September 11, 2006
Mrs. Susan M. Hudson, Clerk
Chittenden Bank Building
Vermont Public Service Board
112 State Street - Drawer 20
Montpelier, VT 05620-2701
Re: Avoided Costs
Dear Mrs. Hudson:
At the workshop on August 25, 2006, the Board asked the Department to file a
letter stating which of the avoided costs it recommends for adoption and for how long.
The Department is recommending that the Board adopt for use by the Energy Efficiency
Utility, pursuant to paragraph 11 of the Memorandum of Understanding approved by the
Board in Docket No. 5980, the avoided costs as presented in the AESC report for all fuels
contained in the report. Further, the Department recommends the Board adopt the
costing period definitions as presented in the report. The Department recommends that
these avoided costs be updated approximately every two years or as circumstances
dictate.
The AESC report contains a recommended methodology for calculating avoided
T&D costs. The Department is working with the utilities to implement this method or to
adapt it to the Vermont situation. Until such time as this work is completed, the
Department recommends no change to the avoided T&D capacity component. The
Department also proposes to update the marginal losses associated with end use
consumption to correspond with the new costing periods. The updated loss multipliers
are attached.
As mentioned in the May 4, 2006 DPS Request for Board Approval of Revised
Avoided Costs, this set of avoided costs was developed in conjunction with the other
states in the New England region. Though the cost projections were customized for
Vermont, they were a part of this regional effort. This regional group has historically
updated these costs on a biannual basis and intends to do so in the future. Therefore, the
Department is anticipating a much more frequent updating of the avoided costs in the
future. We expect the next cycle to begin in the summer of 2007.
Since the report has a series of tables representing different avoided costs for
different regions of New England, the Department is providing some more specific
recommendations regarding which numbers to adopt. For electric prices, the Department
is proposing to adopt the values listed on page 188 of the report in columns 1 through 7
only as capacity and energy values.
The Department recommends that the Board adopt the costing period definitions
reported in the chart on page 148. ISO New England has designated different costing
periods for demand reductions associated with demand resources during the transition
period (December 2006 through May 31, 2010) for the forward capacity market (FCM).
Both definitions require that Efficiency Vermont rework the DSM savings load profiles
to put the savings into appropriate bins. The changes in the energy data will match the
avoided costs as presented in the report. However, the ISO capacity performance hours
do not match those in the ICF report. So that EVT is not required to track multiple
capacity savings amounts, the Department proposes that EVT create a capacity value
consistent with the ISO FCM performance hours for use as the DSM capacity value. The
Department will work with ICF and the AESC participants to reconstitute the capacity
price projections in the report to match the ISO definitions. If that is not possible in a
reasonable way, the Department proposes to use the AESC price data and the ISO
capacity definitions in the short term. This is something that will presumably be rectified
in future avoided cost studies. The goal is to avoid reworking the DSM savings data
twice to accommodate evolving market requirements.
End use avoided costs for natural gas are located in chapter 1, Exhibit 1-20. Costs
for other fossil fuels are contained in Chapter 4, Exhibits 4.2 through 4.8. EVT will
incorporate the selected avoided costs into the screening tool. We are proposing no
changes to the externality values or the risk adjustment.
The Department is not proposing to adopt the DRIPE component of the report for
several reasons. Vermont self supplies much of its capacity needs so price changes will
only effect marginal purchases. The price effects associated with DRIPE represent
transfer payments, and should not be included in the screening tool under accepted
economic tests. Finally, the Department also has some reservations about the
methodology developed by the AESC to calculate the actual value. We will, however,
keep working with our New England colleagues to refine this concept and appropriate
use.
The Department recommends adopting these avoided costs as soon as possible.
This is necessary so that EVT can incorporate these changes by January 1. This timing
will greatly simplify their reporting and documentation functions.
There was some discussion regarding the increase in oil prices since the forecast
was finalized. ICF consultants looked at the differences in their oil and gas price
projections and the effects of those price changes on electric prices. ICF informs us that
the projected oil prices have increased roughly 20% with a corresponding effect of about
5% on gas prices. A fully updated forecast may show additional changes due to other
factors like drilling costs or LNG projections. The 5% change in gas prices will have a
relatively small effect on electric prices - on the order of 3%-4%. Attached is a
spreadsheet showing those changes in the forecast. We do not view this difference as
cause for delay in accepting the December 2005 projections of avoided costs.
The costs as presented in the original ICF report represent an internally
consistent set of prices that was valid a year ago and continue to be appropriate today.
This set is a significant improvement over the costs presently in the screening tool which
date from the late 1990's. Prices for other fuels are important for fuel switching
applications. The Department has already expressed its concern that, due to volatility and
high current prices in the fossil fuel markets, DSM practitioners should limit measures
involving fuel switching. While anticipated oil prices have risen significantly and
anticipated gas prices somewhat in the intervening months, the effect on electricity
avoided costs is small. For these reasons, the Department recommends adoption of the
ICF avoided costs as in the current report without modification, except as discussed
above.
Regarding other purposes for which these costs can or might be used, the
Department is proposing them for use in DSM screening only, consistent with the MOU
in Docket 5980. To the extent that they become a benchmark or reference in other
matters, it will be incumbent on the proponents in those matters to justify their use.
Thank you for the opportunity to submit these comments.
Sincerely,
Riley Allen
Director for Regulated Planning
UPDATED OIL AND GAS PRICES FROM ICF
ICF 06 Oil
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
New Oil 05$
$
50.15
$
59.81
$
56.77
$
54.93
$
52.12
$
52.26
$
51.49
$
50.80
$
50.17
$
49.60
$
49.57
$
49.96
$
50.09
$
50.17
$
50.21
$
50.22
$
50.32
$
50.59
$
50.84
$
51.06
$
51.25
Oil
AESC 2005
Rept
$
45.57
$
46.44
$
44.37
$
43.34
$
44.50
$
47.21
$
45.48
$
43.79
$
42.11
$
40.42
$
38.63
$
38.90
$
39.61
$
40.32
$
41.02
$
41.73
$
42.44
$
43.14
$
43.85
$
44.55
$
45.26
Probable Gas Price
Given Revised Oil,
all else equal
--$
8.15
$
6.63
$
5.66
$
5.02
$
4.95
$
5.13
$
5.26
$
5.71
$
5.40
$
5.46
$
5.35
$
5.55
$
5.71
$
5.83
$
6.08
$
6.16
$
6.42
$
6.50
$
6.86
Gas
AESC 2005
Rept
$
7.88
$
8.33
$
8.02
$
6.16
$
5.25
$
4.55
$
4.61
$
4.80
$
4.98
$
5.51
$
5.14
$
5.16
$
5.13
$
5.27
$
5.44
$
5.56
$
5.84
$
5.92
$
6.26
$
6.34
$
6.79
Notes:
Probable Gas Price does not reflect modeling results. It is based on a simple impact
estimate of oil price change on the gas price.
Conversion from 2003$ to 2005$ = 1.045
6
Vermont Statewide Avoidable Line Losses
Total Annual Losses (MWh)
588,970
Average Annual Losses (% of Load)
10.2%
Average Annual Losses (% of Sales)
11.4%
No Load Losses (% of Total Losses)
25%
No Load Losses (MWh)
147,243
Annual Variable Losses (MWh)
441,728
Sum of 8760 Hourly Loads Squared 3,665,873,568
System Loss Factor
0.0001205 loss/load sq.
Hours per Costing Period
Winter Peak
Winter Off Peak
Summer Peak
Summer Off Peak
Total
2,416
2,672
1,760
1,912
8,760
Variable Energy Losses by Costing Period (MWh)
Winter Peak (Oct - April)
174,152
Winter Off Peak
92,267
Summer Peak (May - September)
109,016
Summer Off Peak
66,292
Total Variable Losses
441,728
Average Variable Energy Losses by Costing Period (% of Sales)
Winter Peak
10.6%
Winter Off Peak
6.2%
Summer Peak
9.7%
Summer Off Peak
7.2%
AVOIDABLE LOSSES:
Marginal Energy Losses by Costing Period (% of Sales)
Winter Peak
21.2%
Winter Off Peak
12.4%
Summer Peak
19.5%
Summer Off Peak
14.5%
Average Variable Losses at Peak Hour (% of Sales)
Peak Hour
15.2%
Summer
Spring/Fall
14.2%
14.7%
7