20140225final_order_no_32986.pdf

Office of the Secretary
Service Date
February 25,2014
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR )CASE NO.IPC-E-13-24
COMMISSION ACCEPTANCE OR )
REJECTION OF AN ENERGY SALES )
AGREEMENT WITH BANNOCK COUNTY,)ORDER NO.32986
IDAHO )
On December 5,2013,Idaho Power Company filed an Application requesting
Commission acceptance or rejection of an Energy Sales Agreement between the Company and
Bannock County,Idaho.Under the Agreement,Bannock County would sell electric energy
generated by the Bannock County Solid Waste Department Landfill Gas-to-Energy Project to the
Company.
Bannock County proposes to operate a 3.2 megawatt (MW)landfill gas-to-energy
plant located near Pocatello,Idaho.The County plans to initially install a 1.6 MW generation
unit and may install another 1.6 MW generation unit within 60 months of the operation date of
the Agreement.The generating facility will be a qualifying facility under applicable provisions
of the Public Utility Regulatory Policies Act of 1978 (PURPA).The Agreement provides for a
20-year term using non-levelized “other”published avoided cost rates currently established by
the Commission in Order No,32817 for energy deliveries of less than 10 aMW.The Agreement
was signed by Bannock County on November 5,2013,and was subsequently signed by Idaho
Power on November 13,2013.The scheduled operation date for the project is May 1,2014.
On January 3,2014,Idaho Power filed three replacement pages for the Agreement,
along with a letter signed by the Bannock County Commissioners approving the replacement
pages.The new pages replace Appendix E to the Agreement containing the non-levelized
energy prices initially stated in the Agreement.On January 15,2014,the Commission issued a
Notice of Application and Notice of Modified Procedure to establish a comment period and
complete the process of Idaho Power’s Application.Written comments were filed only by Staff.
STAFF REVIEW
Nearly all of the terms and conditions contained in the Agreement are the same as
those contained in other recent PURPA agreements.Consequently,Staffs comments focus only
on those parts of the Agreement that are new or different from other recently approved PURPA
ORDER NO.32986 1
agreements.Those differences relate to use of the Mid-Columbia non-firm price index,
requirements for posting a security deposit,and calculation of the proper avoided cost rates.
Security Issues
The Bannock County project is proposed to be developed in two phases.The first
phase is planned to consist of a single generation unit with a nameplate capacity of 1.6 MW.The
scheduled operation date for the first phase is May 1,2014.An identical second generation unit
is also contemplated that,if completed,would be added within five years of the operation date of
the first phase.The second 1.6 MW generation unit would be subject to the same rates and
conditions as the first generation unit,but only for whatever term of the Agreement would
remain.For example,if the second unit were added five years into the 20-year contract,it would
only have a 15-year contract term whereas the first unit would have a 20-year contract.
The Agreement provides that a security deposit must be posted in an amount equal to
$45 per kW times the nameplate capacity of the initial generation unit ($45 x 1,600 kW
$72,000).No security deposit would be required for the second 1.6 MW unit should it be added
in the future.Staff reported that Idaho Power explained the reasons for basing the security
deposit amount on the lesser 1.6 MW capacity rather than 3.2 MW:(1)management of two on
line dates,one for each phase of the project,along with an associated security deposit for each,
would be administratively complex,and could result in higher rates associated with the second
phase;(2)by incorporating the second phase into the original contract,it will effectively have
only a 15-year contract,and Idaho Power believes that a shorter contract would be to the
Company’s advantage;and (3)a delay in bringing the second phase of the project on-line might
be in Idaho Power’s favor if it could procure lower cost replacement power elsewhere;thus,no
delay security would be necessary in that instance.Staff Comments,p.4.
Staff noted that if Idaho Power had required a higher security amount based on 3.2
MW rather than 1.6 MW,Bannock County could have negotiated a separate contract for the
project’s second phase,most likely at a higher rate and for a full 20-year term.Staff believes the
Agreement as written represents a compromise between the parties that is fair and reasonable.
Rates
Staff stated that the rates contained in the contract are based on Commission Order
No.32817 dated May 29,2013.Rates from Order No,32817 are the first to be specific to
ORDER NO.32986 2
different resource types and also the first to be dependent on a utility’s summer or winter
capacity deficit position.
Beginning with Order No.32817,rates can also be dependent on the capacity of the
project because of the extent to which the project’s capacity is able to satisfy any resource
deficiencies the utility may have.Thus,rates for Bannock County,at least in the early years of
the contract (i.e.,Idaho Power’s deficiency period),would be different for a nameplate capacity
of 1.6 MW than for a capacity of 3.2 MW.In its computation of rates,Idaho Power assumed a
capacity of 1.6 MW because that would be the capacity during the years when the rates would be
impacted.Staff agreed with Idaho Power that the rates should be based on an assumed capacity
of 1.6 MW rather than 3.2 MW.
Staff reviewed the revised rates and confirms that they are correct and properly
computed in compliance with Order No.32817.Staff recommended approval of the proposed
Agreement between Idaho Power and Bannock County incorporating replacement pages 47,48,
and 49 submitted on January 3,2014.Staff further recommended that all payments made for
purchases of energy under the Agreement be allowed as prudently incurred expenses for
ratemaking purposes.
References to Mid-C Indcx Price
The Agreement contains several references to use of a Mid-Columbia Market Energy
Price for purposes of pricing surplus energy and for calculating delay damages (See Delay Price,
¶1.8;Market Energy Reference Price,¶1.22;Mid-Columbia Market Energy Cost definition,¶
1.26).The Mid-Columbia Market Energy Cost,by definition in the Agreement,is based on “the
volume weighted average of the daily on-peak and off-peak Platts Mid-Columbia Index activity
for actual non-firm energy transactions as reported by Platts.”
Staff noted that earlier PURPA contracts used a Mid-C index for similar pricing,but
specified Dow-Jones rather than Platts as the source for the index.Earlier contracts also stated
only that the prices should be the “weighted average of the daily on-peak and off-peak activity
for non-firm transaction,”not the “volume weighted average.”Dow-Jones has recently turned
Surplus energy is energy produced and delivered that is more than 110%or less than 90%of the forecasted energy
delivered for the month.Because surplus energy is not planned,it is priced differently than planned net energy.
Delay damages can occur if a facility fails to meet its scheduled operation date and Idaho Power must acquire higher
priced replacement energy from another source.
ORDER NO.32986 3
over publishing of the Mid-C index to Platts,a sister company,so Staff stated a switch to some
source other than Dow-Jones was necessary for this Agreement.
For purposes of this Agreement,Staff stated its conditional support of the Platts Mid-
C index,nor does Staff oppose the practice of volume weighting on-peak and off-peak pricing.
However,two cases currently before the Commission involve questions about whether Platts is
an appropriate index for pricing non-firm energy and whether the index prices should be volume
weighted.Staff stated it intends to examine the Platts Mid-C index as well as several other
candidate indices.Staff also intends to weigh in on whether volume weighting was
contemplated in some existing contracts and whether it should be applied to new contracts going
forward.Because comments in both cases will not be filed until after this case is resolved,Staff
stated its recommendations in this case are not indicative of positions it may take in Case Nos.
IPC-E-13-25 and IPC-E-13-19,nor are they an endorsement of the Platts index or the practice of
volume weighting.
FINDINGS 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
replacement pages,and the comments and recommendations of Commission Staff.We find that
the Bannock County project is qualified to receive the non-levelized published avoided cost rates
contained in the Agreement.We further find that the proposed Agreement contains acceptable
contract provisions consistent with PURPA,FERC regulations and this Commission’s prior
Orders.We find it reasonable to allow payments made under the Agreement as prudently
incurred expenses for ratemaking purposes.By approving the Agreement in this case,the
Commission is NOT stating its approval of the Platt index or volume weighting issue in Case
Nos.IPC-E-13-25 and IPC-E-13-19.Those issues are pending Commission review,and the
ORDER NO.32986 4
Commission’s approval of the Agreement in this case is in no way an indication of what the
Commission will decide in Case Nos.IPC-E-13-25 or Case No.IPC-E-13-19.
ORDER
IT IS HEREBY ORDERED that the Commission approves the Energy Sales
Agreement between Idaho Power and Bannock County with the adjusted rates filed January 3,
2014.
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 2014.
ATTEST:
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MACK A.REDORD,:COMMISSIONER
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PAUL KJELLANDER,PRESIDENT
____
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MARSHA H.SMITH,COMMISSIONER
ORDER NO.32986 5