20111020final_order_no_32384.pdf

Office of the Secretary
Service Date
October 20,201 1
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR A )CASE NO.IPC-E-11-.iO
DETERMINATION REGARDING THE FIRM )
ENERGY SALES AGREEMENT WITH )
INTERCONNECT SOLAR DEVELOPMENT )ORDER NO.32384
LLC FOR THE SALE AND PURCHASE OF )
ELECTRIC ENERGY )
On June 17.201 1,Idaho Power Company filed an Application with the Commission
requesting acceptance or rejection of a 25-year Firm Energy Sales Agreement (Agreement)
between Idaho Power and Interconnect Solar Development LLC (Interconnect Solar:Project).
Interconnect Solar would sell and Idaho Power would purchase electric energy generated by the
Murphy Flats Solar Power Project located near Murphy,Idaho.On July 8,2011,the
Commission issued a Notice of ApplicationlNotice of Modified Procedure and established
comment deadlines.1 Order No.32290.
Following the submission of comments by the parties and the public,the case was
fully submitted for the Commission’s consideration.On September 20,201 1,the Commission
issued Order No.32361.The Commission noted that all parties had acknowledged a
computational error that was made in the escalation rate that was applied to the CCCT capital
cost component from the 2009 IRP that was carried through and used in the IRP pricing model
for the Interconnect Solar project.The Commission stated that we would not be fulfilling our
role of ensuring just and reasonable rates if we approved an Agreement that contained a known
computational error.Idaho Code §61-301,6 1-502.In an effort to permit the parties an
opportunity to correct the mathematical error without creating undue delay,the Commission
allowed Idaho Power and Interconnect Solar until September 27,2011,to resubmit their Firm
Energy Sales Agreement with accurate calculations prior to the Commission making a final
determination regarding the Agreement.Order No.32361.
On September 23,2011,Interconnect Solar filed a Motion for Extension of Time.
Interconnect Solar requested that the Commission allow the parties until September 29,2011,to
Comment deadlines were modified twice with comments ultimately being due no later than September 9,2011,and reply comments due no later than September 16,2011.Order Nos.32308 and 32347.
ORDER NO.32384 1
resubmit their Agreement.The Project’s Motion was considered at the Commission’s decision
meeting held on September 26,2011.During the meeting,Interconnect Solar and Idaho Power
notified the Commission that,due to the nature of the changes,it would be impossible to
complete and submit a corrected and signed Agreement by the originally requested extension
date.Interconnect Solar asked that the Commission allow the Project and Idaho Power until
October 13,2011,to resubmit a Firm Energy Sales Agreement with correct computations.The
Commission granted the Project’s request for an extension.Order No.32364.
On October 11,2011,pursuant to Commission Order Nos.32361 and 32364,Idaho
Power resubmitted the parties’Firm Energy Sales Agreement.The record is now complete.By
this Order,the Commission approves the replacement Agreement signed by Idaho Power and
Interconnect Solar on October 4,2011,for the sale and purchase of electric energy.
THE APPLICATION
The Application states that Interconnect Solar proposes to construct,own,operate and
maintain a 20 MW (maximum capacity,nameplate)photovoltaic solar generating facility.
Application at 2.The Facility will be a QF under the applicable provisions of PURPA.
A.The Agreement
The Agreement is for a term of 25 years and contains avoided cost rates established
pursuant to the Commission’s approved Integrated Resource Plan (IRP)avoided cost
methodology as currently required by the Commission for solar QFs with a design capacity of
more than 100 kilowatts (kW).Order No.32262.Idaho Power asserts that the 25-year contract
term was the result of negotiations that attempted to balance the parties’interests in a manner
that was favorable to Idaho Power customers and to Interconnect Solar.Id.at 3.
Interconnect Solar selected June 1,2012,as its Scheduled First Energy Date and July
1,2012,as its Scheduled Operation Date.Id.at 3.Idaho Power asserts that various
requirements have been placed upon the Interconnect Solar Facility in order for Idaho Power to
accept the Facility’s energy deliveries.Idaho Power states that it will monitor the Facility’s
compliance with initial and ongoing requirements through the term of the Agreement.
Interconnect Solar and Idaho Power agreed to liquidated damage and security
provisions of $45 per kW of nameplate capacity.Agreement ¶J 5.3.2,5.8.1.Delay Liquidated
Damages shall apply if Interconnect Solar fails to bring the Facility on-line by the Scheduled
Operation Date.
ORDER NO.32384 2
Interconnect Solar is responsible to complete a Generation Interconnection
Agreement (GIA)and is responsible for all costs associated with interconnection of the Facility
to Idaho Power’s system and any necessary transmission upgrades for its generation to serve
load.Idaho Power states that,at the time this Application was filed,the GIA has not yet been
signed and the required payment for interconnection and transmission upgrades has not been
paid.Idaho Power estimates that,after payment is made,18 months is required for Idaho Power
to complete the interconnection and transmission facilities.
Idaho Power maintains that Interconnect Solar has been expressly advised in writing
that the Scheduled Operation Date it selected was prior to such time that the
interconnectionltransmission facilities are scheduled to be constructed and completed.
Application at 8.Idaho Power states that Interconnect Solar has acknowledged and expressly
agreed to accept all risk associated with not meeting the Scheduled Operation Date,including
forfeiture of the Delay Security,and potential termination of the Agreement.Id.
The parties have agreed to terms providing for each party’s 50 percent ownership of
any environmental attributes,including RECs,generated by the Facility for the full 25-year term
of the Agreement.
Energy prices in this Agreement are derived from Idaho Power’s AURORA
economic dispatch model for this Facility’s estimated energy shape as specified by Commission
requirements for the IRP-based avoided cost methodology.Id.at 5.The energy prices contain
the previously approved differentiation between Heavy Load and Light Load pricing,as well as
different seasonal prices.Id.This Agreement adds Heavy Load Peak pricing to the months of
July and August.The energy price identified by the IRP methodology for this Facility is
equivalent to a 20-year levelized price of $105.15 per MWh.Id.However,Idaho Power states
that the actual energy pricing stream varies throughout the term of the contract based upon the
month and time of day during which the energy is delivered to Idaho Power.Id.
By its own terms,the Agreement will not become effective until the Commission has
approved all of the Agreement’s terms and conditions and declares that all payments made by
Idaho Power to Interconnect Solar for purchases of energy will be allowed as prudently incurred
expenses for ratemaking purposes.Agreement ¶21.1.
ORDER NO.32384 3
COMMENTS
StaffComments
Staff noted that the IRP methodology has only been employed twice since its
inception—once by Avista to develop rates for Potlatch’s PURPA facility (now Clearwater
Paper),and once by Idaho Power to develop rates for the Rockland wind project.Staff stated
that this case is the first to derive IRP-based rates for a solar project.Staff further observed that
the Agreement presented for Commission approval contains rates,terms and conditions that
differ considerably from those in recent power sales agreements wherein rates were based on
published avoided cost rates.In this Agreement,an assortment of methods have been used to
determine the rates.In particular,energy rates have been computed using an IRP methodology;
a capacity component to the rates has been computed using an entirely new methodology;and
seasonal and heavy/light load hour adjustments have been made using the same adjustment
mechanisms approved for published avoided cost rates.Other terms and conditions in the
Agreement have been determined purely through negotiation between the parties.
As a threshold matter,in preparing responses to Staffs production requests in this
case.Idaho Power identified errors in its computations to determine the capacity component of
the rates.The current levelized price within the Agreement calculates to be $105.15 ($43.44
capacity cost component and $61.71 energy cost component).Upon review of its calculations,
Idaho Power discovered that an inappropriate escalation rate had been applied to the 2009 IRP
combined-cycle combustion turbine (CCCT)capital cost used in this PURPA IRP pricing model.
Correction of the CCCT capital cost component results in a calculated levelized price of $94.59
($32.88 capacity cost component and $61.71 energy cost component).Staff reviewed the
Company’s initial calculations and its revised calculations.Staff agreed that the revised
calculations are correct.
As a basis for determining the capacity value of generation from the Interconnect
Solar Facility,Idaho Power used the capacity cost of a CCCT.2 Idaho Power states that it based
the value of capacity on a CCCT in order to maintain consistency with the published avoided
cost methodology and also to be consistent with previous IRP-based PURPA price calculations.
Staff believes that the generation shape of this project is distinctly different from other PURPA
2 The Company considered the probability of the solar Facility to provide generation during the 3:00 p.m.to 7:00p.m.peak load period during July,and in turn,valued this capacity based on the capacity costs of a CCCT from theCompany’s 2009 IRP.
ORDER NO.32384 4
resources and it is possible that a simple-cycle combustion turbine (SCCT)more closely
resembles the operating characteristics of a solar resource and may be a more appropriate basis
for the avoided cost of capacity.Idaho Power’s existing and future SCCT units would typically
be dispatched in peak summer and winter hours,somewhat similar to the hours when a solar
facility’s generation would be greatest.Staff maintains that solar generation could,at least in
theory,frequently displace generation from SCCT units.
The annual capacity factor for the Interconnect Solar Facility is estimated to be 21
percent based on data collected by Idaho Power for its rooftop solar facility,roughly half the
capacity factor for a typical CCCT but nearly double the capacity factor for a typical SCCT.
Although there is a high likelihood that Interconnect Solar can provide at least some capacity
during Idaho Power’s peak load hours,the Facility cannot guarantee that it can provide capacity
when needed with 100 percent certainty due to cloud cover and darkness.Moreover,unlike a
CCCT or a SCCT,a solar facility is not dispatchable.Because capacity provided by a solar
facility cannot be guaranteed while capacity from either a CCCT or an SCCT can be provided
with nearly 100 percent certainty,Staff believes that whatever capacity a solar facility can
provide is not equivalent to the same unit of capacity from a dispatchable CCCT or SCCT.
To calculate the value of the energy component of the prices in the Agreement,Idaho
Power modeled expected generation from the Facility using the AURORA electric price
forecasting model.The Company assumed that the prices generated by the model reflected the
costs of energy only,and that no capacity value was reflected in the prices.Staff believes that
Idaho Power’s assumption is a conservative one in favor of Interconnect Solar.Staff believes
that there is,in fact,some capacity value contained in AURORA prices.However,Staff is
uncertain of how to quantify the amount.
The method used by Idaho Power to calculate the capacity component of the prices in
the Agreement fails to recognize whether and when Idaho Power actually has a need for new
capacity.Under Idaho Power’s approach,capacity value is added to the prices from the
beginning of the Agreement’s term through its entire duration.The fact is,however,that Idaho
Power does not show a capacity deficit in its 2011 IRP filing until 2015.By adopting a pricing
schedule that includes payment of a capacity component several years prior to Idaho Power’s
identified need for new capacity,prices in the Agreement are higher than they would be
ORDER NO.32384 5
otherwise.Staff believes that some method needs to be devised and deployed to recognize need
for new capacity (or lack of it in this case)in the computation of contract prices.
Annual energy prices in the Agreement are derived using the AURORA economic
dispatch model for the Facility’s estimated energy shape.The energy prices contain the same
differentiation between heavy load and light load pricing,as well as different seasonal prices as
is currently used for published avoided cost rates.In addition,this Agreement introduces heavy
load peak pricing to hours between 3:00 p.m.and 7:00 p.m.in the months of July and August.
Under this pricing mechanism a premium of five percent is added to heavy load peak prices and
prices in heavy load standard hours are decreased by two percent.Staff agrees conceptually to
increasing prices in heavy load peak hours,but sees no direct evidence to specifically support a
five percent premium in heavy load peak hours and a two percent decrease in heavy load
standard hours.The energy price components derived using AURORA would have recognized
the higher and lower energy values throughout the day and throughout the seasons of the year.
Staff suggests that the price shapes calculated by AURORA be used as the basis for hourly and
seasonal price adjustments,rather than hourly and seasonal adjustment factors used for published
avoided cost rates.
Solar,similar to wind,is an intermittent generation resource.Numerous studies have
confirmed and quantified wind integration costs,but very few solar integration cost studies have
been done.Staff believes that solar integration costs are material,and may be comparable to
wind integration costs.Idaho Power reports that it appears to be widely assumed and accepted
that there is some level of integration cost associated with all intermittent resources such as wind
and solar generation.Staff noted that no integration costs have been incorporated into the
Agreement.
Interconnect Solar must complete a Generation Interconnection Agreement (GIA)and
is responsible for all costs associated with interconnection of the Facility to Idaho Power’s
system and any necessary transmission upgrades for its generation to serve load.Idaho Power
maintains that Interconnect Solar has been expressly advised in writing that the Scheduled
Operation Date it selected was prior to such time that the interconnectionltransmission facilities
are scheduled to be constructed and completed.Application at 8.Idaho Power states that
Interconnect Solar has acknowledged and expressly agreed to accept all risk associated with not
meeting the Scheduled Operation Date,including forfeiture of the Delay Security,and potential
ORDER NO.32384 6
termination of the Agreement.Id.Staff expressed concern that the Facility’s Scheduled
Operation Date is prior to the date on which Idaho Power is obligated to complete construction
of the necessary transmission and interconnection facilities.
Ultimately,Staff recommended that the Commission not approve the Agreement.
Staff acknowledged the Commission’s support,and recent reinforcement of,rates derived by the
IRP methodology and negotiations between the parties.However,Staff does not believe that the
rates contained in the Agreement are an accurate reflection of Idaho Power’s avoided costs.
Idaho Power Reply Comments
Idaho Power noted Staff’s rigorous review of the Agreement between Idaho Power
and Interconnect Solar.Idaho Power emphasized that,in calculating and negotiating the rates in
the Agreement,the Company “attempted to apply the methodology in such a way as to be
consistent with both past Commission orders establishing the methodology as well as the
Company’s past practices and assumptions that it has utilized for other QF projects’IRP rate
determinations.”Reply at 3.
Idaho Power recommended that,at a minimum,the rates in the Agreement be revised
to correct the acknowledged computational error.Idaho Power also agreed,on reply,with
Staffs recommendation that the price shapes calculated by AURORA be used as the basis for
hourly and seasonal price adjustments,rather than the hourly and seasonal adjustment factors
used for published avoided cost rate contracts that were applied to this Agreement.Idaho Power
noted that using the price shapes calculated by AURORA would result in a much more accurate
and appropriate seasonal and hourly variation that is unique to this particular project’s energy
output.
Idaho Power agreed with several other recommendations made by Staff,but felt
“constrained to apply the existing methodology in its good faith contract negotiations with this
QF,even if it believed a different methodology was more appropriate,unless and until it is
relieved of that obligation by the Commission.”Reply at 6.
Interconnect Solar Reply Comments
Interconnect Solar strongly opposed Staffs recommendations.Interconnect Solar
classified Staffs recommendations as fundamental changes to significant policy,methodology
and input factors.Generally,the Project argues that Staffs concerns are better addressed as part
ORDER NO.32384 7
of the generic PURPA case currently proceeding before the Commission.Case No.GNR-E-1l-
03.
The Project maintains that shifting to the use of a SCCT for avoided capital cost
differentials “would be completely inconsistent with longstanding Commission requirements for
the calculation of QF avoided cost rates for all PL’RPA projects.as applied for almost two
decades.”Reply at 5 (emphasis in original).Interconnect Solar also disputes Staffs suggestion
that AURORA energy prices include some value for capacity.The Project further disagrees with
Staffs recommendation that no capacity payments be made under the Agreement until Idaho
Power shows a need for new capacity.Interconnect Solar maintains that capacity payments,
even prior to a utility’s need for such capacity,is well-established with this Commission.
Interconnect Solar maintains that Staffs recommendation to assess a solar integration
charge is arbitrary and unsupported by evidence.The Project states that “[d]evelopment of a
solar integration charge deserves the openness of multi-party participation and the many different
expert opinions that will likely emerge....“Reply at 10.
Interconnect Solar chose a Scheduled Operation Date that is prior to Idaho Power’s
estimated date for completion of the Project’s interconnection.Idaho Power required the Project
to acknowledge in a separate letter the financial risk associated with this apparent discrepancy.
Interconnect Solar maintains that “it is likely that the BLM permitting process will be concluded
within a six month time frame,not the 12 months projected by Idaho Power.”Reply at 13.The
Project argues that,“if Interconnect Solar is wrong on this point,the [liquidated damages]more
than adequately compensate Idaho Power and its ratepayers for this mistake.”The Project
explains that,in this way,the ratepayers are fully protected from the risk.
Despite an acknowledged computational error,Interconnect Solar argues that other
considerations such as ownership of renewable energy credits and capacity modeling based on
Idaho Power’s “aging rooftop solar panels”should be recognized as adequate offsets for the
mathematical error.Interconnect Solar urges the Commission to approve the Agreement as
originally submitted.
REVISED AGREEMENT
On September 20,2011,the Commission issued its decision to allow the parties an
opportunity to correct a mathematical error in their Agreement prior to the Commission
deliberating because,as we stated,this Commission cannot approve an agreement with a known
ORDER NO.32384 8
computational error.Order No.32361.On October 11,2011.pursuant to Commission Order
Nos.32361 and 32364,Idaho Power resubmitted the parties’Firm Energy Sales Agreement.In
addition to correcting the mathematical error identified by the Commission,Idaho Power and
Interconnect Solar recalculated pricing based upon (1)an adjustment for daylight savings time
and (2)use of a new energy shape based on utilization of different solar panels by the Project.
The parties also moved out the First Energy Date and the Scheduled Operation Date for the
Project by two months.
Idaho Power states that,upon Interconnect Solar’s review of the Agreement’s
calculations,the Project asserted that it had made an error in the energy shape that it provided to
Idaho Power that serves as the basis for the energy pricing in the PURPA IRP avoided cost
pricing model.The new energy shape contained different output levels during peak load hours
based upon a correction for daylight savings time.“The new energy shape also contained an
increase in total energy delivered based upon the proposed use of different solar panels than
those that were originally planned by Interconnect Solar.”Resubmittal at 2.The result of all
these adjustments is a levelized price of $97.47 per MWh.
DISCUSSION AND CONCLUSIONS
The Idaho Public Utilities 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 costs,to order electric utilities to enter
into fixed-term obligations for the purchase of energy from qualified facilities (QFs)and to
implement FERC rules.
The Commission has reviewed the record in this case,including the Application,the
June 7 and October 4,2011,Agreements,the explanation of revisions,and the comments of the
parties.We initially note that Idaho Power and Interconnect Solar went beyond the scope of the
Commission’s Order allowing the parties to correct a mathematical error in regard to the CCCT
capital cost component of the IRP pricing model.While a correction for daylight savings time
might reasonably be construed as an additional computational error,a change in the acreage,
number of panels,panel wattage and,ultimately,nameplate rating cannot.As a general matter,
the Commission does not take issue with the configuration of a QF project.However,
ORDER NO.32384 9
Interconnect Solar’s configuration changed only after a calculation error caused a downward
adjustment in the levelized price for the Project.
We share the concerns of Commission Staff and Idaho Power regarding Interconnect
Solar’s choice of a Scheduled Operation Date that precedes Idaho Power’s estimated date for
completion of the Project’s interconnection.The Project’s optimism may prove to be foolhardy.
Interconnect Solar maintains its position that interconnection will occur ahead of Idaho Power’s
estimated schedule at its own peril.
We recognize that this is the first solar project to utilize IRP-based rates.We
appreciate Staffs thorough analysis of factors in consideration of an accurate IRP-based avoided
cost for a solar project.These are reasonable factors that the utilities should be considering
while negotiating future power purchase agreements until such time as the Commission
establishes firm guidelines for IRP-based rates.It is this Commission’s intent,and consistent
with PURPA and FERC regulations,that a utility negotiate these agreements with an awareness
of its actual avoided cost.
Ultimately,Idaho Power negotiated an Agreement with Interconnect Solar based on
its past practices and current understanding of this Commission’s directives.As such,and
despite the last minute change in the Project’s configuration,we find that the October 4,2011,
Agreement contains acceptable contract provisions and is consistent with the Commission’s
directives that the terms of an IRP-based avoided cost rate contract be negotiated between the
parties.We further find it reasonable to allow payments made under the Agreement as prudently
incurred expenses for ratemaking purposes.
ORDER
IT IS HEREBY ORDERED that the October 4,2011,Firm Energy Sales Agreement
between Idaho Power and Interconnect Solar is approved without change or condition.
THIS IS A FINAL ORDER.Any person interested in this Order may petition for
reconsideration within twenty-one (2 1)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 §61-626.
ORDER NO.32384 10
DONE by Order of the Idaho Public Utilities Commission at Boise,Idaho this
day of October2011.
PAUL K LLANLR,PRESIDENT
MACK A.REDFORD,COMMISSIONER
6k&4L&ii
MARSHA H.SMITH,COMMISSIONER
ATTEST:
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Jh D,Jewell(J
Commission Secretary
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ORDERNO.32384 11