not consider the
application of grandfathering criteria is erroneous and contrary to Commission precedent.
Specifically,the Projects argue that,“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 eligibility cap.”Reconsideration at 7 (emphasis in original),In cases where the criteria were
met,projects were grandfathered and permitted to use rates previously in effect.The Projects
contend that they satisfied the requirements of the Commission’s grandfathering precedent
before the effective date of the eligibility cap reduction.
Commission Findings:The Projects’reliance on previously utilized grandfathering
criteria is misplaced.First,this Commission has explicitly stated that “we look at the totality of
the facts”in assessing entitlement to grandfathering status.Order No.29954 at 2.In these
Agreements,the “effective date”of each Agreement the date when both parties executed the
Agreement and agreed to be bound by its terms —is well the Commission lowered the
eligibility cap for the published avoided cost rate to 100 kW.Thus,the Projects’Agreements do
not support that use of grandfathering.Second,the Idaho Supreme Court has stated that
“[cjonferment of grandfathered status on [a]qualifying facility is essentially an IPUC finding
that a legally enforceable obligation to sell power existed by a given date.Such a finding is
within the discretion of the state regulatoty agency.”Rosebud Enterprises,128 Idaho 624,91 7
P.2d at 781 (emphasis added).In this consolidated case,we found that each of the five projects
incurred a legally enforceable obligation on December 22,2010.Thus,there is no occasion to
resort to the use of grandfathering criteria.We further find that the time Rocky Mountain Power
took to complete its final review of the Agreements was reasonable.This finding is consistent
with our authority under federal and state law.
Third.our Supreme Court has noted,“Because regulatory bodies perform legislative
as well as judicial functions in their proceedings,they are not so rigorously bound by the
doctrine of stare decisis that they must decide all future cases in the same way as they have
decided similar cases in the past.”Rosebud Enterprises v.Idaho PUC,128 Idaho 609,618,917
ORDER NO.32302 Il
P.2d 766,775 (1996)citing Interrnountain Gas Co.v.Idaho PUC,97 Idaho 113,119,540 P,2d
775,781 (1975),“So long as the Commission enters sufficient findings to show that its action is
not arbitrary and capricious,the Commission can alter its decisions.”Washington Waler Power
v.Idaho PUC,101 Idaho 567,579,617 P.2d 1242,1254 (1980).Therefore,simply because
grandfathering criteria have been used in consideration of QF eligibility to published rates in the
past does not mean that this Commission must decide all future QF eligibility cases in the same
manner.
Regardless of whether it is a change in the eligibility cap for access to published rates
or a change in the rates themselves,the Commission is not bound by prior grandfathering
treatment decisions so long as our decision is based on substantial and competent evidence in the
record and we enter sufficient findings to demonstrate that is the case.The decision of whether
to use grandfathering criteria is within the Commission’s discretion.In contrast to the change in
eligibility for published rates in 2005,no criteria were enunciated or established by this
Commission to determine project eligibility through the use of grandfathering for QF agreements
executed on or after December 14,2010.As stated in our final Order,it is adverse to the public
interest to allow parties who have not executed contracts to avail themselves of an eligibility cap
that is no longer in place.Order No.32260 at 9.Grandfathering contracts that were executed on
or after December 14,2010,and allowing them to utilize an eligibility cap that is no longer
applicable would be contrary to our determination regarding what the public interest requires.
This finding is supported by substantial and competent evidence in the record and is explained in
our Orders.Because the Commission’s decision to not utilize grandfathering criteria was not
arbitrary and/or capricious,we deny reconsideration on this issue.
D.December 14,2010,Effective Date
The Projects next argue that the Commission did not give proper notice of its
intention to require that QFs have fully executed contracts by December 14,2010,in order for 10
aMW projects to be eligible for published avoided cost rates.Reconsideration at 10.
Specifically,the Projects maintain that the Commission did not “state,imply,or otherwise lead
one reasonably to conclude that the Commission would or even might reject its own precedent,
The Commission outlined criteria that it would consider in determining whether a project was eligible for the
previous,no longer applicable,eligibility cap for published avoided cost rates,i.e.,whether a project would be
“grandfathered”and permitted to utilize the old eligibility cap.Order No,29839.
ORDER NO.32302 12
much less violate PURPA,by requiring that a QF have a fully-executed contract in order to
receive published rates.”Id,at 11.The Projects insist that by failing to provide proper notice,
the Commission has acted in an unreasonable and unlawful manner.
Commission Findings:Contrary to the assertion of the Projects,the Commission
provided actual notice to the Projects on December 3,2010,that its decision regarding the
published avoided cost rate eligibility cap would become effective December 14,2010.Order
No.32131 at 5-6,9,granting Cedar Creek’s Petition to Intervene.The Commission’s Order No.
32131 states that “it is our intent that our decision regarding the ‘Joint Motion’to reduce the
published avoided cost eligibility cap shall become effective on December 14,2010.”Id.at 5-6
(emphasis added).Moreover,the ordering section of the Order states:“IT IS FURTHER
ORDERED that the Commission’s decision regarding whether to reduce the published avoided
cost eligibility cap become effective on December 14,2010.”Id.at 9 (capitals in original).
Because this is the very same Order that granted intervention to Cedar Creek,the Projects (i.e.,
Cedar Creek)were provided actual notice.Consequently,we find that the Commission provided
adequate notice to all parties that the eligibility cap was subject to change and that any change
would become effective on December 14,2010.
In the Commission’s final Order in the case establishing the December 14,2010,
effective date for the 100 kW eligibility cap for wind and solar’s access to published rates (GNR
E-10-04),we unequivocally stated that “[ajrguments that the Commission is without authority to
implement its eligibility cap reduction on December 14 are unpersuasive....“Order No.32176
at 10.We noted FERC’s determination that the filed rate doctrine and rule against retroactive
ratemaking do not extend “to cases in which [partiesi are on adequate notice that resolution of
some specific issue may cause a later adjustment to the rate being collected at the time of
service.”Natural Gas clearinghouse v.FERC,965 F.2d 1066,1075 (D.C.Cir.1992)(emphasis
added).We further confirmed that “[t}he goals of equity and predictability are not undermined
when the Commission warns all parties involved that a change in rates is only tentative and
might be disallowed.”OXI USA,Inc.,v.FERC,64 F.3d 679,699 (D.C.Cir.1995).
The Projects insist that by failing to provide proper notice,“regardless of whether the
appropriate notice period was simply the 30-day notice required when the Commission is
performing its legislative function of setting rates,or the more extensive notice required under
Idaho’s Administrative Procedure Act,the Commission has acted in an unreasonable and
ORDER NO.32302 13
unlawful manner...“Id.at 12.The Projects’argument regarding notice is without merit for
several reasons.First,as mentioned above,the Projects had actual notice that the Commission
intended the effective date for the lowered eligibility cap to be December 14,2010.The Projects
(i.e.,Cedar Creek)petitioned to intervene in the GNR-E-10-04 case on November 10,2010 —
five days after the three utilities petitioned the Commission to immediately reduce the eligibility
cap from 10 MW to 100 kW and more than a month before the Commission’s stated effective
date.Cedar Creek Wind Petition at 1 (Case No.GNR-E-10-04).Second,“[t]he Commission,as
part of its statutory duties,determines reasonable rates and investigates and reviews contracts.”
A.W Brown Company v.Idaho Power Company,121 Idaho 812,816,828 P.2d 841,845 (1992)
(emphasis added).These duties are legislative,not adjudicative,in nature.The Commission,as
an agency of the legislative branch of government,exercises delegated legislative powers to
make rates,Id.Idaho Code §6 1-502 defines “Determination of rates”as
Whenever the commission,after a hearing had upon its own motion or upon
complaint,shall find that ...the rules,regulations,practices,or contracts [by
any public utility]affecting such rates ...are unjust,unreasonable,
discriminatory or preferential,or in any wise in violation of any provision of
law .,.the commission shall determine the just,reasonable or sufficient rates,
fares,tolls,rentals,charges,classifications,rules,regulations,practices or
contracts to be thereafter observed and in force .
Review of contracts or agreements that contain PURPA rates falls clearly within the
Commission’s ratesetting,i.e.,legislative,function.Moreover,the APA does not apply to
contested cases before the Commission.Idaho Code §67-5240.There is no question that the
Projects and others were contesting the proposed reduction in the eligibility cap.“The APA
specifically does not apply to ‘those in the legislative or judicial branch.’I.C.§67-5201.”A.W.
Brown Company v.Idaho Power Company,121 Idaho 812,819,828 P.2d 841,848 (1992).
Finally,Idaho Code §6 1-625 prohibits collateral attacks of Commission Orders that
are final and conclusive.“A different rule would lead to endless consideration of matters
previously presented to the Commission and confusion about the effectiveness of Commission
orders.”Utah-Idaho Sugar Co.v.Intermountain Gas Co.,100 Idaho 368,373,597 P.2d 1028,
1063 (1979).The Projects argue that the Commission’s final Order disapproving the
Agreements retroactively applies the reduced 100 kW eligibility cap without notice or due
process.Reconsideration at 12.This argument amounts to a collateral attack of the
Commission’s prior Order reducing the eligibility cap.No party to the GNR-E-10-04 case that
ORDER NO.32302 14
lowered the eligibility cap —including the Projects —timely appealed the Commission’s decision
to lower the eligibility cap effective December 14,2010.Case No.GNR-E-10-04;Order Nos.
32176 and 32212.Therefore,the Commission’s decision to lower the eligibility cap from 10
aMW to 100 kW for wind and solar projects effective December 14,2010,is a final and
conclusive Order of the Commission that is not subject to collateral attack.The Projects’failure
to appeal the Commission’s decision to temporarily reduce the cap effective on December 14,
2010,cannot be revived by seeking reconsideration of the Commission’s final Order in this case.
Therefore,reconsideration of these issues is denied.
Although in this particular case we have established that Cedar Creek had actual
notice,in the alternative,the Commission,‘for good cause shown,may allow changes without
requiring the thirty (30)days’notice herein provided for,by an order specifying the changes so
to be made and the time when they shall take effect....“Idaho Code §61-307,The utilities
had requested an immediate reduction for access to published rates from 10 aMW to 100 kW
claiming that the combined megawatts,the dollar impacts,and the potential adverse
consequences to the system and to customers was enormous.Order No.32131 at 2.On
December 3,2010,the Commission declared that any changes to the published avoided cost rate
eligibility cap would be effective December 14,2010.Id.Although the Commission declined to
immediately reduce QF projects’access to published rates,we declared that any change would
become effective December 14,2010,based on the assertions in the Utilities’Joint Petition.
Absent actual notice,the notice provided would have otherwise met the ‘good cause”exception
to the 30 days’notice requirement of Idaho Code §61-307.
CONCLUSION
The Commission has jurisdiction over PacifiCorp dba Rocky Mountain Power,an
electric utility,and the issues raised in this matter pursuant to the authority and power granted it
under Title 61 of the Idaho Code and the Public Utility Regulatory Policies Act of 1978
(PURPA).The Commission has authority under PURPA and the implementing regulations of
the Federal Energy Regulatory Commission (FERC)to set avoided cost rates,to order electric
utilities to enter into fixed-term obligations for the purchase of energy from qualified facilities
(QFs)and to implement FERC rules.Rosebud Enterprises,Inc.v.Idaho Public Utilities
Commission,128 Idaho 609,612,917 P.2d 766,769 (1996).
ORDER NO.32302 15
Although FERC promulgated the general scheme and rules,it left the actual
implementation of PURPA to the state regulatory authorities.Id.,128 Idaho at 614,917 P.2d
771.FERC rules insist that rates for purchases from QFs be just and reasonable to ratepayers,in
the public interest,and not discriminatory against QFs.18 C.F.R.§292.304(a)(l).Notably,
PURPA and the implementing regulations require only that published/standard avoided cost rates
be established and made available to QFs with a design capacity of 100 kW or less.18 C,F.R.§
292.304(c).When this Commission reduced wind and solar projects’eligibility to published
avoided cost rates we unequivocally stated that continuing to allow large wind and solar projects
access to published avoided cost rates for projects greater than 100 kW was “clearly not in the
public interest.”Order No.32262.We reaffirmed that determination in the present case by
finding that “It is not in the public interest to allow parties with contracts executed on or after
December 14,2010,to avail themselves of an eligibility cap that is no longer applicable.”Order
No.32260 at 9.The Projects have failed to demonstrate that the Commission’s findings are
unreasonable,unlawful,erroneous,or not in conformity with the law.Rule of Procedure 331,
IDAPA 31.01.01.331.01.
The Firm Energy Sales Agreements between Rocky Mountain Power and the five
projects were executed on December 22,2010.The Agreements recite that Rattlesnake Canyon,
Coyote Hill and North Point will each have a maximum capacity of 27.6 MW.Steep Ridge and
Rive Pine will each have a maximum capacity amount of 25.2 MW.Under normal and/or
average conditions,each project will not exceed 10 aMW on a monthly basis.Because the size
of each of these wind projects exceeds 100 kW,they are not eligible to receive the published
avoided cost rate.Nevertheless,the Projects are entitled to PURPA contracts with avoided cost
rates calculated using the IRP Methodology.
ORDER
IT IS HEREBY ORDERED that the Joint Petition for Reconsideration filed by
Rattlesnake Canyon,Coyote Hill,North Point,Steep Ridge and Five Pine wind projects is
denied.
THIS IS A FINAL ORDER ON RECONSIDERATION.Any party aggrieved by
this Order or other final or interlocutory Orders previously issued in this Case Nos.PAC-E-l 1-.
01,PAC-E-1 1-02,PAC-E-1 1-03,PAC-E-1 1-04,and PAC-E-1 1-05 may appeal to the Supreme
ORDERNO.32302 16
Court of Idaho pursuant to the Public Utilities Law and the Idaho Appellate Rules.See Idaho
Code §6 1-627.
DONE by Order of the Idaho Public Utilities Commission at Boise.Idaho this
day of July 2011.
PAUL K LLANtR,PRESIDENT
ARSHA H.SMITH,COMMISSIONER
ATTEST:
we
c’ommission Secretary
O:PACE-I I -O 1 PAC-E-I 1 -02 PAC-E-I I -03 PAC-E-I I -04 PAC-E-II -05ks3
ORDER NO.32302 17
EXHIBIT 9
JOINT PETITION OF UTILITIES
DONOVAN E.WALKER (ISB No.5921)
LISA D.NORDSTROM (1SB No.5733)
Idaho Power Company
P.O.Box 70
Boise,Idaho 83707
Telephone:[phone]
Facsimile:[phone]
dwplker@idahooowørsprn
!aorastrom(gllaan000wer.corfl
Attorneys for Idaho Power Company
DANIEL E.SOLANDER
Rocky Mountain Power
201 South Main
Salt Lake City,Utah 84111
Telephone:[phone]
FacsImile:[phone]
daniel.solanderiWoaclficoro.com
MICHAEL G.ANDREA (ISB No.8308)
Avlsta Corporation
1411 East Mission Avenue—MSC-23
Spokane,Washington 99202
Telephone:[phone]
Facsimile:[phone]
[e-mail]
Attorney for Avista Corporation
C)—-.—.=‘?‘
.4
).:1
4..,
Cfl
AUorney for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE JOINT
PETITION OF IDAHO POWER
COMPANY,AVISTA CORPORATION,
AND ROCKY MOUNTAIN POWER TO
ADDRESS AVOIDED COST ISSUES AND
JOINT MOTION TO ADJUST THE
PUBLISHED AVOIDED COST RATE
ELIGIBILITY CAP.
CASE NO.GNR-E-10-04
JOINT PETITION TO ADDRESS
AVOIDED COST ISSUES AND
JOINT MOTION TO ADJUST ThE
PUBLISHED AVOIDED COST
RATE ELIGIBILITY CAP
Idaho Power Company (Idaho Power”),Avlsta Corporation Avlsta”),and Rocky
Mountain Power (“RMP”)(hereinafter “the Parties”)pursuant to RP 53,56,and 256,
hereby respectfully petItion the Idaho Public Utilities Commission (“Commission”)to
Initiate a docket to Investigate and address various avoided cost and other related
Issues regarding Public Utility Regulatory Policies Act of 1978 (“PURPA”)QualIfying
Facilities (“OF”).AddWonaliy,the PartIes respectfully move that the Commission Issue
JOINT PETITION TO ADDRESS AVOIDED COST ISSUES AND JOINTMOTIONTOADJUSTTHEPUBLISHEDAVOIDEDCOSTRATEELIGIBILITY CAP-I
an Interlocutory Order adjusting the published avoid cost rate eligibility cap for QFs from
10 aMW to 100 kW.This Petition and Motion is based on the following:
On August 6,2009,the Commission initiated Case No.GNR-E-09-03,the review
of the Surrogate Avoidable Resource (“SAR”)methodology for calculating published
avoided cost rates.Numerous parties intervened,filed comments,and otherwise
participated in this proceeding,including Staff,the three electric utilities,and various QF
project developers.On November 3,2010,the Commission convened a public
workshop for all interested parties to discuss the proposals for a wind specific SAR.As
a result of that public workshop,the general consensus was that while there were many
timely and important issues related to PURPA wind QFs and Renewable Energy Credit
(“REC”)ownership,the Commission’s existing avoided cost methodology,the effect of
the same upon the electrical systems of the utilities,the effect upon the utilities’
customers,and the effect upon the continued development of QF projects were much
broader than the discussions around a wind specific SAR.Staff suggested that the
GNR-E-09-03 docket be closed and that an investigation and discussion about the
broader issues related to all PURPA QFs and avoided cost methodology be continued
in a new docket dedicated to that purpose.
Additionally,there was discussion at the November 3 workshop regarding the
need,on an interim basis and during the pendency of this investigation and docket,for
the Commission to adjust the published avoid cost rate eligibility cap for QFs from 10
aMW to 100 kW.This measure has been employed by the Commission in the past on
an interim basis when it has undertaken an investigation and analysis of similar issues.
Our change in published rate availability for certain wind QFs
was based on a showing that there was a need to
JOINT PETITION TO ADDRESS AVOIDED COST ISSUES AND JOINT
MOTION TO ADJUST THE PUBLISHED AVOIDED COST RATE ELIGIBILITY CAP -2
investigate the integration costs of intermittent wind
generation to determine whether an adjustment to the
published avoided cost rate for non-firm wind QFs was
required.It was also recognition of the significant increase
in the number of PURPA wind projects ....We did not
eliminate the utility’s obligation to purchase from wind QFs,
but we established greater administrative control of contracts
during the period of our investigation.For wind QFs greater
than 100 kW offering power on an unfirmed basis,the door
to a purchase contract is not closed.For projects not
qualifying for the published rate,individual negotiation of
rates under an IRP based methodology is required.Under
such IRP based methodology,Company proposed rate
adjustments,if any,are based on individual project
characteristics and are separately considered by the
Commission,
Order No.29872,Case No.IPC-E-05-22.
Many of the same reasons that justified the Commission’s action in the past are
the same reasons that justify the adjustment to the published rate eligibility today.
However,today those reasons and justifications are amplified as the number of
projects,their combined MWs,the dollar impacts,and the potential consequences to
the system and to customers are much larger and much more pronounced than even
those that existed at that time.In 2005,at the time when the Commission last changed
the published rate eligibility as requested here,Idaho Power had received approval from
the Commission for contracts from wind-powered QFs with a total nameplate capacity of
61.5 MW.At that time,Idaho Power also had an additional 21 MW of QF wind contracts
pending approval at the Commission,and an additional 193 MW of new QF wind
contract requests.
In comparison,Idaho Power today has over 208 MW of wind generation currently
operating on its system.Idaho Power has over 264 MW of Commission-approved QF
wind contracts,many of which are currently under construction and scheduled to be on
JOINT PETITION TO ADDRESS AVOIDED COST ISSUES AND JOINT
MOTION TO ADJUST THE PUBLISHED AVOIDED COST RATE ELIGIBiLITY CAP -3
line by December 31,2010,idaho Power also has 80 MW of QF wind pending approval
at the Commission.In addition,Idaho Power has over 570 MW of new QF wind
contract requests,some of which are significantly mature and close to having executed
contracts.In total,Idaho Power could have over 1100 MW of wind powered generation
on its system in the near term,which exceeds the minimum loads experienced on Idaho
Power’s system this year.See,Attachment No.I to this Petition.Cumulatively,this
amount of generation would exceed any other single source of generation —hydro,coal,
natural gas,or other renewables —that exists on Idaho Power’s system.
The same situation exists with Rocky Mountain Power.In 2005,Rocky Mountain
Power had a single 20 MW wind QF contract and less than 50 MW of additional wind
QF requests in Idaho.As of today,RMP has 64 MW of wind QF contracts executed;
however,none have achieved commercial operation,and another 358 MW of standard
wind QF contracts are proposed.Over 300 MW of these proposed standard wind QF
projects started out as large wind projects over 10 aMW and were reconfigured by the
developer into multiple standard QF projects to meet the 10 aMW criteria.The majority
of these projects are proposed for RMP’s Goshen idaho electrical system where
integration of the QF resource as a Network Resource for serving load could be
impacted by transmission constraints across Path C if the wind power is exported to
RMP’s northern Utah load.
The system reliability,operational aspects,and cost of incorporating and
integrating wind generation at such large penetration levels are but some of the issues
that this docket is intended to investigate and address.Other significant issues that
were mentioned at the November 3 workshop are:the ownership and valuation of
JOINT PETITION TO ADDRESS AVOIDED COST ISSUES AND JOINT
MOTION TO ADJUST THE PUBLISHED AVOIDED COST RATE ELlGIBIL(CAP -4
RECs;the lack of capacity (as opposed to energy>provided by intermittent generation
resources and the continued need to build/acquire capacity on the system even with the
addition of wind generated or other intermittent energy;the associated transmission
infrastructure and upgrades needed to bring additional generation to load;the generator
interconnection and transmission service request processes;the mechanical availability
guarantee (“MAG”);posting of security;liquidated damages;lack of a Commission-
approved standard contract template;as well as various other issues.The concern was
also expressed that an unending and unchecked requirement for the utilities to continue
to acquire additional intermittent and other QF generation regardless of any examination
of the utilities’need for additional energy or capacity on its system is circumventing the
Integrated Resource Planning (“IRP”)process.
A significant observation that was discussed at the November 3 workshop is the
increased size and scale of projects that are able to qualify for the published rate
currently.Many of the current QF projects in actuality are not “small”projects but are
large,utility-scale wind farms that are broken up into 10 aMW increments in order to
qualify for the published rates.For Idaho Power and RMP,it is commonplace for the
nameplate rating of these projects to be in the range of 20 to 30 MWs,the same
developer to submit an aggregation of six or more “projects”totaling 100 to 150 MW of
nameplate rating,and the multiple projects to all share interconnection facilities to one
common utility delivery point.The historical “unsophisticated”QF project developers
with a 0.5 MW or a 1.5 MW small hydro canal project —while still in existence —are no
longer the norm and QF projects,for the most part,have evolved to the point where
they are sophisticated parties who are very knowledgeable within this field.In many
JOINT PETITION TO ADDRESS AVOIDED COST ISSUES AND JOINT
MOTION TO ADJUST THE PUBLISHED AVOIDED COST RATE ELIGIBILITY CAP -5
cases,they may have large resources available to them,and in some cases are larger
entities than even the utilities themselves.
It is important to note that the Parties are not asking for a moratorium on the
utilities’obligations to contract with PURPA QF projects.What the Parties are
proposing is only that the eligibility for the published avoided cost rate be modified on an
interim basis.Utilities would still have an obligation to contract for the purchase of
power from QFs that are over the eligibility cap for the published rate,just like they do
today.Rather than the more prescriptive published avoided cost rate pricing and limited
negotiated contracting process,individual negotiation of the rates and contract terms
under an lRP-based methodology is required for QFs above the cap.Much as the
Commission stated in lPC-E-O522,the Parties see this as a way to establish greater
administrative control of the contracts during the pendency of the Commission’s and the
Parties’investigation of the issues.Beyond that,the Parties believe that the IRP-based
methodology with individually negotiated rates and contracts is a better model with
which to address the difficult issues involved and possibly arrive at creative solutions
that will still allow the development of QF projects,but in a manner that is better for
customers and better for the utilities.Idaho Power believes that the recently submitted
Rocklanci Wind Project FESA is a good example of this process.
REQUEST FOR RELIEF
It is important to emphasize that the Petition and Motion do not represent a
retreat by the utilities from a commitment to acquire a significant amount of renewable
resources within a balanced resource portfolio consisting of new generation,
transmission,and demand-side management activities.This request is necessitated by
JOiNT PETITION TO ADDRESS AVOIDED COST ISSUES AND JOINT
MOTION TO ADJUST THE PUBLISHED AVOIDED COST RATE ELIGIBILITY CAP -6
the number of potentially adverse consequences for utility customers,and a shift in the
size,number,magnitude,and sophistication of PURPA QF projects coming onto the
systems of the utilities.PURPA requires that customers be economically indifferent to
the effects of whether power Is purchased from a QF or generated by the utilit When
theutllitylsforcedtobuyQFpowerlnexcessofitstrueavoIdedcostorinexcessofits
minimum loads,customers are no longer Indifferent.The Parties believe that the Issues
raised In this docket should be considered by the Commission at this time and not after
the Impacts on customers have become Inevitable and acute.
The Parties request that theIr request to lower the published avoided cost rate
eligibility cap from 10 aMW to 100 kW be effective lmmedlately and that the
Commission take immedIate action upon the Motion,on fewer than fourteen days
notice,If possible.See,RP 256.CopIes &this Petition and Motion have been served -
either physlcally eiectronkaily or both -upon all parties,Intervenors,and parties that
filed comments In the Wind SAR case,Docket No.GNR-E-09-03.As the Commission
Is well aware,In the past,when the Commission has Investigated and examined
avoided cost rates and Issues,there occurs a ‘race’to the door of the utilities with
projects attempting to position themselves for a claim to “grandfatherlng”and
entitlement to the previously effective rates,terms,conditions,etc.Idaho Power
continues to get such requests from projects on a nearly daily besis.in fact one of the
drMng forces behind the Parties’requests In this case Is just such an Influx of requests
for contracts.It is also Important that this change In eligibility for published avoided cost
rates be applied equally to the Parties)as exclusion of one may act as a “magnet’
attracting a dIsproportIonate number of project proposals for that utIlity.
JOINT PETITION TO ADDRESS AVOIDED COST ISSUES AND JOINT
MOTiON TO ADJUSTThE PUBLISHED AVOIDED COST RATE BLLrFY CAP 7
JOINT PETITION TO ADDRESS AVOIDED COST ISSUES AND JOINT
MOTION TO ADJUST THE PUBLISHED AVOIDED COST RATE ELIGIBILITY CAP -8
WHEREFORE,the Parties respectfully request:
1.That the Commission immediately issue an Order reducing the published
avoided cost rate eligibility cap for PURPA QFs from 10 aMW to 100 kW;and
2.That the Commission convene a prehearing conference to define issues
and establish a schedule for processing and considering the issues raised in the
Petition and defined in the prehearing conference.
DATED at Boise,Idaho,this 5tti day of November 2010.
I /
/)/(V /
DONOVAN E.WALKER
Attorney for Idaho Power Company
5/HAEL G.ANDREA
Attorney for Avista Corporation
7/J (1 /)i
DANIEL SOLANDER I
Attorney for Rocky Mountain Power
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 5th day of November 2010 I served a true and
correct copy of the JOINT PETITION TO ADDRESS AVOIDED COST ISSUES AND
JOINT MOTION TO ADJUST THE PUBLISHED AVOIDED COST RATE ELIGIBILITY
CAP upon the following named parties by the method indicated below,and addressed
to the following:
Commission Staff X Hand Delivered
Scott Woodbury
____
U.S.Mail
Deputy Attorney General
____
Overnight Mail
Idaho Public Utilities Commission
____
FAX
472 West Washington X Email scott,[e-mail]
P.O.Box 83720
Boise,Idaho 83720-0074
Avista Corporation
____
Hand Delivered
Michael Andrea X U.S.Mail
Avista Corporation
____
Overnight Mail
1411 East Mission Avenue
____
FAX
P.O.Box 3727 X Email [e-mail]
Spokane,Washington 99220
Clint Kalich
____
Hand Delivered
Avista Corporation
____
U.S.Mail
1411 East Mission Avenue
____
Overnight Mail
P.O.Box3727
___
FAX
Spokane,Washington 99220-3727 X Email cIint.kalichavistacorp.com
Daniel E.Solander
____
Hand Delivered
Rocky Mountain Power X U.S.Mail
201 South Main
____
Overnight Mail
Salt Lake City,UT 84111
____
FAX
X Email daniel.soIander(pacificorp.com
Bruce Griswold
____
Hand Delivered
PacifiCorp X U.S.Mail
825 NE Multnomah
____
Overnight Mail
Portland,Oregon 97232
____
FAX
X Email bruce.qriswoId(pacifiCorp.com
JOINT PETITION TO ADDRESS AVOIDED COST ISSUES AND JOINT
MOTION TO ADJUST THE PUBLISHED AVOIDED COST RATE ELIGIBILITY CAP -9
J.Ted Weston
____
Hand Delivered
Rocky Mountain Power
____
US.Mail
201 South Main Street,Suite 2300
____
Overnight Mail
Salt Lake City,Utah 84111
____
FAX
X Email ted.westonpacificorp.corn
Peter J.Richardson
____
Hand Delivered
Greg Adams X US.Mail
RICHARDSON &O’LEARY,PLLC
___
Overnight Mail
515 North 27th Street
____
FAX
P.O.Box 7218 X Email eter(richardsonandoleary.com
Boise,Idaho 83702 gregrichardsonandoleary.com
Dr.Don Reading
____
Hand Delivered
Ben Johnson Associates X U.S.Mail
6070 Hill Road
____
Overnight Mail
Boise,Idaho 83703
____
FAX
X Email dreadinq(mindsprinci.com
Dean J.Miller
____
Hand Delivered
MODEVITT &MILLER,LLP X U.S.Mail
420 West Bannock Street
____
Overnight Mail
P.O.Box2564
___
FAX
Boise,Idaho 83701 X Email Ioe(mcdevitt-miller.com
Idaho Windfarms,LLC
____
Hand Delivered
Glenn Ikemoto
____
U.S.Mail
Idaho Windfarms,LLC
____
Overnight Mail
672 Blair Avenue
____
FAX
Piedmont,California 94611 X Email qlennipacbell.net
Renewable Energy Coalition
____
Hand Delivered
Thomas H.Nelson X U.S.Mail
P.O.Box 1211
____
Overnight Mail
Welches,Oregon 97067-1211
____
FAX
X Email neIsonthneJson.com
John R.Lowe
____
Hand Delivered
12050 SW Tremont Street X U.S.Mail
Portland,Oregon 97225
____
Overnight Mail
___
FAX
X Email [e-mail]
JOINT PETiTION TO ADDRESS AVOIDED COST ISSUES AND JOINT
MOTION TO ADJUST THE PUBLISHED AVOIDED COST RATE ELIGIBILITY CAP -10
Sorenson Engineering,Inc.
____
Hand Delivered
Ted S.Sorenson,RE.X U.S.Mail
Sorenson Engineering,Inc.
____
Overnight Mail
5203 South 11th East
____
FAX
Idaho Falls,Idaho 83404-7692 X Email tedtsorenson.net
American Falls Reservoir District 2
____
Hand Delivered
Lynn Harmon
____
U.S.Mail
American Falls Reservoir District 2
____
Overnight Mail
409 North Apple Street
____
FAX
Shoshone,Idaho 83352 X Email lynnharmon(cableone.net
Arron F.Jepson
____
Hand Delivered
Blue Ribbon Energy LLC
____
U.S.Mail
____
Overnight Mail
___FAX
X Email ArronEsgcaol.com
idaho Conservation League
____
Hand Delivered
Benjamin Otto
____
U.S.Mail
710 North Sixth Street
____
Overnight Mail
P.O.Box 844
___
FAX
Boise,Idaho 83701 X Email botto(aidahoconservation,orq
Bill Arkoosh
____
Hand Delivered
___
U.S.Mail
____
Overnight Mail
___
FAX
X Email tunupajohn(ämsn.com
Faulkner Brothers Hydro
____
Hand Delivered
Mitch Arkoosh X U.S.Mail
Faulkner Brothers Hydro
____
Overnight Mail
1989 South 1875 East
____
FAX
Gooding,Idaho 83330 X Email [e-mail]
JOINT PETITION TO ADDRESS AVOIDED COST ISSUES AND JOTNT
MOTION TO ADJUST THE PUBLISHED AVOIDED COST RATE ELIGIBILITY CAP -11
Twin Falls Canal Company
____
Hand Delivered
Brian Olmstead
____
U.S.Mail
Twin Falls Canal Company
____
Overnight Mail
Twin Falls Energy
____
FAX
Midway Power LLC X Email fcn?±cpi1]
P.O.Box 326
Twin Falls,Idaho 83301
..
Donovan E.Walker
JOINT PETITION TO ADDRESS AVOIDED COST ISSUES AND JOINT
MOTION TO ADJUST THE PUBLISHED AVOIDED COST RATE ELIGIBILITY CAP -12
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EXHIBIT 10
ROCKY MOUNTAIN POWER’S REPLY COMMENTS
LOVINGER I KAUFMANN UP
825 NE Multnomah Suite 925 RECEI’s’Ffl office [phone]
Portland,OR 97232-2150 fa:x [phone]
‘i”PR iz 1 3;09
LVII ‘‘KennethEKaufmann
KauU.com
iJ—1lLlT1t
April 8,2011
Via Electronic Mail and Overnight Mail
Jean D.Jewel!,Secretary
Idaho Public Utilities Commission
472 W Washington Street
P0 Box 83720
Boise,ID 83720-0074
Street Address for Express Mail:
472 W.Washington
Boise,ID 83702-5918
Re:Case Nos.PAC-E-1 1-01,PAC-E-1 1-02,PAC-E-l 1-03,PAC-E-l 1-04,PAC-E-1 1-05
TN THE MA1TER OF THE APPLICATION OF PACIFICORP DBA ROCKY
MOUNTAIN POWER FOR A DETERMINATION REGARDING FIRM ENERGY
SALES AGREEMENTs BETWEEN ROCKY MOUNTAIN POWER AND CEDAR
CREEK WIND,LLC
Dear Ms.Jewel!:
Enclosed for filing in the above-captioned docket are an original and seven (7)copies of
REPLY COMMENTS OF ROCKYMOUNTAIN POWER.
An extra copy of this cover letter is enclosed.Please date stamp the extra copy and return it to
me in the envelope provided.
Thank you in advance for your assistance.
Sincerely,
Kenneth E.Kaufmann
cc:PAC-E-1 1-01 Service List
Enclosures
Jeffrey S.Lovinger RE CE IV FE)
Kenneth E.Kaufmann
Lovinger Kaufmann LLP 2811 APR 12 PM 3:09
825 NE Multnomah,Suite 925
Li t
Portland,Oregon 97232 JTILlT ‘c.
Telephone:[phone]
Fax:[phone]
1ovinger1klaw.com
[e-mail]
Attorneys for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )Case No.PAC-E-1 1-01
PACIFICORP DBA ROCKY MOUNTAIN )
POWER FOR A DETERMINATION )
REGARDING A FIRM ENERGY SALES )
AGREEMENT BETWEEN ROCKY )
MOUNTAIN POWER AND CEDAR CREEK )
WIND,LLC (RATTLESNAKE CANYON )
PROJECT )
__________________________________________________________________________________
)
IN THE N THE MATTER OF THE )Case No.PAC-E-1 1-02
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 (COYOTE HILL PROJECT )
)
__________________________________________________________________________________
)
IN THE MATTER OF THE APPLICATION OF )Case No.PAC-E-1 1-03
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))
)
)
IN THE MATTER OF THE APPLICATION OF )Case No.PAC-E-1 1-04
PACIFICORP DBA ROCKY MOUNTAIN )
POWER FOR A DETERMINATION )
REGARDING A FIRM ENERGY SALES )
AGREEMENT BETWEEN ROCKY MOUNTAIN )
POWER AND CEDAR CREEK WIND,LLC )
(STEEP RIDGE PROJECT))
)
___________________________________________________________________________________
)
IN THE MATTER OF THE APPLICATION OF )Case No.Pac-E-1 1-05
PACIFICORP DBA ROCKY MOUNTAIN )
POWER FOR A DETERMINATION )
REGARDING A FIRM ENERGY SALES )
AGREEMENT BETWEEN ROCKY MOUNTAIN )REPLY COMMENTS OF
POWER AND CEDAR CREEK WIND,LLC )PACIFICORP DBA
(FIVE PINE PROJECT))ROCKY MOUNTAIN
POWER
___________________________________________________________________________________
)
Comes now PacifiCorp dba Rocky Mountain Power and files these Reply Comments in
response to Reply Comments of Cedar Creek Wind.’Without recommending that the
Commission approve or disapprove the five Cedar Creek Wind power purchase agreements,
Rocky Mountain Power notes the following facts and law for the Commission’s consideration.
Background
Rocky Mountain Power and Cedar Creek Wind completed negotiation of all terms of the
power purchase agreements (“PPAs”)for Cedar Creek Wind’s five,1OaMW wind qualifying
facilities (“QFs”)prior to December 14,2010,Rocky Mountain Power is aware the Public
Utility Regulatory Policies Act of 1978 (“PURPA”)does not permit a utility to delay signing a
PPA while it waits for a pending rate change to take effect and Rocky Mountain Power acted
with reasonable speed to execute the PPAs given the number of documents and complexity of
‘Rocky Mountain Power’s Reply Comments,as well as the Reply Comments of Cedar Creek Wind filed on April 5,
are out of the prescribed window to comment set forth by the Commission in its February 24,2011 Order No.
32192.Rocky Mountain Power therefore requests that the Commission either strike both Replies or accept both
Replies.
REPLY COMMENTS OF 2
ROCKY MOUNTAiN POWER
review of the multiple transactions requested by Cedar Creek Wind.It is important to note that
the Company’s contract review and execution procedure must comply with Sarbanes Oxley
(“SOX”)regulatory requirements.Beginning when the PPA is in near-final form,various
functions in the Company review the draft PPA and make a preliminary determination of what is
needed for fmal review and approval.From these reviews,the Company determines if there are
any major issues that need to be addressed with the QFs and what follow-up information is
needed for final approval.Once the parties agree to a final draft,the final draft then undergoes a
detailed review and sign-off by management,merchant transmission,accounting,financial
reporting (FAS133,Fin 46,etc.),credit,legal,billing,and delegation of signing authority by the
appropriate Company executive for execution of the agreement.As this final review requires the
involvement of several functions across the Company and detailed scrutiny of the final PPA
draft,the typical time for this final review and execution phase is 5 to 10 business days.Seldom
does this review result in any material changes to the draft PPA.Rather,the final review process
confirms that the contract complies with the Company’s SOX requirements,documents that all
PPA requirements were met,and moves the PPA to execution.Each executed contract is
documented for validation and signed-off by the various functions and a copy of the PPA and
documentation is retained for compliance auditing purposes.
The Company commenced internal review of a near-final draft of the Coyote Creek PPA
on November 15,2010,and continued the internal review process in parallel with the parties’
ongoing negotiations of the near-final drafi and a related transmission agreement.After those
negotiations finished,Cedar Creek Wind signed and delivered original copies of all five PPA
agreements without exhibits to Rocky Mountain Power’s Portland office late on the afternoon of
December 13,2010.Cedar Creek Wind did not deliver final conformed exhibits for each PPA
REPLY COMMENTS OF 3ROCKYMOUNTAINPOWER
until December 14,2010.Once Rocky Mountain Power received the conformed exhibits from
Cedar Creek Wind,the Company verified every page of each PPA (including exhibits),
documented the review,obtained internal approvals,executed the originals,and made copies
before returning a complete set of executed originals to Cedar Creek Wind.During the review,
the Company identified discrepancies in several of the PPA exhibits which were corrected and
confirmed by Cedar Creek Wind on December 16,2010.These discrepancies included;
incorrect project names in Exhibit D for Five Pine,North Point,Rattlesnake Canyon and Steep
Ridge,incorrect QF number for Rattlesnake Canyon,and changes by Cedar Creek Wind to the
Five Pine and North Point PPA exhibits that were incorrectly made on the Coyote Hill exhibits.
The Company also performed additional legal and technical analysis to confirm that the five
projects did not violate the 1-mile rule codified at 18 C.F.R.§292.204,and that the addendum to
the PPAs allocating comingled line losses and station service comported with PURPA and
transmission system interconnection requirements.The Company completed fmal review and
executive approval was received December 22,2010.The Company executed the five PPAs on
December 22,2010 and delivered copies of the signature page to Cedar Creek Wind that same
day with a filly conformed original for each PPA following by mail.
The Company completed review and execution or all five PPAs in 7 business days--well
within the typical range of time that the Company has completed fmal reviews with other QF
projects.It is unlikely that Rocky Mountain Power could have completed its review in a timelier
manner and in no event could the Company have been diligent and still executed the contracts
prior to December 14,having received signed PPAs with no conformed exhibits from Cedar
Creek Wind at the end of the business day on December 13,2010.
REPLY COMMENTS OF 4
ROCKY MOUNTAIN POWER
At the time Rocky Mountain Power executed the agreements,there was uncertainty about
the correct avoided cost rate for all small idaho QFs over 100kW.On November 5,2010,Rocky
Mountain Power,Idaho Power Company,and Avista Corporation jointly petitioned the
Commission to immediately reduce the eligibility cap for published avoided cost rates from
1 OaMW to 100kW.2 The Commission,on December 3,2010,issued Order No.32131,in which
it declined to immediately reduce the 1 OaMW eligibility cap,but simultaneously announced its
intent to review the eligibility cap at a January 27,2011 hearing and to apply the outcome ofthat
process effective December 14,2010.Order No.32131 gave Rocky Mountain Power and
Cedar Creek Wind notice that the eligibility status of the Cedar Creek Wind QFs might change,
effective December 14,2010.However the parties did not know,and could not know,the post-
December 14 status of those projects until the Commission’s final decision (Order No.32176),
issued February 7,2011 .Under those circumstances,Rocky Mountain Power did what it
believed it was obligated to do—it executed the five agreements (the “December 22 PPAs”)with
the terms and conditions the parties agreed to prior to December 14,2010,and with the
published avoided cost rates in effect on December 22,2010.Rocky Mountain Power did not
know,on December 22 or at any time thereafter,whether the Commission would approve the
PPAs as executed.
2 Joint Petition to Address Avoided Cost Issues and Joint Motion ‘o adjus the Published Avoided Cost RateEligibilityCap,Case No.GNR-E-10-04,(Nov.5,2010).
In the Matter ofthe Joint Petition ofIdaho Power Company,Avista Corporation,and PacfiCorp d/b/a RockyMountainPowertoAddressAvoidedCostIssuesandAdjus!the PublishedAvoided Cost Rate Eligibility Cap,CaseNo.GNR-E-10-04,Order No.32121 (2010).
Id.
On December 22,2010,it was not yet clear whether the Commission would decide to reduce the eligibility cap forpublishedavoidedcostrateseffectiveDecember14,2010,and it was therefore not clear on December 22,2010,thatCedarCreekWind’s QF development—a large development which had been disaggregated into five QFs underIOaMW—would not qualify for published avoided cost rates after December 14,2010.
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Discussion
Cedar Creek Wind argues,in its Reply Comments (page 4),that it is entitled to approval
of its contracts because the parties “had a meeting of the minds”prior to December 14,2010.
However,under their terms,the December 22 PPAs are not effective until approved by the
Commission.Section 2.1 of each of PPA provides:
This Agreement shall become effective after execution by both Parties and after
approval by the Commission (“Effective Date”);provided,however,this
Agreement shall not become effective until the Commission has determined,
pursuant to a final and non-appealable order,that the prices to be paid for energy
and capacity are just and reasonable,in the public interest,and that the costs
incurred by PacifiCorp for purchases of capacity and energy from Seller are
legitimate expenses,all of which the Commission will allow PacifiCorp to
recover in rates in Idaho in the event other jurisdictions deny recovery of their
proportionate share of said expenses.
Per the language above,the December 22 PPAs cannot become effective until the Commission
finds that:(1)the prices to be paid for energy and capacity are just and reasonable;(2)the
contract is in the public interest;and (3)costs incurred by the Company for purchases of capacity
and energy from Seller are legitimate expenses,all of which the Commission will allow the
Company to recover in rates in Idaho in the event other jurisdictions deny recovery of their
proportionate share of said expenses.
On previous occasions where QFs sought grandfathered rate treatment the Commission
has,without exception known to the Company,made the above findings and approved
grandfathered rates where the parties fully executed a PPA prior to the date of a rate change.
The Commission also authorizes grandfathered treatment where the parties did not fully execute
the PPA and the QF files a meritorious complaint prior to the rate change alleging that the
utility’s foot dragging prevented full execution of a PPA before the rate change.These two
recognized fact patterns embody what Rocky Mountain Power has referred to before the
Commission as the “bright line”rule for grandfathered rate treatment announced by the
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Commission and affirmed by the Idaho Supreme Court in the I 990s.6 Under the bright line rule,
Cedar Creek Wind could have assured itself of obtaining the preDecember 14,2010 published
avoided cost rates if it had either obtained fully executed PPAs by December 14 or filed a
meritorious complaint by December 14 alleging that Rocky Mountain Power improperly refused
to execute PPAs.Cedar Creek Wind did neither and Cedar Creek Wind therefore is not entitled
to the certain relief of the bright line rule.
Cedar Creek Wind requires an exception to the bright line rule to allow its QFs to qualify
for pre-December 14 published avoided cost rates.There is recent Commission precedent for
granting grandfathered rate treatment in circumstances where the seller failed the bright line test.
In 2010,Idaho Power Company requested,and the Commission granted,grandfathered rate
treatment to both the Grand View Solar and the Yellowstone Power Inc.QFs.7 The Commission
noted that there was a meeting of the minds prior to the rate change but also based its grant of
grandfathered rate treatment on other,equitable,reasons.In Grand View Solar,the Commission
found that “but for consideration by the Company of a non-PURPA contract for the project,a
contract would have been signed prior to March 16,2010.8 In Yellowstone,the Commission
found that a “combination of factors,coupled with evidence of an agreement prior to March 16,
2010,make it clear that approval of the Agreement’s grandfathered avoided cost rate is in the
6 A.WBown Co.,Inc.v.Idaho Power Co.,121 Idaho 812,816,828 P.2d 841 (1992);See,also,In the Matter ofthe
Application ofIdaho Power Companyfor Approval ofa Firm Sales Agreement with Yellowstone Power,Inc.for the
Sale and Purchase ofElectric Energy,Case No.IPC-E-10-22,Comments of the Commisson Staff,at 3 (2010).
See,In the Matter of the Application of Idaho Power Company for Approval of a Firm Energy Sales Agreement
with Grand View Solar PV 1,LLCfor the Sale and Purchase ofElectric Energy,Case No.1PC-E-10-19,Order No.
32068 (2010);In the Matter of the Application ofIdaho Power Company for Approval ofa Firm Sales Agreement
with Yellowstone Power,Inc.for the Sale and Purchase ofElectric Energy,Case No.IPC-E-1 0-22,Order No.32104
(2010).
8 Order No.32068,at 5.
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public interest.”9 These cases may be factually distinguished from Cedar Creek Wind QFs,
based on the “other factors”unique to the Cedar Creek Wind projects.Whereas,Grand View
and Yellowstone are both single QFs with capacity less than 10 aMW,the five Cedar Creek QFs
are,in substance,a single 133 MW project,disaggregated into 10 aMW projects,apparently for
the purpose of qualifying for that to which it otherwise is not entitled—the published avoided
cost rate.The policy implications of grandfathering Cedar Creek Wind PPAs are not the same as
the implications for grandfathering either Grand View or Yellowstone.
Conclusion
Rocky Mountain Power concurs with Cedar Creek Wind’s statement (on page 3 of its
Reply)that the two parties reached agreement on all terms of their December 22 power purchase
agreements prior to December 14,2010.This fact alone does not,however,compel the
Commission to approve those contracts.
Dated this 8th day of April,2011.
Respectfully Submitted,
kenneth Kaufmann
Lovinger Kaufmann,LLP
Of Attorneys for Rocky Mountain Power
9OrderNo.32104,at 12.
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CERTIFICATE OF SERVICE
I herby certify that I have this 8th Day of April,2011,served the foregoing ReplyCommentsofPacifiCorp,d/bla Rocky Mountain Power,in Case No.PAC-E-l 1-0102030405,by electronic and overnight mail,to the following:
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Jean Jewell
Commission Secretary
Idaho Public Utilities Commission
472 W.Washington
P0 Box 83720
Boise,ID 83720-0074
jean.iewe1l@puc(idaho.gov
[e-mail]
Ted Weston
ID REG Affairs MGR
Rocky Mountain Power
201 South Main,Suite 2300
Salt Lake City,UT,84111
E-Mail:ted.weston@;pacificorp.com
Daniel Solander
Rocky Mountain Power
201 South Main,Suite 2300
Salt Lake City,UT,84111
E-Mail:[e-mail]
Ronald L.Williams
Williams Bradbury PC
1015 W.Hays St
Boise,ID 83702
E-Mail:ron(wi1liamsbradbury.com
Jeffery S.Lovinger,OSB 960147
Kenneth E.Kaufmann OSB 982672
Lovinger Kaufmann LLP
Attorneysfor Rocky Mountain Power
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