Capacity Allocation Methodology
E3’s Avoided Cost Calculator allocates capacity value using a proxy for relative
loss-of-load probability (rLOLP) based on CAISO system loads. The value of capacity is
allocated to the top 250 load hours of the year in inverse proportion to the difference
between the calendar year’s peak load (plus the operating reserve margin) and the load in
each hour:
1
ai 
1  mL P  Li
 250
1
 
 h 1 1  m L P  Lh



1
where
ai = hourly capacity allocator in hour i
LP = peak load in calendar year
Li = load in hour i
m = operating reserve margin
This allocation methodology results in hourly allocators for the top 250 load hours that
sum to 1.0; no capacity value is allocated to hours with loads below the threshold set by
the load hour 250.
Current Avoided Cost Calculator Allocation
The version of the Avoided Cost Calculator submitted with the DR Protocols
calculates capacity allocators based on a calendar year of load data stretching from July
1, 2009 through June 31, 2010. This calendar year was selected because it is correlated
with the MRTU day-ahead and real-time prices used to value energy in the calculator.
The single year of load data used results in the allocation of capacity to only three months
of the year (July-September); stakeholders have expressed concern that such a narrow
window of capacity allocation is not appropriate for demand response. Figure 1 shows the
hourly and monthly allocations of capacity value currently calculated in the Avoided Cost
Calculator.
Figure 1. Current allocation of capacity value in Avoided Cost Calculator
45%
40%
Monthly Allocation of Capacity
Hourly Allocation of Capacity (Sorted in
Descending Order of LOLP)
2.5%
2.0%
1.5%
1.0%
0.5%
35%
30%
25%
20%
15%
10%
5%
0.0%
0%
0
100
200
300
400
500
Jan Feb Mar Apr May Jun
Jul Aug Sep Oct Nov Dec
PG&E’s rLOLP as an Alternative for Capacity Allocation
PG&E has provided the hourly relative loss-of-load probability calculated by its
proprietary model as an alternative to the allocation based on loads. PG&E’s rLOLP
allocates capacity value to a wider span of months, including small allocations to
January, February, and April. PG&E’s rLOLP allocation is summarized below in Figure
2.
Figure 2. The allocation of capacity value resulting from PG&E's rLOLP model results.
45%
40%
Monthly Allocation of Capacity
Hourly Allocation of Capacity (Sorted in
Descending Order of LOLP)
2.5%
2.0%
1.5%
1.0%
0.5%
35%
30%
25%
20%
15%
10%
5%
0.0%
0%
0
100
200
300
400
500
Jan Feb Mar Apr May Jun
Jul Aug Sep Oct Nov Dec
Multi-Year Average Capacity Allocation
As an alternative to the single year of load data used to calculate the original
allocators and to using the results of PG&E’s proprietary rLOLP model, E3 proposes the
use of several years of load data to calculate average monthly capacity allocators. By
calculating allocators using load data from 2006-2009 instead of a limited one-year
period, E3’s modified methodology allocates the value of capacity across a wider set of
months, capturing the potential diversity of peak constraints. While this approach does
not match PG&E’s rLOLP calculation perfectly—particularly in May and June, when
constraints are driven as much by supply-side conditions as by demand—it provides a
reasonable and improved approximation of this curve and maintains the advantage of
computational transparency. The allocators calculated based on the 2006-2009 loads are
shown in Figure 3.
Figure 3. Allocation of capacity based on an average of 2006-2009 load data.
45%
40%
Monthly Allocation of Capacity
Hourly Allocation of Capacity (Sorted in
Descending Order of LOLP)
2.5%
2.0%
1.5%
1.0%
0.5%
35%
30%
25%
20%
15%
10%
5%
0.0%
0%
0
100
200
300
400
500
Jan Feb Mar Apr May Jun
Jul Aug Sep Oct Nov Dec
Calculation of Capacity Residual
The Avoided Cost Calculator calculates the value of capacity using a new
combustion turbine as the proxy resource for capacity. The value of capacity is
calculated as the capacity residual: the real annualized cost of a new CT less the annual
net revenues that generator could earn through participation in the real-time energy and
ancillary services markets. Each of the components is calculated individually in the
avoided cost model:
1. Real Annualized Cost of a New CT: The real annualized cost of a CT is
calculated by levelizing the cash flow associated with a new CT using the real
utility after-tax WACC. This cost is adjusted upward for inflation in each year.
2. Net Revenue in Real-Time Market: E3 assumes that the new CT will participate
in the real-time energy market, dispatching in each hour if average real-time
market price in that hour exceeds its operating cost. E3 has characterized the
MRTU real-time market by analyzing data from 7/1/2009-6/31/2010 and
dispatches the CT in each year using this market characterization:
NRRT   max 0, HRM ,h g m  HRCT g m  VOM 
8760
h 1
where
NRRT = net revenue in real time market
HRM,h = real-time market heat rate in hour h
HRCT = heat rate of a new CT
gm = gas price in month m
VOM = variable operations and maintenance cost
3. Ancillary Services Revenues: Ancillary services revenues are assumed to scale
in proportion to the gross revenues earned in the real-time energy market. Based
on data presented in the CAISO 2010 Market Report, the A/S revenues are
assumed to equal 11% of gross real-time energy market revenues.
E3 calculates the capacity residual in each year based only on the net revenues expected
in that year—not on the real annualized lifecycle value of net revenues earned by a new
combustion turbine. E3 has chosen this methodology for several reasons:
1. It is consistent with the approach used to calculate the capacity residual used in
jurisdictions that use the capacity residual to set actual capacity market prices or
capacity market price limits (NYISO and PJM);
2. It is more appropriate as a short-term marginal value of capacity, as the marginal
capacity resource would not be contracted on a long-term basis and, in a
competitive market, would accept a capacity payment based on current market
energy conditions; and
3. It is more consistent with the valuation of energy in the avoided costs, which does
not use a lifecycle approach of a new generator but is based on current market
conditions and extrapolations thereof.
The capacity values calculated based on this methodology in the three years of the
upcoming DR program cycle are shown in Table 1.
Table 1. CT residual calculations using single-year net revenue.
CT Residual Calculation, Current Methodology
Real Annualized CT Fixed Cost
Annual Gross Energy Revenue
Annual Gross A/S Revenue
Annual Operating Cost
CT Residual
Costs in nominal $/kW-yr
2012
191.80
($108.65)
($12.03)
$48.57
119.69
2013
195.63
($121.01)
($13.40)
$56.54
117.77
2014
199.55
($130.86)
($14.49)
$62.12
116.31
Nonetheless, E3 recognizes the alternative possibility of calculating the capacity value
based on the real annualized lifecycle net revenues. Because the value of energy is
expected to escalate faster than the cost of plant construction this alternative methodology
will result in a lower value of capacity in all years. The resulting capacity values are
summarized for the upcoming three-year program cycle in Table 2.
Table 2. CT residual calculations using real annualized lifecycle net revenues.
CT Residual Calculation, Alternative Proposed Methodology
Real Annualized CT Fixed Cost
Lifecycle Annualized Gross Energy Revenue
Lifecycle Annualized Gross A/S Revenue
Lifecycle Annualized Operating Cost
CT Residual Alternative
Costs in nominal $/kW-yr
2012
191.80
($135.01)
($14.95)
$64.51
106.35
2013
195.63
($140.85)
($15.60)
$67.65
106.84
2014
199.55
($146.21)
($16.19)
$70.41
107.55
Figure 4 shows the results of the two alternatives: the higher capacity value is based on a
residual calculated using single-year revenues, while the lower capacity value is based on
a residual calculated using real annualized expected lifecycle revenues.
Figure 4. Capacity value alternatives for DR capacity valuation.
Capacity Residual (nominal $/kW-yr)
$160
$140
$120
$100
$80
$60
$40
Calculated with Annual Net Revenue
$20
Calculated with Annualized Lifecycle Net Revenue
$0
2010
2012
2014
2016
2018
2020