20151117Reply Comments.pdf

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November 17,2015
VIA IAND DELIWRY
Jean D. Jewell
Commission Secretary
Idaho Public Utilities Commission
472W. Washington
Boise,ID 83702
Re:CASE NO. PAC.E-I5-12
IN THE MATTER OF' THE APPLICATION OF ROCKY MOUNTAIN
POWER FOR APPROVAL OF CAPACITY DEFICIENCY PERIOD TO BE
USED FOR AVOIDED COST CALCULATIONS
Dear Ms. Jewell:
Please find enclosed for filing an original and seven (7) copies of Rocky Mountain Power
reply comments in the above-referenced matter.
Informal inquiries may be directed to Ted Weston, Idaho Regulatory Manager at(801) 220-
2963.
Very truly yours,
Please find enclosed for filing an original and seven (7) copies of Rocky Mountain Power's
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Vice President, Regulation
1407 W. North Temple, Suite 330
Salt Lake City, Utah 84116
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Yvonne R. Hogle (lSB No. 8930)
1407 W. North Temple, Suite 320
Salt Lake City, Utah 841l6
Telephone No. [phone]
Facsimile No. [phone]
E-mail: [e-mail]
Attorneyfor Roclcy Mountain Power
IN THE MATTER OF PACIFICORP DBA
ROCKY MOUNTAIN POWER'S
APPLICATION TO APPROVE
CAPACITY DEFICIENCY FOR AVOIDED
COST CALCULATIONS
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. PAC-E-15-12
REPLY COMMENTS OF
ROCKY MOUNTAIN POWER
PacifiCorp, d.b.a. Rocky Mountain Power ("Rocky Mountain Power" or "Company"),
hereby provides reply comments in response to comments filed by the Staff of the Idaho Public
Utilities Commission ("Staff'). Staff recommends the Commission reject the Company's
request to adopt summer 2025 as the Company's first capacity deficit for use in the surrogate
avoided resource ("SAR") model. Instead, Staff recommends the Commission adopt summer
2015 as the first capacity deficit, reflecting the Company's updated system position but
excluding available front office transactions ("FOTs").
BACKGROUND
On October 13,2015, the Company filed an application requesting the Commission
approve summer 2025 as the updated capacity deficiency period for use in the SAR avoided cost
calculations. The Company's application was consistent with the Commission's Order No.
32697 stating that payments to qualifying facilities ("QFs") should recognize the utility's
capacity needs:
"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 true avoided cost for the QF power."'
Consistent with the 2015 Integrated Resource Plan ("lIU"';, the Company included FOTs
in calculating the SAR deficiency period accurately reflecting the fact that the Company's long
term resource plan does not include any new generation capacity until 2028.
REPLY COMMENTS
Staffs recommendation to exclude available FOTs in determining the deficiency period
is based primarily on its assessment that FOTs do not represent committed market purchases and
that the must purchase obligation mandated by PURPA "does not permit utilities to reject offers
to sell by QFs in lieu of utility purchases from the market."2 Staff clarifies its position to be that
"utilities should not be allowed to rely on uncommitted, non-specific market purchases as an
excuse for not needing capacity from QFs."3
Contrary to Staffs assertion, inclusion of FOTs in determining the SAR deficiency
period does not serve as a rejection of QF purchases, but as a means to recognize in standard
avoided costs the timing and costs of the different resources used to balance the Company's
capacity needs and achieve the ratepayer indifference standard mandated by PUMA. Staff cited
Order No. 32697 which reiterates that the avoided cost rate shall not exceed the "'incremental
cost' to the purchasing utility of power which, but for the purchase of power from the QF, such
utility would either generate itself or purchase from another source." Under the approved SAR
I In the Matter of the Commission's Review of PURPA QF Contract Provisions Including the Surrogate Avoided
Resource (SAR) and Integrated Resource Planning (IRP) Methodologies for Calculating Avoided Cost Rates, Case
No. GNR-E-l 1-03, Order No.32697, p.21 (December 18,2012).
2 In the Matter of PacifiCorp DBA Rocty Mountain Power's Application to Approve Capacity De/iciencyfor
Avoided Cost Calculations, Case No. PAC-E-15-12, Comments of the Commission Staff, p. 5 (November 10, 2015).
'Id.
method, once a utility becomes capacity deficient avoided costs include both the variable and
fixed costs of a generic proxy combined cycle combustion turbine ("CCCT"). Staffls
recommendation to adopt summer 2015 as the first capacity deficit fails to recognize the
Company's ability to utilize its existing firm transmission capacity to procure resources in the
wholesale market rather than acquire a new generating resource at a higher cost. Stafls
recommendation will result in retail customers paying a QF the full cost of a CCCT immediately
even though the Company's 2015 IRP does not include a new CCCT resource until2028.
In Order No. 32697 the Commission stated that "A utility cannot be compensated by its
customers for energy produced from a generating facility until the utility establishes the need for
such new generation."4 As demonstrated in the 2015 IRP, the Company does not need additional
generation resources until 2028, but if FOTs are excluded from the determination of the SAR
deficiency period customers will be required to pay QF prices based on an unneeded generic
CCCT beginning in 2015. Excluding FOTs from the determination of the SAR deficiency period
clearly does not result in 'oa rate that holds utility customers harmless."5
Staffls exclusion of FOTs is based solely on the fact that these FOTs are "uncommitted,"
and Staff believes that "uncommitted resources... should not be counted in determining a
utility's capacity deficit position[.]"6 As described in the Company's 2015 IRP, FOTs are
"proxy resources, assumed to be firm, that represent procurement activity made on an on-going
forward basis to help the Company cover short positions."T The Company's FOT selections are
as committed and specific as its 2028 CCCT, which the Commission has found appropriate for
determining the avoided costs for large QFs. While Staff indicates "utilities should not be
a Order No. 32697 , pl5.
5 OrderNo. 32697,p16.
6 Supra.,fn. I
? PacifiCorp 2015 IRP, p128.
allowed to rely on uncommitted, non-specific market purchases" their alternative is to use the
costs of an uncommitted, non-specific CCCT.
Furthermore, the 1,670 MW of 'Available Front Office Transactions' included in Table 1
of the Company's application (Table I shows the 2015 IRP system capacity loads and resources)
represent firm transmission rights currently owned by the Company and included in customers'
rates, which enable access to diverse wholesale market resources. In actual operations and in the
2015 IRP this transmission capacity is routinely relied on to facilitate procurement of available
FOTs to balance the Company's capacity needs and minimize costs. For example, Figure I
below illustrates the amount of short-term firm ("STF") wholesale market purchases, net of
offsetting wholesale market sales, made by the Company at the time of its system peak load from
201I through2014.
HistoricalNet STF Purchases During Peak
2,500
2,000
1,500
As demonstrated by actual transactions, and as projected in the 2015 IRP, the Company will rely
on FOTs to balance its capacity needs before the next major thermal resource acquisition in
2028. The IRP is the Company's long term plan for serving customers and it relies on FOTs
because they provide the best balance of cost and risk. Recognizing 1,670 MW of firm
transmission access to wholesale markets in the determination of the SAR deficiency period
more closely aligns the capacity deficit period with the Company's IRP and the costs that can be
avoided by the addition of a QF.
Figure 2 compares the SAR avoided costs to current forward wholesale market prices for
electricity at the Mid-Columbia and Palo Verde markets. SAR costs are shown separately for
variable costs only (the avoided cost rates paid prior to the SAR capacity deficit period) and
variable plus fixed costs (the SAR avoided cost rates paid if the utility is deemed to be capacity
deficit).
Figure 2
SAR Avoided Costs Versus Forward Market Prices
Current SAR Avoided Costs
Base Load Resources
($a4wh)
September 2015
Official Forward Price Curve
($a4wh)
Year
Variable + Fixed
Variable Costs Costs Mid Columbia Palo Verde
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
$34.06 $s3.9s
s34.42 $s4.61
$3s.69 $s6.17
$39.37 $60.1s$43.0s $e.13$46.00 $67.39
$48.19 $69.89
$49.99 $72.01$s1.27 $73.62$53.87 $76.5s
$23.1 l $25.81
$24.80 $26.6s
$26.28 $27.s0
$27.59 $28.91
$30.05 $30.82
$31.61 $33.42
$33. 13 $37.09
$34.91 $40.33
$36.89 542.29
$39.12 $44.48
As demonstrated in Figure 2, avoided costs, inclusive of the fixed costs for a proxy CCCT, are
significantly higher than current prices for wholesale market transactions. If the Company is not
allowed to recognize existing firm transmission access to firm market purchases when
determining the SAR deficit period, retail customers end up paying more than avoided costs -
customers avoid firm market purchases but incur the fixed and variable costs of a CCCT that will
not be avoided by the Company. Compared to the average market prices shown in Figure 2,
payments to a base load QF generating 10 average megawatts would be more than $2.5 million
higher on an annual basis prior to the first capacity deficit year.
The Company recently demonstrated in Case No. PAC-E-15-03, that its current risk
management policy generally precludes the Company from entering into long term transactions
with terms longer than three years. This policy allows the Company the necessary flexibility to
serve load while managing the risk of changing wholesale market prices. In contrast, if the FOTs
were already contractually committed, customers could be potentially harmed by the addition of
a new QF as the utility would be obligated to take energy from the contracted FOT and the QF.
In other words, FOTs cannot be avoided if they are contractually committed. In Order No. 33357
of Case No. PAC-E-15-03 the Commission recognized the timing of new generation capacity
when determining the proper term length for contracts under the IRP Method for determining
non-standard avoided costs in Idaho. The Commission stated, "As we have said in previous
Orders, a utility is to begin payments to a QF for capacity 'at such time as the utility becomes
capacity deficient...[w]e recognize that a new two-year contract would be unlikely to reach a
capacity deficiency date."8 The Commission also recognizedthat, according to the 2015 IRP,
the capacity surplus period extended to "2028 for PacifiCorp."e
Finally, Idaho Power makes a similar assumption as PacifiCorp regarding access to
wholesale market purchases in its IRP and in its determination of the first capacity deficiency for
the SAR method that was just approved by the Commission.ro In fact, Staff explicitly
recognized Idaho Power's use of available transmission capacity to make future market
purchases in its comments filed August 21,2015, in Case No. IPC-E-15-20. Attachment A to
Staffs comments is taken from the Peak-Hour Load and Resource Balance tables from ldaho
Power's 2015 IRP and clearly shows Idaho Power's reliance on future, uncommitted, market
purchases to meet its capacity needs. [n its comments, Staff explained that Idaho Power's
deficiency period was moving up one year (from 2025 to 2024) because of the termination of
four PURPA contracts which equated to 74 MW of lost capacity. When Staff verified this
change it did not conclude that Idaho Power was now deficient 74 MW because it no longer had
committed resources, but instead confirmed that Idaho Power was deficient only 47 MW because
it still had 27 MW transmission capacity available which could be used for market purchases to
meet peak demand. In Case No. IPC-E-15-20, the Commission approved a first capacity deficit
year of 2024 for Idaho Power, and the deficit year determination recognized access to wholesale
markets as part of the resource balance. Inconsistent treatment for PacifiCorp in the current case
will result in avoided cost rates that are approximately $2OAvIWh higher for PacifiCorp
compared to ldaho Power each year through 2023. Such disparity encourages QF developers
located in Idaho Power's service territory to obtain a transmission wheel to PacifiCorp to take
t Order No. 33357, p25.
e Order No. 33357, p24.
'o Case No. IPC-E- 15-20, Order No . 33377 .
advantage of higher prices despite the fact that, like Idaho Power, the Company has no need for
new resources in the next decade.
Recognizing available FOTs that are facilitated by existing firm transmission access to
wholesale markets in the determination of the SAR deficiency period results in avoided costs
rates that are consistent with the 2015 IRP by more closely aligning the time period in which
QFs are paid the full cost of a CCCT with the time period the Company plans to acquire such
additional generation capacity. Removing FOTs from the equation will result in retail customers
paying a QF the full cost of a CCCT immediately even though the Company's 2015 IRP does not
include a new CCCT resource until 2028, which clearly does not result in "a rate that holds
utility customers harmless."l I
RECOMMENDATION
For the reasons set forth above, Rocky Mountain Power respectfully requests that the
Commission approve its application as filed, identifying summer 2025 as the first capacity deficit
for use in the SAR model.
DATED this lTth day of November 2015.
rr Order No. 32697, p16.