20140814Application.pdf

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An IDACORP Company
DONOVAN E. WALKER
Lead Counse!
[e-mail]
August 13,2014
VIA HAND DELIVERY
Jean D. Jewell, Secretary
ldaho Public Utillties Commission
472 West Washington Street
Boise, ldaho 83702
Re: Case No. !PC-E-14-22
Confirming Use of Capacity Deficiency Period in IRP Methodology - ldaho
Power COmpany's Application
Dear Ms. Jewell:
Enclosed for filing please find an original and seven (7) copies of ldaho Power
Company's Application in the above matter.
DEW:csb
Enclosures
Very truly yours,ZG
Donovan E. Walker
1221 W. ldaho st. (83702)
P.O. Box 70
Boise, lD 83707
DONOVAN E. WALKER (lSB No. 5921)
ldaho Power Company
1221West ldaho Street (83702)
P.O. Box 70
Boise, ldaho 83707
Telephone: [phone]
Facsimile: [phone]
[e-mail]
Attorney for Idaho Power Company
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY
CONFIRMING USE OF THE CAPACITY
DEFICIENCY PERIOD FOR THE
INCREMENTAL COST, INTEGMTED
RESOURCE PLAN, AVOIDED COST
METHODOLOGY.
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-14-22
APPLICAT!ON
Idaho Power Company ("ldaho Powe/'or "Company"), in accordance with RP 52,
the applicable provisions of the Public Utility Regulatory Policies Act of 1978 ("PURPA'),
and ldaho Public Utilities Commission ("Commission") Order Nos. 32697 and 33084,
hereby respectfully applies to the Commission for an order confirming the use of a July
2021 capacity deficiency period in the approved incrementa! cost, integrated resource
plan, avoided cost methodology ("lRP Methodology") applicable to the negotiated
avoided cost rates for proposed PURPA qualifying facility ("QF') wind and solar projects
that exceed 100 kilowatts ('kW"), and a!! other proposed QF projects that exceed 10
average megawatts ("aMW").
APPLICATION - 1
ln support of this Application, ldaho Power represents as follows:
I. CAPACITY DEFICIENCY FROM ORDER NO. 32697
On December 18, 2012, the Commission issued Order No. 32697, Case No.
GNR-E-11-03, which authorized the use of ldaho Powe/s incremental cost lRP
Methodology. Order No. 32697, p. 21. The Surrogate Avoided Resource ("SAR')
avoided cost methodology ("SAR Methodology") is applicable to published, or standard,
rate avoided cost contracts. ld., pp. 14-17. Solar and wind QF projects that do not
exceed 100 kW, and all other QF projects that do not exceed 10 aMW, are eligible for
published avoided cost rates. ld. All QF projects that exceed the aforementioned
published rate eligibility caps of 100 kW and 10 aMW receive negotiated avoided cost
rates based upon the approved incremental cost, IRP Methodology. ld., pp.20-21.
With regard to the capacity deficiency, the Commission directed, "We further find
it appropriate to identify each utility's capacity deficiency based on load and resource
balancesfound in each utility's IRP.' /d., p. 16.
ln 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. lf 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, p.21.
The Commission went on to discuss the Integrated Resource Plan ("lRP")
planning process and the use of inputs from the IRP planning process in the calculation
of avoided cost rates. ld., pp.22-23. The Commission directed:
APPLICATION - 2
ln an effort to address the concems of the QF developers
who maintain that a utility could manipulate variables within
the IRP planning process in a way that would negatively
impact the pricing of capacity paid to a QF, we find it
reasonable and fair to subject each utility's determination of
capacity deficiency to further scrutiny. Therefore, when a
utility submits its lntegrated Resource Plan to the
Commission, a case shall be initiated to determine the
capacity deficiency to be utilized in the SAR Methodology.
The capacity determined through the lRP planning process
will be the starting point, and will be presumed to be correct
subject to the outcome of the proceeding.
Order No. 32697, p.23.
With regard to the IRP Methodology, the Commission stated, "in order to
maintain the most accurate and up-to-date reflection of a utility's true avoided cost,
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)." ld., p.22.
Consequently, a literal reading of the relevant portions of Order No. 32697, cited
above, concludes that for both the SAR and IRP Methodologies the utility's capacity
deficiency is initially established to be the same as that identified by the utility's IRP
planning process. For the SAR Methodology, a separate case proceeding is initiated at
the time the IRP is filed to separately establish the capacity deficiency period for the
SAR Methodology. This happens every two years. For the IRP Methodology, the utility
updates the load and resource balance forecasts annually, in conjunction with the
annual update to the natural gas and fue! price forecasts. This was initially set to occur
on June 1 of each year. ld., p.22. However, upon clarification and reconsideration, this
was later changed to October 15 of each year. Order No. 32802, p. 3.
APPLICATION - 3
II. CAPACITY DEFICENCY FROM CASE NO. IPC-E.13.21
As directed by Order No. 32697, ldaho Power initiated a proceeding on
November 4,2013, seeking approval of the capacity deficiency to be utilized in the SAR
Methodology. Case No. IPC-E-13-21. ldaho Power asked the Commission to approve
a capacity deficit period with a first deficit occurring in July 2021. Case No. IPC-E-13-
21, Application, p. 5. The capacity deficit from the 2013 IRP showed a first deficit of
July 2016. ld., p.2. Updating the IRP's July 2016 first deficit with the October 2013
load, gas, and cogeneration and small power production ("CSPP') forecasts resulted in
a first deficit of July 2013. /d., p. 3. Finally, updating the July 2013 first deficit with the
inclusion of up to 440 megawatts ("MW") of demand response ("DR") pursuant to the
October 2,2013, DR settlement agreement moves the first deficit to July 2021. ld., p. 4.
Upon reconsideration, and the additional evidence that as of April 24,2014, the
Company had demand response program customers for the 2014 season with an
enrolled capacity exceeding 400 MW, the Commission ordered the Company to "utilize
July 2021 as its first capacity deficit to be used in the Company's SAR methodology, as
more fully described herein." Order No. 33084.
III. DISCUSSION
Order No. 32697 directs an independent update for the Company's current
capacity deficit for the SAR Methodology. Both the SAR and the IRP Methodologies
start with a default capacity deficit which is the same as that established by the most
recent IRP planning process. For the 2013 IRP planning process, a first deficit was
identified as 2016 in the preferred resource portfolio. However, because of the
suspension of the Company's DR programs tn 2013 at the time the 2013 IRP was
finalized and filed with the Commission, the first deficit of 2016 legitimately did not
APPLICATION - 4
consider the approximate 400 MW of DR. Subsequent to the filing of the 2013 lRP, the
Company entered into a settlement stipulation regarding its DR programs, which was
subsequently approved by the Commission. This stipulation obligated the Company to
accept up to 440 MW of DR. For 2014, the Company received actual subscribed
customers to its DR programs that exceeded 400 MW. Consequently, the Commission
updated the Company's first deficit from the IRP planning process to now include
consideration of the Company's DR programs, which were not considered in the
preferred resource portfolio of the lRP. This resulted in the Commission-approved first
deficit of July 2021for avoided cost rates established by the SAR Methodology.
The inputs to the IRP Methodology are currently scheduled to be updated,
pursuant to Order Nos. 32697 and 32802, in October 2014. However, because of the
unique circumstances regarding the way that DR programs were excluded in the 2013
lRP, those MW were not initially included in the IRP Methodology and its resulting
negotiated avoided cost rates. Consequently, Idaho Power, in the determination of
negotiated avoided cost rates pursuant to the IRP Methodology, has previously entered
into contracts (Grand View Solar and Boise City Solar) and previously sent initial
indicative pricing runs to several other proposed projects that contain capacity
payments for the entire term of the 20-year contract. However, once the Commission
determined in Order No. 33084 that the Company was capacity sufficient through July
of 2021, ldaho Power sent the revised SAR Methodology published rate pricing, as well
as revised indicative pricing pursuant to the IRP Methodology, to all projects that had
previously requested pricing. The updated indicative pricing runs removed the capacity
portion of the avoided cost rates through June of 2021 to recognize the current first
capacity deficit of July 2021.
APPLICATION - 5
ldaho Power believes the correct avoided cost pricing for all proposed PURPA
projects takes into account the determined first capacity deficit of July 2021. The IRP
Methodology is meant to be a more flexible, negotiated process whereby a more
accurate representation of avoided costs can be determined and reduced to an
obligation that is passed on to ldaho Power's customers for the next 20 years. The
Commission clearly intended, in Order No. 32697, that the utility's capacity deficiency
be updated, and that a capacity payment be reflected in avoided cost rates only for
those times that the utility is capacity deficient.
ln computing avoided cost rates under the IRP Methodology,
each of the three utilities already employs a two-step
approach in which energy and capacity values are computed
separately. ln 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. lf 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, p.21.
The inputs to the IRP Methodology are updated every two years with each new
lRP, and annually in October with updated gas, load, and CSPP forecasts. The
capacity component of avoided cost rates in the IRP Methodology is established
separately from the energy component of the rate. The energy component is based
upon the proposed project's specific hourly generation profile, which is compared to an
AURORA modeled run of the Company's system. ln this comparison, for each hour that
the QF provides generation, the highest cost Company resource serving load
(generation or market purchase) for that hour is assigned as that hour's avoided cost.
APPLICATION - 6
These hourly incremental costs are accumulated into monthly heavy-load and light-load
prices that represent the avoided cost of energy. The capacity component of the
avoided cost rate is based upon the cost of a simple-cycle natural gas combustion
turbine and the QF's peak-hour capacity factor. Consequently, it is not necessary to
change or update any of the inputs in the AURORA modeling or the IRP Methodology
that are determined by the IRP and the October updates. The capacity component of
the avoided cost rate is simply removed for any years that the utility is capacity
sufficient. ln this case, with a Commission determination that the Company is capacity
sufficient until July 2021, the indicative pricing for negotiated rate, proposed QF projects
was revised to remove the capacity portion of the rate until the July 2021 first capacity
deficit.
ldaho Power currently has two signed solar contracts filed with the Commission
for its review: Grand View at 80 MW and Boise City Solar at 40 MW, which were
entered into prior to the Commission determination of a first capacity deficit of July
2021. ln addition, ldaho Power currently has just over 529 MW of proposed new solar
QF projects seeking pricing and contracts. Of this 529 MW, eight proposed projects
(just over 208 MW) had previously received initial indicative pricing that included
capacity payments for the entire term of the contract sent prior to the Commission's July
2021 first capacity deficit determination. Each of these projects has received
superseding and updated indicative pricing runs with the capacity portion of the rates
removed through June of 2021. The difference in the rates varies for each project's
unique generation profile but the approximate difference in rates over a 2}-year contract
term is about $6.3 million for a 20 MW project. The difference in avoided cost rates for
those eight projects that received revised indicative pricing is approximately $65 million.
APPLICATION - 7
The difference in price for all 529 MW of proposed solar projects is just about $170
million.
Several projects have raised objection to ldaho Power's inclusion of a first
capacity deficit of July 2021 in their indicative avoided cost prices, claiming that ldaho
Power "lacks authorization to unilaterally alter prices based on the IRP methodology to
remove payments for capacity" and that they have a legally enforceable obligation to the
previous indicative pricing containing capacity payments for the entire duration of the
contract. Not only is this an incorrect assertion regarding the law of how a legally
enforceable obligation is established in the state of Idaho, but it is also incorrect as to
the process of establishing negotiated rates under the approved !RP Methodology.
The ldaho Supreme Court has recently issued an opinion in which it has
examined and reaffirmed the Commission's authority and process for establishing a
legally enforceable obligation as proper and consistent with both state and federal law.
ldaho Power Co., v. ldaho Public Utilities Comm'n., 155 Idaho 780, 316 P.3d 1278
("Grouse CreeK'). The ldaho Supreme Court affirmed that, "IPUC has authority under
state and federal law, to require that before a developer can lock in a certain rate, there
must be either a signed contract to sell at that rate or a meritorious complaint alleging
that the project is mature and that the developer has attempted and failed to negotiate a
contract with the utility; that is, there would be a contract but for the conduct of the
utility." 1d.,316 P.3d at 1285 (quoting Rosebud Enterpriseg /nc. v. ldaho Public Utilities
Comm'n, 131 ldaho 1, 6, 951 P.2d 521,526 (1997)). "[W]e again affirm IPUC's
requirement that a finding of a legally enforceable obligation requires a showing that
there would have been a contract but for the actions of the utility." Here, ldaho Power
has simply sent to the projects, at their requests, initial indicative modeled pricing
APPLICATION - 8
runs-and has updated such indicative prices with the removal of the capacity portion of
the rate for those months prior to July 2021, subsequent to the Commission's
determination that the utility was capacity sufficient through that date. These projects
do not have a signed contract with the utility and have not established that ldaho Power
will not negotiate with them, nor have they shown that ldaho Power has refused to
purchase or contract.
lf a QF project feels that the utility is refusing to contract for the purchase of its
generation, then it may seek a legally enforceable obligation determination from the
Commission to bind the utility and its customers to the purchase, even in the absence of
a contract. Such a procedure, and such a concept as a legally enforceable obligation,
exists to prevent a situation where the utility refuses to purchase from the QF. Grouse
Creek, 316 P.3d al 1280, 1285. It does not exist so that the QF can pick and choose
what contractual terms, conditions, and rates it unilaterally wishes to impose on the
utility and its customers. Those items, most particularly the rates, are determined by the
Commission, not by the QF, and not by the utility. PURPA requires that the utility
purchase. The Commission determines the terms and conditions of the purchase and
the appropriate price.
As previously mentioned, the approved IRP Methodology is meant to be a
flexible and dynamic process that arrives at a more accurate estimate of the utility's
avoided cost that ultimately is reduced to a 2O-year obligation passed on to ldaho
Power's customers. lt is not the same as the certainty and availability of published
avoided cost rates. lt is specifically and expressly a negotiated rate process that utilizes
the IRP Methodology to establish the presumptive avoided cost rate as a starting point
for the negotiated rate. Absent any specia! circumstances or considerations that would
APPLICATION - 9
justify an upward or downward adjustment to that rate, the modeled rate would be the
negotiated avoided cost rate. Not only is it within ldaho Power's "authorization" to
remove the capacity portion of the modeled, lndicative price for times that the utility is
capacity sufficient, it is the Company's obligation to ensure that an avoided cost rate is
not locked in for the next 20 years that passes on to its customers avoided cost rates
that are overpriced by more than $170 million.
IV. MODIFIED PROCEDURE
ldaho Power believes that a hearing is not necessary to consider the issues
presented herein and respectfully requests that this Application be processed under
Modified Procedure; i.e., by written submissions rather than by hearing. RP 201 ef seg.
lf, however, the Commission determines that a technical hearing is required, the
Company stands ready to prepare and present its testimony in such hearing.
V. COMMUNICATIONS AND SERVICE OF PLEADINGS
Communications and service of pleadings, exhibits, orders, and other documents
relating to this proceeding should be sent to the following:
Donovan E. Walker
Lead Counsel
Regulatory Dockets
ldaho Power Company
1221West ldaho Street
P.O. Box 70
Boise, ldaho 83707
[e-mail]
dockets@ idahopower. com
Randy C. Allphin
Energy Contract Ad ministrator
ldaho Power Company
1221West ldaho Street
P.O. Box 70
Boise, ldaho 83707
ra I I ph i n @id a hopower. co m
VI. REQUEST FOR RELIEF
ldaho Power respectfully requests that the Commission issue an order: (1)
authorizing that this matter may be processed by Modified Procedure and (2) confirming
APPLICATION - 1O
use of a first capacity deficit of July 2021 for purposes of avoided cost prices
determined by the incremental cost, IRP Methodology.
Respectfully submitted this 13h day of August 2014.Zu
DONOVAN E. WALKER
Attomey for ldaho Power Gompany
APPLICATION.l,I