Document ID: EPA-HQ-OAR-2003-0053-0171
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2004-01-29T05:00Z

ATTACHMENT
1
September
24,
2003
Email
from
J.
Lee
of
ICF
"
Lee,
Jason"
<
JLee@
icfconsulting.
com>
09/
24/
2003
10:
36
AM
To:
John
Robbins/
DC/
USEPA/
US@
EPA,
"
Galef,
Barry"
<
Bgalef@
icfconsulting.
com>
cc:
Sikander
Khan/
DC/
USEPA/
US@
EPA
Subject:
RE:
Baseline
NOx
Emission
Levels
for
Industrial
Boilers
Here
are
the
baseline
NOx
emission
levels.

Uncontrolled
NOx
levels
for
coal­
fired
boilers
(
not
including
fluidized­
bed
and
stoker­
fired
boilers)
firing
bituminous
coals
(
range,
average,
and
median
values
of
NOx)
­
min:.
219
max:.
751
average:.
7146583
median:.
717
Uncontrolled
NOx
levels
for
coal­
fired
boilers
(
not
including
fluidized­
bed
and
stoker­
fired
boilers)
firing
sub­
bituminous
coals
(
range,
average,
and
median
values
of
NOx)
­
min:
.717
max:.
751
average:
.72125
median:.
717
Uncontrolled
NOx
levels
for
gas­
fired
boilers
(
range,
average,
and
median
values
of
NOx)
­
min:
.14
max:
.386
average:
.2459038
median:.
245
Uncontrolled
NOx
levels
for
oil­
fired
boilers
(
range,
average,
and
median
values
of
NOx)
­
min:.
219
max:
.278
average:.
219486
median:.
219
Thank
You!

J.
JASON
LEE
ICF
Consulting
9300
Lee
Highway
Fairfax,
VA
22031
703.934.3578
jlee@
icfconsulting.
com
ATTACHMENT
2
Non­
EGU
Inventory
Summary
NON­
EGU
INVENTORY
SUMMARY
(
Reported
9/
15/
03)

The
Emission
Monitoring
Branch
(
EMB)
of
the
Clean
Air
Markets
Division
(
CAMD)
has
developed
an
inventory
of
non­
electrical
generating
(
non­
EGU)
units
that
are
currently
reporting
under
the
NOX
SIP
Call,
the
Acid
Rain
and
the
Ozone
Transport
Commission
programs.
This
inventory
represents
all
non­
EGU
units
subject
to
reporting
requirements
under
the
various
programs
under
Part
75
(
i.
e.
ARP,
NOX
SIP,
OTC).
The
inventory
is
based
on
data
submitted
to
CAMD
for
the
2nd
quarter
of
2003,
as
of
August
15,
2003,
which
serves
as
the
baseline
for
this
inventory.

Procedure
Units
subject
to
reporting
requirements
under
Part
75
must
provide
CAMD
with
quarterly
electronic
data
report
(
EDR)
files
which
provide
the
following
information:

 
Unit
Description
Information
(
unit
ID,
facility
name,
State,
unit
type,
etc.)
 
Operational
Characteristics
(
fuels
used,
add­
on
controls,
hours
of
operation,
etc.)
 
Monitoring
Plan
Information
 
QA/
QC
test
results
 
Hourly
Emissions
and
Heat
Input
(
NOX,
CO2,
SO2)

This
information
is
quality
assured
by
EMB
and
Market
Operations
Branch
(
MOB)
to
verify
that
the
data
is
accurate
and
that
it
meets
all
regulatory
requirements.

Due
to
the
large
amount
of
data
(
hourly
data
for
a
3­
month
period),
EMB
has
developed
a
specific
procedure
in
creating
this
inventory.
This
procedure
consists
of:
(
1)
segregating
all
reporting
data
between
EGUs
and
non­
EGUs,
(
2)
collecting
and
sorting
identified
source
data
for
non­
hourly
information
such
as,
fuel
type
used,
control
technology,
unit
ID,
etc.,
and
(
3)
creating
server
queries
to
collect
and
summarize
hourly
data
such
as
hours
of
operation,
total
heat
input,
pollutant
emissions,
etc.
All
collected
data
are
then
sorted
to
provide
a
cohesive
inventory.
It
should
be
noted
that
the
inventory
is
based
solely
on
data
submitted
for
the
2nd
quarter
of
2003.
This
quarter
data
was
used
due
to
the
addition
of
many
industrial
sources
subject
to
the
NOX
SIP
rule,
whose
first
reporting
period
was
the
2nd
quarter.

Results
The
resulting
inventory
includes
a
total
of
280
units,
which
were
identified
as
non­
EGU
sources.
Table
1
of
this
document
provides
a
breakdown
of
these
units
by
source
category,
and
provides
additional
data
as
to
what
types
of
fuel
are
used
by
each
unit,
what
NOX
control
the
units
have
if
any.
As
indicated
in
Table
1,
the
majority
of
all
the
non­
EGUs
are
Dry
Bottom
Wall­
Fired
Boilers
(
50%).
Turbines
make
up
a
small
percentage
of
all
non­
EGU
units
(
9%).
Table
1
also
indicates
that
most
units
are
coal
fired
(
36%).
However,
process
gas1
is
the
second
most
used
fuel
(
26%)
as
might
be
expected
from
industrial
sources.
Finally,
add­
on
controls
are
present
in
36%
of
all
units,
and
most
prevalent
in
the
Dry
Bottom
Wall­
Fired
boilers
(
46%
of
all
controlled
units).

1
Process
gas
is
any
gas
derived
from
an
industrial
process,
which
can
be
used
as
a
fuel,
such
as
blast
furnace
gas
from
steel
mill
operations.
Of
the
total
of
280
non­
EGU
units,
only
78
units
indicated
any
hours
of
operation
during
the
2nd
quarter
of
2003.
Table
2
provides
a
breakdown
of
all
units,
which
reported
any
hours
of
operation
during
the
2nd
quarter
of
2003.
For
these
units
the
additional
analyses
of
average
NOX
rate
by
fuel
type
(
for
controlled
and
non­
controlled
units)
and
average
operating
time
by
fuel
type
(
for
all
units)
was
conducted.
As
indicated
in
Table
2,
for
most
fuels,
the
NOX
emission
rate
(
lb/
Btu)
is
lower
for
controlled
units
except
for
the
Dry
Bottom
Wall­
Fired
boilers
burning
pipeline
natural
gas,
process
gas
or
residual
oil.
The
reader
should
not
however,
that
these
numbers
may
not
be
representative
as
the
2nd
quarter
2003
data
since
this
is
considered
a
practice
year
for
many
of
these
sources
(
NOX
SIP)
and
may
not
yet
reflect
carefully
quality
assured
data.
As
more
quarters
of
data
are
collected,
better
trends
will
be
realized
for
these
fuels
and
boiler
types.

In
addition
to
Tables
1
and
2,
three
charts
are
included
which
better
illustrate
the
breakdown
of
the
boiler
data
by
source
category
and
fuels
burned.

Conclusions
This
inventory
is
based
on
actual
reporting
data
by
sources
classified
as
non­
EGUs,
and
therefore,
we
expect
it
to
be
more
accurate
than
surveys
or
general
industrial
sector
data.
Analysis
of
the
data
from
this
inventory
has
revealed
important
trend
information
for
various
types
of
units,
fuels,
and
control
technologies.
As
this
inventory
grows
with
additional
quarterly
information,
the
trends
can
be
refined
and
extrapolated
based
on
a
larger
data
pool.
Also,
we
hope
that
this
inventory
can
be
cross­
referenced
with
other
government
and
industry
inventories
to
include
useful
data
such
as
fuel
characteristics
(
sulfur
and
ash
mercury
content)
and
other
information
that
is
not
normally
gathered
via
Part
75
requirements.
We
are
in
the
process
of
analyzing
whether
this
inventory
can
be
cross­
referenced
with
the
industrial
boilers
database
that
OAQPS
has
developed
in
support
of
the
MACT
rule
and
hope
to
be
able
t
report
on
our
findings
shortly.

Prepared
by:
Manuel
J.
Oliva
 
EMB,
CAMD
Thuy
Nguyen
 
EMB,
CAMD
September
15,
2003
Table
1
 
Total
Non
EGU's
Category
Cyclone
Boiler
Cell
Burner
Boiler
Combined
Cycle
Turbine
Circulating
Fluidized
Bed
Boiler
Combustion
Turbine
Dry
Bottom
Wall­
Fired
Boiler
Dry
Bottom
Turbo­
Fired
Boiler
Dry
Bottom
Vertically­

Fired
Boiler
Cement
Kiln
Other
Boiler
Stoker
Boiler
Tangentially
Fired
Boiler
Wet
Bottom
Wall­
Fired
Boiler
Total
Number
of
Units
7
2
9
2
16
139
2
3
2
48
18
26
6
280
Unit
Fuel
Type
Coal
5
1
0
2
0
39
2
0
2
8
18
18
6
101
Diesel
0
0
0
0
2
4
0
0
0
5
0
0
0
11
Natural
Gas
0
0
0
0
6
4
0
0
0
4
0
0
0
14
Other
Gas
1
1
2
0
0
7
0
0
0
0
0
1
0
12
Pipeline
Natural
Gas
0
0
5
0
8
22
0
0
0
12
0
1
0
48
Process
Gas
1
0
2
0
0
49
0
3
0
13
0
4
0
72
Residual
Oil
0
0
0
0
0
11
0
0
0
0
0
1
0
12
Unit
Control
Type
CM
4
0
0
0
0
5
0
0
0
0
0
3
1
13
DLNB
0
0
4
0
8
0
0
0
0
0
0
0
0
12
H2O
0
0
0
0
5
0
0
0
0
0
0
0
0
5
LNB
0
0
0
0
0
29
0
3
0
2
1
0
0
35
LNBO
0
0
0
0
0
7
0
0
0
3
0
0
0
10
LNC1
0
0
0
0
0
0
0
0
0
0
0
7
0
7
LNC3
0
0
0
0
0
0
0
0
0
0
0
1
0
1
LNCB
0
1
0
0
0
0
0
0
0
0
0
0
0
1
O
0
0
0
0
0
0
0
0
1
1
0
2
0
4
OFA
0
0
0
0
0
0
0
0
0
0
1
1
0
2
SCR
0
0
0
0
0
4
0
0
0
0
0
0
0
4
SNCR
1
0
0
0
0
0
0
0
0
0
0
0
0
1
STM
0
0
2
0
1
0
0
0
0
0
0
0
0
3
Total
NOx
Controls
5
1
6
0
14
45
0
3
1
6
2
14
1
98
Table
2
 
Reporting
Non
EGU's
Category
Cyclone
Boiler
Cell
Burner
Boiler
Combined
Cycle
Turbine
Circulating
Fluidized
Bed
Boiler
Combustion
Turbine
Dry
Bottom
Wall­
Fired
Boiler
Dry
Bottom
Turbo­
Fired
Boiler
Dry
Bottom
Vertically­

Fired
Boiler
Cement
Kiln
Other
Boiler
Stoker
Boiler
Tangentially
Fired
Boiler
Wet
Bottom
Wall­
Fired
Boiler
Total
Number
of
Units
5
1
6
2
5
29
0
0
0
10
5
14
1
78
Unit
Fuel
Type
Coal
4
1
0
2
0
7
2
5
12
1
34
Diesel
0
0
0
0
2
0
0
0
0
0
2
Natural
Gas
0
0
0
0
0
1
2
0
0
0
3
Other
Gas
1
0
2
0
0
4
0
0
0
0
7
Pipeline
Natural
Gas
0
0
2
0
3
4
0
0
0
0
9
Process
Gas
0
0
2
0
0
7
6
0
0
0
15
Residual
Oil
0
0
0
0
0
6
0
0
1
0
7
Unit
Control
Type
CM
4
0
0
0
0
0
0
0
3
1
8
DLNB
0
0
1
0
1
0
0
0
0
0
2
H2O
0
0
0
0
3
0
0
0
0
0
3
LNB
0
0
0
0
0
6
1
0
0
0
7
LNBO
0
0
0
0
0
5
0
0
0
0
5
LNC1
0
0
0
0
0
0
0
0
6
0
6
LNC3
0
0
0
0
0
0
0
0
0
0
0
LNCB
0
1
0
0
0
0
0
0
0
0
1
O
0
0
0
0
0
0
0
0
0
0
0
OFA
0
0
0
0
0
0
0
0
0
0
0
SCR
0
0
0
0
0
0
0
0
0
0
0
SNCR
0
0
0
0
0
0
0
0
0
0
0
STM
0
0
2
0
1
0
0
0
0
0
3
Total
NOx
Controls
4
1
3
0
5
11
1
0
9
1
35
Table
2
 
Reporting
Non
EGU's
(
Continued)

Category
Cyclone
Boiler
Cell
Burner
Boiler
Combined
Cycle
Turbine
Circulating
Fluidized
Bed
Boiler
Combustion
Turbine
Dry
Bottom
Wall­
Fired
Boiler
Dry
Bottom
Turbo­
Fired
Boiler
Dry
Bottom
Vertically­

Fired
Boiler
Cement
Kiln
Other
Boiler
Stoker
Boiler
Tangentially
Fired
Boiler
Wet
Bottom
Wall­
Fired
Boiler
Total
Coal
0.1518
0.9615
0.6779
0.8674
0.4252
0.6167
Diesel
Natural
Gas
0.2455
0.1523
0.1989
Other
Gas
0.1343
2.9854
0.1693
1.0963
Pipeline
Natural
Gas
0.0484
0.0484
Process
Gas
0.1821
0.0265
0.1843
0.1309
Average
NOx
Rate
by
Fuel
Type
(
Non
Controlled
Units)
Residual
Oil
0.1808
0.2390
0.2099
Overall
Average
NOx
Rate
0.1343
1.5837
0.1518
0.2720
0.3382
0.8674
0.3321
0.3835
Coal
0.5295
0.6919
0.4416
0.3642
0.4714
0.4997
Diesel
0.4135
0.4135
Natural
Gas
0.0291
0.0291
Other
Gas
Pipeline
Natural
Gas
0.0324
0.0678
0.1234
0.0746
Process
Gas
0.1108
0.1108
Average
NOx
Rate
by
Fuel
Type
(
Controlled
Units)
Residual
Oil
0.2188
0.2188
Overall
Average
NOx
Rate
0.5295
0.6919
0.0324
0.2406
0.2237
0.0291
0.3642
0.4714
0.2244
Coal
1,505.06
1,987.25
2,046.00
1,479.81
1,402.2
2
1,417.9
6
1,562.90
1,464.00
1,608.15
Diesel
10.71
10.71
Natural
Gas
1,456.00
1,160.5
0
1,308.25
Other
Gas
1,464.00
623.27
1,799.81
1,295.70
Pipeline
Natural
Gas
607.05
1,384.49
1,165.39
1,052.31
Process
Gas
1,486.66
1,454.15
1,641.2
2
1,527.34
Average
Operating
Time
by
Fuel
Type
(
All
Units)
Residual
Oil
1,675.64
476.25
1,075.95
Overall
Average
Operating
Time
1,484.53
1,987.25
905.66
2,046.00
697.60
1,505.14
1,401.3
1
1,417.9
6
1,019.58
1,464.00
1,125.49
CHART
1­
TOTAL
NON
EGUs
BY
FUEL
(
2Q
­
2003)

Total
Unit
Population
­
280
38%

4%

5%

4%

18%

27%
4%

Coal
Diesel
Natural
Gas
Other
Gas
Pipeline
Natural
Gas
Process
Gas
Residual
Oil
0
20
40
60
80
100
120
140
Cyclone
Boiler
Cell
Burner
Boiler
Combined
Cycle
Turbine
Circulating
Fluidized
Bed
Boiler
Combustion
Turbine
Dry
Bottom
Wall­

Fired
Boiler
Dry
Bottom
Turbo­

Fired
Boiler
Dry
Bottom
Vertically­

Fired
Boiler
Cement
Kiln
Other
Boiler
Stoker
Boiler
Tangentially
Fired
Boiler
Wet
Bottom
Wall­

Fired
Boiler
CHART
2­
TOTAL
NON
EGUs
BY
SOURCE
CATEGORY
(
2Q
­
2003)
Residual
Oil
Process
Gas
Pipeline
Natural
Gas
Other
Gas
Natural
Gas
Diesel
Coal
CHART
3
­
REPORTING
NON
EGUs
BY
FUEL
(
2Q
­
2003)

Reporting
Unit
Population
­
78
44%

3%

4%

9%

12%

19%
9%

Coal
Diesel
Natural
Gas
Other
Gas
Pipeline
Natural
Gas
Process
Gas
Residual
Oil
ATTACHMENT
3
SEPTEMBER/
OCTOBER
EMAILS
BETWEEN
S.
KHAN
OF
EPA
AND
J.
STAUDT
OF
ANDOEVER
TECHNOLOGY
Jim
Staudt
<
staudt@
AndoverT
echnology.
com>

10/
24/
2003
03:
18
PM
Please
respond
to
staudt
To:
Sikander
Khan/
DC/
USEPA/
US@
EPA
cc:
Subject
RE:
NOx
Reduction
and
Costs
for
LNB/
OFA
Sikander,

I've
attached
two
files.
The
one
C_
006_
ICF_
Transport_
memo
was
prepared
specifically
for
the
work
I
am
doing
for
you,
and
you
should
read
this
one
first.
The
other
one,
C_
03_
007
Technical
Memorandum,
is
associated
with
other
work
I
am
doing
for
EPA
under
my
ICF
Contract,
but
has
quite
a
bit
of
information
that
relates
directly
to
the
state
of
the
art
in
coal
combustion
NOx
controls.
So,
I
am
attaching
that
as
well
as
supporting
information.
I
will
look
forward
to
reviewing
this
material
with
you
on
Tuesday
morning.

Best
Regards,

Jim
Staudt,
Ph.
D.,
CFA
Andover
Technology
Partners
phone:
(
978)
683­
9599
staudt@
AndoverTechnology.
com
www.
AndoverTechnology.
com
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­­­­­
Original
Message­­­­­
From:
Khan.
Sikander@
epamail.
epa.
gov
[
mailto:
Khan.
Sikander@
epamail.
epa.
gov]
Sent:
Wednesday,
September
10,
2003
6:
22
AM
To:
Jim
Staudt
Subject:
NOx
Reduction
and
Costs
for
LNB/
OFA
Jim,

Thank
you
very
much
for
spending
a
considerable
amount
of
time
with
me
on
NOx
controls
for
industrial
boilers.
I
am
summarizing
below
the
items
we
discussed.
I
will
use
these
items
to
start
developing
the
cost
curves.
Once
you
have
been
formally
notified
of
this
work,
please
use
these
numbers
as
a
starting
point.
In
the
meantime,
if
something
jumps
at
you,
please
let
me
know.

All
numbers
quoted
below
are
for
3
sizes
of
industrial
boilers:
100,
250,
and
1000
MMBtu/
hr.
As
you
would
note,
I
have
tweaked
some
of
the
numbers
we
discussed
to
fit
the
information
I
need
to
develop
the
cost
curves.
For
coal,
I
would
assume
post­
retrofit
unburned
carbon
increasing
by
100%.
For
oil,
with
gas
recirculation,
I
am
assuming
that
there
is
no
increase
in
the
unburned
carbon
level
(
could
you
please
let
me
know,
if
you
agree).
I
am
also
assuming
that
for
both
oil
and
gas,
the
gas
recirculation
system
would
be
designed
for
a
20%
gas
recirculation
rate.

Low
NOx
Burners/
Gas
Recirculation
for
Gas
Firing
Use
a
NOx
level
of
0.1
lb/
MMBtu
with
Low
NOx
burners
and
0.05
lb/
MMBtu
with
Low
NOx
burners
and
gas
recirculation
(
GR).
Use
$
2,000/
MMBtu
for
the
1,000
MMBtu/
hr
boiler
and
a
factor
of
0.3
to
adjust
the
cost
for
the
smaller
boilers
(
this
is
the
cost
for
both
the
LNB
and
GR).
Use
half
of
the
cost
in
Item
2
for
Low
NOx
burner
only.

Low
NOx
Burners/
Gas
Recirculation
for
Oil
Firing
Use
a
NOx
level
of
0.35
lb/
MMBtu
with
Low
NOx
burners
and
0.25
lb/
MMBtu
with
Low
NOx
burners
and
gas
recirculation
(
GR).
Use
$
2,000/
MMBtu
for
the
1,000
MMBtu/
hr
boiler
and
a
factor
of
0.3
to
adjust
the
cost
for
the
smaller
boilers
(
this
is
the
cost
for
both
the
LNB
and
GR).
Use
half
of
the
cost
in
Item
2
for
Low
NOx
burner
only.

Low
NOx
Burners/
OFA
for
Coal
Firing
Use
a
NOx
level
of
0.4
lb/
MMBtu
(
for
bituminous
coal)
and
0.3
(
for
sub­
bituminous
coal)
with
Low
NOx
burners
and
0.3
lb/
MMBtu
(
for
bituminous
coal)
and
0.2
(
for
sub­
bituminous
coal)
with
Low
NOx
burners
and
overfire
air
(
OFA).
Use
$
5,000/
MMBtu
for
a
350
MMBtu/
hr
boiler
and
a
factor
of
0.3
to
adjust
the
cost
for
the
three
study
boilers
(
this
is
the
cost
for
LNB
alone).
For
the
overfire
air,
add
$
15/
KW
to
the
cost
in
Item
2
above
to
come
up
with
the
cost
of
both
LNB
and
OFA.

Sikander
Khan
US
EPA
Telephone:
202­
564­
9781
Fax:
202­
564­
1980
Email
Address:
khan.
sikander@
epa.
gov
C_
03_
006_
ICF_
Transport_
memo.
doc
C_
03_
007_
Technical
Memorandum.
doc
(
Note:
The
above
two
attachments
are
provided
as
Attachments
.)
ATTACHMENT
4
FEBRUARY
7,
2002,
MEMORANDUM
FROM
D.
SELLERS
TO
K.
CULLIGAN
MEMORANDUM
TO:
Kevin
Culligan
FROM:
David
Sellers
RE:
Pulverized
Coal
Units
Achieving
0.21
to
0.30
lb
NOx/
mmBtu
DATE:
February
7,
2002
This
memo
is
a
follow
up
to
the
earlier
memo
sent
to
you
February
1,
2001,
regarding
pulverized
coal
units
that
had
achieved
an
average
NOx
rate
of
0.20
lb/
mmBtu
in
2000
or
in
the
first
3
quarters
of
2001
without
add
on
NOx
control.

Tables
are
provided
which
identify
pulverized
coal
units
in
two
additional
groups:
units
that
achieved
NOx
rates
of
0.21
through
0.25
lb/
mmBtu,,
and
units
that
achieved
rates
of
0.26
lb/
mmBtu
through
0.30
lb/
mmBtu
during
the
same
2000
or
2001
period.
In
addition
the
tables
include
NOx
rates
for
previous
years
(
1995
­
1999),
the
type
of
primary
combustion
related
NOx
control,
and
the
primary
type
of
coal
burned.

The
primary
fuel
type
(
bituminous,
subbituminous,
or
lignite)
is
identified
for
the
units
based
on
the
FERC
Form
423
database
for
2000,
and
EPA's
Hg
ICR
1999
fuel
data.
The
FERC
data
is
at
the
plant
level
while
the
Hg
ICR
data
is
at
the
unit
level.
In
cases
where
a
plant
or
unit
burned
more
than
one
type
of
coal,
the
coal
type
with
the
highest
proportion
was
identified
as
the
primary
fuel.

The
EIA­
1605B
Greenhouse
Gas
Voluntary
Reporting
database
and
a
previous
PQA
literature
review
of
boiler
optimization
projects
were
reviewed
to
identify
if
any
of
the
units
had
installed
boiler
optimization
software.
None
of
the
units
listed
here
turned
up
in
either
source.

A
preliminary
internet
search
for
boiler
optimization
at
the
25
units
achieving
0.21through
0.25
lb/
mmBtu
found
information
on
one
unit,
Crawford
Unit
7
in
Illinois.
Midwest
Generation
had
installed
an
ESC
DAS
and
Expert
Control
software
package
on
that
unit
in
2000.
Table
1:
Pulverized
Coal
Boilers
Achieving
a
NOx
Rate
of
0.21
­
0.25
lb/
mmBtu,
Sorted
Based
on
2001
NOx
Rate
State
Plant
Name
ORIS
Unit
ID
Boiler
Type
Primary
NOx
Controls
2000
NOX
Rate
lb/
mmBtu
2001
Thru
Q3
Preliminary
NOX
Rate
lb/
mmBtu*
1995_
2000
Percent
Reduction
North
Dakota
Coal
Creek
6030
1
T
LNC3
0.21
0.21
66
Oklahoma
Hugo
6772
1
WBF
EIA_
LN
0.22
0.21
24
Wisconsin
Weston
4078
3
T
OFA
0.22
0.21
_
9
Missouri
Sikeston
6768
1
DB
EIA_
LN
0.23
0.21
43
Texas
Monticello
6147
3
DB
EIA_
LN
0.24
0.21
3
Texas
Martin
Lake
6146
2
T
U
0.29
0.21
16
Texas
Martin
Lake
6146
2
T
U
0.29
0.21
16
Colorado
Pawnee
6248
1
DB
LNBO
0.21
0.22
21
Wisconsin
Edgewater
4050
5
DB
LNB
0.21
0.22
3
Delaware
Edge
Moor
593
4
T
LNB
0.22
0.22
53
Colorado
Comanche
470
1
T
U
0.24
0.22
_
10
Indiana
R
M
Schahfer
6085
15
DB
LNB
0.26
0.22
_
9
Texas
Limestone
298
LIM2
T
OFA
0.28
0.22
44
Texas
Gibbons
Creek
6136
1
T
LNC1
0.29
0.22
35
North
Dakota
Coal
Creek
6030
2
T
LNC3
0.22
0.23
69
Montana
J
E
Corette
2187
2
T
OFA
0.24
0.24
55
Kentucky
Shawnee
1379
10
OB
O
0.29
0.24
_
10
Illinois
Crawford
867
7
T
U
0.3
0.24
1
South
Carolina
Cope
Station
7210
COP
1
T
LNC2
0.26
0.25
South
Carolina
Cope
Station
7210
COP
1
T
LNC2
0.26
0.25
Texas
Coleto
Creek
6178
1
T
LNC1
0.24
0.27
38
Wisconsin
South
Oak
Creek
4041
5
AF
U
0.23
NA
7
Wisconsin
South
Oak
Creek
4041
6
AF
U
0.23
NA
7
Indiana
Dean
H
Mitchell
996
11
DB
U
0.26
NA
57
Indiana
Dean
H
Mitchell
996
6
T
EIA_
LNO
V
0.26
NA
57
NOx
Control
Codes:

Code
Description
EIA­
LN
EIA767
Data
­
Low
NOx
Burner
Technology
EIA­
LNOV
EIA767
Data
­
Low
NOx
Burner
Technology
with
Overfire
Air
EIA­
OV
EIA767
Data
­
Overfire
Air
LNB
Low
NOx
Burner
Technology
(
DB
Boilers)

LNBO
Low
NOx
Burner
Technology
with
Overfire
Air
(
DB
Boilers)

LNC1
Low
NOx
Burner
Technology
with
Close­
Coupled
Overfire
Air
(
T
Boilers)

LNC2
Low
NOx
Burner
Technology
with
Separated
Overfire
Air
(
T
Boilers)

LNC3
Low
NOx
Burner
Technology
with
Close­
Coupled
and
Separated
Overfire
Air
(
T
Boilers)

OFA
Overfire
Air
U
Uncontrolled
*
South
Oak
Creek
and
Dean
Mitchell
units
are
served
by
a
common
stack.
The
preliminary
2001
data
does
not
include
a
NOx
rate
apportionment
for
each
of
these
units.
Table
2:
Pulverized
Coal,
0.21­
0.25
lb
NOx/
mmBtu
Units
­
Fuel
Information
State
Plant
Name
ORIS
Unit
ID
Boiler
Type
Primary
NOx
Controls
2000
NOX
Rate
lb/
mmBtu
2001
Thru
Q3
Preliminary
NOX
Rate
lb/
mmBtu
FERC
423
Plant
Primary
Fuel
2000
FERC
423
Plant
Fuel
Origin
BOM
Dist
FERC
423
Fuel
Origin
States
Hg
ICR
1999
Fuel
Information
Colorado
Comanche
470
1
T
U
0.24
0.22
SUB
19
WY
Colorado
Pawnee
6248
1
DB
LNBO
0.21
0.22
SUB
19
WY
Delaware
Edge
Moor
593
4
T
LNB
0.22
0.22
BIT
8
WV
Illinois
Crawford
867
7
T
U
0.3
0.24
SUB
Indiana
Dean
H
Mitchell
996
11
DB
U
0.26
NA
SUB
19
WY
Indiana
Dean
H
Mitchell
996
6
T
EIA_
LNO
0.26
NA
SUB
19
WY
Indiana
R
M
Schahfer
6085
15
DB
LNB
0.26
0.22
SUB
19
WY
Kentucky
Shawnee
1379
10
OB
O
0.29
0.24
BIT
17
CO
Missouri
Sikeston
6768
1
DB
EIA_
LN
0.23
0.21
SUB
19
WY
Montana
J
E
Corette
2187
2
T
OFA
0.24
0.24
SUB
North
Dakota
Coal
Creek
6030
1
T
LNC3
0.21
0.21
LIG
21
ND
North
Dakota
Coal
Creek
6030
2
T
LNC3
0.22
0.23
LIG
21
ND
Oklahoma
Hugo
6772
1
WBF
EIA_
LN
0.22
0.21
SUB
19
WY
South
Carolina
Cope
Station
7210
COP1
T
LNC2
0.26
0.25
BIT
8
KY
South
Carolina
Cope
Station
7210
COP1
T
LNC2
0.26
0.25
BIT
8
KY
Texas
Coleto
Creek
6178
1
T
LNC1
0.24
0.27
BIT
17
CO
Texas
Gibbons
Creek
6136
1
T
LNC1
0.29
0.22
SUB
19
WY
Texas
Limestone
298
LIM2
T
OFA
0.28
0.22
LIG
15
TX
Texas
Martin
Lake
6146
2
T
U
0.29
0.21
LIG
15
TX
Texas
Martin
Lake
6146
2
T
U
0.29
0.21
LIG
15
TX
Texas
Monticello
6147
3
DB
EIA_
LN
0.24
0.21
LIG
15
TX
Wisconsin
Edgewater
4050
5
DB
LNB
0.21
0.22
SUB
19
WY
Wisconsin
South
Oak
Creek
4041
5
AF
U
0.23
NA
SUB
Wisconsin
South
Oak
Creek
4041
6
AF
U
0.23
NA
SUB
Wisconsin
Weston
4078
3
T
OFA
0.22
0.21
SUB
19
WY
Table
3:
Pulverized
Coal,
0.21­
0.25
lb
NOx/
mmBtu
Units
­
Average
NOx
Emission
Rates
1995
­
2001Q3
State
Plant
Name
ORIS
Unit
ID
Boiler
Type
Primary
NOx
Controls
1995
NOX
Rate
lb/
mmBtu
1996
NOX
Rate
lb/
mmBtu
1997
NOX
Rate
lb/
mmBtu
1998
NOX
Rate
lb/
mmBtu
1999
NOX
Rate
lb/
mmBtu
2000
NOX
Rate
lb/
mmBtu
2001
Thru
Q3
Preliminary
NOX
Rate
lb/
mmBtu
1995_
2000
Percent
Reduction
Colorado
Comanche
470
1
T
U
0.22
0.24
0.24
0.26
0.30
0.24
0.22
_
10
Colorado
Pawnee
6248
1
DB
LNBO
0.27
0.23
0.21
0.21
0.23
0.21
0.22
21
Delaware
Edge
Moor
593
4
T
LNB
0.46
0.31
0.31
0.32
0.31
0.22
0.22
53
Illinois
Crawford
867
7
T
U
0.30
0.31
0.33
0.31
0.32
0.3
0.24
1
Indiana
Dean
H
Mitchell
996
11
DB
U
0.60
0.39
0.30
0.32
0.29
0.26
NA
57
Indiana
Dean
H
Mitchell
996
6
T
EIA_
LNO
0.60
0.39
0.32
0.33
0.29
0.26
NA
57
Indiana
R
M
Schahfer
6085
15
DB
LNB
0.24
0.23
0.21
0.23
0.24
0.26
0.22
_
9
Kentucky
Shawnee
1379
10
OB
O
0.26
0.25
0.28
0.29
0.26
0.29
0.24
_
10
Missouri
Sikeston
6768
1
DB
EIA_
LN
0.41
0.43
0.39
0.72
0.24
0.23
0.21
43
Montana
J
E
Corette
2187
2
T
OFA
0.54
0.45
0.37
0.28
0.25
0.24
0.24
55
North
Dakota
Coal
Creek
6030
1
T
LNC3
0.63
0.58
0.56
0.58
0.31
0.21
0.21
66
North
Dakota
Coal
Creek
6030
2
T
LNC3
0.72
0.60
0.57
0.39
0.23
0.22
0.23
69
Oklahoma
Hugo
6772
1
WBF
EIA_
LN
0.29
0.32
0.26
0.29
0.32
0.22
0.21
24
South
Carolina
Cope
Station
7210
COP1
T
LNC2
0.00
0.00
0.00
0.00
0.27
0.26
0.25
South
Carolina
Cope
Station
7210
COP1
T
LNC2
0.00
0.00
0.00
0.00
0.27
0.26
0.25
Texas
Coleto
Creek
6178
1
T
LNC1
0.39
0.40
0.36
0.28
0.24
0.24
0.27
38
Texas
Gibbons
Creek
6136
1
T
LNC1
0.45
0.38
0.37
0.34
0.33
0.29
0.22
35
Texas
Limestone
298
LIM2
T
OFA
0.50
0.46
0.42
0.41
0.43
0.28
0.22
44
Texas
Martin
Lake
6146
2
T
U
0.35
0.31
0.30
0.32
0.26
0.29
0.21
16
Texas
Martin
Lake
6146
2
T
U
0.35
0.31
0.30
0.32
0.26
0.29
0.21
16
Texas
Monticello
6147
3
DB
EIA_
LN
0.25
0.24
0.24
0.22
0.22
0.24
0.21
3
Wisconsin
Edgewater
4050
5
DB
LNB
0.22
0.23
0.23
0.23
0.23
0.21
0.22
3
Wisconsin
South
Oak
Creek
4041
5
AF
U
0.25
0.23
0.24
0.28
0.26
0.23
NA
7
Wisconsin
South
Oak
Creek
4041
6
AF
U
0.25
0.24
0.24
0.29
0.26
0.23
NA
7
Wisconsin
Weston
4078
3
T
OFA
0.20
0.21
0.21
0.20
0.23
0.22
0.21
_
9
Table
4:
Pulverized
Coal,
0.26­
0.30
lb
NOx/
mmBtu
Units
­
Fuel
Information
Sorted
Based
on
2000
NOx
Rate
State
Plant
Name
ORIS
Unit
ID
Boiler
Type
Primary
NOx
Controls
2000
NOx
Rate
lb/
mmBtu
2001
Thru
Q3
Preliminary
NOx
Rate
lb/
mmBtu
FERC
423
Plant
Primary
Fuel
2000
FERC
423
Plant
Fuel
Origin
BOM
Dist.
FERC
423
Fuel
Origin
States
Hg
ICR
1999
Fuel
Information
Indiana
Dean
H
Mitchell
996
11
DB
0.26
NA
SUB
19
WY
Indiana
Dean
H
Mitchell
996
6
T
EIA_
LNOV
0.26
NA
SUB
19
WY
Texas
J
T
Deely
6181
1
T
LNC1
0.26
NA
SUB
19
WY
Texas
J
T
Deely
6181
2
T
LNC1
0.26
NA
SUB
19
WY
Michigan
Belle
River
6034
2
DB
LNB
0.26
0.26
SUB
22
MT
Colorado
Arapahoe
465
4
DVF
LNBO
0.26
0.27
SUB
19
WY
Arkansas
Independence
6641
2
T
OFA
0.26
0.29
SUB
19
WY
Alabama
James
H
Miller
Jr
6002
2
DB
0.26
0.29
SUB
19
WY
Colorado
Valmont
477
5
T
LNC3
0.26
0.29
BIT
17
CO
Illinois
Waukegan
883
7
T
LNC1
0.26
0.3
SUB
Michigan
Dan
E
Karn
1702
2
DB
LNBO
0.26
0.32
SUB
19
WY
Michigan
Belle
River
6034
1
DB
LNB
0.27
0.26
SUB
22
MT
Michigan
J
R
Whiting
1723
1
DB
LNB
0.27
0.26
SUB/
BIT
19/
08
WY/
WV
Iowa
Muscatine
1167
9
T
LN
0.27
0.26
SUB
19
WY
Kansas
Quindaro
1295
2
DB
EIA_
LN
0.27
0.26
SUB
19
WY
Wyoming
Laramie
River
6204
2
DB
LNB
0.27
0.27
SUB
19
WY
Kansas
Holcomb
108
SGU1
DB
LNB
0.27
0.28
SUB
19
WY
Georgia
Scherer
6257
4
T
EIA_
OV
0.27
0.28
SUB
19
WY
Pennsylvania
Eddystone
3161
2
T
LNC3
0.27
0.29
BIT
02
PA
Oklahoma
GRDA
165
2
DB
EIA_
LN
0.27
0.32
SUB
19
WY
Georgia
Yates
728
Y7BR
T
LNC2
0.28
0.26
BIT
08
KY,
VA,
WV
Georgia
Yates
728
Y6BR
T
LNC2
0.28
0.27
BIT
08
KY,
VA,
WV
Arizona
Cholla
113
4
T
EIA_
OV
0.28
0.28
SUB
18
NM
Arkansas
Flint
Creek
6138
1
DB
LNB
0.28
0.29
SUB
19
WY
Iowa
Louisa
6664
101
DB
EIA_
LN
0.28
0.29
SUB
19
WY
Minnesota
Clay
Boswell
1893
4
T
LNC1
0.28
0.3
SUB
22
MT
(
cont.)
Table
4:
Pulverized
Coal,
0.26­
0.30
lb
NOx/
mmBtu
Units
­
Fuel
Information
Sorted
Based
on
2000
NOx
Rate
(
cont.)

Texas
Harrington
Station
6193
061B
T
OFA
0.28
0.3
SUB
19
WY
Nevada
Reid
Gardner
2324
4
DB
LNBO
0.28
0.31
BIT
20
UT
Indiana
Dean
H
Mitchell
996
5
T
0.29
NA
SUB
19
WY
Tennessee
Gallatin
3403
1
T
LNC2
0.29
NA
BIT
10
IL
Tennessee
Gallatin
3403
2
T
LNC2
0.29
NA
BIT
10
IL
Nebraska
North
Omaha
2291
1
T
0.29
NA
SUB
19
WY
Nebraska
North
Omaha
2291
2
T
0.29
NA
SUB
19
WY
Nebraska
North
Omaha
2291
3
T
LNC1
0.29
NA
SUB
19
WY
Indiana
Petersburg
994
1
T
LNC3
0.29
NA
BIT
11
IN
Missouri
Iatan
6065
1
DB
LNB
0.29
0.26
SUB
19
WY
Texas
Welsh
6139
1
DB
LNB
0.29
0.26
SUB
19
WY
Wyoming
Wyodak
6101
BW91
DB
EIA_
LN
0.29
0.26
SUB
19
WY
Louisiana
Big
Cajun
2
6055
2B3
DB
LNB
0.29
0.28
SUB
19
WY
Massachusetts
Brayton
Point
1619
2
T
LNC3
0.29
0.28
BIT
Virginia
Clover
7213
1
T
EIA_
LNAA
0.29
0.28
BIT
08
VA
Minnesota
Hoot
Lake
1943
3
DB
LNB
0.29
0.28
SUB
22
MT
Texas
Oklaunion
127
1
DB
LNB
0.29
0.28
SUB
19
WY
Nebraska
Gerald
Whelan
Energy
60
1
T
OFA
0.29
0.3
SUB
19
WY
North
Carolina
Roxboro
2712
2
T
LNC2,
OFA
0.29
0.3
BIT
08
WV
Mississippi
Victor
J
Daniel
Jr
6073
2
T
0.29
0.31
BIT
17
CO
Pennsylvania
Eddystone
3161
1
T
LNC3
0.29
0.32
BIT
02
PA
Colorado
Rawhide
6761
101
T
LNC1
0.29
0.33
SUB
19
WY
Missouri
Meramec
2104
2
T
0.29
0.44
SUB
19
WY
Tennessee
Gallatin
3403
3
T
LNC2
0.3
NA
BIT
10
IL
Tennessee
Gallatin
3403
4
T
LNC2
0.3
NA
BIT
10
IL
Minnesota
Sherburne
County
6090
1
T
LNC1
0.3
NA
SUB
22
MT
(
cont.)

Minnesota
Sherburne
County
6090
2
T
LNC3
0.3
NA
SUB
22
MT
Kentucky
Mill
Creek
1364
1
T
LN
0.3
0.26
BIT
09
KY
Indiana
Cayuga
1001
2
T
LNC2
0.3
0.28
BIT
11
IN
Texas
Tolk
Station
6194
172B
T
OFA
0.3
0.28
SUB
19
WY
Massachusetts
Brayton
Point
1619
1
T
LNC3
0.3
0.29
BIT
Virginia
Clover
7213
2
T
EIA_
LNAA
0.3
0.29
BIT
08
VA
Texas
Harrington
Station
6193
062B
T
OFA
0.3
0.29
SUB
19
WY
Texas
Monticello
6147
2
T
0.3
0.29
LIG
15
TX
North
Dakota
R
M
Heskett
2790
B2
OB
0.3
0.29
LIG
21
ND
Texas
Monticello
6147
1
T
0.3
0.3
LIG
15
TX
Texas
Tolk
Station
6194
171B
T
OFA
0.3
0.3
SUB
19
WY
Missouri
Montrose
2080
1
T
O
0.3
0.31
SUB
19
WY
Wisconsin
Port
Washington
4040
4
DB
0.3
0.31
BIT
02
PA
Michigan
J
C
Weadock
1720
7
T
0.3
0.32
SUB
19
WY
Missouri
Meramec
2104
4
DB
LNB
0.3
0.33
SUB
19
WY
Pennsylvania
Portland
3113
2
T
LNC3
0.3
0.34
BIT
Table
5:
Pulverized
Coal,
0.26­
0.30
lb
NOx/
mmBtu
Units
­
Average
NOx
Emission
Rates
1995
­
2001Q3
Sorted
Based
on
2000
NOx
Rate
State
Plant
Name
ORIS
Unit
ID
Boiler
Type
Primary
NOx
Controls
1995
NOX
Rate
lb/
mmBtu
1996
NOX
Rate
lb/
mmBtu
1997
NOX
Rate
lb/
mmBtu
1998
NOX
Rate
lb/
mmBtu
1999
NOX
Rate
lb/
mmBtu
2000
NOX
Rate
lb/
mmBtu
2001
Thru
Q3
Prelim.

NOX
Rate
lb/
mmBtu
2000_
1995
Percent
Reduction
Indiana
Dean
H
Mitchell
996
11
DB
0.60
0.39
0.30
0.32
0.29
0.26
NA
57
Indiana
Dean
H
Mitchell
996
6
T
EIA_
LNOV
0.60
0.39
0.32
0.33
0.29
0.26
NA
57
Texas
J
T
Deely
6181
1
T
LNC1
0.40
0.37
0.36
0.30
0.29
0.26
NA
35
Texas
J
T
Deely
6181
2
T
LNC1
0.40
0.37
0.35
0.32
0.29
0.26
NA
35
Michigan
Belle
River
6034
2
DB
LNB
0.27
0.28
0.30
0.29
0.27
0.26
0.26
4
Colorado
Arapahoe
465
4
DVF
LNBO
0.38
0.35
0.31
0.24
0.22
0.26
0.27
32
Arkansas
Independence
6641
2
T
OFA
0.27
0.29
0.26
0.24
0.29
0.26
0.29
5
Alabama
James
H
Miller
Jr
6002
2
DB
0.53
0.58
0.57
0.54
0.31
0.26
0.29
51
Colorado
Valmont
477
5
T
LNC3
0.52
0.32
0.28
0.31
0.26
0.26
0.29
50
Illinois
Waukegan
883
7
T
LNC1
0.31
0.35
0.34
0.28
0.31
0.26
0.3
16
Michigan
Dan
E
Karn
1702
2
DB
LNBO
0.72
0.74
0.71
0.69
0.30
0.26
0.32
64
Michigan
Belle
River
6034
1
DB
LNB
0.27
0.27
0.28
0.27
0.25
0.27
0.26
1
Michigan
J
R
Whiting
1723
1
DB
LNB
0.80
0.71
0.38
0.38
0.31
0.27
0.26
66
Iowa
Muscatine
1167
9
T
LN
0.34
0.32
0.31
0.29
0.30
0.27
0.26
19
Kansas
Quindaro
1295
2
DB
EIA_
LN
0.37
0.31
0.34
0.33
0.38
0.27
0.26
27
Wyoming
Laramie
River
6204
2
DB
LNB
0.33
0.28
0.22
0.26
0.26
0.27
0.27
18
Kansas
Holcomb
108
SGU1
DB
LNB
0.25
0.28
0.28
0.29
0.28
0.27
0.28
_
9
Georgia
Scherer
6257
4
T
EIA_
OV
0.29
0.31
0.32
0.34
0.27
0.27
0.28
8
Pennsylvania
Eddystone
3161
2
T
LNC3
0.38
0.31
0.30
0.31
0.24
0.27
0.29
29
Oklahoma
GRDA
165
2
DB
EIA_
LN
0.32
0.32
0.35
0.29
0.34
0.27
0.32
17
Georgia
Yates
728
Y7BR
T
LNC2
0.31
0.31
0.31
0.32
0.29
0.28
0.26
11
Georgia
Yates
728
Y6BR
T
LNC2
0.32
0.33
0.33
0.33
0.29
0.28
0.27
13
Arizona
Cholla
113
4
T
EIA_
OV
0.38
0.35
0.30
0.27
0.31
0.28
0.28
27
Arkansas
Flint
Creek
6138
1
DB
LNB
0.38
0.30
0.30
0.31
0.30
0.28
0.29
26
Iowa
Louisa
6664
101
DB
EIA_
LN
0.26
0.30
0.27
0.26
0.26
0.28
0.29
_
6
Minnesota
Clay
Boswell
1893
4
T
LNC1
0.36
0.34
0.34
0.34
0.32
0.28
0.3
22
Texas
Harrington
Station
6193
061B
T
OFA
0.31
0.28
0.24
0.36
0.31
0.28
0.3
9
(
cont.)
Table
5:
Pulverized
Coal,
0.26­
0.30
lb
NOx/
mmBtu
Units
­
Average
NOx
Emission
Rates
1995
­
2001Q3
Sorted
Based
on
2000
NOx
Rate
(
cont.)

Nevada
Reid
Gardner
2324
4
DB
LNBO
0.32
0.26
0.27
0.28
0.30
0.28
0.31
13
Indiana
Dean
H
Mitchell
996
5
T
0.44
0.39
0.35
0.35
0.29
0.29
NA
34
Tennessee
Gallatin
3403
1
T
LNC2
0.38
0.39
0.39
0.36
0.33
0.29
NA
23
Tennessee
Gallatin
3403
2
T
LNC2
0.38
0.39
0.39
0.36
0.33
0.29
NA
23
Nebraska
North
Omaha
2291
1
T
0.46
0.47
0.43
0.35
0.34
0.29
NA
37
Nebraska
North
Omaha
2291
2
T
0.46
0.48
0.43
0.35
0.34
0.29
NA
37
Nebraska
North
Omaha
2291
3
T
LNC1
0.46
0.48
0.44
0.34
0.34
0.29
NA
37
Indiana
Petersburg
994
1
T
LNC3
0.44
0.28
0.26
0.30
0.26
0.29
NA
33
Missouri
Iatan
6065
1
DB
LNB
0.34
0.29
0.29
0.30
0.28
0.29
0.26
16
Texas
Welsh
6139
1
DB
LNB
0.23
0.25
0.26
0.33
0.32
0.29
0.26
_
27
Wyoming
Wyodak
6101
BW91
DB
EIA_
LN
0.33
0.32
0.31
0.31
0.29
0.29
0.26
12
Louisiana
Big
Cajun
2
6055
2B3
DB
LNB
0.25
0.30
0.28
0.26
0.29
0.29
0.28
_
14
Massachusetts
Brayton
Point
1619
2
T
LNC3
0.35
0.32
0.33
0.34
0.29
0.29
0.28
18
Virginia
Clover
7213
1
T
EIA_
LNAA
0.44
0.30
0.30
0.29
0.29
0.29
0.28
35
Minnesota
Hoot
Lake
1943
3
DB
LNB
0.63
0.64
0.60
0.35
0.26
0.29
0.28
54
Texas
Oklaunion
127
1
DB
LNB
0.46
0.48
0.48
0.46
0.33
0.29
0.28
36
Nebraska
Gerald
Whelan
Energy
60
1
T
OFA
0.36
0.36
0.26
0.24
0.29
0.29
0.3
20
North
Carolina
Roxboro
2712
2
T
LNC2,
OFA
0.62
0.66
0.39
0.34
0.31
0.29
0.3
53
Mississippi
Victor
J
Daniel
Jr
6073
2
T
0.31
0.32
0.26
0.21
0.27
0.29
0.31
7
Pennsylvania
Eddystone
3161
1
T
LNC3
0.33
0.31
0.31
0.32
0.28
0.29
0.32
13
Colorado
Rawhide
6761
101
T
LNC1
0.34
0.33
0.32
0.35
0.35
0.29
0.33
15
Missouri
Meramec
2104
2
T
0.53
0.65
0.53
0.47
0.38
0.29
0.44
45
Tennessee
Gallatin
3403
3
T
LNC2
0.42
0.40
0.39
0.37
0.35
0.3
NA
28
Tennessee
Gallatin
3403
4
T
LNC2
0.42
0.40
0.39
0.37
0.35
0.3
NA
28
Minnesota
Sherburne
County
6090
1
T
LNC1
0.28
0.25
0.27
0.28
0.27
0.3
NA
_
7
(
cont.)
Minnesota
Sherburne
County
6090
2
T
LNC3
0.28
0.25
0.27
0.27
0.27
0.3
NA
_
7
Kentucky
Mill
Creek
1364
1
T
LN
0.70
0.53
0.42
0.45
0.39
0.3
0.26
57
Indiana
Cayuga
1001
2
T
LNC2
0.33
0.36
0.34
0.33
0.33
0.3
0.28
10
Texas
Tolk
Station
6194
172B
T
OFA
0.37
0.33
0.30
0.29
0.32
0.3
0.28
20
Massachusetts
Brayton
Point
1619
1
T
LNC3
0.36
0.30
0.31
0.32
0.29
0.3
0.29
18
Virginia
Clover
7213
2
T
EIA_
LNAA
0.00
0.00
0.00
0.00
0.28
0.3
0.29
Texas
Harrington
Station
6193
062B
T
OFA
0.40
0.33
0.29
0.29
0.34
0.3
0.29
24
Texas
Monticello
6147
2
T
0.31
0.32
0.31
0.32
0.29
0.3
0.29
3
North
Dakota
R
M
Heskett
2790
B2
OB
0.34
0.35
0.32
0.34
0.31
0.3
0.29
13
Texas
Monticello
6147
1
T
0.30
0.30
0.31
0.29
0.30
0.3
0.3
1
Texas
Tolk
Station
6194
171B
T
OFA
0.40
0.36
0.32
0.33
0.30
0.3
0.3
25
Missouri
Montrose
2080
1
T
O
0.43
0.36
0.32
0.35
0.33
0.3
0.31
31
Wisconsin
Port
Washington
4040
4
DB
0.30
0.29
0.30
0.30
0.28
0.3
0.31
0
Michigan
J
C
Weadock
1720
7
T
0.41
0.41
0.41
0.36
0.35
0.3
0.32
26
Missouri
Meramec
2104
4
DB
LNB
0.94
0.37
0.34
0.34
0.33
0.3
0.33
68
Pennsylvania
Portland
3113
2
T
LNC3
0.43
0.48
0.41
0.34
0.28
0.3
0.34
30
(
cont.)

NOx
Control
Codes:

Code
Description
EIA­
LN
EIA767
Data
­
Low
NOx
Burner
Technology
EIA­
LNAA
EIA767
Data
­
Low
NOx
Burner
Technology
with
Advanced
Overfire
Air
EIA­
LNOV
EIA767
Data
­
Low
NOx
Burner
Technology
with
Overfire
Air
EIA­
OV
EIA767
Data
 
Overfire
Air
LNB
Low
NOx
Burner
Technology
(
DB
Boilers)

LNBO
Low
NOx
Burner
Technology
with
Overfire
Air
(
DB
Boilers)

LNC1
Low
NOx
Burner
Technology
with
Close­
Coupled
Overfire
Air
(
T
Boilers)

LNC2
Low
NOx
Burner
Technology
with
Separated
Overfire
Air
(
T
Boilers)

LNC3
Low
NOx
Burner
Technology
with
Close­
Coupled
and
Separated
Overfire
Air
(
T
Boilers)

OFA
Overfire
Air
U
Uncontrolled