20110608final_order_no_32257.pdf

Office of the Secretary
Service Date
June 8,2011
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY FOR A )CASE NO.IPC-E-1O-61
DETERMINATION REGARDING A FIRM )
ENERGY SALES AGREEMENT BETWEEN )
IDAHO POWER AND GROUSE CREEK WIND )
PARK,LLC )
______________________________________________________________________________________
)
IN THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY FOR A )CASE NO.IPC-E-1O-62
DETERMINATION REGARDING A FIRM )
ENERGY SALES AGREEMENT BETWEEN )
IDAHO POWER AND GROUSE CREEK WIND )
PARK II,LLC )ORDER NO.32257
On December 29,2010,Idaho Power Company filed two Applications each
requesting acceptance or rejection of a 20-year Firm Energy Sales Agreement (“Agreements”)
between Idaho Power and Grouse Creek Wind Park,LLC,and Grouse Creek Wind Park II,LLC
(Facility;Project).Both projects are located near Lynn,Utah,and managed by Wasatch Wind
Intermountain,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).
Idaho 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 Wasatch
Wind on behalf of each of the two projects.’On April 7,2011,Wasatch Wind filed a Motion to
Set Time for Oral Argument because “the records in these cases are lengthy and Idaho Power
appears to interpret the evidence different than the Grouse Creek QFs....“Motion at 5.
Commission Staff and Idaho Power filed objections to the projects’motion.On April 27,2011,
The parties in these two cases have all filed consolidated comments because the “relevant facts for each of these
projects are substantially similar.”Comments of Wasatch Wind at n.1.Consequently,the Commission finds it
reasonable and appropriate to consolidate these cases and issue this consolidated final Order.Rule 247,IDAPA
31.01.01.247.
ORDER NO.32257 1
the Commission issued an Order denying the projects’motion.2 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.32176 at 1.
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)(12).
When a QF project is larger than the published 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.
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
2 The Commission found that “the evidentiary record sufficiently reflects the positions of all parties.Moreover,the
Projects have not alleged that their position is not adequately presented through written submissions.”Order No.
32236 at 2.
ORDER NO.32257 2
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-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.
THE AGREEMENTS
On December 28,2010,Idaho Power and each of the two wind projects entered into
their respective Agreements.Under the terms of the Agreements,each wind project agrees to
sell electric energy to Idaho Power for a 20-year term using the 10 aMW non-levelized published
avoided cost rates.Applications at 4.The nameplate rating of each Facility is 21 MW.Under
normal and/or average conditions,each Facility will not exceed 10 aMW on a monthly basis.
Idtho 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.
Each Facility has selected June 1,2013,as its Scheduled First Energy Date and
December 1,2013,as its Scheduled Operation Date.Applications at 5.Idaho Power asserts that
various requirements have been placed upon the Facilities in order for Idaho Power to accept the
Facilities’energy deliveries.Idaho Power states that it will monitor the Facilities’compliance
with initial and ongoing requirements through the term of the Agreements.Idaho Power asserts
that it has advised each Facility of the Facility’s responsibility to work with Idaho Power’s
delivery business 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 December 1,2013,Scheduled Operation Date.
The Applications state that each Facility “is currently in the beginning stages of the
generator interconnection process.[Each}Facility is located outside of Idaho Power’s service
territory and thus must complete the interconnection process with a different host utility.”Id.at
ORDER NO.32257 3
6.The Agreements require each Facility to acquire interconnection and continuous firm
transmission capacity to a Point of Delivery on Idaho Power’s system.Idaho 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 Operation Date delay
damages will be assessed.Id.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.at 7.
The parties have each agreed to liquidated damage and security provisions of $45 per kW of
nameplate capacity.Agreements,¶J 5.3.2,5.8.1.
Idaho Power states that each Facility has also been made aware of and accepted the
provisions in each Agreement and Idaho Power’s approved Schedule 72 regarding non-
compensated curtailment or disconnection of its Facility should certain operating conditions
develop on Idaho Power’s system.The Applications note that the parties’intent and
understanding is that “non-compensated curtailment would be exercised when the generation
being provided by the Facility in certain operating conditions exceeds or approaches the
minimum load levels of [Idaho Power’s]system such that it may have a detrimental effect upon
[Idaho Power’s]ability to manage its thermal,hydro,and other resources in order to meet its
obligation to reliably serve loads on its system.”Applications at 7.
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 Idaho Power
to the Facilities for purchases of energy will be allowed as prudently incurred expenses for
ratemaking purposes.Agreements ¶21.1.
THE COMMENTS
A.Staff Comments
Staff observed that both of the Agreements are nearly identical.The two Facilities
collectively are expected to generate 128,887 MWh annually.Under the non-levelized rates in
the Agreements,the annual energy payments by Idaho Power for the expected generation will be
approximately $8.3 million in 2014 increasing to approximately $15.9 million in 2033,or a
cumulative total of $236.4 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
$83.8 million.
ORDER NO.32257 4
Both of the Agreements were signed by the Project developer on December 20,2010,
and signed by Idaho Power on December 28,2010.The Agreements were filed with the
Commission on December 29,2010.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 each of the Agreements to be December 28,
2010,
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 100 kW,Staff maintains that approval of the Agreements
is prohibited by Order No.32176.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.The Projects’Comments
The Projects assert that these wind projects began development in 2007,have
possessed rights to use private lands for the Project sites since February 2008,and have over two
years of wind data supporting its output projections.Comments at 2.The Projects claim that
they have been in formal power sales contract negotiations with Idaho Power since February
2010.In April 2010,Idaho Power provided the Projects with PURPA contract pricing
(calculated through the Aurora model)consistent with a project producing up to 65 MW.In June
2010,the Projects signed a letter of understanding provided by Idaho Power,“which stated Idaho
Power would not execute a power sales contract prior to when the Project received confirmation
that the results of the initial Idaho Power transmission capacity application for transmission to its
load center are known and the Project accepts the results.”Id.at 12.In a June 25,2010,e-mail,
the Projects indicated to Idaho Power that “due to federal permitting issues,[the Projects]
intended to reduce [their]overall footprint and wished to discuss power sales contracts for two
single 10 aMW projects,instead of the large 65 MW project.”Id.at 13.On July 14,2010,the
Projects submitted a formal request for two 10 aMW PURPA contracts to Idaho Power.Id.
ORDER NO.32257 5
On October 1,2010,the Projects sent a letter to Idaho Power expressing their intent
to obligate themselves to two power sales agreements.Id.at 14.The letter ‘expressed [the
Projects’]concern also with the legality of the high $45/kw delay liquidated damages security
provision Idaho Power had begun requiring....“Id.at 15.Idaho Power responded on
November 1,2010,by providing a draft standard FESA and indicating that the Projects must
agree to the $45/kW delay security amount —which terms were contained in the draft agreement.
Id.
After the utilities filed their Joint Petition in the GNR-E-10-04 case,the Projects each
filed complaints with the Commission against Idaho Power on November 8,2010.The Projects
assert that,on November 19,2010,they agreed with idaho Power to stay the complaint
proceedings and execute standard QF wind contracts “containing the $45/kw delay security but
not containing the precondition of firm transmission rights prior to execution.”Id.at 4.On
December 2,2010,the Projects provided Idaho Power with contracts containing the project
specifics for each project and on December 9,2010,the Projects clarified the online date to
comply with the BPA transmission service request.On December 16,2010,Idaho Power
provided executable Agreements to the Projects.Id.at 19.On December 20,2010,the Projects
executed the Agreements and sent them back to Idaho Power by overnight delivery.3 Idaho
Power executed the Agreements on December 28,2010,and filed them with the Commission the
next day.id.
The Projects argue that because they filed meritorious complaints on November 8,
2010,and because all project specifics and material terms of the contracts were finalized prior to
December 14,2010,the Commission should approve both FESAs containing the published
avoided cost rates.The Projects maintain that,“[w]hen the published rates change,or become
otherwise unavailable to a QF before the QF can obtain a contract,the QF is entitled to
grandfathered rates if it can demonstrate that ‘but for’the actions of [the utility,the QF]was
otherwise entitled to a power purchase contract.”Id.at 7.The Projects further allege that the
large sums of money and time spent in developing the Projects and the advanced stage of their
maturity evidences their intent to obligate themselves to a power purchase agreement.Id.
Both Projects and Idaho Power represent that Grouse Creek Wind Park and Grouse Creek Wind Park 11 signed
their respective Agreements on December 21,2010.However,the date reflected in each Agreement filed with this
Commission under the Project manager’s signature is clearly December 20,2010.
ORDER NO.32257 6
C.Idaho Power Reply
Idaho Power stated that it executed the two Agreements in good faith and will honor
them if approved by the Commission.Reply at 10.Idaho Power argued that “the continuing and
unchecked requirement for the Company to acquire additional intermittent and other QF
generation regardless of its need for additional energy or capacity on its system not only
circumvents the Commission-mandated IRP planning process and creates system reliability and
operational issues,but it also increases the price its customers must pay for their energy needs
above the Company’s actual avoided costs.”Id.at 11.
Idaho Power’s reply comments explained its internal processing of PLJRPA power
purchase agreements.4 Idaho Power states that,once the proposed draft PPA is in final draft
form,an internal Sarbanes Oxley (‘SOX’)review is required.This review takes approximately
10 business days and provides confirmation from all necessary divisions within the Company
that the contract meets all SOX requirements and thus enables Idaho Power to execute the PPA.
Following the SOX review,three executable copies of the PPA are prepared and sent to the
project.When signed contracts are returned to Idaho Power by the project,Idaho Power
schedules a time for the appropriate Idaho Power executive to sign and execute the agreement.
Id.at 6.“Generally this is accomplished within one to two business days of when the executed
agreement is received back from the project,but is dependent on the limited availability of the
required Company executive with the requisite authority to execute contracts containing such
large monetary obligations as those contained in the typical 20-year PURPA PPA.”Id.
Idaho Power maintains that it began communications with the Projects in February
2010.The initial project was a single 150 MW project spread across 4,000 acres of land.Id.at
7.Discussions on the 150 MW project continued until April 2010,when Idaho Power was
informed that the Projects were now considering a single 65 MW project.Id.In July 2010,the
Projects informed Idaho Power that it wished to discuss power sales contracts for two single 10
aMW projects,instead of the larger 65 MW single project.Idaho Power maintains that,during
negotiations,the Projects objected to certain terms in the PPAs regarding Idaho Power’s security
deposit requirements.In addition,because the Projects were located off Idaho Power’s system,
the Company initially required commitments from the Projects regarding the Projects’ability to
deliver energy to Idaho Power’s system.Idaho Power later agreed to relax this precondition.In
The Firm Energy Sales Agreements are also known as Power Purchase Agreements,or “PPAs.”
ORDER NO.32257 7
its reply,Idaho Power notes that “the Projects have still not entered into a definitive transmission
service agreement with Bonneville Power Administration (‘BPA’)to enable it to deliver energy
to Idaho Power’s system.”Id.at 8.
Idaho Power maintains that on December 2,2010,the Projects returned “marked-up
versions of previously sent draft PPAs”to Idaho Power.Id ‘These mark-ups were the first time
Idaho Power was definitively informed of the Projects’size and configuration.”Id.On
December 9,2010,the Projects provided Idaho Power with the Projects’proposed online dates.
On December 14,2010,Idaho Power sent an information request to the Projects seeking
information necessary to finalize the PPAs and on December 15 Idaho Power sent an email to the
Projects confirming the first energy and commercial operation dates.On December 16,2010,
Idaho Power states that it provided the Projects with executable copies of the Agreements.On
December 20,2010,the Projects executed the Agreements and returned them to Idaho Power by
overnight mail.Idaho Power executed the Agreements on December 28,2010,and filed them
with the Commission the next day.
Idaho Power equates the public interest implications of these contracts with those
contemplated by the Court in Sierra-Mobile cases,including Agricultural Products,and its
progeny.Idaho Power maintains that the Commission,“may annul,supersede,or reform the
contracts of the public utilities it regulates in the public interest.”Reply at 11 (internal citations
omitted).
DISCUSSION AND FINDINGS
The Commission has jurisdiction over Idaho 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,Idaho Power,and
Wasatch Wind.It is clear from the record that extensive review of PPAs is conducted by both
ORDER NO.32257 8
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 $230 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.
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 [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.”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 “The date
stated in the opening paragraph of this ...Agreement representing the date upon which this
[Agreement]was fully executed by both Parties.”Agreements ¶1.11.The opening paragraph is
dated “this 28 day of December,2010.”Agreements at 1.It is clear that the Projects signed the
Agreements on December 20,and Idaho Power signed on December 28,2010.Id.at 29.Thus,
on the date the two 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
ORDER NO.32257 9
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 Projects also argue that “[w]hen the published rates change.or become otherwise
unavailable to a QF before the QF can obtain a contract,the QF is entitled to grandfathered rates
if it can ‘demonstrate that but for the actions of [the utility,the QF]was otherwise entitled to a
power purchase contract.”Comments at 7.However,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.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)(1-2).Wind and
solar projects larger than 100 kW 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 rate 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 Idaho Power and the two Projects were
executed on December 28,2010.The Agreements recite that each Project will have a maximum
capacity amount of 21 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 published rate contracts.Simply put,the rates contained
in the Agreements do not comply with Order No.32176.Therefore,we disapprove the two Firm
Energy Sales Agreements.
ORDER
IT IS HEREBY ORDERED that the December 28,2010,Firm Energy Sales
Agreements between Idaho Power and Grouse Creek Wind Park and Grouse Creek Wind Park II
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)
ORDER NO.32257 10
days after any person has petitioned for reconsideration,any other person may cross-petition for
reconsideration.See Idaho Code §61-626.
DONE by Order of the Idaho Public Utilities Commission at Boise,Idaho this
day of June 2011.
MACK A.REDFO&D,COMMISSIONER
ATTEST:
&J .
Jdh D.Jewel!i
Commission Secretary
O:IPC-E-10-61 IPC-E-I 0-62ks4
.J
MARSHA H.SMITH,COMMISSIONER
PAUL PRESIDENT
ORDER NO.32257 11