POWER June 2011 - 64

PLANT ECONOMICS
total MWh generation and output (ignored
by the standard formula) that must
be provided when a deficiency in energy
(kWh or MWh) must be made up by bringing
another unit in the system online and/
or when a deficiency in capacity (kW or
MW) must be made up by purchasing firm
capacity from neighboring systems. The
COE analysis is adjusted to a common annual
total energy generation basis using
the following terms:
Sc
Se
= System replacement capacity cost ($/
kW-yr)
= System replacement energy cost ($/
kWh)
∆P = Capacity to be replaced (kW)
∆E = Energy to be replaced (kWh)
For multiple unit comparisons, the alternative
with highest total energy production
can be selected as the basis to determine
∆P and ∆E. Energy replacement cost (Se
) is
dependent on the makeup of the particular
generating system, for which the alternatives
are evaluated using COE. Note, however,
that the economic dispatch principle
requires using a variable generation cost
at least equal to or higher than that of the
units under consideration. Otherwise, the
replacing unit would already be online and
generating electricity.
Case Study
The new COE formulation's contribution
to the life-cycle cost analysis is best illustrated
using an example. Consider a
Table 1. Key data and parameters used for calculating COE. The data
shown here are for illustration purposes and do not reflect any existing product and/or
guarantee. Sources: Electric Power Research Institute, U.S. Energy Information Administration,
and PJM
Parameter
Annual load-weighted average ambient temperature
Rated power at ISO base (P)
Rated efficiency
Specific price of plant
First-year fuel cost options
Fixed O&M
Energy replacement cost options (Se)
Capacity replacement cost (Sc)
Variable O&M
Capital charge factor ()
Levelization factor (L)
Reliability (R)
Maintenance factor (μ)
Value
64F
500 MW
57.50%
$1,000/kW
$5 and $10/mmBtu (HHV)
$15/kW
6¢ and 11¢/kWh
$50/kW-yr
1.5 mils/kWh
15%
1.25
99%
2.5
2. Combined-cycle part-load efficiency. Plant B has better part-load efficiency
lapse than Plant A in this hypothetical comparison. Thus, at the same average load, B has
better efficiency (less fuel consumption) than A. The benefit of the faster start-up capability
is a higher effective load factor (less time spent at lower loads) and, consequently, higher
efficiency. Note that the generic curves shown here are for illustration purposes and do not
reflect any existing product and/or guarantee. Source: GE Energy
1.0
standard 500-MW CC plant (57.5% rated
efficiency) described as Plant A. Two enhancements
are planned for Plant A: improved
part-load heat rate and a faster
start-up and load ramp capability (assumed
50% shorter time). The new product that
incorporates these improvements will be
called Plant B. The remainder of the key
plant parameters and assumptions used in
this case study are summarized in Table 1.
The beneficial impact of the planned improvements
on the COE is conceptually
explained in Figure 2.
Two operating scenarios for Plant B
could be analyzed:
■ Scenario B1. Plant B reaches baseload
quicker than Plant A, allowing the plant
to be dispatched for a longer period.
Therefore, it generates more revenue-
but at the expense of higher total fuel
consumption and emissions. Heff
is the
same as for Plant A, or 4,552 hours (calculated
previously).
■ Scenario B2. Plant B starts later than
Plant A and reaches baseload at the
same time as Plant A normally would.
The benefit to operating in this manner
is lower fuel consumption and emissions-but
at the expense of less generation
(less revenue). Heff
is reduced by
150 hours to 4,402 hours.
It would seem that starting a " fast " power
plant as early as possible so that it contributes
baseload power to the grid quicker
(scenario B1) is a better strategy than
starting it as late as possible to be online
at the last minute (scenario B2). However,
this may not be the case when electricity
sale prices are taken into account.
If the price before the prescribed time
when the market price becomes effective is
significantly lower (or even below the variable
cost of generation), the apparent advantage
of B1 may be much more modest or
even nonexistent. In fact, B1 is most likely
to occur in an emergency situation, when
immediate dispatch is required to exploit an
opportunity or to make up for a sudden or imminent
loss in generation.
However, B2 is probably the norm for
Part load efficiency
lapse benefit
B
A
Load factor benefit
of fast start
CC load or load factor
64
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1.0
regular plant starts. Furthermore, a plant
may have fast-start capability, but the plant
owner may choose to use it sparingly or
not at all unless paid a premium by a system
operator to dispatch on short notice
at a significant premium. Thus, the actual
value of the fast-start capability is more
likely to fall somewhere between the two
scenarios. For this example, a weighted
average of the performance of the two scenarios
is used.
POWER | June 2011
CC efficiency

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POWER June 2011

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