20141006Comments.pdf

KRISTINE A. SASSER
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720.0074
(208) 334-03s7
BAR NO. 6618
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
IN THE MATTER OF THE APPLICATION OF
IDAHO POWER COMPANY FOR
CONFIRMATION OF THE CAPACITY
DEFICIENCY PERIOD FOR INCREMENTAL
COST, INTEGRATED RESOURCE PLAN,
AVOIDED COST METHODOLOGY.
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-8.I4-22
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
Attorney of record, Kristine A. Sasser, Deputy Attorney General, and in response to the Notice of
Application and Notice of Modified Procedure issued in Order No. 331 16 on September 5,2014
and scheduling OrderNo. 33147 issued on September 30, 2014, in Case No. IPC-E-14-22, submits
the following comments.
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 deficiency
STAFF COMMENTS OCTOBER 6,2074
based on load and resource balances found in each utility's IRP." Order No. 32697 at 16. With
regard to the capacity deficiency, the Commission further stated the following:
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. at21.
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 Resource]
Methodology." Id. at23. 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. at22.
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 20l6,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
luly 2021.
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 in20l3, 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
avoided cost rates, Idaho Power has entered into contracts that contain capacity payments for the
STAFF COMMENTS OCTOBER 6,2014
entire term of the 2l-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 programs.
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 def,rcit of July 2021 (includes 400 MW of demand response) instead of
July 2016 (ldaho 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 2021for
purposes of avoided cost prices determined through use of the IRP methodology.
STAFF ANALYSIS
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. This case is focused
only on the IRP methodology, which is used to compute rates for wind and solar projects larger
than 100 kW and for all other projects larger than l0 aMW.
The Commission stated in Order No. 32697 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)." Idaho Power is
STAFF COMMENTS OCTOBER 6,2014
currently between IRP filings. The Company's 2013 IRP was accepted by the Commission on
February 24,2014, and its 2015 IRP is expected to be filed on June 30, 2015.
Under the IRP methodology, in years between IRP filings, the utility is supposed to update
its load forecast in conjunction with annual updates to natural gas and fuel price forecasts. This
was initially set to occur on June 1 of each year. Order No. 32697, p. 22. However, upon
clarification and reconsideration, this was later changed to October 15 of each year in order to
better accommodate the planning cycles of the utilities. Order No. 32802, p. 3. In this case, Idaho
Power is requesting to adjust its load resource balance outside of the October 15 update cycle it
would normally follow.
The out-of-cycle adjustment is proposed by Idaho Power in order to include 400 MW of
demand response that had previously not been included due to temporary suspension of the
programs in 2013 and uncertainty about whether, when, and in what amounts the programs might
be reinstated. 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 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.
For reference, the exact language from Order No. 32697 pertaining to updates under the
IRP methodology is reproduced below:
Updates. We find that, 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 f,rlings. For the sake of consistency,
these annual updates should occur simultaneously with SAR updates - on June I of
each year. In addition, it is appropriate to consider long-term contract
commitments because of the potential effect that such commitments have on a
utility's load and resource balance, We find it reasonable to include long-term
contract considerations in an IRP Methodology calculation at such time as the QF
and utility have entered into a signed contract for the sale and purchase of QF
power. We fuither find it appropriate to consider PURPA contracts that have
terminated or expired in each utility's load and resource balance. We find it
STAFF COMMENTS OCTOBER 6,2014
reasonable that all other variables and assumptions utilized within the IRP
Methodology remain fixed between IRP filings (every two years).
In essence, this case presents a question of whether the Commission should follow a strict,
literal interpretation of a prior order or whether the Commission's intent as expressed in the order
should prevail. A careful reading of the excerpt from Order No. 32697 shown above could lead to
a conclusion that the only updates that can be made annually are updates to load forecasts and fuel
price forecasts, and that the only out-of-cycle adjustments that are permitted are due to new or
terminated PURPA contracts. It could be argued that updates to a utility's load resource balance
due to the addition of new utility resources, such as demand response, are not permitted between
IRP filings.
On the other hand, it could be argued that the Commission never intended for Order No.
32697 to be dissected and parsed to such a degree that the real intent is lost or diluted. Even
though the Commission focused on how PURPA contract commitments affect the utility's load
and resource balance, Staff believes the Commission's intent is to recognize all factors that affect
the load and resource balance, so that the IRP methodology can more accurately reflect true
avoided costs. For example, in another section of the same Order, the Commission stated the
following:
In 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. 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.
OrderNo. 32697 at2l.
When both of the passages quoted above are taken together, it seems clear that the
Commission is trying to balance accuracy in reflecting a utility's real deficit position, with some
degree of certainty for QFs seeking contract rates. By requiring annual updates to load forecasts,
fuel price forecasts and long term contracts, the Commission appears to be striving for a dynamic,
fluid process to ensure the utility's need for new resources is represented as accurately as possible.
Further, if the Commission expects the utility to update its load resource balance each time a new
STAFF COMMENTS OCTOBER 6,2014
long term contract is signed or expires, is also seems reasonable to believe the Commission
expects that the addition of new utility-owned resources, such as demand response in this case, to
also be reflected in the load resource balance at whatever time those resources are added. At the
same time, however, QFs need some certainty so that they are not chasing a moving target. In
other words, the utility should not be paying for capacity until it is actually needed, but QFs
should have some assurance that rates will not be changed except on a predictable schedule.
Obviously, the decision is for the Commission to make, but Staff believes this is an
instance in which the Commission's intent should take precedence over a strict interpretation of
the Order. In writing its orders, the Commission cannot anticipate every circumstance that may
arise or envision every interpretation dispute that could occur. Quite simply, the Commission did
not specifically address whether or when demand response should be reflected in determining a
utility capacity position. Its intent, however, does seem to be clearly expressed. Moreover, 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, Staff recommends that the Commission approve Idaho Power's request to
confirm use a first capacity deficit of July 2O2l for purposes of avoided cost prices determined by
the incremental cost IRP methodology.
With regard to those QFs who may have received indicative pricing from Idaho Power
based on a first capacity deficit other than July 2021and those who may make claims that a legally
enforceable obligation (LEO) had been established before the Company revised the indicative
prices, Staff recommends that each project be considered individually. Without knowing the
specific facts of each case, it would not be practical or appropriate in this case for the Commission
to rule as to whether a LEO had been established.
STAFF COMMENTS OCTOBER 6,2014
STAT'F RECOMMENIIATION
Staffrccommends that the Commission approve Idatro Power's request to use a first
capacrty deficit of July 2021fsr purposes of anoided cost prices determined by the IRP
methodology.
Respectfully submitted this P day of Octob er20l4.
Technical Staff: Rick Sterling
Yao Yin
i:umicc:commcnt/ipce l4.22ksrpqry commcnts
STAFF COMMENTS OCTOBER 6,2014
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 6', DAY oF OCToBER 2014,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC.E.I4-22, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
DONOVAN E. WALKER
REGULATORY DOCKETS
IDAHO POWER COMPANY
P.O. BOX 70
BOISE,ID 83707
E-MAIL: dwalker@.idahooower.com
dockets@idahopower. com
RANDY C. ALLPHIN
ENERGY CONTRACT ADMINISTRATOR
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: [e-mail]
CERTIFICATE OF SERVICE