Document ID: EPA-HQ-OAR-2002-0056-0037
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2004-01-27T05:00Z

TO:
Bill
Maxwell,
U.
S.
Environmental
Protection
Agency,
OAQPS
(
C439­
01)

FROM:
Jeffrey
Cole,
RTI
International
DATE:
December
2003
SUBJECT:
Methodology
for
Estimating
Cost
and
Emissions
Impact
for
Coal­
and
Oil­
Fired
Electric
Utility
Steam
Generating
Units
National
Emission
Standards
for
Hazardous
Air
Pollutants
This
memorandum
describes
the
development
of
cost
and
emissions
impacts
estimates
for
electric
utility
steam­
generating
units
that
will
be
subject
to
a
National
Emission
Standard
for
Hazardous
Air
Pollutants
(
NESHAP).
The
estimates
support
regulations
for
mercury
(
Hg)
from
coal­
fired
units
and
nickel
(
Ni)
from
oil­
fired
units.

MEMORANDUM
OUTLINE
1.0
Introduction
2.0
Methodology
for
Estimating
Cost
and
Emission
Impacts
2.1
Costs
for
Coal­
fired
Units
2.2
Environmental
Impacts
for
Coal­
fired
Units
2.3
Costs
for
Oil­
fired
Units
2.4
Environmental
Impacts
for
Oil­
fired
Units
3.0
References
Appendix
A.
Cost
and
Emissions
Impacts
Calculations
Appendix
B.
Equations
for
Cost
and
Impacts
Estimates
2
1.0
INTRODUCTION
Costs
were
estimated
for
controls
to
reduce
Hg
emissions
from
coal­
fired
units
and
Ni
emissions
from
oil­
fired
units.
Costing
was
based
on
adaptations
of
methods
given
in
the
EPA
Air
Pollution
Control
Cost
Manual1
(
Manual).
The
Manual
uses
sizing
information,
equipment
cost
curves,
and
factors
associated
with
specific
controls
to
arrive
at
overall
capital
and
annual
costs.

Where
costs
are
not
available,
or
to
check
current
equipment
costs,
vendor
contacts
can
be
made
to
get
such
costs.
Four
major
elements
are
included
in
the
costing:
direct
and
indirect
capital
costs,
and
direct
and
indirect
annual
costs
(
including
annualized
costs
for
capital
recovery).

Direct
capital
costs
include
purchased
equipment
(
control
device
plus
auxiliary
equipment,

instrumentation,
sales
tax,
and
freight)
and
installation
(
foundation
and
supports,
handling
and
erection,
electrical,
piping,
insulation,
and
painting).
Site
preparation
and
buildings
are
not
usually
required,
but
would
be
included
with
direct
capital
costs.
Indirect
capital
costs
include
engineering,
construction
and
field
expense,
contractor
fees,
start­
up,
performance
test,
and
allowance
for
contingencies.
Direct
annual
costs
are
comprised
of
operating
labor
(
operator
and
supervisor),
operating
materials,
maintenance
labor
and
materials,
replacement
parts,
utilities
(
such
as
electricity
or
compressed
air),
and
waste
disposal.
Indirect
annual
costs
include
overhead,
administrative
charges,
property
tax,
insurance,
and
capital
recovery
(
the
annualized
cost
of
money
borrowed
to
purchase
and
install
the
control
system).
The
annualization
of
capital
recovery
is
based
on
estimated
equipment
life
and
interest
rate.
For
fabric
filters
(
baghouses)
and
electrostatic
precipitators
(
ESP),
equipment
life
is
estimated
at
20
years.
For
spray­
dryer
adsorbers
(
SDA)
life
is
estimated
at
15
years.
Interest
rates
are
taken
as
7
percent
for
all
equipment.

Because
the
costing
is
for
equipment
to
be
installed
at
existing
plants,
extra
costs
are
required
to
accommodate
difficulties
in
working
around
equipment
and
structures
already
in
place.
These
extra
costs
appear
as
a
retrofit
factor
included
in
the
total
capital
investment.

Values
for
retrofit
factors
use
here
are
1.4
for
baghouses
and
ESP,
and
1.2
for
SDA
units.
1
Some
boiler/
furnace
units
are
smaller
than
the
equivalent
of
25
MW,
but
are
paired
with
similar
units
to
serve
a
25
MW
(
or
greater)
generator.
3
For
coal
fired
units,
costs
were
estimated
using
a
population
of
1,143
units
(
furnace/
boiler
combinations)
ranging
in
equivalent
rated
electrical
capacity
from
16
MW1
to
1,426
MW.

Oilfired
units
were
costed
based
on
218
units
ranging
in
size
from
25
MW
to
1,028
MW.

Incremental
impacts
associated
with
installing
controls
include
power
to
operate
them,

solid
waste
(
ash)
that
must
be
disposed
of,
water
consumption
where
applicable,
and
wastewater
treatment.
All
of
these
quantities
are
estimated
as
part
of
the
costing
methods
so
that
annual
operating
costs
can
be
found.
Impacts
due
to
compliance
monitoring,
recordkeeping,
and
reporting
are
not
given
here.
They
can
be
found
in
Form
SF­
83
that
is
part
of
the
rulemaking
package.

A
major
impact
is
the
emission
reduction
attributed
to
installation
of
controls.
These
reductions
and
the
costs
and
other
impacts
are
given
on
a
nationwide
basis.
The
modeling
used
for
estimation
is
based
in
part
on
the
individual
units,
but
the
estimate
for
any
single
unit
may
not
be
accurate.
However,
in
the
nationwide
aggregate,
estimates
are
expected
to
be
reasonable.

Tables
1
and
2
show
the
results
for
costs
and
impacts
associated
with
controlling
Hg
emissions
from
coal­
fired
electric
utility
units
and
Ni
from
oil­
fired
electric
utility
units,

respectively.
Table
3
shows
totals
for
the
two
fuel
types.

While
environmental
impacts
are
given
for
all
units,
not
all
are
projected
to
require
costs
for
new
or
upgraded
controls.
Units
that
are
below
the
proposed
emission
limits
would
not
require
equipment
changes.
For
coal­
fired
units,
719
are
estimated
to
require
equipment
changes.

For
oil­
fired
units,
189
are
estimated
to
require
equipment
changes.
These
numbers
are
equivalent
to
63
percent
and
87
percent
of
the
coal­
and
oil­
fired
units,
respectively.

Appendix
A
contains
the
spreadsheets
used
for
generating
costing
equations
and
environmental
impacts
for
coal­
and
oil­
fired
units.
The
spreadsheets
are
of
simple
construction,

but
contain
large
amounts
of
information.
Rows
are
used
for
units
(
one
row
per
unit)
and
columns
are
used
for
input
data
(
e.
g.,
unit
MW)
and
for
cost
or
impact
calculations
(
e.
g.,
capital
cost).
4
Table
1.
Estimated
incremental
impacts
for
coal­
fired
utility
units,
rounded,
in
millions
except
for
mercury
reduction
Unit
type
Capital
cost,

1999
$
Annual
cost,
1999
$/
y
Energy
usage,

kWh/
y
Solid
waste,

tons/
y
Mercury
reductions,

tons/
y
Mercury
reductions,
tons/
y
Water
usage,
gal/
y
(
good
units
under
limit)
(
all
units
at
limit)

Bituminous
4,609
728
89
0.194
14.4
13.3
208
Subbituminous
607
92
4
0.009
2.0
­
1.6
0
Lignite
61
9
0
0.001
0.4
­
0.5
0
Blends
657
101
5
0.009
2.1
1.6
0
IGCC
0
0
0
0.0
0.0
0.0
0
Coal
refuse
57
18
33
0.082
0.1
0.05
117
Total
5,991
948
131
0.300
19.0
12.9
325
"
Good
units"
are
estimated
to
emit
below
proposed
limits
without
adding
new
controls.

Table
2.
Estimated
Incremental
impacts
for
oil­
fired
utility
boiler
emission
reductions,
rounded,
in
millions
except
for
nickel
reductions
Impact
Capital
cost,
Annual
cost,
Energy,
Solid
waste,
Ni
reduction
2001
$
2001
$/
y
kWh/
y
tons/
y
tons/
y
PM
control,
all
plants
2,190
417
1,292
0.002
620
Table
3.
Total
estimated
incremental
impacts
for
coal­
and
oil­
fired
utility
boiler
emission
reductions,
rounded,
in
millions
except
for
mercury
and
nickel
reductions
Impact
Capital
cost
Annual
cost
Energy
Solid
waste
Water
usage
Mercury
reductions,

current
rate
for
good
units
Mercury
reductions,
all
units
at
limit
Nickel
reductions
Units
1999
$
1999
$/
y
kWh/
y
tons/
y
gal/
y
tons/
y
tons/
y
tons/
y
8,181
1,365
1,423
0.302
325
19.0
12.9
620
5
2.0
METHODOLOGY
FOR
ESTIMATING
COST
AND
EMISSION
IMPACTS
2.1
Costs
for
Coal­
fired
Units
A
variety
of
control
strategies
is
available
for
removing
mercury
from
flue
gas.
Data
from
the
1999
information
collection
request
(
ICR)
sent
to
all
electric
utility
owners
and
operators
showed
year­
long
Hg­
in­
coal
concentrations
and,
for
79
units
(
total
of
80
stack
test
reports,
one
tested
twice),
Hg
removal
results
for
the
last
flue­
gas
treatment
device
before
the
unit's
stack.

These
devices
included
ESP,
baghouses,
cyclones,
particle
scrubbers,
wet
flue­
gas
desulfurization
(
FGD)
scrubbers,
and
SDA
desulfurization
systems.
Although
only
79
units
were
tested,
all
units
have
some
form
of
particulate
matter
(
PM)
control
and
many
have
controls
for
sulfur
oxides
and/
or
nitrogen
oxides.

Examination
of
the
data
showed
that
effectiveness
of
these
devices
varied,
and
appeared
to
be
affected
by
factors
such
as
coal
rank,
coal
constituents,
and
upstream
controls
(
e.
g.,
selective
catalytic
reduction
[
SCR],
and
selective
non­
catalytic
reduction
[
SNCR]).
Because
of
the
complexity
of
selecting
specific
systems
for
each
of
the
1,143
electric
utility
units,
and
with
limited
resources
available
for
cost
and
impacts
estimation,
a
simplified
methodology
was
used
for
estimating
costs
and
impacts.

For
each
unit,
an
estimate
was
made
of
its
1999
emission
level
based
on
modeling
with
information
from
the
1999
ICR
(
see
memorandum
Mercury
Emission
Estimates
for
Coal­
fired
Power
Plants,
from
C.
Allen
to
J.
Cole,
December
2003;
note
that
the
memorandum
and
its
associated
spreadsheet
use
an
emission
limit
of
0.52
lb
Hg/
TBtu
for
waste
fuels,
which
was
later
changed
to
0.38
lb
Hg/
TBtu
and
used
for
costs
and
impacts
estimates).
This
estimate
(
minus
the
amount
of
the
limit)
was
divided
by
the
projected
emission
limit
for
the
subcategory
applicable
to
the
unit
to
provide
a
ratio.
Depending
on
the
ratio,
the
unit
was
assigned
a
multiplier
representing
a
fraction
of
the
cost
of
a
new
fabric
filter
and
auxiliaries
sized
for
the
unit.
For
example,
if
a
bituminous
unit
emitted
at
the
rate
of
3
lb
Hg/
TBtu
with
a
limit
of
2
lb
Hg/
TBtu,
the
ratio
would
be
0.5,
or
50
percent
greater
emissions
than
allowed.
For
a
ratio
of
1.5
or
below
(
but
above
0;

units
with
a
ratio
of
0
or
less
would
not
require
further
reductions),
the
assigned
multiplier
was
set
at
0.3.
The
unit
was
estimated
to
be
able
to
come
into
compliance
through
refurbishing,

upgrading,
or
otherwise
altering
its
existing
control
equipment
or
process
for
30
percent
of
the
6
cost
of
a
new
fabric
filter
and
auxiliaries.
This
30
percent
level
represents
judgement
as
to
how
much
money
would
be
required
to
take
whatever
action
is
needed.
For
ratios
between
1.5
and
3,

or
3
and
9,
the
multipliers
were
0.5
or
1,
respectively.
For
ratios
above
9,
the
multiplier
and
associated
baghouse
cost
were
replaced
with
the
cost
of
an
SDA/
baghouse
sized
to
the
unit.

The
Manual
was
used
to
cost
fabric
filters
at
three
sizes
for
each
coal
rank:
100,
500,
and
975
MW
for
bituminous,
subbituminous,
and
lignite.
The
costs
per
MW
(
capital
and
annual)
were
plotted
against
unit
size
in
MW
and
equations
were
developed
from
the
plots.
The
resulting
six
equations
(
three
for
capital
costs
and
three
for
annual
costs)
were
used
as
appropriate
for
the
three
ranks
of
coal,
the
size
of
the
unit,
and
the
amount
of
excess
emissions.
For
example,
if
the
unit
given
above
were
500
MW,
the
equivalent
capital
cost
to
meet
the
emission
limit
would
be
as
shown
in
the
following
equation:

Capital
cost
=
[
8,847
x
ln(
500)
+
14,386]
x
500
x
0.3
=
$
10.4
million
(
1999
dollars).

The
term
in
brackets
represents
the
equation
derived
for
bituminous
coals
as
used
for
a
500
MW
unit.
Because
the
equation
is
on
a
MW
basis,
it
must
be
multiplied
by
the
unit
size
of
500
MW.
Unit
incremental
capital
costs
for
the
fabric
filter
equations
range
from
about
$
55/
kW
to
$
85/
kW
in
1999
dollars.
Appendix
B
gives
the
equations
used
for
cost
and
impact
estimates.

Costing
for
SDA
units
was
based
on
detailed
information
in
a
National
Lime
Association
(
NLA)
document.
2
The
document
provides
capital
and
annual
costs
for
two
500
MW
systems
burning
low­
sulfur
Appalachian
bituminous
coal
and
low­
sulfur
Powder
River
Basin
subbituminous
coal
respectively.
Four
cases
were
costed:
new
units
with
both
coals
and
retrofit
units
with
both
coals.
Unit
costs
for
these
units
ranged
from
$
122/
kW
to
$
163/
kW.

Costs
attributed
to
the
rule
are
incremental,
representing
only
costs
added
to
a
plant's
existing
costs
for
emission
control.
For
example,
costs
of
solid
waste
handling
and
disposal
for
an
existing
ESP
would
be
increased
by
a
relatively
small
amount
for
additional
ash
collected
after
upgrading,
not
by
the
entire
amount
of
ash
handled
in
the
upgraded
unit.
7
2.2
Environmental
Impacts
for
Coal­
fired
Units
The
nationwide
environmental
impacts
shown
in
Table
1,
incremental
increases
in
electricity,
solid
waste,
and
water
(
and
reductions
in
mercury),
were
developed
as
part
of
the
cost
estimates.
All
of
these
incremental
increases
are
required
to
estimate
annual
operating
and
maintenance
costs
and
are
included
in
spreadsheets
based
on
the
Manual.
As
with
capital
and
annual
costs,
equations
were
developed
from
the
costing
spreadsheets
to
estimate
impacts
on
a
MW
basis.
For
the
500
MW
example
given
above,
incremental
electricity
usage
is
found
from
the
following
equation:

Electricity
=
[­
56.224
x
ln(
500)
+
791.88]
x
500
=
221,235
kWh/
y.

Water
usage
for
SDA
units
is
derived
from
the
NLA
document.
Because
the
spray
drier
evaporates
all
of
the
water
used
for
slurrying
calcium
sorbent,
no
dedicated
wastewater
stream
exists.

2.3
Costs
for
Oil­
fired
Units
Unlike
coal­
fired
utility
units,
most
oil­
fired
units
do
not
have
PM
controls.
To
meet
the
proposed
Ni
limitations,
most
units
will
require
the
installation
of
an
ESP
or
fabric
filter.
Although
the
first
fabric
filter
on
a
full­
scale,
oil­
fired
utility
unit
was
installed
in
the
1960s,
the
filters
have
not
become
popular
because
of
safety
concerns.
For
this
reason,
all
units
not
having
an
ESP
were
assumed
to
require
one
at
90
percent
efficiency
to
meet
the
emission
limit.
As
with
coal­
fired
units,
equations
were
developed
to
estimate
costs
as
a
function
of
unit
size
in
MW.
The
equations
were
based
on
unit
sizes
of
150,
370,
and
700
MW.
Costs
were
also
estimated
for
25,
50,
and
70
MW
units
as
a
check
on
smaller
units.
Because
most
units
do
not
have
an
ESP,
the
incremental
costs
include
essentially
all
capital
and
annual
items
at
full
cost.
Table
5
gives
the
equations
used
for
costing.

Credit
was
given
for
units
already
equipped
with
an
ESP.
Similarly,
for
units
having
cyclones
or
multicyclones,
new
ESP
units
were
assumed
to
require
an
efficiency
of
80
percent.

Assuming
a
60­
MW
unit
without
an
existing
ESP
or
multicyclone,
estimated
capital
cost
was
found
from
the
following
equation:
8
Capital
cost
=
[­
162,853
x
ln(
60)
+
813,007)]
x
60
=
$
8,773,842.

Many
of
the
plants
have
two
or
more
relatively
small
units.
These
plants
were
examined
and,
where
it
appeared
feasible,
units
were
combined
to
exhaust
to
one
large
ESP
rather
than
having
a
separate
ESP
for
each
unit.
This
strategy
tended
to
reduce
estimated
capital
and
annual
costs
at
appropriate
plants,
and
is
a
likely
action
for
plants
to
take.

2.4
Environmental
Impacts
for
Oil­
fired
Units
As
with
coal­
fired
units,
environmental
impacts
were
estimated
as
part
of
the
costing
spreadsheets.
For
ESP
units,
only
electricity
and
solid
waste
added
to
environmental
impacts.
For
both
impacts,
the
spreadsheet
values
were
nearly
constant
across
ESP
sizes:
28,873
kWh/
y­
MW
and
0.163
tons/
y­
MW
for
solid
waste.
For
example,
a
60
MW
plant
would
use
the
following
amount
of
electricity:

Electricity
usage
=
28,873
x
60
=
1,732,380
kWh/
y
Note
that
severe
time
constraints
in
preparing
the
cost
and
impact
estimates
(
and
this
memorandum)
have
led
to
using
engineering
judgement
to
a
greater
degree
than
would
ordinarily
be
used.
It
is
likely
that
the
error
bounds
for
these
estimates
are
broader
than
usual.
Also
engineering
judgement
was
used
in
the
emission
factor
bin
assignments
that
lead
to
the
emission
totals
taken
from
the
1999
EU/
ICE
data
national
emissions
model.
This
technique
for
choosing
emission
factors
occasionally
caused
apparently
similarly
configured
units
with
similar
fuel
consumption
to
have
significantly
different
emission
totals..
9
1.
U.
S.
Environmental
Protection
Agency.
EPA
Air
Pollution
Control
Cost
Manual,
sixth
edition.
EPA
­
452­
02­
001.
Office
of
Air
Quality
Planning
and
Standards,
Research
Triangle
Park,
NC.
January
2002.

2.
National
Lime
Association.
Dry
Flue
Gas
Desulfurization
Technology
Evaluation,
Project
Number
11311­
000,
September
26,
2002
3.0
References
10
Appendix
A
Cost
and
Emissions
Impacts
Calculations
See
Excel
Spreadsheets:
Costs­
impacts
Hg
coal­
docket.
xls,
Costs­
impacts
Ni
oil­
docket.
xls,
and
ESP
util­
oil­
docket.
xls
11
Appendix
B
Equations
for
Cost
and
Impacts
Estimates
12
Equations
for
Cost
and
Impacts
Estimates
Cost
and
impacts
equations
for
coal­
fired
utility
units
Coal
rank
Capital
cost,
$/
MW
Annual
cost,
$/(
y­
MW)

Bituminous
8,847
x
ln(
size)
+
14,386
1295.5
x
ln(
size)
+
2,638.6
Subbituminous
8,256.1
x
ln(
size)
+
20,570
3.2078
x
(
size)
+
9,106.6
Lignite
8,047.5
x
ln(
size)
+
27,528
1,233
x
ln(
size)
+
4,430.7
Electricity,
kWh/(
y­
MW)
Solid
waste,
tons/(
y­
MW)
Water,
gal/(
y­
MW)

Bituminous
­
56.224
x
ln(
500)
+
791.88
0.725
x
(
size)
289,000
x
(
size)

Subbituminous
­
58.806
x
ln(
size)
+
828.25
1.112
x
(
size)
359,834
x
(
size)

Lignite
­
58.806
x
ln(
size)
+
828.25
1.317
x
(
size)
414,375
x
(
size)

Cost
and
impacts
equations
for
oil­
fired
utility
units
Capital
cost,
$/
MW
Annual
cost,
$/(
y­
MW)

size
<
83
MW
­
162,853
x
ln(
size)
+
813,007
­
23,373
x
ln(
x)
+
118,878
size
>
83
MW
­
24,890
x
ln(
size)
+
204,138
­
3,538.9
x
ln(
size)
+
31,394
Electricity,
kWh/(
y­
MW)
Solid
waste,
tons/(
y­
MW)

all
sizes
28,873
x
(
size)
0.163
x
(
size)