20120217final_order_no_32462.pdf

Office of the Secretary
Service Date
February 17,2012
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR A )CASE NO.IPC-E-11-26
DETERMINATION REGARDING ITS )
FIRM ENERGY SALES AGREEMENT )
WITH HIGH MESA ENERGY,LLC.)ORDER NO.32462
______________________________________________________________________________
)
On November 22,2011,Idaho Power Company filed an Application with the
Commission requesting acceptance or rejection of a 20-year Firm Energy Sales Agreement
(Agreement)between Idaho Power and High Mesa Energy,LLC (High Mesa)dated November
16,2011.The Application states that High Mesa would sell and Idaho Power would purchase
electric energy generated by the High Mesa wind project (Facility)located near Bliss,Idaho.
Idaho Power requested that its Application be processed by Modified Procedure.
On December 16,2011,the Commission issued a Notice of Application/Notice of
Modified Procedure and established comment deadlines.Order No.32414.Staff was the only
person or party to file comments.High Mesa filed reply comments.By this Order,the
Commission approves the Agreement between Idaho Power and High Mesa for the sale and
purchase of electric energy.
THE AGREEMENT
The Application states that High Mesa proposes to own,operate and maintain a 40
MW (maximum capacity,nameplate)generating facility.Application at 2.The Facility will be
a QF under the applicable provisions of the Public Utility Regulatory Policies Act of 1978
(PURPA).The Agreement is for a term of 20 years and contains avoided cost rates calculated
through the use of the Integrated Resource Plan (IRP)methodology.Idaho Power notes that the
energy price identified by the IRP methodology for this Facility is equivalent to a 20-year
levelized price of $56.43 per MWh.1 Application at 4.The Agreement includes “split
ownership”of the Renewable Energy Certificates (RECs)generated over the 20-year term of the
Agreement.Id.at 3.
l The actual energy pricing stream varies throughout the term of the contract based upon the time of year and time of
day during which the energy is delivered to Idaho Power.
ORDER NO.32462 1
High Mesa selected November 1,2012,as its Scheduled First Energy Date and
December 28,2012,as its Scheduled Operation Date.Id.at 2.Idaho Power asserts that various
requirements have been placed upon the 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.
The Application maintains that all applicable interconnection charges and monthly
operation or maintenance charges under Schedule 72 will be assessed to High Mesa.Idaho
Power states that the Facility is currently in the generator interconnection process.“Upon
resolution of any and all upgrades required to acquire transmission capacity for this Facility’s
generation,and upon execution of the FESA and the GIA,this Facility may then be designated as
a network resource.”Id.at 5.High Mesa and Idaho Power have agreed to liquidated damage
and security provisions.Agreement ¶J 5.3,5.8.1.
Idaho Power states that the Facility has also been made aware of and accepted the
provisions in the 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 Application notes 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.”Application at 6.
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 High Mesa Energy for purchases of energy will be allowed as prudently incurred
expenses for ratemaking purposes.Agreement ¶21.1.
COMMENTS
Staff Comments
Staff notes 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.The IRP methodology has only been
employed three times since its inception.Staff maintains that there are numerous assumptions
ORDER NO.32462 2
and decisions that must be made in order to use the IRP methodology,many of which are unique
to particular generation technologies.In this Agreement,an assortment of methods has been
used to determine the rates.In particular,energy rates have been computed using an IRP
methodology,and a capacity component to the rates has been computed using a new
methodology not yet thoroughly scrutinized.In addition,some terms and conditions in the
Agreement have been determined purely through negotiation between the parties.
The Agreement contains non-levelized avoided cost rates that escalate annually from
2012 through the end of the contract term in 2032.The rates are specified by month for both
heavy and light load hours.Idaho Power notes that the energy price identified by the IRP
methodology for this Facility is equivalent to a 20-year levelized price of $56.43 per MWh.
Application at 4.By comparison,the 20-year levelized published avoided cost rate is $68.51.
Idaho Power’s analysis indicates that a total of approximately $105 million will be paid to High
Mesa over the 20-year term of the Agreement.The net present value of the payments is
estimated to be approximately $45 million.
Although the rates in the Agreement were computed using the IRP methodology,
there are many assumptions and computational details that have yet to be standardized.In the
current case,Idaho Power has made assumptions and employed computational methods it
believes are reasonable and within the bounds of the IRP methodology.However,Staff states
that,for some elements,it would have made different assumptions and calculations.
As a basis for determining the capacity value of generation from the High Mesa
project,Idaho Power used the capacity cost of a combined-cycle combustion turbine (CCCT).
The Company considered the probability of the wind Facility to provide generation during the
3:00 p.m.to 7:00 p.m.peak load period during July,and in turn,valued this capacity based on
the capacity costs of a CCCT from the Company’s 2009 IRP.The annual capacity factor for the
High Mesa facility is estimated to be 26%.To investigate whether an SCCT or a CCCT would
be a more appropriate basis for calculating capacity value,Staff compared the capacity factors
for SCCT and CCCT units included in the Company’s 20-year resource plan in its 2009 IRP.
Based on modeling results from the IRP,the capacity factors for Idaho Power’s existing SCCT
units and the future SCCT units in the preferred resource portfolio ranged from 0 to 14%,and
averaged about 9%for all peaking units.By contrast,the Langley Gulch CCCT,the only CCCT
in Idaho Power’s portfolio,shows an annual capacity factor ranging from 36 to 49%,with a 20-
ORDER NO.32462 3
year average of 49%.If an SCCT instead of a CCCT were used as the basis for calculating
capacity value for the Facility,the calculated levelized price would drop from $56.43 to $53.47
per MWh.
Idaho Power examined generation estimates for the project during the period from
3:00 p.m.to 7:00 p.m.in July when the utility’s annual hourly peak load typically occurs.Idaho
Power then chose a capacity value that would be exceeded 90%of the time.Idaho Power
reasoned that the 90%exceedance value was appropriate because it was consistent with
assumptions made for other resources in its IRP.While a 90%capacity factor may be reasonable
for planning purposes,it could be argued that a 100%exceedance value should be used for a rate
determination in order for the capacity of a wind facility to be equivalent to a unit of capacity
from a SCCT or a CCCT.If a 100%exceedance criterion were used instead of a 90%value,the
capacity value of the wind facility would necessarily decrease from the value computed by Idaho
Power.
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 that AURORA prices reflect only the value of energy is a
conservative one in favor of High Mesa.Staff believes that there is,in fact,some capacity value
contained in AURORA prices.
Staff noted that 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.However,Idaho Power
does not show a capacity deficit in its 2009 IRP until 2013 (the 2011 IRP does not show a
capacity deficit until the year 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 otherwise.Staff believes that some method
needs to be devised and deployed to recognize need for new capacity in the computation of
contract prices.
ORDER NO.32462 4
The analysis done by Idaho Power to derive the prices contained in the Agreement
was based on data and assumptions from the Company’s 2009 IRP.Although Idaho Power’s use
of the 2009 IRP for computing avoided cost rates was appropriate because it was the most
recently acknowledged IRP at the time the analysis was done,the data and assumptions in the
2011 IRP are undeniably more current and would produce different results.If this Agreement is
rejected and must eventually be renegotiated,Staff recommended that the 2011 IRP be used as a
basis for the analysis.
In its analysis to compute the rates included in the Agreement,Idaho Power used a
weighted cost of capital of 7%.This is the same weighted cost of capital that the Company used
in preparing its 2009 IRP.Staff believes that a more appropriate weighted cost of capital is
7.86%,the weighted cost of capital from Idaho Power’s last general rate case (IPC-E-11-08).If
a weighted cost of capital of 7.86%is used instead of 7%,the avoided cost rates computed by
Idaho Power would be lowered slightly.
For the last two years of the Agreement,Idaho Power estimated the avoided cost
rates rather than computing them.Idaho Power’s AURORA simulations from the 2009 IRP only
extended through 2029,consequently,rates beyond 2029 could not be based exactly on
AURORA.To derive rates beyond 2029,Idaho Power simply extrapolated the rates from the
prior year using a 3%escalation rate.Staff maintains that a more appropriate approach would be
to extend the years over which the AURORA modeling is conducted in order to capture energy
prices over the full term of the Agreement.
Pursuant to PURPA and FERC regulations,avoided costs paid to QFs are not to
exceed the incremental cost that the utility would incur if it generated the energy/capacity itself
or purchased from another source.Staff does not believe that the rates contained in this
Agreement are an accurate reflection of Idaho Power’s avoided costs.The overall impact of all
of the changes proposed by Staff would be a decrease in avoided cost rates of approximately $3
per MWh.This is equivalent to slightly more than a 5%decrease.Consequently,Staff
recommended that the Commission not approve the Agreement.
High Mesa Reply Comments
High Mesa states that the Agreement between it and Idaho Power was arrived at
through arms-length bargaining and based on Idaho Power’s past practices and current
understanding of Commission directives.Reply at 1.High Mesa argues that Staffs reasons for
ORDER NO.32462 5
opposing approval of the Agreement are not based on “the Commission’s long-standing practice
for calculation of avoided cost rates for PURPA projects.”Id.at 2.High Mesa requests that the
Commission “consider this Agreement from the same vantage point as Rockland and
Interconnect Solar.”Id.at 5.High Mesa insists that this Agreement is feasible for the project
and favorable to Idaho Power’s customers and should,therefore,be approved.
DISCUSSION AND FINDINGS
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
Agreement,the comments of Commission Staff,and reply of High Mesa.Based on the record,
we find that the proposed Agreement submitted in this case contains acceptable contract
provisions including the non-levelized avoided cost rates calculated through the use of the IRP
methodology.We appreciate Staffs diligence in performing an independent review of each
power purchase agreement as it is filed for approval with this Commission.We expect to see the
IRP methodology issues addressed by Staff argued more fully,and to conclusion,in the generic
PURPA docket currently before the Commission.See GNR-E-l 1-03.Finally,we find it
reasonable to allow payments made under the Agreement as prudently incurred expenses for
ratemaking purposes.
ORDER
IT IS HEREBY ORDERED that the November 16,2011,Firm Energy Sales
Agreement between Idaho Power and High Mesa is approved without change or condition.
THIS IS A FfNAL 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.32462 6
DONE by Order of the Idaho Public Utilities Commission at Boise,Idaho this /7’
day of February 2012.
PAUL K LA PRESIDENT
MACK A.REDFORD,COMMISSIONER
SHA H.SMITH,COMMISSIONER
ATTEST:
/1 ,/1/‘r(i
J’an D.Jewel!;
Cmmission Secretary
O:IPC-E-1 1-26ks2
ORDER NO.32462 7