20141029final_order_no_33159.pdf

Office of the Secretary
Service Date
October 29.2014
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR )CASE NO.IPC-E-14-22
CONFIRMATION OF THE CAPACITY )
DEFICIENCY PERIOD FOR )
INCREMENTAL COST,INTEGRATED )ORDER NO.33159
RESOURCE PLAN,AVOIDED COST )
METHODOLOGY.)
Idaho Power Company filed an Application with the Commission on August 13,
2014,requesting that the Commission issue an Order confirming the use of a July 2021 capacity
deficiency period in the approved incremental cost,integrated resource plan,avoided cost
methodology (IRP methodology)applicable to negotiated avoided cost rates for proposed
PURPA qualifying facilities (QFs).
On September 4,2014,the Commission issued a Notice of Application and Notice of
Modified Procedure setting a comment deadline of September 30,2014,and a reply deadline of
October 7,2014.Idaho Conservation League (ICL)and Intermountain Energy Partners LLC
petitioned for,and were granted,intervention.Order Nos.33135 and 33146.On September 29,
2014,ICL filed a motion to extend the comment deadline an additional 60 days.Idaho Power
opposed the motion but offered as an alternative to expedite production responses,extend the
comment deadline to October 6 and allow until October 10 for the Company to file a reply.ICL
accepted Idaho Power’s proposal to modify the schedule.On September 30,2014,the
Commission approved the modified schedule.Order No.33147.
By this Order,and as set out in greater detail below,we confirm July 2021 as Idaho
Power’s capacity deficiency period for purposes of incremental avoided cost calculations within
the IRP methodology.
BACKGROUND
On December 18,2012,the Commission issued Order No.32697 authorizing the use
of Idaho Power’s incremental cost IRP methodology.Solar and wind QF projects that exceed
100 kilowatts (kW)and all other QF generation that exceeds 10 average megawatts (aMW)
negotiate avoided cost rates based on the approved incremental cost,IRP methodology.In its
Order,the Commission stated “We further find it appropriate to identify each utility’s capacity
ORDER NO.33159 1
deficiency based on load and resource balances found in each utility’s IRP.”Order No.32697 at
16.
In calculating a QF’s ability to contribute to a utility’s need for capacity,we
find it reasonable for the utilities to only begin payments for capacity at such
time that the utility becomes capacity deficient.If a utility is capacity surplus,
then capacity is not being avoided by the purchase of QF power.By including
a capacity payment only when the utility becomes capacity deficient,the
utilities are paying rates that are a more accurate reflection of a true avoided
cost for the QF power.
Id.at 21.The Commission discussed the use of inputs from the Company’s integrated resource
planning process in the calculation of avoided cost rates.The Commission directed that ‘when a
utility submits its Integrated Resource Plan to the Commission,a case shall be initiated to
determine the capacity deficiency to be utilized in the SAR [Surrogate Avoided Resourcel
Methodology.”Id.at 23.With regard to the IRP methodology,the Commission stated that
‘utilities must update fuel price forecasts and load forecasts annually —between IRP filings.
all other variables and assumptions utilized within the IRP Methodology remain fixed between
IRP filings (every two years).’Id.at 22.
For purposes of the SAR methodology,the Commission recently determined that
Idaho Power experiences its first capacity deficiency in July 2021.Order No.33084.Although
the Company’s 2013 integrated resource planning process showed a first deficit in July 2016,
Idaho Power presented evidence that it had 400 MW of demand response program customers
enrolled for the 2014 season.The addition of 400 MW of capacity pushed the Company’s deficit
out to July 2021.
THE APPLICATION
Idaho Power states that both the SAR and the IRP methodologies start with a default
capacity deficit which is the same as that established by the most recent integrated resource
planning process.For the 2013 planning process,a first deficit was identified as 2016 in the
Company’s preferred resource portfolio.However,Idaho Power states that because of the
suspension of the Company’s demand response programs in 2013,the first deficit of 2016
legitimately did not consider the approximately 400 MW of demand response.
Because of the unique circumstances of demand response not being considered in the
planning process and therefore also not being considered in the IRP methodology calculation of
ORDER NO.33159
avoided cost rates,Idaho Power has entered into contracts that contain capacity payments for the
entire term of the 20-year agreements.Idaho Power believes the correct avoided cost pricing for
all proposed PURPA projects should take into account the Commission’s finding that Idaho
Power experiences its first capacity deficit in July 2021.The Company maintains that the IRP
methodology is meant to be a more flexible,negotiated process whereby a more accurate
representation of avoided cost can be determined.Therefore,the IRP methodology should
reflect the capacity deficiency that the Commission determined based on the consideration of an
additional 400 MW of capacity —provided through the Company’s demand response program.
Idaho Power states that the Company has just over 529 MW of proposed new solar QF projects
seeking pricing and contracts.The difference in price for all 529 MW of proposed solar when
applying a capacity deficit of July 2021 (includes 400 MW of demand response)instead of July
2016 (Idaho Power’s 2013 integrated resource planning process determination of capacity
deficiency)is approximately $170 million over the life of the projects.
Idaho Power states that because the IRP methodology is meant to be flexible and
because the Company is obligated to ensure that avoided cost rates are an accurate reflection of
the utility’s avoided cost,the Commission should confirm use of a first capacity deficit of July
2021 for purposes of avoided cost prices determined through use of the IRP methodology.
COMMENTS
Commission Staff
Avoided cost rates applied to PURPA contracts consist of two primary components —
an energy component and a capacity component.The energy component usually comprises the
majority of the avoided cost rate,but the capacity component can comprise about 20 to 50
percent of the rate depending on the season of the year and the life stage of the contract.The
significance of a utility’s capacity deficiency period is that it determines whether the avoided
cost rates contain a capacity component.Conceptually,in those years when a utility is surplus,
i.e.,when its supply exceeds its demand,the utility would not be paying for capacity it does not
need.Although the capacity component of avoided cost rates is computed somewhat differently
in the SAR methodology than in the IRP methodology,in principle they are the same.
As summarized by Idaho Power in its Application,in Case No.IPC-E-13-21 relating
to the SAR methodology,Idaho Power asked the Commission to approve a capacity deficit
period with a first deficit occurring in July 2021,which resulted from the inclusion of 440 MW
ORDER NO.33159 3
of demand response.The Company’s request was initially denied,primarily for lack of
evidence.Upon reconsideration,and based on additional evidence submitted by Idaho Power.
the Commission on July 30,2014,ordered Idaho Power to utilize July 2021 as its first capacity
deficit to be used in the Company’s SAR methodology.Order No.33084.Because the
Commission agreed to recognize 400 MW of demand response as a resource for purposes of the
SAR methodology.Idaho Power believes it would be reasonable to also recognize the same
demand response for purposes of the IRP methodology.
Staff believes it would not be reasonable to ignore 400 MW of demand response
resources in calculating avoided cost rates under the IRP methodology,while including those
same resources in determining rates under the SAR methodology.Staff believes that the public
interest requires that avoided cost rates be as accurate as possible,especially given that the
difference to ratepayers could be as much as $170 million over the next 20 years as suggested by
Idaho Power.
It is important to note that this case is an anomaly.Normally demand response would
be considered in Idaho Power’s IRP process and naturally reflected in the IRP methodology.
Unfortunately,because the Company’s DR programs were suspended and the future use of DR
in meeting customer’s capacity needs was unclear,demand response was not considered as part
of the Company’s resource stack.However,because DR is now known and measureable.it is
reasonable to include it as part of the Company’s resources available to meet customers’capacity
needs.Therefore,StafT recommended the Commission approve Idaho Power’s request to use a
first capacity deficit of July 2021 for purposes of avoided cost prices determined by the
incremental cost IRP methodology.
Idaho Conservation League
The Idaho Conservation League (JCL)argues that “[t]he simplest resolution for the
Commission is to follow Order No.32697 and defer any update to resource assumptions to the
IRP process.”Comments at 2.ICL maintains that the IRP methodology does not require an
extrinsic determination of a utility’s resource deficiency date.Logically,if a QF is delivering
energy instead of a Company resource,then the QF is providing capacity in that hour and should
be compensated for providing that service.”Comments at 5.ICL goes on to assert that ‘[b]y
ensuring capacity payments are tied to a QF’s ability to deliver energy at or below avoided costs,
ORDERNO.33159 4
the IRP Methodology inherently balances the demands of PURPA with protecting Idaho
ratepayers.”Comments at 5-6.
ICL states that future demand response participation is an assumption,not a long-
term,contractual commitment.As such,changes to demand response should not be updated
outside of the IRP cycle.Although ICL recognizes that Idaho Power’s 2015 IRP is currently
being developed and will likely result in a revised capacity position,the organization asserts that
“Idaho Power asks the Commission to confirm that current DR programs will continue at current
sizes until at least 2021 .“Comments at 3.
Alternatively.ICL recommended the Commission utilize the existing IRP
methodology update scheduled for October 15,2014.ICL encourages the Commission to
consolidate the two dockets.However,ICL believes consolidation of the cases would likely lead
to a complex,time-consuming review.Ultimately,the organization asserts that ‘[w]hatever the
Commission decides here will have no direct impact on customers in terms of either increasing
or deceasing [sic]utility rates.”Comments at 2.
Iiiterrnountain Energy Parttiers
Intermountain Energy Partners (Intermountain,IEP)urges the Commission to reject
Idaho Power’s proposal to utilize 2021 as its first capacity deficit year when calculating avoided
cost rates under the IRP methodology.Intermountain states that,because Idaho Power’s demand
response programs are single year commitments,they have no bearing on the Company’s long-
term sufficiency needs.TEP maintains that “the sufficiency effect of the DR contracts should be
limited to the period over which those contracts are in effect.Counting them toward sufficiency
in years for which no contracts exist is overly speculative.”Comments at 3.
Finally,JEP supports the arguments made by ICL.Specifically,Intermountain
asserts that demand response participation does not amount to a long-term contract commitment
or any other variable that the Commission has deemed modifiable between IRP filings.
Idaho Power Reply
Idaho Power replies that use of a 2021 capacity deficit year in the calculation of IRP
methodology avoided cost rates is reasonable and ensures that customers do not pay more than
the Company’s avoided cost in 20-year power purchase obligations.Idaho Power emphasizes
that the Commission’s intent was clear when it determined that a utility should not pay for
capacity within the avoided cost rates for years when the utility is capacity sufficient.Moreover,
ORDERNO.33159
Idaho Power maintains that to fail to take into account the Company’s capacity needs “would
violate PURPA,as customers would be paying costs that are substantially above the Company’s
avoided cost.”Reply at 4.
Idaho Power argues that the comments of ICL and TEP are unpersuasive and without
merit.Specifically,the Company takes exception to JEP’s representation that Idaho Power’s
estimated demand response dispatch is inaccurate.Idaho Power explains that “[t]he way that the
various programs work does not translate to flipping a switch whereby all 403 MW comes on
and off at will to meet the capacity needs of the Company However,all three programs
were dispatched,or called upon,several times throughout 2014 and contributed MW reductions
that exceeded any identified capacity deficits for 2014 and beyond.”Reply at 4-5.
Idaho Power asserts that ICL’s statements with regard to the impact that a capacity
deficiency determination has on ratepayers is erroneous.The Company states that 100 percent of
PURPA expenses are passed through to its customers on an annual basis through the Company’s
power cost adjustment (PCA).“The difference in avoided cost rates at issue here —whether
capacity payments are made to a qualifying facility (“QF”)when the utility is capacity sufficient
through 2021 —is approximately $6.3 million for every 20 MW project.”Reply at 7.
The Company maintains that,contrary to ICL’s assertions,this case is neither
complex nor technical.It does not require calculations or additional modeling of the IRP
methodology.“Payment of a separate capacity component of the rate is not a model input.”
Comments at 8.Idaho Power states that the capacity component is separately determined and is
simply removed in the years the Company is capacity sufficient.Idaho Power asserts that both
the SAR and the IRP methodologies start with a default capacity deficit that is established by the
most recent IRP planning process.However,because the Company’s demand response
programs were suspended at the time its 2013 IRP was finalized and filed with the Commission,
it did not take into account capacity provided by the Company’s demand response programs.
Based on the terms of a Commission-approved settlement,Idaho Power now has more than 400
MW of demand response customer subscriptions for 2014.The Company states that it would be
unjust,unreasonable,and not in conformity with PURPA to require customers to pay for
capacity when the Company is not experiencing a capacity deficit.
ORDER NO.33159 6
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.
PURPA requires that utilities purchase generation produced by QFs under a federal
rate mechanism (i.e.,avoided cost)that is established and implemented by state utility
commissions,Order No.32697 at 7.The rates at which Idaho electric utilities purchase QF
power must be approved by this Commission.Idaho Power Co.v.Idaho Public Utilities
Coin,nissio,z,155 Idaho 780,789,316 P.3d 1278,1287 (2013).The IRP methodology,at issue
here,takes into account many different variables and produces a result based on the
characteristics of the generation and each individual utility’s need for the resources.Specifically
with regard to capacity,we have previously stated that
In calculating a QF’s ability to contribute to a utility’s need for capacity,we
find it reasonable for the utilities to only begin payments for capacity at such
time that the utility becomes capacity deficient.If a utility is capacity surplus,
then capacity is not being avoided by the purchase of QF power.By including
a capacity payment only when the utility becomes capacity deficient,the
utilities are paying rates that are a more accurate reflection of a true avoided
cost for the QF power.
Order No.32697 at 21.Consequently,it would be unreasonable to ignore more than 400 MW of
demand response resources when determining Idaho Power’s capacity deficit as it pertains to the
IRP methodology.
We acknowledge that demand response was not a variable that this Commission
recognized would be updated in the IRP methodology between IRP filing cycles (every two
years.)Order No.32697.However,because we are a regulatory agency that performs both
judicial and legislative functions,we are not so rigidly bound by the doctrine of stare decisis.
Idaho Power Co.v.Idaho PUC,155 Idaho 780,788,316 P.3d 1278,1286 (2013).Under
ordinary circumstances,Idaho Power’s demand response resources would have been considered
within the Company’s integrated resource planning process and already taken into account.
ORDER NO.33159 7
Because the programs had been suspended,demand response resources were not included in the
Company’s 2013 portfolio.Following settlement negotiations and approval by this Commission,
Idaho Power modified and resumed its demand response programs.The Company currently
reports an enrolled capacity in excess of 400 MW.
Based on the Companys demonstrated demand response program participation,we
recently determined that,for purposes of the Surrogate Avoided Resource (SAR)methodology,
Idaho Power experiences its first capacity deficiency in July 2021.Order No.33084 at 5.We
find that ignoring the Company’s demand response contribution in calculations under the IRP
methodology would unjustly inflate avoided costs paid to QFs and harm ratepayers by requiring
them to pay for capacity provided by a QF that the utility does not need.Contrary to ICL’s
assertions,energy and capacity are not inextricably linked.PURPA and FERC regulations
clearly define avoided costs as 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.l0l(b)(6).If a QF resource provides energy,but the utility already has
sufficient capacity to meet its customers’needs,then capacity is not being avoided by the
purchase of QF power.Inclusion of capacity payments when the Company is not capacity
deficient results in overpayment to the QF for its generation —.an expense that is passed directly
on to Idaho Power’s ratepayers.ICL’s statement that “whatever the Commission decides here
will have no direct impact on customers”is entirely without merit.
Intermountain Energy Partners urged the Commission to reject Idaho Power’s
proposal to include its demand response and,thereby,satisfy capacity needs through July 2021.
IEP argued that,because demand response programs are single year commitments,they have no
bearing on the Company’s long-term capacity needs.We find that it is not necessary for the
Company’s demand response programs to run concurrently with a 20-year power purchase
agreement in order for the program’s current participation to be used as a reasonable estimation
of participation into the future.Indeed,FERC regulations endorse just such an approach.
FERC regulations require that a QF be given the option to choose an avoided cost
fixed at the time the QF’s obligation is incurred.18 C.F.R.§292.304(d)(2).
FERC anticipated that if the avoided cost of power was less when delivered
than the price in the PPA,the utility would be subsidizing the QF ‘at the
expense of the utility’s other ratepayers.’However,FERC was also cognizant
that in other cases,the required rate will turn out to be lower than the avoided
ORDER NO.33159 8
costs at the time of purchase.[FERCI does not believe that the reference in
[PURPA]to incremental cost of alternative energy was intended to require a
minute-by-minute evaluation of costs which would be checked against rates
established in long term contracts between [QFs]and electric utilities.
New York State Electric &Gas Corp.V.Saranac Power Partners,117 F.Supp.2d 211,221
(2000).FERC adopted the theory that overestimations and underestirnations would balance out.
We find that symmetry in terms establishing the QF’s avoided cost rate is fair,just and
reasonable.When a QF chooses to receive a fixed avoided cost rate for the duration of its power
purchase agreement,the snapshot of variables in a calculation under the IRP methodology
necessarily includes the uti1itys current estimation of when it will become capacity deficient
even though it is understood that the utility’s capacity needs will change over time based on
customer growth,availability and cost of resources,and environmental considerations!
requirements.
Inclusion of Idaho Power’s demand response produces a more accurate avoided cost
and,therefore,more closely aligns with the intent and requirements of PURPA and FERC
regulations.Therefore,we find it just and reasonable to include the capacity provided by Idaho
Power’s demand response programs in calculations made under the IRP methodology.We
further find that the capacity provided by demand response is sufficient to meet the Company’s
needs until July 2021.
ORDER
IT IS HEREBY ORDERED that Idaho Power’s Application is approved.We
confirm July 2021 as the Companys capacity deficiency period for use in the incremental cost
IRP methodology.
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.33159 9
DONE by Order of the Idaho Public Utilities Commission at Boise,Idaho this
day of October 2014.
j \
MACK A.REDFORD,COMMISSIONER
ATTEST:
Jean D Jewel!
Commission Secretary
O:JPC-E-1 4-22ks3
MARSHA H.SM.ITH,COMMISSIONER
ORDERNO.33159 10