RESPONSE
TO
SIGNIFICANT
PUBLIC
COMMENTS
ON
THE
PROPOSED
CLEAN
AIR
MERCURY
RULE
Received
in
response
to:

Proposed
National
Emission
Standards
for
Hazardous
Air
Pollutants;
and,
in
the
Alternative,
Proposed
Standards
of
Performance
for
New
and
Existing
Stationary
Sources:
Electric
Utility
Steam
Generating
Units
(
69
FR
4652;
January
30,
2004)

Supplemental
Notice
for
the
Proposed
National
Emission
Standards
for
Hazardous
Air
Pollutants;
and,
in
the
Alternative,
Proposed
Standards
of
Performance
for
New
and
Existing
Stationary
Sources:
Electric
Utility
Steam
Generating
Units
(
69
FR
12398;
March
16,
2004)

Proposed
National
Emission
Standards
for
Hazardous
Air
Pollutants;
and,
in
the
Alternative,
Proposed
Standards
of
Performance
for
New
and
Existing
Stationary
Sources,
Electric
Utility
Steam
Generating
Units:
Notice
of
Data
Availability
(
69
FR
69864;
December
1,
2004)

Docket
Number
OAR­
2002­
0056
1.0
INTRODUCTION
AND
BACKGROUND
2.0
APPLICABILITY
AND
SUBCATEGORIZATION
US
Environmental
Protection
Agency
Emissions
Standards
Division
Office
of
Air
Quality
Planning
and
Standards
Research
Triangle
Park,
North
Carolina
27711
15
March
2005
i
General
Outline
1.0
INTRODUCTION
AND
BACKGROUND
2.0
APPLICABILITY
AND
SUBCATEGORIZATION
3.0
PERFORMANCE
STANDARDS
FOR
COAL­
FIRED
ELECTRIC
UTILITY
STEAM
GENERATING
UNITS
4.0
PERFORMANCE
STANDARDS
FOR
OIL­
FIRED
ELECTRIC
UTILITY
STEAM
GENERATING
UNITS
5.0
MERCURY
CAP­
AND­
TRADE
PROGRAM
6.0
MERCURY
EMISSIONS
MONITORING
7.0
IMPACT
ESTIMATES
8.0
COMPLIANCE
WITH
EXECUTIVE
ORDERS
AND
STATUTES
9.0
NODA
10.0
OTHER
Appendix
A
LIST
OF
COMMENTERS
1­
1
1.0
INTRODUCTION
AND
BACKGROUND
The
purpose
of
this
document
is
to
provide
EPA's
responses
to
public
comments
received
on
the
notice
of
proposed
rulemaking
(
NPR),
"
Proposed
National
Emission
Standards
for
Hazardous
Air
Pollutants;
and,
in
the
Alternative,
Proposed
Standards
of
Performance
for
New
and
Existing
Stationary
Sources:
Electric
Utility
Steam
Generating
Units"
(
Clean
Air
Mercury
Rule;
CAMR)
(
69
FR
4652;
January
30,
2004);
on
the
supplemental
notice
of
proposed
rulemaking
(
SNPR),
"
Supplemental
Notice
for
the
Proposed
National
Emission
Standards
for
Hazardous
Air
Pollutants;
and,
in
the
Alternative,
Proposed
Standards
of
Performance
for
New
and
Existing
Stationary
Sources:
Electric
Utility
Steam
Generating
Units"
(
69
FR
12398;
March
16,
2004);
and
on
the
notice
of
data
availability
(
NODA),
"
Proposed
National
Emission
Standards
for
Hazardous
Air
Pollutants;
and,
in
the
Alternative,
Proposed
Standards
of
Performance
for
New
and
Existing
Stationary
Sources,
Electric
Utility
Steam
Generating
Units:
Notice
of
Data
Availability"
(
69
FR
69864;
December
1,
2004).

The
opportunity
for
written
and
oral
public
comment
on
the
proposed
rulemaking
was
announced
with
the
NPR,
the
SNPR,
and
the
NODA.
Concurrent
public
hearings
on
the
NPR
were
held
on
February
25
and
26,
2004,
in
Chicago,
IL,
Philadelphia,
PA,
and
Research
Triangle
Park,
NC.
A
public
hearing
on
the
SNPR
was
held
on
March
31,
2004,
in
Denver,
CO.
No
public
hearing
was
held
on
the
NODA.
The
period
for
public
comment
on
the
NPR
closed
on
March
30,
2004,
but
was
extended
to
April
30,
2004,
upon
publication
of
the
SNPR.
Following
numerous
requests
for
an
extension,
the
public
comment
period
was
reopened
on
May
1,
2004,
and
extended
to
June
29,
2004.
The
public
comment
period
on
the
NODA
closed
on
January
3,
2005.
In
addition,
a
telephone
hotline
was
established
for
use
by
the
public
in
providing
comments.

EPA
received
approximately
500,000
comments
on
this
proposed
rulemaking,
including
numerous
mass­
mailings
and
approximately
5,000
"
unique"
comments.
A
listing
of
the
commenters
is
provided
in
Appendix
A
to
this
document.
A
complete
set
of
the
public
comments
received
(
including
the
transcripts
of
the
public
hearings
and
telephone
hotline
calls)
is
available
as
part
of
eDocket
OAR­
2002­
0056.
This
docket
can
be
accessed
at
www.
epa.
gov/
edocket
or
through
the
U.
S.
EPA
Docket
Center,
1301
Constitution
Avenue,
NW,
Washington,
D.
C.,
20004
in
the
Public
Reading
Room,
Room
B102,
EPA
West
Building,
8:
30
a.
m.
through
4:
30
p.
m.,
Monday
through
Friday.

A
summary
of
the
public
comments
received
and
EPA's
responses
is
contained
in
the
subsequent
chapters
of
this
document.
In
this
document,
EPA
has
followed
the
following
three
criteria:

!
Detailed
responses
are
provided
only
for
those
comments
deemed
to
be
significant.
Other
comments
may
be
summarized
and
general
responses
provided.

!
Comments
determined
to
be
"
late
public
comments"
on
the
NODA
(
i.
e.,
received
after
the
close
of
the
public
comment
period
for
the
NODA)
are
neither
summarized
in
this
document
nor
are
responses
provided.
Comments
received
between
June
30,
2004
1­
2
(
following
the
June
29,
2004,
end
of
the
public
comment
period
on
the
NPR
and
SNPR)
and
November
30,
2004
(
prior
to
the
December
1,
2004,
opening
of
the
public
comment
period
on
the
NODA)
were
considered
in
the
decisions
on
the
final
rule
because
the
comment
period
was
reopened
on
December
1,
2004,
if
only
on
a
limited
number
of
issues.
Responses
are
not
provided
to
comments
received
after
the
close
of
the
public
comment
period
on
the
NODA
on
January
3,
2005,
because
there
was
insufficient
time
for
adequate
analyses
of
these
comments.

!
Comments
received
on
the
proposed
Clean
Air
Act
(
CAA)
section
112(
d)
maximum
achievable
control
technology
(
MACT)
approach
and
on
the
proposed
approach
to
institute
a
cap­
and­
trade
rulemaking
under
the
authority
of
CAA
section
112(
n)(
1)(
A)
have
neither
been
summarized
nor
responded
to
in
this
document.
We
have
taken
this
approach
because
these
two
proposed
regulatory
approaches,
which
were
two
of
the
three
regulatory
approaches
proposed,
were
not
selected
for
promulgation.
Some
commenters
on
CAA
section
112(
d)
discussed
alternative
measures
of
what
the
proper
emissions
standards
would
be
under
a
MACT,
or
criticized
EPA's
methodology
for
estimating
those
standards.
To
the
extent
these
commenters
have
stated,
or
believe,
that
EPA
should
have
performed
additional
MACT
calculations,
and
compared
these
revised
calculations
with
the
emissions
reductions
achieved
under
CAA
sections
110(
a)(
2)(
D)
and
111
before
revising
its
2000
CAA
section
112(
n)
determination
or
promulgating
CAMR,
EPA
disagrees.
In
assessing
the
effects
of
Hg
emissions
from
U.
S.
utilities,
EPA
identified,
to
the
extent
possible
given
limits
in
data
and
modeling
capability,
all
utility­
attributable
Hg
emissions
that
deposit
in
the
U.
S.
or
otherwise
affect
U.
S.
public
health.
EPA
used
this
information
 
what
would
happen
if
Hg
emissions
form
U.
S.
utilities
were
eliminated
completely
 
to
identify
the
effects,
and
any
remaining
risks,
of
today's
regulatory
actions.
Because
EPA
has
concluded
the
effects
and
benefits
of
emissions
reductions
beyond
those
achieved
through
the
Clean
Air
Interstate
Rule
(
CAIR)
and
CAMR
are
small,
and
would
not
justify
different
decisions
than
those
reached
today,
EPA
has,
therefore,
not
relied
upon
comparison
between
the
emissions
standards
under
a
MACT
and
emissions
after
the
actions
adopted
today.
2­
1
2.0
APPLICABILITY
AND
SUBCATEGORIZATION
2.1
APPLICABILITY
2.1.1
Definitions
Comment:

One
commenter
(
OAR­
2002­
0056­
2922)
stated
that
EPA
uses
the
terms
"
coal­
fired
electric
utility
steam
generating
unit,"
"
integrated
gasification
combined
cycle
electric
utility
steam
generating
unit,"
and
"
oil­
fired
electric
utility
steam
generating
unit"
to
define
applicability
in
the
proposed
rules.
However
those
terms
are
not
defined
anywhere
in
the
proposed
revisions
(
or
the
existing
40
CFR
60).
EPA
should
add
definitions
for
those
units
that
are
consistent
with
the
definitions
in
proposed
40
CFR
60
Subpart
UUUUU
and
with
the
public
comments
on
those
definitions.

Response:

EPA
has
provided
the
additional
definitions,
as
appropriate,
as
suggested
by
the
commenter.

Comment:

One
commenter
(
OAR­
2002­
0056­
2922)
stated
that
EPA
proposes
to
incorporate
Hg
and
Ni
standards
into
40
CFR
60
subpart
Da
through
section
60.45a(
a)
and
(
b)
and
section
60.46a,
respectively.
As
revisions
to
the
NSPS,
applicability
of
those
limits
to
new
units
is
limited
to
units
that
commenced
construction
after
the
proposal
date
of
January
30,
2004.
EPA
proposes
to
reflect
that
limited
applicability
only
by
means
of
parenthetical
statements
in
the
compliance
provisions
in
40
CFR
60
Subpart
Da
60.48a(
m)
and
(
n).
The
commenters
do
not
believe
that
EPA's
approach
is
sufficient
to
make
applicability
clear.
Instead,
EPA
should
follow
the
approach
it
took
with
promulgation
of
a
new
output­
based
NOx
standard
and
also
include
a
clear
statement
of
applicability
in
the
provisions
setting
out
the
new
standards.

Response:

EPA
has
clarified
the
applicability
language
as
suggested
by
the
commenter.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2922,
­
2634,
­
2718)
identified
a
number
of
instances
where
the
definitions
do
not
reflect
the
proposed
regulatory
provisions.
For
example,
the
provisions
for
regulation
of
"
oil­
fired"
units
apply
to
any
unit
combusting
oil.
Because
some
coal­
fired
units
combust
oil
for
start­
up,
the
definitions
of
"
coal­
fired"
and
"
oil­
fired"
should
be
revised
to
make
clear
that
units
that
combust
both
coal
and
oil
are
not
"
oil­
fired,"
and
that
any
unit
regulated
as
a
coal­
fired
unit
is
not
subject
to
the
"
oil­
fired"
unit
limits.
Those
revisions
2­
2
would
be
consistent
with
EPA's
statements
in
the
preamble
regarding
applicability.

Several
commenters
(
OAR­
2002­
0056­
2634,
­
2718,
­
2922)
stated
that
under
the
proposed
rule,
units
combusting
"
natural
gas
at
greater
than
or
equal
to
98
percent"
of
the
unit's
annual
fuel
consumption
are
not
affected
units
under
this
proposal.
Because
other
provisions
in
the
rule
state
that
they
apply
to
"
coal­
fired"
units,
the
definition
of
"
coal­
fired"
should
be
revised
to
reflect
the
98
percent
or
more
exclusion
for
combustion
of
natural
gas.

Response:

EPA
has
clarified
the
definitions.
It
was
EPA's
intention
that
the
definition
of
a
"
coalfired
boiler
would
be
the
governing
definition.
That
is,
if
a
unit
burned
coal,
in
any
amount,
then
it
would
be
classified
as
a
"
coal­
fired"
boiler
and
subject
to
the
Hg
regulation.
A
unit
that
is
designed
to
burn
oil
is
more
likely
to
be
able
physically
and
actually
to
combust
natural
gas
interchangeably
than
is
a
unit
designed
to
burn
coal.
Units
continue
to
be
exempt
from
the
emission
limits
during
periods
of
startup,
shutdown,
and
malfunction.
Therefore,
coal­
fired
units
that
combust
natural
gas
during
such
periods
would,
during
these
periods,
be
exempt
from
the
regulations.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2634,
­
2718,
­
2922)
noted
that
the
rule
would
include
several
exclusions
related
to
combustion
of
"
natural
gas,"
which
is
not
defined.
Section
63.10042
should
be
revised
to
include
a
definition
of
natural
gas.
EPA
should
also
consider
whether
combustion
of
synthetic
gaseous
fuels
that
are
not
derived
from
coal
(
e.
g.,
digester
gas
and
landfill
gas)
also
should
be
eligible
for
the
98
percent
exclusion.
The
commenters
believe
that
they
should
be.

Response:

EPA
will
add
the
definition
of
natural
gas
as
suggested
by
the
commenters.
However,
the
other
synthetic
gases
noted
by
the
commenters
are
not
"
fossil
fuels"
under
the
definitions
in
40
CFR
60.41a
and,
therefore,
units
firing
these
fuels
would
not
be
subject
to
this
regulation
unless
such
firing
was
in
combination
with
the
firing
of
coal.

Comment:

One
commenter
(
OAR­
2002­
0056­
3449)
stated
that
a
definition
of
startup
should
be
added
to
the
rule.

Response:

"
Startup"
is
already
defined
in
the
General
Provisions
at
40
CFR
60.2.

2.1.2
Industrial
Boilers
2­
3
Comment:

One
commenter
(
OAR­
2002­
0056­
2331)
agreed
with
EPA's
position
that
the
rule
should
apply
to
only
electric
utility
steam
generating
facilities
(
EGU).
The
commenter
added
that
non­
EGU
should
not
be
included
under
the
proposed
rule.
The
commenter
also
stated
that
Hg
emissions
from
industrial
boilers
are
insignificant
in
comparison
with
those
from
EGU.

Response:

EPA
concurs
that
industrial
boilers
should
not
be
included
in
the
same
source
category
as
electric
utility
steam
generating
units.

2.1.3
Cogeneration
Units
Comment:

One
commenter
(
OAR­
2002­
0056­
2277)
believed
that
consistent
with
Acid
Rain
regulations,
the
proposed
definition
of
"
electric
utility
steam
generating
unit"
seems
intended
to
exclude
units
that
are
primarily
designed
to
provide
power
to
industrial
facilities.
The
commenter
believed
the
definition
seems
intended
to
create
two
categories
that
are
regulated,
typical
electricity
generating
utilities,
and
co­
generation
units
that
supply
more
than
one­
third
of
its
potential
electric
output
capacity
and
more
than
25
megawatts­
electric
(
MWe)
output
to
any
utility
power
distribution
system
for
sale.
The
commenter
noted
that,
however,
as
written,
the
first
category
seems
overly
broad
and
could
be
read
to
include
the
industrial
units
that
are
intentionally
excluded
from
the
second
category
(
those
that
supply
less
than
one­
third
of
the
units
potential
electric
output
capacity
or
less
than
25
MWe
output
to
any
utility
power
distribution
system
for
sale).
The
commenter
further
noted
that,
as
written,
the
second
category
does
not
create
an
exemption
from
the
first
category,
although
it
seems
intended
to
create
this
exemption.
To
clarify
that
the
regulation
applies
only
to
units
that
produce
more
than
one­
third
of
their
power
for
sale,
the
commenter
suggested
the
definition
be
changed
as
follows:

Electric
utility
steam
generating
unit
means
any
fossil
fuel­
fired
combustion
unit
of
more
than
25
MWe
that
serves
a
generator
that
produces
more
than
one
third
of
its
potential
electric
output
capacity
and
more
than
25
MWe
of
its
electricity
for
sale.
A
unit
that
co­
generates
steam
and
electricity
and
supplies
more
than
one­
third
of
its
potential
electric
output
capacity
and
more
than
25
MWe
output
to
any
utility
power
distribution
system
for
sale
is
also
considered
an
electric
utility
steam
generating
unit.

The
commenter
noted
that,
alternately
the
regulation
could
be
changed
as
follows
to
show
that
the
second
category
exempts
units
from
the
first
category:

Electric
utility
steam
generating
unit
means
any
fossil
fuel­
fired
combustion
unit
of
more
than
25
MWe
that
serves
a.
generator
that
produces
electricity
far
sale.
A
unit
that
co­
generates
steam
and
electricity
and
supplies
less
than
one­
third
of
its
potential
electric
2­
4
output
capacity
or
less
than
25
MWe
output
to
any
utility
power
distribution
systems
for
sale
is
not
an
electric
utility
steam
generating
unit.

Response:

EPA
believes
that
the
definition
provided
in
revised
subpart
Da
clearly
defines
two
categories
of
new
sources
 
utility
units
and
non­
utility
units
(
which
could
include
industrial
boilers,
combustion
turbines,
etc.).
That
is,
a
joint
condition
must
be
met
in
order
to
be
classified
as
a
Utility
Unit
 
the
unit
must
provide
more
than
one­
third
of
its
potential
electric
output
capacity
and
more
than
25
MWe
electrical
output
to
any
utility
power
distribution
system
for
sale.
Further,
the
boiler
itself
must
be
capable
of
combusting
more
than
73
MW
(
250
million
Btu/
hr)
heat
input
(
which
equates
to
25
MWe
on
an
output
basis).
The
Agency's
historical
interpretation
of
the
subpart
Da
definition
has
been
that
a
boiler
meeting
the
capacity
definition
(
i.
e.,
greater
than
250
million
Btu/
hr)
but
connected
to
an
electrical
generator
with
a
generation
capacity
of
25
MWe
or
less
would
still
be
classified
as
an
"
electric
utility
steam
generating
unit"
under
subpart
Da.
However,
one
or
more
new
boilers
with
heat
input
capacities
less
than
250
million
Btu/
hr
connected
to
an
electrical
generator
with
a
generation
capacity
of
greater
than
25
MWe
would
not
be
considered
Utility
Units
because
they
individually
do
not
meet
the
definition
(
they
would
be
considered
industrial
boilers).
EPA
acknowledges
that
there
are
differences
in
definitions
between
the
NSPS
program
and
the
Acid
Rain
and
other
trading
programs
(
e.
g.,
CAIR)
that
result
from
the
underlying
statutory
mandates.

With
regard
to
the
amount
of
power
sold
to
the
grid
and
the
"
trigger"
beyond
which
a
unit
is
considered
a
Utility
Unit
for
the
purposes
of
this
rulemaking,
again
there
are
definitional
differences
that
have
developed
from
the
statutory
mandates.
EPA
believes
that
new
sources
have
the
foreknowledge
of
the
rules
in
effect
and,
thus,
should
be
expected
to
be
able
to
determine
up­
front
whether
they
want
to
be
considered
a
Utility
Unit
or
an
industrial
boiler
(
i.
e.,
do
they
plan
on
selling,
or
is
it
likely
that
they
will
sell,
more
than
one­
third
of
their
power
in
the
future).
Therefore,
EPA
considers
a
new
cogeneration
unit
to
be
subject
to
the
subpart
Da
Hg
emission
limit
if
it
ever
exceeds
the
definitional
threshold.
Existing
units,
discussed
further
elsewhere
in
this
document,
are
brought
into
the
program
at
its
inception
rather
than
at
their
start­
up.
Therefore,
EPA
is
using
an
annual
average
threshold
for
existing
units,
noting
that
if
the
threshold
is
ever
met
for
a
given
year,
then
the
unit
will
be
considered
a
Utility
Unit
from
there
on
out.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2085,
­
2206,
­
2906,
­
2922,
­
3525)
recommended
that
the
final
rule
allow
cogeneration
(
or
combined
heat
and
power;
CHP)
units
above
25
MWe
to
supply
up
to
25
MWe
electrical
output
or
up
to
one­
third
of
their
potential
electrical
output
capacity
to
a
utility
power
distribution
system
for
sale
on
a
net
annual
basis
as
is
done
in
the
Acid
Rain
program.
This
would
likely
minimize
the
possibility
of
non­
utility
units
being
classified
as
utility
units
based
upon
unique
situations
of
relatively
short
duration
or
of
unrepresentative
operating
history
(
e.
g.,
if
power
was
generally
used
exclusively
at
the
plant
at
which
it
was
generated,
but
was
sold
to
the
grid
when
the
production
facility
was
down
for
maintenance).
In
2­
5
the
event
that
a
unit
were
classified
as
a
Utility
Unit
and
had
to
meet
a
more
stringent
standard,
the
EPA
should
provide
a
reasonable
period
of
time
for
the
unit
to
come
into
compliance.
Two
commenters
(
OAR­
2002­
0056­
2206,
­
2906)
stated
that
this
requirement
stands
in
contrast
to
EPA's
proposed
CAIR,
where
the
definition
for
a
Utility
Unit
is
based
on
a
historical
annual
average
(
69
FR
4610).
The
commenter
stated
that
to
prevent
these
undesirable
consequences,
and
to
prevent
conflicts
and
confusion
with
the
definition
of
a
Utility
Unit
in
the
CAIR,
EPA
should
base
the
Utility
Unit
definition
on
a
net
annualized
average
and
not
"
during
any
portion
of
the
year."

One
commenter
(
OAR­
2002­
0056­
2085)
stated
that
EPA
created
a
new
opportunity
for
misunderstanding
by
proposing
in
the
rule
that
a
cogeneration
unit
that
meets
the
definition
of
a
Utility
Unit
during
any
portion
of
a
year
would
be
subject
to
the
proposed
rule
(
69
Fed.
Reg.
4657).
The
commenter
believed
that
EPA
should
not
adopt
its
proposed
approach
to
cogeneration
units
that
may
operate
as
"
electric
utility
steam
generation
units"
on
a
short­
term
or
temporary
basis.
According
to
the
commenter,
the
proposed
approach
will
create
complicated
and
unnecessary
issues
in
implementation.
The
commenter
asked
is
a
"
year"
a
calendar
year
or
a
12­
month
rolling
average?
The
commenter
also
asked
how
long
does
a
cogeneration
unit
need
to
meet
the
"
electric
utility
steam
generation
unit"
definition
to
qualify
­
one
day,
one
hour,
or
one
minute?
The
commenter
believed
that
EPA
will
not
gain
a
material
improvement
in
environmental
conditions
by
creating
these
implementation
problems
(
caused
by
a
unit
being
classified
as
an
"
electric
utility
steam
generation
unit"
on
a
short­
term
or
temporary
basis).
According
to
the
commenter,
the
Industrial
Boiler
MACT
rule
has
Hg
limits
for
boilers
of
the
size
involved
here
(
40
CFR
Part
63
Subpart
DDDDD,
Table
1).
The
commenter
noted
that
for
coal­
fired
electric
utility
units,
the
principal
environmental
benefit
is
the
Hg
limit.
The
commenter
believed
these
cogeneration
units
should
be
subject
only
to
the
Industrial
Boiler
MACT
(
40
CFR
Part
63
Subpart
DDDDD).

Three
commenters
(
OAR­
2002­
0056­
2206,
­
2906,
­
3525)
stated
that
in
the
preamble,
EPA,
absent
rationale,
states
that
any
CHP
unit
that
meets
the
definition
of
a
Utility
Unit
during
any
portion
of
the
year
would
become
subject
to
the
rule.
The
commenters
stated
that
requiring
a
CHP
unit
to
stay
below
the
Utility
Unit
definition
on
an
instantaneous
basis
provides
a
disincentive
for
facilities
to
invest
in
new
CHP
capacity
or
to
maximize
the
output
and
efficiency
of
their
current
CHP
and
energy­
producing
network
of
units.
The
commenters
encouraged
EPA
to
confirm
that
for
purposes
of
its
proposed
definitions
of
"
electric
utility
steam
generating
unit"
and
"
cogeneration
unit,"
all
sales
of
electricity
will
be
measured
on
a
"
net"
annual
basis,
as
is
done
in
the
Acid
Rain
program.
The
commenters
stated
that
in
determining
that
"
net"
basis,
EPA's
accounting
should
take
account
of
the
specific
situation
of
major
facilities
with
a
number
of
cogeneration
units.
The
commenters
stated
that
at
such
plants,
some
units
may
be
over
the
size
threshold,
while
others
may
be
below
it.
Yet,
according
to
the
commenters,
the
electricity
from
all
those
units
will
be
pooled
before
it
is
either
used
in
the
plant
or
sold
to
the
grid.
In
that
case,
the
commenters
believed
EPA's
accounting
rules
should
provide
for
determining
when
the
threshold
conditions
have
been
met
by
looking
at
all
the
electricity
generated
by
all
the
cogeneration
units,
whether
they
were
subject
to
the
SIP
call
or
not.
The
commenters
asserted
that
no
other
approach
would
be
administratively
feasible.
In
addition,
the
commenters
pointed
out
that,
in
some
cases,
contractual
arrangements
may
exist
between
the
cogeneration
facility
and
2­
6
the
local
electric
utility
wherein
all
generated
power
is
considered
sold
to
the
utility
and
all
electricity
used
on
the
site
is
purchased
from
the
utility.
According
to
the
commenters,
in
reality,
only
a
small
portion
of
the
generated
power
really
enters
the
grid
from
the
cogeneration
facility,
and
only
that
"
net"
sales
of
power
should
be
considered
when
determining
applicability
with
the
EGU
definition.
Subject
to
these
qualifications,
the
commenters
supported
the
cogeneration
unit
threshold
being
used
for
consideration
as
an
EGU,
specifically,
a
unit
serving
a
generator
with
a
nameplate
capacity
of
greater
than
25
MW
and
supplying
more
than
one­
third
of
its
potential
electric
output
capacity
and
more
than
25
MW
to
any
utility
power
distribution
system
for
sale.
The
commenters
stated
however,
it
would
provide
additional
clarity
and
prevent
confusion
if
it
was
specifically
stated
that
units
associated
with
generators
of
25
MWe
capacity
or
less
were
not
affected
sources
under
this
subpart;
and
any
cogeneration
units
not
supplying
both
more
than
one­
third
of
their
potential
electric
output
capacity
and
more
than
25
MWe
to
any
utility
power
distribution
system
for
sale
were
not
affected
sources
under
this
subpart.
The
commenters
recommended
that
EPA
include
this
additional
clarifying
language
in
the
final
rule.

Two
commenters
(
OAR­
2002­
0056­
2206,
­
2906)
stated
that
requiring
a
cogeneration
unit
to
stay
below
the
Utility
Unit
definition
on
an
instantaneous
basis
would
create
a
large
disincentive
for
facilities
to
invest
in
new
CHP
capacity,
or
to
maximize
the
output
and
efficiency
of
their
current
cogeneration
and
energy­
producing
network
of
units.
According
to
the
commenters,
cogeneration
units
are
inherently
more
efficient
than
traditional
Utility
Units
(
in
many
cases
twice
as
efficient),
and
often
provide
distributed
key
power
to
the
grid
during
transient
or
short­
term
periods
of
peak
power
demand.
The
commenters
stated
that
in
order
to
prevent
being
included
within
the
Utility
Unit
definition,
many
cogeneration
units
will
likely
establish
tight
restrictions
on
exporting
excess
power
to
the
grid,
or
eliminate
export
all
together.
According
to
the
commenters,
this
would
have
the
perverse
effect
of
reduced
cogeneration
unit
power
output,
reduced
overall
grid
efficiency
and
reduced
industrial
steam
and
electricity
generation
efficiency.

Response:

EPA
believes
that
its
historic
interpretation
of
the
subpart
Da
definition
of
an
"
electric
utility
steam
generating
unit"
has
been
that
meeting
the
criteria
(
i.
e.,
more
than
one­
third
of
its
potential
electric
output
capacity
and
more
than
25
MW
net­
electrical
output
to
any
utility
power
distribution
system
for
sale)
at
any
time
subjects
the
source
to
subsequent
compliance
with
the
appropriate
standard.
Subpart
Da
is
applicable
to
each
new
electric
utility
steam
generating
unit
otherwise
meeting
the
definition.
Thus,
there
is
no
more
basis
for
considering
a
group
of
cogeneration
units
for
the
purpose
of
determining
applicability
with
the
rule
than
there
is
currently
for
considering
a
group
of
non­
cogeneration
boilers.

Comment:

One
commenter
(
OAR­
2002­
0056­
3525)
stated
that
in
both
the
proposed
rule
and
preamble
(
69
FR
4696
and
69
FR
4762),
EPA
applies
the
18
CFR
292.205
efficiency
methodology
to
cogeneration
facilities
(
implied
to
be
limited
to
solid­
fuel
fired
facilities
because
gas­
fired
units
are
not
included
in
the
rule
applicability).
The
commenter
submitted
that
this
2­
7
proposed
emission
rate
calculation
for
cogeneration
units
appears
to
unfairly
penalize
them
for
sales
of
any
electric
power
less
than
the
full
generation
capacity.
According
to
the
commenter,
such
a
penalty
is
contrary
to
the
Bush
Administration's
stated
intent
to
advance
the
application
of
cogeneration
facilities
and
thereby
improve
the
nation's
energy
efficiency
and
achieve
greenhouse
gas
emission
intensity
reductions.
The
commenter
strongly
encouraged
EPA
to
reconsider
this
approach.
The
commenter
believed
a
much
more
equitable
and
workable
approach
would
be
to
provide
cogeneration
facilities
with
the
ability
to
use
input­
based
emission
limits
and
calculations.
The
commenter
stated
that
in
that
way,
the
boiler,
fuels,
and
emissions
controls
will
determine
compliance
without
the
apparent
emission
rate
being
unfairly
skewed
by
the
portion
of
electricity
sold
to
the
grid.
According
to
the
commenter,
this
method
also
follows
from
past
EPA
practice
in
establishing
emissions
standards.
The
commenter
submitted
that
EPA
should
establish
emissions
standards
that
encourage
installation
and
operation
of
highly
efficient
cogeneration
facilities,
and
recognize
their
inherent
variability
in
design
and
operating
profiles
versus
typical
single
use
electric
utility
units.

Response:

The
approach
EPA
has
taken
with
regard
to
crediting
the
steam
generated
beyond
that
necessary
to
generate
electric
power
in
a
cogeneration
system
is
consistent
with
that
taken
during
the
earlier
revision
of
the
subpart
Da
NOx
emission
limits.
We
believe
that
consistency
is
appropriate
for
this
application.

Comment:

Two
commenters
(
OAR­
2002­
0056­
2906,
­
3525)
supported
EPA's
decision
not
to
set
emission
limits
for
utility
units
that
burn
98
percent
or
more
of
natural
gas.
The
commenters
noted
that
historically,
EPA
has
not
drawn
a
distinction
among
natural
gas
and
other
refinery
or
process
gases,
but
rather
has
determined
to
define
and
regulate
them
as
simply
"
gaseous
fuels."
The
commenters
noted
that
although
most
commercial
gas­
fired
utility
units
burn
natural
gas,
many
CHP
units
located
at
petroleum
refineries
or
petrochemical
facilities
also
burn
some
amount
of
refinery
fuel
gas
or
other
process
gas
that
is
being
produced
and
consumed
onsite
for
energy
production.
Commenter
OAR­
2002­
0056­
2906
noted
that
in
the
Industrial
Boiler
MACT,
EPA
included
not
only
natural
gas
but
also
process
gas
and
refinery
gas
in
the
same
subcategory.
In
other
words,
in
that
rule
EPA
did
not
draw
a
distinction
among
natural
gas
and
other
refinery
or
process
gases,
but
rather
defined
and
regulated
them
as
simply
"
gaseous
fuel."
The
commenter
stated
that
this
same
issue
exists
for
Utility
Units
under
the
proposed
rule,
and
in
particular
cogeneration
units
that
meet
EPA's
definition
of
a
Utility
Unit.
The
commenter
believed
that
most
readers
would
conclude
that
this
rule
and
its
emission
limits
do
not
apply
to
CHP­
type
or
other
utility
units
that
burn
98
percent
or
more
of
natural
gas,
including
other
gaseous
fuels.
The
commenters
stated
that,
however,
it
would
help
clarify
matters
if
the
rule
specifically
stated
that
this
exemption
applies
not
just
to
natural
gas,
but
also
to
other
gaseous
fuels
such
as
process
and
refinery
gases,
as
well
as
other
non­
residual
fuel
oil
fuels,
in
keeping
with
EPA's
approach
in
the
Industrial
Boiler
MACT.

Response:
2­
8
EPA
believes
that
a
reasonable
interpretation
of
its
exclusion
provision
for
natural
gasfired
units
would
include
other
gaseous
fossil
fuels.
However,
EPA
has
clarified
in
the
final
rule
to
indicate
that
only
units
that
combust
coal,
in
any
amount,
or
any
coal­
derived
fuel
are
subject
to
the
rule.

2.1.4
Combined
Heat
and
Power
Units
Comment:

Several
commenters
(
OAR­
2002­
0056­
2066,
­
2206,
­
2833,
­
3530)
stated
that
the
final
NSPS
utility
rule
should
not
extend
its
mandates
to
either
current
or
future
CHP
systems.
The
commenters
stated
that
in
virtually
all
cases,
CHP
units
are
a
source
of
highly
efficient
power
with
correspondingly
low
emissions.
According
to
the
commenters,
because
cogeneration
units
are
generally
twice
as
efficient
(
i.
e.;
more
output
per
unit
of
input)
as
non­
CHP
Utility
Units,
they
consume
less
coal
and
oil,
and
have
significantly
less
emissions
than
fossil­
fuel
burning
non­
CHP
Utility
Units.
The
commenters
asserted
that,
for
this
reason,
encouraging
CHP
units
should
be
part
of
EPA's
strategy
toward
reducing
harmful
emissions
from
the
electricity
generating
sector.
The
commenters
stated
that
the
Agency
should
not,
therefore,
seek
to
impose
additional
regulation
on
these
units.
The
commenters
added
that
hundreds
of
industrial
facilities
depend
on
the
economic
efficiencies
of
CHP.
The
commenters
stated
that
in
fact,
the
President's
National
Energy
Policy
recommends
the
increased
use
of
CHP
systems
to
improve
energy
efficiency
and
decrease
air
emissions
(
See
National
Energy
Policy,
Report
of
the
National
Energy
Policy
Development
Group,
May
2001,
pp.
4­
11
and
6­
18).
The
commenters
also
stated
that
however,
industrial
units
should
be
given
the
opportunity
to
voluntarily
opt­
in
to
the
benefits
of
the
cap­
and­
trade
program.
The
commenters
stated
that
any
opt­
in
provision
should
be
drafted
to
encourage
participation
and
recognize
cost­
effective
emission
reductions
tailored
to
the
unique
attributes
of
manufacturing
facilities.

Two
commenters
(
OAR­
2002­
0056­
2066,
­
2206)
stated
that
CHP
units
currently
represent
only
about
3
percent
of
the
electric
generating
capacity
covered
by
Agency's
proposal.
According
to
the
commenters,
CHP
units
are
generally
twice
as
efficient
when
compared
to
their
utility
counterparts,
and
about
two­
thirds
of
all
CHP
units
burn
natural
gas
and
have
extremely
low
NOx
emission
rates.
The
commenter
stated
that
although
individual
CHP
emission
rates
will
vary,
the
average
gas­
fired
CHP
emission
rates
are
only
15
to
25
percent
of
that
emitted
by
a
typical
utility.
The
commenter
added
that
even
CHP
units
using
coal
or
oil
as
a
fuel
source
are
still
much
more
efficient
than
a
utility
using
the
same
fuels.
The
commenter
further
stated
that
CHP
units
are
usually
only
a
small
part
of
a
much
larger
industrial
facility
or
complex.
According
to
commenter
OAR­
2002­
0056­
2206,
including
CHP
units
in
this
rule
may
require
them
to
install
flue
gas
desulfurization
(
FGD)
or
selective
catalytic
reduction
(
SCR)
control
technology
by
2010
or
purchase
credits.
The
commenter
stated
that
these
costs
will
be
a
significant
disincentive
to
building
these
environmentally
superior
forms
of
electricity
generation
and
could
significantly
impair
continued
reliance
on
this
type
of
environmentally
wise
technology.
The
commenter
asserted
that
including
these
units
into
this
rulemaking
would
layer
another
set
of
regulations
on
the
entire
facility,
thus
further
complicating
on­
going
compliance
efforts,
and,
because
there
are
relatively
little
emissions
coming
from
such
units,
not
significantly
reduce
the
amount
of
Hg.
The
2­
9
commenter
added
that
EPA
is
proposing
that
compliance
with
its
new
standards
will
be
based
on
emissions
attributable
to
combustion
for
electricity
generation,
and
not
from
steam
production
(
See
e.
g.,
69
FR
at
4,668
and
4,696).
For
these
reasons,
the
commenters
believed
that
CHP
units
should
be
exempted
from
inclusion
in
this
rulemaking.
According
to
the
commenters,
inclusion
of
traditional
CHP
facilities
would
provide
negligible
environment
benefit
while
discouraging
application
of
these
ultra­
efficient
power
and
steam
generators
both
now
and
in
the
future.

Response:

EPA
sees
no
reason
to
exclude
cogeneration
or
CHP
units
that
otherwise
meet
the
definition
of
"
electric
utility
steam
generating
unit"
from
the
final
rule,
as
units
meeting
the
definition
would,
like
other
similarly
sized
but
non­
cogeneration
units,
be
emitters
of
Hg.

2.1.3
Other
Comment:

One
commenter
(
OAR­
2002­
0056­
2835)
stated
that
for
any
regulatory
program
for
Hg
and
Ni
emissions,
EPA
should
clarify
that
compliance
with
the
regulatory
requirements
qualifies
as
a
pollution
control
project.
The
commenter
stated
that
regardless
of
whether
EPA
implements
a
regulatory
program
under
CAA
section
112(
d),
section
112(
n)(
1)(
A),
or
section
111,
the
regulation
should
provide
that
projects
and/
or
activities
undertaken
by
electric
utilities
to
comply
with
the
obligations
of
a
Hg
regulatory
program
do
not
trigger
the
requirements
of
New
Source
Review
(
NSR)
or
Prevention
of
Significant
Deterioration
(
PSD).
The
commenter
further
stated
that
as
a
matter
of
policy,
an
affected
source
should
not
trigger
additional
regulatory
requirements
when
undertaking
efforts
to
comply
with
a
set
of
new
regulations,
particularly
where
the
new
rules
lead
to
reductions
in
HAP.

The
commenter
noted
that
the
proposed
emission
guidelines
for
oil­
fired
units
already
include
a
provision
in
Section
60.4010(
b)
which
states
that
"[
p]
hysical
or
operational
changes
made
to
an
existing
electric
utility
steam
generating
unit
solely
to
comply
with
an
emission
guideline
are
not
considered
a
modification
or
reconstruction
and
would
not
subject
an
existing
electric
utility
steam
generating
unit
to
the
requirements
of
subpart
Da
(
see
Section
60.40a
of
subpart
Da)."
The
commenter
recommended
that
this
provision
be
expanded
to
include
the
requirements
imposed
by
the
NSR
and
PSD
programs.
Furthermore,
the
commenter
urged
EPA
to
include
this
expanded
provision
in
any
regulatory
program
for
all
electric
utilities
(
i.
e.,
the
MACT
standard
or
a
cap­
and­
trade
program).
The
commenter
stated
that
by
making
the
rule
explicit
that
such
projects
would
not
trigger
the
NSR
and
PSD
programs,
EPA
avoids
the
situation
where
State
permitting
agencies
have
to
second
guess
whether
implementation
projects
and
activities
are
indeed
pollution
control
projects.

Response:

NSR
and
PSD
are
only
triggered
through
emission
increases.
Compliance
with
the
promulgated
rule
would
not
result
in
emission
increases
and,
thus,
would
not
trigger
NSR
or
2­
10
PSD.

2.2
SUBCATEGORIZATION
The
proposed
NSPS
includes
Hg
emission
limits
for
new
coal­
fired
units
subcategorized
by
coal
rank
(
bituminous,
subbituminous,
lignite,
waste
coal,
integrated
gasification
combined
cycle
[
IGCC]).
The
rationale
for
subcategorization
under
section
111
is
the
same
as
was
described
in
the
January
30,
2004,
proposed
section
112
standards.
Therefore,
many
commenters
only
addressed
subcategorization
in
the
context
of
section
112;
it
is
presumed
that
their
comments,
when
not
otherwise
explicitly
stated,
also
pertain
to
the
proposed
section
111
standards.

2.2.1
Support
for
Subcategorization
Comment:

One
commenter
(
OAR­
2002­
0056­
2915)
pointed
out
that
under
CAA
section
111,
EPA
has
previously
subcategorized
coal­
fired
utility
units
based
on
the
sulfur
levels
in
the
coals
they
burn.
The
commenter
noted
that
this
subcategorization
approach
was
approved
by
the
U.
S.
Court
of
Appeals
for
the
District
of
Columbia
Circuit
in
Sierra
Club
v.
Costle,
657
F.
2d
298
(
D.
C.
Cir.
1981).
The
commenter
stated
that
in
approving
EPA's
NSPS
regulations,
the
Court
recognized
that
CAA
section
111
allowed
EPA
"
to
distinguish
among
classes,
types
and
sizes
within
categories."
The
commenter
noted
that
the
Court
explained
that
"[
o]
n
the
basis
of
this
language
alone,
it
would
seem
presumptively
reasonable
for
EPA
to
set
different...
standards
for
utility
plants
that
burn
coal
of
varying
sulfur
content."
Thus,
the
Court
found
that
EPA
could
create
subcategories
based
on
the
type
of
fuel
an
EGU
burns.

One
commenter
(
OAR­
2002­
0056­
2862)
stated
that
in
establishing
a
new
source
NSPS
for
Hg,
EPA
should
subcategorize
coal­
fired
power
plants
based
on
the
rank
of
coal
fired.
The
commenter
stated
that
pursuant
to
CAA
section
111(
b)(
2),
EPA
has
the
authority
to
distinguish
among
classes,
types,
and
sizes
within
categories
of
new
sources
for
the
purpose
of
establishing
NSPS
standards.
(
42
U.
S.
C.
section
7411(
2))
The
commenter
stated
that
it
supports
EPA's
proposed
subcategorization
of
coal­
fired
power
plants
based
on
coal
rank
and
also
referred
to
the
Circuit
Court
case
(
Sierra
Club
v.
Costle,
657
F.
2d
298
(
D.
C.
Cir.
1981)).

Several
commenters
(
OAR­
2002­
0056­
2067,
­
2161,
­
2247,
­
2264,
­
2332,
­
2365,
­
2375,
­
2634,
­
2721,
­
2725,
­
2835,
­
2891,
­
2897,
­
2898,
­
2900,
­
2907,
­
2911,
­
2915,
­
2918,
­
2948,
­
3198,
­
3200,
­
3398,
­
3440,
­
3469,
­
3514,
­
3537,
­
3539,
­
4139,
­
4191)
supported
EPA's
use
of
subcategories.
Two
commenters
(
OAR­
2002­
0056­
2375,
­
2918)
supported
EPA's
decision
to
subcategorize
bituminous,
subbituminous,
and
lignite­
burning
affected
units
and
stated
that
EPA's
subcategorization
based
on
coal
rank
is
proper
under
section
111,
which
gives
EPA
broad
authority
to
subcategorize
as
it
deems
appropriate.
The
commenter
also
stated
that
the
CAA,
as
interpreted
by
the
D.
C.
circuit
and
the
legislative
history,
make
clear
that
EPA
has
broad
authority
to
distinguish
among
classes,
types,
and
sizes
of
sources
to
account
for
differences
in
the
effectiveness
of
control
technology.
One
commenter
(
OAR­
2002­
0056­
2375)
stated
that
EPA's
2­
11
approach
to
the
subcategorization
of
electric
utility
steam
generating
units
is
generally
appropriate
and
consistent
with
the
CAA
and
believes
that
subcategorization
of
coal­
fired
and
oil­
fired
units
into
two
subcategories
is
warranted
based
on
their
distinct
emissions
profiles
and
their
typical
uses
as
base­
load
and
peaking
units,
respectively.
The
commenter
also
supported
EPA's
proposal
to
subcategorize
coal­
fired
units
by
coal
rank,
in
part,
to
account
for
the
significant
impact
coal
rank
can
have
on
overall
plant
design,
the
design
process
and
the
operation
of
pollution
controls.

According
to
several
commenters
(
OAR­
2002­
0056­
2067,
­
2365,
­
2375,
­
2725,
­
2898,
­
3198,
­
3514),
subcategorization
by
coal
rank
is
amply
supported
by
the
differences
in
Hg
speciation
that
in
turn
impact
the
effectiveness
of
control
technology.
One
commenter
(
OAR­
2002­
0056­
2891)
notes
that
cooperatives
are
users
of
all
three
general
coal
ranks
and,
in
relation
to
the
rest
of
the
industry,
are
heavy
users
of
subbituminous
and
lignite
coals.
The
commenter
stated
that
because
it
is
much
more
difficult
and
expensive
to
reduce
Hg
emissions
from
these
when
compared
to
eastern
bituminous
coal,
a
single
standard
for
Hg
emission
limits
for
all
coal­
fired
power
plants
would
be
impossible,
as
a
practical
matter,
for
some
lignite
and
subbituminous
coal
burning
plants
to
meet.
The
commenter
believed
that
it
is
imperative
that
in
the
final
rule,
the
use
of
any
specific
coal
type
or
rank
must
not
be
advantaged
or
disadvantaged.

One
commenter
(
OAR­
2002­
0056­
2897)
stated
that
concerns
that
subcategorization
causes
an
increase
in
allowable
Hg
emissions
are
unjustified
in
that
under
a
cap­
and­
trade
system,
the
emissions
cannot
exceed
the
cap,
and
under
a
MACT
system
the
average
floor
effectively
sets
the
emission
level.
The
commenter
believed
that
subcategorization
does
not
necessarily
raise
emissions
but
merely
ensures
that
the
compliance
burden
is
evenly
distributed.
The
commenter
also
stated
that
concerns
that
subcategorization
may
result
in
more
complex
permitting
are
overstated
and
can
be
resolved.
The
commenter
indicated
that
permitting
is
a
relatively
minor
issue
compared
with
the
disruption
to
the
nation's
energy
system
and
fuel
switching,
including
switching
to
gas,
that
will
occur
if
bituminous
and
subbituminous
coals
are
not
subcategorized
separately.

One
commenter
(
OAR­
2002­
0056­
2375)
supported
EPA's
subcategorization
of
IGCC
units
based
on
the
distinct
processes
that
such
units
employ
(
i.
e.,
they
are
the
only
units
that
do
not
combust
coal
in
the
unit
during
operation).

One
commenter
(
OAR­
2002­
0056­
2948)
supported
EPA's
decision
to
subcategorize
electric
utility
steam
generating
units
and
stated
that
EPA
should
place
oil­
fired
units
in
a
different
category
than
coal­
fired
units
because
emissions
from
those
plants
differ
markedly.

One
commenter
(
OAR­
2002­
0056­
2721)
agreed
with
EPA's
proposed
five
subcategories
­
four
based
on
coal
ranks
and
one
for
process
type
­
and
disagreed
with
the
option
to
combine
subbituminous
with
bituminous
coals
for
the
purposes
of
Hg
regulations.
The
commenter
did
not
agree
that
a
five­
category
program
places
a
burden
on
the
Utility
Unit
for
tracking
burn
rates
from
various
coal
sources
on
a
monthly
or
annual
basis.
The
commenter
asserted
the
practical
implications
of
this
co­
categorization
would
be
significant.
The
commenter
stated
that
the
differences
in
the
Hg
emission
levels
on
subbituminous
and
bituminous
coals
are
great
and
have
been
well
documented
and
published
in
the
ICR
data.
The
commenter
noted
that
these
coals
are
2­
12
currently
blended
for
sulfur
compliance.
The
commenter
stated
that
because
of
the
significant
higher
sulfur
content
in
the
bituminous
coal,
the
reverse
scenario
of
blending
bituminous
coal
with
subbituminous
coal
for
Hg
compliance
would
be
detrimental
to
the
SO2
compliance
of
the
facility.

Several
commenters
(
OAR­
2002­
0056­
2260,
­
2560,
­
2725,
­
3440)
supported
EPA's
proposal
to
use
subcategories
in
setting
emissions
limits
and
providing
allocations
to
adequately
address
differences
in
abilities
to
control
Hg
based
on
coal
chemistry
that
varies
with
coal
rank.
One
commenter
(
OAR­
2002­
0056­
2560)
stated
that
their
coal­
fired
facilities
have
different
boiler
configurations
and
fuel
firing
abilities,
and
that
this
is
typical
for
the
industry.
The
commenter
further
stated
that
a
key
consideration
in
Hg
removal
from
coal
is
the
presence
or
lack
of
halogens.
The
commenter
supported
subcategorization
in
that
it
recognizes
the
technological
challenges
presented
by
the
lack
of
halogens
in
Powder
River
Basin
(
PRB)
subbituminous
coals.

One
commenter
(
OAR­
2002­
0056­
2725)
believes
that
subcategorization
should
include
at
least
three
categories:
lignite,
subbituminous,
and
bituminous
coals.
The
commenter
stated
all
these
coal
ranks
behave
differently
when
burned,
releasing
significantly
different
levels
of
Hg
that
may
require
different
controls.
The
commenter
adds
that
Hg
control
costs
for
lignite
and
subbituminous
coals
may
be
higher
at
plants
that
already
have
particulate
matter
(
PM)
and
sulfur
dioxide
(
SO2)
controls
than
the
control
costs
for
plants
burning
bituminous
coal.
The
commenter
stated
that
any
regulation
of
Hg
that
includes
a
one­
size­
fits­
all
standard
would
unfair.
The
commenter
stated
that
lignite
and
subbituminous
coals
are
fundamentally
different
from
bituminous
coal.

Several
commenters
(
OAR­
2002­
0056­
2830,
­
3543,
­
3406)
supported
the
separate
treatment
of
lignite
through
the
subcategorization
process.

One
commenter
(
OAR­
2002­
0056­
3208)
believed
it
is
important
for
EPA
to
recognize
the
relative
disadvantage
at
which
it
now
places
PRB
subbituminous
coal
due
to
the
preponderance
of
elemental
Hg
in
its
content.
The
commenter
submits
that
PRB
coal
now
will
be
placed
at
risk
in
contravention
of
previous
environmental
policies
that
encouraged
its
use.
According
to
the
commenter,
these
factors
should
motivate
EPA
to
recognize
the
need
for
subcategorization
of
coals
in
determining
MACT
for
Hg
removal.

In
supporting
EPA's
decision
to
create
separate
subcategories
for
bituminous
and
subbituminous
coals,
one
commenter
(
OAR­
2002­
0056­
2897)
stated
that
bituminous
coals
are
more
likely
to
be
used
in
a
plant
equipped
with
wet
flue
gas
desulfurization
(
wet
FGD)
for
SO2
control
and
selective
catalytic
reduction
(
SCR)
for
nitrogen
oxides
(
NOx)
control
and
are,
therefore,
more
likely
to
benefit
from
"
co­
benefit"
capture
in
these
systems,
whereas
a
subbituminous
coal
is
more
likely
to
be
burned
in
a
plant
with
a
dry
scrubber,
which
has
shown
no
quantifiable
Hg
capture
in
testing
to
date.
The
commenter
also
stated
that
supra
fuel
switching
is
not
a
viable
solution
and
failing
to
subcategorize
between
bituminous
and
subbituminous
would
create
regional
disparities.

Several
commenters
(
OAR­
2002­
0056­
1969,
­
2161,
­
2535,
­
2661,
­
2843,
­
2867,
­
2891,
­
2897,
­
3539)
supported
separate
subcategories
stating
that
there
are
significant
differences
2­
13
between
the
two
coals,
subsequent
speciation
of
the
Hg
in
the
flue
gases,
and
differences
in
achievable
emission
reductions.
One
commenter
(
OAR­
2002­
0056­
2661)
stated
that
if
coal
ranks
were
combined
into
a
single
category,
rural
electric
consumers
would
be
negatively
impacted.
The
commenter
stated
that
if
a
single
standard
for
Hg
emission
limits
were
set
for
all
coal­
fired
power
plants,
based
on
bituminous
rank
coals,
it
would
be
impossible,
as
a
practical
matter,
for
some
lignite
and
subbituminous
coal
burning
plants
to
meet
that
standard.
One
commenter
(
OAR­
2002­
0056­
2891)
stated
that
cooperatives
are
users
of
all
three
general
coal
ranks
and,
in
relation
to
the
rest
of
the
industry,
are
heavy
users
of
subbituminous
and
lignite
coals
and
would
be
disadvantaged
under
a
single
emission
limit.

One
commenter
(
OAR­
2002­
0056­
2948)
stated
that
EPA
should
subcategorize
units
based
on
differences
between
coal
ranks.
The
commenter
did
not
believe,
however,
that
EPA
should
place
units
burning
coals
of
more
than
one
rank
in
a
separate
subcategory
because
large
differences
exist
in
the
way
plants
burn
coals
of
more
than
one
rank.

One
commenter
(
OAR­
2002­
0056­
2067)
agreed
with
EPA
that
there
is
no
demonstrated
justification
to
create
a
separate
category
for
circulating
fluidized
bed
(
CFB)
units.

Response:

EPA
concurs
with
the
commenters.

2.2.2
No
Subcategorization
Comment:

Many
commenters
(
OAR­
2002­
0056­
2575,
­
2823,
­
2878,
­
2920,
­
3459)
doubt
the
legality
of
EPA's
use
of
subcategorization
by
coal
rank.
One
commenter
(
OAR­
2002­
0056­
2920)
stated
that
EPA's
proposal
to
subcategorize
by
coal
rank
is
unlawful,
arbitrary,
and
capricious
for
the
following
reasons:

(
1)
EPA
provides
no
reason
to
believe
that
just
because
some
plants
are
located
near
mine
mouths
(
e.
g.,
lignite
plants),
they
are
of
a
different
class,
type,
or
size
than
other
units;

(
2)
EPA
argues
that
the
characteristics
of
the
coal
rank
to
be
burned
was
the
driving
factor
in
how
a
unit
was
designed,
but
does
not
say
what
those
design
differences
are
and
does
not
claim
that
any
such
differences
are
so
great
that
plants
designed
to
burn
different
ranks
of
coal
are
different
classes,
types,
or
sizes
of
a
unit;

(
3)
EPA
admits
that
many
plants
burn
two
or
more
different
ranks
of
coal;

(
4)
EPA
admits
that
its
basis
for
subcategorization
was
to
ensure
that
standards
are
achievable
for
all
sources
through
the
use
of
certain
technologies.
According
to
the
commenter,
this
argument
has
been
found
unlawful
(
Cement
Kiln
Recycling
Coalition
v.
2­
14
EPA);

(
5)
EPA
appears
not
to
have
seriously
considered
alternative
subcategorization
approaches
or
no
subcategorization.

One
commenter
(
OAR­
2002­
0056­
2878)
stated
that
EPA
fails
to
provide
any
technical
rationale
to
justify
why
coal
rank
should
define
the
allowable
emissions
a
unit
can
emit
when
technology
is
available
that
enables
all
plants
to
meet
high
levels
of
Hg
control
regardless
of
coal
rank.
According
to
the
commenter,
EPA's
rationale
is
based
on
a
misguided
claim
that
boilers
are
specifically
designed
for
a
specific
rank
of
fuel.
Yet,
according
to
the
commenter,
units
burn
more
than
one
rank
of
coal
in
the
same
boiler.
In
support,
the
commenter
cited
the
Stanton
study
which
showed
that
high
levels
of
Hg
reduction
can
be
achieved
with
currently
available
technology,
regardless
of
coal
rank.
According
to
the
commenter,
the
Stanton
study
was
used
as
the
basis
for
Iowa's
recent
permit
for
a
new
unit
burning
subbituminous
coal
from
the
PRB
that
requires
83
percent
reduction
using
activated
carbon
injection
(
ACI)
or
other
sorbent
injection.

According
to
one
commenter
(
OAR­
2002­
0056­
2823),
11
State
Attorneys
General
contend
that
EPA's
proposed
subcategorization
by
coal
rank
is
unlawful
because:

(
1)
EPA
applied
the
scheme
inconsistently
(
i.
e.,
EPA
cannot
insist
that
emission
standards
be
set
for
specific
subcategories
and
then
reject
standards
that
are
so
tailored
because
they
are
not
appropriate
for
every
unit
in
the
category
as
a
whole);

(
2)
EPA's
scheme
does
not
accurately
reflect
industry
practices
as
it
applies
to
the
subcategorization
scheme
because
there
are
units
that
burn
more
than
one
rank
of
coal;
and
(
3)
The
proposed
scheme
does
not
serve
to
protect
health
and
the
environment
in
that
EPA
admits
that
it
elected
to
subcategorize
by
coal
rank
so
as
to
produce
a
standards
achievable
by
all
units,
ensuring
that
units
continue
to
operate
rather
than
on
protecting
human
health
and
the
environment.

One
commenter
(
OAR­
2002­
0056­
2575)
argued
that
subcategorization
can
only
be
done
on
three
criteria:
class,
type,
and
size
of
sources
and
the
factor
that
coal
rank
is
one
of
the
characteristics
of
a
coal­
fired
boiler
does
not
mean
it
can
be
used
for
subcategorization.
The
commenter
stated
that
EPA's
reliance
on
coal
rank
is
misplaced
because
many
coal­
fired
units
blend
or
fire
two
or
more
ranks
of
coal
in
the
same
boiler
and
EPA
itself
states
that
coal
blending
is
possible
and
not
uncommon.
The
commenter
stated
that
EPA
also
claims
(
with
no
support)
that
fuel
switching
would
require
significant
modification
or
retooling
of
a
unit.
The
commenter
cited
case
law
to
support
its
contention
that
EPA's
subcategorization
is
not
permitted.
The
commenter
stated
that
EPA's
justification
for
rejecting
a
no
subcategorization
option
is
factually
and
legally
indefensible.
That
is,
EPA
based
its
subcategorization
on
two
principles:

(
1)
plants
were
largely
designed
based
on
coal
rank
to
be
burned
and
fuel
switching
would
be
problematic,
and
2­
15
(
2)
the
type
of
coal
rank
to
be
burned
is
based
on
economic
issues,
including
availability
withing
the
area.

The
commenter
stated
that,
as
stated
above,
reliance
on
coal
rank
is
factually
wrong
and
fuel
switching
is
a
common
practice.

According
to
one
commenter
(
OAR­
2002­
0056­
3459),
EPA's
proposed
subcategories
are
contrary
to
law,
without
rational
basis,
arbitrary
and
capricious,
and
an
abuse
of
discretion.
The
commenter
stated
that
EPA
proposes
subcategorization
by
coal
rank,
based
on
the
arguments
that
combustion
technologies
are
coal­
rank
specific
and
that
many
utilities
are
dependent
on
particular
mines
and,
therefore,
particular
ranks
of
coal.
According
to
the
commenter,
these
arguments
are
not
supported
by
the
facts:

(
1)
Utilities
regularly
burn
more
than
one
rank
of
coal
together
and
there
is
no
significant
technical
difference
in
the
boilers
receiving
various
ranks
of
coal.

(
2)
EPA's
reliance
on
American
Society
for
Testing
and
Materials
(
ASTM)
methods
to
determine
coal
rank
is
so
technically
problematic
that
it
erodes
EPA's
rationale
for
subcategorization
by
coal
rank.
Coal
rank
is
not
an
easily
discernible
and
always
clear
characteristic
of
coal
and
EPA
itself
acknowledges
some
overlap.

(
3)
Individual
mines
can
produce
different
ranks
of
coal.
EPA's
justification
that
many
utilities
are
dependent
on
particular
mines
and
therefore
particular
ranks
of
coal
is
not
supported.

(
4)
EPA
acknowledges
that
coals
of
varying
ranks
have
similar
combustion
and
handling
properties,
and
operators
have
learned
to
handle
these
blends
but
then
ignores
it.

(
5)
EPA's
assumptions
also
differ
from
real
world
experience
where
many
units
switched
to
low­
sulfur
coal
to
satisfy
the
acid
rain
program
requirements,
demonstrating
that
units
are
capable
of
burning
a
mix
of
coal
ranks.

(
6)
Even
if
different
ranks
do
have
different
properties,
coal
treatment
technology
may
allow
one
coal
rank
to
act
in
ways
that
make
it
more
like
a
coal
of
a
different
rank.
EPA
acknowledges
that
a
key
consideration
in
subcategorization
decisions
is
whether
different
units
have
differences
in
the
feasibility
in
the
application
of
control
technology.
However,
available
evidence
shows
that
units
burning
different
ranks
of
coal
are
equally
amenable
to
Hg
pollution
controls.
Both
high
and
low
rank
coals
(
such
as
bituminous
and
subbituminous)
coal
can
be
controlled
by
the
same
control
technology
(
7)
Although
EPA
has
only
spurious
rationale
for
subcategorization
of
existing
units;
there
is
no
rationale
for
new
units.
These
can
be
designed
to
provide
optimum
performance
when
firing
all
coal
ranks.

Response:
2­
16
EPA
continues
to
believe
that
it
has
the
statutory
authority
to
subcategorize
based
on
coal
rank
and
process
type,
as
appropriate
for
a
given
standard.
As
initially
structured,
subpart
Da
subcategorized
based
on
the
sulfur
content
of
the
coal
(
essentially
based
on
coal
rank)
for
SO2
emission
limits
and
based
on
coal
rank
for
NOx
emission
limits.
This
approach
was
selected
because
of
the
differences
in
the
relative
ability
of
the
respective
control
technologies
to
effect
emission
reductions
on
the
various
coal
ranks.
Although
EPA
has
subsequently
changed
the
format
of
the
NOx
emission
limits
and
has
recently
proposed
to
establish
common
SO2
emission
limits
regardless
of
coal
rank
(
70
FR
9706),
we
believe
that
the
conditions
existing
at
proposal
of
the
previous
standards
(
e.
g.,
the
inability
of
the
technologies
to
control
SO2
and
NOx
equally
from
all
coal
ranks)
equally
apply
now
for
Hg
and
justify
the
use
of
subcategorization
by
coal
rank
for
the
Hg
emission
limits.
This
does
not
indicate,
however,
that
at
some
point
in
the
future,
the
performance
of
control
technologies
on
Hg
emissions
will
not
advance
to
the
point
that
the
rank
of
coal
being
fired
is
irrelevant
to
the
level
of
Hg
control
achieved
(
similar
to
the
point
reached
by
controls
for
SO2
and
NOx
emissions).
At
that
time,
EPA
may
adjust
the
approach
to
Hg
controls
appropriately.

Comment:

Many
commenters
(
OAR­
2002­
0056­
1471,
­
1611,
­
1682,
­
1686,
­
1687,
­
1773,
­
1861,
­
2108,
­
2160,
­
2243,
­
2334,
­
2415,
­
2441,
­
2819,
­
2833,
­
2878,
­
2887,
­
2889,
­
2924,
­
3199,
­
3435,
­
3437,
­
3440,
­
3449)
opposed
the
use
of
subcategories
based
on
fuel
types.
One
commenter
(
OAR­
2002­
0056­
3199)
recommended
that
EPA
establish
fuel­
neutral
limits
that
account
for
the
high
variability
in
coal,
combustion
processes,
and
control
system
performance
under
different
types
of
firing
conditions.
Several
commenters
(
OAR­
2002­
0056­
1471,
­
1611,
­
1773,
­
1861,
­
2108)
believe
that
subcategorization
by
coal
rank
is
not
warranted
or
is
otherwise
questionable
because
a
unit
can
burn
bituminous
or
subbituminous
coal
with
no
change
to
the
boiler.
They
argued
that
a
fuel­
neutral
rule
would
provide
an
incentive
for
plants
to
blend
the
two
ranks
of
coal
and
point
to
the
industrial
boiler
MACT
which
was
fuel
neutral.
These
commenters
stated
that
subcategorization
by
coal
rank
simply
guarantees
the
continuing
use
of
Hg­
heavy
fuel.
In
opposing
subcategorization,
two
commenters
(
OAR­
2002­
0056­
2243,
­
2878)
stated
that
the
percent
removal
requirement
should
be
the
same
for
all
fuel
ranks
and
unit
configurations.
One
commenter
(
OAR­
2002­
0056­
2878)
recommended
a
single
performance
standard
to
reduce
emissions
by
90
percent
in
2007
and
stated
that
this
can
be
achieved
by
ACI
with
an
electrostatic
precipitator
(
ESP)
and
a
retrofit
fabric
filter
or
a
fabric
filter
alone.

Several
commenters
(
OAR­
2002­
0056­
1682,
­
1686,
­
1687,
­
2108)
oppose
subcategorization
by
coal
rank
because
plants
burning
western,
subbituminous,
or
lignite
coal
remain
uncontrolled
while
plants
burning
eastern
bituminous
coal
must
have
one
or
more
controls.
The
commenters
stated
that
this
is
inconsistent
with
the
CAA's
fuel
neutrality
and
harms
the
economies
of
States
with
eastern
coal.
According
to
the
commenters,
Illinois
has
seen
a
25
percent
increase
in
Hg
emissions
due
to
a
switch
to
subbituminous
coals.
They
stated
that
this
impact
has
not
been
reflected
in
the
EPA
analyses.
One
commenter
(
OAR­
2002­
0056­
2160)
stated
that
Illinois,
Indiana,
Ohio,
and
West
Virginia
oppose
subcategorization
by
coal
rank
and
prefer
limits
that
are
fuel
neutral.
The
commenter
stated
that
the
more
stringent
limits
for
bituminous
coal
will
result
in
fuel
switching
with
severe
economic
impacts
on
States
that
produce
2­
17
bituminous
coal
and
negligible
emission
reductions
due
to
switching
to
subbituminous
coal
as
the
low
cost
compliance
strategy
for
Hg.
One
commenter
(
OAR­
2002­
0056­
2819)
supported
a
single
fuel­
neutral
limit
that
would
not
be
any
less
stringent
than
the
rules
proposed
by
New
Jersey
and
promulgated
by
Massachusetts.
According
to
the
commenter,
compliance
can
be
achieved
through
currently
available
technologies:
for
a
cyclone
boiler,
SCR
can
be
used
in
conjunction
with
FGD
or
ACI
and
a
particulate
control
device,
and,
for
a
tangential
boiler,
compliance
can
be
achieved
through
an
appropriate
PM
control
device
that
collects
fly
ash
if
needed
or
by
ACI
with
a
particulate
control
device
when
fly
ash
re­
injection
systems
are
used.
Two
commenters
(
OAR­
2002­
0056­
2924,
­
3449)
oppose
subcategorization
on
the
grounds
that
the
higher
limit
for
subbituminous
coal
could
encourage
operators
to
switch
and
blend
fuels
resulting
in
an
increase
in
Hg
emissions.
One
commenter
(
OAR­
2002­
0056­
2924)
stated
that
as
a
result,
they
would
continue
to
be
impacted
by
Hg
emissions
from
other
areas
and
that
differentiation
should
be
based
on
the
type
of
unit
(
which
would
not
discriminate
against
fuel
type),
not
the
rank
of
coal.

One
commenter
(
OAR­
2002­
0056­
3449)
stated
that
subbituminous
coals
or
blends
of
subbituminous
and
bituminous
coals
can
frequently
be
burned
in
units
previously
burning
only
bituminous
coal
without
extensive
retrofit.
According
to
this
commenter,
combustion
of
waste
coal
or
anthracite
coals
also
results
in
similar
emissions;
thus,
separate
limits
for
bituminous,
subbituminous,
and
waste
coal
is
questionable.
One
commenter
(
OAR­
2002­
0056­
2889)
stated
that
if
EPA
had
used
a
sufficiently
long
averaging
time
(
which
it
did
not
attempt
to
address),
it
would
obviate
the
need
to
consider
variability
of
coal
Hg
content,
allowing
a
coal­
neutral
rule.
The
commenter
stated
that
another
difficulty
with
the
subcategorization
scheme
is
the
inaccuracy
typically
encountered
in
determining
the
amount
of
different
ranks
of
coal
in
a
blend,
which
is
typically
done
in
a
bulldozer.
One
commenter
(
OAR­
2002­
0056­
2887)
stated
that
practical
reasons
for
limiting
the
number
of
subcategories
is
the
reduced
regulatory
burden
and
increased
plant
flexibility
in
fuel
procurement
and
management
strategies.
One
commenter
(
OAR­
2002­
0056­
2819)
stated
that
EPA's
analyses
supporting
subcategorization
are
severely
flawed
because
of
the
limited
amount
of
stack
test
data
collected
and
analyzed
to
date.
The
commenter
stated
that
as
more
data
is
collected
(
primarily
at
the
State
level),
it
is
evident
that
factors
other
than
coal
rank
are
more
important
in
determining
Hg
speciation
and
the
ability
of
commercially
available
control
technologies
to
reduce
emissions
from
coal­
fired
boilers.
According
to
the
commenter,
important
factors
that
affect
Hg
speciation
and
control
effectiveness
include:
the
combustion
efficiency
of
the
utility
boiler,
and
the
combination
of
control.
One
commenter
(
OAR­
2002­
0056­
3437)
stated
that
subcategorization
creates
a
competitive
advantage
for
western
coal
that
is
not
justified
and
is
inconsistent
with
other
Federal
programs
such
as
the
NOx
SIP
Call
and
the
proposed
Clean
Air
Interstate
Rule
(
CAIR;
originally
titled
at
proposal
the
Interstate
Air
Quality
Rule,
IAQR),
which
are
fuel
neutral.
One
commenter
(
OAR­
2002­
0056­
3435)
stated
that
the
variability
of
the
Hg
and
chlorine
(
Cl)
content
of
coal
within
a
rank,
the
ability
of
a
unit
to
burn
more
than
one
rank
of
coal,
and
the
magnitude
of
the
difference
in
emission
limits
diminishes
the
merit
of
subcategorization
by
coal
rank,
particularly
for
bituminous
and
subbituminous
units.

One
commenter
(
OAR­
2002­
0056­
2944)
disagreed
with
the
proposal
to
subcategorize
based
on
coal
ranks.
The
commenter
stated
that
coal
rank
is
a
continuous
variable,
a
function
of
2­
18
degree,
not
one
of
kind,
stretching
from
before
peat
on
the
one
end
to
past
anthracite
on
the
other.
The
commenter
noted
that
these
classifications
grade
into
each
other
and
in
many
cases
can
be
subject
to
dispute
and
added
that,
as
noted
in
the
proposed
rules,
the
ASTM
classification
of
coal
rank
has
overlapping
attributes.

One
commenter
(
OAR­
2002­
0056­
2944)
noted
that
U.
S.
boilers
commonly
fire
mixes
of
coals
of
different
ranks,
citing
information
from
the
ICR
that
although
around
215
utility
boilers
burned
only
subbituminous
coals,
nearly
as
many
burned
both
combinations
of
subbituminous
and
bituminous.
The
commenter
added
that
about
25
percent
of
the
boilers
that
burned
lignite
burned
other
coal
ranks
as
well.
The
commenter
further
stated
that
over
the
last
two
decades
a
very
significant
number
of
U.
S.
plants
converted
their
boilers
from
burning
high­
sulfur
bituminous
coals
to
low­
sulfur
subbituminous
coals
to
reduce
their
SO2
emissions.
According
to
the
commenter,
obviously,
there
is
nothing
particularly
unique
about
coal
rank
that
should
lead
to
subcategorization
and
dramatically
different
Hg
emission
limits.
The
commenter
observed
that
U.
S.
coal­
fired
boilers
burn
combinations
of
many
carbonaceous
fuels:
in
addition
to
lignite,
subbituminous,
and
bituminous
coals
they
burn
anthracite,
petroleum
coke,
waste
subbituminous,
waste
bituminous,
waste
anthracite,
biomass,
and
waste
tires.
The
commenter
asked
is
it
logical,
or
practical
to
have
separate
emission
standard
determinations
for
each.
The
commenter
further
asked
how
can
compliance
be
fairly
determined
at
the
over
20
percent
of
plants
that
burn
multiple
fuels
simultaneously.

The
commenter
continued
that
the
three
primary
coal­
fired
boiler
fuel
types
contain
Hg
relative
to
their
heating
value
at
about
the
same
degree.
The
commenter
stated
that
each
coal
rank
has
about
70
percent
of
its
deliveries
with
Hg
contents
measured
between
4
and
14
pounds
of
Hg
per
trillion
British
thermal
units
(
lb/
TBtu).
The
commenter
added
that
median
Hg
contents
of
each
coal
rank
are
also
similar
at
7,
5
and
8
lb
Hg/
T
Btu
for
bituminous,
subbituminous,
and
lignite
respectively.
(
The
commenter
further
noted
that
although
subbituminous
coals
contain
less
Hg
than
bituminous
coals,
they
ended
up
being
allowed
to
emit
nearly
three
times
as
much
in
the
currently­
proposed
regulations.)
The
commenter
stated
that
there
is
nothing
obvious
about
the
Hg
content
of
coals
of
different
ranks
that
justifies
subcategorization.

Response:

EPA
believes
that
there
are
sufficient
differences
in
the
design
and
operation
of
utility
boilers
utilizing
the
different
coal
ranks
to
justify
subcategorization
by
major
coal
rank.
As
documented
in
the
record,
utility
boilers
vary
in
size
depending
on
the
rank
of
coal
burned
(
i.
e.,
boilers
designed
to
fire
lignite
coal
are
larger
than
those
designed
to
fire
subbituminous
coal
which,
in
turn,
are
larger
than
those
designed
to
fire
bituminous
coal).
Boilers
designed
to
burn
one
fuel
(
e.
g.,
lignite)
can
not
randomly
or
arbitrarily
change
fuels
without
extensive
testing
and
tuning
of
both
the
boiler
and
the
control
device.
Further,
if
a
different
rank
of
coal
is
burned
in
a
boiler
designed
for
another
rank,
either
in
total
or
through
blending,
the
practice
is
only
done
with
ranks
that
have
similar
characteristics
to
those
for
which
the
boiler
was
originally
designed.
That
is,
the
ASTM
classification
system
is
structured
on
a
continuum
based
on
a
number
of
characteristics
(
e.
g.,
heat
content
or
Btu
value,
fixed
carbon,
volatile
matter,
agglomerating
vs.
non­
agglomerating)
and
provides
basic
information
regarding
combustion
characteristics.
2­
19
Because
more
than
one
characteristic
is
used,
the
possibility
exists
for
numerous
situations
where
a
coal
could
be
"
classified"
in
one
rank
based
on
one
characteristic
but
in
another
rank
based
on
another
characteristic.
Ranking
is
based
on
an
evaluation
of
all
characteristics.
Therefore,
it
is
possible
that
(
for
example)
a
non­
agglomerating
subbituminous
coal
with
a
heating
value
of
8,300
Btu/
lb
(
ASTM
classification
III.
3
 
"
Subbituminous
C
coal")
could
be
co­
fired
with,
or
substituted
for,
a
non­
agglomerating
lignite
coal
with
heating
value
of
8,300
Btu/
lb
(
ASTM
classification
IV.
1­­"
Lignite
A
coal").
This
does
not,
however,
mean
that
it
is
possible
for
a
boiler
designed
to
burn
the
Lignite
A
coal
to
burn
an
agglomerating
coal
with
a
heating
value
of
13,000
Btu/
lb
(
e.
g.,
ASTM
classification
II.
5
 
"
High
volatile
C
bituminous
coal").
Further,
it
does
not
mean
that
the
substituted
coal
would
exhibit
the
same
"
controllability"
with
respect
to
emissions
reductions
as
the
original
coal,
regardless
of
its
compatibility
with
the
boiler.
The
fact
that
a
number
of
Utility
Units
co­
fire
different
ranks
of
coal
does
not
negate
the
overall
differences
in
the
ranks
that
preclude
universal
coal
rank
switching,
particularly
when
the
design
coal
ranks
are
not
adjacent
on
the
ASTM
classification
continuum.

Although
other
classification
approaches
have
been
suggested
(
e.
g.,
based
on
the
geologic
age
of
the
coal;
see
OAR­
2002­
0056­
5411),
the
ASTM
classification
system
remains
the
one
most
recognized
and
utilized
by
the
industry
and
the
one
which
the
EPA
believes
is
most
suitable
for
use
as
a
basis
for
subcategorization.
EPA
further
believes
that,
at
this
time,
coal
rank
is
an
appropriate
and
justifiable
basis
on
which
to
subcategorize
for
the
purposes
of
this
rule.
We
address
elsewhere
in
this
document
comments
related
to
the
appropriate
emission
level
for
each
subcategory.

2.2.3
Single
Subcategory
for
Bituminous
and
Subbituminous
Comment:

Many
commenters
(
OAR­
2002­
0056­
1675,
­
1677,
­
1762,
­
1848,
­
1852,
­
1853,
­
2160,
­
2269,
­
2660,
­
2826,
­
2860,
­
2871,
­
2878,
­
2875,
­
2889,
­
2904,
­
2905,
­
2908,
­
2937,
­
2944,
­
3205,
­
3324,
­
3366,
­
3394,
­
3406,
­
3435,
­
3449,
­
3560)
opposed
subcategorization
and
setting
different
limits
for
bituminous
and
subbituminous
coal
ranks.
Some
commenters
(
OAR­
2002­
0056­
1675,
­
2160,
­
2871,
­
2889,
­
3324,
­
3394)
stated
that
such
subcategorization
discriminates
against
bituminous
coal
and
could
result
in
increased
emissions
as
plants
switch
to
subbituminous
coal
to
take
advantage
of
the
lax
limit,
rather
than
install
Hg
controls.
Two
commenters
(
OAR­
2002­
0056­
2871,
­
2889)
stated
that
the
final
rule
should
address
the
lax
requirement
for
subbituminous
coal
by
requiring
a
stricter
limit
for
subbituminous
coal
(
i.
e.,
80
percent).
One
commenter
(
OAR­
2002­
0056­
3406)
stated
that
the
rationale
for
subcategorization
presumably
is
that
Hg
emissions
from
subbituminous
coal
are
more
difficult
to
control.
The
commenter
believed,
however,
this
is
almost
certainly
a
short­
term
problem
in
light
of
the
progress
that
has
been
and
is
being
made
with
respect
to
the
development
of
Hg
controls
for
this
coal
rank
and
that
development
of
these
needed
controls
for
subbituminous
coal
actually
will
be
stalled
if
strict
control
standards
are
not
promulgated.
Another
commenter
(
OAR­
2002­
0056­
2160)
stated
that
when
Hg­
specific
control
technologies
are
commercialized,
there
will
be
no
differentiation
in
their
performance
for
different
ranks
of
coal,
which
they
say,
is
2­
20
supported
by
preliminary
data
which
indicates
that
there
are
no
removal
differences
between
bituminous
and
subbituminous
coals
using
the
compact
hybrid
particulate
collector
(
COHPAC)
technology.

Two
commenters
(
OAR­
2002­
0056­
2878,
­
3205)
cited
the
paper,
"
Mercury
Air
Pollution:
The
Case
for
Rigorous
MACT
Standards
for
Subbituminous
Coal,"
to
support
their
contention
that
there
is
no
technical
justification
for
the
separate
subcategories.
The
commenters
stated
that
the
technology
is
available
that
can
achieve
90
percent
reduction
at
the
same
costs
for
both
ranks
of
coal
using
ACI
and
an
ESP
and
COHPAC
baghouse
for
particulate
collection
and
nearly
all
the
western
plants
are
already
equipped
with
either
an
ESP
or
baghouse.
According
to
the
commenters,
subcategorizing
these
two
ranks
of
coal
also
may
result
in
plants
switching
or
locking
into
using
the
dirtier
western
subbituminous
coal
because
of
the
more
lenient
limits.
The
commenters
also
stated
that
separate
limits
would
be
difficult
to
implement
and
enforce
because
many
plants
burn
both
ranks
of
coal,
some
coals
cannot
be
classified
as
either
rank
under
the
ASTM
standard,
and
the
amounts
vary
from
month
to
month
and
year
to
year.
One
commenter
(
OAR­
2002­
0056­
3205)
stated
that
the
proposed
Roundup
power
plant
provides
a
perfect
example
of
the
implementation
issues
that
arise
with
EPA's
proposed
subcategorization.
A
review
of
300
samples
from
various
points
across
the
nearby
basin
from
which
the
plant's
coal
would
come
could
not
be
classified
as
bituminous
or
subbituminous
by
ASTM
standards.

One
commenter
(
OAR­
2002­
0056­
3205)
stated
that
EPA
fails
to
provide
an
adequate
rationale
to
justify
weaker
standards
for
units
burning
subbituminous
coal.
In
opposing
separate
subcategories
for
units
burning
bituminous
and
subbituminous
coal,
one
commenter
(
OAR­
2002­
0056­
3406)
explained
that
companies
are
increasingly
attempting
to
capture
subtle
changes
in
fuel
price
and
viewing
fuel
supply
as
a
compliance
option,
with
the
result
that
many
companies
use
various
blends
of
coal
to
optimize
their
emission
performance.
The
commenter
believed
that
the
use
of
subcategories
may
significantly
limit
the
flexibility
to
manage
a
facility's
operational
conditions
and
fuel
choice;
in
the
context
of
a
competitive
market
for
supplying
electric
generation,
operational
flexibility
and
fuel
choice
are
of
paramount
importance.
One
commenter
(
OAR­
2002­
0056­
3435)
stated
that
the
variability
of
the
Hg
and
Cl
content
of
coal
within
a
rank,
the
ability
of
a
unit
to
burn
more
than
one
rank
of
coal,
and
the
magnitude
of
the
difference
in
emission
limits
diminishes
the
merit
of
subcategorization
by
coal
rank,
particularly
for
bituminous
and
subbituminous
units.

One
commenter
(
OAR­
2002­
0056­
3449)
opposed
subcategorization
by
coal
rank
stating
that
subcategorization
results
in
more
blending
of
subbituminous
coal
at
existing
bituminous
units.
The
commenter
stated
that
coal
blending
is
becoming
more
common
and
can
result
in
Hg
emission
reductions
(
30
to
40
percent
subbituminous
coal
with
about
60
to
70
percent
bituminous
coal
reduced
Hg
emissions
by
about
35
percent
at
one
plant).
According
to
the
commenter,
this
is
because
subbituminous
coal
has
less
Hg
and
the
combination
of
blend
characteristics
and
existing
controls
for
bituminous
coal
maintains
the
efficiency
of
Hg
control
for
the
blend.
The
commenter
stated
that
this
contradicts
EPA's
assumption
that
it
is
harder
to
control
Hg
from
subbituminous
coal.
According
to
the
commenter,
it
may
be
that
the
lack
of
control
systems,
especially
for
NOx,
will
cause
lower
Hg
removal
at
some
subbituminous
plants.
2­
21
One
commenter
(
OAR­
2002­
0056­
2860)
favored
a
single
category
for
bituminous
and
subbituminous
coal
stating
that
a
fuel­
neutral
standard
would
facilitate
compliance
by
simplifying
recordkeeping
and
reporting
for
the
type
of
fuel
burned.
The
commenter
also
stated
that
it
was
not
clear
in
the
ICR
database
how
EPA
determined
which
sources
are
considered
in
each
subcategory
because
a
number
of
sources
identified
one
fuel
as
primary
yet
tested
another
fuel.

Two
commenters
(
OAR­
2002­
0056­
1848,
­
1853)
opposed
subcategorization
for
subbituminous
coal
as
unnecessary
and
potentially
illegal,
stating
that
the
decision
is
at
odds
with
the
FACA
workgroup
as
evidenced
in
October
30,
2002,
memorandum.

Some
commenters
(
OAR­
2002­
0056­
2826,
­
3560)
stated
that
because
of
the
CAA
and
rules
relevant
to
SO2,
several
Midwest
utilities
switched
to
low
sulfur
western
subbituminous
coal,
thereby
increasing
the
amount
of
Hg
that
was
emitted.
Yet,
under
the
proposed
Hg
rules,
power
plants
burning
low­
sulfur
western
coal
will
be
subject
to
less
strict
Hg
emissions
limits
than
plants
that
burn
bituminous
and
coal
refuse.
Those
power
plants
that
switched
to
lower
sulfur
coal
will
benefit
from
the
less
stringent
Hg
standard,
even
though
these
plants
are
emitting
more
Hg.
The
commenter
stated
that
they
should
not
be
penalized
for
making
the
choice
to
continue
to
burn
coal
refuse
and
bituminous
coal,
rather
than
switching
to
low­
sulfur
western
coal,
especially
when
it
has
in
place
on
both
units
all
the
technology
considered
sufficient
for
compliance.

According
to
one
commenter
(
OAR­
2002­
0056­
2905),
Wisconsin
recently
completed
a
Hg
rule
that
is
reasonable,
achievable,
and
cost
effective
and
urges
EPA
to
promulgate
a
more
stringent
rule,
particularly
for
subbituminous
coal.
According
to
the
commenter,
Wisconsin,
where
many
utilities
rely
heavily
on
western
subbituminous
coal,
requires
a
40
percent
reduction
by
2010,
75
percent
by
2015,
and
80
percent
by
2018.

One
commenter
(
OAR­
2002­
0056­
3435)
recommended
a
single
subcategory
for
existing
units
burning
bituminous
and
subbituminous
coal
with
separate
subcategories
for
lignite,
coal
refuse­
fired,
and
IGCC
units.
The
commenter
stated
that
according
to
EPA,
an
estimated
23
percent
of
the
coal­
fired
utilities
burn
two
or
more
ranks
of
coal
in
the
same
boiler.
Because
the
proposed
rule
does
not
prohibit
a
utility
from
fuel
switching,
the
commenter
stated
that
a
unit
could
switch
to
a
lower
rank
coal
and
increase
emissions
by
as
much
as
190
percent.
The
commenter
argued
that
combining
bituminous
and
subbituminous
units
in
one
category
would
preserve
flexibility
for
fuel
blending
and
switching
without
affecting
the
applicable
emission
standard.
Although
fuel
switching
is
not
an
option
due
to
design
limitations,
the
commenter
stated
that
there
are
plants
that
are
capable
of
burning
both
ranks
of
coal.
According
to
the
commenter,
if
other
coal
ranks
such
as
lignite
are
given
a
separate
limit,
the
use
of
lower
rank
coal
should
be
subject
to
approval,
considering
either
the
operation
of
the
facility
or
other
environmental
impacts,
such
as
NOx
or
SO2
reductions.
Another
commenter
(
OAR­
2002­
0056­
3406)
recommended
a
single
standard
for
existing
pulverized
coal
units
burning
bituminous
and
subbituminous
coal.

Response:

As
noted
above,
EPA
believes
that
subcategorization
by
coal
rank,
including
for
2­
22
bituminous
and
subbituminous
ranks,
is
appropriate
in
this
case.
The
ability
of
some
units
to
burn
more
than
one
rank
of
coal
does
not
override
the
overall
appropriateness
of
the
approach.
We
will
address
later
in
this
document
the
respective
emission
limits
for
the
various
coal
ranks.
Further,
we
believe
that
the
regulatory
approach
being
taken
(
e.
g.,
cap­
and­
trade)
will
address
the
monitoring
and
recordkeeping
concerns
raised.

Comment:

One
commenter
(
OAR­
2002­
0056­
1852)
sought
clarification
on
how
EPA
will
calculate
a
Hg
emission
standard,
based
upon
the
proposed
subcategories,
for
coals
that
have
undergone
pre­
combustion.
According
to
the
commenter,
pre­
combustion
technology
alters
a
fuel's
chemical
and
physical
properties
so
that
the
end
resulting
fuel
does
not
resemble
the
initial
feedstock.

Response:

Under
the
approach
being
taken
for
the
final
rule
(
i.
e.,
cap­
and­
trade),
units
will
be
assigned
Hg
allocations.
Compliance
with
the
allocated
Hg
emissions
"
cap"
may
then
be
accomplished
by
any
means
the
owner/
operator
chooses.

Comment:

One
commenter
(
OAR­
2002­
0056­
2269)
recommended
combining
subbituminous
coal
and
western
bituminous
coal
into
a
single
subcategory
because:

(
1)
The
similar
low
sulfur,
low
Hg,
low
Cl,
and
high
calcium
content
of
western
bituminous
and
subbituminous
coal
is
consistent
with
similar
Hg
flue
gas
speciation
(
and
consequently,
similar
emission
control
performance);

(
2)
Combining
them
into
a
single
class
simplifies
equitable
development
and
enforcement
of
rules;
and
(
3)
The
amount
of
Hg
in
western
bituminous
coal
is
only
5
percent
of
the
total
Hg
in
coal
burned
in
the
U.
S.,
so
this
change
would
have
a
negligible
effect
on
emission
reductions.

They
recommended
that
the
same
limits
as
proposed
for
subbituminous
coal
also
apply
to
western
bituminous
coals
at
new
and
existing
plants.
The
commenter
believed
that
the
proximity
of
subbituminous
and
bituminous
coals
in
the
west
will
cause
market
impacts
and
complicated
oversight
if
limits
are
specified
by
rank.
The
commenter
stated,
for
example,
both
kinds
of
coal
may
be
produced
from
a
single
mine
or
a
single
county
or
region.
And,
where
the
ASTM
rank
parameter
is
near
the
subbituminous/
bituminous
threshold,
the
commenter
stated
that
regulators
will
need
to
consider
complicated
scientific
factors
as
well
as
the
impact
of
the
sampling
method
on
moisture
content
to
know
which
rank
is
which.
The
commenter
also
recommended
that
State
Hg
budgets
should
be
revised
to
reflect
coal
origin,
where
the
algorithm
used
for
plants
burning
subbituminous
coal
is
also
used
for
plants
burning
western
bituminous
coal
and
adjusted
in
2­
23
proportion
to
their
fractional
share
of
western
bituminous
coal
as
needed.

Response:

As
noted
above,
although
EPA
recognizes
that
the
ASTM
classification
system
may
not
be
perfect
and,
in
fact,
has
occurrences
of
overlap,
it
remains
the
most
widely
accepted
system
and,
therefore,
is
appropriate
for
use
in
subcategorizing
for
the
purpose
of
this
rule.

2.2.4
Lignite
Comment:

To
recognize
the
differences
in
lignite
coals,
several
commenters
(
OAR­
2002­
0056­
1803,
­
2054,
­
2422,
­
2844,
­
2867,
­
2915,
­
3327,
­
3440,
­
3463,
­
3469,
­
3510,
­
3543,
­
4191,
­
4891)
stated
their
support
for
creation
of
a
subcategory
for
units
burning
Gulf
Coast
lignite
separate
from
units
burning
Fort
Union
lignite.
One
commenter
(
OAR­
2002­
0056­
3543)
supported
a
separate
subcategory
for
Gulf
Coast
lignite
because
the
current
rule
structure
could
force
generators
to
switch
coal
ranks,
primarily
from
lignite
and
subbituminous
to
bituminous
coal.
According
to
the
commenter,
Gulf
Coast
lignite
is
substantially
different
from
other
lignite
coals
and,
because
it
is
an
important
fuel
source,
should
remain
viable.
The
commenter
stated
that
under
a
cap
and
trade
approach,
the
subcategorization
should
be
used
to
determine
allocations
for
State
Hg
budgets.
According
to
some
commenters
(
OAR­
2002­
0056­
2054,
­
2422,
­
3510,
­
4191),
the
higher
Hg
content
of
Gulf
Coast
lignite
and
higher
Hg
emissions
from
units
burning
Gulf
Coast
lignite
versus
Fort
Union
lignite
for
similarly
controlled
boilers
justifies
separate
subcategories
and
higher
emission
limits
for
units
burning
Gulf
Coast
lignite.
Several
commenters
(
OAR­
2002­
0056­
2915,
­
3463,
­
3478,
­
4191)
stated
that
inaccurate
analytical
methods
(
method
ASTM
D
3684
for
coals
with
high
ash
and
moisture
content)
used
during
EPA's
Hg
ICR
coal
sampling
gave
erroneously
low
Hg
content
readings
for
Gulf
Coast
lignite
in
comparison
to
more
accurate
analytical
methods.
Using
a
new
analyzer
and
ASTM
D
6414
method,
the
commenter
stated
that
Hg
in
fuel
averaged
a
six­
fold
increase
over
the
other
method.
A
commenter
(
3478)
stated
that
they
believe
that
all
high
ash
coals
may
have
a
higher
Hg
content
in
the
coal
than
the
ICR
data
reveals
and
if
this
is
the
case,
and
the
stack
emissions
are
also
higher,
then
EPA
has
proposed
a
much
more
stringent
standard
than
a
70
percent
reduction.
The
commenter
further
discusses
the
problems
with
the
test
methods
used
to
analyze
for
Hg
and
Cl
in
these
samples
and
stated
that
the
allowance
allocations
must
be
based
on
a
baseline
adjustment
factor
of
at
least
3
for
lignite
plants
to
meet
the
targets.

Several
commenters
(
OAR­
2002­
0056­
2915,
­
3463,
­
4191)
stated
that
if
EPA
does
not
establish
a
separate
subcategory
for
Gulf
Coast
lignite
with
a
higher
emission
standard,
they
should
offer
an
alternative
percent
reduction
option.

Response:

EPA
continues
to
believe
that
there
is
insufficient
evidence
available
to
justify
separate
subcategories
for
Gulf
Coast
and
Fort
Union
lignites.
The
reanalysis
of
the
data
in
support
of
2­
24
the
revised
new­
source
NSPS
Hg
emission
limits,
discussed
later
in
this
document,
incorporated
data
from
units
firing
both
types
of
lignite,
further
lessening
the
necessity
of
additional
subcategorization.
EPA
will
continue
to
evaluate
the
Hg
emission
data
that
becomes
available,
including
that
generated
through
the
studies
on
emerging
Hg
control
technologies
by
the
U.
S.
Department
of
Energy
(
DOE),
and
reassess
the
issue
of
further
subcategorizing
lignites
during
the
normal
NSPS
review
cycle.

Comment:

Although
one
commenter
(
OAR­
2002­
0056­
3406)
supported
the
separate
treatment
of
lignite
through
the
subcategorization
process,
the
commenter
adds
that
a
great
deal
of
research
and
development
is
focused
on
controlling
Hg
emissions
from
lignite
coal,
and
strict
control
standards
will
certainly
further
fuel
these
development
efforts.

Response:

EPA
concurs
with
this
comment
and
believes
that
the
regulatory
approach
being
taken
will
further
serve
to
advance
the
development
of
improved
Hg
control
technologies.

2.2.5
Integrated
Gasification
Combined
Cycle
(
IGCC)

Comment:

One
commenter
(
OAR­
2002­
0056­
2948)
opposed
including
IGCC
units
in
this
rulemaking
because
those
units
differ
fundamentally
from
electric
steam
generating
units.

Response:

EPA
agrees
that
IGCC
units
differ
fundamentally
from
other
types
of
coal­
fired
electric
utility
steam
generating
units
in
their
mode
of
combustion
and
operation.
However,
they
remain
"
fossil­
fired
electric
utility
steam
generating
units"
under
the
subpart
Da
definitions
of
"
fossil
fuel"
and
"
electric
utility
steam
generating
unit"
(
see
40
CFR
60.41a)
currently
included
in
subpart
Da
and,
therefore,
are
included
within
this
rule.

2.2.6
Coal
Refuse
Comment:

According
to
one
commenter
(
OAR­
2002­
0056­
2160),
waste
coals
are
insignificant
in
the
overall
fuel
mix;
there
is
no
value
in
regulating
them
separately,
which
creates
unnecessary
complexity.

One
commenter
(
OAR­
2002­
0056­
2162)
stated
that
waste
coal­
fired
plants
should
not
be
subject
to
the
proposed
Hg
rules.
2­
25
Response:

Although
insignificant
in
the
overall
mix
of
fuels
used
in
Utility
Units,
coal
refuse­
fired
units
are
typically
utilized
in
fluidized
bed
combustors
(
FBC),
a
type
of
boiler
not
in
general
use
for
other
coal
ranks.
For
this
reason,
coupled
with
the
fact
that
their
emission
characteristics
are
dissimilar
from
other
coal
ranks,
EPA
is
considering
coal
refuse
as
a
separate
subcategory
for
purposes
of
this
rule.

Comment:

According
to
one
commenter
(
OAR­
2002­
0056­
2920),
EPA
must
regulate
plants
burning
waste
coal
refuse,
including
culm,
gob,
and
subbituminous
coal
refuse,
as
incineration
units
under
CAA
section
129.
According
to
the
commenter,
it
is
not
relevant
whether
a
unit
recovers
energy
from
the
combustion
of
waste
(
coal
refuse­
burning
plants
do
not
fall
into
the
exception
for
specific
energy
recovery
units
under
section
129(
g)(
1)).
The
commenter
stated
that
EPA's
failure
to
regulate
coal
refuse­
burning
power
plants
as
incinerators
under
section
129
contravenes
the
CAA.

Response:

Coal
refuse
is
a
recognized
subcategory
under
subpart
Da
(
see
40
CFR
60.41b);
this
revision
of
the
rule
merely
continues
to
consider
"
coal
refuse"
as
a
subcategory
of
"
fossil
fuelfired
electric
utility
steam
generating
units."

Comment:

One
commenter
(
OAR­
2002­
0056­
2842)
noted
that
EPA
proposed
to
include
all
waste
coal
units
in
a
single
subcategory,
regardless
of
the
rank
of
waste
coal
burned
and
stated
that
EPA
must
establish
separate
waste
coal
subcategories
based
on
coal
rank
or
otherwise
adjust
the
waste
coal
emission
limits
to
reflect
the
control
and
other
issues
that
would
be
expected
to
be
associated
with
subbituminous
or
lignite
waste
coals.
The
commenter
also
stated
that
EPA
must
modify
the
limits
to
account
for
the
possibility
that
the
units
used
to
develop
the
limits
might
burn
any
rank
of
waste
coal
from
any
source,
which,
depending
upon
the
Hg
content
and
control
issues
of
the
Hg
in
the
coal,
would
require
adjustments
to
the
limits.
According
to
the
commenter,
waste
coal
units
have
the
same
issues
EPA
identified
for
conventional
units
regarding
coal
rank.
The
commenter
also
stated
that
EPA
has
based
the
limits
on
data
from
only
two
units,
both
of
which
fired
waste
bituminous
coals,
and
ignored
the
fact
that
waste
subbituminous
and
lignite
coals
can
be
expected
to
have
the
same
issues
concerning
emissions
controllability
as
the
coal
ranks
from
which
the
waste
coal
is
derived.
The
commenter
also
stated
that
EPA
must
take
the
same
considerations
into
account
to
the
extent
that
it
considers
a
rule
under
CAA
section
111.

Response:

As
the
commenter
noted,
EPA
used
the
only
coal
refuse
data
available
in
establishing
the
proposed
NSPS
emission
limits.
No
additional
coal
refuse
emission
data
were
provided
during
2­
26
the
public
comment
period;
therefore,
EPA
has
no
additional
data
upon
which
to
base
any
further
subcategorization
of
the
"
coal
refuse"
subcategory.
As
discussed
later
in
this
document,
EPA
is,
however,
reassessing
the
approach
taken
to
develop
the
new
source
NSPS
limits.

Comment:

One
commenter
(
OAR­
2002­
0056­
3525)
stated
that
waste­
fuel
combustion
is
a
variable
process,
because
the
waste
varies
from
mine
site
to
mine
site.
According
to
the
commenter,
existing
CFB
plants
are
among
the
newest
of
the
boiler
fleet
in
this
country,
most
having
been
built
to
meet
best
available
control
technology
(
BACT)
requirements
within
the
last
15
years.
According
to
the
commenter,
all
of
the
units
with
which
he
is
aware
have
current
Hg
removal
rates
of
96
to
99
percent.
The
commenter
stated
that
using
more
restrictive
input
limits
on
these
units
appears
to
be
punishing
facilities
that
made
early
investment
in
technology.
The
commenter
stated
that
the
variability
of
Hg
content
in
the
fuel
is
greater
than
that
of
regular
coal
and
that
carbon
injection
and
other
Hg
removal
methods
currently
under
study
are
not
directly
adaptable
to
CFB
design
operations.
The
commenter
stated
that
if
variability
of
fuel
quality
justifies
the
proposed
limit
for
bituminous
coal,
then
at
least
a
similar
limit
seems
reasonable
for
a
unit
combusting
waste
products
from
bituminous
coal
mining
processes.
The
commenter
asserted
that
assignment
of
less
than
20
percent
of
that
value
to
units
that
currently
meet
BACT
is
overly
restrictive
and
discriminatory,
as
well
as
arbitrary
and
capricious.
The
commenter
submits
that
similarly,
emission
limits
for
firing
of
other
rank
coal
wastes
should
be
at
least
the
level
of
limits
applied
to
those
other
respective
coal
ranks.

Response:

EPA
disagrees
that
the
limits
proposed
for
coal
refuse­
fired
units
is
arbitrary
and
capricious
given
that
the
limits
are
based
on
data
from
such
units
and
were
not
extrapolated
from
non­
coal
refuse­
fired
units.
As
discussed
later
in
this
document,
EPA
is,
however,
reassessing
the
approach
taken
to
develop
the
new
source
NSPS
limits.

Comment:

According
to
one
commenter
(
OAR­
2002­
0056­
2162),
EPA
may
only
regulate
waste
coal­
fired
sources
as
part
of
the
broader
category
of
electric
utility
steam
generating
units,
rather
than
as
a
distinct
subcategory
subject
to
a
unique
emission
limitation.
The
commenter
pointed
out
that
EPA
has
developed
a
unique,
and
unduly
stringent,
Hg
emission
control
level
applicable
only
to
waste
coal­
fired
units
without
making
a
finding
that
emissions
from
waste
coal­
fired
sources
would
pose
a
hazard
to
public
health,
or
that
the
regulation
of
such
units
is
"
appropriate
and
necessary."
According
to
the
commenter,
EPA's
finding
that
it
is
"
appropriate
and
necessary"
to
regulate
Hg
emissions
for
electric
utility
steam
generating
units
applied
generally
to
all
coal­
fired
sources
in
that
source
category
and
that
it
is
inconsistent,
therefore,
for
EPA
to
distinguish
waste
coal­
fired
sources
under
the
proposed
rule
as
a
separate
and
distinct
source
category
subject
to
unduly
stringent
emission
limitations.
The
commenter
stated
that
any
determination
to
regulate
Hg
emissions
from
waste
coal
plants
 
as
sources
that
are
"
reasonably
anticipated
to
cause
adverse
health
effects"
 
only
can
be
justified
under
EPA's
statutory
mandate,
if
at
all,
if
waste
coal
sources
2­
27
are
members
of
the
broader
source
category
of
electric
utility
steam
generating
units.
Accordingly,
in
order
for
the
Agency
to
appropriately
regulate
waste
coal
plants,
it
must
not
distinguish
between
waste
coal
plants
and
other
coal­
fired
electric
utility
steam
generating
units
in
establishing
proposed
emission
limits.
For
these
reasons,
if
the
Agency
regulates
waste
coal
fired
sources
under
the
Proposed
Mercury
Rules,
the
commenter
argued
that
the
Hg
emission
levels
applied
to
waste
coal­
fired
sources
must
be
consistent
with
those
applied
to
conventional
coal­
fired
sources,
such
as
sources
firing
bituminous
coal.

Response:

As
noted
earlier,
EPA
believes
that
it
has
the
statutory
authority
to
subcategorize
"
fossil
fuel­
fired
electric
utility
steam
generating
units"
for
purposes
of
regulation
under
CAA
section
111.
Further,
based
on
the
subcategorization,
EPA
proposed
a
unique
Hg
emissions
limit
for
each
of
the
subcategories
and
does
not
believe
that
any
are
"
unduly
stringent"
as
the
commenter
asserts,
given
that
each
was
based
on
the
data
available.
As
discussed
later
in
this
document,
EPA
is,
however,
reassessing
the
approach
taken
to
develop
the
new
source
NSPS
limits.

2.2.7
Fluidized
Bed
Combustors
Comment:

Several
commenters
(
OAR­
2002­
0056­
2375,
­
2911,
­
2918,
­
2948,
­
3537)
supported
a
subcategory
for
FBC
units.
Three
commenters
(
OAR­
2002­
0056­
2375,
­
2918,
­
3537)
stated
that
EPA
should
create
a
subcategory
for
FBC
units
to
subsume
the
proposed
subcategory
for
units
that
combust
waste
coal
because
FBC
units
use
a
fundamentally
distinct
process
for
fuel
combustion
that
implicates
differences
in
design,
construction,
and
equipment.
According
to
the
commenters,
such
differences
are
sufficient
to
establish
that
FBC
units
constitute
a
different
"
class"
or
"
type"
of
utility
steam
generating
unit.
Both
commenters
stated
that
subcategorization
is
further
warranted
because
the
FBC
unit
process
and
design
differences
have
significant
implications
for
Hg
removal
efficiency.
One
commenter
(
OAR­
2002­
0056­
2918)
provided
a
list
of
the
main
differences
between
FBC
units
and
conventional
boilers
and
stated
that
these
differences
are
important
for
the
higher
Hg
removal
efficiencies
of
FBC
units
and
such
differences
should
make
FBC
units
a
distinct
subcategory.
The
commenter
offered
examples
of
when
EPA
has
created
subcategories
among
sources
due
to
the
performance
of
control
technology
(
i.
e.,
steel
pickling
and
phosphoric
acid
manufacturing
MACT).

Two
commenters
(
OAR­
2002­
0056­
3445,
­
3556)
supported
EPA's
proposed
subcategories
based
on
coal
rank
but
feel
additional
subcategorization,
specifically
a
separate
category
for
FBC
units,
is
appropriate
because
FBC
units
use
a
fundamentally
different
combustion
process
than
pulverized­
coal
units,
making
them
a
different
type
of
source.

Response:

EPA
agrees
that
FBC
units
operate
and
are
designed
differently
than
conventional
2­
28
pulverized
coal
(
PC)
boilers.
However,
with
the
exception
of
FBC
units
firing
coal
refuse,
there
was
no
clear
indication
from
the
available
data
that
such
units
impacted
on
the
ultimate
Hg
control
effected.
That
is,
in
some
cases,
FBC
units
had
higher
removal
rates
than
most
with
respect
to
their
Hg
emissions;
in
other
cases,
FBC
units
had
lower
removal
rates
than
most.
Therefore,
EPA
concluded
that
it
was
the
coal
rank,
rather
than
the
process
type
(
e.
g.,
FBC,
PC)
that
should
govern
in
any
determination
relating
to
subcategorization.

2.2.8
Fuel
Switching
and
Impacts
on
U.
S.
Coal
Supply
Comment:

Many
comments
were
received
regarding
fuel
switching
and
the
impacts
of
the
proposed
rule
on
fuel
switching.
Several
commenters
(
OAR­
2002­
0056­
1969,
­
2067,
­
2260,
­
2834,
­
2897,
­
3198)
agreed
with
EPA
that
fuel
switching
is
not
practicable
to
meet
the
proposed
Hg
emission
limits.
One
commenter
(
OAR­
2002­
0056­
2260)
stated
that
furthermore,
there
exists
no
one
fuel
in
sufficient
quantities
and
availability
that
can
be
used
by
all
utilities.
The
commenter's
boilers
were
designed
to
burn
western
subbituminous/
bituminous
coals
and
cannot
switch
to
burn
eastern
bituminous
coals.
Eastern
coals
also
have
higher
levels
of
sulfur
and
would
overload
their
scrubber
control
units.
The
commenter's
remote
location
in
southeastern
Arizona
also
makes
it
impossible
to
transport
coals
from
regions
other
than
the
west.
Additionally,
the
commenter's
units
are
limited
in
the
amount
of
natural
gas
that
can
be
burned
because
of
severe
constraints
on
the
natural
gas
supply
in
the
region.

One
commenter
(
OAR­
2002­
0056­
1969)
stated
that
EPA
has
appropriately
concluded
that
fuel
switching
is
not
a
compliance
option
which
is
consistent
with
the
CAA
and
favors
the
development
of
consistent
standards
that
do
not
create
regional
inequities
or
favor
one
fuel
type
over
another.

One
commenter
(
OAR­
2002­
0056­
2945)
stated
that
any
fuel
switching
or
shift
in
coal
utilization
away
from
bituminous
coal
due
to
the
proposed
rules
would
have
a
drastic
adverse
impact
on
mining
employment
and
on
electric
power
generation.

One
commenter
(
OAR­
2002­
0056­
2891)
stated
that
cooperatives
believe
that
fuel
switching
is
not
a
reasonable
or
practical
alternative
for
many
units
to
meet
the
new
emission
limits
and
that
in
many
cases,
plants
may
have
no
option
but
to
shut
down.

Response:

Modeling
done
in
support
of
EPA's
proposed
rules
does
not
indicate
that
a
significant
amount
of
fuel
switching
will
be
undertaken
by
the
utility
sector
to
comply
with
the
proposed
rules.
Some
companies
may
chose
to
change
fuels
to
effect
compliance
with
either
the
CAIR
or
CAMR,
or
both.
Further,
EPA
believes
that
some
sources
have
extremely
limited
options
(
in
some
cases,
no
options)
with
regard
to
other
coals
or
fuels
that
could
be
fired
at
a
given
Utility
Unit.
Therefore,
EPA
proposed
emission
limits
that
would
be
achievable
for
such
units
that
would
not
require
fuel
switching.
2­
29
Comment:

Some
commenters
were
concerned
over
the
impacts
of
the
rule
on
bituminous
coal.
One
commenter
(
OAR­
2002­
0056­
3445)
stated
that
in
addition
to
coal­
fired
power
plants
which
burn
bituminous
coal,
they
also
own
and
operate
bituminous
coal
mining
and
terminal
operations.
The
commenter
stated
that
any
Hg
regulation
must
treat
all
coals
fairly.
The
commenter
added
that
providing
an
advantage
to
coal
from
one
region
over
coal
from
other
regions
encourages
fuel
switching
as
a
compliance
strategy
and
could
limit
the
diversity
of
fuels
available
for
electrical
generation.
The
commenter
stated
that
it
is
critical
to
the
nation's
security
that
all
forms
of
coal
continue
to
be
available
for
electrical
generation.

One
commenter
(
OAR­
2002­
0056­
2845)
stated
that
any
rule
must
not
favor
one
rank
of
coal
over
another
and
that,
although
fuel
switching
appears
to
be
an
acceptable
control
option,
it
will
severely
reduce
employment
in
the
bituminous
coal
sector.

One
commenter
(
OAR­
2002­
0056­
2692)
stated
that
the
proposed
rules
threaten
the
future
of
the
Appalachian
coal
industry.
The
commenter
stated
that
industry
and
elected
representatives
from
western
States
have
for
some
time
pushed
EPA
for
a
rule
that
would
advantage
western
coal.
According
to
the
commenter,
EPA
responded
to
these
concerns
by
publishing
rules
on
January
30,
2004,
that
provide
a
major
disadvantage
to
eastern
coal.
The
commenter
stated
that
specifically,
the
rules
as
proposed
require
sharp
cuts
in
Hg
emissions
from
eastern
bituminous
coals,
but
require
far
smaller
cuts
from
the
subbituminous
and
lignite
coals
of
the
west.
According
to
the
commenter,
this
difference
in
treatment
is
so
great
that
it
will
certainly
produce
an
illogical
result:
utilities
will
be
encouraged
to
burn
more
western
coal,
despite
the
fact
that
it
has
higher
levels
of
Hg.
The
commenter
stated
that
the
result
will
be
more
pollution
and
less
eastern
coal
jobs.

One
commenter
(
OAR­
2002­
0056­
3469)
stated
that
the
Hg
rule
and
the
CAIR
will
further
concentrate
U.
S.
coal
supply
among
Wyoming
Southern
PRB
subbituminous
coal
producers
and
delay
emission
control
technology
retrofits
and
further
erode
production
from
the
Illinois
Basin
as
well
as
niche
coal
and
lignite
production
regions,
including
certain
Indian
reservations.

One
commenter
(
OAR­
2002­
0056­
2661)
stated
that
EPA's
generalities
of
Hg
emissions
in
coal,
as
a
one
size
fits
all,
implies
a
greater
burden
for
subbituminous
coal
users.
The
commenter
noted
that
substantial
reductions
in
SO2
and
NOx
were
achieved
by
the
conversion
to
low
sulfur
coal
­
subbituminous
coals.
The
commenter
stated
that
units
that
have
borne
the
economic
burden
for
fuel
switching
should
not
bear
a
disproportionate
burden
of
Hg
emission
reduction
strategy
now.
Further,
the
commenter
did
not
believe
it
is
in
the
best
interest
of
the
U.
S.
energy
policy
to
favor
limited
coal
choices
based
on
any
emission
threshold
currently
established
by
EPA.
According
to
the
commenter,
EPA's
policy
would
continue
to
hamper
U.
S.
energy
needs
and
reliance
on
foreign
and
other
inappropriate
sources
of
fuel
for
U.
S.
consumer
energy
needs.

One
commenter
(
OAR­
2002­
0056­
3531)
expressed
concern
with
the
discriminating
impact
the
proposed
rule
will
have
on
Ohio
and
other
eastern
bituminous
coals.
The
commenter
stated
the
current
rule
proposals
may
allow
sources
burning
western
coal
to
continue
to
do
so
2­
30
without
installing
any
control
technologies.
The
commenter
stated
that
essentially,
the
cost
of
all
Hg
reductions
under
the
current
proposal
would
be
borne
entirely
by
sources
burning
eastern
coals,
such
as
in
Ohio.
According
to
the
commenter,
there
is
no
valid
technical
or
economic
justification
for
such
discrimination.
The
commenter
stated
that
Hg
reductions
must
be
based
on
an
examination
of
the
best­
controlled
sources
in
each
fuel
subcategory
and
a
valid
determination
of
the
level
of
control
that
can
be
achieved
within
each
subcategory.
The
commenter
concluded
that
EPA
must
revise
the
rules
to
not
favor
regional
fuel
usage
and,
instead,
require
reductions
for
all
sources
based
on
available
technical
data.
One
commenter
(
OAR­
2002­
0056­
2870)
encouraged
EPA
to
adopt
approaches
to
control
Hg
emissions
from
power
plants
that
will
ensure
a
level
playing
field
among
all
coal
ranks
and
will
promote
an
equitable
strategy
to
address
interstate
pollutant
transport.
The
commenter
claimed
the
rule
creates
an
uneven
playing
field
that
would
harm
the
bituminous
coal
industry
and
its
coal
miners.
One
commenter
(
OAR­
2002­
0056­
2937)
recognized
that
although
difficult
regulatory
decisions
must
be
made,
the
commenter
felt
that
good
science,
coupled
with
a
sense
of
fairness
can
produce
a
rule
that
yields
Hg
reduction
in
a
way
that
does
not
compromise
the
viability
of
bituminous
coal
producing
regions.

Response:

EPA's
modeling
has
shown
little
significant
coal
switching
as
a
result
of
the
proposed
CAMR
and
CAIR
actions.
We
believe
that
this
rebuts
the
commenter's
suggestions
that
one
or
another
coal
rank
is
"
advantaged"
or
"
disadvantaged"
with
respect
to
other
coal
ranks.
EPA's
responses
to
comments
on
the
allocation
adjustment
factors
are
found
elsewhere
in
this
document.

Comment:

Many
commenters
(
OAR­
2002­
0056­
1625,
­
1673,
­
1768,
­
1802,
­
2020,
­
2066,
­
3478,
­
3513,
­
3517,
­
3530)
expressed
concern
over
the
impacts
of
the
proposed
rule
on
the
nation's
energy
supply.
Several
commenters
(
OAR­
2002­
0056­
1673,
­
1768,
­
3478)
believed
that
the
Hg
levels
set
by
this
rulemaking
should
not
result
in
the
loss
of
viability
of
any
fuel
type,
such
as
lignite,
considering
the
severe
impact
this
would
have
on
local
communities,
jobs
and
the
nation's
energy
security
from
the
loss
of
this
significant
domestic
fuel
supply
for
electric
generation.

One
commenter
(
OAR­
2002­
0056­
3513)
stated
that
the
nation's
largest
energy
supply
will
be
unduly
impacted
if
EPA
fails
to
adequately
consider
the
vital
role
that
coal­
based
electricity
plays
in
America's
current
and
future
economic
prosperity;
the
demand
for
electricity
is
growing
and
other
fuels
 
such
as
natural
gas
 
cannot
meet
this
growing
demand.

One
commenter
(
OAR­
2002­
0056­
3517)
stated
that
coal
represents
our
single
largest
domestic
reserve
of
fossil
fuel,
representing
95
percent
of
the
reserves
(
as
compared
to
crude
oil
at
2
percent
and
natural
gas
at
3
percent).
The
commenter
asserted
that
coal
is
electricity,
accounting
for
87
percent
of
the
use
of
coal
in
the
nation,
and
is
responsible
for
50
percent
of
total
electricity
generated
in
the
U.
S.
The
commenter
believed
it
is
incumbent
upon
EPA
to
promulgate
responsible
and
achievable
standards
so
as
to
not
impact
the
reliability
and
cost
of
2­
31
electric
service.

Several
commenters
(
OAR­
2002­
0056­
1768,
­
3530)
stated
that
the
final
rule
must
be
consistent
with
the
need
for
reliable
and
affordable
electric
power,
including
affordable
use
of
all
coal
ranks
and
options
for
efficient
on­
site
power
generation
such
as
CHP.
The
commenter
stated
that
the
final
rule
must
facilitate
 
not
discourage
 
the
availability
of
an
adequate
and
diverse
fuel
supply
for
the
future,
including
coal,
natural
gas,
nuclear
energy,
hydroelectric,
and
renewable
sources.
According
to
several
commenters
(
OAR­
2002­
0056­
1768,
­
2066),
the
final
rule
must
not
aggravate
the
already
precarious
natural
gas
supply
which
is
currently
inadequate.
One
commenter
(
OAR­
2002­
0056­
2066)
stated
that
these
actions
will
inhibit,
if
not
totally
eliminate,
plans
for
any
new
coal­
fired
base
load
electric
generation,
and
this
forgone
option
will
undoubtedly
be
replaced
by
additional
natural
gas­
fired
generation.

Should
EPA
proceed
with
the
rulemaking,
one
commenter
(
OAR­
2002­
0056­
2847)
urged
the
agency
to
adopt
sufficient
subcategories
of
expected
reductions
so
as
to
limit
the
potential
for
economic
disruption
in
the
coal,
transportation,
and
utility
industry
sectors.

Although
supporting
full
use
of
categories
and
subcategories
to
adequately
address
differences
in
abilities
to
reduce
Hg
based
on
such
things
as
coal
chemistry
that
varies
with
coal
rank,
one
commenter
(
OAR­
2002­
0056­
3200)
stated
that
it
is
imperative
that
no
fuel
type
be
afforded
an
unfair
market
advantage
and
that
overly
aggressive
mandatory
reductions
in
Hg
emissions
be
avoided
that
would
lead
to
loss
of
fuel
diversity,
higher
energy
prices
and
a
strain
on
electric
reliability,
all
of
which
are
inconsistent
with
sound
energy
policies.

Several
commenters
(
OAR­
2002­
0056­
1675,
­
2160,
­
2660,
­
2875,
­
2904,
­
2908,
­
2937,
­
3324,
­
3366,
­
3560)
stated
that
limits
that
favor
one
coal
over
another
may
have
considerable
economic
impacts
due
to
the
higher
control
costs
affecting
coal
producers,
utilities,
and
customers.
According
to
two
commenters
(
OAR­
2002­
0056­
2875,
­
2937),
a
significant
loss
of
employment
would
occur
in
the
Appalachian
areas
of
their
State
and
would
be
devastating
to
an
area
already
suffering
from
excessively
high
unemployment
rates.

Several
commenters
(
OAR­
2002­
0056­
1675,
­
1677,
­
1762,
­
2944)
stated
that
subbituminous
coal,
which
is
primarily
produced
in
the
West,
will
receive
favorable
treatment
at
the
expense
of
eastern
bituminous
coal
that
will
make
bituminous
coal
virtually
non­
competitive
with
western
subbituminous
coal.
One
commenter
(
OAR­
2002­
0056­
2944)
stated
that
subcategorization
will
result
in
regional
disparities
and
inconsistences
in
the
industry
which
EPA
stated
that
it
intended
to
avoid.

One
commenter
(
OAR­
2002­
0056­
1852)
opposed
EPA's
proposal
to
subcategorize
stating
that
the
widely
varying
proposed
emission
rates
for
coal
subcategories
could
cause
disruption
to
coal
supplies
and
fuel
blends
in
order
for
utilities
to
comply
with
the
Hg
standard.

Response:

As
noted
above,
EPA's
modeling
has
shown
little
significant
coal
switching
as
a
result
of
2­
32
the
proposed
CAMR
and
CAIR
actions.
We
believe
that
this
rebuts
the
commenter's
suggestions
that
one
or
another
coal
rank
is
"
advantaged"
or
"
disadvantaged"
with
respect
to
other
coal
ranks.
Further,
we
do
not
believe
that
the
final
rules
will
have
a
negative
impact
on
the
nation's
energy
security,
employment
rates,
or
energy
reliability.
Responses
to
comments
on
the
allocation
adjustment
factors
are
found
elsewhere
in
this
document.

Comment:

One
commenter
(
OAR­
2002­
0056­
3198)
stated
that
these
regulations
will
have
a
tremendous
impact
on
the
mining
industry
in
Wyoming
and
on
the
state
as
a
whole
and
it
is
critical
that
EPA
adequately
address
the
unique
chemistry
of
Wyoming
coal.

Response:

EPA
believes
that
it
has
adequately
addressed
the
commenter's
concerns
in
the
rule
through
the
finalizing
of
two
emission
limits
for
subbituminous
coals,
depending
on
the
type
of
FGD
unit
used
and
the
allocation
factors
used
in
the
trading
program.

Comment:

According
to
one
commenter
(
OAR­
2002­
0056­
3254),
Illinois
Hg
emissions
have
risen
about
28
percent
while
burning
western
coal.
The
commenter
stated
that
Illinois
coal
Hg
content
is
1/
3
that
of
western
coal
and
that
EPA
should
not
allow
western
coal
to
be
burned.

Response:

EPA
does
not
feel
that
it
is
in
the
best
interest
of
the
country
to
prohibit
the
use
of
some
ranks
of
coal
when
those
coals
can
be
adequately
controlled
to
limit
Hg
emissions.

Comment:

One
commenter
(
OAR­
2002­
0056­
3525)
encouraged
EPA
to
reduce
Hg
emissions
without
undermining
fuel
diversity.
The
commenter
believed
that
flexibility
will
more
likely
be
achieved
through
EPA's
market­
based,
cap­
and­
trade,
approach
to
controlling
Hg
emissions
than
through
the
MACT
approach.
The
commenter
stated
that
the
tight
time
frame
for
reductions
in
the
Hg
MACT
approach
could
leave
utilities
with
no
real
choice
but
to
install
a
significant
quantity
of
additional
gas
fired
generation
facilities
and
thereby
switch
fuels
as
a
primary
means
of
compliance.
The
commenter
stated
that
market­
based
mechanisms,
like
the
successful
cap­
and­
trade
program
under
the
acid
rain
program,
will
dramatically
increase
the
cost­
effectiveness
of
any
program.
The
commenter
supported
an
approach
of
imposing
Hg
emissions
reductions
to
a
level
commensurate
with
co­
benefits
achieved
through
the
SO2
and
NOx
emissions
reductions
of
the
proposed
CAIR.
The
commenter
stated
this
will
help
mitigate
the
costs
of
compliance,
which
will
be
borne
by
all
electricity
consumers.
According
to
the
commenter,
when
establishing
emission
limits,
the
inherent
fuel
quality
differences
and
the
varying
capability
of
emission
control
devices
to
capture
Hg
between
coal
ranks
needs
to
be
considered
2­
33
and
properly
accommodated.
The
commenter
urged
EPA
to
establish
a
rule
that
does
not
preferentially
disadvantage
a
particular
fuel
or
fuel
type
so
that
fuel
diversity
of
the
electrical
generation
sector
is
not
artificially
restricted.

Response:

EPA
concurs
with
the
commenter's
belief
that
a
cap­
and­
trade
approach
will
better
serve
to
protect
the
environment
while
at
the
same
time
allowing
the
industry
to
maintain
fuel
diversity.

2.2.9
Other
Subcategorization
Approaches
Comment:

One
commenter
(
OAR­
2002­
0056­
2422)
suggested
the
following
subcategorization
approach:
hot
stack,
wet
stack,
and
saturated
stack
configurations.
According
to
the
commenter,
this
approach
recognizes
that
many
hot­
stack
eastern
units
fired
with
bituminous
coals
are
not
cost­
effective
candidates
for
capital­
intensive
control
technology
retrofits.
The
commenter
believed
that
EPA
should
provide
emission­
based
exemptions
for
relatively
small
Hg­
emitting
units
to
mitigate
the
substantial
risks
of
plant
closures
among
older
and
smaller
units.

One
commenter
(
OAR­
2002­
0056­
2634)
stated
in
addition
to
subcategorization
by
coal
rank,
further
subcategorization
could
be
warranted,
based
on
pollution
control
process
configuration
and
coal
chemistry,
due
to
its
impact
on
Hg
speciation
and
its
ability
to
be
controlled
by
present
technology.

Response:

EPA
believes
that
cost­
effective
emission
reduction
approaches
are
available
for
"
hot­
stack"
units,
particularly
when
the
CAMR
is
taken
in
concert
with
the
CAIR.
EPA
analyzed
the
commenter's
suggested
subcategorization
approach
but
believes
subcategorization
based
on
coal
rank
is
more
easily
implemented
and
more
adequately
addresses
the
coal
chemistry
issue.

Comment:

One
commenter
(
OAR­
2002­
0056­
2267)
believed
that
EPA
should
create
a
subcategory
for
small
municipal
generators
under
the
MACT
approach.

Response:

EPA
sees
no
justification
for
creating
such
a
subcategory.
Such
units
are
constructed
and
operated
in
a
manner
similar
to
other
"
electric
utility
steam
generating
units"
and,
as
such,
are
sources
of
Hg
emissions.
Coal­
fired
municipal
units
otherwise
meeting
the
definition
would
be
subject
to
the
final
rule.
2­
34
2.2.10
New
Units
Comment:

Several
commenters
(
OAR­
2002­
0056­
1969,
­
2067,
­
2634,
­
2721,
­
2843,
­
3403,
­
3514,
­
3537)
supported
the
proposal
to
use
the
same
coal
subcategories
for
new
plants
as
for
existing
plants.
However,
one
commenter
(
OAR­
2002­
0056­
2067)
stated
that
the
EPA
ICR
reference
data
should
be
supplemented
with
more
recent
and
representative
power
plants
and
coal
sources.
The
commenter
stated
that
Hg
removal
data
used
to
set
the
standards
for
the
best
performing
utility
units
must
be
accurate
and
represent
the
variations
of
coal
within
each
coal
rank.
The
commenter
stated
that
standards
for
new
power
plants
should
be
adopted
to
encourage
the
construction
of
cleaner
coal
plants
and
maintain
a
diverse
mix
of
fuel.

One
commenter
(
OAR­
2002­
0056­
1969)
stated
that
the
historical
fuel
mix
is
indicative
of
regional
and
economic
conditions
and
fuel
needs
and
according
to
the
commenter,
selection
of
other
subcategorization
methodologies
for
new
units
could
affect
their
future
market
conditions
and
an
ongoing
need
for
a
diversified
electrical
generation
fuel
mix.

One
commenter
(
OAR­
2002­
0056­
2721)
believed
that
without
subcategorization,
the
location
of
new
units
will
be
biased
geographically
near
the
fuel
types
that
provide
for
the
ease
of
compliance.
According
to
the
commenter,
this
unfair
siting
advantage
will
place
strenuous
hardships
on
the
electrical
supply
chain
of
the
country
and
place
economic
hardship
in
areas
of
the
western
U.
S.
where
typically
the
low
Cl
content
of
coal
resides.

One
commenter
(
OAR­
2002­
0056­
3435)
recommended
a
single
subcategory
for
new
units
burning
bituminous
and
subbituminous
coal.
The
commenter
stated
that
the
difference
in
the
limits
for
new
bituminous
and
subbituminous
coal
would
allow
a
233
percent
increase
in
emissions.

Response:

EPA
continues
to
believe
that
new
sources
should
be
subcategorized
in
the
same
manner
as
existing
units.

Comment:

One
commenter
(
OAR­
2002­
0056­
3459)
stated
that,
although
EPA
has
only
spurious
rationale
for
subcategorization
of
existing
units,
there
is
no
rationale
for
new
units.
The
commenter
stated
that
these
can
be
designed
to
provide
optimum
performance
when
firing
all
coal
ranks
and
that
EPA
must
reject
subcategorization
and
establish
a
single
limit
for
new
units.
According
to
the
commenter,
the
effect
of
EPA's
proposal
is
to
make
the
standards
less
stringent
by
subcategorizing
according
to
the
rank
of
coal.
The
commenter
stated
that
the
words
of
a
statute
must
be
read
in
their
context
and
with
a
view
to
their
place
in
the
overall
statutory
scheme
and
that
Congressional
intent
was
to
use
subcategorization
sparingly;
the
same
reasons
the
NOx
NSPS
was
fuel
neutral
(
improvements
in
control
technologies
were
available
on
all
utility
boilers)
2­
35
applies
here.

Response:

EPA
believes
that
the
proposed
requirement
for
new
units
to
comply
with
an
output­
based
emission
limit
will
ensure
that
they
are
designed
to
achieve
optimum
performance.
However,
units
designed
to
burn
bituminous
coals
will
still
not
be
able
to
burn
lignite
coals
(
for
example)
and,
thus,
the
need
for
subcategorization
remains.
As
noted
earlier,
EPA
concurs
that
advancements
in
Hg
control
technologies
may
lead
to
more
"
fuel
neutral"
formats;
however,
that
time
has
not
come.

Comment:

One
commenter
(
OAR­
2002­
0056­
3537)
contends
that
IGCC
units
use
fundamentally
different
processes
than
conventional
boilers
and
should
be
placed
in
their
own
new
unit
subcategory.

Response:

EPA
concurs
that
new
IGCC
units
should
continue
to
be
subcategorized
separately
from
other
coal­
fired
units.

Comment:

One
commenter
(
OAR­
2002­
0056­
2862)
stated
that
in
establishing
a
new
source
NSPS
for
Hg,
EPA
should
also
subcategorize
coal­
fired
power
plants
based
on
the
process
type.
The
commenter
believed
that
it
is
vital
that
EPA
further
consider
the
performance
of
representative
boiler
types
and
variations
in
Hg
content.

Response:

EPA
does
not
believe
that
there
is
any
additional
justification
for
subcategorizing
new
units
by
process
type
than
there
is
for
existing
units.

2.2.11
Coal
Blends
Comment:

Two
commenters
(
OAR­
2002­
0056­
2535,
­
3435)
favored
a
subcategory
for
units
burning
a
blend
of
subbituminous
and
bituminous
coals.
One
commenter
(
OAR­
2002­
0056­
2535)
believed
that
blends
of
subbituminous
and
bituminous
coals
should
not
be
categorized
under
subbituminous
coal.
The
commenter
stated
that
EPA
incorrectly
set
the
limit
for
subbituminous
coal
by
mis­
classifying
blended
fuel
units
as
subbituminous
units,
resulting
in
a
erroneously
higher
number
of
plants
classified
as
subbituminous
plants.
The
commenter
cited
certain
plants
named
by
EPA
as
being
subbituminous
plants
(
e.
g.,
Craig,
La
Cygne,
Lawrence,
Newton,
and
Presque
Isle)
2­
36
as
potentially
burning
blends
of
subbituminous
and
bituminous
coal.
For
each
of
the
plants
identified
as
burning
subbituminous
coal,
the
Energy
Information
Administration
(
EIA)
database
was
reviewed
by
the
commenter
to
determine
which
mine
the
coal
was
shipped
from
in
1999.
According
to
the
commenter,
EPA's
Table
2
summary
of
the
coal
supply
data
as
reported
to
the
EIA
for
these
plants,
shows
these
plants
categorized
as
subbituminous
plants,
but
may
instead
be
plants
that
burn
a
blend
of
bituminous
and
subbituminous
coals.
The
commenter
further
stated
that
neither
the
EIA
data
nor
the
ICR
data
differentiates
as
to
what
coals
were
delivered
to
which
unit
within
a
facility,
so
the
shipments
listed
above
are
for
the
plant
as
a
whole
for
1999.
The
commenter
was
unable
to
find
any
clear
documentation
as
to
what
rank
of
coal
was
being
burned
during
the
EPA
ICR
tests.
The
commenter
stated
that
unless
EPA
is
able
to
accurately
determine
what
coals
were
burned
during
the
test,
the
assumption
must
be
made
that
it
was
a
subbituminous/
bituminous
blend
and
the
plant
must
be
placed
in
the
"
blend"
category.
The
commenter
further
stated
as
unsound
the
suggestion
that
any
plant
that
burned
over
90
percent
subbituminous
coal
should
still
be
classified
as
a
subbituminous
unit
and
that
the
remaining
blend
be
considered
a
deminimus
amount.
The
commenter
stated
that
there
needs
to
be
a
better
evaluation
of
blended
coals,
and
how
these
different
ranks
of
coals
interact
relative
to
the
species
of
Hg
that
is
emitted.

Response:

As
noted
above,
EPA
does
not
believe
that
a
subcategory
based
on
blended
use
of
bituminous
and
subbituminous
coals
is
warranted.
EPA
relied
on
the
facilities
to
provide
accurate
information
regarding
the
rank
of
fuel
burned
and,
in
some
cases,
errors
were
corrected.
It
is
true
that
some
units
noted
by
the
commenter
received
shipments
of
multiple
ranks
of
coal
during
the
reporting
period,
they
reported
burning
only
one
rank
of
coal
during
their
emission
test
program
and,
therefore,
have
been
classified
as
being
in
that
subcategory.
However,
as
noted
later
in
this
document,
EPA
has
reevaluated
the
basis
for
the
new
source
NSPS
limits
for
the
final
rule.

Comment:

Commenter
OAR­
2002­
0056­
3459
states
that
EPA's
proposed
case­
by­
case
alternative
for
units
burning
a
blend
of
coals
is
unlawful.
EPA
must
establish
emission
standards
for
each
subcategory
of
sources
that
emit
HAP
and
those
standards
are
to
be
based
on
the
best
performing
units
within
the
subcategory.
However,
EPA
does
not
propose
a
uniform
standard
for
units
burning
a
blend
of
coals
and
does
not
base
the
standard,
such
as
it
is,
on
the
best
performing
units.
Even
though
EPA
effectively
creates
a
subcategory
for
units
burning
a
blend
of
coals,
it
makes
no
effort
to
establish
standards
for
that
subcategory.

Response:

The
approach
being
taken
for
blended
coals
is
consistent
with
the
procedures
already
inplace
in
40
CFR
60,
subpart
Da.

2.2.12
Other
2­
37
Comment:

One
commenter
(
OAR­
2002­
0056­
2897)
agreed
with
EPA's
decision
to
subcategorize
by
coal
rank
and
to
differentiate
between
bituminous
and
subbituminous
coals.
The
commenter
also
stated
that
the
ICR
data
used
to
support
the
claim
that
PRB
coal
is
compliant
must
be
questioned.
The
commenter
agreed
with
EPA's
determination
that
the
overlap
in
coal
classification
properties
does
not
compromise
its
ability
to
subcategorize
by
coal
rank
and
overlap
only
occurs
in
a
very
limited
number
of
cases
and
it
remains
true
that
coal
rank
is
a
significant
factor
that
distinguishes
the
design
and
operational
characteristics
of
different
boilers.

Response:

EPA
has
reanalyzed
the
data
used
to
support
the
Hg
emission
limit
for
subbituminous
coals.
Discussion
of
this
reanalysis
is
contained
elsewhere
in
this
document.

Comment:

Not
all
commenters
(
OAR­
2002­
0056­
2661,
­
2692,
­
2870,
­
2937,
­
2944,
­
3208,
­
3469,
­
3531,
­
4139)
agreed
with
EPA's
use
of
subcategories.
One
commenter
(
OAR­
2002­
0056­
2944)
stated
that
the
combustion
processes
involved
in
IGCC
systems,
FBC,
and
PC
boilers
are
themselves
fundamentally
different
in
their
mechanical
operation
and
the
resulting
processes
offer
distinctly
different
possibilities
for
limiting
Hg
emissions.
The
commenter
added
that
in
actual
practice
each
of
these
combustion
types
produces
significantly
different
relative
Hg
emissions.
According
to
the
commenter,
because
the
differences
between
these
classes
of
coal
combustors
is
a
matter
of
kind,
rather
than
one
of
degree,
it
is
logical
to
determine
separate
emission
limits
for
them.
The
commenter
believed
that
because
the
combustion
process,
opportunities
for
limiting
emissions,
and
typical
emission
results
of
cyclone
boilers
and
stoker
boilers
are
very
similar
to
those
of
PC
boilers,
it
makes
regulatory
sense
to
combine
them
into
the
class
of
pulverized
boilers.

Response:

As
noted
above,
EPA
concurs
that
IGCC
units
should
be
subcategorized
separately
but
disagrees
with
the
commenters
with
regard
to
FBC
units.

Comment:

One
commenter
(
OAR­
2002­
0056­
4139)
suggested
that
the
logic
used
in
establishing
the
subcategories
needs
to
be
reassessed.

Response:

EPA
has
reviewed
its
analysis
leading
to
the
proposed
subcategories
and
continues
to
believe
that
the
subcategories
proposed
continue
to
be
appropriate.
2­
38
Comment:

In
addition
to
demonstrating
the
efficacy
of
ACI,
one
commenter
(
OAR­
2002­
0056­
3208)
and
other
participants
in
research
funded
in
part
by
the
U.
S.
Department
of
Energy's
National
Energy
Technology
Laboratory
stated
that
they
are
exploring
the
potential
use
of
oxidizing
agents,
enhanced
sorbents,
and
coal
blending
as
potential
pathways
to
achieving
significant
reductions
in
Hg
emissions
from
use
of
PRB
coals.
On
this
basis,
the
commenter
urges
EPA
to
adopt
a
separate
subcategory
for
PRB
coals
within
a
subbituminous
coal
category.

One
commenter
(
OAR­
2002­
0056­
4139)
agreed
that
the
importance
of
coal
ranks
may
diminish
and
that
EPA
should
review
its
limits
by
coal
rank
periodically
and
make
them
more
stringent
if
appropriate
due
to
improving
Hg
control
technology.

Response:

EPA
stands
by
its
decision
with
regard
to
subcategorization.
Further,
EPA
believes
that
the
research
noted
by
commenter
­
3208
supports
more
limited,
rather
than
broader,
subcategorization
scenarios
(
i.
e.,
fewer,
perhaps
none,
rather
than
more
subcategories)
when
the
rule
is
reviewed
in
the
future
as
suggested
by
commenter
­
4139.

Comment:

According
to
some
commenters
(
OAR­
2002­
0056­
2364,
­
2430),
EPA's
straw
proposals
of
August
2001
and
December
2001
contained
subcategorization
possibilities
calling
for
90
percent
control,
have
defensible
MACT
floors,
are
cost
effective,
have
timely
implementation,
and
are
preferable
to
EPA's
proposals.

Response:

The
"
straw
proposals"
noted
by
the
commenters
were
extremely
preliminary
in
nature
and
were
never
the
basis
for
any
proposal
options.
The
data
upon
which
the
straw
proposals
were
based
were
subsequently
determined
to
be
in
error
with
regard
to
levels
of
Hg
control
achieved
by
existing
controls.
Further
analysis
of
the
available
data
also
indicated
that
the
subcategories
used
at
proposal
were
appropriate.

2.3
GENERAL
COMMENTS
Comment:

One
commenter
(
OAR­
2002­
0056­
2485),
also
noted
that
many
sources
of
natural
gas
contain
high
levels
of
Hg
and
should
be
included
in
this
subpart.

Response:

EPA
received
no
data
or
information
during
the
public
comment
period
to
indicate
that
2­
39
its
determination
that
regulation
of
natural
gas­
fired
Utility
Units
was
neither
necessary
nor
appropriate
was
in
error.
Therefore,
EPA
stands
by
that
decision.
