MEMORANDUM
TO:
Robert
Wayland,
Group
Leader,
Combustion
Group,
OAQPS,
EPA
FROM:
Jim
Eddinger,
Combustion
Group,
OAQPS,
EPA
DATE:
March
15,
2005
SUBJECT:
Statistical
Analysis
of
Mercury
Test
Data
to
Determine
BDT
for
Mercury
Emissions
BACKGROUND
Under
section
111
of
the
Clean
Air
Act,
new
source
performance
standards
(
NSPS)
are
to
established
based
on
best
demonstrated
technology
(
BDT)
considering
cost,
non­
air
quality
environmental
impacts,
and
energy
requirements.
This
memorandum
presents
an
approach
to
determining
an
appropriate
achievable
mercury
(
Hg)
emission
level
for
utility
boilers
fired
with
bituminous
coal,
subbituminous
coal,
lignite
coal,
and
coal
refuse
that
reflects
BDT
by
using
ICR­
3
data.

For
each
coal
type,
ICR­
3
data
were
reviewed
to
identify
the
units
that
were
using
technologies
which
were
most
effective
at
capturing
`
from
coal­
fired
power
plants.
The
technologies
that
appeared
most
effective
in
reducing
Hg
emissions
were
those
that
were
installed,
or
likely
would
be
installed,
to
comply
with
the
current
NSPS
standards
for
particulate
matter
(
PM)
and
sulfur
dioxide
(
SO2).
This
combination
of
controls
was
most
effective
in
reducing
Hg
emissions
and,
thus,
is
considered
BDT.

For
bituminous
coal­
fired
boilers,
BDT
is
considered
to
be
the
combination
of
a
fabric
filter
(
FF)
and
a
flue
gas
desulfurization
(
FGD)
system.
However,
recent
test
data
reports
show
that
a
bituminous
coal­
based
system
including
an
SCR,
ESP,
and
wet
FGD
may
also
be
capable
of
meeting
the
performance
limit
set
for
bituminous
coal­
fired
Utility
Units,
and
this
was
considered
in
setting
the
limit.
The
FGD
may
be
either
a
wet
scrubber
system
or
a
spray
dryer
absorber
(
SDA).
Of
the
27
bituminous
units
listed
in
ICR­
3,
five
units
had
a
combination
of
a
FF
and
a
FGD.
These
units
are
listed
in
Table
1,
along
with
the
control
efficiency,
test
results,
and
the
BDT
statistical
analysis
results.

For
subbituminous
coal­
fired
units,
BDT
was
determined
to
be
depended
on
water
availability.
For
subbituminous
units
that
are
under
potential
water
restriction
in
the
western
United
States
and,
thus,
do
not
have
a
wet
FGD
system
as
an
option
for
SO2
control,
BDT
is
considered
to
be
a
combination
of
a
FF
with
a
SDA
(
a
dry
FGD
system).
For
subbituminous
units
that
are
not
under
water
restrictions,
BDT
is
a
FF
in
combination
with
a
wet
FGD
system.
Of
the
27
subbituminous
units
listed
in
ICR­
3,
two
units
have
controls
representing
BDT
for
the
wet
2
FGD
subbituminous
subcategory
and
four
units
have
controls
representing
BDT
for
the
dry
FGD
subbituminous
subcategory.
These
units
are
listed
in
Table
2,
along
with
the
control
efficiency,
test
results,
and
the
BDT
statistical
analysis
results.

For
lignite
coal­
fired
units,
BDT
is
considered
to
be
either
a
FF/
SDA
system
or
an
ESP
with
a
wet
FGD
system.
Of
the
12
lignite
coal
units
listed
in
ICR­
3,
six
units
have
controls
representing
BDT.
These
units
are
listed
in
Table
3
along
with
the
control
efficiency,
test
result,
and
the
BDT
statistical
analysis
results.

For
coal
refuse,
the
ICR­
3
contain
data
on
only
two
units.
Both
were
fluidized
bed
combustion
(
FBC)
units
equipped
with
fabric
filters.
Both
have
reported
Hg
control
efficiency
of
greater
than
99
percent.
Therefore,
BDT
for
coal
refuse
units
would
appear
to
be
FBC/
FF
combination.
One
unit
fired
waste
anthracite,
the
other
fired
waste
bituminous.

STATISTICAL
ANALYSIS
To
determine
the
appropriate
achievable
Hg
emission
level
for
each
coal
type
that
reflects
BDT,
a
statistical
analysis
was
conducted
to
determine
the
appropriate
control
efficiency
achieved
by
BDT.
That
is,
the
Hg
reduction
efficiency
achievable
for
a
source
using
BDT
at
the
90th
percentile
confidence
limit
using
the
one­
sided
z­
statistics
test
(
i.
e.,
the
control
efficiency
which
BDT
is
estimated
to
be
able
to
achieve
90
percent
of
the
time)
was
determined..

The
statistical
approach
used
was
the
one­
sided
z­
statistics
test
using
the
equation:

confidence
limit
=
average
­
z
*
standard
deviation,

where
the
value
of
z
is
a
function
of
the
degrees
of
freedom
and
obtained
from
the
statistical
table
listing
t
distribution
critical
values.
The
number
of
degrees
of
freedom
for
sample
size
n
is
simply
n­
1
for
a
one­
sample
mean
problem.
The
z
values
used
in
determining
the
90
percentile
confidence
limit
are:

Degrees
of
Freedom
z
value
2
1.886
3
1.638
4
1.533
5
1.476
The
calculated
control
efficiency
for
BDT
was
then
applied
to
the
maximum
annual
average
uncontrolled
Hg
emission
rate
for
that
coal
type
to
determine
the
appropriate
NSPS
Hg
emission
3
limits.
The
maximum
annual
average
uncontrolled
Hg
emission
rate
were
calculated
from
the
annual
average
Hg
fuel
content
values
listed
in
ICR­
3.
This
was
considered
reasonable
since
compliance
with
the
NSPS
will
be
based
on
a
12­
month
rolling
average.
Also
the
maximum
annual
average
Hg
fuel
content
was
used
for
any
unit
in
the
subcategories
because
the
NSPS
is
applicable
nationwide.
Using
the
highest
Hg
fuel
content
ensures
that
the
developed
NSPS
limit
are
achievable
by
a
unit
located
anywhere
in
the
United
States.

Bituminous
Coal
For
bituminous
coal­
fired
units,
the
data
used
consisted
of
Hg
control
efficiency
for
the
5
units
and
the
annual
average
fuel
Hg
content
for
all
bituminous
units.
The
control
efficiency
of
the
5
units
using
BDT
range
from
83.8
percent
(
Intermountain)
to
98.5
percent
(
Mecklenburg
Cogeneration
Facility).
The
annual
average
fuel
Hg
content
for
any
bituminous
coal
unit
range
from
a
low
of
0.0289
ppm
(
Bay
Front
Plant
Generating)
to
0.3186
ppm
(
AES
Cayuga).
However,
the
highest
annual
average
fuel
Hg
content
reported
is
85
percent
higher
than
the
2nd
highest
value
and
is
considered
an
outliner
compared
to
the
other
36
bituminous
units.
Therefore,
the
2nd
highest
annual
average
fuel
Hg
content
of
0.1727
ppm
(
Logan
Generating
Plant)
was
used
to
determine
the
maximum
annual
average
uncontrolled
Hg
emission
rate.

The
average
(
mean)
of
the
control
efficiencies
is
94.8
percent,
and
the
standard
deviation
is
6.2.
Therefore,
using
the
above
equation:

confidence
limit
=
average
­
z
*
standard
deviation
90
percent
confidence
limit
=
94.8
­
1.533
*
6.2
the
achievable
control
efficiency
for
Hg
emissions
reflecting
BDT
for
bituminous
coal­
fired
units
is
85
percent.

Since
the
Hg
emissions
from
any
control
system
is
a
linear
function
of
the
inlet
Hg
fuel,
assuming
a
constant
control
efficiency,
the
achievable
Hg
emission
limit
reflecting
BDT
for
bituminous
coal
units
was
calculated
by
applying
the
85
percent
reduction
to
the
the
maximum
annual
average
uncontrolled
Hg
emission
rate.
Therefore,
the
achievable
Hg
emission
limit
reflecting
BDT
for
bituminous
coal
units
is
1.96
lbHg/
trillion
Btu.
The
analysis
results
are
reported
in
Table
1.

Subbituminous
Coal
For
subbituminous
coal­
fired
units,
the
same
approach
was
performed
as
for
bituminous
coal
units,
except
that
the
analysis
was
performed
for
the
two
subcategories
of
subbituminous
units
(
wet
FGD
and
dry
FGD).

Wet
FGD
units
4
The
control
efficiency
of
the
2
units
using
BDT
range
are
82.6
percent
(
Clay
Boswell
2)
and
62.6
percent
(
Comanche).
Both
of
these
unit
are
controlled
only
with
a
FF,
but
are
considered
to
reflect
BDT
since
the
addition
of
a
wet
FGD
would
only
enhance
the
Hg
removal
achieved
by
the
FF.
There
are
no
subbituminous
coal
units
listed
in
ICR­
3
that
have
a
combination
of
a
FF
and
a
wet
FGD.
The
annual
average
fuel
Hg
content
for
any
subbituminous
coal
unit
range
from
a
low
of
0.0254
ppm
(
Craig)
to
0.1558
ppm
(
Jack
Watson).
However,
the
highest
annual
average
fuel
Hg
content
reported
is
46
percent
higher
than
the
2nd
highest
value
and
is
considered
an
outliner
compared
to
the
other
34
subbituminous
units.
Therefore,
the
2nd
highest
annual
average
fuel
Hg
content
of
0.0918
ppm
(
San
Juan)
was
used
to
determine
the
maximum
annual
average
uncontrolled
Hg
emission
rate.

The
average
(
mean)
of
the
control
efficiencies
is
72.4
percent,
and
the
standard
deviation
is
12.9.
Therefore,
using
the
above
equation:

confidence
limit
=
average
­
z
*
standard
deviation
90
percent
confidence
limit
=
72.4
­
1.476
*
12.9
the
achievable
control
efficiency
for
Hg
emissions
reflecting
BDT
for
wet
FGD
subbituminous
coal
units
is
53
percent.
Therefore,
the
achievable
Hg
emission
limit
reflecting
BDT
for
wet
FGD
subbituminous
coal
units
calculated
by
applying
the
53
percent
reduction
to
the
the
maximum
annual
average
uncontrolled
Hg
emission
rate
is
4.0
lbHg/
TBtu.
The
analysis
results
are
reported
in
Table
2.

Dry
FGD
units
The
control
efficiency
of
the
4
units
using
BDT
range
from
23.8
percent
(
Sherburne
County
Generation
Plant)
to
52.5
percent
(
AES
Hawaii).
The
annual
average
fuel
Hg
content
for
any
subbituminous
coal
unit
range
from
a
low
of
0.0254
ppm
(
Craig)
to
0.1558
ppm
(
Jack
Watson).
However,
the
highest
annual
average
fuel
Hg
content
reported
is
46
percent
higher
than
the
2nd
highest
value
and
is
considered
an
outliner
compared
to
the
other
34
subbituminous
units.
Therefore,
the
2nd
highest
annual
average
fuel
Hg
content
of
0.0918
ppm
(
San
Juan)
was
used
to
determine
the
maximum
annual
average
uncontrolled
Hg
emission
rate.

The
average
(
mean)
of
the
control
efficiencies
is
35.4
percent,
and
the
standard
deviation
is
12.15.
Therefore,
using
the
above
equation:

confidence
limit
=
average
­
z
*
standard
deviation
90
percent
confidence
limit
=
35.4
­
1.638
*
12.15
the
achievable
control
efficiency
for
Hg
emissions
reflecting
BDT
for
dry
FGD
subbituminous
coal
units
is
16
percent.
Therefore,
the
achievable
Hg
emission
limit
reflecting
BDT
for
dry
FGD
subbituminous
coal
units
calculated
by
applying
the
16
percent
reduction
to
the
the
maximum
annual
average
uncontrolled
Hg
emission
rate
is
7.4
lbHg/
TBtu.
The
analysis
results
are
reported
5
in
Table
3.

Lignite
Coal
For
lignite
coal
units,
the
control
efficiency
of
the
6
units
using
BDT
range
from
33.3
percent
(
Antelope
Valley
Station)
to
57
percent
(
TNP­
One).
Two
(
Heskett
Station
and
TNPOne
of
the
6
units
are
fluidized
bed
combustion
(
FBC)
units
which
serves
as
a
dry
SO2
control.
The
annual
average
fuel
Hg
content
for
any
lignite
coal
unit
range
from
a
low
of
0.0620
ppm
(
TNP­
One
which
was
doubled
from
the
reported
value
in
ICR­
3
based
on
later
submitted
information)
to
0.1754
ppm
(
Monticello).
The
highest
annual
average
fuel
Hg
content
of
0.1754
ppm
was
used
to
determine
the
maximum
annual
average
uncontrolled
Hg
emission
rate.

The
average
(
mean)
of
the
control
efficiencies
is
44.6
percent,
and
the
standard
deviation
is
8.8.
Therefore,
using
the
above
equation:

confidence
limit
=
average
­
z
*
standard
deviation
90
percent
confidence
limit
=
44.6
­
1.476
*
8.8
the
achievable
control
efficiency
for
Hg
emissions
reflecting
BDT
for
lignite
coal
units
is
32
percent.
Therefore,
the
achievable
Hg
emission
limit
reflecting
BDT
for
lignite
coal
units
calculated
by
applying
the
32
percent
reduction
to
the
maximum
annual
average
uncontrolled
Hg
emission
rate
is
13.7
lbHg/
TBtu.
The
analysis
results
are
reported
in
Table
4.

For
coal
refuse
units,
the
approach
was
similar
except
that
no
statistical
analysis
of
the
control
efficiency
was
performed
since
the
reported
control
efficiency
for
both
units
both
was
99.9
percent.
Both
units
are
FBC
boilers
with
FF.
One
unit
combust
waste
anthracite,
the
other
combust
waste
bituminous.
The
highest
annual
average
Hg
fuel
content
is
0.7029
ppm
for
waste
bituminous.
The
achievable
Hg
emission
limit
reflecting
BDT
calculated
by
applying
the
BDT
control
efficiency
of
99.9
percent
to
the
maximum
annual
average
uncontrolled
Hg
emission
rate
is
0.13
lbHg/
TBtu.

Conversation
to
Output­
Based
Units
The
output­
based
equivalent
Hg
emission
limits
of
the
BDT
emission
limits
(
lb
Hg/
TBtu
heat
input)
calculated
above
can
be
computed
by
using
the
following
equation:

Eo(
lb/
MWh)
=
Ei(
lb/
million)
x
n(
heat
rate)
x
1000
kwh/
Mwh.
For
bituminous
coal­
fired
units
the
output­
based
BDT
limit
would
be:
Eo(
lb/
MWh)
=
1.96
lb/
trillion
x
10,667
Btu/
kwh
x
1000
kwh/
Mwh.
x
0.000001
where
0.000001
is
the
conversion
factor
from
TBtu
to
million
Btu
OR
Eo(
lb/
MWh)
=
1.96
lb/
trillion
x
1.056
where
1.056
is
the
conversion
factor
from
lb/
TBtu
to
lb
x
10­
5
lb/
Mwh
6
Therefore,
for
bituminous
coal
Eo(
lb/
MWh)
=
0.000021lb/
Mwh
or
2.1
x
10­
5
lb/
Mwh
The
output­
based
Hg
limits
for
each
coal
type
would
be:

bituminous
coal
=
2.1
x
10­
5
lb/
Mwh
subbituminous
coal
(
wet
FGD
units)
=
4.2
x
10­
5
lb/
Mwh
subbituminous
coal
(
dry
FGD
units)
=
7.8
x
10­
5
lb/
Mwh
lignite
coal
=
14.5
x
10­
5
lb/
Mwh
coal
refuse
=
0.14
x
10­
5
lb/
Mwh
Permit
Information
Recent,
available
permit
Hg
levels
were
evaluated
for
comparison
with
the
limits
presented
above.
The
available
permit
information
is
presented
in
Appendix
A.
Comparison
of
the
available
permit
limits
with
those
developed
above
is
a
valid
"
reality
check"
on
the
appropriateness
of
NSPS's
limits
determined
above
that
reflect
BDT.
Available
permits
on
bituminous­
fired
units
have
Hg
emission
limits
ranging
from
approximately
2.0
x
10­
5
lb/
MWh
to
3.9
x
10­
5
lb/
MWh;
those
for
subbituminous­
fired
units
range
from
1.1
x
10­
5
lb/
MWh
to
12.6
x
10­
5
lb/
MWh.
Considering
the
limited
number
of
permits
and
the
limited
experience
in
developing
appropriate
Hg
limits
for
those
permits,
the
NSPS
Hg
emission
limits
developed
above
are
in
reasonable
agreement
with
these
permits.
Insufficient
permit
information
is
available
to
do
a
similar
comparison
for
lignite­
and
coal
refuse­
fired
units
but
we
have
used
the
same
analytic
procedure
for
these
subcategories.
7
TABLE
1
MERCURY
DATA
FOR
BITUMINOUS
COAL­
FIRED
UTILITY
BOILERS
USED
FOR
DETERMINING
BDT
BDT:
Fabric
filter
and
spray
dryer
absorber
OR
Fabric
filter
and
wet
FGD
Units
using
BDT:

Plant
Name
Unit
Name
Controls
Test
Average
(
lb/
TBtu)
Control
Efficiency
(%)
Fuel
Hg
content
during
test
(
ppm)
Annual
Average
fuel
Hg
content
(
ppm)
Mecklenburg
Cogeneration
Facility
GEN
1
FF/
SDA
0.1062
98.5
0.0967
0.0932
SEI
­
Birchwood
Power
Facility
1
FF/
SDA/
SCR
0.2379
97.2
0.1100
0.1470
Logan
Generating
Plant
GEN
1
FF/
SDA/
SCR
0.3348
97.8
0.1800
0.1727
Clover
Power
Station
2
FF/
WS
0.3529
96.7
0.1594
0.0978
Intermountain
2SGA
FF/
WS
0.2466
83.8
0.0233
0.0391
Average
percent
reduction
of
BDT
units:
94.8
percent
Standard
deviation:
6.2
Percent
reduction
of
BDT:
85
percent
Highest
annual
average
Hg
content
used:
0.1727
ppm
(
Logan
Generating
Plant)
Maximum
annual
average
uncontrolled
Hg
emission
rate:
13.3
lb/
T
Btu
Basis
for
calculated
uncontrolled
emission
rate:
Annual
average
fuel
Hg
content
=
0.1727
ppm
Average
heat
content
of
bituminous
coal
=
13,000
Btu/
lb
(
Steam)
8
TABLE
2
MERCURY
DATA
FOR
SUBBITUMINOUS
COAL
­
WET
FGD
UNITS
USED
FOR
DETERMINING
BDT
BDT:
Fabric
filter
and
wet
FGD
Units
using
BDT:

Plant
Name
Unit
Name
Controls
Test
Average
(
lb/
TBtu)
Control
Efficiency
(%)
Fuel
Hg
content
during
test
(
ppm)
Annual
Average
fuel
Hg
content
(
ppm)
Clay
Boswell
2
FF
0.6633
86.0
0.0567
0.0701
Comanche
2
FF
2.5931
65.8
0.0922
0.0767
Average
percent
reduction
of
BDT
units:
72.4
percent
Standard
deviation:
12.9
Percent
reduction
of
BDT:
53
percent
Highest
annual
average
Hg
content
used:
0.0918
ppm
(
San
Juan)
Maximum
annual
average
uncontrolled
Hg
emission
rate:
8.7
lb/
T
Btu
Basis
for
calculated
uncontrolled
emission
rate:
Annual
average
fuel
Hg
content
=
0.0918
ppm
Average
heat
content
of
bituminous
coal
=
12,280
Btu/
lb
(
Steam)

TABLE
3
MERCURY
DATA
FOR
SUBBITUMINOUS
COAL
­
DRY
FGD
UNITS
USED
FOR
DETERMINING
BDT
BDT:
Fabric
filter
and
SDA
Units
using
BDT:
Plant
Name
Unit
Name
Controls
Test
Average
(
lb/
TBtu)
Control
Efficiency
(%)
Fuel
Hg
content
during
test
(
ppm)
Annual
Average
fuel
Hg
content
(
ppm)
AES
Hawaii
A
FBC/
FF
0.4606
52.5
0.0267
0.0279
Craig
3
FF/
SDA
0.7248
33.6
0.0100
0.0254
Sherburne
County
3
FF/
SDA
7.5401
23.8*
0.0800
0.0528
Rawhide
101
FF/
SDA
7.7630
31.8
0.0733
0.0469
*
Run
1
control
efficiency,
runs
2
and
3
were
unrealistic
and
not
used.

Average
percent
reduction
of
BDT
units:
35.4
percent
Standard
deviation:
12.15
Percent
reduction
of
BDT:
16
percent
Highest
annual
average
Hg
content
used:
0.0918
ppm
(
San
Juan)
Maximum
annual
average
uncontrolled
Hg
emission
rate:
8.7
lb/
T
Btu
Basis
for
calculated
uncontrolled
emission
rate:
Annual
average
fuel
Hg
content
=
0.0918
ppm
Average
heat
content
of
bituminous
coal
=
12,280
Btu/
lb
(
Steam)
9
10
TABLE
4
MERCURY
DATA
FOR
LIGNITE
COAL
USED
FOR
DETERMINING
BDT
BDT:
Fabric
filter
and
SDA
Units
using
BDT:
Plant
Name
Unit
Name
Controls
Test
Average
(
lb/
TBtu)
Control
Efficiency
(%)
Fuel
Hg
content
during
test
(
ppm)
Annual
Average
fuel
Hg
content
(
ppm)
R.
M.
Heskett
Station
B2
ESP­
CS
3.9768
56.1
0.0863
0.0881
Coyote
1
FF/
SDA
7.9523
38.2
0.1107
0.1348
Limestone
1
ESP/
WS
13.6612
51.0
0.1390
0.1460
Monticello
3
ESP/
WS
18.3232
47.6
0.4150
0.1754
Antelope
Valley
Station
B1
FF/
SDA
4.0042
65.7
0.0620
0.0658
TNP­
One
U2
FF
10.8596
59.2
0.2547
0.0620*

*
ICR­
3
value
doubled
based
on
later
data
received
Average
percent
reduction
of
BDT
units:
44.6
percent
Standard
deviation:
8.8
Percent
reduction
of
BDT:
32
percent
Highest
annual
average
Hg
content
used:
0.1754
ppm
(
Monticello)
Maximum
annual
average
uncontrolled
Hg
emission
rate:
20.1
lb/
T
Btu
Basis
for
calculated
uncontrolled
emission
rate:
Annual
average
fuel
Hg
content
=
0.1754
ppm
Average
heat
content
of
bituminous
coal
=
8,735
Btu/
lb
(
Steam)

TABLE
4
MERCURY
DATA
FOR
COAL
REFUSE­
FIRED
UTILITY
BOILERS
USED
FOR
DETERMINING
BDT
Plant
Name
Unit
Name
Fuel
Controls
Test
Average
(
lb/
TBtu)
Control
Efficiency
(%)
Fuel
Hg
content
during
test
(
ppm)
Annual
Average
fuel
Hg
content
(
ppm)

Kline
Township
Cogen
Facility
GEN
1
Waste
Anthracite
FBC/
FF
0.0816
99.9
0.3333
0.1733
Scrubgrass
Generating
Company
GEN
1
Waste
Bituminous
FBC/
FF
0.0936
99.9
0.5267
0.7029
.
11
12
APPENDIX
A
13
Table
1.
Summary
of
Approved
State
Air
Permits
with
Mercury
Emission
Limitations
for
Coal­
Fired
Electric
Utility
Steam
Generating
Units
Category
State
Permitting
Authority
Electric
Utility
Source
Permit
Information
Project
Status
Comments
Name
Boiler
Type
Unit
Capacity
Type
Approval
Date
Hg
Emissions
Limitation
Bituminous
Illinois
EPA
Prairie
State
Generating
Co.

Prairie
State
Generating
Station
Units
1
and
2
PC
750
MW
(
each
unit)
Construction
1­
14­
2005
Federal
NESHAP
limit
Illinois
EPA
Corn
Belt
Energy
Corporation
Prairie
Energy
Power
Plant
PC
91
MW
Construction
12­
17­
2002
4
x
10­
6
lb/
MMBtu
heat
input
Illinois
EPA
Indeck­
Elwood
LLC
(
Indeck)
CFB
660
MW
Construction
10­
10­
2003
2
x
10­
6
lb/
MMBtu
heat
input
South
Carolina
DHEC
Santee
Cooper
Power
Cross
Generating
Station
Units
3
and
4
PC
660
MW
(
each
unit)
Construction
2­
5­
2004
3.6
x
10­
6
lb/
MMBtu
heat
input
Under
construction
Facility
subject
to
consent
decree
with
EPA
Kentucky
DEP
Thoroughbred
Generating
Station
Units
1
and
2
PC
750
MW
(
each
unit)
Construction
10­
11­
2002
3.21
x
10­
6
lb/
MMBtu
heat
input
Kentucky
DEP
Hugh
L.
Spurlock
Power
Station
CFB
270
MW
Air
Quality
Permit
8­
4­
2002
2.65
x
10­
6
lb/
MMBtu
heat
input
West
Virginia
DEP
Longview
Power
PC
600
MW
Construction
3­
2­
2004
1.46
x
10­
2
lb/
hr
based
on
a
3­
hour
average
and
6.38
x
10­
2
TPY
based
on
12
month
rolling
average.

Subbituminous
Iowa
DNR
MidAmerican
Energy
Co.

Council
Bluffs
Energy
Center
Unit
4
PC
790
MW
Construction
6­
17­
2003
1.7
x
10­
6
lb/
MMBtu
heat
input
PRB
coal
Supercritical
boiler
Sorbent
injection
Utah
DEQ
Sevier
Power
Company's
NEVCO
Energy
CFB
270
MW
Air
Quality
Permit
10­
12­
2004
4
x
10­
7
lb/
MMBtu
heat
input
Burns
a
mixture
of
western
bituminous
/
western
(
non
SRB)
subbituminous
coal
Arkansas
ADEQ
Plum
Point
Energy
Associates
PC
550­
800
MW
Operating
8­
20­
2003
12.8
x
10­
6
lb/
MMBtu
heat
input
Montana
DEQ
Bull
Mountain
Energy
Roundup
Power
Plant
Units
1
and
2
PC
390
MW
(
each
unit)
MACT
7­
25­
2003
3.23
x
10­
6
lb/
MMBtu
heat
input
Montana
DEQ
Rocky
Mountain
Power
Hardin
Generation
Project
PC
113
MW
Air
Quality
Permit
12­
22­
2004
5.8
lb/
TBtu
heat
input
based
on
1­
hour
average
Permit
decision
under
appeal
Existing
unit
permit
revision
triggered
by
reconstruction
Table
1
(
Continued)

Category
State
Permitting
Authority
Electric
Utility
Source
Permit
Information
Project
Status
Comments
Name
Boiler
Type
Unit
Capacity
Type
Approval
Date
Hg
Emissions
Limitation
14
Missouri
DNR
City
Utilities
of
Springfield
Southwest
Power
Station
Unit
2
PC
275
MW
Construction
12­
15­
2004
7.5
x
10­
6
lb/
MMBtu
heat
input
Arizona
DEQ
Tucson
Electric
Power
Company
Springerville
Units
3
and
4
PC
400
MW
(
each
unit)
Air
Quality
Permit
2­
14­
2002
6.9
x
10­
6
lb/
MMBtu
heat
input
Wisconsin
DER
WE
Energies
Elm
Road
Generating
Station
PC
615
MW
(
each
unit)
Construction
1­
14­
2004
1.12
lb/
TBtu
heat
input
in
any
12­
consecutive
months
PRB
coal
Supercritical
boiler
Wisconsin
Public
Service
Corp.

Weston
Plant
PC
500
MW
Construction
10­
19­
2004
1.7
lb/
TBtu
heat
input
in
any
12­
consecutive
months
Permit
decision
under
appeal
PRB
coal
Supercritical
boiler
Sorbent
injection
Lignite
Texas
TCEQ
Texas­
New
Mexico
Power
Company
TNP
One
Units
1
and
2
CFB
175
MW
(
each
unit)
Air
Quality
Permit
5­
12­
1987
Maximum
Allowable
Emission
Rates
0.3
lb/
hr,
1.3
TPY
Permit
to
construct
and
operate
Issued
5/
12/
87
Texas
TCEQ
Alcoa's
Rockdale
Power
Plant
CFB
1and
CFB
2
CFB
216.5
MW
Net
(
each
unit)
Air
Quality
Permit
10­
25­
2003
Maximum
Allowable
Emission
Rates
0.033
lb/
hr,
0.048
TPY
While
these
units
will
be
industrial
boilers
at
a
primary
aluminum
plant
they
are
fed
by
a
minemouth
facility
and
by
permit
must
meet
40
CFR
Part
60
Subparts
A
and
Da.

IGCC
No
units
of
this
design
have
been
permitted
Coal
refuse
Kentucky
DEP
Kentucky
Mountain
Power
CFB
250
MW
Construction
6­
15­
2000
81
x
10­
6
lb/
MMBtu
heat
input
Coal
refuse/
coal
Illinois
EPA
EnviroPower
of
Illinois,
LLC
CFB
250
MW
(
each
unit)
Construction
7­
3­
2001
4
x
10­
6
lb/
MMBtu
heat
input
Burns
a
mixture
of
bituminous
coal
refuse
(
culm)
and
bituminous
coal
15
Table
2.
Summary
of
Air
Pollution
Control
Configfurations
for
Coal­
Fired
Electric
Utility
Steam
Generating
Units
With
Approved
State
Air
Permits
with
Mercury
Emission
Limitations
Category
Electric
Utility
Source
Air
Emission
Control
Configuration
Comments
Name
Boiler
Type
Unit
Capacity
Combustion
Controls
Post­
Combustion
Control
Sequence
Bituminous
Prairie
State
Generating
Co.

Prairie
State
Generating
Station
Units
1
and
2
PC
750
MW
(
each
unit)
Low­
NO
x
burners
SCR
ESP
Wet
FGD
Scrubber
Wet
ESP
Corn
Belt
Energy
Corporation
Prairie
Energy
Power
Plant
PC
91
MW
Low­
NO
x
burners/
staged
combustion
SCR
ESP
Wet
FGD
Scrubber
Indeck­
Elwood
LLC
(
Indeck)
CFB
660
MW
SNCR
Lime
Injection
Fabric
Filter
Santee
Cooper
Power
Cross
Generating
Station
Units
3
and
4
PC
660
MW
(
each
unit)
SCR
ESP
Wet
FGD
Scrubber
Thoroughbred
Generating
Station
Units
1
and
2
PC
750
MW
(
each
unit)
Low­
NO
x
burners
SCR
ESP
Wet
FGD
Scrubber
Wet
ESP
Hugh
L.
Spurlock
Power
Station
CFB
270
MW
SNCR
Lime
Injection
Fabric
Filter
Longview
Power
PC
600
MW
Low­
NO
x
burners
SCR
Wet
FGD
Scrubber
Fabric
Filter
Subbituminous
MidAmerican
Energy
Co.

Council
Bluffs
Energy
Center
Unit
4
PC
790
MW
Low­
NO
x
burners
SCR
Activated
Carbon
Injection
Lime
Spray
Dryer
Fabric
Filter
Sevier
Power
Company's
NEVCO
Energy
CFB
270
MW
SNCR
Lime
Injection
Lime
Spray
Dryer
Fabric
Filter
Burns
a
mixture
of
western
bituminous
/
western
(
non
SRB)
subbituminous
coal
Plum
Point
Energy
Associates
PC
550­
800
MW
SCR
Wet
FGD
Scrubber
Fabric
Filter
Bull
Mountain
Energy
Roundup
Power
Plant
Units
1
and
2
PC
390
MW
(
each
unit)
Low­
NO
x
burners
SCR
Lime
Spray
Dryer
PJ
Fabric
Filter
Rocky
Mountain
Power
Hardin
Generation
Project
PC
113
MW
SCR
Lime
Spray
Dryer
Fabric
Filter
City
Utilities
of
Springfield
Southwest
Power
Station
Unit
2
PC
275
MW
Low­
NO
x
burners
SCR
Activated
Carbon
Injection
(
Note
A)
Lime
Spray
Dryer
Fabric
Filter
Table
2
(
Continued)

Category
Electric
Utility
Source
Air
Emission
Control
Configuration
Comments
Name
Boiler
Type
Unit
Capacity
Combustion
Controls
Post­
Combustion
Control
Sequence
16
Tucson
Electric
Power
Company
Springerville
Units
3
and
4
PC
400
MW
(
each
unit)
Low­
NO
x
burners
SCR
Lime
Spray
Dryer
Fabric
Filter
WE
Energies
Elm
Road
Generating
Station
PC
615
MW
(
each
unit)
Low­
NO
x
burners
SCR
ESP
Wet
FGD
Scrubber
Wet
ESP
Wisconsin
Public
Service
Corp.

Weston
Plant
PC
500
MW
Low­
NO
x
burners
SCR
Activated
Carbon
Injection
Lime
Spray
Dryer
Fabric
Filter
Lignite
Texas­
New
Mexico
Power
Company
TNP
One
Units
1and
2
CFB
175
MW
(
each
unit)
Lime
Injection
Fabric
Filter
Alcoa's
Rockdale
Power
Plant
CFB
1and
CFB
2
CFB
216.5
MW
Net
(
each
unit)
SNCR
Lime
Injection
Fabric
Filter
IGCC
No
units
of
this
design
have
been
permitted
Coal
refuse
Kentucky
Mountain
Power
CFB
250
MW
SCNR
Lime
Injection
Fabric
Filter
EnviroPower
of
Illinois,
LLC
CFB
250
MW
(
each
unit)
SNCR
Lime
Injection
Fabric
Filter
Burns
a
mixture
of
bituminous
coal
refuse
(
culm)
and
bituminous
coal
Note
A.
The
entity
building
this
plant
decided
to
include
as
a
part
of
this
project
the
emissions
associated
with
a
potential
Hg
control
system.
The
entity
building
this
plant
is
anticipating
controlling
Hg
emissions
by
means
of
injecting
powdered
activated
carbon.
However,
a
final
decision
as
to
the
exact
method
of
Hg
control
has
not
been
made.
The
entity
building
this
plant
does
plan
on
installing
some
type
of
Hg
control,
but
is
holding
off
making
a
final
decision
until
a
later
date
so
that
the
most
effective
system
of
Hg
control
that
has
been
shown
to
be
compatible
with
the
NO
X,
PM,
and
SO
X
pollution
control
technologies
can
be
determined.
If
the
Hg
control
is
not
powdered
activated
carbon,
then
it
will
be
at
least
as
effective.
17
Table
3.
Summary
of
Mercury
Emission
Limitations
for
Coal­
Fired
Electric
Utility
Steam
Generating
Units
Category
Electric
Utility
Source
Emission
Limits
Comments
Name
Permit
Hg
Emissions
Limitation
Converted
to
input­
based
Emissions
Limitation
Converted
to
output­
based
Emissions
Limitation
Bituminous
Prairie
State
Generating
Co.

Prairie
State
Generating
Station
Units
1
and
2
Federal
NESHAP
limit
NA
NA
No
defined
emission
limit
Corn
Belt
Energy
Corporation
Prairie
Energy
Power
Plant
4
x
10­
6
lb/
MMBtu
heat
input
4
lb/
TBtu
3.9
x
10­
5
lb/
MWh
A
Indeck­
Elwood
LLC
(
Indeck)
2
x
10­
6
lb/
MMBtu
heat
input
2
lb/
TBtu
2
x
10­
5
lb/
MWh
A
Santee
Cooper
Power
Cross
Generating
Station
Units
3
and
4
3.6
x
10­
6
lb/
MMBtu
heat
input
3.6
lb/
TBtu
3.5
x
10­
5
lb/
MWh
A
Thoroughbred
Generating
Station
Units
1
and
2
3.21
x
10­
6
lb/
MMBtu
heat
input
3.21
lb/
TBtu
3.2
x
10­
5
lb/
MWh
A
Hugh
L.
Spurlock
Power
Station
2.65
x
10­
6
lb/
MMBtu
heat
input
2.65
lb/
TBtu
2.6
x
10­
5
lb/
MWh
A
Longview
Power
1.46
x
10­
2
lb/
hr
based
on
a
3­
hour
average
and
6.38
x
10­
2
TPY
based
on
12
month
rolling
average.
2.4
lb/
TBtu
2.3
x
10­
5
lb/
MWh
A,
B
Subbituminous
MidAmerican
Energy
Co.

Council
Bluffs
Energy
Center
Unit
4
1.7
x
10­
6
lb/
MM
Btu
heat
input
1.7
lb/
TBtu
1.7
x
10­
5
lb/
MWh
A
Sevier
Power
Company's
NEVCO
Energy
4
x
10­
7
lb/
MM
Btu
heat
input
0.4
lb/
TBtu
0.39
x
10­
5
lb/
MWh
A
Plum
Point
Energy
Associates
12.8
lb/
TBtu
heat
input
12.8
lb/
TBtu
12.6
x
10­
5
lb/
MWh
A
Bull
Mountain
Energy
Roundup
Power
Plant
Units
1
and
2
3.23
x
10­
6
lb/
MMBtu
heat
input
3.23
lb/
TBtu
3.2
x
10­
5
lb/
MWh
A
Rocky
Mountain
Power
Hardin
Generation
Project
5.8
lb/
TBtu
heat
input
based
on
1­
hour
average
5.8
lb/
T
Btu
5.7
x
10­
5
lb/
MWh
A
City
Utilities
of
Springfield
Southwest
Power
Station
Unit
2
7.5
x
10­
6
lb/
MMBtu
heat
input
7.5
lb/
TBtu
7.4
x
10­
5
lb/
MWh
A
Table
3
(
Continued)

Category
Electric
Utility
Source
Emission
Limits
Comments
Name
Permit
Hg
Emissions
Limitation
Converted
to
input­
based
Emissions
Limitation
Converted
to
output­
based
Emissions
Limitation
18
Tucson
Electric
Power
Company
Springerville
Units
3
and
4
6.9
x
10­
6
lb/
MMBtu
heat
input
6.9
lb/
TBtu
6.8
x
10­
5
lb/
MWh
A
WE
Energies
Elm
Road
Generating
Station
1.12
lb/
TBtu
heat
input
in
any
12­
consecutive
months
1.12
lb/
TBtu
1.1
x
10­
5
lb/
MWh
A
Wisconsin
Public
Service
Corp.

Weston
Plant
1.7
lb/
TBtu
heat
input
in
any
12­
consecutive
months
1.7
lb/
TBtu
1.7
x
10­
5
lb/
MWh
A
Lignite
Texas­
New
Mexico
Power
Company
TNP
One
Units
1
and
2
Maximum
Allowable
Emission
Rates
0.3
lb/
hr,
1.3
TPY
190
lb/
TBtu
186
x
10­
5
lb/
MWh
A,
C,
D
Alcoa's
Rockdale
Power
Plant
CFB
1and
CFB
2
Maximum
Allowable
Emission
Rates
0.033
lb/
hr,
0.048
TPY
3.7
lb/
TBtu
3.6
x
10­
5
lb/
MWh
A,
E
IGCC
No
units
of
this
design
have
been
permitted
2
x
10­
5
lb/
MWh
F
Coal
refuse
Kentucky
Mountain
Power
81
x
10­
6
lb/
MMBtu
heat
input
81
lb/
TBtu
80
x
10­
5
lb/
MWh
A,
G
Coal
refuse/
coal
EnviroPower
of
Illinois,
LLC
4
x
10­
6
lb/
MMBtu
heat
input
4
lb/
TBtu
3.9
x
10­
5
lb/
MWh
A,
H
Notes:

A
The
emission
limits
were
converted
from
input­
based
standard
(
lb/
TBtu)
to
output­
based
standard
(
lb/
MWh)
by
multiplying
by
9.8
x
10­
6.
This
factor
incorporates
a
35
percent
efficiency
is
10
joules
per
watt
hour
(
J/
Wh)
(
9,833
Btu
per
kilowatt
hour
(
kWh)).

B
Based
on
a
boiler
capacity
of
6,114
MMBtu/
hr.
A
permitted
emission
limit
of
6.38
x
10­
2
TPY
*
2000
lb/
T
/
8760
hr/
yr
/
6,114
MMBtu/
hr
=
2.4
x
10­
6
lb/
MMBtu
or
2.4
lb/
Tbtu.
2.4
lb/
Tbtu
*
9.8
x
10­
6
=
2.3
x10­
5
lb/
MWh.

C
Based
on
EPA
ICR
stack
testing
done
on
10/
6
­
10/
8/
99.
While
testing
the
coal
feed
averaged
234,897
lb/
hr.
The
heat
content
of
the
coal
averaged
6670
Btu/
lb.
234,897
lb/
hr
*
6670
Btu/
lb
/
1,000,000
=
1,566.6
MMBtu/
hr.
A
permitted
emission
limit
of
1.3
TPY
*
2000
lb/
T
/
8760
hr/
yr
/
1,566.6
MMBtu/
hr
=
1.90
x
10­
4
lb/
MMBtu
or
190
lb/
Tbtu.
190
lb/
Tbtu
*
9.8
x
10­
6
=
186
x10­
5
lb/
MWh.

D
This
permit
level
predates
the
1990
Amendments
to
the
CAA
so
we
would
not
give
it
much
credence.
There
appear
to
be
no
other
new
or
existing
lignite­
fired
units
with
a
Hg
emission
limit.

E
Based
on
a
boiler
capacity
of
2,960
MMBtu/
hr.
A
permitted
emission
limit
of
0.048
TPY
*
2000
lb/
T
/
8760
hr/
yr
/
2,960
MMBtu/
hr
=
3.7
x
10­
6
lb/
MMBtu
or
3.7
lb/
Tbtu.
3.7
lb/
Tbtu
*
9.8
x
10­
6
=
3.6
x10­
5
lb/
MWh.

F
The
are
currently
no
units
of
this
design
(
IGCC)
have
been
permitted.
However
it
is
prudent
to
promulgate
a
new
emissions
limit.
For
this
limit
we
used
the
ICR
proposed
emission
limit
data
from
the
only
two
IGCC
units
in
the
country.

G
This
is
a
very
high
limit
for
a
bituminous
coal
refuse
(
culm)­
fired
unit
with
this
furnace
type
and
these
controls.
We
called
Kentucky
DEP
and
asked
about
the
limit
and
they
also
noted
it
was
very
high
and
wondered
why
it
hadn't
been
challenged.

H
This
unit
is
permitted
to
fire
a
mixture
of
waste
bituminous
(
culm)
and
bituminous
coal
therefore
it
is
not
strictly
a
coal
refuse­
fired
unit.
