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ESD\
Combustion
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Boilers\
OMB
2004\
Preamble­
final(
Feb04).
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Combustion
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Promulgation
2004\
Preamble­
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02­
18­
04).
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6560­
50­
P
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
63
[
OAR­
2002­
0058;
FRL­
]

RIN
2060­
AG69
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
AGENCY:
Environmental
Protection
Agency
(
EPA).

ACTION:
Final
rule.

SUMMARY:
The
EPA
is
promulgating
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
for
industrial,
commercial,
and
institutional
boilers
and
process
heaters.
The
EPA
has
identified
industrial,

commercial,
and
institutional
boilers
and
process
heaters
as
major
sources
of
hazardous
air
pollutants
(
HAP)
emissions.

The
final
rule
will
implement
section
112(
d)
of
the
Clean
Air
Act
(
CAA)
by
requiring
all
major
sources
to
meet
HAP
emissions
standards
reflecting
the
application
of
the
maximum
achievable
control
technology
(
MACT).
The
final
rule
is
expected
to
reduce
HAP
emissions
by
58,000
tons
per
year
(
tpy).

The
HAP
emitted
by
facilities
in
the
boiler
and
process
heater
source
category
include
arsenic,
cadmium,
chromium,

hydrogen
chloride
(
HCl),
hydrogen
fluoride,
lead,
manganese,
3
mercury,
nickel,
and
various
organic
HAP.
Exposure
to
these
substances
has
been
demonstrated
to
cause
adverse
health
effects
such
as
irritation
to
the
lung,
skin,
and
mucus
membranes,
effects
on
the
central
nervous
system,
kidney
damage,
and
cancer.
These
adverse
health
effects
associated
with
the
exposure
to
these
specific
HAP
are
further
described
in
this
preamble.
In
general,
these
findings
only
have
been
shown
with
concentrations
higher
than
those
typically
in
the
ambient
air.

The
EPA
is
also
adding
numerous
compliance
provisions
including
health­
based
compliance
alternatives
for
the
hydrogen
chloride
and
total
selected
metals
emission
limits.

This
action
is
being
taken
to
respond
to
comments
submitted
during
the
public
comment
period
and
is
based
on
EPA's
evaluation
of
the
available
information
concerning
the
potential
hazards
from
exposure
to
HCl
and
manganese
emitted
by
boilers
and
process
heaters.

EFFECTIVE
DATE:
[
INSERT
THE
DATE
60
DAYS
AFTER
DATE
OF
PUBLICATION
OF
THE
FINAL
RULE
IN
THE
FEDERAL
REGISTER]

ADDRESSES:
The
official
public
docket
is
the
collection
of
materials
that
is
available
for
public
viewing
at
the
Office
of
Air
and
Radiation
Docket
and
Information
Center
(
Air
Docket)
in
the
EPA
Docket
Center,
Room
B­
102,
1301
Constitution
Avenue,
NW,
Washington,
DC.
4
FOR
FURTHER
INFORMATION
CONTACT:
For
information
concerning
applicability
and
rule
determinations,
contact
your
State
or
local
representative
or
appropriate
EPA
Regional
Office
representative.
For
information
concerning
rule
development,
contact
Jim
Eddinger,
Combustion
Group,

Emission
Standards
Division
(
C439­
01),
U.
S.
EPA,
Research
Triangle
Park,
North
Carolina
27711,
telephone
number
(
919)

541­
5426,
fax
number
(
919)
541­
5450,
electronic
mail
address
eddinger.
jim@
epa.
gov.

SUPPLEMENTARY
INFORMATION:
Regulated
Entities.
Categories
and
entities
potentially
regulated
by
this
action
include:

Category
NAICS
Code
SIC
Code
Examples
of
potentially
regulated
entities
Any
industry
using
a
boiler
or
process
heater
as
defined
in
the
final
rule
211
13
Extractors
of
crude
petroleum
and
natural
gas
321
24
Manufacturers
of
lumber
and
wood
products
322
26
Pulp
and
paper
mills
325
28
Chemical
manufacturers
324
29
Petroleum
refineries,
and
manufacturers
of
coal
products
316,
326,
339
30
Manufacturers
of
rubber
and
miscellaneous
plastic
products
331
33
Steel
works,
blast
furnaces
5
332
34
Electroplating,
plating,
polishing,
anodizing,
and
coloring
336
37
Manufacturers
of
motor
vehicle
parts
and
accessories
221
49
Electric,
gas,
and
sanitary
services
622
80
Health
services
611
82
Educational
services
This
table
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
for
readers
regarding
entities
likely
to
be
regulated
by
this
action.
This
table
lists
examples
of
the
types
of
entities
EPA
is
now
aware
could
potentially
be
regulated
by
this
action.
Other
types
of
entities
not
listed
could
also
be
affected.
To
determine
whether
your
facility,
company,
business,
organization,
etc.,
is
regulated
by
this
action,
you
should
examine
the
applicability
criteria
in
§
63.7485
of
the
final
rule.
If
you
have
any
questions
regarding
the
applicability
of
this
action
to
a
particular
entity,
consult
the
person
listed
in
the
preceding
FOR
FURTHER
INFORMATION
CONTACT
section.

Docket.
The
EPA
has
established
an
official
public
docket
for
this
action
under
Docket
ID
No.
OAR­
2003­
0058
and
Docket
ID
No.
A­
96­
47.
The
official
public
docket
consists
of
the
documents
specifically
referenced
in
this
action,
any
public
comments
received,
and
other
information
related
to
this
action.
All
items
may
not
be
listed
under
both
docket
6
numbers,
so
interested
parties
should
inspect
both
docket
numbers
to
ensure
that
they
have
received
all
materials
relevant
to
the
final
rule.
Although
a
part
of
the
official
docket,
the
public
docket
does
not
include
Confidential
Business
Information
(
CBI)
or
other
information
whose
disclosure
is
restricted
by
statute.
The
official
public
docket
is
the
collection
of
materials
that
is
available
for
public
viewing
at
the
Office
of
Air
and
Radiation
Docket
and
Information
Center
(
Air
Docket)
in
the
EPA
Docket
Center,

Room
B102,
1301
Constitution
Ave.,
NW,
Washington,
DC.
The
EPA
Docket
Center
Public
Reading
Room
is
open
from
8:
30
a.
m.

to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Reading
Room
is
(
202)
566­
1744,
and
the
telephone
number
for
the
Air
and
Radiation
Docket
is
(
202)
566­
1742.
A
reasonable
fee
may
be
charged
for
copying
docket
materials.

Electronic
Access.
You
may
access
this
Federal
Register
document
electronically
through
the
EPA
Internet
under
the
"
Federal
Register"
listings
at
http://
www.
epa.
gov/
fedrgstr/.

An
electronic
version
of
the
public
docket
is
available
through
EPA's
electronic
public
docket
and
comment
system,

EPA
Dockets.
You
may
use
EPA
Dockets
at
http://
www.
epa.
gov/
edocket/
to
view
public
comments,
access
the
index
listing
of
the
contents
of
the
official
public
docket,
and
to
access
those
documents
in
the
public
docket
7
that
are
available
electronically.
Once
in
the
system,

select
"
search,"
then
key
in
the
appropriate
docket
identification
number.

Worldwide
Web
(
WWW).
In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
the
final
rule
is
also
available
on
the
WWW
through
the
Technology
Transfer
Network
(
TTN).
Following
signature,
a
copy
of
the
final
rule
will
be
posted
on
the
TTN
policy
and
guidance
page
for
newly
proposed
or
promulgated
rules
at
the
following
address:

http://
www.
epa.
gov/
ttn/
oarpg.
The
TTN
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.
If
more
information
regarding
the
TTN
is
needed,

call
the
TTN
HELP
line
at
(
919)
541­
5384.

Judicial
Review.
Under
section
307(
b)(
1)
of
the
CAA,

judicial
review
of
the
NESHAP
is
available
by
filing
a
petition
for
review
in
the
U.
S.
Court
of
Appeals
for
the
District
of
Columbia
Circuit
by
[
INSERT
THE
DATE
60
DAYS
AFTER
PUBLICATION
OF
THE
FINAL
RULE
IN
THE
FEDERAL
REGISTER].
Only
those
objections
to
the
final
rule
that
were
raised
with
reasonable
specificity
during
the
period
for
public
comment
may
be
raised
during
judicial
review.

Under
section
307(
b)(
2)
of
the
CAA,
the
requirements
that
are
the
subject
of
the
final
rule
may
not
be
challenged
later
in
civil
or
criminal
proceedings
brought
by
EPA
to
enforce
these
requirements.
8
Background
Information
Document.
The
EPA
proposed
the
NESHAP
for
industrial,
commercial,
and
institutional
boilers
and
process
heaters
on
January
13,
2003
(
68
FR
1660)
and
received
218
comment
letters
on
the
proposal.
A
memorandum
"
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters,
Summary
of
Public
Comments
and
Responses,"

containing
EPA's
responses
to
each
public
comment
is
available
in
Docket
No.
OAR
 
2002­
0058.

Outline.
The
information
presented
in
this
preamble
is
organized
as
follows:

I.
Background
Information
A.
What
is
the
statutory
authority
for
the
final
rule?
B.
What
criteria
are
used
in
the
development
of
NESHAP?
C.
How
was
the
final
rule
developed?
D.
What
is
the
relationship
between
the
final
rule
and
other
combustion
rules?
E.
What
are
the
health
effects
of
pollutants
emitted
from
industrial,
commercial,
and
institutional
boilers
and
process
heaters?
II.
Summary
of
the
Final
Rule
A.
What
source
categories
and
subcategories
are
affected
by
the
final
rule?
B.
What
is
the
affected
source?
C.
What
pollutants
are
emitted
and
controlled?
D.
Does
the
final
rule
apply
to
me?
E.
What
are
the
emission
limitations
and
work
practice
standards?
F.
What
are
the
testing
and
initial
compliance
requirements?
G.
What
are
the
continuous
compliance
requirements?
H.
What
are
the
notification,
recordkeeping
and
reporting
requirements?
I.
What
are
the
health­
based
compliance
alternatives
and
how
do
I
demonstrate
eligibility?
III.
What
are
the
significant
changes
since
proposal?
B.
Definition
of
Affected
Source
C.
Sources
Not
Covered
by
the
NESHAP
9
D.
Emission
Limits
E.
Definitions
Added
and
Revised
F.
Requirements
for
Sources
in
Subcategories
Without
Emission
Limit
or
Work
Practice
Requirements
G.
Carbon
Monoxide
Work
Practice
Emission
Level
and
Requirements
H.
Fuel
Analysis
Option
I.
Emissions
Averaging
J.
Opacity
Limit
K.
Operating
Limit
Determination
L.
Revision
of
Compliance
Dates
IV.
What
are
the
responses
to
significant
comments?
A.
Applicability
B.
Format
C.
Compliance
Schedule
D.
Subcategorization
E.
MACT
Floor
F.
Beyond
the
MACT
Floor
G.
Work
Practice
Requirements
H.
Compliance
I.
Emissions
Averaging
J.
Risk­
based
Approach
V.
Impacts
of
the
Final
Rule
A.
What
are
the
air
quality
impacts?
B.
What
are
the
water
and
solid
waste
impacts?
C.
What
are
the
energy
impacts?
D.
What
are
the
control
costs?
E.
What
are
the
economic
impacts?
F.
What
are
the
social
costs
and
benefits
of
the
final
rule?
G.
How
will
the
health­
based
compliance
alternatives
reduce
impacts?
VI.
Statutory
and
Executive
Order
Reviews
A.
Executive
Order
12866:
Regulatory
Planning
and
Review
B.
Paperwork
Reduction
Act
C.
Regulatory
Flexibility
Act
D.
Unfunded
Mandates
Reform
Act
of
1995
E.
Executive
Order
13132:
Federalism
F.
Executive
Order
13175:
Consultation
and
Coordination
with
Indian
Tribal
Governments
G.
Executive
Order
13045:
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
H.
Executive
Order
13211:
Actions
Concerning
Regulations
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
I.
National
Technology
Transfer
and
Advancement
Act
J.
Congressional
Review
Act
I.
Background
Information
10
A.
What
is
the
statutory
authority
for
the
final
rule?

Section
112
of
the
CAA
requires
us
to
list
categories
and
subcategories
of
major
sources
and
area
sources
of
HAP
and
to
establish
NESHAP
for
the
listed
source
categories
and
subcategories.
Industrial
boilers,
commercial
and
institutional
boilers,
and
process
heaters
were
listed
on
July
16,
1992
(
57
FR
31576).
Major
sources
of
HAP
are
those
that
have
the
potential
to
emit
greater
than
10
tpy
of
any
one
HAP
or
25
tpy
of
any
combination
of
HAP.

B.
What
criteria
are
used
in
the
development
of
NESHAP?

Section
112(
c)(
2)
of
the
CAA
requires
that
we
establish
NESHAP
for
control
of
HAP
from
both
existing
and
new
major
sources,
based
upon
the
criteria
set
out
in
CAA
section
112(
d).
The
CAA
requires
the
NESHAP
to
reflect
the
maximum
degree
of
reduction
in
emissions
of
HAP
that
is
achievable,

taking
into
consideration
the
cost
of
achieving
the
emission
reduction,
any
non­
air
quality
health
and
environmental
impacts,
and
energy
requirements.
This
level
of
control
is
commonly
referred
to
as
the
MACT.

The
minimum
control
level
allowed
for
NESHAP
(
the
minimum
level
of
stringency
for
MACT)
is
the
"
MACT
floor,"

as
defined
under
section
112(
d)(
3)
of
the
CAA.
The
MACT
floor
for
existing
sources
is
the
emission
limitation
achieved
by
the
average
of
the
best­
performing
12
percent
of
existing
sources
for
categories
and
subcategories
with
30
or
11
more
sources,
or
the
average
of
the
best­
performing
five
sources
for
categories
or
subcategories
with
fewer
than
30
sources.
For
new
sources,
the
MACT
floor
cannot
be
less
stringent
than
the
emission
control
achieved
in
practice
by
the
best­
controlled
similar
source.

C.
How
was
the
final
rule
developed?

We
proposed
standards
for
industrial,
commercial,
and
institutional
boilers
and
process
heaters
on
January
13,

2003
(
68
FR
1660).
Public
comments
were
solicited
at
the
time
of
proposal.
The
public
comment
period
lasted
from
January
13,
2003,
to
March
14,
2003.
Industry
representatives,
regulatory
agencies,
environmental
groups,

and
the
general
public
were
given
the
opportunity
to
comment
on
the
proposed
rule
and
to
provide
additional
information
during
the
public
comment
period.

We
received
a
total
of
218
public
comment
letters
on
the
proposed
rule.
Comments
were
submitted
by
industry
trade
associations,
owners/
operators
of
boilers
and
process
heaters,
State
regulatory
agencies
and
their
representatives,
and
environmental
groups.
Today's
final
rule
reflects
our
consideration
of
all
of
the
comments
and
additional
information
received.
Major
public
comments
on
the
proposed
rules,
along
with
our
responses
to
those
comments,
are
summarized
in
this
preamble.

D.
What
is
the
relationship
between
the
final
rule
and
12
1Please
note
that
boilers
that
burn
small
quantities
of
hazardous
waste
under
the
exemptions
provided
by
40
CFR
266.108
are
subject
to
today's
final
rule.
other
combustion
rules?

The
final
rule
regulates
source
categories
covering
industrial
boilers,
institutional
and
commercial
boilers,

and
process
heaters.
These
source
categories
potentially
include
combustion
units
that
are
already
regulated
by
other
MACT
standards.
Therefore,
we
are
excluding
from
the
final
rule
any
combustion
units
that
are
already
or
will
be
subject
to
regulation
under
another
MACT
standard
under
40
CFR
part
63.

Combustion
units
that
are
regulated
by
other
standards
and
are
therefore
excluded
from
the
final
rule
include:

municipal
waste
combustors
covered
by
the
new
source
performance
standards
(
NSPS)
in
40
CFR
part
60,
subparts
AAAA,
BBBB,
or
Cb);
hospital/
medical/
infectious
solid
waste
incineratorsincineration
units
covered
by
section
129
of
the
NSPS
in
40
CFR
part
60,
subparts
Ce
or
Ec;
CAA;
boilers
or
process
heaters
required
to
have
a
permit
under
section
3005
of
the
Solid
Waste
Disposal
Act
or
covered
by
the
hazardous
waste
combustor
NESHAP
in
40
CFR
part
63,
subpart
EEE1;

commercial
and
industrial
solid
waste
incinerators
(
CISWI)

covered
in
40
CFR
part
60,
subparts
CCCC
and
DDDD;
and
recovery
boilers
or
furnaces
covered
by
40
CFR
part
63,
13
subpart
MM.

Fossil
fuel­
fired
utility
boilers
are
exempt
from
the
final
rule.
Non­
fossil
fuel­
fired
utility
boilers
are
covered
byWith
regards
to
solid
waste
incineration
units,

EPA
solicited
on
February
17,
2004
(
69
FR
7390)
public
comments
on
the
definition
of
"
commercial
and
industrial
solid
waste
incineration
unit"
for
the
purpose
of
determining
which
combustion
sources
to
regulate
under
section
129
and
which
to
regulate
under
section
112
(
e.
g.,

boilers
and
process
heaters).

Electric
utility
steam
generating
units
are
not
subject
to
the
final
rule.
A
fossil
fuel­
firedn
electric
utility
boiler
steam
generating
units
is
a
fossil
fuel­
fired
combustion
unit
of
more
than
25
megawatts
that
serves
a
generator
that
produces
electricity
for
sale.
A
fossil
fuel­
fired
unit
that
cogenerates
steam
and
electricity
and
supplies
more
than
one­
third
of
its
potential
electric
output
capacity
and
more
than
25
megawatts
electrical
output
to
any
utility
power
distribution
system
for
sale
is
considered
an
electric
utility
steam
generating
unit.

Nonfossil
fuel­
fired
utility
boilers
and
electric
utility
steam
generating
units
less
than
25
megawatts
are
covered
by
the
final
rule.

In
1986,
EPA
codified
the
NSPS
for
industrial
boilers
(
40
CFR
part
60,
subparts
Db
and
Dc)
and
revised
portions
of
14
them
in
1999.
The
NSPS
regulates
emissions
of
particulate
matter
(
PM),
sulfur
dioxide,
and
nitrogen
oxides
from
boilers
constructed
after
June
19,
1984.
Sources
subject
to
the
NSPS
are
stillalso
subject
to
the
final
rule
because
the
final
rule
regulates
sources
of
hazardous
air
pollutants
while
the
NSPS
does
not.
However,
in
developing
the
final
rule
for
industrial,
commercial,
and
institutional
boilers
and
process
heaters,
EPA
minimized
the
monitoring
requirements,
testing
requirements,
and
recordkeeping
requirements
to
avoid
duplicating
requirements.

Because
of
the
broad
applicability
of
the
final
rule
due
to
the
definition
of
a
process
heater,
certain
process
heaters
could
appear
to
fit
the
applicability
of
another
existing
MACT
rule.
We
have,
therefore,
included
in
the
list
of
combustion
units
exempt
fromnot
subject
to
the
final
rule
refining
kettles
subject
to
the
secondary
lead
MACT
rule
(
40
CFR
part
63,
subpart
X);
ethylene
cracking
furnaces
covered
by
40
CFR
part
63,
subpart
YY;
and
blast
furnace
stoves
described
in
the
EPA
document
entitled
"
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Integrated
Iron
and
Steel
Plants
­
Background
Information
for
Proposed
Standards"
(
EPA­
453/
R­
01­
005).

E.
What
are
the
health
effects
of
pollutants
emitted
from
industrial,
commercial,
and
institutional
boilers
and
process
heaters?
15
The
final
rule
protects
air
quality
and
promotes
the
public
health
by
reducing
emissions
of
some
of
the
HAP
listed
in
section
112(
b)(
1)
of
the
CAA.
As
noted
above,

emissions
data
collected
during
development
of
the
proposed
rule
show
that
HCl
emissions
represent
the
predominant
HAP
emitted
by
industrial
boilers.
Industrial
boilers
emit
lesser
amounts
of
hydrogen
fluoride,
metals
(
arsenic,

cadmium,
chromium,
mercury,
manganese,
nickel,
and
lead),

and
organic
HAP
emissions.
Although
numerous
organic
HAP
may
be
emitted
from
industrial
boilers
and
process
heaters,

only
a
few
account
for
essentially
all
the
mass
of
organic
HAP
emissions.
These
organic
HAP
are:
formaldehyde,

benzene,
and
acetaldehyde.

Exposure
to
these
HAP
is
associated
with
a
variety
of
adverse
health
effects.
These
adverse
health
effects
include
chronic
health
disorders
(
e.
g.,
irritation
of
the
lung,
skin,
and
mucus
membranes,
effects
on
the
central
nervous
system,
and
damage
to
the
kidneys),
and
acute
health
disorders
(
e.
g.,
lung
irritation
and
congestion,
alimentary
effects
such
as
nausea
and
vomiting,
and
effects
on
the
kidney
and
central
nervous
system).
We
have
classified
three
of
the
HAP
as
human
carcinogens
and
five
as
probable
human
carcinogens.
We
do
not
know
the
extent
to
which
the
adverse
health
effects
described
above
occur
in
the
populations
surrounding
these
facilities.
However,
to
the
16
extent
the
adverse
effects
do
occur,
the
final
rule
will
reduce
emissions
and
subsequent
exposures.

Acetaldehyde
Acetaldehyde
is
ubiquitous
in
the
environment
and
may
be
formed
in
the
body
from
the
breakdown
of
ethanol
(
ethyl
alcohol).
Acute
(
short­
term)
exposure
to
acetaldehyde
results
in
effects
including
irritation
of
the
eyes,
skin,

and
respiratory
tract.
In
humans,
symptoms
of
chronic
(
long­
term)
exposure
to
acetaldehyde
resemble
those
of
alcoholism.
Long­
term
inhalation
exposure
studies
in
animals
reported
damage
to
the
nasal
epithelium
and
mucous
membranes,
growth
retardation,
and
increased
kidney
weight.

The
EPA
has
classified
acetaldehyde
as
a
probable
human
carcinogen
(
Group
B2)
based
on
animal
studies
that
have
shown
nasal
tumors
in
rats
and
laryngeal
tumors
in
hamsters.

Arsenic
Acute
(
short­
term)
high­
level
inhalation
exposure
to
arsenic
dust
or
fumes
has
resulted
in
gastrointestinal
effects
(
nausea,
diarrhea,
abdominal
pain),
and
central
and
peripheral
nervous
system
disorders.
Chronic
(
long­
term)

inhalation
exposure
to
inorganic
arsenic
in
humans
is
associated
with
irritation
of
the
skin
and
mucous
membranes.

Human
data
suggest
a
relationship
between
inhalation
exposure
of
women
working
at
or
living
near
metal
smelters
and
an
increased
risk
of
reproductive
effects,
such
as
17
spontaneous
abortions.
Inorganic
arsenic
exposure
in
humans
by
the
inhalation
route
has
been
shown
to
be
strongly
associated
with
lung
cancer,
while
ingestion
of
inorganic
arsenic
in
humans
has
been
linked
to
a
form
of
skin
cancer
and
also
to
bladder,
liver,
and
lung
cancer.
The
EPA
has
classified
inorganic
arsenic
as
a
Group
A,
human
carcinogen.

Benzene
Acute
(
short­
term)
inhalation
exposure
of
humans
to
benzene
may
cause
drowsiness,
dizziness,
headaches,
as
well
as
eye,
skin,
and
respiratory
tract
irritation,
and,
at
high
levels,
unconsciousness.
Chronic
(
long­
term)
inhalation
exposure
has
caused
various
disorders
in
the
blood,

including
reduced
numbers
of
red
blood
cells
and
aplastic
anemia,
in
occupational
settings.
Reproductive
effects
have
been
reported
for
women
exposed
by
inhalation
to
high
levels
and
adverse
effects
on
the
developing
fetus
have
been
observed
in
animal
tests.
Increased
incidence
of
leukemia
(
cancer
of
the
tissues
that
form
white
blood
cells)
has
been
observed
in
humans
occupationally
exposed
to
benzene.
The
EPA
has
classified
benzene
as
a
Group
A,
known
human
carcinogen.

Beryllium
Acute
(
short­
term)
inhalation
exposure
to
high
levels
of
beryllium
has
been
observed
to
cause
inflammation
of
the
lungs
or
acute
pneumonitis
(
reddening
and
swelling
of
the
18
lungs)
in
humans;
after
exposure
ends,
these
symptoms
may
be
reversible.
Chronic
(
long­
term)
inhalation
exposure
of
humans
to
beryllium
has
been
reported
to
cause
chronic
beryllium
disease
(
berylliosis),
in
which
granulomatous
(
noncancerous)
lesions
develop
in
the
lung.
Inhalation
exposure
to
beryllium
has
been
demonstrated
to
cause
lung
cancer
in
rats
and
monkeys.
Human
studies
are
limited,
but
suggest
a
causal
relationship
between
beryllium
exposure
and
an
increased
risk
of
lung
cancer.
Oral
exposure
to
beryllium
was
found
to
cause
stomach
lesions
in
dogs,
but
effects
on
humans
are
not
well­
described.
We
have
classified
beryllium
as
a
Group
B1,
probable
human
carcinogen,
when
inhaled;
data
are
inadequate
to
determine
whether
beryllium
is
carcinogenic
when
ingested.

Cadmium
The
acute
(
short­
term)
effects
of
cadmium
inhalation
in
humans
consist
mainly
of
effects
on
the
lung,
such
as
pulmonary
irritation.
Chronic
(
long­
term)
inhalation
or
oral
exposure
to
cadmium
leads
to
a
build­
up
of
cadmium
in
the
kidneys
that
can
cause
kidney
disease.
Cadmium
has
been
shown
to
be
a
developmental
toxicant
at
high
doses
in
animals,
resulting
in
fetal
malformations
and
other
effects,

but
no
conclusive
evidence
exists
in
humans.
An
association
between
cadmium
exposure
and
an
increased
risk
of
lung
cancer
has
been
reported
from
human
studies,
but
these
19
studies
are
inconclusive
due
to
confounding
factors.
Animal
studies
have
demonstrated
an
increase
in
lung
cancer
from
long­
term
inhalation
exposure
to
cadmium.
The
EPA
has
classified
cadmium
as
a
Group
B1,
probable
carcinogen.

Chromium
Chromium
may
be
emitted
by
industrial
boilers
in
two
forms,
trivalent
chromium
(
chromium
III)
or
hexavalent
chromium
(
chromium
VI).
The
respiratory
tract
is
the
major
target
organ
for
chromium
VI
toxicity,
for
acute
(

shortterm
and
chronic
(
long­
term)
inhalation
exposures.

Shortness
of
breath,
coughing,
and
wheezing
have
been
reported
from
acute
exposure
to
chromium
VI,
while
perforations
and
ulcerations
of
the
septum,
bronchitis,

decreased
pulmonary
function,
pneumonia,
and
other
respiratory
effects
have
been
noted
from
chronic
high
dose
exposure
in
occupational
settings.
Limited
human
studies
suggest
that
chromium
VI
inhalation
exposure
may
be
associated
with
complications
during
pregnancy
and
childbirth,
while
animal
studies
have
not
reported
reproductive
effects
from
inhalation
exposure
to
chromium
VI.
Human
and
animal
studies
have
clearly
established
that
inhaled
chromium
VI
is
a
carcinogen,
resulting
in
an
increased
risk
of
lung
cancer.
The
EPA
has
classified
chromium
VI
as
a
Group
A,
human
carcinogen.

Chromium
III
is
less
toxic
than
chromium
VI.
The
20
respiratory
tract
is
also
the
major
target
organ
for
chromium
III
toxicity,
similar
to
chromium
VI.
Chromium
III
is
an
essential
element
in
humans,
with
a
daily
intake
of
50
to
200
micrograms
per
day
recommended
for
an
adult.
The
body
can
detoxify
some
amount
of
chromium
VI
to
chromium
III.
The
EPA
has
not
classified
chromium
III
with
respect
to
carcinogenicity.

Formaldehyde
Both
acute
(
short­
term)
and
chronic
(
long­
term)

exposure
to
formaldehyde
irritates
the
eyes,
nose,
and
throat,
and
may
cause
coughing,
chest
pains,
and
bronchitis.

Reproductive
effects,
such
as
menstrual
disorders
and
pregnancy
problems,
have
been
reported
in
female
workers
exposed
to
formaldehyde.
Limited
human
studies
have
reported
an
association
between
formaldehyde
exposure
and
lung
and
nasopharyngeal
cancer.
Animal
inhalation
studies
have
reported
an
increased
incidence
of
nasal
squamous
cell
cancer.
The
EPA
considers
formaldehyde
a
probable
human
carcinogen
(
Group
B2).

Hydrogen
chloride
Hydrogen
chloride,
also
called
hydrochloric
acid,
is
corrosive
to
the
eyes,
skin,
and
mucous
membranes
at
high
concentration.
Acute
(
short­
term)
inhalation
exposure
may
cause
eye,
nose,
and
respiratory
tract
irritation
and
inflammation
and
pulmonary
edema
in
humans.
Chronic
(
long­
21
term)
occupational
exposure
to
hydrochloric
acid
has
been
reported
to
cause
gastritis,
bronchitis,
and
dermatitis
in
workers.
Prolonged
exposure
to
low
concentrations
may
also
cause
dental
discoloration
and
erosion.
No
information
is
available
on
the
reproductive
or
developmental
effects
of
hydrochloric
acid
in
humans.
In
rats
exposed
to
hydrochloric
acid
by
inhalation,
altered
estrus
cycles
have
been
reported
in
females
and
increased
fetal
mortality
and
decreased
fetal
weight
have
been
reported
in
offspring.
The
EPA
has
not
classified
hydrochloric
acid
for
carcinogenicity.

Hydrogen
fluoride
Acute
(
short­
term)
inhalation
exposure
to
gaseous
hydrogen
fluoride
can
cause
severe
respiratory
damage
in
humans,
including
severe
irritation
and
pulmonary
edema.

Chronic
(
long­
term)
exposure
to
fluoride
at
low
levels
has
a
beneficial
effect
of
dental
cavity
prevention
and
may
also
be
useful
for
the
treatment
of
osteoporosis.
Exposure
to
higher
levels
of
fluoride
may
cause
dental
fluorosis.
One
study
reported
menstrual
irregularities
in
women
occupationally
exposed
to
fluoride.
The
EPA
has
not
classified
hydrogen
fluoride
for
carcinogenicity.

Lead
Lead
is
a
very
toxic
element,
causing
a
variety
of
effects
at
low
dose
levels.
Brain
damage,
kidney
damage,
22
and
gastrointestinal
distress
may
occur
from
acute
(

shortterm
exposure
to
high
levels
of
lead
in
humans.
Chronic
(
long­
term)
exposure
to
lead
in
humans
results
in
effects
on
the
blood,
central
nervous
system
(
CNS),
blood
pressure,
and
kidneys.
Children
are
particularly
sensitive
to
the
chronic
effects
of
lead,
with
slowed
cognitive
development,
reduced
growth
and
other
effects
reported.
Reproductive
effects,

such
as
decreased
sperm
count
in
men
and
spontaneous
abortions
in
women,
have
been
associated
with
lead
exposure.

The
developing
fetus
is
at
particular
risk
from
maternal
lead
exposure,
with
low
birth
weight
and
slowed
postnatal
neurobehavioral
development
noted.
Human
studies
are
inconclusive
regarding
lead
exposure
and
cancer,
while
animal
studies
have
reported
an
increase
in
kidney
cancer
from
lead
exposure
by
the
oral
route.
The
EPA
has
classified
lead
as
a
Group
B2,
probable
human
carcinogen.

Manganese
Health
effects
in
humans
have
been
associated
with
both
deficiencies
and
excess
intakes
of
manganese.
Chronic
(
long­
term)
exposure
to
low
levels
of
manganese
in
the
diet
is
considered
to
be
nutritionally
essential
in
humans,
with
a
recommended
daily
allowance
of
2
to
5
milligrams
per
day
(
mg/
d).
Chronic
exposure
to
high
levels
of
manganese
by
inhalation
in
humans
results
primarily
in
CNS
effects.

Visual
reaction
time,
hand
steadiness,
and
eye­
hand
23
coordination
were
affected
in
chronically­
exposed
workers.

Manganism,
characterized
by
feelings
of
weakness
and
lethargy,
tremors,
a
mask­
like
face,
and
psychological
disturbances,
may
result
from
chronic
exposure
to
higher
levels.
Impotence
and
loss
of
libido
have
been
noted
in
male
workers
afflicted
with
manganism
attributed
to
inhalation
exposures.
The
EPA
has
classified
manganese
in
Group
D,
not
classifiable
as
to
carcinogenicity
in
humans.

Mercury
Mercury
exists
in
three
forms:
elemental
mercury,

inorganic
mercury
compounds
(
primarily
mercuric
chloride),

and
organic
mercury
compounds
(
primarily
methyl
mercury).

Each
form
exhibits
different
health
effects.
Various
major
sources
may
release
elemental
or
inorganic
mercury;

environmental
methyl
mercury
is
typically
formed
by
biological
processes
after
mercury
has
precipitated
from
the
air.

Acute
(
short­
term)
exposure
to
high
levels
of
elemental
mercury
in
humans
results
in
CNS
effects
such
as
tremors,

mood
changes,
and
slowed
sensory
and
motor
nerve
function.

High
inhalation
exposures
can
also
cause
kidney
damage
and
effects
on
the
gastrointestinal
tract
and
respiratory
system.
Chronic
(
long­
term)
exposure
to
elemental
mercury
in
humans
also
affects
the
CNS,
with
effects
such
as
increased
excitability,
irritability,
excessive
shyness,
and
24
tremors.
The
EPA
has
not
classified
elemental
mercury
with
respect
to
cancer.

Acute
exposure
to
high
levels
of
inorganic
mercury
by
the
oral
route
may
result
in
effects
such
as
nausea,

vomiting,
and
severe
abdominal
pain.
The
major
effect
from
chronic
exposure
to
inorganic
mercury
is
kidney
damage.

Reproductive
and
developmental
animal
studies
have
reported
effects
such
as
alterations
in
testicular
tissue,
increased
embryo
resorption
rates,
and
abnormalities
of
development.

Mercuric
chloride
(
an
inorganic
mercury
compound)
exposure
has
been
shown
to
result
in
forestomach,
thyroid,
and
renal
tumors
in
experimental
animals.
The
EPA
has
classified
mercuric
chloride
as
a
Group
C,
possible
human
carcinogen.

Nickel
Nickel
is
an
essential
element
in
some
animal
species,

and
it
has
been
suggested
it
may
be
essential
for
human
nutrition.
Nickel
dermatitis,
consisting
of
itching
of
the
fingers,
hand
and
forearms,
is
the
most
common
effect
in
humans
from
chronic
(
long­
term)
skin
contact
with
nickel.

Respiratory
effects
have
also
been
reported
in
humans
from
inhalation
exposure
to
nickel.
No
information
is
available
regarding
the
reproductive
or
developmental
effects
of
nickel
in
humans,
but
animal
studies
have
reported
such
effects.
Nickel
forms
released
from
industrial
boilers
include
soluble
nickel
compounds,
nickel
subsulfide,
and
25
nickel
carbonyl.
Human
and
animal
studies
have
reported
an
increased
risk
of
lung
and
nasal
cancers
from
exposure
to
nickel
refinery
dusts
and
nickel
subsulfide.
Animal
studies
of
soluble
nickel
compounds
(
i.
e.,
nickel
carbonyl)
have
reported
lung
tumors.
The
EPA
has
classified
nickel
refinery
subsulfide
as
Group
A,
human
carcinogens
and
nickel
carbonyl
as
a
Group
B2,
probable
human
carcinogen.

Selenium
Selenium
is
a
naturally
occurring
substance
that
is
toxic
at
high
concentrations
but
is
also
a
nutritionally
essential
element.
Acute
(
short­
term)
exposure
to
elemental
selenium,
hydrogen
selenide,
and
selenium
dioxide
by
inhalation
results
primarily
in
respiratory
effects,
such
as
irritation
of
the
mucous
membranes,
pulmonary
edema,
severe
bronchitis,
and
bronchial
pneumonia.
Studies
of
humans
chronically
(
long­
term)
exposed
to
high
levels
of
selenium
in
food
and
water
have
reported
discoloration
of
the
skin,

pathological
deformation
and
loss
of
nails,
loss
of
hair,

excessive
tooth
decay
and
discoloration,
lack
of
mental
alertness,
and
listlessness.
The
consumption
of
high
levels
of
selenium
by
pigs,
sheep,
and
cattle
has
been
shown
to
interfere
with
normal
fetal
development
and
to
produce
birth
defects.
Results
of
human
and
animal
studies
suggest
that
supplementation
with
some
forms
of
selenium
may
result
in
a
reduced
incidence
of
several
tumor
types.
One
selenium
26
compound,
selenium
sulfide,
is
carcinogenic
in
animals
exposed
orally.
We
have
classified
elemental
selenium
as
a
Group
D,
not
classifiable
as
to
human
carcinogenicity,
and
selenium
sulfide
as
a
Group
B2,
probable
human
carcinogen.

II.
Summary
of
the
Final
Rule
A.
What
source
categories
and
subcategories
are
affected
by
the
final
rule?

The
final
rule
affects
industrial
boilers,

institutional
and
commercial
boilers,
and
process
heaters.

In
the
final
rule,
process
heater
means
an
enclosed
device
using
controlled
flame,
that
is
not
a
boiler,
and
the
unit's
primary
purpose
is
to
transfer
heat
indirectly
to
a
process
material
(
liquid,
gas,
or
solid)
or
to
heat
a
transfer
material
for
use
in
a
process
unit,
instead
of
generating
steam.
Process
heaters
are
devices
in
which
the
combustion
gases
do
not
directly
come
into
contact
with
process
materials.
Process
heaters
do
not
include
units
used
for
comfort
heat
or
space
heat,
food
preparation
for
on­
site
consumption,
or
autoclaves.
Boiler
means
an
enclosed
device
using
controlled
flame
combustion
and
having
the
primary
purpose
of
recovering
thermal
energy
in
the
form
of
steam
or
hot
water.
Waste
heat
boilers
are
excluded
from
the
definition
of
boiler.
A
waste
heat
boiler
(
or
heat
recovery
steam
generator)
means
a
device,
without
controlled
flame
27
combustion,
that
recovers
normally
unused
energy
and
converts
it
to
usable
heat.
Waste
heat
boilers
incorporating
duct
or
supplemental
burners
that
are
designed
to
supply
50
percent
or
more
of
the
total
rated
heat
input
capacity
of
the
waste
heat
boiler
are
considered
boilers
and
not
waste
heat
boilers.
Emissions
from
a
combustion
unit
with
a
waste
heat
boiler
are
regulated
by
the
applicable
standards
for
the
particular
type
of
combustion
unit.
For
example,
emissions
from
a
commercial
or
industrial
solid
waste
incineration
unit,
or
other
incineration
unit
with
a
waste
heat
boiler
are
regulated
by
standards
established
under
section
129
of
the
CAA.

Hot
water
heaters
also
are
not
regulated
under
the
final
rule.
A
hot
water
heater
is
a
closed
vessel,
with
a
capacity
of
no
more
than
120
U.
S.
gallons,
in
which
water
is
heated
by
combustion
of
gaseous
or
liquid
fuel
and
is
withdrawn
for
use
external
to
the
vessel
at
pressures
not
exceeding
160
pounds
per
square
inch
gauge
and
water
temperatures
not
exceeding
210
degree
Fahrenheit
(
99
degrees
Celsius).

Temporary
boilers
also
are
not
regulated
under
the
final
rule.
A
temporary
boiler
is
any
gaseous
or
liquid
fuel­
fired
boiler
that
is
designed,
and
is
capable
of,
being
carried
or
moved
from
one
location
to
another,
and
remains
at
any
one
location
for
less
than
180
consecutive
days.
28
Additionally,
any
new
temporary
boiler
that
replaces
an
existing
temporary
boiler
and
is
intended
to
perform
the
same
or
similar
function
will
be
included
in
the
determination
of
the
consecutive
180
day
time
period.

Boilers
or
process
heaters
that
are
used
specifically
for
research
and
development
are
not
regulated
under
the
final
rule.
However,
units
that
only
provide
steam
to
a
process
at
a
research
and
development
facility
are
still
subject
to
the
final
rule.

B.
What
is
the
affected
source?

In
the
final
rule,
the
affected
source
is
defined
as
follows:
(
1)
the
collection
of
all
existing
industrial,

commercial,
or
institutional
boilers
and
process
heaters
within
a
subcategory
located
at
a
major
source;
or
(
2)
each
new
or
reconstructed
industrial,
commercial
or
institutional
boiler
and
process
heater
located
at
a
major
source.

The
affected
source
does
not
include
combustion
units
that
are
subject
to
another
standard
under
40
CFR
part
63,

or
covered
by
other
standards
listed
in
this
preamble.

C.
What
pollutants
are
emitted
and
controlled?

Boilers
and
process
heaters
can
emit
a
wide
variety
of
HAP,
depending
on
the
material
burned.
Because
of
the
large
number
of
HAP
potentially
present
in
emissions
and
the
disparity
in
the
quantity
and
quality
of
the
emissions
information
available,
we
use
several
surrogates
to
control
29
multiple
HAP
in
the
final
rule.
This
will
reduce
the
burden
of
implementation
and
compliance
on
both
regulators
and
the
regulated
community.

We
grouped
the
HAP
into
four
common
categories:

mercury,
non­
mercury
metallic
HAP,
inorganic
HAP,
and
organic
HAP.
In
general,
the
pollutants
within
each
group
have
similar
characteristics
and
can
be
controlled
with
the
same
techniques.

Next,
we
identified
compounds
that
could
be
used
as
surrogates
for
all
the
compounds
in
each
pollutant
category.

For
the
non­
mercury
metallic
HAP,
we
chose
to
use
PM
as
a
surrogate.
Most,
if
not
all,
non­
mercury
metallic
HAP
emitted
from
combustion
sources
will
appear
on
the
flue
gas
fly­
ash.
Therefore,
the
same
control
techniques
that
would
be
used
to
control
the
fly­
ash
PM
will
control
non­
mercury
metallic
HAP.
Particulate
matter
was
also
chosen
instead
of
specific
metallic
HAP
because
all
fuels
do
not
emit
the
same
type
and
amount
of
metallic
HAP
but
most
generally
emit
PM.

The
use
of
PM
as
a
surrogate
will
also
eliminate
the
cost
of
performance
testing
to
comply
with
numerous
standards
for
individual
metals.

However,
we
are
sensitive
to
the
fact
that
some
sources
that
burn
fuels
containing
very
little
metals,
but
would
have
sufficient
PM
emissions
to
require
control
under
the
PM
provisions
of
the
proposed
rule.
In
such
cases,
PM
would
30
not
be
an
appropriate
surrogate
for
metallic
HAP.

Therefore,
in
the
final
rule,
an
alternative
metals
emission
limit
is
included.
A
source
may
choose
to
comply
with
the
alternative
metals
emissions
limit
instead
of
the
PM
limit
to
meet
the
final
rule.

For
inorganic
HAP,
we
chose
to
use
HCl
as
a
surrogate.

The
emissions
test
information
available
indicate
that
the
primary
inorganic
HAP
emitted
from
boilers
and
process
heaters
are
acid
gases,
with
HCl
present
in
the
largest
amounts.
Other
inorganic
compounds
emitted
are
found
in
much
smaller
quantities.
Also,
control
technologies
that
would
reduce
HCl
would
also
control
other
inorganic
compounds
that
are
acid
gases.
Thus,
the
best
controls
for
HCl
would
also
be
the
best
controls
for
other
inorganic
HAP
that
are
acid
gases.
Therefore,
HCl
is
a
good
surrogate
for
inorganic
HAP
because
controlling
HCl
will
result
in
a
corresponding
control
of
other
inorganic
HAP
emissions.

For
organic
HAP,
we
chose
to
use
carbon
monoxide
(
CO)

as
a
surrogate
to
represent
the
variety
of
organic
compounds,
including
dioxins,
emitted
from
the
various
fuels
burned
in
boilers
and
process
heaters.
Because
CO
is
a
good
indicator
of
incomplete
combustion,
there
is
a
direct
correlation
between
CO
emissions
and
the
formation
of
organic
HAP
emissions.
Monitoring
equipment
for
CO
is
readily
available,
which
is
not
the
case
for
organic
HAP.
31
Also,
it
is
significantly
easier
and
less
expensive
to
measure
and
monitor
CO
emissions
than
to
measure
and
monitor
emissions
of
each
individual
organic
HAP.
Therefore,
using
CO
as
a
surrogate
for
organic
HAP
is
a
reasonable
approach
because
minimizing
CO
emissions
will
result
in
minimizing
organic
HAP
emissions.

D.
Does
the
final
rule
apply
to
me?

The
final
rule
applies
to
you
if
you
own
or
operate
a
boiler
or
process
heater
located
at
a
major
source
meeting
the
requirements
in
this
preamble.

E.
What
are
the
emission
limitations
and
work
practice
standards?

You
must
meet
the
emission
limits
and
work
practice
standards
for
the
subcategories
in
Table
1
of
this
preamble
for
each
of
the
pollutants
listed.
Emission
limits
and
work
practice
standards
were
developed
for
new
and
existing
sources;
and
for
large,
small,
and
limited
use
solid,

liquid,
and
gas
fuel­
fired
units.
Large
units
are
those
watertube
boilers
and
process
heaters
with
heat
input
capacities
greater
than
10
million
British
thermal
units
per
hour
(
MMBtu/
hr).
Small
units
are
any
firetube
boilers
or
any
boiler
and
process
heater
with
heat
input
capacities
less
than
or
equal
to
10
MMBtu/
hr.
Limited
use
units
are
those
large
units
with
capacity
utilizations
less
than
or
equal
to
10
percent
as
required
in
a
federally
enforceable
32
permit.

If
your
new
or
existing
boiler
or
process
heater
is
permitted
to
burn
a
solid
fuel
(
either
as
a
primary
fuel
or
a
backup
fuel),
or
any
combination
of
solid
fuel
with
liquid
or
gaseous
fuel,
the
unit
is
in
one
of
the
solid
subcategories.
If
your
new
or
existing
boiler
or
process
heater
burns
a
liquid
fuel,
or
a
liquid
fuel
in
combination
with
a
gaseous
fuel,
the
unit
is
in
one
of
the
liquid
subcategories,
except
if
the
unit
burns
liquid
only
during
periods
of
gas
curtailment.
If
your
new
or
existing
boiler
or
process
heater
burns
a
gaseous
fuel
not
combined
with
any
liquid
or
solid
fuels,
or
burns
liquid
fuel
only
during
periods
of
gas
curtailment
or
gas
supply
emergencies,
the
unit
is
in
the
gaseous
subcategory.

Table
1.
EMISSION
LIMITS
AND
WORK
PRACTICE
STANDARDS
FOR
BOILERS
AND
PROCESS
HEATERS
(
pounds
per
million
British
thermal
units
(
lb/
MMBtu))

Sour
ce
Subcateg
ory
Particul
ate
Matter
(
PM)
or
Total
Select
ed
Metals
Hydrog
en
Chlori
de
(
HCl)
Mercu
ry
(
Hg)
Carbon
Monoxid
e
(
CO)(
pp
m
New
Boil
er
or
Proc
ess
Heat
er
Solid
Fuel,
Large
Unit
0.025
or
0.0003
0.02
0.000
003
400
(@
7%
oxy
gen)

Solid
Fuel,
Small
Unit
0.025
or
0.0003
0.02
0.000
003
­­
33
Solid
Fuel,
Limited
Use
0.025
or
0.0003
0.02
0.000
003
400
(@
7%
oxy
gen)

Liquid
Fuel,
Large
Unit
0.03
­­
0.0005
­­
400
(@
3%
oxy
gen)

Liquid
Fuel,
Small
Unit
0.03
­­
0.0009
­­
­­

Liquid
Fuel,
Limited
Use
0.03
­­
0.0009
­­
400
(@
3%
oxy
gen)

Gaseous
Fuel
Large
Unit
­­
­­
­­
­­
400
(@
3%
oxy
gen)

Gaseous
Fuel
Small
Unit
­­
­­
­­
­­
­­

Gaseous
Fuel
Limited
Use
­­
­­
­­
­­
400
(@
3%
oxy
gen)

Exis
ting
Boil
er
or
Proc
ess
Heat
er
Solid
Fuel,
Large
Unit
0.07
or
0.002
0.09
0.000
009
­­

Solid
Fuel,
Small
Unit
­­
­­
­­
­­
­­

Solid
Fuel,
Limited
Use
0.21
or
0.002
­­
­­
­­
34
Liquid
Fuel,
Large
Unit
­­
­­
­­
­­
­­

Liquid
Fuel,
Small
Unit
­­
­­
­­
­­
­­

Liquid
Fuel,
Limited
Use
­­
­­
­­
­­
­­

Gaseous
Fuel
­­
­­
­­
­­
­­

For
solid
fuel­
fired
boilers
or
process
heaters,

sources
may
choose
one
of
two
emission
limit
options:
(
1)

existing
and
new
affected
units
may
choose
to
limit
PM
emissions
to
the
level
listed
in
Table
1
of
this
preamble,

or
(
2)
existing
and
new
affected
units
may
choose
to
limit
total
selected
metals
emissions
to
the
level
listed
in
Table
1
of
this
preamble.
Sources
meeting
the
emission
limits
must
also
meet
operating
limits.

We
have
provided
several
compliance
alternatives
in
the
final
rule.
Sources
may
choose
to
demonstrate
compliance
based
on
the
fuel
pollutant
content.
Sources
are
also
allowed
to
demonstrate
compliance
for
existing
large
solid
fuel­
fired
units
using
emissions
averaging.

F.
What
are
the
testing
and
initial
compliance
requirements?

As
the
owner
or
operator
of
a
new
or
existing
boiler
or
35
process
heater,
you
must
conduct
performance
tests
(
i.
e.

stack
testing)
or
an
initial
fuel
analysis
to
demonstrate
compliance
with
any
applicable
emission
limits.
The
applicable
emission
limits
and,
therefore,
the
required
performance
tests
and
fuel
analysis
are
different
depending
on
the
subcategory
classification
of
the
unit.
Existing
units
in
the
small
solid
fuel
subcategory
and
existing
units
in
any
of
the
liquid
or
gaseous
fuel
subcategories
do
not
have
applicable
emission
limits
and,
therefore,
are
not
required
to
conduct
stack
tests
or
fuel
analyses.
Other
units
are
required
to
conduct
the
following
compliance
tests
or
fuel
analyses
where
applicable:

(
1)
Conduct
initial
and
annual
stack
tests
to
determine
compliance
with
the
PM
emission
limits
using
EPA
Method
5
or
Method
17
in
appendix
A
to
part
60
of
this
chapter.

(
2)
Affected
sources
in
the
solid
fuel
subcategories
may
choose
to
comply
with
an
alternative
total
selected
metals
emission
limit
instead
of
PM.
Sources
would
conduct
initial
and
annual
stack
tests
to
determine
compliance
with
the
total
selected
metals
emission
limit
using
EPA
Method
29
in
appendix
A
to
part
60
of
this
chapter.

(
3)
Conduct
initial
and
annual
stack
tests
to
determine
compliance
with
the
mercury
emission
limits
using
EPA
Method
29
in
appendix
A
to
part
60
of
this
chapter
or
36
the
ASTM
D6784­
02.

(
4)
Conduct
initial
and
annual
stack
tests
to
determine
compliance
with
the
HCl
emission
limits
using
EPA
Method
26
in
appendix
A
to
part
60
of
this
chapter
(
for
boilers
without
wet
scrubbers)
or
EPA
Method
26A
in
appendix
A
to
part
60
of
this
chapter
(
for
boilers
with
wet
scrubbers).

(
5)
For
new
sourcesboilers
and
process
heaters
in
any
of
the
limited
use
subcategories
and
new
boilers
and
process
heaters
in
any
of
the
large
subcategories
with
heat
input
capacities
greater
than
10
MMBtu/
hr
but
less
than
100
MMBtu/
hr,
conduct
initial
and
annual
stack
tests
to
determine
compliance
with
the
CO
work
practice
limit
using
EPA
Method
10,
10A,
or
10B
in
appendix
A
to
part
60
of
this
chapter.

(
6)
Use
EPA
Method
19
in
appendix
A
to
part
60
of
this
chapter
to
convert
measured
concentration
values
to
pound
per
million
British
thermal
units
(
Btu)
values.

(
7)
For
new
units
in
any
of
the
liquid
fuel
subcategories
that
do
not
burn
residual
oil,
instead
of
conducting
an
initial
and
annual
compliance
test
you
may
submit
a
signed
statement
in
the
Notification
of
Compliance
Status
report
that
indicates
that
you
only
burn
liquid
fossil
fuels
other
than
residual
oil.

(
1)
For
affected
sources
that
choose
to
meet
the
37
emission
limits
based
on
fuel
analysis,
conduct
the
fuel
analysis
using
method
ASTM
D5865­
01ael
or
ASTM
E711­
87
to
determine
heat
content;
ASTM
D3684­
01
(
for
coal),
SW­
846­

7471A
(
for
solid
samples)
or
SW­
846­
7470A
(
for
liquid
samples)
to
determine
mercury
levels;
SW­
846­
6010B
or
ASTM
D3683­
94
(
for
coal)
or
ASTM
E885­
88
(
for
biomass)
to
determine
total
selected
metals
concentration;
SW­
846­
9250
or
ASTM
E776­
87
(
for
biomass)
to
determine
chlorine
concentration;
and
ASTM
D3173
or
ASTM
E871
to
determine
moisture
content.

As
part
of
the
initial
compliance
demonstration,
you
must
monitor
specified
operating
parameters
during
the
initial
performance
tests
that
demonstrate
compliance
with
the
PM
(
or
metals),
mercury,
and
HCl
emission
limits.
You
must
calculate
the
average
parameter
values
measured
during
each
test
run
over
the
3­
run
performance
test.
The
minimum
or
maximum
of
the
three
average
values
(
depending
on
the
parameter
measured)
for
each
applicable
parameter
establishes
the
site­
specific
operating
limit.
The
applicable
operating
parameters
for
which
operating
limits
must
be
established
are
based
on
the
emissions
limits
applicable
to
your
unit
as
well
as
the
types
of
add­
on
controls
on
the
unit.
A
summary
of
the
operating
limits
that
must
be
established
for
the
various
types
of
controls
are
as
follows:
38
(
1)
For
boilers
and
process
heaters
without
wet
scrubbers
that
must
comply
with
the
mercury
emission
limit
and
either
a
PM
emission
limit
or
a
total
selected
metals
emission
limit,
you
must
meet
an
opacity
limit
of
20
percent
for
existing
sources
(
based
on
6­
minute
averages),
except
for
one
6­
minute
period
per
hour
of
not
more
than
27
percent,
or
10
percent
for
new
sources
(
based
on
1­
hour
block
averages).
Or,
if
the
unit
is
controlled
with
a
fabric
filter,
instead
of
meeting
an
opacity
operating
limit,
the
sourceyou
may
elect
to
operate
the
fabric
filter
such
that
an
installedusing
a
bag
leak
detection
system
such
that
corrective
actions
are
initiated
within
1
hour
of
a
bag
leak
detection
system
alarm
does
not
soundand
you
operate
and
maintain
the
fabric
filter
such
that
the
alarm
is
not
engaged
for
more
than
5
percent
of
the
total
operating
time
duringin
any
6­
month
reporting
period.
If
you
can
demonstrate
compliance
with
the
PM,
mercury,
or
metals
limits
but
cannot
demonstrate
compliance
with
the
opacity
operating
limit,
then
you
can
establish
a
site­
specific
maximum
opacity
operating
limit
using
data
from
a
continuous
opacity
monitoring
system
and
calculated
from
the
average
opacity
for
each
individual
test
run.

(
2)
For
boilers
and
process
heaters
without
wet
or
dry
scrubbers
that
must
comply
with
an
HCl
emission
limit,
you
must
determine
the
average
chloride
content
level
in
the
39
input
fuel(
s)
during
the
HCl
performance
test.
This
is
your
maximum
chloride
input
operating
limit.

(
3)
For
boilers
and
process
heaters
with
wet
scrubbers
that
must
comply
with
a
mercury,
PM
(
or
total
selected
metals)
and/
or
an
HCl
emission
limit,
you
must
measure
pressure
drop
and
liquid
flow
rate
of
the
scrubber
during
the
performance
test
and
calculate
the
average
value
for
each
test
run.
The
minimum
test
run
average
establishes
your
site­
specific
pressure
drop
and
liquid
flow
rate
operating
levels.
If
different
average
parameter
levels
are
measured
during
the
mercury,
PM
(
or
metals)
and
HCl
tests,

the
highest
of
the
minimum
test
run
average
values
establishes
your
site­
specific
operating
limit.
If
you
are
complying
with
an
HCl
emission
limit,
you
must
measure
pH
during
the
performance
test
for
HCl
and
determine
the
average
for
each
test
run
and
the
minimum
value
for
the
performance
test.
This
establishes
your
minimum
pH
operating
limit.

(
4)
For
boilers
and
process
heaters
with
dry
scrubbers
that
must
comply
with
an
HCl
emission
limit,
you
must
measure
the
sorbent
injection
rate
during
the
performance
test
for
mercury
and
HCl
and
calculate
the
average
for
each
test
run.
The
minimum
test
run
average
during
the
performance
test
establishes
your
site­
specific
minimum
sorbent
injection
rate
operating
limit.
40
(
5)
For
boilers
and
process
heaters
with
fabric
filters
in
combination
with
wet
scrubbers
that
must
comply
with
a
mercury
emission
limit,
PM
(
or
total
selected
metals)

emission
limit
and/
or
an
HCl
emission
limit,
you
must
measure
the
pH,
pressure
drop,
and
liquid
flowrate
of
the
wet
scrubber
during
the
performance
test
and
calculate
the
average
value
for
each
test
run.
The
minimum
test
run
average
establishes
your
site­
specific
pH,
pressure
drop,

and
liquid
flowrate
operating
limits
for
the
wet
scrubber.

Furthermore,
the
fabric
filter
must
be
operated
such
that
the
bag
leak
detection
system
alarm
does
not
sound
more
than
5
percent
of
the
operating
time
during
any
6­
month
period.

(
6)
For
boilers
and
process
heaters
with
electrostatic
precipitators
(
ESP)
in
combination
with
wet
scrubbers
that
must
comply
with
a
mercury,
PM
(
or
total
selected
metals)

and/
or
an
HCl
emission
limit,
you
must
measure
the
pH,

pressure
drop,
and
liquid
flow
rate
of
the
wet
scrubber
during
the
HCl
performance
test,
and
you
must
measure
the
voltage
and
secondary
current
of
the
ESP
collection
plates
or
total
power
input
during
the
mercury
and
PM
(
or
metals)

performance
test.
Calculate
the
average
value
of
these
parameters
for
each
test
run.
The
minimum
test
run
averages
establish
your
site­
specific
minimum
pH,
pressure
drop,
and
liquid
flowrate
operating
limit
for
the
wet
scrubber
and
the
minimum
voltage
and
current
operating
limits
for
the
ESP.
41
(
7)
For
boilers
and
process
heaters
that
choose
to
comply
with
the
alternative
total
selected
metals
emission
limit
instead
of
PM,
you
must
determine
the
total
selected
metals
content
of
the
inlet
fuels
that
were
burned
during
the
total
selected
metals
performance
test.
This
value
is
your
maximum
fuel
inlet
metals
content
operating
limit.

(
8)
For
boilers
and
process
heaters
that
burn
a
mixture
of
multiple
fuels,
you
must
determine
the
mercury
content
of
the
inlet
fuels
that
were
burned
during
the
mercury
performance
test.
This
value
is
your
maximum
fuel
inlet
mercury
operating
limit.
Units
burning
only
a
single
fuel
type
(
not
including
start­
up
fuels)
do
not
need
to
determine,
by
fuel
analysis,
the
fuel
inlet
operating
limit
when
conducting
performance
tests.

(
9)
For
new
boilers
and
process
heaters
in
any
of
the
large
or
limited
use
subcategories
and
with
heat
input
capacities
greater
or
equal
to
100
MMBtu/
hr,
you
must
monitor
CO
to
demonstrate
that
average
CO
emissions,
on
a
daily
average,
are
at
or
below
an
exhaust
concentration
of
400
parts
per
million
(
ppm)
by
volume
on
a
dry
basis
corrected
to
3
percent
oxygen
for
units
in
the
liquid
subcategories
and
corrected
to
7
percent
for
units
in
the
solid
subcategories.
For
new
boilers
and
process
heaters
in
any
of
the
large
or
limited
use
subcategories
andor
with
heat
input
capacities
less
than
100
MMBtu/
hr,
you
must
42
conduct
initial
test
of
CO
emissions
to
demonstrate
compliance
with
the
CO
work
practice
limit.

The
final
rule
also
provides
you
another
compliance
alternative.
You
may
demonstrate
compliance
by
emissions
averaging
for
existing
large
solid
fuel­
firedfuel
boilers
in
States
that
choose
to
allow
emissions
averaging
in
their
operating
permit
program.

G.
What
are
the
continuous
compliance
requirements?

To
demonstrate
continuous
compliance
with
the
emission
limitations,
you
must
monitor
and
comply
with
the
applicable
site­
specific
operating
limits
established
during
the
performance
tests
or
fuel
analysis.
Upon
detecting
an
excursion
or
exceedance,
you
must
restore
operation
of
the
unit
to
its
normal
or
usual
manner
of
operation
as
expeditiously
as
practicable
in
accordance
with
good
air
pollution
control
practices
for
minimizing
emissions.
The
response
shall
include
minimizing
the
period
of
any
startup,

shutdown
or
malfunction
and
taking
any
necessary
corrective
actions
to
restore
normal
operation
and
prevent
the
likely
recurrence
of
the
cause
of
an
excursion
or
exceedance.
Such
actions
may
include
initial
inspections
and
evaluation,

recording
that
operations
returned
to
normal
without
operator
action,
or
any
necessary
follow­
up
actions
to
return
operation
to
below
the
work
practice
standard.

(
1)
For
boilers
and
process
heaters
without
wet
43
scrubbers
that
must
comply
with
a
mercury
emission
limit
and
either
a
PM
emission
limit
or
a
total
selected
metals
emission
limit,
you
must
continuously
monitor
opacity
and
maintain
the
opacity
at
or
below
the
maximum
opacity
operating
limit
for
new
and
existing
sources.
Or,
if
the
unit
is
controlled
with
a
fabric
filter,
instead
of
continuous
monitoring
opacity,
the
fabric
filter
may
be
continuously
operated
such
that
the
bag
leak
detection
system
alarm
does
not
sound
more
than
5
percent
of
the
operating
time
during
any
6­
month
period.

(
2)
For
boilers
and
process
heaters
without
wet
or
dry
scrubbers
that
must
comply
with
an
HCl
emission
limit,
you
must
maintain
monthly
records
of
fuel
use
that
demonstrate
that
you
have
burned
no
new
fuel
types
or
new
mixtures
such
that
you
have
maintained
the
fuel
HCl
content
level
at
or
below
your
site­
specific
maximum
HCl
input
operating
limit.

If
you
plan
to
burn
a
new
fuel
type
or
a
new
mixture
than
what
was
burned
during
the
initial
performance
test,
then
you
must
re­
calculate
the
maximum
HCl
input
anticipated
from
the
new
fuels
based
on
supplier
data
or
your
own
fuel
analysis.
If
the
results
of
re­
calculating
the
HCl
input
exceeds
the
average
HCl
content
level
established
during
the
initial
test,
then
you
must
conduct
a
new
performance
test
to
demonstrate
continuous
compliance
with
the
HCl
emission
limit.
44
(
3)
For
boilers
and
process
heaters
with
wet
scrubbers
that
must
comply
with
a
mercury,
PM
(
or
total
selected
metals)
and/
or
an
HCl
emission
limit,
you
must
monitor
pressure
drop
and
liquid
flow
rate
of
the
scrubber
and
maintain
the
3­
hour
block
averages
at
or
above
the
operating
limits
established
during
the
performance
test.
You
must
monitor
the
pH
of
the
scrubber
and
maintain
the
3­
hour
block
average
at
or
above
the
operating
limit
established
during
the
performance
test
to
demonstrate
continuous
compliance
with
the
HCl
emission
limits.

(
4)
For
boilers
and
process
heaters
with
dry
scrubbers
that
must
comply
with
a
PM
(
or
total
selected
metals)
or
mercury
emission
limit,
and/
or
an
HCl
emission
limit,
you
must
continuously
monitor
the
sorbent
injection
rate
and
maintain
it
at
or
above
the
operating
limits
established
during
the
HCl
performance
test.

(
5)
For
boilers
and
process
heaters
with
fabric
filters
in
combination
with
wet
scrubbers,
you
must
monitor
the
pH,
pressure
drop,
and
liquid
flowrate
of
the
wet
scrubber
and
maintain
the
levels
at
or
above
the
operating
limits
established
during
the
HCl
performance
test.
You
must
also
maintain
the
operation
of
the
fabric
filter
such
that
the
bag
leak
detection
system
alarm
does
not
sound
more
than
5
percent
of
the
operating
time
during
any
6­
month
period.
45
(
6)
For
boilers
and
process
heaters
with
ESP
in
combination
with
wet
scrubbers
that
must
comply
with
a
mercury,
PM
and/
or
an
HCl
emission
limit,
you
must
monitor
the
pH,
pressure
drop,
and
liquid
flow
rate
of
the
wet
scrubber
and
maintain
the
3­
hour
block
averages
at
or
above
the
operating
limits
established
during
the
HCl
performance
test.
Also,
you
must
monitor
the
voltage
and
secondary
current
of
the
ESP
collection
plates
or
total
power
input
and
maintain
the
3­
hour
block
averages
at
or
above
the
operating
limits
established
during
the
mercury
or
PM
(
or
metals)
performance
test.

(
7)
For
boilers
and
process
heaters
that
choose
to
comply
with
the
alternative
total
selected
metals
limit
instead
of
PM
emission
limit,
you
must
maintain
monthly
fuel
records
that
demonstrate
that
you
burned
no
new
fuel
type
or
new
mixtures
such
that
the
total
selected
metals
content
of
the
inlet
fuel
was
maintained
at
or
below
your
maximum
fuel
inlet
metals
content
operating
limit
set
during
the
metals
performance
test.
If
you
plan
to
burn
a
new
fuel
type
or
new
mixture,
then
you
must
re­
calculate
the
maximum
metals
input
anticipated
from
the
new
fuels
based
on
supplier
data
or
own
fuel
analysis.
If
the
results
of
re­
calculating
the
metals
input
exceeds
the
average
metals
content
level
established
during
the
initial
test,
then
you
must
conduct
a
new
performance
test
to
demonstrate
continuous
compliance
46
with
the
alternate
selected
metals
emission
limit.

(
8)
For
boilers
and
process
heaters
that
choose
tomust
comply
with
the
mercury
emission
limit,
you
must
maintain
monthly
fuel
records
that
demonstrate
that
you
burned
no
new
fuel
type
or
new
mixture
such
that
the
total
selected
mercury
content
of
the
inlet
fuel
was
maintained
at
or
below
your
maximum
fuel
inlet
metals
content
operating
limit
set
during
the
mercury
performance
test.
If
you
plan
to
burn
a
new
fuel
type
or
new
mixture
than
what
was
burned
during
the
initial
performance
test,
then
you
must
re­
calculate
the
maximum
mercury
input
anticipated
from
the
new
fuels
based
on
supplier
data
or
own
fuel
analysis.
If
the
results
of
re­
calculating
the
mercury
input
exceeds
the
average
mercury
content
level
established
during
the
initial
test,
then
you
must
conduct
a
new
performance
test
to
demonstrate
continuous
compliance
with
the
mercury
emission
limit.

(
9)
For
boilers
and
process
heaters
that
choose
to
comply
with
any
emission
limit
based
on
fuel
analysis,
you
must
maintain
monthly
fuel
records
to
demonstrate
that
the
content
of
fuel
is
maintained
below
the
appropriate
applicable
emission
limit.

(
10)
For
new
boilers
and
process
heaters
in
any
of
the
large
or
limited
use
subcategories
with
heat
input
capacities
greater
or
equal
to
100
MMBtu/
hr,
you
must
continuously
monitor
CO
and
maintain
the
average
daily
CO
47
emissions
at
or
below
400
ppm
by
volume
on
a
dry
basis
(
corrected
to
3
percent
oxygen
for
units
in
the
liquid
or
gaseous
subcategories,
and
7
percent
for
units
in
the
solid
fuel
subcategories)
to
demonstrate
compliance
with
the
work
practice
standards
at
all
times
except
during
startup,

shutdown,
and
malfunction
and
when
the
unit
is
operating
less
than
50
percent
of
the
rated
capacity.

If
a
control
device
other
than
the
ones
specified
in
this
section
is
used
to
comply
with
the
final
rule,
you
must
establish
site­
specific
operating
limits
and
establish
appropriate
continuous
monitoring
requirements,
as
approved
by
the
EPA
Administrator.

If
you
choose
to
comply
using
emissions
averaging,
you
must
demonstrate
on
a
monthly
basis
that
mercury,
metals,

PM,
and
HCl
emission
limits
can
be
met
over
a
12­
month
period.

H.
What
are
the
notification,
recordkeeping
and
reporting
requirements?

If
your
boiler
or
process
heater
is
in
the
existing
large
andgaseous
fuel
subcategory,
or
existing
limited
use
gaseous
fuel­
fired
subcategoriesfuel
subcategory,
or
existing
large
and
limited
used
liquid
fuel­
fired
subcategories,
new
small
gaseous
fuel­
firedliquid
fuel
subcategory,
or
existing
limited
use
liquid
fuel
subcategory,
or
a
new
small
liquid
fuel­
firedfuel
units
that
48
only
burn
gaseous
fuels
or
distillate
oil,
you
only
have
to
submit
the
initial
notification
report.
If
your
boiler
or
process
heater
is
in
the
existing
small
gaseous,
liquid,
or
solid
fuel­
firedfuel
subcategories
or
new
small
gaseous
fuel
subcategory,
you
are
not
required
to
keep
any
records
or
submit
any
reports.

If
your
boiler
or
process
heater
is
in
any
other
subcategory,
then
you
must
keep
the
following
records:

(
1)
All
reports
and
notifications
submitted
to
comply
with
the
final
rule.

(
2)
Continuous
monitoring
data
as
required
in
the
final
rule.

(
3)
Each
instance
in
which
you
did
not
meet
each
emission
limit
work
practice
and
operating
limit,
including
periods
of
startup,
shutdown,
and
malfunction
(
i.
e.,

deviations
from
the
final
rule).

(
4)
Monthly
hours
of
operation
by
each
source
that
is
in
a
limited
use
subcategory.

(
5)
Monthly
fuel
use
by
each
boilers
and
process
heaters
subject
to
an
emission
limit
including
a
description
of
the
type(
s)
of
fuel(
s)
burned,
amount
of
each
fuel
type
burned,
and
units
of
measure
(
6)
Calculations
and
supporting
information
of
chloride
fuel
input,
as
required
in
the
final
rule.

(
7)
Calculations
and
supporting
information
of
total
49
selected
metals
and
mercury
fuel
input,
as
required
in
the
final
rule,
if
applicable.

(
8)
A
copy
of
the
results
of
all
performance
tests,

fuel
analysis,
opacity
observations,
performance
evaluations,
or
other
compliance
demonstrations
conducted
to
demonstrate
initial
or
continuous
compliance
with
the
final
rule.

(
9)
A
copy
of
any
federally
enforceable
permit
that
limits
the
annual
capacity
factor
of
the
source
to
less
than
or
equal
to
10
percent.

(
10)
A
copy
of
your
site­
specific
startup,
shutdown,

and
malfunction
plan.

(
11)
A
copy
of
your
site­
specific
monitoring
plan
developed
for
the
final
rule,
if
applicable.

(
12)
A
copy
of
your
site­
specific
fuel
analysis
plan
developed
for
the
final
rule,
if
applicable.

(
13)
A
copy
of
the
emissions
averaging
plan,
if
applicable.

You
must
submit
the
following
reports
and
notifications:

(
1)
Notifications
required
by
the
General
Provisions.

(
2)
Initial
Notification
no
later
than
120
calendar
days
after
you
become
subject
to
this
subpart.

(
3)
Notification
of
Intent
to
conduct
performance
tests
and/
or
compliance
demonstration
at
least
30
calendar
50
days
before
the
performance
test
and/
or
compliance
demonstration
is
scheduled.

(
4)
Notification
of
Compliance
Status
60
calendar
days
following
completion
of
the
performance
test
and/
or
compliance
demonstration.

(
5)
Notification
of
intent
to
demonstrate
compliance
by
emissions
averageing.

(
6)
Notification
of
intent
to
demonstrate
eligibility
for
either
health­
based
compliance
alternative.

(
6)
Compliance
reports
semi­
annually.

I.
What
are
the
health­
based
compliance
alternatives,
and
how
do
I
demonstrate
eligibility?

HCl
Compliance
Alternative.

As
an
alternative
to
the
requirement
for
each
large
solid
fuel­
fired
boiler
to
demonstrate
compliance
with
the
HCl
emission
limit
in
the
final
rule,
you
may
demonstrate
compliance
with
a
health­
based
facility­
wide
HCl
equivalent
allowable
emission
limit.

The
procedures
for
demonstrating
eligibility
for
the
HCl
compliance
alternative
(
as
outlined
in
appendix
A
of
the
final
rule)
are:

(
1)
You
must
include
in
your
demonstration
every
emission
point
within
the
facility
that
emits
a
respiratory
toxicant
included
on
EPA's
list
of
hazardous
air
pollutants.
51
(
2)
You
must
conduct
HCl
and
chlorine
emissions
tests
for
every
emission
point
covered
under
subpart
DDDDD.

(
3)
You
must
obtain
either
through
emission
testing
or
through
the
development
and
documentation
of
best
engineering
estimates
of
maximum
emissions
of
respiratory
toxicants
from
all
emission
points
at
the
facility
not
covered
under
subpart
DDDDD
of
part
63
from
which
a
respiratory
toxicant
might
reasonably
be
emitted.

(
4)
You
must
determine
the
total
maximum
hourly
mass
HCl­
equivalent
emission
rate
for
your
facility
by
summing
the
maximum
hourly
toxicity­
weighted
emission
rates
of
all
appropriate
respiratory
toxicants
(
calculated
using
the
maximum
rated
capacities
of
the
units)
for
each
of
the
units
at
your
facility.

(
5)
Use
the
look­
up
table
in
the
appendix
A
of
subpart
DDDDD
to
determine
if
your
facility
is
in
compliance
with
health­
based
HCl­
equivalent
emission
limit.

(
6)
Select
the
maximum
allowable
HCl­
equivalent
emission
rate
from
the
look­
up
table
in
appendix
A
of
subpart
DDDDD
of
part
63
for
your
facility
using
the
average
stack
height
of
your
subpart
DDDDD
emission
units
as
your
stack
height
and
the
minimum
distance
between
any
respiratory
toxicant
emission
point
at
the
facility
and
the
closest
boundary
of
the
nearest
residential
(
or
52
residentially
zoned)
area
as
your
fenceline
distance.

(
7)
Your
facility
is
in
compliance
if
your
maximum
HCl­
equivalent
emission
rate
does
not
exceed
the
value
specified
in
the
look­
up
table
in
appendix
A
of
subpart
DDDDD.

(
8)
As
an
alternative
to
using
the
look­
up
table,
you
may
conduct
a
site­
specific
compliance
demonstration
(
as
outlined
in
appendix
A
of
subpart
DDDDD
of
part
63)
which
demonstrate
that
your
facility
cannot
cause
an
individual
chronic
inhalation
exposure
from
respiratory
toxicants
which
can
exceed
a
Hazard
Index
(
HI)
value
of
1.0.

Total
Selected
Metals
cCompliance
Alternative.

In
lieu
of
complying
with
the
emission
standard
for
total
selected
metals
(
TSM)
in
supart
DDDDD
of
part
63
based
on
the
sum
of
emissions
for
the
eight
selected
metals,
you
may
demonstrate
eligibility
for
complying
with
the
TSM
standard
based
on
excluding
manganese
emissions
from
the
summation
of
TSM
emissions
for
the
affected
source
unit.

The
procedures
for
demonstrating
eligibility
for
the
TSM
compliance
alternative
(
as
outlined
in
appendix
A
of
the
subpart
DDDDD)
are:

(
1)
You
must
include
in
your
demonstration
every
emission
point
within
the
facility
that
emits
a
CNS
toxicant
included
on
EPA's
list
of
hazardous
air
pollutants.
53
(
2)
You
must
conduct
manganese
emissions
tests
for
every
emission
point
covered
under
subpart
DDDDD
that
emits
manganese.

(
3)
You
must
obtain
either
through
emission
testing
or
through
the
development
and
documentation
of
best
engineering
estimates
of
maximum
emissions
of
CNS
toxicants
from
all
emission
points
at
the
facility
not
covered
under
subpart
DDDDD
from
which
a
CNS
toxicant
might
reasonably
be
emitted.

(
4)
You
must
determine
the
total
maximum
hourly
manganese
equivalent
emission
rate
from
your
facility
by
summing
the
maximum
hourly
toxicity­
weighted
emission
rates
of
all
appropriate
CNS
toxicants
(
calculated
using
the
maximum
rated
heat
input
capacities)
for
each
of
the
units
at
your
facility.

(
5)
Use
the
look­
up
table
in
appendix
A
of
subpart
DDDDD
to
determine
if
your
facility
is
eligible
for
complying
with
the
TSM
limit
based
on
the
sum
of
emissions
for
seven
metals
(
excluding
manganese)
for
the
affected
source
units.

(
6)
Select
the
maximum
allowable
manganese­
equivalent
emission
rate
from
the
look­
up
table
in
appendix
A
of
subpart
DDDDD
for
your
facility
using
the
average
stack
height
of
your
subpart
DDDDD
emission
units
as
your
stack
height
and
the
minimum
distance
between
any
CNS
toxicant
54
emission
point
at
the
facility
and
the
closest
boundary
of
the
nearest
residential
(
or
residentially
zoned)
area
as
your
fenceline
distance.

(
7)
Your
facility
is
eligible
if
your
maximum
manganese­
equivalent
emission
rate
does
not
exceed
the
value
specified
in
the
look­
up
table
in
appendix
A
of
subpart
DDDDD.

(
8)
As
an
alternative
to
using
look­
up
table
to
determine
if
your
facility
is
eligible
for
the
TSM
compliance
alternative,
you
may
conduct
a
site­
specific
compliance
demonstration
(
as
outlined
in
appendix
A
of
subpart
DDDDD)
which
demonstrates
that
your
facility
cannot
cause
an
individual
chronic
inhalation
exposure
from
CNS
toxicants
which
can
exceed
a
HI
value
of
1.0.

If
you
elect
to
demonstrate
eligibility
for
either
of
the
health­
based
compliance
alternatives,
you
must
submit
certified
documentation
supporting
compliance
with
the
procedures
at
least
1
year
before
the
compliance
date.

You
must
submit
supporting
documentation
including
documentation
of
all
maximum
capacities,
existing
control
devices
used
to
reduce
emissions,
stack
parameters,
and
fencelineproperty
boundary
distances
to
each
on­
site
source
of
HCl­
equivalent
and/
or
manganese­
equivalent
emissions.

You
must
keep
records
of
the
information
used
in
developing
the
eligibility
demonstration
for
your
affected
55
source.

To
be
eligible
for
either
health­
based
compliance
alternative,
the
parameters
that
defined
your
affected
source
as
eligible
for
the
health­
based
compliance
alternatives
(
including,
but
not
limited
to,
fuel
type,
type
of
control
devices,
process
parameters
documented
as
worstcase
conditions
during
the
emissions
testing
used
for
your
eligibility
demonstration)
must
be
incorporated
as
Federally
enforceable
limits
into
your
title
V
permit.
If
you
do
not
meet
these
criteria,
then
your
affected
source
is
subject
to
the
applicable
emission
limits,
operating
limits,
and
work
practice
standards
in
Subpart
DDDDD.

If
you
intend
to
change
key
parameters
(
including
distance
of
stack
to
the
fencelineproperty
boundary)
that
may
result
in
lower
allowable
health­
based
emission
limits,

you
must
recalculate
the
limits
under
the
provisions
of
this
section,
and
submit
documentation
supporting
the
revised
limits
prior
to
initiating
the
change
to
the
key
parameter.

If
you
intend
to
install
a
new
solid
fuel­
fired
boiler
or
process
heater
or
change
any
existing
emissions
controls
that
may
result
in
increasing
HCl­
equivalent
and/
or
manganese­
equivalent
emissions,
you
must
recalculate
the
total
maximum
hourly
HCl­
equivalent
and/
or
manganeseequivalent
emission
rate
from
your
affected
source,
and
submit
certified
documentation
supporting
continued
56
eligibility
under
the
revised
information
prior
to
initiating
the
new
installation
or
change
to
the
emissions
controls.

III.
What
are
the
significant
changes
since
proposal?

A.
Definition
of
Affected
Source
The
definition
of
affected
source
in
§
63.7490
has
been
revised
to
be:
(
1)
the
collection
of
all
existing
industrial,
commercial,
or
institutional
boilers
or
process
heaters
within
a
subcategory
located
at
a
major
source;

and/
or
(
2)
each
new
or
reconstructed
industrial,
commercial,

or
institutional
boiler
or
process
heater
located
at
a
major
source.

B.
Sources
Not
Covered
by
the
NESHAP
The
exemptions
in
the
applicability
section
of
the
final
NESHAP
(
§
63.7490(
c))
haves
been
writtenrevised
to
also
includeclarify
that
the
following
are
not
subject
to
this
rule:
blast
furnace
stoves,
any
boiler
or
process
heater
specifically
listed
as
an
affected
source
in
another
MACT
standard,
temporary
boilers,
and
blast
furnace
gas
fuelfired
boilers
and
process
heaters.

C.
Emission
limits
The
emission
limit
for
mercury
in
the
existing
large
solid
fuel
subcategories
has
been
written
as
0.000009
lb/
MMBtu
(
from
0.000007
lb/
MMBtu
at
proposal).
57
D.
Definitions
Added
and
Revised
The
EPA
has
written
the
definitions
of
large,
limited
use,
and
small
gaseous
subcategories
to
include
gaseous
fuel­
fired
boilers
and
process
heaters
that
burn
liquid
fuel
during
periods
of
gas
curtailment
or
gas
supply
emergencies.

The
final
rule
also
includes
a
definition
of
fuel
type
which
is
used
in
the
fuel
analysis
compliance
options.
Fuel
type
means
each
category
of
fuels
that
share
a
common
name
of
classification.
Examples
include,
but
are
not
limited
to:
bituminous
coal,
subbituminous
coal,
lignite,

anthracite,
biomass,
construction/
demolition
material,
salt
water
laden
wood,
creosote
treated
wood,
tires,
and
residual
oil.
Individual
fuel
types
received
from
different
suppliers
are
not
considered
new
fuel
types
except
for
construction/
demolition
material.

Construction/
demolition
material
means
waste
building
material
that
result
from
the
construction
or
demolition
operations
on
houses
and
commercial
and
industrial
buildings.

Unadulterated
wood,
component
of
biomass,
means
wood
or
wood
products
that
have
not
been
painted,
pigment­
stained,

or
pressure
treated
with
compounds
such
as
chromate
copper
arsenate,
pentachlorophenol,
and
creosote.
Plywood,

particle
board,
oriented
strand
board,
and
other
types
of
wood
products
bound
by
glues
and
resins
are
included
in
this
58
definition.

We
have
included
a
definition
for
temporary
boiler
to
mean
any
gaseous
or
liquid
fuel­
fired
boiler
that
is
designed,
and
is
capable
of,
being
carried
or
moved
from
one
location
to
another.
A
temporary
boiler
that
remains
at
a
location
for
more
than
180
consecutive
days
is
no
longer
considered
to
be
a
temporary
boiler.
Any
temporary
boiler
that
replaces
a
temporary
boiler
at
a
location
and
is
intended
to
perform
the
same
or
similar
function
will
be
included
in
calculating
the
consecutive
time
period.

The
final
rule
also
contains
a
definition
written
for
waste
heat
boiler
that
identifies
waste
heat
boilers
incorporating
duct
or
supplemental
burners
that
are
designed
to
supply
50
percent
or
more
of
the
total
rated
heat
input
capacity
of
the
waste
heat
boiler
as
not
being
waste
heat
boilers,
but
are
considered
boilers
and
subject
to
the
final
rule.

E.
Requirements
for
Sources
in
Subcategories
Without
Emission
Limit
or
Work
Practice
Requirements
In
the
final
rule,
we
have
clarified
that
sources
in
the
existing
large
and
limited
use
gaseous
fuel
subcategories,
existing
large
and
limited
use
liquid
fuel
subcategories,
new
small
gaseous
fuel
subcategory
and
new
small
liquid
fuel
subcategory
are
only
subject
to
the
initial
notification
requirements
in
§
63.9(
b)
of
subpart
A
59
of
this
part
and
are
not
required
to
submit
as
startup,

shutdown,
and
malfunction
(
SSM)
plan
as
part
of
their
initial
notification.
We
have
written
the
final
rule
to
state
that
sources
in
the
existing
small
gaseous
fuel,

liquid
fuel,
and
solid
fuel
subcategories
are
not
subject
to
any
requirements
in
the
final
rule
or
of
subpart
A
of
this
part.

F.
Carbon
Monoxide
Work
Practice
Emission
Level
and
Requirements
The
final
rule
provides
revisions
to
the
CO
work
practice
emission
levels.
For
new
sources
in
the
solid
fuel
subcategory,
the
work
practice
standard
has
been
written
to
be
corrected
to
7
percent
oxygen
rather
than
3
percent.

Units
in
the
gaseous
and
liquid
fuel
subcategories
still
have
to
correct
to
3
percent
oxygen.

The
final
rule
also
allows
sources
with
heat
input
capacities
greater
than
10
MMBtu/
hr
but
less
that
100
MMBtu/
hr
to
conduct
initial
and
annual
compliance
tests
to
demonstrate
compliance
with
the
CO
limit.
Sources
greater
than
100
MMBtu/
hr
must
still
demonstrate
compliance
using
CO
continuous
emission
monitors
(
CEM).

The
final
rule
also
does
not
allow
you
to
calculate
data
average
using
data
recorded
during
periods
where
your
boiler
or
process
heater
is
operating
at
less
than
50
percent
of
its
rated
capacity,
monitoring
malfunctions,
60
associated
repairs,
out­
of­
control
periods,
or
required
quality
assurance
or
control
activities.
You
must
use
all
data
collected
during
all
other
periods
in
assessing
compliance.

G.
Fuel
Analysis
Option
We
have
clarified
the
fuel
analysis
options
in
the
final
rule.
You
are
not
required
to
conduct
performance
tests
for
hydrogen
chloride,
mercury,
or
total
selected
metals
if
you
demonstrate
compliance
with
the
hydrogen
chloride,
mercury,
or
total
selected
metals
limits
based
on
the
fuel
pollutant
content.
Your
operating
limit
is
then
the
emission
limit
of
the
applicable
pollutant.
You
are
not
required
to
conduct
emission
tests.

If
you
demonstrate
compliance
with
the
HCl,
mercury,
or
TSM
limit
by
performance
tests,
then
your
operating
limits
are
the
operating
limits
of
the
control
device
(
if
used)
and
the
fuel
pollutant
content
of
the
fuel
type/
mixture
burned.

Units
burning
multiple
fuel
types
are
required
to
determine
by
fuel
analysis,
the
fuel
pollutant
content
of
the
fuel/
mixture
burned
during
the
performance
test.

The
final
rule
specifies
the
testing
and
initial
and
continuous
compliance
requirements
to
be
used
when
complying
with
the
fuel
analysis
options.
Fuel
analysis
tests
for
total
chloride,
gross
calorific
value,
mercury,
metal
analysis,
sample
collection,
and
sample
preparation
are
61
included
in
the
final
rule.

We
have
written
the
requirement
to
remove
the
need
for
conducting
additional
tests
if
you
receive
fuel
from
a
new
supplier.
You
are
required
to
conduct
another
performance
test
and
fuel
analysis,
if
you
demonstrated
compliance
through
performance
testing,
only
when
you
burn
a
new
fuel
type
or
mixture,
and
the
results
of
recalculating
the
fuel
pollutant
content
are
higher
than
the
level
established
during
the
initial
performance
test.

H.
Emissions
Averaging
We
have
included
a
compliance
alternative
in
the
final
rule
to
allow
emissions
averaging
between
existing
large
solid
fuel­
fired
boilers
only.
Compliance
must
be
demonstrated
on
a
12­
month
rolling
averagemonthly
basis,

determined
at
the
end
of
every
month.
If
you
elect
to
comply
with
the
emissions
averaging
compliance
alternative,

you
must
use
equations
provided
in
the
final
rule
to
demonstrate
that
particulate
matter
or
TSM,
HCl,
and
mercury
from
all
applicable
units
do
not
exceed
the
emission
limits
specified
in
the
final
rule.
If
you
use
this
option,
you
must
also
develop
and
submit
an
implementation
plan
no
later
than
6
months
before
the
date
that
the
facility
intends
to
demonstrate
compliance.

I.
Opacity
Limit
At
proposal,
we
required
sources
meeting
the
PM
and
62
mercury
limits
to
determine
site­
specific
opacity
operating
limits
based
on
levels
during
the
initial
performance
test.

To
demonstrate
continuous
compliance
with
the
opacity
limit,

the
final
rule
provides
two
options.
The
opacity
operating
limits
have
been
established
to
be
20
percent
(
based
on
6­

minute
averages)
except
for
one
6­
minute
period
per
hour
of
not
more
than
27
percent
for
existing
sources
and
10
percent
(
based
on
1­
hour
block
averages).

J.
Operating
Limit
Determination
The
final
rule
defines
maximum
and
minimum
operating
parameters
that
must
be
met.
For
sources
complying
with
the
alternative
opacity
requirement
of
establishing
opacity
limits
during
the
initial
performance
test,
the
maximum
opacity
operating
limit
is
110
percent
of
the
highest
testrun
average
opacity
measured
according
to
the
final
rule
during
the
most
recent
performance
test
demonstrating
compliance
with
the
applicable
emission
limit.
For
sources
meeting
the
standards
using
scrubbers
or
ESP,
the
minimum
pressure
drop,
scrubber
effluent
pH,
scrubber
flow
rate,

sorbent
flow
rate,
voltage
or
amperage
means
90
percent
of
the
lowest
test
run
average
pressure
drop,
scrubber
effluent
pH,
scrubber
flow
rate,
sorbent
flow
rate,
voltage
or
amperage
measured
according
to
the
most
recent
performance
test
demonstrating
compliance
with
the
applicable
emission
limits.
63
The
final
rule
clarifies
that
operation
above
the
established
maximum
or
below
the
established
minimum
operating
parameters
constitute
a
deviation
of
established
operating
parameters.

K.
Revision
of
Compliance
Dates
In
§
63.7510,
we
have
also
written
the
date
by
which
you
have
to
demonstratecomplete
a
compliance
demonstration
to
be
180
days
after
the
compliance
date
instead
of
at
the
compliance
date.

IV.
What
are
the
responses
to
significant
comments?

We
received
218
public
comment
letters
on
the
proposed
rule.
Complete
summaries
of
all
the
comments
and
responses
are
found
in
the
Response­
to­
Comments
document
(
see
SUPPLEMENTARY
INFORMATION
section).

A.
Applicability
Comment:
Many
commenters
requested
that
EPA
exempt
units
that
are
not
subject
to
emission
limits
or
work
practice
requirements
from
monitoring,
recordkeeping,
and
reporting
requirements.

Response:
We
contend
that
sSources
in
subcategories
that
do
not
have
any
emission
limitations
and
work
practices
shouldare
not
be
required
to
keep
records
or
reports
other
than
the
initial
notification.
This
is
appropriate
because
no
reports
other
than
the
initial
notification
would
apply
64
to
these
units.
The
SSM
plan
is
not
necessary
nor
required
for
these
units
because
§
63.6(
e)(
3)
of
subpart
A
of
this
part
requires
an
affected
source
to
develop
an
SSM
plan
for
control
equipment
used
to
comply
with
the
relevant
standard.

The
proposed
rule
was
not
intended
to
require
monitoring,

recordkeeping,
and
reporting
(
including
startup,
shutdown,

and
malfunction
plans),
other
than
the
initial
notification
for
sources
not
subject
to
an
emission
limit.
We
have
clarified
this
decision
in
the
final
rule.
We
have
also
determined
that
existing
small
units
and
new
small
gaseous
fuel
units,
which
are
not
subject
to
emission
limits
or
work
practices
in
this
standard,
and
which
are
also
not
subject
to
such
requirements
in
any
other
Federal
regulation,
should
also
not
have
to
provide
an
initial
notification.
These
small
sources
are
generally
gas­
fired
and
since
they
have
minimal
emissions,
they
are
usually
considered
as
insignificant
emission
units
by
State
permitting
agencies.

Comment:
Several
commenters
requested
that
EPA
specifically
exclude
portable/
transportable
units
from
the
final
rule.
The
commenters
stated
that
facilities
periodically
use
these
units
to
supply
or
supplement
other
site
steam
supplies
when
there
is
a
mechanical
problem
that
takes
a
unit
out
of
service
or
during
planned
outages.
The
commenters
added
that
because
they
are
used
on
a
limited
basis,
portable
units
are
not
fully
integrated
with
site
65
control
systems
and
most
portable/
transportable
units
are
owned
by
a
rental
company
and
may
not
be
operated
by
the
facility
owner/
operator.

Response:
We
agree
with
the
commenters
that
temporary/
portable
units
are
used
only
on
a
limited
basis
and
are
not
integrated
into
a
facilitiey's
control
system.

These
units
are
gas
or
oil
fired
units.
Units
in
the
existing
gaseous
or
liquid
subcategories
are
not
subject
to
emission
limits
or
work
practice
standards.
Consequently,

we
have
decided
to
exemptthat
temporary/
portable
units
fromare
not
subject
to
the
final
rule.
We
have
added
a
definition
for
temporary
boiler
to
mean
any
gaseous
or
liquid
fuel­
fired
boiler
that
is
designed,
and
is
capable
of,
being
carried
or
moved
from
one
location
to
another.
A
temporary
boiler
that
remains
at
a
location
for
more
than
180
consecutive
days
is
no
longer
considered
to
be
a
temporary
boiler.
Any
temporary
boiler
that
replaces
a
temporary
boiler
at
a
location
and
is
intended
to
perform
the
same
or
similar
function
will
be
included
in
calculating
the
consecutive
time
period.
We
chose
the
180­
day
time
frame
because
that
is
the
length
of
time
a
new
source
has
after
startup
to
conduct
the
initial
performance
test.

Comment:
Several
commenters
requested
EPA
provide
a
lower
size
cut­
off
for
the
small
unit
subcategory.
Several
commenters
argued
that
the
benefits
from
requiring
smaller
66
units
to
install
controls
would
be
minimal
given
the
overall
monitoring,
recordkeeping,
and
reporting
burden.
Several
commenters
also
requested
lower
size
cutoffs
to
make
the
final
rule
similar
to
others
established
by
EPA
(
e.
g,
new
source
performance
(
NSPS),
Nitrogen
Oxide
(
NOx)
SIP
Call).

Several
commenters
noted
several
recent
court
decisions
in
which
the
court
has
decided
that
a
de
minimis
exemption
is
appropriate
since
the
regulation
of
small
sources
would
yield
a
gain
of
trivial
or
no
value
yet
would
impose
significant
regulatory
burden.
A
wide
range
of
lower
size
cutoffs
were
suggested.
However,
one
commenter
said
that
EPA
should
not
develop
de
minimis
exemptions.
The
commenter
noted
that
de
minimis
exemptions
do
not
spare
EPA's
resources
for
use
on
other
purposes
and
are
not
justified
by
reductions
in
industry
burden
or
inconvenience.
The
commenter
noted
that
EPA
did
not
establish
any
administrative
record
justifying
the
de
minimis
exemption.

Response:
We
have
reviewed
the
commenters
arguments
and
all
the
data
provided
in
the
comment
letters.
There
is
no
justification
for
developing
a
lower
size
cut­
off
or
de
minimis
level.
We
would
also
note
the
designation
of
large
and
small
subcategories
was
not
based
solely
on
size
of
the
unit.
Large
and
small
subcategories
were
developed
because
small
units
less
than
10
MMBtu/
hr
heat
input
typically
use
a
combustor
design
that
is
not
common
in
larger
units.
Large
67
boilers
generally
use
the
watertube
combustor
design.
The
design
of
the
boiler
or
process
heater
will
influence
the
completeness
of
the
combustion
process
which
will
influence
the
formation
of
organic
HAP
emissions.
Additionally,
the
vast
majority
of
small
units
use
natural
gas
as
fuel.
The
EPA
chose
to
develop
large
and
small
subcategories
to
account
for
these
differences
and
their
affect
on
the
type
of
emissions.
The
cut­
off
between
the
large
and
small
subcategories
of
10
MMBtu/
hr
was
based
on
typical
sizes
for
fire
tube
units,
and
also
when
considering
cut­
offs
in
State
and
Federal
rules.
Lastly,
we
would
like
to
note
that
the
final
rule
does
not
impose
any
requirements
for
existing
units
in
any
of
the
small
subcategories.

Comment:
Many
commenters
asked
EPA
to
clarify
which
sources
are
exempted
fromnot
covered
by
the
final
rule.

Response:
We
have
included
an
extensive
list
of
sources
that
are
exempt
fromnot
subject
to
the
final
rule.

The
final
rule
clarifies
that
boilers
and
process
heaters
that
are
included
as
part
of
the
affected
source
in
any
other
NESHAP
are
exempt
fromnot
subject
to
the
NESHAP
for
industrial
boilers
and
process
heaters.
However,
we
do
not
exemptexclude
boilers
and
process
heaters
that
are
used
as
control
devices
unless
they
are
specifically
considered
part
of
any
other
NESHAP's
definition
of
affected
source.

Incinerators,
thermal
oxidizers,
and
flares
do
not
generally
68
fall
under
the
definition
of
a
boiler
or
process
heater
and
would
not
be
subject
to
the
final
rule.
The
final
rule
excludes
waste
heat
boilers
and
waste
heat
boilers
with
supplemental
firing,
as
long
as
the
supplemental
firing
does
not
provide
more
than
50
percent
of
the
waste
heat
boiler's
heat
input.
If
your
waste
heat
boiler
does
receive
50
percent
of
its
total
heat
input
from
supplemental
firing,
it
would
be
subject
to
the
NESHAP
for
industrial
boilers
unless
it
is
subject
to
any
other
NESHAP.
The
final
rule
directly
exempts
some
sources
and
provides
a
blanket
exemption
for
sources
that
have
been
specifically
listed
as
an
affected
source
under
any
other
NESHAP.
We
specifically
exemptexclude
comfort
heaters
from
the
final
rule.
However,

this
exemptionexclusion
does
not
include
boilers
used
to
make
steam
or
heated
water
for
comfort
heat.
If
your
boiler
meets
the
definition
of
a
hot
water
heater,
then
it
would
not
be
exempt
fromsubject
to
the
final
rule.
However,
if
the
temperature,
pressure,
or
capacity
specifications
of
your
boiler
exceed
the
criteria
specified
for
hot
water
heaters,
then
your
boiler
would
be
subject
to
the
final
rule.
We
recognize
the
unique
properties
of
blast
furnace
gas
having
high
CO
concentrations
and
none
to
almost
no
organic
compounds.
Consequently,
we
agree
that
for
these
sources
CO
is
not
a
surrogate
for
organic
HAP
emissions
since
CO
is
the
primary
component
of
blast
furnace
gas
and
69
virtually
no
organic
HAP
are
generated
in
its
combustion.

As
a
result,
we
exemptexclude
from
the
final
rule
units
that
receive
90
percent
or
more
of
their
total
heat
input
from
blast
furnace
gas.
In
the
final
rule,
we
provide
a
generic
exemption
for
sources
that
are
specifically
listed
as
an
affected
source
in
any
other
standards
under
40
CFR
part
63
in
addition
to
the
list
of
specific
exemptions.
In
addition,
research
and
development
(
R&
D)
operations
are
not
subject
to
the
final
rule.
Excluding
them
is
consistent
with
EPA
statements
in
the
advanced
notice
of
proposed
rulemaking
to
list
R&
D
as
a
separate
source
category
(
62
FR
25877)
that
including
R&
D
operations
in
a
rule
governing
manufacturing
operations
would
be
problematic.
Therefore,

boilers
or
process
heaters
that
are
used
specifically
for
research
and
development
are
not
regulated
under
the
final
rule.
However,
units
that
only
provide
steam
to
a
process
or
for
heating
at
a
research
and
development
facility
are
still
subject
to
the
final
rule.
This
should
address
the
commenters'
concern
over
overlapping
applicability.

Comment:
Several
commenters
suggested
that
EPA
revise
the
proposed
definition
of
affected
source
to
be
consistent
with
the
definition
of
affected
source
in
the
General
Provisions.
The
definition
in
the
rule
as
proposed
is
much
more
narrow
than
that
in
the
General
Provisions,
even
though
the
General
Provisions
states
that
each
standard
will
70
redefine
affected
source
based
on
published
justification
as
to
why
the
definition
would
result
in
significant
administration,
practical
or
implementation
problems.
The
commenters
argued
that
EPA
failed
to
provide
justification
for
the
proposed
definition
of
affected
source,
which
is
narrower
than
the
definition
of
affected
source
in
the
General
Provisions.

Response:
We
agree
with
the
commenters
and
in
the
final
rule
have
incorporated
the
broader
definition
of
affected
source
from
the
revised
General
Provisions.
The
EPA
did
not
receive
any
comments
opposing
the
new
definitions
forGeneral
Provisions
define
the
affected
source
as
"
the
collection
of
equipment,
activities,
or
both
within
a
single
contiguous
area
and
new
affected
source
for
future
MACT
standards
when
they
were
proposed
on
March
23,
2001
(
66
FR
16318).
Accordingly,
EPA
adopted
these
definitions
as
promulgated
on
April
5,
2002
(
67
FR
16582).
under
common
control
that
is
included
in
a
section
112(
c)
source
category
or
subcategory
.
.
.
"
Therefore,
the
definition
of
existing
affected
source
in
the
final
rule
is
the
collection
of
existing
industrial,
commercial,
or
institutional
boilers
and
process
heaters
within
a
subcategory
located
at
a
major
source
of
HAP
emissions.

B.
Format
Comment:
Several
commenters
opposed
using
one
or
more
71
surrogates
for
the
HAP
regulated.
Some
commenters
stated
that
EPA
must
set
emission
standards
for
each
HAP
emitted
by
this
category.
One
commenter
explained
that
the
use
of
surrogates
is
acceptable
if:
(
1)
the
surrogates
reflect
the
actual
emissions
of
the
represented
pollutants,
(
2)
the
emission
limit
set
for
the
surrogate
is
consistent
with
the
emission
limit
calculated
for
the
represented
pollutants,

and
(
3)
the
surrogates
have
substantially
the
same
properties
as
the
represented
pollutants
and
is
controlled
by
the
same
mechanism.
Based
on
these
criteria,
the
commenter
argued
that
EPA's
selection
of
surrogates
is
inadequate.
One
commenter
specifically
contended
that
CO
is
not
an
adequate
surrogate
for
dioxin
because
dioxin
emissions
are
affected
by
the
temperature
of
the
emissions,

how
quickly
the
temperature
is
lowered,
and
the
levels
of
chlorine
in
the
materials
that
are
being
combusted
and
control
devices.
Other
commenters
supported
the
use
of
surrogates
to
represent
the
HAP
list.

Response:
As
discussed
in
the
proposal
preamble,
the
use
of
surrogates
for
the
HAP
regulated
is
appropriate.

Because
of
the
large
number
of
HAP
potentially
present,
the
disparity
in
the
quality
and
quantity
of
the
emissions
information
available,
particularly
for
different
fuel
types,
we
chose
to
group
HAP
into
four
categories:

mercury,
non­
mercury
metallic
HAP,
inorganic
HAP,
and
72
organic
HAP.
In
general,
the
pollutants
within
each
group
have
similar
characteristics
and
can
be
controlled
with
the
same
techniques.
We
then
chose
compounds
that
could
be
used
as
surrogates
for
all
the
compounds
in
each
pollutant
category.
We
have
used
surrogates
in
previous
NESHAP
as
a
technique
to
reduce
the
performance
testing
costs,
and
thus
the
use
of
surrogates
is
appropriate
in
the
final
rule.

For
inorganic
HAP,
we
chose
to
use
HCl
as
a
surrogate.

The
emissions
test
information
available
to
us
indicated
that
the
primary
inorganic
HAP
emitted
from
boilers
and
process
heaters
is
HCl.
Much
smaller
amounts
of
hydrogen
fluoride
and
chlorine
are
emitted.
Control
technologies
that
would
reduce
HCl
would
also
control
other
inorganic
HAP.
Additionally,
we
had
limited
emissions
information
for
other
inorganic
HAP.
By
focusing
on
HCl,
we
have
achieved
control
of
the
largest
emitted
and
most
widely
emitted
HAP,

and
control
of
HCl
would
also
constitute
control
of
other
inorganic
HAP.

For
non­
mercury
metallic
HAP,
we
chose
to
use
PM
as
a
surrogate.
Most,
if
not
all,
non­
mercury
metallic
HAP
emitted
from
combustion
sources
will
appear
on
the
flue
gas
fly­
ash.
Therefore,
the
same
control
technology
that
would
be
used
to
control
fly­
ash
PM
will
control
non­
mercury
metallic
HAP.
A
review
of
data
in
the
emission
database
for
PM
control
devices
having
both
inlet
and
outlet
emissions
73
results
shows
control
efficiencies
for
each
non­
mercury
metallic
HAP
similar
to
PM.
Particulate
matter
was
also
chosen
instead
of
a
specific
metallic
HAP
because
all
fuels
do
not
emit
the
same
type
and
amount
of
metallic
HAP,
but
most
generally
emit
PM
that
includes
some
amount
and
combination
of
metallic
HAP.
We
maintain
that
particulate
matter
reflects
the
emissions
of
non­
mercury
metallic
HAP
as
these
compounds
usually
comprise
a
percentage
of
the
emitted
particulate
matter.
Since
the
NESHAP
program
is
technologybased
the
technologies
that
have
been
developed
and
implemented
to
control
particulate
matter,
also
control
nonmercury
metallic
HAP.
Furthermore,
since
non­
mercury
metallic
HAP
is
a
component
of
particulate
matter,
we
can
use
particulate
matter
as
a
surrogate
for
the
purposes
of
the
final
rule.

While
we
did
use
PM
as
a
surrogate
for
non­
mercury
metallic
HAP,
we
also
provided
an
alternative
total
selected
metals
emission
limit
based
on
the
sum
of
the
emissions
of
the
eight
most
common
and
largest
emitted
metallic
HAP
compounds
from
boilers
and
process
heaters.
Again,
a
total
selected
metals
number
was
used
instead
of
limits
for
each
individual
metallic
HAP
because
sufficient
information
was
not
available
for
each
metallic
HAP
for
every
fuel
type.

However,
a
total
metals
number
could
be
calculated
for
every
fuel
type.
74
We
realize
that
mercury
emissions
can
exist
in
different
forms
depending
on
combustion
conditions
and
concentrations
of
other
compounds.
That
is
why
we
have
mercury
as
a
separate
pollutant
category
in
the
final
rule
and
do
not
provide
for
a
surrogate.

For
organic
HAP,
we
chose
to
use
CO
as
a
surrogate
to
represent
the
variety
of
organic
compounds
emitted
from
the
various
fuels
burned.
Both
organic
HAP
and
CO
emissions
are
the
result
of
incomplete
combustion
of
the
fuel.
Because
CO
is
a
good
indicator
of
incomplete
combustion,
there
is
a
direct
correlation
between
CO
emissions
and
minimizing
organic
HAP
emissions.
The
extent
to
which
CO
and
HAP
emissions
are
related
can
also
depend
on
site­
specific
operating
conditions
for
each
boiler
or
process
heater.

This
site­
specific
nature
may
result
in
various
degrees
of
correlation
between
CO
and
organic
HAP
emissions,
but
it
is
proven
that
reductions
in
CO
emissions
result
in
a
reduction
of
organic
HAP
emissions.
The
control
methods
for
both
CO
and
organic
HAP
are
the
same,
i.
e.,
complete
combustion.

This
result
would
not
have
been
different
if
MACT
floor
analyses
were
conducted
for
specific
organic
HAP
or
for
a
surrogate
compound
such
as
CO.
For
boilers
and
process
heaters,
we
have
determined
that
CO
is
a
reasonable
indicator
of
incomplete
combustion.
Also,
we
did
not
set
emission
limits
for
each
specific
organic
HAP
because
we
75
lacked
sufficient
information
for
many
of
the
organic
HAP
for
all
the
fuels
combusted.
We
acknowledge
that
there
are
many
factors
that
affect
the
formation
of
dioxin,
but
we
also
recognize
that
dioxin
can
be
formed
in
both
the
combustion
unit
and
downstream
in
the
associated
PM
control
device.
Minimizing
organic
HAP
emissions
can
limit
the
formation
of
dioxin
in
the
combustion
unit.
We
reviewed
all
the
good
combustion
practice
(
GCP)
information
available
in
the
boiler
population
database
and
determined
that
no
floor
level
of
control
exists,
except
for
limiting
CO
emissions,

such
that
GCP
could
be
incorporated
into
the
standard.
One
control
technique,
controlling
inlet
temperature
to
the
PM
control
device,
that
has
demonstrated
controlling
downstream
formation
of
dioxins
in
other
source
categories
(
e.
g.,

municipal
waste
combustors)
was
analyzed
for
industrial
boilers.
In
all
cases,
no
increase
in
dioxins
emissions
were
indicated
across
the
PM
control
device
even
at
high
inlet
temperatures.
However,
we
requested
comment
on
controls
that
would
achieve
reductions
of
organic
HAP,

including
any
additional
data
that
might
be
available.
The
EPA
did
not
receive
any
additional
supporting
information
or
data.
Additionally,
more
stringent
options
beyond
the
floor
level
of
control
were
evaluated,
but
were
determined
to
be
too
costly
and
emission
reductions
associated
with
the
options
could
not
be
evaluated
because
no
information
was
76
available
that
indicated
a
relationship
between
the
GCP
and
emission
reduction
of
organics
(
including
dioxin).

C.
Compliance
Schedule
Comment:
Many
commenters
requested
that
EPA
provide
an
additional
year
to
comply
with
the
final
rule.
Commenters
explained
that
the
time
lines
associated
with
permitting,

capital
appropriation,
project
bid,
and
construction
activities
are
significant
and
that
the
3­
year
deadline
would
not
provide
adequate
time
for
the
estimated
3,730
existing
units
at
affected
sources
to
be
retrofitted
as
necessary
to
meet
the
new
MACT
standards.
The
commenters
added
that
sources
subject
to
the
final
rule
would
also
be
competing
with
sources
that
are
subject
to
other
combustion
rules
for
the
same
vendors.

Response:
The
EPA
disagrees
with
the
commenters
that
the
3­
year
compliance
deadline
is
too
short
considering
the
number
of
sources
that
will
be
competing
for
the
resources
and
materials
from
engineering
consultants,
equipment
vendors,
construction
contractors,
financial
institutions,

and
other
critical
suppliers.
The
EPA
recognizes
the
possibility
that
these
same
consultants,
vendors,
etc.,
may
also
be
used
to
comply
with
the
utility
MACT
standard.

However,
we
know
that
many
sources
will
not
need
to
install
controls.
As
a
result,
since
not
everyone
will
need
more
than
3
years
to
actually
install
controls,
the
final
rule
77
does
not
allow
an
extra
year
for
existing
sources
to
comply
with
the
final
rule.
Section
112(
i)(
3)(
B)
of
the
CAA
allows
EPAthe
permit
authority,
on
a
case­
by­
case
basis
to
grant
an
extension
permitting
an
existing
source
up
to
1
additional
year
to
comply
with
standards
if
such
additional
period
is
necessary
for
the
installation
of
controls.
This
provision
is
sufficient
for
those
sources
where
the
3­
year
deadline
would
not
provide
adequate
time
to
retrofit
as
necessary
to
comply
with
the
requirements
of
the
standard.

D.
Subcategorization
Comment:
Two
commenters
said
that
EPA
does
not
have
the
authority
to
develop
subcategories
for
the
purpose
of
reducing
compliance
costs
or
weakening
the
standard.
The
commenters
also
noted
that
costs
should
not
be
considered
in
subcategorizing
and
establishing
the
MACT
floor.
One
commenter
explained
that
EPA
has
failed
to
present
a
persuasive
rationale
for
the
establishment
of
new
or
different
subcategories,
such
as
a
wood­
fired
unit
subcategory
and
noted
that
EPA
cannot
subcategorize
based
on
fuel
type,
cost,
level
of
emission
reductions,
control
technology
applicability
or
effectiveness,
achievability
of
emission
reductions,
or
health
risks.
The
commenter
argued
that
EPA
cannot
subcategorize
to
reduce
cost
because
that
would
change
CAA
section
112
standards
into
a
cost­
benefit
program
and
that
is
not
legally
defensible.
The
commenter
78
noted
that
the
D.
C.
Circuit
court
recently
held
that,
when
confronted
with
the
cost
argument,
costs
are
not
relevant
when
determining
MACT
floors.

Response:
If
the
commenters
are
referring
to
the
request
for
comment
regarding
further
subcategorizations
than
what
was
proposed,
the
EPA
agrees
that
there
is
no
justification
for
any
further
subcategories.
The
final
rule
maintains
the
subcategories
presented
in
the
proposed
rule.

If
the
commenters
are
referring
to
subcategories
presented
in
the
proposed
rule,
section
112(
d)(
1)
of
the
CAA
states
"
the
Administrator
may
distinguish
among
classes,
types,
and
sizes
of
sources
within
a
category
or
subcategory"
in
establishing
emission
standards.
Thus,
we
have
discretion
in
determining
appropriate
subcategories
based
on
classes,

types,
and
sizes
of
sources.
We
used
this
discretion
in
developing
subcategories
for
the
industrial,
commercial,
and
institutional
boilers
and
process
heaters
source
category.

Through
subcategorization,
we
are
able
to
define
subsets
of
similar
emission
sources
within
a
source
category
if
differences
in
emissions
characteristics,
processes,
aie
pollution
control
device
(
APCD)
viability,
or
opportunities
for
pollution
prevention
exist
within
the
source
category.

We
first
subcategorized
boilers
and
process
heaters
based
on
the
physical
state
of
the
fuel
(
solid,
liquid,
or
gaseous),

which
will
affect
the
type
of
pollutants
emitted
and
79
controls
applicable,
and
the
design
and
operation
of
the
boiler,
which
influences
the
formation
of
organic
HAP
emissions.
We
then
further
subcategorized
boilers
and
process
heaters
based
on
size.
Our
distinctions
are
based
on
technological
differences
in
the
equipment.
For
example,

small
units
are
package
units
typically
having
capacities
less
than
10
million
Btu
per
hour
heat
input
and
use
a
combustor
design
which
is
not
common
in
large
units.
A
review
of
the
information
gathered
on
boilers
also
shows
that
a
number
of
units
operate
as
backup,
emergency,
or
peaking
units
that
operate
infrequently.
The
boiler
database
indicates
that
these
infrequently
operated
units
typically
operate
10
percent
of
the
year
or
less.
These
limited
use
boilers,
when
called
upon
to
operate,
must
respond
without
failure
and
without
lengthy
periods
of
startup.
Since
their
use
and
operation
are
different
compared
to
typical
industrial,
commercial,
and
institutional
boilers,
we
decided
that
such
limited
use
units
should
have
their
own
subcategory.

The
EPA
contends
that
nNeither
the
subcategories
or
MACT
floor
analysis
was
conducted
considering
costs,
either
in
the
proposed
rule
or
in
the
final
rule.

Comment:
Many
commenters
requested
EPA
to
develop
a
separate
subcategory
for
small
municipal
electric
utilities.

Reasons
for
creating
a
subcategory
for
small
electrical
80
utility
steam
generating
units
included:
(
1)
EPA
has
authority
to
establish
such
a
subcategory
of
sources
to
be
regulated
under
CAA
section
112
and
is
meant
to
address
control
costs
and
feasibility,
(
2)
past
EPA
practice
supports
subcategorization
in
this
instance,
(
3)
differences
between
municipal
utility
boilers
and
non­
utility
boilers
justify
subcategorization,
and
(
4)
EPA
cannot
properly
account
for
cost
and
energy
concerns
mandated
in
the
MACT
standard
setting
process
without
subcategorization
for
municipal
utility
boilers.
The
commenters
added
that
the
unique
physical
attributes
of
municipally­
owned
utilities,

as
well
as
their
significant
and
direct
impact
on
municipal
tax
base,
support
a
separate
subcategorization.

Response:
The
EPA
sees
no
technical
or
legal
justification
for
creating
a
separate
subcategory
for
municipal
utilities.
Boilers
at
municipal
utilities
fire
the
same
type
of
fuels,
have
the
same
type
of
combustor
designs,
and
can
use
the
same
type
of
controls
as
other
units
in
the
large
subcategory.
Consequently,
the
subcategories
that
are
in
the
final
rule
are
the
same
as
at
proposal.
We
would
also
like
to
clarify
that
subcategories
were
developed
based
on
combustor
design
and
not
on
industrial
sector.
Also,
had
we
gone
beyond­
the­
floor,
we
would
have
considered
cost
in
the
final
determination.

Since
we
did
not
go
beyond­
the­
floor
level
of
control,
cost
81
did
not
play
a
role
in
the
analysis.

Comment:
Many
commenters
requested
EPA
add
a
subcategory
for
medium
sized
boilers
and
process
heaters.

Response:
The
EPA
does
not
see
justification
for
creating
a
separate
subcategory
for
medium
sized
units.
The
designation
of
large
and
small
subcategories
was
not
based
solely
on
size
of
the
unit.
Large
and
small
subcategories
were
developed
because
small
units
less
than
10
MMBtu/
hr
heat
input
typically
use
a
combustor
design
that
is
not
common
in
larger
units.
Large
boilers
generally
use
the
watertube
combustor
design.
The
design
of
the
boiler
or
process
heater
will
influence
the
completeness
of
the
combustion
process
which
will
influence
the
formation
of
organic
HAP
emissions.
The
EPA
chose
to
developed
large
and
small
subcategories
to
account
for
these
differences
and
their
affect
on
the
type
of
emissions.
The
proposed
size
break
between
the
large
and
small
subcategories
of
10
MMBtu/
hr
was
based
on
typical
sizes
for
firetube
and
cast
iron
units
and
considering
cut­
offs
in
State
and
Federal
permitting
requirements
and
rules.
The
EPA
does
not
view
medium
sized
boilers
as
being
different
than
larger
boilers.

Combustor
designs,
applicable
air
pollution
control
devices,

fuels
used,
and
operation
are
similar
for
large
and
medium.

While
actual
pollution
controls
used
and
monitoring
equipment
may
be
different,
the
CAA
does
not
allow
EPA
to
82
subcategorize
on
these
parameters.

Section
112(
d)(
1)
of
the
CAA
allows
EPA
to
distinguish
among
classes,
types,
and
size
in
establishing
MACT
standards.
As
indicated
above,
at
proposal,
the
size
break
selected
between
large
and
small
units
of
10
MMBtu/
hr
was
based
on
typical
sizes
for
fire
tube
units
and
also
considering
cut­
offs
in
State
and
Federal
permitting
requirements
and
emission
rules.
Based
on
comments,
we
have
examined
information
in
the
docket
regarding
the
population
and
characteristics
of
industrial,
commercial,
and
institutional
boilers.
It
is
correct
that
boilers
below
10
MMBtu/
hr
are
generally
not
required
to
be
permitted
and
are
either
firetube
or
cast
iron
boilers.
Based
on
review
of
the
thousands
of
responses
received
on
a
information
collection
request
(
ICR)
conducted
during
the
rulemaking,
it
is
obvious
and
appropriate
that
the
distinction
between
small
and
large
units
needs
to
include
size.
It
is
apparent
from
the
ICR
responses
that
facilities
know
the
size
of
their
units
but
do
not
generally
know
the
exact
type
of
the
units.
Many
responses
indicated
that
the
boiler
was
both
firetube
and
watertube.
Many
more
responses
did
not
list
the
boiler
type
at
all.
Therefore,
the
inclusion
of
size
in
the
definition
of
small
and
large
subcategories
is
appropriate.

Based
on
review
of
the
1979
EPA
document
on
boiler
83
population
and
the
information
collection
request
(
ICR)

survey
database,
the
appropriate
size
break
between
small
and
large
type
units
is
10
MMBtu/
hr.
In
the
EPA
document,

99
percent
of
the
boilers
listed
as
being
below
10
MMbtu/
hr
are
either
firetube
or
cast
iron.
Since
these
trends
are
from
a
25
year
old
report,
we
analyzed
our
ICR
survey
database
which
confirmed
these
findings.

E.
MACT
Floor
Comment:
Several
commenters
supported
EPA's
finding
that
the
MACT
floor
level
for
existing
gas
and
liquid
fuelfired
units
is
no
emission
reductions.
Other
commenters
contended
that
EPA
has
legal
authority
to
set
the
MACT
floor
as
"
no
emissions
control"
for
particular
HAP
categories.
A
commenter
said
that
EPA's
proposed
"
no
control"
as
the
MACT
floor
for
some
subcategories
is
unlawful.
The
commenter
noted
that
EPA
has
a
clear
statutory
obligation
to
set
emission
standards
for
each
listed
HAP.
One
commenter
argued
that
EPA's
determination
that
"
no
control"
is
the
MACT
floor
for
some
subcategories
is
unacceptable.
The
commenter
specifically
challenged
EPA's
determination
ofthat
"
no
control"
is
the
MACT
floor
for
organic
pollutants.
The
commenter
noted
that
the
U.
S.
Court
of
Appeals
for
the
D.
C.

Circuit
had
squarely
held,
in
the
National
Lime
case,
that
EPA
was
not
allowed
to
make
a
"
no
control"
determination
for
84
a
pollutant
emitted
by
a
listed
category
of
sources.

Response:
First,
we
believe
the
MACT
floor
methodology
we
use
is
consistent
with
D.
C.
Circuit's
holding
in
the
National
Lime
case.
The
D.
C.
Circuit
held
that
by
focusing
only
on
technology
EPA
ignored
the
directive
in
section
112(
d)(
2)
to
consider
pollution­
reducing
measures
including
process
changes
and
substitution
of
materials.

We
also
believe
thatThe
EPA
has
ample
legal
authority
to
set
the
MACT
floor
at
"
no
emissions
reductions".
This
is
because
the
statute
requires
EPA
to
set
standards
that
are
duplicable
by
others.
In
National
Lime,
the
court
threw
out
EPA's
determination
of
a
no
control
floor
because
it
was
based
only
on
a
control
technology
approach.
The
court
stated
that
EPA
must
look
at
what
the
best
performers
achieve,
regardless
of
how
they
achieve
it.
Therefore,
our
determination
that
the
MACT
floor
for
certain
subcategories
or
HAP
is
"
no
emissions
reduction"
is
lawful
because
we
determined
that
the
best­
performing
sources
were
not
achieving
emissions
reduction
through
the
use
of
an
emission
control
system
and
there
were
no
other
appropriate
methods
by
which
boilers
and
process
heaters
could
reduce
HAP
emissions.
Furthermore,
setting
emissions
standards
on
the
basis
of
actual
emissions
data
alone
where
facilities
have
no
way
of
controlling
their
HAP
emissions
would
contravene
85
the
plain
statutory
language
as
well
as
Congressional
intent
that
affected
sources
not
be
forced
to
shut
down.

The
EPA
agrees
with
the
commenter
that
all
factors
which
might
control
HAP
emissions
must
be
considered
in
making
a
floor
determination
for
each
subcategory.
However,

EPA
disagrees
that
it
must
express
the
floor
as
a
quantitative
emission
level
in
those
instances
where
the
source
on
which
the
floor
determination
is
based
has
not
adopted
or
implemented
any
measure
that
would
reduce
emissions.

A
detailed
discussion
of
the
MACT
floor
methodology
is
presented
in
the
memorandum
"
MACT
Floor
Analysis
for
New
and
Existing
Sources
in
the
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
Source
Categories"

in
the
docket.
In
summary,
we
considered
several
approaches
to
identifying
MACT
floor
for
existing
industrial,

commercial,
and
institutional
boilers
and
process
heaters.

Based
on
recent
court
decisions,
in
most
cases
the
most
acceptable
approach
for
determining
the
MACT
floor
is
likely
to
involve
primarily
the
consideration
of
available
emissions
test
data.
However,
after
review
of
the
available
HAP
emission
test
data,
we
determined
that
it
was
inappropriate
to
use
this
MACT
floor
approach
to
establish
emission
limits
for
boilers
and
process
heaters.
The
main
problem
with
using
only
the
HAP
emissions
data
is
that,
86
based
on
the
test
data
alone,
uncontrolled
units
(
or
units
with
low
efficiency
add­
on
controls)
were
frequently
identified
as
being
among
the
best
performing
12
percent
of
sources
in
a
subcategory,
while
many
units
with
high
efficiency
controls
were
not.
However,
these
uncontrolled
or
poorly
controlled
units
are
not
truly
among
the
best
controlled
units
in
the
category.
Rather,
the
emissions
from
these
units
are
relatively
low
because
of
particular
characteristics
of
the
fuel
that
they
burn,
that
can
not
reasonably
be
replicated
by
other
units
in
the
category
or
subcategory.
A
review
of
fuel
analyses
indicate
that
the
concentration
of
HAP
(
metals,
HCl,
mercury)
vary
greatly,

not
only
between
fuel
types,
but
also
within
each
fuel
type.

Therefore,
a
unit
without
any
add­
on
controls,
but
burning
a
fuel
containing
lower
amounts
of
HAP,
can
have
emission
levels
that
are
lower
than
the
emissions
from
a
unit
with
the
best
available
add­
on
controls.
If
only
the
available
HAP
emissions
data
are
used,
the
resulting
MACT
floor
levels
would,
in
most
cases,
be
unachievable
for
many,
if
not
most,

existing
units,
even
those
that
employ
the
most
effective
available
emission
control
technology.
Another
problem
with
using
only
emissions
data
is
that
there
is
very
limited
or
no
HAP
emissions
information
available
to
the
Agency
for
the
subcategories.
This
is
consistent
with
the
fact
that
units
in
these
source
categories
have
not
historically
been
87
required
to
test
for
HAP
emissions.

We
also
considered
using
HAP
emission
limits
contained
in
State
regulations
and
permits
as
a
surrogate
for
actual
emission
data
in
order
to
identify
the
emissions
levels
from
the
best
performing
units
in
the
category
for
purposes
of
establishing
MACT
standards.
However,
we
found
no
State
regulations
or
State
permits
which
specifically
limit
HAP
emissions
from
these
sources.

Consequently,
we
concluded
that
the
most
appropriate
approach
for
determining
MACT
floors
for
boilers
and
process
heaters
is
to
look
at
the
control
options
used
by
the
units
within
each
subcategory
in
order
to
identify
the
best
performing
units.
Information
was
available
regarding
the
emission
control
options
employed
by
the
population
of
boilers
identified
by
the
EPA.
We
considered
several
possible
control
controlstechniques
(
i.
e.,
factors
that
influence
emissions),
including
fuel
substitution,
process
changes
and
work
practices,
and
add­
on
control
technologies.

We
first
considered
whether
fuel
switching
would
be
an
appropriate
control
option
for
sources
in
each
subcategory.

We
considered
the
feasibility
of
both
fuel
switching
to
other
fuels
used
in
the
subcategory
and
to
fuels
from
other
subcategories
were
considered.
This
consideration
included
determining
whether
switching
fuels
would
achieve
lower
HAP
88
emissions.
A
second
consideration
was
whether
fuel
switching
could
be
technically
achieved
by
boilers
and
process
heaters
in
the
subcategory
considering
the
existing
design
of
boilers
and
process
heaters.
We
also
considered
the
availability
of
various
types
of
fuel.
After
considering
these
factors,
we
determined
that
fuel
switching
was
not
an
appropriate
control
technology
for
purposes
of
determining
the
MACT
floor
level
of
control
for
any
subcategory.
This
decision
was
based
on
the
overall
effect
of
fuel
switching
on
HAP
emissions,
technical
and
design
considerations,
and
concerns
about
fuel
availability.

We
also
concluded
that
process
changes
or
work
practices
were
not
appropriate
criteria
for
identifying
the
MACT
floor
level
of
control
for
units
in
the
boilers
and
process
heaters
category.
The
HAP
emissions
from
boilers
and
process
heaters
are
either
fuel
dependent
(
i.
e.,

mercury,
metals,
and
inorganic
HAP)
or
combustion
related
(
i.
e.,
organic
HAP).
Fuel
dependent
HAP
are
typically
controlled
by
removing
them
from
the
flue
gas
after
combustion.
Therefore,
they
are
not
affected
by
the
operation
of
the
boiler
or
process
heater.
Consequently,

process
changes
would
be
ineffective
in
reducing
these
fuelrelated
HAP
emissions.

On
the
other
hand,
organic
HAP
can
be
formed
from
incomplete
combustion
of
the
fuel.
Good
combustion
practice
89
(
GCP),
in
terms
of
boilers
and
process
heaters,
could
be
defined
as
the
system
design
and
work
practices
expected
to
minimize
organic
HAP
emissions.
While
few
sources
in
EPA's
database
specifically
reported
using
good
combustion
practices,
the
data
that
we
have
suggests
that
boilers
and
process
heaters
within
each
subcategory
might
use
any
of
a
wide
variety
of
different
work
practices,
depending
on
the
characteristics
of
the
individual
unit.
The
lack
of
information,
and
lack
of
a
uniform
approach
to
assuring
combustion
efficiency,
is
not
surprising
given
the
extreme
diversity
of
boilers
and
process
heaters,
and
given
the
fact
that
no
applicable
Federal
standards,
and
most
applicable
State
standards,
do
not
include
work
practice
requirements
for
boilers
and
process
heaters.
Even
those
States
that
do
have
such
requirements
do
not
require
the
same
work
practices.
For
example,
CO
emissions
are
generally
a
good
indicator
of
incomplete
combustion,
and,
therefore,
low
CO
emissions
might
reflect
good
combustion
practices.
(
As
discussed
in
the
proposal,
CO
is
considered
a
surrogate
for
organic
HAP
emissions.)
Therefore,
we
considered
whether
existing
CO
emission
limits
might
be
used
to
establish
good
combustion
practice
standards
for
boilers
and
process
heaters.
We
reviewed
State
regulations
applicable
to
boilers
and
process
heaters,
and
then
for
each
subcategory
we
matched
the
applicability
of
State
CO
emission
limits
90
with
information
on
the
locations
and
characteristics
of
the
boilers
and
process
heaters
in
the
population
database.

Ultimately,
we
found
that
very
few
units
(
less
than
6
percent)
in
any
subcategory
were
subject
to
CO
emission
limits.
We
concluded
that
this
information
did
not
allow
EPA
to
identify
a
level
of
performance
that
was
representative
of
good
combustion
across
the
various
units
in
any
subcategory.
Therefore,
we
did
not
establish
a
CO
emission
limit,
as
a
surrogate
for
organic
HAP
emissions,
as
a
part
of
the
MACT
floor
for
existing
units.
However,
we
have
considered
the
appropriateness
of
such
requirements
in
the
context
of
evaluation
possible
beyond­
the­
floor
options.

In
general,
boilers
and
process
heaters
are
designed
for
good
combustion.
Facilities
have
an
economic
incentive
to
ensure
that
fuel
is
not
wasted,
and
the
combustion
device
operates
properly
and
is
appropriately
maintained.
In
fact,

existing
boilers
and
process
heaters
are
used
typically
as
high
efficiency
control
devices
to
control
(
reduce)
emission
streams
containing
organic
HAP
compounds
from
various
process
operations.
Therefore,
EPA's
inability
to
establish
a
combustion
practice
requirement
as
part
of
the
MACT
floor
for
existing
sources
in
this
category
should
not
reduce
the
incentive
for
owners
and
operators
to
run
their
boilers
and
process
heaters
at
top
efficiency.

As
a
result
of
the
evaluation
of
the
feasibility
of
91
establishing
emission
limits
based
on
control
techniques
such
as
fuel
switching
and
good
combustion
practices,
we
concluded
that
add­
on
control
technology
should
be
the
primary
factor
for
purposes
of
identifying
the
best
controlled
units
within
each
subcategory
of
boilers
and
process
heaters.
We
identified
the
types
of
air
pollution
control
techniques
currently
used.
We
ranked
those
controls
according
to
their
effectiveness
in
removing
the
different
HAP
categories
of
pollutants;
including
metallic
HAP
and
PM,

inorganic
HAP
such
as
acid
gases,
mercury,
and
organic
HAP.

We
then
listed
all
the
boilers
and
process
heaters
in
the
population
database
in
order
of
decreasing
control
device
effectiveness
within
each
subcategory
for
each
pollutant
type.
Then
we
identified
the
top
12
percent
of
units
within
each
category
based
on
this
ranking,
and
determined
what
kind
of
emission
control
technology,
or
combination
of
technologies,
the
units
in
the
top
12
percent
employed.

Finally,
we
looked
at
the
emissions
test
data
from
boilers
and
process
heaters
that
used
the
same
control
technology,

or
technologies,
as
the
units
in
the
top
12
percent
to
estimate
the
average
emissions
limitation
achieved
by
the
these
units.

This
approach
reasonably
ensures
that
the
emission
limit
selected
as
the
MACT
floor
adequately
represents
the
average
level
of
control
actually
achieved
by
units
in
the
92
top
12
percent.
The
analysis
of
the
measured
emissions
from
units
representative
of
the
top
12
percent
is
reasonably
designed
to
provide
a
meaningful
estimate
of
the
average
performance,
or
central
tendency,
of
the
best
controlled
12
percent
of
units
in
a
given
subcategory.
For
existing
subcategories
where
less
than
12
percent
of
units
in
the
subcategory
use
any
type
of
control
technology,
we
looked
to
see
if
we
could
estimate
the
central
tendency
of
the
best
controlled
units
by
looking
at
the
unit
occupying
the
median
point
in
the
top
12
percent
(
the
unit
at
the
94th
percentile).
If
the
median
unit
of
the
top
12
percent
is
using
some
control
technology,
we
might
use
the
measured
emission
performance
of
that
individual
unit
as
the
basis
for
estimating
an
appropriate
average
level
of
control
of
the
top
12
percent.
For
subcategories
were
less
than
6
percent
of
the
units
in
a
HAP
grouping
used
controls
or
limited
emissions,
the
median
unit
for
that
HAP
grouping
reflects
no
emissions
reduction.
Therefore,
in
these
circumstances,
EPA
believes
that
it
has
appropriately
established
the
MACT
floor
emission
levels
for
these
sources
as
no
emission
reduction.

Comment:
Many
commenters
opposed
EPA
using
emissions
data
from
units
in
the
large
subcategory
to
develop
emission
limits
for
units
in
the
small
or
limited
use
subcategories.

Some
commenters
stated
that
it
was
not
appropriate
to
assume
93
that
emissions
rates
achievable
by
large
units
are
achievable
by
small
units,
even
the
best
controlled
units.

Other
commenters
argued
that
the
use
of
large
unit
data
in
MACT
determinations
for
other
subcategories
would
defeat
the
purpose
of
the
subcategorization
and
violate
the
requirements
of
CAA
section
112
because
the
use
of
this
data
does
not
represent
sources
in
the
relevant
category
or
subcategory.

Response:
The
EPA
disagrees
with
the
commenters
and
maintains
that
it
has
conducted
the
MACT
floor
analysis
appropriately.
Section
112(
d)
of
the
CAA
requires
us
to
establish
emission
limits
for
new
sources
based
on
the
performance
of
the
best­
controlled
similar
source.
The
CAA
does
not
specify
that
the
similar
source
must
be
within
the
same
source
category
or
subcategory.
To
the
contrary,
our
interpretation
of
section
112(
d)
is
that
we
are
obligated
to
consider
similar
sources
from
other
source
categories
or
subcategories
in
determining
the
best­
controlled
similar
source
for
establishing
MACT
for
new
sources.

For
new
limited
use
and
small
units,
we
concluded
that
the
best­
controlled
similar
sources
are
found
in
the
large
subcategory.
First,
EPA
determined
the
control
technology
used
by
the
best
controlled
sources
in
the
subcategory.
For
example,
only
units
in
the
population
database
less
than
10
MMBtu/
hr
(
and
not
in
the
limited
use
subcategory)
were
used
94
to
determine
the
MACT
floor
control
technology
for
units
in
the
small
subcategories.
Second,
EPA
used
information
in
the
emissions
test
database
to
establish
the
emission
level
associated
with
the
MACT
floor
control
technology.
The
emissions
test
database
did
not
contain
test
data
for
limited
use
or
small
boilers
and
process
heaters.
The
EPA's
interpretation
of
CAA
sSection
112(
d)
allowsrequires
EPA
to
use
information
from
similar
sources
to
set
the
MACT
floor
when
no
information
from.
Such
sources
may
not
be
in
the
same
subcategory
is
available.
Although
the
units
in
the
small
and
limited
use
subcategories
are
different
enough
to
warrant
their
own
subcategory
(
i.
e.,
different
purposes
and
operation),
emissions
of
the
specific
types
of
HAP
for
which
limits
are
being
proposed
are
expected
to
be
related
more
to
the
type
of
fuel
burned
and
the
type
of
control
used,
than
to
unit
operation.
Consequently,
EPA
determined
that
emissions
information
from
large
fuel
fired
units
could
be
used
to
establish
MACT
floor
levels
for
the
small
and
limited
use
subcategories
because
the
fuels
and
controls
are
similar.
The
proposal
preamble
requested
additional
information
from
commenters
to
refine/
revise
the
approach
if
necessary.
No
commenters
provided
emissions
information
for
limited
use
or
small
subcategory
boilers
or
process
heaters.

Comment:
Several
commenters
requested
that
EPA
account
for
variability
in
fuel
composition
as
MACT
floors
are
95
established
and
to
provide
adequate
allowances
for
inherent
fuel
supply
variability.
Some
commenters
argued
that
there
is
no
flexibility
in
the
rule
to
account
for
this
variability
and
noted
that
coal
composition
can
vary
by
location
and
also
within
an
individual
seam.

Response:
As
described
in
the
memorandum
"
Revised
MACT
Floor
Analysis
for
the
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heater
National
Emission
Standards
for
Hazardous
Air
Pollutants
Based
on
Public
Comments"
in
the
docket,
the
calculation
of
numerical
emission
limits
was
a
two­
step
analysis.
The
first
step
involved
calculating
a
numerical
average
of
the
appropriate
subset
of
emission
test
data.
The
second
step
involved
generating
and
applying
an
appropriate
variability
factor
to
account
for
unavoidable
variations
in
emissions
due
to
uncontrollable
variations
in
fuel
characteristics
and
ordinary
operational
variability.
Accounting
for
variability
is
appropriate
in
order
to
generate
a
more
accurate
estimation
of
the
actual,
long
term,
performance
of
a
source
(
e.
g.,
the
source
occupying
the
median
point
in
the
top
12%).
An
emission
test
provides
a
momentary
snapshot,

not
an
estimation
of
continuous
performance.
In
order
to
translate
the
former
into
the
latter,
we
must
account
for
that
ordinary
and
unavoidable
variability
that
the
source
is
like
to
experience
over
time.
This
give
us
a
more
96
reasonable
estimate
of
the
actual
level
of
emissions
control
that
the
unit
is
achieving.
The
EPA
contends
that
by
considering
the
variability
of
emissions
information,
we
have
indirectly
incorporated
variability
in
fuel,
operating
conditions,
and
sampling
and
analytical
conditions
because
these
parameters
vary
from
emission
tests
conducted
from
one
unit
to
another,
and
even
within
each
test
set
of
three
measurements
at
a
single
unit.
The
most
elementary
measure
of
variation
is
range.
Range
is
defined
as
the
difference
between
the
largest
and
smallest
values.
This
is
the
variability
methodology
used
in
the
proposed
rule.
That
is,

for
each
unit
with
multiple
emissions
tests
conducted
over
time,
the
variability
was
calculated
by
dividing
the
highest
three­
run
test
result
by
the
lowest
three­
run
test
result.

The
overall
variability
was
calculated
by
averaging
all
the
individual
unit
variability
factors.
This
overall
variability
factor
was
multiplied
by
the
overall
average
emission
level
to
derive
a
MACT
floor
limit
representative
of
the
average
emission
limitation
achieved
by
the
top
12
percent
of
units.
We
believe
that
this
approach
adequately
accounts
for
inherent
fuel
supply
variability.
Based
on
comments,
EPA
did
conduct
a
more
robust
statistical
analysis
(
t­
test)
of
the
mercury
emissions
data
used
in
the
MACT
floor
analysis
to
identify
the
97.5th
percent
confidence
97
limit.
This
analysis
provided
similar
results
to
the
variability
analysis
conducted
in
the
proposed
rule.

Consequently,
EPA
decided
not
to
change
its
variability
methodology.
A
detailed
discussion
of
the
statistical
analysis
conducted
is
provided
in
the
memorandum
"
Statistical
Analysis
of
Mercury
Test
Data
Variability
in
Response
to
Public
Comments
on
Determination
of
the
MACT
Floor
for
Mercury
Emissions"
in
the
docket.

Comment:
Several
commenters
supported
EPA's
finding
that
the
MACT
floor
level
of
control
for
existing
gasgaseous
and
liquid
fuel­
firedfuel
units
is
no
control.
Other
commenters
contended
that
EPA's
proposed
"
no
control"
as
the
MACT
some
subcategories
is
unlawful.
The
commenters
noted
that
EPA
has
a
clear
statutory
obligation
to
set
emission
standards
for
each
listed
HAP
(
the
commenter
cited
legal
briefs).
One
commenter
specifically
challenged
EPA's
determination
of
the
MACT
floor
for
organic
pollutants.
The
commenter
explained
that
EPA
should
rank
the
units
for
which
emissions
data
is
available
according
to
the
best
performing
units,
not
based
on
the
add­
on
control
level
of
6
percent
of
the
total
population.
The
commenter
noted
that
the
U.
S.

Court
of
Appeals
for
the
D.
C.
Circuit
had
squarely
held,
in
the
National
Lime
case,
that
EPA
was
not
allowed
to
make
a
"
no
control"
determination
for
a
pollutant
emitted
by
a
98
listed
category
of
sources.

Response:
The
EPA
agrees
that
all
factors
which
might
control
HAP
emissions
must
be
considered
in
making
a
floor
determination
for
each
subcategory.
However,
EPA
disagrees
that
it
must
express
the
floor
as
a
quantitative
emission
level
in
those
instances
where
the
sources
on
which
the
floor
determination
is
based
has
not
adopted
or
implemented
any
measure
that
would
reduce
emissions.
For
several
subcategories
and
certain
HAP,
EPA
has
not
identified
any
adjustments
or
other
operational
modifications
that
would
materially
reduce
emissions
by
these
units,
and
EPA
had
determined
that
no
add­
on
controls
are
presently
in
use.
In
these
circumstances,
EPA
feels
that
it
has
established
appropriately
the
MACT
floors
for
these
sources
as
no
emission
reduction.

Comment:
One
commenter
pointed
out
that
the
variability
factor
used
to
make
the
calculated
MACT
floor
less
stringent
is
not
allowed
by
section
112
of
the
CAA.

The
commenter
mentioned
that
the
variability
factors
are
not
consistent,
as
one
factor
considers
the
fuel
variability
and
the
other
factor
considers
the
test
data
variability.

Response:
Section
112(
d)(
2)
of
the
CAA
requires
that
emissions
standards
promulgated
shall
require
the
maximum
degree
of
reduction
in
emissions
that
the
Administrator,

taking
into
consideration
the
costs
of
achieving
such
99
emission
reduction,
determines
is
achievable
for
new
and
existing
sources
in
the
subcategory
to
which
such
emission
standards
applies.
Accounting
for
variability
is
appropriate
in
order
to
generate
a
more
accurate
estimation
of
the
actual,
long
term,
performance
of
a
source
(
e.
g.,
the
source
occupying
the
median
point
in
the
top
12%).
An
emission
test
provides
a
momentary
snapshot,
not
an
estimation
of
continuous
performance.
In
order
to
translate
the
former
into
the
latter,
we
must
account
for
that
ordinary
and
unavoidable
variability
that
the
source
is
like
to
experience
over
time.
This
give
us
a
more
reasonable
estimate
of
the
actual
level
of
emissions
control
that
the
unit
is
achieving.
As
such,
due
to
variations
in
fuel
burned,
and
ordinary
operational
variability
any
emission
limit
set
from
a
point
source
measurement
alone
may
not
be
indicative
of
normal
emissions
or
operations
of
the
unit.

Attempting
to
base
a
standard
(
either
a
floor
standard,
or
a
beyond­
the­
floor
standard)
solely
on
point
measurements
would
lead
to
unachievable
standards
for
all
sources.

Limits
set
by
EPA
must
be
achieved
at
all
times,
and
it
is
important
that
the
MACT
floor
limit
adequately
account
for
the
normal
and
unavoidable
variability
in
the
process
and
in
the
operation
of
the
control
device.

Variability
was
assessed
two
ways.
For
existing
subcategories,
variability
in
emissions
information
was
used
100
to
develop
variability
factors
for
all
subcategories
where
emissions
information
was
available.
Variability
in
fuel
content
was
used
only
in
situations
regarding
determining
the
achievable
MACT
floor
level
for
new
sources
from
the
emission
test
result
on
the
best
controlled
similar
source.

We
believe
this
approach
is
appropriate
since
the
main
uncertainty
associated
with
the
emission
test
result
from
the
best
controlled
similar
source
is
fuel
variability.

Corresponding
fuel
analysis
results
waswere
not
available
for
the
emissions
test
results
from
the
best
controlled
similar
source.
Whereas,
the
average
emission
level
of
the
best
12
percent
of
the
units
has,
besides
fuel
variability,

the
uncertainty
associated
with
operational
and
design
variability
of
the
various
control
devices
installed
on
units
that
represent
the
best
12
percent
of
the
units.
For
example,
available
fuel
analysis
information
shows
that
mercury
content
of
coal
varies
by
a
factor
of
12.54.

Dividing
the
highest
mercury
emission
test
result
by
the
lowest
mercury
test
results
from
coal­
fired
units
included
in
units
that
represent
the
best
12
percent
results
in
a
variability
factor
of
20.
Therefore,
we
concluded
that
fuel
availability
was
inherently
considered
in
the
MACT
floor
analysis
approach
used
for
existing
subcategories.

Comment:
Many
commenters
requested
that
EPA
revise
the
MACT
floor
methodology
for
mercury
emission
limits.
The
101
commenters
contended
that
the
variability
factor
was
calculated
inappropriately.
Other
commenters
stated
that
EPA
should
account
for
variability
in
fuel
composition
in
the
MACT
floor
analysis.
Other
commenters
expressed
concern
that
the
floor
level
of
control
was
based
on
fabric
filters,

which
has
not
been
proven
at
all
sources
to
reduce
mercury.

Response:
As
discussed
in
the
proposal
preamble,
the
MACT
floor
analysis
for
mercury
was
based
on
a
two
step
process.
First
the
percentage
of
units
with
control
technologies
that
could
achieve
mercury
emissions
reductions
was
determined
using
the
boiler
population
databases.
If
the
control
technology
analysis
indicated
that
at
least
12
percent
of
sources
in
the
subcategory
used
a
control
device
that
could
achieve
mercury
emissions
reductions,
then
the
control
technology
present
at
the
median
(
6th
percentile)
was
identified
as
the
MACT
floor
control
technology.
The
MACT
floor
level
of
control
for
mercury
was
identified
as
a
fabric
filter.
The
control
effectiveness
of
fabric
filters
was
based
on
emissions
information
for
utility
boilers
that
indicated
that
mercury
emissions
reductions
were
being
achieved
with
this
technology.
In
this
case,
we
could
use
control
efficiency
information
from
another
similar
source
category
to
supplement
the
information
available
in
this
source
category
because
of
the
similarity
in
fuel
burned,

combustor
type,
and
control
methodology
and
operation.
We
102
maintain
that
fabric
filters
are
still
the
appropriate
level
of
control
for
the
MACT
floor.

Second,
the
emission
limit
associated
with
the
MACT
floor
control
technology
was
calculated
using
emissions
information
for
units
in
the
subcategory,
whenever
possible.

For
most
of
the
subcategories
developed,
emissions
information
was
adequate.
Only
for
the
emission
limit
for
new
source
liquids
and
the
variability
factor
for
new
source
solids
was
fuel
pollutant
content
incorporated
into
the
MACT
floor
analyses.
The
mercury
fuel
content
of
coal
from
the
utility
industry
was
used
in
developing
the
variability
factors
for
new
solid
fired
units.
This
was
done
because
mercury
emissions
are
dependent
on
the
quantity
of
mercury
in
the
fuel
burned.
Coal
available
to
utilities
and
industrial
boilers
and
process
heaters
is
expected
to
be
similar,
and
coal
is
the
solid
fuel
that
is
routinely
used
in
such
units
that
has
generally
the
greatest
degree
of
HAP
variability.
We
maintain
that
the
utility
database
used
at
proposal
to
develop
the
variability
factor
for
new
sources
was
adequate
in
establishing
the
MACT
floor
emission
limit.

The
EPA
recognizes
that
the
mercury
emissions
database
for
industrial
boilers
is
limited.
However,
EPA
is
directed
by
the
CAA
to
develop
standards
for
sources
using
whatever
data
is
available.
Prior
to
proposal
and
during
the
Industrial
Combustion
Coordinated
Rulemaking
(
ICCR)
process,
103
EPA
conducted
a
thorough
search
for
HAP
emission
test
reports.
This
search
was
supported
by
industry,
trade
groups,
and
States.
For
criteria
pollutants,
such
as
PM,

substantial
emission
information
was
available
and
gathered.

For
mercury
and
other
HAP,
this
was
not
the
case.

Industrial
boilers
have
not
generally
been
required
to
test
for
HAP
emissions.
In
the
proposed
rule,
EPA
requested
commenters
to
provide
additional
emissions
information.

However,
only
one
source
provided
any
additional
mercury
emissions
data.
This
information
(
test
results
from
three
additional
coal­
fired
industrial
boilers)
was
used
to
revise
the
mercury
emission
limit
for
existing
sources.
We
also
reviewed
the
mercury
emission
database
used
to
develop
the
MACT
floor
emission
limit
for
existing
sources.
After
review,
we
determined
that
a
revision
to
the
variability
factor
was
appropriate.
The
additional
data
and
the
revised
variability
factor
was
used
to
re­
calculate
the
mercury
emission
limit
to
be
0.000009
lb/
MMBtu
(
from
0.000007
lb/
MMBtu
at
proposal).
A
detailed
discussion
of
the
revised
MACT
floor
analysis
conducted
is
provided
in
the
memorandum
"
Revised
MACT
Floor
Analysis
for
the
Industrial,
Commercial,

and
Institutional
Boilers
and
Process
Heaters
National
Emission
Standards
for
Hazardous
Air
Pollutants
Based
on
Public
Comments"
in
the
docket.

Variability
of
the
emissions
data
were
incorporated
104
into
the
final
emission
limits.
The
EPA
contends
that
by
considering
the
variability
of
emissions
information,
we
have
indirectly
incorporated
variability
in
fuel,
operating
conditions,
and
sampling
and
analytical
conditions
because
these
parameters
vary
from
emission
tests
conducted
from
one
unit
to
another,
and
even
within
one
unit.
The
EPA
does
not
consider
it
appropriate
or
feasible
to
incorporate
variability
from
a
multitude
of
parameters
because
such
information
is
not
available
and
cannot
be
correlated
to
the
emissions
information
in
the
emissions
test
database.
For
the
final
rule,
EPA
did
conduct
a
statistical
analysis
of
the
data
to
identify
the
97.5th
percent
confidence
interval.

This
analysis
provided
similar
results
to
the
variability
analysis
conducted
in
the
proposed
rule.
Consequently,
EPA
decided
not
to
change
its
variability
methodology.
A
detailed
discussion
of
the
statistical
analysis
conducted
is
provided
in
the
memorandum
"
Statistical
Analysis
of
Mercury
Test
Data
Variability
in
Response
to
Public
Comments
on
Determination
of
the
MACT
Floor
for
Mercury
Emissions"
in
the
docket.

Comment:
Several
commenters
contended
that
the
California
standards
which
the
CO
requirements
are
based
on
do
not
require
CO
CEMS,
but
require
initial
compliance
testing
and
periodic
subsequent
performance
testing.

Response:
The
commenters
are
correct
that
the
105
California
CO
regulations
do
not
require
CO
CEMS.
The
regulations
do
provide
sources
with
the
option
of
conducting
annual
testing
or
installing
CO
CEMS
to
demonstrate
compliance
with
the
CO
emission
limit.
Because
the
regulations
that
were
the
basis
of
the
MACT
floor
do
not
provide
specifics
on
which
boilers
should
conduct
annual
testing
and
which
should
use
CO
CEMS,
we
reviewed
the
cost
information
provided
by
the
commenters
to
make
this
determination.
In
considering
the
additional
cost
information
and
reviewing
the
cost
information
used
in
the
proposed
rule,
the
EPA
decided
that
changes
to
the
CO
compliance
requirements
were
warranted.
The
final
rule
requires
that
new
units
with
heat
input
capacities
less
than
100
MMBtu/
hr
conduct
initial
and
annual
performance
tests
for
CO
emissions.
New
units
with
heat
input
capacities
greater
or
equal
to
100
MMBtu/
hr
are
still
required
to
install,
operate,
and
maintain
a
CO
CEM.

Regardless
of
whether
the
California
regulations
do
or
do
not
require
CO
CEMS,
we
would
have
reviewed
the
need
for
continuous
monitoring
and
operating
limits
in
order
to
ensure
the
most
accurate
indication
of
proper
operation
of
the
control
system.
The
purpose
of
all
of
the
minimum
operating
parameter
limits
in
the
standard
is
to
ensure
continuous
compliance
by
ensuring
that
the
air
pollution
control
equipment
is
operating
as
they
were
during
the
106
latest
performance
test
demonstrating
compliance
with
the
emission
limits.
The
operating
parameters
are
established
as
"
minimum"
to
provide
enforceable
boundaries
in
their
operation.
Operating
outside
the
bounds
of
the
minimum
parameters
may
lead
to
increased
air
emissions.

The
EPA
would
also
like
to
clarify
that
operation
above
the
CO
limit
constitutes
a
deviation
of
the
work
practice
standard.
However,
the
determination
of
what
deviations
constitute
violations
of
the
standard
is
up
to
the
discretion
of
the
entity
responsible
for
enforcement
of
the
standards.

F.
Beyond
the
MACT
Floor
Comment:
Many
commenters
contended
that
carbon
injection
should
have
been
required
as
an
beyond­
the­
floor
option.
Other
commenters
supported
EPA's
decision
to
not
require
any
controls
beyond­
the­
floor.

Response:
For
the
final
rule,
EPA
maintains
that
options
beyond
the
MACT
floor
are
not
appropriate
for
the
standard.
The
EPA
is
required
by
the
CAA
to
set
the
standard
at
a
minimum
on
the
best
controlled
12
percent
of
sources
(
for
existing
units)
or
best
controlled
similar
source
(
for
new
units).
The
CAA
also
requires
EPA
to
consider
costs
and
non­
air
quality
impacts
and
energy
requirements
when
considering
more
stringent
requirements
than
the
MACT
floor.
As
documented
in
the
memorandum
107
"
Methodology
for
Estimating
Costs
and
Emissions
Impacts
for
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
National
Emission
Standards
for
Hazardous
Air
Pollutants"
in
the
docket,
EPA
did
consider
the
cost
and
emission
impacts
of
a
variety
of
regulatory
options
more
stringent
than
the
MACT
floor
for
each
subcategory.
The
EPA
recognizes
that
for
some
subcategories,
more
stringent
controls
than
the
MACT
floor
can
be
applied
and
achieve
additional
emission
reductions.
However,
EPA
also
determined
that
the
cost
impacts
of
such
controls
were
very
high.
Considering
both
the
costs
and
emission
reductions,

EPA
determined
that
it
would
be
infeasible
to
require
any
options
more
stringent
than
the
floor
level.

For
the
final
rule,
EPA
maintains
that
carbon
injection
should
not
be
required
as
an
above
the
floor
technology.
As
discussed
in
the
proposal
preamble,
we
identified
one
existing
industrial
boiler
that
was
using
carbon
injection.

The
emissions
data
that
we
obtained
from
the
boiler
indicated
that
this
carbon
injection
unit
was
not
achieving
mercury
emissions
reductions.
This
result
led
us
to
conclude
that
it
was
not
the
new
source
floor
level
of
control.
However,
there
may
have
been
other
reasons
for
the
ineffectiveness
of
this
system
(
e.
g.,
low
inlet
mercury
levels,
insufficient
carbon
injection
rate,
ESP
instead
of
fabric
filter
for
PM
control).
Therefore,
we
considered
108
carbon
injection
as
a
beyond­
the­
floor
option,
but
decided
that
while
this
control
technique
has
been
used
in
other
source
categories,
there
is
no
demonstrated
evidence
that
it
would
work
for
industrial
boilers
and
process
heaters
because
the
type
of
mercury
emitted
and
properties
of
the
emission
streams
are
sufficiently
different
for
boilers
and
process
heaters
and
other
source
categories.
For
fabric
filters,
we
had
some
emissions
information
for
utility
boilers
that
indicated
that
mercury
emissions
reductions
were
being
achieved
with
this
technology.
In
this
case,
we
could
confidently
use
control
efficiency
information
from
another
similar
source
category
to
supplement
the
information
available
in
this
source
category.
Unlike
fabric
filters,
the
available
emissions
information
indicated
that
carbon
injection
was
not
effective
for
industrial
boilers
and
process
heaters.

G.
Work
Practice
Requirements
Comment:
Many
commenters
requested
EPA
consider
exceedences
of
the
CO
limit
to
be
a
trigger
for
corrective
action
rather
than
a
violation.

Response:
In
the
final
rule,
we
have
clarified
that
an
exceedence
of
the
CO
limit
constitutes
a
deviation
of
the
work
practice
standard.
An
observed
exceedence
of
a
monitoring
parameter
is
not
an
automatic
violation.
You
are
required
to
report
any
deviation
from
an
applicable
emission
109
limitation
(
including
operating
limit).
We
will
review
the
information
in
your
report
along
with
other
available
information
to
determine
if
the
deviation
constitutes
a
violation.
The
determination
of
what
emission
or
operating
limit
deviation
constitutes
violations
of
the
standard
is
up
to
the
discretion
of
the
entity
responsible
for
enforcement
of
the
standard.

H.
Compliance
Comment:
Many
commenters
requested
that
EPA
simplify
and
write
the
fuel
monitoring
requirements
to
not
require
retesting
of
fuel
for
changes
in
fuel
supplier.

Response:
We
agree
that
the
fuel
monitoring
requirements
in
the
proposal
needed
to
be
clarified
and
explained
further.
Therefore,
we
have
clarified
the
fuel
analysis
options
in
the
final
rule.
If
you
elect
to
demonstrate
compliance
with
the
HCl,
mercury,
or
total
selected
metals
limit
by
using
fuel
which
has
a
statistically
lower
pollutant
content
than
the
emission
limit,
then
your
operating
limit
is
the
emission
limit
of
the
applicable
pollutant.
Under
this
option,
you
are
not
required
to
conduct
performance
tests
(
i.
e.
stack
tests).

If
you
demonstrate
compliance
with
the
HCl,
mercury,
or
total
selected
metals
limit
by
using
fuel
with
a
statistically
higher
pollutant
content
than
the
applicable
emission
limit,
but
performance
tests
demonstrate
that
you
110
can
meet
the
emission
limits,
then
your
operating
limits
are
the
operating
limits
of
the
control
device
(
if
used)
and
the
fuel
pollutant
content
of
the
fuel
type/
mixture
burned.

The
final
rule
specifies
the
testing
methodology
and
procedures
and
the
initial
and
continuous
compliance
requirements
to
be
used
when
complying
with
the
fuel
analysis
options.
Fuel
analysis
tests
for
total
chloride,

gross
calorific
value,
mercury,
metal
analysis,
sample
collection,
and
sample
preparation
are
included
in
the
final
rule.

If
you
elect
to
comply
based
on
fuel
analysis,
you
are
required
to
statistically
analyze,
using
the
z­
test,
the
data
to
determine
the
90th
percentile
confidence
level.
It
is
the
90th
percentile
confidence
level
that
is
required
to
be
used
to
determine
compliance
with
the
applicable
emission
limit.
The
statistical
approach
is
required
to
assist
in
ensuring
continuous
compliance
by
statistically
accounting
for
the
inherent
variability
in
the
fuel
type.

You
are
required
to
recalculate
the
fuel
pollutant
content
only
if
you
burn
a
new
fuel
type
or
fuel
mixture.

You
are
required
to
conduct
another
performance
test
if
you
demonstrate
compliance
through
performance
testing,
you
burn
a
new
fuel
type
or
mixture,
and
the
results
of
recalculating
the
fuel
pollutant
content
are
higher
than
the
level
established
during
the
initial
performance
test
111
Comment:
Many
commenters
requested
EPA
consider
exceedences
of
parametric
limits
to
be
a
trigger
for
corrective
action
rather
than
a
violation.

Response:
In
the
final
rule,
we
have
clarified
than
an
exceedence
of
the
parametric
limits
constitute
a
deviation
of
the
operating
limits.
An
observed
exceedence
of
a
monitoring
parameter
is
not
an
automatic
violation.
You
are
required
to
report
any
deviation
from
an
applicable
emission
limitation
(
including
operating
limit).
We
will
review
the
information
in
your
report
along
with
other
available
information
to
determine
if
the
deviation
constitutes
a
violation.
The
determination
of
what
emission
or
operating
limit
deviation
constitutes
violations
of
the
standard
is
up
to
the
discretion
of
the
entity
responsible
for
enforcement
of
the
standard.

Comment:
Many
commenters
requested
EPA
revise
the
opacity
requirements.
Commenters
objected
to
the
provision
in
the
proposed
NESHAP
that
would
establish
an
opacity
"
operating
limit"
based
on
the
initial
performance
test.

Some
commenters
contended
that
EPA
has
provided
no
data
or
references
demonstrating
a
relationship
between
opacity
and
particulate,
total
metals,
or
mercury
emissions.
Other
commenters
argued
that
the
proposed
opacity
limit
approach
for
dry
control
devices
is
unworkable
due
to
the
inherent
inability
of
continuous
opacity
monitors
(
COMS)
to
112
accurately
measure
opacity
at
levels
less
than
10
percent.

Some
commenters
argued
that
the
performance
and
opacity
achieved
during
the
initial
test
may
not
be
representative
of
the
unit's
performance.
Other
commenters
explained
that
equipment
condition,
fuel
and
operating
variations,
and
other
uncontrollable
parameters
may
result
in
varying
emissions
and
emissions
control
equipment
efficiencies
over
time.
Commenters
suggested
requiring
the
NSPS
limits
for
opacity
rather
than
setting
opacity
based
on
the
initial
compliance
test.

Response:
We
have
reviewed
the
information
provided
by
the
commenters,
and
agree
that
the
opacity
operating
limit
requirements
in
the
proposed
rule
are
not
appropriate
for
this
source
category.
Because
of
the
variability
in
fuels
burned,
the
combination
of
fuels
burned,
and
the
typical
operation
of
boilers
and
process
heaters,
we
have
decided
that
an
opacity
limit
set
based
on
the
initial
performance
test
may
not
be
representative
of
the
units
typical
performance.

To
demonstrate
continuous
compliance
byWe
have
revised
the
opacity
operating
limit,
the
final
rule
provides
two
options.
As
the
commenters
suggested,
provision
by
requiring
existing
units
canto
maintain
opacity
to
less
than
or
equal
to
20
percent
(
based
on
6­
minute
averages)
except
for
one
6­
minute
period
per
hour
of
not
more
than
27
113
percent.
This
is
the
opacity
limit
contained
in
the
current
NSPS
for
industrial
boilers,
which
has
a
similar
PM
emission
limit
as
the
final
rule.
Therefore,
it
was
determined
that
it
was
appropriate
to
include
a
similar
opacity
level
as
the
control
device
operating
limit
for
existing
units.
New
sources
can
maintain
their
opacity
operating
limit
to
less
than
or
equal
to
10
percent
(
based
on
1­
hour
block
averages).
This
level
appears
to
be
the
lowest
opacity
level
currently
applicable
to
industrial
boilers
in
State
regulations.

Comment:
Several
commenters
objected
to
the
requirement
to
conduct
performance
testing
at
worst
case
conditions.
The
commenters
found
this
requirement
to
be
unrealistic
because
stack
testing
must
be
scheduled
well
in
advance
and
worst­
case
conditions
depend
on
fuel,
load,
and
many
other
variables,
making
it
impossible
to
assure
that
the
testing
will
occur
during
worst­
case
conditions.
Two
commenters
contended
there
can
be
no
guarantee
that
mineral
properties
for
a
fuel
source
at
the
time
of
the
baseline
test
can
be
guaranteed
beyond
the
content
identified
during
purchase
contract
negotiations
with
a
fuel
supplier.
Two
commenters
suggested
that
EPA
define
what
worst
case
conditions
are
because
sources
do
not
have
the
experience
to
determine
worst­
case
representative
process
conditions.

Response:
We
agree
that
more
direction
and
114
clarification
is
needed
regarding
testing
at
worst
case
conditions.
We
have
modified
fuel
sampling
requirements
and
performance
testing
fuel
use
requirements
to
simplify
compliance.
During
performance
testing,
sources
are
required
to
burn
the
type
of
fuel
or
mixture
of
fuel
types
that
have
the
highest
concentration
of
regulated
HAP.
This,

in
combination
with
revised
fuel
sampling
requirements
(
e.
g.,
based
on
fuel
type
and
not
on
supplier,
etc),
will
simplify
the
determination
of
the
fuel
blend
during
the
performance
test.
Sources
are
also
required
to
conduct
performance
tests
under
representative
full
load
operating
conditions.

Comment:
Several
commenters
objected
to
the
requirement
for
annual
performance
tests
because
they
felt
that
it
is
overly
burdensome
given
the
ongoing
compliance
demonstrations
required
by
the
boiler
NESHAP.
Several
commenters
suggested
that
initial
performance
testing
should
be
required
with
subsequent
performance
testing
occurring
every
3
to
5
years.
Some
commenters
stated
that
5­
year
test
intervals
are
consistent
with
title
V
permits
and
have
been
allowed
in
other
MACT
standards
(
e.
g.
Hazardous
Waste
Combustors).

Response:
We
have
worked
to
minimize
the
testing
and
monitoring
requirements
of
the
final
rule
while
retaining
the
ability
to
ensure
compliance
with
the
emission
limits
115
and
work
practice
requirements.
We
are
providing
an
option
for
sources
to
conduct
performance
testing
once
every
3
years
if
they
conduct
successful
performance
testing
for
3
consecutive
years.
We
are
also
allowing
sources
to
demonstrate
compliance
with
the
HCl,
mercury,
and
total
selected
metals
emission
limits
through
fuel
testing
if
they
do
not
need
emission
control
devices
to
achieve
the
standard.

I.
Emissions
Averaging
In
the
proposal
preamble,
we
solicited
comments
on
an
emissions
averaging
or
bubbling
compliance
alternative,
as
part
of
the
EPA's
general
policy
of
encouraging
the
use
of
flexible
compliance
approaches
where
they
can
be
properly
monitored
and
enforced,
and
whether
EPA
should
include
emissions
averaging
in
the
final
rule.
Emissions
averaging
can
provide
sources
the
flexibility
to
comply
in
the
least
costly
manner
while
still
maintaining
regulation
that
is
workable
and
enforceable.
We
requested
comment
on
an
averaging
approach
for
determining
compliance
with
the
nonmercury
metallic
HAP,
HCl,
mercury,
and/
or
PM
standards
for
existing
sources.
We
indicated
that
averaging
would
allow
owners
and
operators
to
submit
non­
mercury
metals,
mercury,

HCl,
and/
or
PM
emissions
limits
to
the
Administrator
for
approval
for
each
existing
boiler
in
the
averaging
group
such
that
if
these
emission
limits
are
met,
the
total
116
emissions
from
all
existing
boilers
in
the
averaging
group
are
less
than
or
equal
to
emission
limits
(
for
non­
mercury
metals,
mercury,
HCl,
or
PM)
applicable
to
units
in
the
particular
subcategory.
We
indicated
also
that
averaging
would
not
be
applicable
to
new
sources
and
could
only
be
used
between
boilers
and
process
heaters
in
the
same
subcategory.
Also,
owners
or
ownersoperators
of
existing
sources
subject
to
the
Industrial
Boiler
New
Source
Performance
Standards
(
NSPS)
(
40
CFR
60,
subparts
Db
and
Dc)

would
be
required
to
continue
to
meet
the
PM
emission
standard
of
that
NSPS
regardless
of
whether
or
not
they
are
averaging.

Emissions
averaging
has
been
incorporated
into
the
final
rule
as
a
means
of
complying
with
subpart
DDDDD.

Emissions
averaging
allows
an
individual
sourceaffected
unit
emitting
above
the
allowable
emission
limit
required
by
subpart
DDDDD
to
comply
with
that
emission
limit
by
averaging
its
emissions
with
other
a
second
sourceffected
units
at
the
same
facility
emitting
below
the
allowable
emission
limit
required
by
subpart
DDDDD.

Comment:
Many
commenters
supported
including
averaging
in
the
final
rule.
Commenters
cited
numerous
reasons,

including
cost
effectiveness,
energy
efficiency,
greater
flexibility
in
compliance,
and
greater
environmental
benefit.
Commenters
also
cited
40
CFR
part
63,
subpart
MM,
117
Pulping
Chemical
Recovery
Combustion
MACT
as
a
precedent
for
including
emissions
averaging
in
MACT
standards.
Two
commenters
disagreed
with
allowing
emissions
averaging,

stating
that
it
would
complicate
compliance
determinations,

does
not
fit
within
the
CAA
mandate,
and
is
inconsistent
with
the
purpose
of
CAA
section
112.
Many
of
those
commenters
who
supported
emissions
averaging
recommended
additional
flexibility,
such
as
including
new
units,
and
bubbling
across
subcategories.

Response:
The
final
rule
includes
an
emissions
averaging
compliance
alternative
because
we
believe
that
emissions
averaging
represents
an
equivalent,
more
flexible,

and
less
costly
alternative
to
controlling
certain
emission
points
to
MACT
levels.
We
have
concluded
that
a
limited
form
of
averaging
could
be
implemented
and
not
lessen
the
stringency
of
the
standard.
We
agree
with
the
commenters
that
some
type
of
emissions
averaging
would
provide
flexibility
in
compliance,
cost
and
energy
savings
to
owners
and
operators.
We
also
recognize
that
we
must
ensure
that
any
emissions
averaging
option
can
be
implemented
and
enforced,
will
be
clear
to
sources,
and
most
importantly,

will
achieve
no
less
emissions
reductions
than
unit
by
unit
implementation
of
the
MACT
requirements.

The
final
rule
is
not
the
first
NESHAP
to
include
provisions
permitting
emission
averaging.
The
emissions
118
averaging
provisions
in
the
final
rule
are
based
in
part
on
the
emissions
averaging
provisions
in
the
Hazardous
Organic
NESHAP
(
HON).
The
legal
basis
and
rationale
for
the
HON
emissions
averaging
provisions
were
provided
in
the
preamble
to
the
final
HONHazardous
Organic
NESHAP
(
59
FR
19425,
April
22,
1994).
In
general,
EPA
has
concluded
that
it
is
permissible
to
establish
within
a
NESHAP
a
unified
compliance
regimen
that
permits
averaging
across
affected
units
subject
to
the
standard
under
certain
conditions.

Averaging
across
affected
units
is
permitted
only
if
it
can
be
demonstrated
that
the
total
quantity
of
any
particular
HAP
that
may
be
emitted
by
that
portion
of
a
contiguous
major
source
that
is
subject
to
the
NESHAP
will
not
be
greater
under
the
averaging
mechanism
than
it
would
be
if
each
individual
affected
unit
complied
separately
with
the
applicable
standard.
Under
this
rigorous
test,
the
practical
outcome
of
averaging
is
equivalent
in
every
respect
to
compliance
by
the
discrete
units,
and
the
statutory
policy
embodied
in
the
MACT
floor
provisions
is,

therefore,
fully
effectuated.

The
EPA
has
generally
imposed
certain
limits
on
the
scope
and
nature
of
emissions
averaging
programs.
These
limits
include:
(
1)
no
averaging
between
different
types
of
pollutants,
(
2)
no
averaging
between
sources
that
are
not
part
of
the
same
major
source,
(
3)
no
averaging
between
119
sources
within
the
same
major
source
that
are
not
subject
to
the
same
NESHAP,
and
(
4)
no
averaging
between
existing
sources
and
new
sources.

The
final
rule
fully
satisfies
each
of
these
criteria.

Accordingly,
EPA
has
concluded
that
the
averaging
of
emissions
across
affected
units
permitted
by
the
final
rule
is
consistent
with
the
CAA.
In
addition,
EPA
notes
that
the
provision
in
the
final
rule
that
requires
each
facility
that
intends
to
utilize
emission
averaging
to
submit
an
emission
averaging
plan
provides
additional
assurance
that
the
necessary
criteria
will
be
adhered
tofollowed.
In
this
emission
averaging
plan,
the
facility
must
include
the
identification
of
(
1)
all
units
in
the
averaging
group,
(
2)

the
control
technology
installed,
(
3)
the
process
parameter
that
will
be
monitored,
(
4)
the
specific
control
technology
or
pollution
prevention
measure
to
be
used,
(
5)
the
test
plan
for
the
measurement
of
particulate
matter
(
or
selected
total
metals),
hydrogen
chloride,
or
mercury
emissions,
and
(
6)
the
operating
parameters
to
be
monitored
for
each
control
device.
Upon
receipt,
the
regulatory
authority
will
not
approve
an
emission
averaging
plan
containing
averaging
between
emissions
of
different
types
of
pollutants
or
between
sources
in
different
subcategories.

The
rationale
for
including
certain
limitationsprovisions
and
requirements
as
part
of
today's
120
emissions
averaging
provisions
generally
follows
the
HON
andcompliance
alternative
is
summarized
below.

The
final
rule
excludes
new
affected
sources
from
the
emissions
averaging
provision.
New
sources
have
historically
been
held
to
a
stricter
standard
than
existing
sources
because
it
is
most
cost
effective
to
integrate
state­
of­
the­
art
controls
into
equipment
design
and
to
install
the
technology
during
construction
of
new
sources.

One
reason
we
allow
emissions
averaging
is
to
give
existing
sources
flexibility
to
achieve
compliance
at
diverse
points
with
varying
degrees
of
add­
on
control
already
in
place
in
the
most
cost­
effective
and
technically
reasonable
fashion.

This
concern
does
not
apply
to
new
sources
which
can
be
designed
and
constructed
with
compliance
in
mind.

Only
existing
large
solid
fuel
units
that
are
part
of
the
affected
source
(
collection
of
existing
boilers
and
process
heaters),
as
defined
in
the
final
rule,
can
be
included
in
anthe
emissions
averageaveraging
compliance
alternative.
Of
the
nine
subcategories
established
for
existing
sources,
existing
large
solid
fuel
units
is
the
only
subcategory
for
which
multiple
HAP
emissions
limits
apply.
For
the
existing
small
solid
fuel
subcategory
and
the
six
existing
gaseous
and
liquid
fuel
subcategories,
no
HAP
emissions
limits
are
included
in
the
final
rule
and,

thus,
it
would
not
be
appropriate
to
includeallow
these
121
units
in
anto
average
emissions
average.
As
for
the
existing
limited
use
solid
fuel
subcategory,
since
these
units,
as
defined
in
the
final
rule,
operated
on
a
limited
basis
(
capacity
factor
of
less
than
10
percent)
and
are
subject
only
to
a
less
stringent
PM
emissions
limit
(
as
a
surrogate
for
non­
mercury
metals),
we
believe
it
would
be
inappropriate
to
include
these
units
in
emissions
averaging
with
units
in
the
existing
large
solid
fuel
subcategory.

For
purposes
of
emission
averaging,
we
are
allowing
a
source
that
elects,
after
the
effective
date
of
the
rule,
to
modify
an
existing
large
solid
fuel
boiler
in
the
identified
averaging
group
by
fuel
substitution,
such
that
its
applicable
subcategory
would
change,
to
choose
to
remain
in
the
original
subcategory
and
continue
to
meet
the
applicable
emission
limits
in
this
subpart
for
existing
large
solid
fuel
units.
allow
these
units
to
average
emissions.

For
existing
large
solid
fuel
units,
one
control
techniques
available,
under
certain
circumstances,
for
complying
with
the
emission
limits
in
the
final
rule
is
fuel
substitution.
IHowever,
if
a
facility
elected
to
convert
an
existing
large
solid
fuel
unit
over
to
100
percent
natural
gas
firing,
in
order
to
comply
with
the
emissions
limits
for
existing
large
solid
fuel
units,
the
unit
would
effectively
change
from
being
in
the
existing
large
solid
fuel
subcategory
to
being
in
the
existing
large
gaseous
fuel
122
subcategory.
Fuel
substitution
is
more
likely
to
be
applied
to
comply
with
the
final
rule
if
allowed
under
the
emissions
averaging
compliance
alternative.
UIf
allowed
under
emission
averaging,
a
facility
with
more
than
one
large
solid
fuel
unit
may
determine
it
is
more
advantageous
to
switch
one
existing
large
solid
fuel
unit
to
natural
gas
than
install
additional
controls
on
eachanother
of
their
existing
large
solid
fuel
units
in
order
to
comply
with
the
final
rule.
Therefore,
for
purposes
of
emission
averaging,

we
are
allowing
a
source
that
elects,
after
the
effective
date
of
the
rule,
to
modify
an
existing
large
solid
fuel
boiler
by
fuel
substitution
to
remain
in
its
original
subcategory
and
continue
to
meet
the
applicable
emission
limits
for
existing
large
solid
fuel
units.
We
believe
including
this
provision
in
the
emissions
averaging
compliance
alternative
is
appropriate
since
fuel
substitution
is,
in
certain
situations,
a
potential
and
available
pollution
prevention
control
technique
for
an
existing
large
solid
fuel
unit
to
comply
with
the
emission
limits.
This
provision
would
be
an
incentive
for
switching
to
a
less
polluting
fuel
and,
thus,
would
result
in
additional
benefit
to
the
environment
by
reducing
other
pollutants
of
concerns
(
i.
e.,
sulfur
dioxide
and
nitrogen
oxide).

In
the
MACT
floor
analysis
conducted,
we
considered
123
several
possible
control
techniques
including
fuel
substitution,
but,
for
the
reasons
summarized
below
and
discussed
in
detail
in
the
memorandum
"
MACT
Floor
Analysis
for
the
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
National
Emission
Standards
for
Hazardous
Air
Pollutants"
located
in
the
docket,
we
decided
that
fuel
substitution
is
not
an
appropriate
criteria
for
identifying
the
MACT
floor
level
of
control
for
the
boilers
and
process
heaters
category.
We
first
considered
whether
fuel
switching
would
be
an
appropriate
control
option
for
sources
in
each
subcategory.
We
considered
the
feasibility
of
both
fuel
switching
to
other
fuels
used
in
the
subcategory
and
to
fuels
from
other
subcategories.
This
consideration
included
determining
whether
switching
fuels
would
achieve
lower
HAP
emissions.
A
second
consideration
was
whether
fuel
switching
could
be
technically
achieved
by
boilers
and
process
heaters
in
the
subcategory
considering
the
existing
design
of
boilers
and
process
heaters.
We
also
considered
the
availability
of
various
types
of
fuel.
After
considering
these
factors,
we
determined
that
fuel
switching,
while
a
potential
pollution
prevention
technique
in
certain
situations,
was
not
an
universally
appropriate
control
technology
for
purposes
of
determining
the
MACT
floor
level
of
control
for
any
subcategory.
This
decision
was
based
on
the
overall
effect
of
fuel
switching
on
HAP
124
emissions,
technical
and
design
considerations
and
concerns
about
fuel
availability.

As
for
comments
regarding
the
inclusion
of
new
units
in
the
emissions
averaging,
as
stated
previously,
no
averaging
can
be
permitted
between
existing
sources
and
new
sources
since
new
sources
have
historically
been
held
to
a
stricter
standard
than
existing
sources.
However,
the
final
rule
takes
a
different
approach
regarding
new
large
gaseous
fuel
units
that
are
replacements
for
existing
large
solid
fuel
units.
We
believe
it
is
appropriate
to
allow
a
source,

having
access
to
an
adequate
supply
of
natural
gas,
that
elects
to
comply
with
the
emission
limits
for
an
existing
large
solid
fuel
unit
by
replacing
theat
unit
with
a
new
gaseous
fuel
unit.
This
situation
is
similar
to
the
fuel
substitution
situation
previously
discussed.
In
this
case,

the
source
may
determine
that
it
is
more
advantageous
to
permanently
shutdown
an
existing
large
solid
fuel
unit
and
replace
it
with
a
new
gaseous
fuel
unit
instead
of
just
converting
the
existing
large
solid
fuel
unit
over
to
100
percent
natural
gas
firing.
A
new
gas­
fired
unit
would
be
a
more
efficient
steam
generator
that
a
solid
fuel
designed
unit
converted
to
gas
firing.
Under
the
emission
averaging
provision,
the
source
would
be
allowed
to
continue,
in
effect,
to
include
in
the
emission
averaging
the
existing
large
solid
fuel
unit
that
is
permanently
shutdown
and
125
replaced
after
the
effective
date
of
the
final
rule.
The
contribution
of
this
permanently
shutdown
unit
in
the
emission
averaging
is
based
on
the
heat
input
(
or
steam
production)
of
the
new
gaseous
unit
(
up
to
the
rated
heat
input
capacity
of
the
permanently
shutdown
unit).
The
new
gaseous
fuel
unit
would
be
subject
to
the
emission
limits
and
associated
monitoring,
testing,
and
reporting
and
recordkeeping
requirements
for
new
gaseous
fuel
units.
This
provision
would
be
an
incentive
for
replacing
existing
more
polluting
and
less
efficient
units
and,
thus,
would
result
in
additional
benefit
to
the
environment
by
reducing
other
pollutants
of
concerns
(
i.
e.,
sulfur
dioxide
and
nitrogen
oxide).

The
final
rule
also
takes
a
different
approach
to
averaging
from
the
HON
approach
regarding
the
exclusion
from
emissions
averaging
any
units
equipped
with
emission
control
systems
that
were
installed
prior
to
the
passage
of
the
1990
Amendments
to
the
Act
on
November
15,
1990.
to
comply
with
a
State
or
Federal
rule
or
statute
(
other
than
today's
final
rule).
In
the
final
rule,
we
do
not
include
this
restriction.
In
this
standard,
owners
and
operators
are
permitted
to
average
across
all
existing
large
solid
fuel
units
regardless
of
preexisting
controls
in
determining
overall
compliance
with
the
standard.
In
the
HON
rulemaking,
EPA
had
concerns
that
credits
for
controls
126
applied
to
comply
with
another
rule
increase
the
source
ability
to
generate
credits,
but
do
not
generate
any
new
emissions
reductions,
thus
creating
more
emissions.
For
this
rulemaking,
we
believe
it
would
be
inappropriate
to
disallow
a
facility
from
including
in
the
emission
average
a
low
emitting
source
just
because
it
has
a
preexisting
control
device.
Most,
if
not
all,
existing
large
solid
fuel
boilers
are
equipped
with
some
type
of
control
device
to
reduce
flyash.
Most
of
these
control
devices
are
low
efficiency
mechanical
collectors
(
e.
g.,
cyclones
or
multiclones)
for
collecting
large
particles
but
are
ineffective
in
reducing
HAP
emissions.
In
the
HON,
the
preexisting
controls
were
installed
to
comply
with
a
State,

Federal,
or
tribal
rule
covering
the
HAP
being
regulated
by
the
HON.
This
is
not
the
case
for
industrial
boilers
and
process
heaters.
Current
Federal
(
such
as,
NSPS),
State,

and
tribal
rules
covering
industrial
boilers
and
process
heaters
do
not
regulate
HAP
(
metals,
mercury,
and
HCl)

emissions.
The
existing
rules
regulate
criteria
pollutants
(
SO2,
NOx,
PM,
and
opacity).
Thus,
if
existing
units
with
control
devices
were
disallowed
to
be
used
in
emission
averaging,
there
would
be
no
existing
units
eligible
for
emission
averaging.
We
believe
that
taking
a
different
approach
regarding
previous
actions
is
appropriate
since,

unlike
in
the
case
of
the
HON,
the
existing
controls
on
127
large
solid
fuel
boilers
were
not
installed
to
control
HAP
emissions
and
are
ineffective
in
controlling
one
or
more
of
the
HAP
being
regulated.
Therefore,
for
the
HAP
regulated
(
mainly
HCl
and
mercury),
it
would
be
unreasonable
and
inappropriate
to
disallow
credit
for
sources
equipped
with
control
devices
due
to
previous
actions.

The
HON
requires
a
hazard
and
risk
study
for
emission
points
included
in
an
emissions
average
largely
because
the
HON
emission
averaging
provisions
allowed
averaging
across
all
HAP
(
interpollutant
trading)
covered
by
the
HON.
The
concern
with
the
HON
approach
was
that
such
a
provisions
would
allow
emissions
of
a
more
hazardous
pollutant
to
be
increased
for
corresponding
decreases
in
a
less
hazardous
pollutant.
Unlike
the
HON,
in
the
final
rule,
emission
averaging
is
allowed
only
on
a
single
pollutant
(
mercury,

HCl,
or
PM)
basis
and
not
across
all
pollutants.
Since
we
are
only
allowing
the
averaging
on
a
single
pollutant
basis,

we
believe
that
emission
averaging
will
achieve
a
comparable
hazard/
risk
benefit
as
point­
by­
point
compliance.
Thus,
the
final
rule
does
not
require
a
hazard
or
risk
study.

The
HON
requires
a
discount
factor
of
10
percent
in
credit
calculations
to
share
with
the
environment
some
portion
of
the
cost
savings
due
to
emissions
averaging
and
to
account
for
uncertainty
in
emissions
estimation.
Due
to
differences
(
discussed
below)
between
large
solid
fuel
128
boilers
and
HON
sources,
we
do
not
believe
it
is
necessary
for
the
final
rule
to
include
a
discount
factor.

The
HON
proposal
preamble
(
57
FR
62652,
December
31,

1992)
and
the
HON
final
preamble
discuss
how
cost
savings
due
to
emissions
averaging
should
be
shared
between
industry
and
the
environment.
For
the
HON,
we
decided
that
it
was
appropriate
that
industry
share
any
cost
savings
realized
from
emissions
averaging
and
included
a
discount
factor
because
the
costs
of
controlling
different
emission
points
could
vary
significantly.
The
HON
proposal
preamble
also
discussed
the
level
of
uncertainty
in
estimating
emissions
reductions
that
may
result
from
facilities
using
emissions
averaging.
For
the
HON,
the
uncertainty
arose
from
differing
accuracies
available
for
estimating
emissions
from
the
number
of
emission
points
at
a
HON
facility,
the
number
of
HAP
emitted
from
HON
facilities,
and
the
different
types
of
emission
points.

Large
solid
fuel
boiler
facilities
differs
in
almost
every
relevant
factor
from
the
HON.
First,
as
discussed
previously,
the
number
of
large
solid
fuel
boilers
that
might
be
included
in
an
emissions
average
is
fewer
than
could
be
included
in
a
HON
average
and,
therefore,
less
of
a
concern.
Second,
the
magnitude
of
emissions
from
HON
emission
points
is
typically
much
greater
than
the
emissions
from
large
solid
fuel
boilers.
Third,
emission
averaging
129
for
large
solid
fuel
boilers
is
on
a
single
HAP
basis
compared
to
averaging
over
140
HAP
emitted
from
HON
facilities.
Fourth,
large
solid
fuel
boilers
are
much
more
similar
emission
points
than
those
regulated
by
the
HON
and,

therefore,
unlikely
to
introduce
additional
uncertainty.

With
concern
about
the
equivalency
of
emissions
reductions
from
averaging
and
non­
averaging
in
mind,
the
Administrator
is
also
imposing
under
the
emission
averaging
provision
caps
on
the
current
emissions
from
each
of
the
sources
in
the
averaging
group.
The
emissions
for
each
unit
in
the
averaging
group
would
be
capped
at
the
emission
level
being
achieved
on
the
effective
date
of
the
final
rule.

These
caps
would
ensure
that
emissions
do
not
increase
above
the
emission
levels
that
sources
currently
are
designed,

operated,
and
maintained
to
achieve.
In
the
absence
of
performance
tests,
in
documenting
these
caps,
these
sources
will
documented
the
type,
design,
and
operating
specification
of
control
devices
installed
on
the
effective
date
of
the
final
rule
to
ensure
that
existing
controls
are
not
removed
or
lessen.
By
including
this
provision
in
the
final
rule,
the
Administrator
has
taken
yet
another
step
to
assist
in
ensuring
that
emission
averaging
results
in
environmental
benefits
equivalent
or
better
over
what
would
have
happened
without
emission
averaging.

We
believe
the
inclusion
of
emissions
averaging
into
130
rules
and
the
decision
on
how
to
design
an
emission
averaging
approach
for
a
particular
source
category
must
be
evaluated
for
each
source
category.
Although
the
HON
and
the
final
rule
share
the
same
legal
basis
for
including
emission
averaging
as
a
compliance
option
and
the
same
basic
system
of
credits
and
debits,
some
of
the
restrictions
reasonable
for
the
HON
emissions
averaging
provisions
are
unnecessary
for
the
final
rule.
Emission
averaging
would
not
be
allowed
in
any
State
that
selects
to
exclude
this
option
from
its
approved
permitting
program.

J.
Risk­
based
Approach
Comment:
Several
commenters
supported
EPA's
incorporation
of
risk­
based
concepts
into
the
MACT
Program.

One
commenter
believed
that
providing
risk­
based
applicability
criteria
for
sources
whose
HAP
emissions
do
not
pose
a
significant
risk
is
appropriate.
Several
commenters
believed
that
there
is
clear
legal
authority
in
the
CAA
to
construct
NESHAP
based
on
risk,
and
such
an
approach
is
very
appropriate
in
the
case
of
the
Industrial
Boiler
MACT.
The
commenter
also
noted
that
the
regulatory
framework
exists
within
their
State
to
implement
such
an
approach.
Several
commenters
added
that
risk­
based
alternatives
will
function
as
indirect
emission
limits
that
must
be
maintained
by
the
facilities
to
assure
that
the
criteria
are
met,
and,
thus,
such
alternatives
for
low­
risk
131
facilities
are
supportable
by
EPA's
authority
under
section
112(
d)(
4)
and
112(
c)(
9)
of
the
CAA
and
EPA's
inherent
de
minimis
authority.
Another
commenter
asserted
that
there
are
ways
to
structure
the
rule
to
focus
on
facilities
that
pose
significant
risks
and
avoid
imposition
of
high
costs
on
facilities
that
pose
little
risk.
An
appropriate
approach
would
be
to
allow
individual
facilities
to
conduct
a
risk
assessment
to
show
that
itthey
poses
insignificant
risks
to
the
public.
However,
one
commenter
does
not
believe
that
it
is
appropriate
for
State
and
local
programs
to
determine
which
facilities
should
be
exempted
from
MACT.
Several
commenters
supported
a
risk­
based
off­
rampcompliance
alternative
for
HCl.

Response:
The
EPA
has
determined
that
it
can
establish
applicable
health­
based
emission
standards
for
HCl
and
manganese
for
affected
sources
in
this
category
pursuant
to
its
authority
under
section
112(
d)(
4)
of
the
CAA.
As
a
result,
EPA
has
included
such
standards
in
the
final
rule
as
alternative
compliance
requirements.
Under
this
approach,

affected
sources
can
choose
to
comply
with
either
the
MACTbased
emission
limits
or
the
health­
based
emission
limits.

Sources
which
choose
to
comply
with
the
health­
based
emission
limit(
s)
will
remain
subject
to
those
limits,
but
will
need
to
comply
with
testing,
monitoring
and
reporting
132
requirements
commensurate
with
the
compliance
option
they
have
chosen.
The
EPA
believes
that
such
health­
based
standards
are
consistent
with
both
the
commenters'
support
for
an
approach
that
minimizes
the
impact
on
low­
risk
facilities
and
EPA's
statutory
mandate
under
section
112.

Section
112(
d)(
4)
authorizes
EPA
to
consider
established
heath
thresholds,
with
an
ample
margin
of
safety,
when
promulgating
emission
standards
under
section
112.
HCl
and
Mn
are
two
pollutants
for
which
health
thresholds
have
been
established.
Issues
concerning
our
legal
authority
to
establish
health­
based
emission
standards
under
section
112(
d)(
4)
of
the
CAA
are
discussed
in
detail
below.

We
are
not
using
section
112(
c)(
9)
for
the
final
rule,

and
there
are
no
additional
subcategories
andis
no
delisting
of
categories
or
subcategories,
as
would
be
consistent
with
section
112(
c)(
9).

The
criteria
defining
how
affected
sources
demonstrate
that
they
meet
the
threshold
emissions
levels
for
the
health­
based
compliance
alternative(
s)
is
included
in
appendix
A
to
subpart
DDDDD
of
part
63.
The
criteria
in
appendix
A
to
subpart
DDDDD
of
part
63
were
developed
for
and
apply
only
to
the
Boiler
and
process
heater
source
category
and
are
not
applicable
to
other
source
categories.

The
final
rule
provides
two
ways
that
an
affected
source
may
133
demonstrate
compliance
with
the
health­
based
emission
limits.
The
first
option
is
through
the
use
of
lookup
tables
which
allow
facilities
to
determine,
using
a
limited
number
of
site­
specific
input
parameters,
whether
emissions
from
boilers
and
process
heaters
might
cause
a
hazard
index
(
HI)
limit
for
non­
carcinogens
to
be
exceeded.
The
second
option
is
a
tiered
modeling
approach
(
each
tier
less
conservative
and
more
complex
than
the
previous)
which
allows
those
facilities
that
do
not
match
the
site­
specific
input
parameters
on
which
the
lookup
tables
are
based
to
demonstrate
compliance
with
the
health­
based
emission
limits
by
modeling
using
site­
specific
information.

The
affected
source
will
have
to
demonstrate
that
it
meets
the
criteria
established
by
today's
final
rule
and
then
assume
Federally
enforceable
limitations,
as
described
in
appendix
A
of
subpart
DDDDD
of
part
63,
that
ensure
their
specified
HAP
emissions
do
not
subsequently
increase
to
exceed
levels
reflected
in
their
demonstrations.

Comment:
Multiple
commenters
are
opposed
to
the
riskbased
exemptions.
Some
noted
that
the
proposal
to
include
risk­
based
exemptions
is
critically
flawed
and
opposes
adoption
of
the
risk­
based
exemptions
into
MACT.

One
commenter
stated
that
the
inclusion
of
case­
by­
case
risk­
based
exemptions
into
the
first
phase
of
the
MACT
program
will
negate
the
legislative
mandate
and
jeopardize
134
the
effectiveness
of
the
national
air
toxics
program
to
adequately
protect
public
health
and
the
environment
and
to
establish
a
level
playing
field.
Therefore,
the
commenter
strongly
disagrees
with
inclusion
of
risk­
based
exemptions
in
the
MACT
standard
process.
The
commenter
was
very
concerned
that
EPA
referenced
a
fundamentally
flawed
interpretation
of
§
112(
d)(
4)
written
by
an
industry
(
AF&
PA)

subject
to
regulation.
Of
particular
concern
was
AF&
PA's
unprecedented
proposal
to
include
"
de
minimis
exemptions"

and
"
cost"
in
the
MACT
standard
process.

One
commenter
stated
the
belief
that
the
use
of
riskbased
concepts
to
evade
MACT
applicability
is
contrary
to
the
intent
of
the
CAA
and
is
based
on
a
flawed
interpretation
of
Section
112(
d)(
4)
of
the
CAA.
The
commenter
added
that
the
CAA
requires
a
technology­
based
floor
level
of
control
and
does
not
provide
exclusions
for
risk
or
secondary
impacts
from
applying
the
MACT
floor.

One
commenter
stated
that
in
separate
rulemakings
and
lawsuits,
EPA
has
adopted
legal
positions
and
policies
that
refute
and
contradict
the
very
risk­
based
and
cost­
based
approaches
contained
in
the
proposals.
In
these
other
arena,
the
commenter
contended
that
EPA
has
properly
rejected
risk
assessment
to
alter
the
establishment
of
MACT
standards.
EPA
also
has
properly
rejected
cost
in
135
determining
MACT
floors
and
in
denying
a
basis
for
avoiding
the
MACT
floor.
The
commenter
attached
passages
from
several
EPA
briefs:
Brief
for
Respondent
Environmental
Protection
Agency,
Sierra
Club
v.
EPA;
Brief
for
Respondent
Environmental
Protection
Agency,
Cement
Kiln
Recycling
Coalition
v.
EPA,
No.
99­
1457
and
consolidated
cases,
D.
C.

Cir.)
(
Jan.
18,
2001)
(
Attachment
1);
Brief
for
Respondent
Environmental
Protection
Agency,
National
Lime
Ass'n
v.
EPA,

233
F.
3D
625
(
D.
C.
Cir.
2000)
(
July
14,
2000)
(
Attachment
3).

Several
commenters
stated
that
the
preamble
discussion
of
the
risk­
based
approaches
is
not
sufficient
to
allow
for
complete
public
comment
and,
therefore,
it
would
not
be
appropriate
for
EPA
to
go
directly
to
a
final
rule
(
without
reproposal)
with
any
of
the
approaches
outlined
in
the
proposal.
The
commenter
recommended
that
the
risk­
based
exemption
proposal
be
dropped
because
it
is
unacceptable.

Response:
For
many
of
the
reasons
provided
by
the
commenters,
wWe
are
not
identifying
and
deleting
a
subcategory
of
sources
in
this
source
category
pursuant
to
the
authority
of
CAA
section
112(
c)(
9)
because
there
is
no
currently
definable
subcategory
which
meets
the
criteria
specified
in
that
section.
We
also
are
relying
on
de
minimus
authority.
Legal
issues
associated
with
the
risk­
136
based
provisions
are
addressed
below
and
in
the
comment/
response
memorandum.

As
discussed
above,
we
are,
however,
including
in
the
final
rule
alternative
health­
based
emission
standards
for
HCl
and
manganese
based
on
our
authority
under
CAA
section
112(
d)(
4).
Section
112(
d)(
4)
authorizes
EPA
to
consider
health
thresholds,
with
an
ample
margin
of
safety,

in
establishing
emission
standards.
The
analysis
necessary
to
do
this
can
generally
be
characterized
as
a
risk
analysis.
Thus,
we
disagree
with
the
commenter
that
we
must
wait
for
implementation
of
section
112(
f)
before
utilizing
risk
analysis.

Comment:
Many
commenters
stated
that
the
proposal
to
include
risk­
based
exemptions
is
contrary
to
the
1990
CAA
Amendments
(
CAAA)
which
calls
for
MACT
standards
based
on
technology
rather
than
risk
as
a
first
step.
They
added
that
congress
incorporated
the
residual
risk
program
under
§
112(
f)
to
follow
the
MACT
standards
(
not
to
replace
them).

The
commenters
added
that
the
need
for
the
technology­
based
approach
has
been
recently
reinforced
by
the
results
of
the
National
Air
Toxics
Assessment
(
NATA),
which
indicates
that
exposure
to
air
toxics
is
very
high
throughout
the
country
in
urban
and
remote
areas.
Several
commenters
added
that
risk­
based
approaches
will
be
used
separately
to
augment
and
improve
technology­
based
standards
that
do
not
adequately
137
provide
protection
to
the
public.
One
commenter
added
that
they
have
been
unable
to
substantiate
the
basis
for
EPA's
support
of
the
regulatory
relief
sought
by
industry
through
risk­
based
exemptions.
I
and
that,
in
fact,
the
use
of
risk
assessment
at
this
stage
of
the
MACT
program
is
directly
opposed
to
Title
III
of
the
CAA.

Response:
We
disagree
that
inclusion
of
health­
based
compliance
alternatives,
in
the
form
of
emission
standards
based
on
the
authority
of
section
112(
d)(
4)
of
the
CAA,
in
the
final
rule
is
contrary
to
the
1990
CAAA.
The
Boiler
MACTfinal
rule
is
a
technology­
based
standard
developed
using
the
procedures
dictated
by
section
112
of
the
CAA.

The
only
difference
inbetween
the
Boiler
MACTfinal
rule
and
other
MACT
is
that
we
used
our
discretion
under
CAA
section
112(
d)(
4)
to
base
appropriate
parts
of
the
Boiler
MACTfinal
rule
on
established
health
thresholds,
with
an
ample
margin
of
safety.
We
believe
that
the
Boiler
rulemaking
is
particularly
well­
suited
for
a
health­
based
compliance
alternative,
established
pursuant
to
the
criteria
set
forth
in
section
112(
d)(
4).
In
addition
to
the
fact
that
there
are
established
health
thresholds
for
HCl
and
manganese,
EPA
has
determined
that
many
of
the
facilities
in
this
source
category
do
not
emit
these
pollutants
in
amounts
that
pose
a
significant
risk
to
the
surrounding
population.

Those
sources
that
can
demonstrate
that
the
emissions
of
138
acid
gases
and
manganese
meet
the
threshold
emission
levels
will
be
in
compliance
with
the
MACT.
The
criteria
are
based
on
health­
protective
estimates
of
risk
and
the
threshold
emission
levels
will
provide
ample
protection
of
human
health
and
the
environment.

Inclusion
of
health­
based
compliance
alternatives
in
the
Boiler
rule
does
not
alter
the
MACT
program.
Rather,
it
merely
represents
EPA
availing
itself,
in
appropriate
circumstances,
of
the
authority
Congress
granted
it
in
section
112(
d)(
4)
of
the
CAA.
We
recognize
that
such
provisions
are
only
appropriate
for
certain
HAP,
and
our
decision­
making
process
required
source
category­
specific
input
from
stakeholders.
The
10­
year
MACT
standards,
which
are
now
being
completed,
are
the
last
group
of
MACT
standards
currently
planned
for
development,
and
for
any
risk
provisions
to
be
useful,
the
provisions
must
be
finalized
in
a
timely
manner
(
i.
e.,
not
later
than
the
promulgation
of
the
MACT
standards).
These
final
MACT
source
categories
were
included
in
the
"
10­
year
bin"
because
they
were
considered
to
be
the
lowest
risk
source
categories.

Although
NATA
may
show
measurable
concentrations
of
toxic
air
pollution
across
the
country,
these
data
do
not
suggest
that
EPA
should
not
establish
health­
based
emission
standards
pursuant
to
its
authority
under
section
112(
d)(
4)
139
when
it
determines
that
it
is
appropriate
to
do
so.
The
alternative
health­
based
emission
standards
included
in
the
final
rule
will
ensure
that
affected
sources
which
choose
to
comply
with
those
standards
do
not
emit
HCl
and/
or
manganese
at
levels
that
are
harmful
to
public
health.

Affected
sources
which
choose
to
comply
with
the
alternative
health­
based
emission
standards
must
account
for
background
concentrations
of
HCl
and/
or
manganese
in
demonstrating
compliance
with
the
applicable
standard.
Section
II.
I
of
this
document
discusses
how
background
concentrations
are
accounted
for
by
Boiler
facilities
in
demonstrating
that
they
meet
the
health­
based
emission
standards.

Comment:
Many
commenters
stated
that
the
proposal
to
allow
risk­
based
exemptions
would
divert
back
to
the
timeconsuming
NESHAP
development
process
that
existed
prior
to
the
CAAA
of
1990.
The
commenters
asserted
that
under
this
process,
which
began
with
a
risk
assessment
step,
only
eight
NESHAP
were
promulgated
during
a
20­
year
period.
The
commenters
continued
that
if
the
proposed
approaches
are
inserted
into
upcoming
standards,
the
commenters
fear
the
MACT
program
(
which
is
already
far
behind
schedule)
would
be
further
delayed.
One
commenter
supported
EPA
efforts
to
determine
alternative
MACT
setting
methodologies
but
strongly
recommended
that
these
be
pursued
separately
from
this
rulemaking.
The
commenter
contended
that
this
will
140
provide
for
timely
issuance
of
final
RICE
and
Boiler/
Process
Heater
MACT
standards
relative
to
the
settlement
deadline.

Two
commenters
stated
that
delays
could
be
exacerbated
by
litigation
following
legal
challenges
to
the
rules,
and
such
delays
would
trigger
the
MACT
hammer,
which
would
unnecessarily
burden
the
State
and
local
agencies
and
the
industries.
The
commenters
concluded
that
further
delay
is
unacceptable.
The
commenters
did
not
want
to
be
in
a
position
of
implementing
the
112(
j)
program
and
urged
EPA
to
not
delay
the
issuance
of
any
MACT
standard.
The
commenters
noted
that
according
to
a
recently
proposed
EPA
rule
regarding
section
112(
j),
the
regulated
community
and
State
and
local
agencies
would
have
to
proceed
with
Part
2
permit
applications,
followed
by
case­
by­
case
MACT,
if
EPA
misses
the
newly
agreed­
upon
MACT
deadlines
by
as
little
as
two
months.
This
would
be
time
consuming,
costly,
and
burdensome
for
both
regulators
and
the
regulated
community.

Response:
We
disagree
that
allowing
health­
based
compliance
alternatives
in
the
final
rule
will
alter
the
MACT
program
or
affect
the
schedule
for
promulgation
of
the
remaining
MACT
standards.
We
do
not
anticipate
any
further
delays
in
completing
the
remaining
MACT
standards.
The
setting
of
alternative
health­
based
emission
standards
in
the
Boiler
rulemaking
affects
only
the
Boiler
NESHAP,
and
not
all
other
MACT
standards
that
have
yet
to
be
141
promulgated.

We
believe
that
the
approach
taken
in
the
Boiler
rulemaking
is
particularly
well­
suited
to
acid
gases
and
manganese,
which
are
the
only
pollutants
included
in
the
health­
based
compliance
alternatives.
For
many
facilities,

the
pollutants
are
currently
emitted
in
amounts
that
do
not
expose
anyone
in
surrounding
population
to
concentrations
above
the
established
health
thresholds.
As
a
result,

emissions
of
HCl
and/
or
manganese
at
these
facilities
do
not
pose
a
significant
risk
to
the
surrounding
population.
Only
those
Boiler
facilities
that
demonstrate
that
their
emissions
are
below
the
health­
based
emission
standard(
s),

are
eligible
for
the
compliance
alternatives.

Including
health­
based
compliance
alternatives
for
boiler
sources
does
not
mean
that
EPA
will
automatically
provide
such
alternatives
for
other
industries.
Rather,
as
has
been
the
case
throughout
the
MACT
rule
development
process,
EPA
will
undertake
in
each
individual
rule
to
determine
whether
it
is
appropriate
to
exercise
its
discretion
to
use
its
authority
under
section
112(
d)(
4)
in
developing
applicable
emission
standards.
Furthermore,
EPA
has
no
intentions
of
re­
opening
previously
promulgated
NESHAP
in
light
of
decisions
made
specific
to
the
Boilers
source
category.
The
Boilers
NESHAP
is
being
promulgated
by
the
February
2004
court­
ordered
deadline.
Any
delays
in
142
implementation
of
the
Boilers
NESHAP
caused
by
legal
challenges
are
beyond
our
control.

Comment:
Many
commenters
stated
that
the
risk­
based
proposal
removes
the
"
level­
playing
field"
that
would
result
from
the
proper
implementation
of
technology­
based
MACT
standards.
The
commenters
added
that
establishing
a
baseline
level
of
control
is
essential
to
prevent
industry
from
moving
to
areas
of
the
country
that
have
the
least
stringent
air
toxics
programs,
which
was
one
of
the
primary
goals
of
developing
a
uniform
national
air
toxics
program
under
section
112
of
the
1990
CAA
amendments.
The
riskbased
approaches
would
jeopardize
future
reductions
of
HAPs
in
a
uniform
and
consistent
manner
across
the
nation.

Response:
We
agree
that
one
of
the
primary
goals
of
developing
a
uniform
national
air
toxics
program
under
section
112
of
the
1990
CAA
amendments
was
to
establish
a
level
playing
field.
We
do
not
believe
that
providing
health­
based
compliance
alternatives
for
sources
that
can
meet
them
in
the
final
rule
will
do
anything
to
create
an
unlevel
playing
field
for
Boiler
facilitiessources
subject
to
this
rule.
The
final
Boiler
NESHAPrule
and
its
criteria
for
demonstrating
eligibility
for
the
health­
based
compliance
alternatives
apply
uniformly
to
boilers
across
the
nation
in
the
large
solid
fuel­
fired
subcategories.
The
Boiler
NESHAP
establishes
a
two
baseline
levels
of
emission
143
reduction
for
HCl
and
manganese,
one
based
on
a
traditional
MACT
analysis
and
the
other
based
on
EPA's
evaluation
of
the
health
threat
posed
by
emissions
of
these
two
pollutants.
All
Boiler
facilities
must
meet
one
of
these
baseline
levels,
and
all
facilities
with
boilers
in
the
applicable
subcategories
have
the
same
opportunity
to
demonstrate
that
they
can
meet
the
alternative
health­
based
emission
standards.
The
criteria
for
qualifying
to
comply
with
the
alternative
health­
based
emission
standards
are
not
dependent
on
local
air
toxics
programs.
Therefore,
concerns
regarding
facilities
moving
to
areas
of
the
country
with
less­
stringent
air
toxics
programs
should
be
alleviated.

Comment:
Multiple
commenters
believed
that
Section
112(
d)(
4)
provides
EPA
with
authority
to
exclude
sources
that
emit
threshold
pollutants
from
regulation.
The
commenters
indicated
that
Section
112(
d)(
4)
allows
for
discretion
in
developing
MACT
standards
for
HAP
with
health
thresholds.
The
commenters
added
that
the
use
of
section
112(
d)(
4)
authority
also
is
supported
by
CAA's
legislative
history,
which
emphasizes
that
Congress
included
§
112(
d)(
4)

in
the
CAA
to
prevent
unnecessary
regulation
of
source
categories.

One
commenter
pointed
out
that
Congress
does
not
differentiate
between
technology­
based
"
emission
standards"

set
under
section
112(
d)(
3)
versus
"
health
threshold"
based
144
"
emission
standards"
set
under
section
112(
d)(
4).
Instead,

the
statute
explicitly
treats
emission
standards
promulgated
under
section
112(
d)(
3)
and
112(
d)(
4)
as
equivalent
by
not
distinguishing
between
those
emission
standards
under
the
residual
risk
provisions
of
section
112(
f).
One
commenter
added
that
EPA
is
permitted
to
establish
alternative
standards
as
long
as
it
ensures
that
ambient
concentrations
are
less
than
the
health
thresholds
plus
a
margin
of
safety
and
the
emissions
do
not
cause
adverse
environmental
effects.
Multiple
commenters
pointed
out
that
EPA
has
exercised
such
authority
and
cited
the
NESHAP
for
Chemical
Recovery
Combustion
Sources
at
Kraft,
Soda,
Sulfite,
and
Stand­
Alone
Semichemical
Pulp
and
Paper
MACTMills.
In
addition,
the
commenters
added
that
in
the
Pulp
and
Paper
MACTat
NESHAP,
EPA
identified
circumstances
in
which
they
would
decline
to
exercise
112(
d)(
4)
authority
 
where
significant
or
widespread
environmental
harm
would
occur
as
a
result
of
emissions
from
the
category
and
the
estimated
health
thresholds
are
subject
to
substantial
scientific
uncertainty.
The
comenters
concluded
that
EPA
determined
that
these
considerations
were
not
relevant
to
emissions
from
the
pulp
and
paper
source
category,
and
the
commenters
believe
that
the
same
is
true
for
their
source
categories
and
that
the
same
treatment
is
warranted
for
many
facilities
within
the
source
categories.
The
commenters
noted
that
145
facilities
that
cannot
meet
the
risk
criteria
would
remain
subject
to
the
MACT
requirements.

One
commenter
added
that
the
risk­
based
approaches
are
squarely
in
line
with
the
plain
meaning
of
section
112(
d)(
4).
The
commenters
cited
the
Senate
report
(
Sen
Rep.

No.
228,
101st
Congress,
1st
Sess
175­
6
(
1990))
showed
that
Congress
contemplated
that
sources
within
the
same
category
or
subcategory
would
be
subject
to
varied
regulatory
requirements,
depending
on
the
risk
they
pose
to
public
health.
The
commenters
added
that
nothing
in
the
statutory
definition
of
"
emission
standard"
suggests
that
the
term
is
limited
to
a
requirement
for
the
installation
of
control
technology.
The
commenters
added
that
the
risk­
based
compliance
alternatives
would
meet
this
requirement
because
they
would
apply
to
an
entire
source
category
or
subcategory.
EPA
could
create
a
subcategory
for
low­
risk
sources
and
tailor
an
emission
standard
to
this
subcategory,

or
apply
to
all
sources
in
the
category
a
NESHAP
containing
multiple
compliance
options,
one
or
more
being
risk­
based.

Multiple
commenters
stated
that
the
plain
meaning
of
§
112(
d)(
4)
does
not
allow
EPA
to
make
MACT
standard
s
for
individual
sources.
Two
commenters
noted
that
section
112(
d)(
4)
states
that
"
with
respect
to
pollutants
for
which
a
health
threshold
has
been
established,
the
Administrator
may
consider
such
threshold
level,
with
ample
margin
of
146
safety,
when
establishing
emission
standards
under
this
subsection."

Several
commenters
contended
that
EPA
has
misinterpreted
the
provision
in
112(
d)(
4)
in
that
Section
112(
d)(
4)
does
not
state
that
EPA
can
use
applicability
thresholds
"
in
lieu
of"
the
Section
112(
d)(
3)
MACT
floor
requirements.
The
commenter
interpreted
Section
112(
d)(
4)

to
state
that
health
based
thresholds
can
be
considered
when
establishing
the
degree
of
the
MACT
floor
requirements,
but
it
should
not
be
used
to
supplant
the
requirements
established
pursuant
to
Section
112(
d)(
3).

Many
commenters
stated
that
the
legislative
history
of
§
112(
d)(
4)
clearly
rejects
EPA's
proposed
facility­

byfacility
MACT
exemptions.
The
commenters
noted
that
Congress
considered
and
rejected
the
applicability
cutoffs
upon
which
EPA
now
solicits
comment.
The
commenters
noted
that
the
House
version
of
the
1990
Amendments
allowed
States
to
issue
permits
that
exempted
a
source
from
compliance
with
MACT
rules
if
the
source
presented
sufficient
evidence
to
demonstrate
negligible
risk,
and
the
Senate
version
of
the
1990
Amendments
contained
no
such
provision.
In
conference,

Congress
considered
both
the
House
and
Senate
versions
and
rejected
the
House
bill's
exemption
for
specific
facilities
in
favor
of
the
Senate
bill's
language.
147
Response:
The
EPA
believes
that
it
has
properly
exercised
the
authority
granted
to
it
pursuant
to
section
112(
d)(
4)
of
the
CAA
in
establishing
health­
based
emission
standards
for
HCl
and
manganese
which
are
applicable
to
the
large
solid
fuel­
fired
subcategories.
The
EPA
believes
that
section
112(
d)(
4)
authorizes
it
to
ignoreby­
pass
the
mandate
in
section
112(
d)(
3)
in
appropriate
circumstances.
Those
circumstances
are
present
in
the
large
solid
fuel­
fired
Boiler
subcategories.

Section
112(
d)(
4)
provides
EPA
with
authority,
at
its
discretion,
to
develop
health­
based
emission
standards
for
HAP's
"
for
which
a
health
threshold
has
been
established",

provided
that
the
standard
reflects
the
health
threshold
"
with
an
ample
margin
of
safety."
(
The
full
text
of
the
section
112(
d)(
4):
"[
w]
ith
respect
to
pollutants
for
which
a
health
threshold
has
been
established,
the
Administrator
may
consider
such
threshold
level,
within
an
ample
margin
of
safety,
when
establishing
emission
standards
under
this
subsection.")

The
EPA
presumptively
applies
section
112(
d)(
4)
only
to
HAP's
that
are
not
carcinogens
because
Congress
clearly
intended
that
carcinogens
be
considered
nonthreshold
pollutants.
(
Staff
of
the
Senate
Committee
on
Environment
and
Public
Works,
A
Legislative
History
of
the
Clean
Air
Act
Amendments
of
1990,
Vol.
1
at
876,
statement
of
Senator
148
Durenberger
during
Senate
Debate
of
October
27,
1990:
"
With
respect
to
the
pollutants
for
which
a
safe
threshold
can
be
set,
the
authority
to
set
a
standard
less
stringent
than
maximum
achievable
control
technology
is
contained
in
subsection
(
d)(
4).
With
respect
to
carcinogens
and
other
non­
threshold
pollutants,
no
such
authority
exists
in
subsection
(
d)
or
in
any
other
provision
of
the
Act.")
The
legislative
history
further
indicates
that
if
EPA
invokes
this
provision,
it
must
assure
that
any
emission
standard
results
in
ambient
concentrations
less
than
the
health
threshold,
with
an
ample
margin
of
safety,
and
that
the
standards
must
also
be
sufficient
to
protect
against
adverse
environmental
effects
(
S.
Rep.
No.
228,
101st
Cong.
at
171).

(
Section
112(
a)(
7)
of
the
CAA
defines
the
term
"
adverse
environmental
effect"
as
"
any
significant
and
widespread
adverse
effect,
which
may
reasonably
be
anticipated,
to
wildlife,
aquatic
life,
or
other
natural
resources,

including
adverse
impacts
on
populations
of
endangered
or
threatened
species
or
significant
degradation
of
environmental
quality
over
broad
areas.)
Costs
are
not
to
be
considered
in
establishing
a
standard
pursuant
to
section
112(
d)(
4)
(
Ibid.).

Both
the
plain
language
of
section
112(
d)(
4)
and
the
legislative
history
cited
above
indicate
that
EPA
has
the
discretion
under
section
112(
d)(
4)
to
develop
health­
based
149
standards
for
some
source
categories
emitting
threshold
pollutants,
and
that
those
standards
may
be
less
stringent
than
the
corresponding
"
floor"­
based
MACT
standard
would
be.

The
EPA
does
not
believe
that
its
use
of
such
standards
is
limited
to
situations
where
every
source
in
the
category
or
subcategory
can
comply
with
them.
As
is
the
case
with
technology­
based
standards,
a
particular
source's
ability
to
comply
with
a
health­
based
standard
will
depend
on
its
individual
circumstances,
as
will
what
it
must
do
to
achieve
compliance.

In
developing
health­
based
emission
standards
under
section
112(
c)(
4),
EPA
seeks
to
assure
that
those
standards
ensure
that
the
concentration
of
the
particular
HAP
to
which
an
individual
exposed
at
the
upper
end
of
the
exposure
distribution
is
exposed
does
not
exceed
the
health
threshold.
The
upper
end
of
the
exposure
distribution
is
calculated
using
the
"
high
end
exposure
estimate,"
defined
as
"
a
plausible
estimate
of
individual
exposure
for
those
persons
at
the
upper
end
of
the
exposure
distribution,

conceptually
above
the
90th
percentile,
but
not
higher
than
the
individual
in
the
population
who
has
the
highest
exposure"
(
EPA
Exposure
Assessment
Guidelines,
57
FR
22888,

May
29,
1992).
The
EPA
believes
that
assuring
protection
to
persons
at
the
upper
end
of
the
exposure
distribution
is
consistent
with
the
"
ample
margin
of
safety"
requirement
in
150
section
112(
d)(
4).

The
EPA
emphasizes
that
use
of
section
112(
d)(
4)

authority
is
wholly
discretionary.
As
the
legislative
history
described
above
indicates,
cases
may
arise
in
which
other
considerations
dictate
that
the
Agency
should
not
invoke
this
authority
to
establish
less
stringent
standards,

despite
the
existence
of
a
health
effects
threshold
that
is
not
jeopardized.
For
instance,
EPA
does
not
anticipate
that
it
would
set
less
stringent
standards
where
the
estimated
health
threshold
for
a
contaminant
is
subject
to
large
uncertainty.
Thus,
in
considering
appropriate
uses
of
its
discretionary
authority
under
section
112(
d)(
4),
EPA
considers
other
factors
in
addition
to
health
thresholds,

including
uncertainty
and
potential
"
adverse
environmental
effects,"
as
that
phrase
is
defined
in
section
112(
a)(
7).

We
agree
that
section
112(
d)(
4)
is
appropriate
for
establishing
emission
standards
for
HCl
and
manganese
applicable
to
the
large
solid
fuel­
fired
subcategories,
and
therefore
we
have
established
such
standards
as
an
alternate
compliance
requirement
for
affected
sources
in
those
subcategories.
Affected
sources
in
the
large
solid
fuelfired
subcategories
which
believe
that
they
can
demonstrate
compliance
with
one
or
both
of
the
health­
based
emission
standards
may
choose
to
comply
with
those
standards
in
lieu
of
the
otherwise
applicable
MACT­
based
standard.
151
Comment:
Many
commenters
contended
that
the
proposal
will
place
a
very
intensive
resource
demand
on
state
and
local
agencies
to
review
source's
risk
assessments,
and
state/
local
agencies
may
not
have
expertise
in
risk
assessment
methodology
or
the
resources
needed
to
verify
information
(
e.
g.,
emissions
data
and
stack
parameters)

submitted
with
each
risk
assessment.

Other
commenters
believe
that
a
risk­
based
program
can
be
structured
and
implemented
in
a
manner
that
does
not
adversely
impact
limited
State
resources.
One
commenter
asserted
that
EPA
should
work
closely
with
States
and
industry
to
implement
the
risk­
based
approach
in
a
nonburdensome
manner.
Another
commenter
stated
that
the
risk­
based
approaches,
like
other
MACT
standards,
would
simply
be
incorporated
into
each
state's
existing
Title
V
program.
The
commenter
concluded
that
because
the
Title
V
framework
already
exists,
the
addition
of
a
risk­
based
MACT
standard
would
not
require
States
to
overhaul
existing
permitting
programs.
Another
commenter
contended
that
the
final
MACT
rule
itself
should
set
forth
the
applicability
criteria
­
including
the
threshold
levels
of
exposure
­
that
sources
must
meet
to
qualify
for
a
risk­
based
determination.

Each
source
would
have
the
burden
of
demonstrating
that
its
exposures
are
below
this
limit,
and
therefore
the
states
would
not
be
required
to
develop
their
own
risk
assessment
152
guidance
or
to
conduct
source­
specific
risk
assessments.

Response:
The
health­
based
emission
limits
for
HCl
and
manganese
which
EPA
has
adopted
in
the
Boiler
NESHAP
do
not
rely
on
site­
specific
risk
assessments
and,
therefore,

should
not
impose
significant
resource
burdens
on
States.

Further,
the
required
compliance
demonstration
methodology
is
structured
in
such
a
way
as
to
avoid
the
need
for
States
to
have
significant
expertise
in
risk
assessment
methodology.
We
have
considered
the
commenters'
concerns
in
developing
the
criteria
defining
eligibility
for
these
compliance
alternatives,
and
we
believe
that
the
approach
that
is
included
in
the
final
rule
provides
clear,
flexible
requirements
and
enforceable
compliance
parameters.
The
final
rule
provides
two
ways
that
a
facility
may
demonstrate
eligibility
for
complying
with
the
alternative
health­
based
emission
standard.
First,
look­
up
tables,
which
are
included
as
Tables
2
(
HCl)
and
3
(
manganese)
in
appendix
A
of
subpart
DDDDD
of
part
63,
allow
facilities
to
determine,

using
a
limited
number
of
site­
specific
input
parameters,

whether
emissions
from
their
sources
might
cause
a
hazard
index
limit
(
hazard
quotient
in
the
case
of
manganese)
to
be
exceeded.
If
a
facility
cannot
demonstrate
eligibility
using
a
look­
up
table,
a
modeling
approach
can
be
followed.

Appendix
A
to
the
final
rule
presents
the
criteria
for
performing
this
modeling.
153
Regarding
commenters'
concerns
with
looking
for
a
threshold
level
for
carcinogens,
the
compliance
alternatives
only
apply
to
HCl
and
MN,
which
are
not
carcinogens.
Also,

regarding
the
concern
expressed
by
a
commenter
about
exempting
a
facility
based
on
limited
emission
data
if
EPA
established
a
subcategory
listing
low­
risk
sources,
we
have
not
used
section
112(
c)(
9)
authority
to
establish
a
low­
risk
subcategory
for
the
Industrial/
Commercial/
Institutional
Boilers
and
Process
Heaters
source
category.
With
respect
to
guidance
for
performing
site­
specific
modeling,
all
of
the
procedures
for
performing
such
modeling
are
available
in
peer­
reviewed
scientific
literature,
and
therefore,
no
additional
guidance
needs
to
be
developed.

Only
a
portion
of
the
major
facilities
in
the
large
solid
fuel­
fired
boilers
and
process
heaters
subcategory
will
submit
eligibility
demonstrations
for
the
compliance
alternatives.
Of
this
portion
of
major
sources,
we
believe
that
most
will
be
able
to
demonstrate
eligibility
based
on
simple
analyses
(
e.
g.,
using
the
look­
up
tables
provided
in
Appendix
A).
However,
it
is
likely
that
some
facilities
will
require
more
detailed
modeling.
The
criteria
for
demonstrating
eligibility
for
the
compliance
alternatives
are
clearly
spelled
out
in
the
final
rule.
Because
these
requirements
are
clearly
spelled
out
and
because
any
standards
or
requirements
created
under
section
112
are
154
considered
applicable
requirements
under
part
70,
the
compliance
alternatives
would
be
incorporated
into
Title
V
programs,
and
States
would
not
have
to
overhaul
existing
permitting
programs.

Finally,
with
respect
to
the
burden
associated
with
ongoing
assurance
that
facilities
which
opt
to
do
so
continue
to
comply
with
the
health­
based
compliance
alternatives,
the
burden
to
States
will
be
minimal.
Rather
than
developing
detailed
recordkeeping
and
reporting
requirements
for
facilities
that
initially
qualify
for
the
health­
based
compliance
alternatives,
we
are
requiring
periodic
review
of
the
compliance
demonstration
and
certification
that
the
affected
source
still
qualifies
for
the
alternatives
every
five
years
to
ensure
continuing
compliance.
Additionally,
before
changing
key
parameters
that
may
impact
an
affected
source's
ability
to
continue
to
meet
one
or
both
of
the
health­
based
emission
standards,
the
affected
source
is
required
to
evaluate
it
ability
to
continue
to
comply
with
the
health­
based
emission
standard(
s)
and
submit
documentation
to
the
permitting
authority
supporting
continued
eligibility
for
the
compliance
alternative.
Finally,
in
accordance
with
the
provisions
of
Title
V
of
the
Clean
Air
Act
and
part
70
of
40
CFR
(
collectively
"
Title
V"),
the
owner
or
operator
of
any
affected
source
opting
to
comply
with
the
health­
based
155
emission
standards
will
be
required
to
certify
compliance
with
those
standards
on
an
annual
basis.

The
EPA
believes
that
the
promulgation
of
specific
alternative
health­
based
emission
limits
and
a
uniform
methodology
for
demonstrating
compliance
with
those
alternatives
alleviates
any
concern
regarding
the
public
process
required
in
reviewing/
approving
the
proposed
approaches
and
making
substantial
changes
to
existing
regulations.
It
also
addresses
concerns
regarding
the
costs
and
resources
associated
with
assuring
adequate
public
participation
in
the
process
of
reviewing
site­
specific
risk
analyses.

To
ensure
that
affected
sources
which
choose
to
comply
with
the
alternative
health­
based
emission
standards
continue
to
comply
with
those
standards
after
the
initial
compliance
demonstration,
specified
assessment
parameters
(
e.
g.,
HCL
and/
or
manganese
emission
rate,
boiler
heat
output,
etc.)
must
be
included
in
their
Title
V
permit
as
enforceable
requirements.
Draft
permits
and
permit
applications
must
be
made
available
from
the
state
or
local
agency
responsible
for
issuing
the
permit,
or
in
the
case
where
EPA
is
issuing
the
permit,
from
the
EPA
regional
office.
Members
of
the
public
may
request
that
the
state
or
local
agency
include
them
on
their
public
notice
mailing
list,
thus
providing
the
public
the
opportunity
to
review
156
the
appropriateness
of
these
requirements.
Every
proposed
Title
V
permit
has
a
30
day
public
comment
period
and
a
45
day
EPA
review
period.
If
EPA
does
not
object
to
the
permit,
any
member
of
the
public
may
petition
EPA
to
object
to
the
permit
within
60
days
of
the
end
of
the
EPA
review
period.

We
acknowledge
the
comments
regarding
comments
submitted
by
others.
However,
we
will
respond
to
those
specific
comments
submitted
by
others
rather
than
agreeing
or
disagreeing
with
one
commenter's
assessment
of
another's
comments.

V.
Impacts
of
the
Final
Rule
A.
What
are
the
air
impacts?

Table
2
of
this
preamble
illustrates,
for
each
subcategory,
the
emissions
reductions
achieved
by
the
final
rule
(
i.
e.,
the
difference
in
emissions
between
a
boiler
or
process
heater
controlled
to
the
floor
level
of
control
and
boilers
or
process
heaters
at
the
current
baseline)
for
new
and
existing
sources.
The
estimates
in
Table
2
regarding
reductions
in
HAP
and
criteria
pollutant
emissions
will
necessarily
be
affected
by
the
extent
to
which
sources
demonstrate
eligibility
for
the
health­
based
compliance
alternatives.

Nationwide
emissions
of
selected
HAP
(
i.
e.,
HCl,
157
hydrogen
fluoride,
lead,
and
nickel)
will
be
reduced
by
58,500
tpy
for
existing
units
and
73
tpy
for
new
units.

Depending
on
the
number
of
facilities
demonstrating
eligibility
for
the
health­
based
compliance
alternatives,

the
total
HAP
reduction
for
existing
units
could
fall
to
50,600
tpy.
Emissions
of
HCl
will
be
reduced
by
42,000
tpy
for
existing
units
and
72
tpy
for
new
units.
Depending
on
the
number
of
facilities
demonstrating
eligibility
for
the
health­
based
compliance
alternatives,
the
total
HCl
emissions
reduction
for
existing
units
could
fall
to
36,400
tpy.
Emissions
of
mercury
will
be
reduced
by
1.9
tpy
for
existing
units
and
0.006
tpy
for
new
units.
Emissions
of
PM
will
be
reduced
by
565,000
tpy
for
existing
units
and
480
tpy
for
new
units.
Depending
on
the
number
of
facilities
demonstrating
eligibility
for
the
health­
based
compliance
alternatives,
the
total
PM
emissions
reduction
for
existing
units
could
fall
to
547,000
tpy.
Emissions
of
total
selected
nonmercury
metals
(
i.
e.,
arsenic,
beryllium,

cadmium,
chromium,
lead,
manganese,
nickel,
and
selenium)

will
be
reduced
by
1,100
tpy
for
existing
units
and
will
be
reduced
by
1.4
tpy
for
new
units.
Depending
on
the
number
of
facilities
demonstrating
eligibility
for
the
health­
based
compliance
alternatives,
the
total
nonmercury
metals
emissions
reduction
for
existing
units
could
fall
to
950
tpy.
In
addition,
emissions
of
sulfur
dioxide
are
158
established
to
be
reduced
by
113,000
tpy
for
existing
sources
and
110
tpy
for
new
sources.
Depending
on
the
number
of
facilities
demonstrating
eligibility
for
the
health­
based
compliance
alternatives,
the
total
sulfur
dioxide
emissions
reduction
for
existing
units
could
fall
to
49,000
tpy.

A
discussion
of
the
methodology
used
to
estimate
emissions
and
emissions
reductions
is
presented
in
"
Estimation
of
Baseline
Emissions
and
Emissions
Reductions
for
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters"
in
the
docket.
To
estimate
the
potential
impacts
of
the
health­
based
compliance
alternatives,
we
performed
a
preliminary
"
rough"
assessment
of
the
large
solid
fuel
subcategory
to
determine
the
extent
to
which
facilities
might
become
eligible
for
the
health­
based
compliance
alternatives.
Based
on
the
results
of
this
rough
assessment,
448
coal­
fired
boilers
could
potentially
be
eligible
for
the
HCl
compliance
alternative
and
386
biomassfired
boilers
could
be
potentially
eligible
for
the
TSM
compliance
alternative.

TABLE
2.
SUMMARY
OF
EMISSIONS
REDUCTIONS
FOR
EXISTING
AND
NEW
SOURCES
(
TPY)

Source
Subcategory
HCl
PM
Non
Mercury
Metalsa
Mercury
Existing
Units
Large
solid
units
42,100
560,000
1,100
2
159
Small
solid
units
0
0
0
0
Limited
use
solid
units
0
2,800
8
0.002
Liquid
units
0
0
0
0
Gaseous
units
0
0
0
0
New
Units
Large
solid
units
70
31
0.01
0.006
Small
solid
units
2.4
440
1.4
0.0006
Limited
use
solid
units
0.2
11
0.02
0.00002
Liquid
units
0
0
0
0
Gaseous
units
0
0
0
0
a
Includes
arsenic,
beryllium,
cadmium,
chromium,
lead,
manganese,
nickel,
and
selenium.

Our
estimates
regarding
reductions
in
HAP
and
criteria
pollutant
emissions
will
necessarily
be
affected
by
the
extent
to
which
sources
demonstrate
eligibility
for
the
health­
based
compliance
alternatives.

B.
What
are
the
water
and
solid
waste
impacts?

The
EPA
estimates
the
additional
water
usage
that
would
result
from
the
MACT
floor
level
of
control
to
be
110
million
gallons
per
year
for
existing
sources
and
0.6
million
gallons
per
year
for
new
sources.
In
addition
to
the
increased
water
usage,
an
additional
3.7
million
gallons
per
year
of
wastewater
will
be
produced
for
existing
sources
160
and
0.6
million
gallons
per
year
for
new
sources.
The
costs
of
treating
the
additional
wastewater
are
$
18,000
for
existing
sources
and
$
2,300
for
new
sources,
in
advance
of
any
facility
demonstrating
eligibility
for
the
health­
based
provisionscompliance
alternatives.
These
costs
are
accounted
for
in
the
control
costs
estimates.

The
EPA
estimates
the
additional
solid
waste
that
would
result
from
the
MACT
floor
level
of
control
to
be
102,000
tpy
for
existing
sources
and
1
tpy
for
new
sources.
The
estimated
costs
of
handling
the
additional
solid
waste
generated
are
$
1.5
million
for
existing
sources
and
$
17,000
for
new
sources,
in
advance
of
any
facility
demonstrating
eligibility
for
the
health­
based
provisionscompliance
alternatives.
These
costs
are
also
accounted
for
in
the
control
costs
estimates.

A
discussion
of
the
methodology
used
to
estimate
impacts
is
presented
in
"
Estimation
of
Impacts
for
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
NESHAP"
in
the
docket.

C.
What
are
the
energy
impacts?

The
EPA
expects
an
increase
of
approximately
1,130
million
kilowatt
hours
(
kWh)
in
national
annual
energy
usage
as
a
result
of
the
final
rule,
in
advance
of
any
facility
demonstrating
eligibility
for
the
health­
based
provisionscompliance
alternatives.
Of
this
amount,
1,120
161
million
kWh
is
estimated
from
existing
sources
and
13
million
kWh
is
estimated
from
new
sources.
The
increase
results
from
the
electricity
required
to
operate
control
devices
installed
to
meet
the
final
rule,
such
as
wet
scrubbers
and
fabric
filters.

D.
What
are
the
control
costs?

To
estimate
the
national
cost
impacts
of
the
final
rule
for
existing
sources,
EPA
developed
several
model
boilers
and
process
heaters
and
determined
the
cost
of
control
equipment
for
these
model
boilers.
The
EPA
assigned
a
model
boiler
or
heater
to
each
existing
unit
in
the
database
based
on
the
fuel,
size,
design,
and
current
controls.
The
analysis
considered
all
air
pollution
control
equipment
currently
in
operation
at
existing
boilers
and
process
heaters.
Model
costs
were
then
assigned
to
all
existing
units
that
could
not
otherwise
meet
the
proposed
emission
limits.
The
resulting
total
national
cost
impact
of
the
final
rule
is
$
1,790
million
in
capital
expenditures
and
$
860
million
per
year
in
total
annual
costs,
in
advance.

Depending
on
the
number
of
any
facility
facilities
demonstrating
eligibility
for
the
health­
based
provisionscompliance
alternatives,
these
costs
could
fall
to
$
1,440
million
in
capital
expenditures
and
$
690
million
per
year
in
total
annual
costs.
The
total
capital
and
annual
costs
include
costs
for
testing,
monitoring,
and
162
recordkeeping
and
reporting.
Table
3
of
this
preamble
shows
the
capital
and
annual
cost
impacts
for
each
subcategory.

Costs
include
testing
and
monitoring
costs,
but
not
recordkeeping
and
reporting
costs.
The
costs
estimates
in
Table
3
do
not
reflect
the
extent
to
which
sources
become
eligible
for
the
health­
based
compliance
alternatives.

TABLE
3.
SUMMARY
OF
CAPITAL
AND
ANNUAL
COSTS
FOR
NEW
AND
EXISTING
SOURCES
Source
Subcategory
Estimated/
Projected
No.
of
Affected
Units
Annualized
Cost
(
106$/
yr)
Capital
Costs
(
106$)

Existing
Units
Large
solid
units
3,481
814
1,605
Small
solid
units
327
0
0
Limited
use
solid
units
249
23
105
Liquid
units
7,251
0
0
Gaseous
units
46,892
0
0
New
Units
Large
solid
units
211
10
21
Small
solid
units
25
3
3
Limited
use
solid
units
11
1
1
Large
liquid
units
90
1
3
Small
liquid
units
164
0
0
163
Limited
use
liquid
units
51
0.3
2
Gaseous
units
3,463
11
51
Using
Department
of
Energy
projections
on
fuel
expenditures,
EPA
estimated
the
number
of
additional
boilers
that
could
be
potentially
constructed.
The
resulting
total
national
cost
impact
of
the
final
rule
in
the
5th
year
is
$
58
million
in
capital
expenditures
and
$
18.6
million
per
year
in
total
annual
costs,
in
advance
of
any
facility
demonstrating
eligibility
for
the
health­
based
provisions.

Costs
are
mainly
for
testing
and
monitoring.

A
discussion
of
the
methodology
used
to
estimate
cost
impacts
is
presented
in
"
Methodology
and
Results
of
Estimating
the
Cost
of
Complying
with
the
Industrial,

Commercial,
and
Institutional
Boiler
and
Process
Heater
NESHAP"
in
the
docket.

E.
What
are
the
economic
impacts?

The
economic
impact
analysis
shows
that
the
expected
price
increase
for
output
in
the
40
affected
industries
would
be
no
more
than
0.04
percent
as
a
result
of
the
final
rule
for
industrial
boilers
and
process
heaters.
The
expected
change
in
production
of
affected
output
is
a
reduction
of
only
0.03
percent
or
less
in
the
same
164
industries.
In
addition,
impacts
to
affected
energy
markets
show
that
prices
of
petroleum,
natural
gas,
electricity
and
coal
should
increase
by
no
more
than
0.05
percent
as
a
result
of
implementation
of
the
final
rule,
and
output
of
these
types
of
energy
should
decrease
by
no
more
than
0.01
percent.
These
impacts
are
generated
in
advance
of
any
facility
demonstrating
eligibility
for
the
health­
based
provisions.
Therefore,
it
is
likely
that
there
is
no
adverse
impact
expected
to
occur
for
those
industries
that
produce
output
affected
by
the
final
rule,
such
as
lumber
and
wood
products,
chemical
manufacturers,
petroleum
refining,
and
furniture
manufacturing.

F.
What
are
the
social
costs
and
benefits
of
the
final
rule?

Our
assessment
of
costs
and
benefits
of
the
final
rule
is
detailed
in
the
"
Regulatory
Impact
Analysis
for
the
Final
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
MACT."
The
Regulatory
Impact
Analysis
(
RIA)

is
located
in
the
Docket.

It
is
estimated
that
3
years
after
implementation
of
the
final
rule,
HAP
will
be
reduced
by
58,500
tpy
(
53,200
megagrams
per
year
(
Mg/
yr))
due
to
reductions
in
arsenic,

beryllium,
HCl,
and
several
other
HAP
from
existing
affected
emission
sources.
Of
these
reductions,
42,000
tpy
(
38,200
Mg/
yr)
are
of
HCl.
In
addition
to
these
reductions,
there
165
are
73
tpy
(
66
Mg/
yr)
of
HAP
reductions
expected
from
new
sources.
Of
these
reductions,
virtually
all
of
them
are
of
HCl.
The
health
effects
associated
with
these
HAP
are
discussed
earlier
in
this
preamble.
While
it
is
beneficial
to
society
to
reduce
these
HAP,
we
are
unable
to
quantify
and
provide
a
monetized
estimate
of
the
benefits
at
this
time.

Despite
our
inability
to
quantify
and
provide
monetized
benefit
estimates
from
HAP
reductions,
it
is
possible
to
derive
rough
estimates
for
one
of
the
more
important
benefit
categories,
i.
e.,
the
potential
number
of
cancer
cases
avoided
and
cancer
risk
reduced
as
a
result
of
the
imposition
of
the
MACT
level
of
control
on
this
source
category.
Our
analysis
suggests
that
imposition
of
the
MACT
level
of
control
would
reduce
cancer
cases
by
possibly
tens
of
cases
per
year,
on
average,
starting
some
years
after
implementation
of
the
final
rule.
This
risk
reduction
estimate
is
uncertain
and
should
be
regarded
as
an
extremely
rough
estimate,
and
should
be
viewed
in
the
context
of
the
full
spectrum
of
unquantified
noncancer
effects
associated
with
the
HAP
reductions.
Noncancer
effects
associated
with
the
HAP
are
presented
earlier
in
this
preamble.

The
control
technologies
used
to
reduce
the
level
of
HAP
emitted
from
affected
sources
are
also
expected
to
reduce
emissions
of
PM
(
PM10,
PM2.5),
and
sulfur
dioxide
166
(
SO2).
It
is
estimated
that
PM10
emissions
reductions
total
approximately
562,000
tpy
(
510,000
Mg/
yr),
PM2.5
emissions
reductions
total
approximately
159,000
tpy
(
145,000
Mg/
yr),

and
SO2
emissions
reductions
total
approximately
113,000
tpy
(
102,670
Mg/
yr).
These
estimated
reductions
occur
from
existing
sources
in
operation
3
years
after
the
implementation
of
the
requirements
of
the
final
rule
and
are
expected
to
continue
throughout
the
life
of
the
sources.

In
general,
exposure
to
high
concentrations
of
PM2.5
may
aggravate
existing
respiratory
and
cardiovascular
disease
including
asthma,
bronchitis
and
emphysema,
especially
in
children
and
the
elderly.
Nitrogen
oxides
and
SO2
are
also
contributors
to
acid
deposition,
or
acid
rain,
which
causes
acidification
of
lakes
and
streams
and
can
damage
trees,

crops,
historic
buildings
and
statues.
Exposure
to
PM2.5
can
lead
to
decreased
lung
function,
and
alterations
in
lung
tissue
and
structure
and
in
respiratory
tract
defense
mechanisms
which
may
then
lead
to,
increased
respiratory
symptoms
and
disease,
or
in
more
severe
cases,
premature
death
or
increased
hospital
admissions
and
emergency
room
visits.
Children,
the
elderly,
and
people
with
cardiopulmonary
disease,
such
as
asthma,
are
most
at
risk
from
these
health
effects.
Fine
PM
can
also
form
a
haze
that
reduces
the
visibility
of
scenic
areas,
can
cause
acidification
of
water
bodies,
and
have
other
impacts
on
167
soil,
plants,
and
materials.
As
SO2
emissions
transform
into
PM,
they
can
lead
to
the
same
health
and
welfare
effects
listed
above.

Therefore,
for
PM10
and
PM2.5
(
including
SO2
contributions
to
ambient
concentrations
of
PM2.5),
we
provide
a
monetary
estimate
for
the
benefits
associated
with
the
reduction
in
emissions
associated
with
the
final
rule.

To
do
so,
we
conducted
an
air
quality
assessment
to
determine
the
change
in
ambient
concentrations
of
PM10
and
PM2.5
that
result
from
reductions
of
PM
and
SO2
at
existing
affected
facilities.
Unfortunately,
our
data
are
not
able
to
define
the
exact
location
of
the
reductions
for
every
affected
boiler
and
process
heater.
Because
of
this
limitation,
the
benefits
assessment
is
conducted
in
two
phases.
First,
an
air
quality
analysis
was
conducted
for
emissions
reductions
from
those
emissions
sources
that
have
an
known
link
to
a
specific
control
device,
which
represents
approximately
50
percent
of
the
total
emissions
reductions
mentioned
above.
Using
this
subset
of
information,
we
determined
the
air
quality
change
nationwide.
The
results
of
the
air
quality
assessment
served
as
input
to
a
model
that
estimates
the
total
monetary
value
of
benefits
of
the
health
effects
listed
above.
Total
benefits
associated
with
this
portion
of
the
analysis
(
in
phase
one)
are
$
8.2
billion
in
the
year
2005
(
presented
in
1998
dollars).
168
In
the
second
phase
of
our
analysis,
for
those
emissions
reductions
from
affected
sources
that
do
not
have
a
known
link
to
a
specific
control
device,
the
results
of
the
air
quality
analysis
in
phase
one
serve
as
a
reasonable
approximation
of
air
quality
changes
to
transfer
to
the
remaining
emissions
reductions
of
the
final
rule.
Because
there
is
not
a
reasonable
way
to
apportion
the
total
benefits
of
the
combined
impact
of
the
PM
and
SO2
reductions
from
the
air
quality
and
benefit
analyses
completed
above,

we
performed
two
additional
air
quality
analyses.
One
analysis
was
performed
to
evaluate
the
impact
on
air
quality
of
the
PM
reductions
alone
(
holding
SO2
unchanged),
and
one
to
evaluate
the
impact
on
air
quality
from
the
SO2
reductions
alone
(
holding
PM
unchanged).
With
independent
PM
and
SO2
air
quality
assessments,
we
can
determine
the
total
benefit
associated
with
each
component
of
total
pollutant
reductions.
The
total
benefit
associated
with
the
PM
and
SO2
reductions
with
unspecified
location
(
in
phase
two)
are
$
7.9
billion.

The
benefit
estimates
derived
from
the
air
quality
modeling
in
the
first
phase
of
our
analysis
uses
an
analytical
structure
and
sequence
similar
to
that
used
in
the
benefits
analyses
for
the
proposed
Nonroad
Diesel
rule
and
proposed
Integrated
Air
Quality
Rule
(
IAQR)
and
in
the
"
section
812
studies"
analysis
of
the
total
benefits
and
169
costs
of
the
Clean
Air
Act.
We
used
many
of
the
same
models
and
assumptions
used
in
the
Nonroad
Diesel
and
IAQR
analyses
as
well
as
other
Regulatory
Impact
Analyses
(
RIAs)
prepared
by
the
Office
of
Air
and
Radiation.
By
adopting
the
major
design
elements,
models,
and
assumptions
developed
for
the
section
812
studies
and
other
RIAs,
we
have
largely
relied
on
methods
which
have
already
received
extensive
review
by
the
independent
Science
Advisory
Board
(
SAB),
the
National
Academies
of
Sciences,
by
the
public,
and
by
other
federal
agencies.

The
benefits
transfer
method
used
in
the
second
phase
of
the
analysis
is
similar
to
that
used
to
estimate
benefits
at
the
proposal
of
this
rule,
and
in
the
proposed
Reciprocating
Internal
Combustion
Engines
NESHAP.
A
similar
method
has
also
been
used
in
recent
benefits
analyses
for
the
proposed
Nonroad
Large
Spark­
Ignition
Engines
and
Recreational
Engines
standards
(
67
FR
68241,
November
8,

2002).

The
sum
of
benefits
from
the
two
phases
of
analysis
provide
an
estimate
of
the
total
benefits
of
the
rule,
as
presented
in
Table
5
below.
Total
benefits
of
the
final
rule
are
approximately
$
16.3
billion
(
1999$).
This
economic
benefit
is
associated
with
approximately
2,270
avoided
premature
mortalities,
5,100
avoided
cases
of
chronic
bronchitis,
xxxx
avoided
non­
fatal
heart
attacks,
thousands
170
of
avoided
hospital
and
emergency
room
visits
for
respiratory
and
cardiovascular
diseases,
tens
of
thousands
of
avoided
days
with
respiratory
symptoms,
and
millions
of
avoided
work
loss
and
restricted
activity
days.
This
estimate
is
generated
in
advance
of
any
facility
demonstrating
eligibility
for
the
health­
based
provisions.

Table
5.
Estimate
of
Total
Annual
Benefits
of
the
Industrial
Boilers/
Process
Heaters
NESHAPA
Endpoint
Avoided
Incidenc
eB
(
cases/
y
ear)
Monetary
BenefitsC
(
millions
1999$,

adjusted
for
growth
in
real
income)

Premature
mortalityD
(
long­
term
exposure,
adults,
30
and
over)
2,270
$
14,240
Chronic
bronchitis
(
adults,
26
and
over,
WTP
valuation)
5,100
$
1,835
Hospital
Admissions
 
Pneumonia
(
adults,
over
64)
1,100
$
15
Hospital
Admissions
 
COPD
(
adults,

64
and
over)
900
$
10
Hospital
Admissions
 
Asthma
(
65
230
<$
5
171
and
younger)

Hospital
Admissions
 
Cardiovascular
(
adults,
over
64)
2,660
$
50
Emergency
Room
Visits
for
Asthma
(
65
and
younger)
2,040
<$
1
Asthma
Attacks
(
asthmatics,
all
ages)
173,490
B1
Acute
bronchitis
(
children,
8­
12)
4,700
<$
1
Lower
respiratory
symptoms
(
children,
7­
14)
51,240
$
1
Upper
respiratory
symptoms
(
asthmatic
children,
10­
11)
196,860
$
5
Work
loss
days
(
adults,
18­
65)
398,670
$
40
Minor
restricted
activity
days
(
adults,
age
18­
65)
1,942,34
0
$
100
Other
PM­
related
health
effects
E
U1
B2
HAP­
related
health
effectsE
U2
B3
Total
Monetized
Health­
Related
BenefitsF
 
$
16,300+
BH
A
The
results
presented
in
this
table
include
all
emission
reductions
including
those
identified
for
specific
sources
included
in
the
Inventory
Database
included
in
the
Phase
One
analysis
and
the
remaining
reductions
not
included
in
the
Inventory
Database
included
in
the
Phase
Two
analysis
B
Incidences
are
rounded
to
the
nearest
10
and
may
not
add
due
to
rounding.
Incidences
of
unquantified
endpoints
are
indicated
with
a
U.
C
Dollar
values
are
rounded
to
the
nearest
5
million
and
may
not
add
due
to
rounding.
The
value
of
unquantified
endpoints
are
indicated
with
a
B.
D
The
estimated
value
for
PM­
related
premature
mortality
assumes
a
5­
year
distributed
lag
structure
and
discounted
at
a
3%
rate,
which
is
described
in
the
Heavy
Duty
Diesel
RIA.
172
E
A
detailed
listing
of
unquantified
PM
and
HAP
related
health
effects
is
provided
in
Table
6.

Every
benefit­
cost
analysis
examining
the
potential
effects
of
a
change
in
environmental
protection
requirements
is
limited,
to
some
extent,
by
data
gaps,
limitations
in
model
capabilities
(
such
as
geographic
coverage),
and
uncertainties
in
the
underlying
scientific
and
economic
studies
used
to
configure
the
benefit
and
cost
models.

Deficiencies
in
the
scientific
literature
often
result
in
the
inability
to
estimate
changes
in
health
and
environmental
effects.
Deficiencies
in
the
economics
literature
often
result
in
the
inability
to
assign
economic
values
even
to
those
health
and
environmental
outcomes
that
can
be
quantified.
While
these
general
uncertainties
in
the
underlying
scientific
and
economics
literatures
are
discussed
in
detail
in
the
RIA
and
its
supporting
documents
and
references,
the
key
uncertainties
which
have
a
bearing
on
the
results
of
the
benefit­
cost
analysis
of
today's
action
are
the
following:

1.
The
exclusion
of
potentially
significant
benefit
categories
(
e.
g.,
health
and
ecological
benefits
of
reduction
in
hazardous
air
pollutants
emissions);

2.
Errors
in
measurement
and
projection
for
variables
such
as
population
growth;

3.
Uncertainties
in
the
estimation
of
future
year
173
emissions
inventories
and
air
quality;

4.
Uncertainties
associated
with
the
extrapolation
of
air
quality
monitoring
data
to
some
unmonitored
areas
required
to
better
capture
the
effects
of
the
standards
on
the
affected
population;

5.
Variability
in
the
estimated
relationships
of
health
and
welfare
effects
to
changes
in
pollutant
concentrations;
and
6.
Uncertainties
associated
with
the
benefit
transfer
approach.

Despite
these
uncertainties,
we
believe
the
benefitcost
analysis
provides
a
reasonable
indication
of
the
expected
economic
benefits
of
the
final
rule
under
a
given
set
of
assumptions.

Based
on
estimated
compliance
costs
(
control
+

administrative
costs
associated
with
Paperwork
Reduction
Act
requirements
associated
with
the
rule
and
predicted
changes
in
the
price
and
output
of
electricity),
the
estimated
social
costs
of
the
Industrial
Boilers
and
Process
Heaters
NESHAP
are
$
863
million
(
1999$).
Social
costs
are
different
from
compliance
costs
in
that
social
costs
take
into
account
the
interactions
between
affected
producers
and
the
consumers
of
affected
products
in
response
to
the
imposition
of
the
compliance
costs.
In
this
action,
coal­
fired
utilities
are
the
affected
producers
and
users
of
174
electricity
are
the
consumers
of
the
affected
product.

As
explained
above,
we
estimate
$
16.3
billion
in
benefits
from
the
final
rule,
compared
to
$
863
million
in
costs.
It
is
important
to
put
the
results
of
this
analysis
in
the
proper
context.
The
large
benefit
estimate
is
not
attributable
to
reducing
human
and
environmental
exposure
to
the
HAPs
that
are
reduced
by
the
final
rule.
It
arises
from
ancillary
reductions
in
PM
and
SO2
that
result
from
controls
aimed
at
complying
with
the
NESHAP.
Although
consideration
of
ancillary
benefits
is
reasonable,
we
note
that
these
benefits
are
not
uniquely
attributable
to
the
regulation.

The
Agency
believes
nonetheless
that
the
key
rationale
for
controlling
arsenic,
beryllium,
HCl,
and
the
other
HAPs
associated
with
the
final
rule
is
to
reduce
public
and
environmental
exposure
to
these
HAPs,
thereby
reducing
risk
to
public
health
and
wildlife.
Although
the
available
science
does
not
support
quantification
of
these
benefits
at
this
time,
the
Agency
believes
the
qualitative
benefits
are
large
enough
to
justify
substantial
investment
in
these
emission
reductions.

It
should
be
recognized,
however,
that
this
analysis
does
not
account
for
many
of
the
potential
benefits
that
may
result
from
these
actions.
Thus,
our
estimate
of
total
benefits
also
includes
a
"
B"
to
represent
those
additional
health
and
environmental
benefits
which
could
not
be
175
expressed
in
quantitative
incidence
and/
or
economic
value
terms.
The
net
benefits
would
be
greater
if
all
the
benefits
of
the
other
pollutant
reductions
could
be
quantified.
Notable
omissions
to
the
net
benefits
include
all
benefits
of
HAP
reductions,
including
reduced
cancer
incidences,
toxic
morbidity
effects,
and
cardiovascular
and
CNS
effects,
and
all
welfare
effects
from
reduction
of
ambient
PM
and
SO2.
A
full
appreciation
of
the
overall
economic
consequences
of
the
industrial
boiler
and
process
heater
standards
requires
consideration
of
all
benefits
and
costs
expected
to
result
from
the
final
rule,
not
just
those
benefits
and
costs
that
could
be
expressed
here
in
dollar
terms.
A
full
listing
of
the
benefit
categories
that
could
not
be
quantified
or
monetized
in
our
base
estimate
are
provided
in
Table
6
of
this
preamble.

TABLE
6.
 
UNQUANTIFIED
BENEFIT
CATEGORIES
Unquantified
benefit
categories
associated
with
HAP
Unquantified
benefit
categories
associated
with
PM
176
Health
Categories
 
Airway
responsiveness
 
Pulmonary
inflammation
 
Increases
susceptibility
to
respiratory
infection
 
Acute
inflammation
and
respiratory
cell
damage
 
Chronic
respiratory
damage/
Premature
aging
of
lungs
 
Emergency
room
visits
for
asthma
 
Changes
in
pulmonary
function.
 
Morphological
changes.
Altered
host
defense
mechanisms
 
Cancer
 
Other
chronic
respiratory
disease
 
Emergency
room
visits
for
asthma
 
Emergency
visits
for
non­
asthma
respiratory
and
cardiovascular
causes
 
Lower
and
upper
respiratory
systems
 
Acute
bronchitis
 
Shortness
of
breath
 
Increased
school
absence
rates
 
Materials
damage
 
Damage
to
ecosystems
(
e.
g.,
acid
sulfate
deposition).
 
Nitrates
in
drinking
water
 
Visibility
in
recreational
and
residential
areas
Welfare
Categories
 
Ecosystem
and
vegetation
effects
 
Damage
to
urban
ornamentals
(
e.
g.
grass,
flowers,
shrubs,
and
trees
in
urban
areas)
 
Commercial
field
crops
 
Fruit
and
vegetable
crops
 
Reduced
yields
of
tree
seedlings,
commercial
and
noncommercial
forests
 
Damage
to
ecosystems
 
Materials
damage
Using
the
results
of
the
benefit
analysis,
we
can
use
benefit­
cost
comparison
(
or
net
benefits)
as
another
tool
to
evaluate
the
reallocation
of
society's
resources
needed
to
address
the
pollution
externality
created
by
the
operation
of
industrial
boilers
and
process
heaters.
The
additional
costs
of
internalizing
the
pollution
produced
at
major
sources
of
emissions
from
industrial
boilers
and
process
177
heaters
are
compared
to
the
improvement
in
society's
wellbeing
from
a
cleaner
and
healthier
environment.
Comparing
benefits
of
the
final
rule
to
the
costs
imposed
by
alternative
ways
to
control
emissions
optimally
identifies
a
strategy
that
results
in
the
highest
net
benefit
to
society.

In
the
final
rule,
we
include
only
one
option,
the
minimal
level
of
control
mandated
by
the
CAA,
or
the
MACT
floor.

Other
alternatives
that
lead
to
higher
levels
of
control
(
or
beyond­
the­
floor
alternatives)
lead
to
higher
estimates
of
benefits
net
of
costs,
but
also
lead
to
additional
economic
impacts,
including
more
substantial
impacts
to
small
entities.
For
more
details,
please
refer
to
the
RIA
for
the
final
rule.

Table
7
of
this
preamble
presents
a
summary
of
costs,

benefits,
and
net
benefits
(
i.
e.,
benefits
minus
costs).

Based
on
estimated
compliance
costs
associated
with
the
the
final
rule
are
$
863
million
(
1999
dollars).
This
estimate
of
social
cost
is
generated
in
advance
of
any
facility
demonstrating
eligibility
for
the
health­
based
provisions.

Social
costs
are
different
from
compliance
costs
in
that
social
costs
take
into
account
the
interactions
of
consumers
and
producers
of
affected
products
in
response
to
the
imposition
of
the
compliance
costs.
Therefore,
the
Agency's
estimate
of
monetized
benefits
net
of
costs
is
$
15.2
billion
+
B
(
1999
dollars)
in
2005.
178
TABLE
7.
 
ANNUAL
NET
BENEFITS
OF
THE
INDUSTRIAL
BOILERS
AND
PROCESS
HEATERS
NESHAP
IN
2005a
MACT
floor
(
million
1999$)

Social
Costsb
$
863
Social
Benefits:
b,
c
HAP­
related
health
and
welfare
benefits
Not
monetized
PM­
related
welfare
benefits
Not
monetized
SO2­
and
PM­
related
health
benefits:
$
16,100
+
B
Net
Benefits
(
Benefits
­
Costs):
c
$
15,235
+
B
a
All
costs
and
benefits
are
rounded
to
the
nearest
$
5
million.
Thus,
figures
presented
in
this
table
may
not
exactly
equal
benefit
and
cost
numbers
presented
in
earlier
sections
of
the
chapter.
b
Note
that
costs
are
the
total
costs
of
reducing
all
pollutants,
including
HAP
as
well
as
SO2
and
PM10.
Benefits
in
this
table
are
associated
only
with
PM
and
SO2
reductions.
c
Not
all
possible
benefits
or
disbenefits
are
quantified
and
monetized
in
this
analysis.
Potential
benefit
categories
that
have
not
been
quantified
and
monetized
are
listed
in
Table
8
 
13
of
the
RIA.
B
is
the
sum
of
all
unquantified
benefits
and
disbenefits.

G.
How
will
the
health­
based
provisions
reduce
impacts?

Today's
final
rule
contains
health­
based
provisions
establishing
eligibility
criteria
for
an
exemption
from
the
HCl
emission
limit
and
an
exclusion
from
including
manganese
in
the
total
selected
metals
emission
rate.
Therefore,
the
impacts
of
today's
final
rule
will
be
reduced.
The
reduction
in
costs,
environmental,
and
economic
impacts
associated
with
inclusion
of
the
health­
based
provisions
in
179
the
final
rule
are
summarized
in
this
section.

1.
Estimated
Number
of
Eligible
Facilities
To
estimate
the
potential
impact
of
the
health­
based
provisions,
EPA
performed
a
preliminary
"
rough"
assessment
of
the
large
solid
fuel
subcategory.
Based
on
the
results
of
this
rough
assessment,
448
coal­
fired
boilers
could
potentially
be
eligible
for
the
HCl
exemption
and
386
biomass­
fired
boilers
could
be
potentially
eligible
for
the
manganese
exclusion,
provided
these
assessments
are
confirmed
by
source­
specific
demonstrations.
The
difference
in
regulatory
impacts
due
to
inclusion
of
the
health­
based
provisions
in
the
final
rule
are
summarized
in
the
following
paragraphs.

Based
on
the
HCl
lookup
table,
facilities
with
less
than
587
million
Btu
per
hour
heat
input
of
coal
capacity
would
be
exempt
from
complying
with
the
HCl
emission
limit.

Assuming
2
boilers
per
facility
and
the
uncontrolled
HCl
emission
factor,
this
would
indicate
coal­
fired
boilers
below
250
million
Btu
per
hour
would
not
incur
any
control
costs.
Based
on
the
manganese
lookup
table,
facilities
with
less
than
84
million
Btu
per
hour
heat
input
of
wood
capacity
would
be
able
to
exclude
manganese
from
the
total
selected
metals
emission
rate.
Assuming
2
boilers
per
facility
and
controlled
with
cyclones,
this
would
indicate
wood­
fired
boilers
below
45
million
Btu
per
hour
would
not
180
incur
any
control
costs.

2.
Air
quality
impacts
We
estimate
that
the
total
HAP
emissions
reductions
estimate
provided
in
section
III.
B
will
decrease
by
5600
tons/
yr)
due
to
facilities
becoming
eligible
for
the
healthbased
provisions.
Therefore,
considering
the
impact
of
facilities
becoming
eligible
for
the
health­
based
provisions,
we
estimate
that
today's
final
rule
will
result
in
a
total
reduction
in
HAP
emissions
of
52,400
tons/
yr.

Including
the
health­
based
provisions
will
affect
the
estimates
of
criteria
pollutant
reductions
as
well.
We
estimate
that
PM
and
SO2
emissions
reductions
estimates
will
decrease
by
17,100
and
64,000
tons/
yr,
respectively.
As
a
result,
we
estimate
that
the
total
reduction
in
PM
and
SO2
emissions
will
be
approximately
549,000
and
49,000
tons/
yr,

respectively.

3.
Cost
impacts
Facilities
that
become
eligible
for
the
health­
based
provisions
will
not
need
to
install
APCD
to
comply
with
the
final
rule.
Therefore,
the
high­
end
estimated
costs
of
today's
final
rule
will
be
less
than
the
estimates
presented
in
section
V.
D
We
estimate
that
the
total
annualized
costs,

which
include
annualized
capital
costs
for
control
and
monitoring
equipment,
operation
and
maintenance
expenses,

and
recordkeeping
and
reporting
costs,
will
decrease
by
$
145
181
million.
Therefore,
we
estimate
that
the
total
annualized
costs
of
the
final
rule
are
$
690
million.

4.
Economic
impacts
We
estimate
that
the
economic
impact
estimates
provided
in
section
V.
E
will
decrease
due
to
facilities
becoming
eligible
for
the
health­
based
provisions.
Annual
social
costs
will
decrease
by
$
117
million,
the
increases
in
product
prices
will
be
reduced
by
0.1
percent,
while
output
decreases
will
change
minimally.
Therefore,
considering
the
impact
of
facilities
becoming
eligible
for
the
health­
based
provisions,
we
estimate
that
today's
final
rule
will
result
in
estimated
annual
social
costs
of
$
746
million,
product
price
increases
of
no
more
than
0.4
percent,
and
decrease
in
output
of
less
than
0.1
percent.

5.
Social
costs
and
benefits
We
estimate
that
the
total
monetized
benefit
estimate
of
$
16.3
billion
(
provided
in
section
V.
F)
will
decrease
by
$
1.7
billion
($
1999)
due
to
facilities
becoming
eligible
for
the
health­
based
provisions.
Therefore,
considering
the
impact
of
facilities
becoming
eligible
for
the
health­
based
provisions,
we
estimate
that
today's
final
rule
will
result
in
total
monetized
benefits
of
$
14.5
billion
+
B
($
1999).

In
addition,
the
estimate
of
total
annualized
net
benefits
(
benefits
­
social
costs)
will
decrease
by
$
1.6
billion.

Therefore,
we
estimate
that
the
total
annualized
net
182
benefits
of
the
final
rule
are
$
13.8
billion
+
B
($
1999).

VI.
Administrative
and
Executive
Order
Reviews
A.
Executive
Order
12866:
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,

1993),
the
EPA
must
determine
whether
a
regulatory
action
is
"
significant"
and,
therefore,
subject
to
review
by
the
OMB
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
"
significant
regulatory
action"
as
one
that
is
likely
to
result
in
a
rule
that
may:

(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,
competition,
jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
tribal
governments
or
communities;

(
2)
create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;

(
3)
materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs,
or
the
rights
and
obligation
of
recipients
thereof;
or
(
4)
raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.

Pursuant
to
the
terms
of
Executive
Order
12866,
the
EPA
has
determined
that
the
final
rule
is
a
"
significant
183
regulatory
action"
because
it
has
an
annual
effect
on
the
economy
of
over
$
100
million.
As
such,
the
final
rule
was
submitted
to
OMB
for
review.

B.
Paperwork
Reduction
Act
The
information
collection
requirements
in
the
final
rule
have
been
submitted
for
approval
to
the
Office
of
Management
and
Budget
(
OMB)
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
The
information
collection
requirements
are
not
enforceable
until
OMB
approves
them.

The
information
requirements
are
based
on
notification,

recordkeeping,
and
reporting
requirements
in
the
NESHAP
General
Provisions
(
40
CFR
part
63,
subpart
A),
which
are
mandatory
for
all
operators
subject
to
national
emission
standards.
These
recordkeeping
and
reporting
requirements
are
specifically
authorized
by
section
114
of
the
CAA
(
42
U.
S.
C.
7414).
All
information
submitted
to
EPA
pursuant
to
the
recordkeeping
and
reporting
requirements
for
which
a
claim
of
confidentiality
is
made
is
safeguarded
according
to
Agency
policies
set
forth
in
40
CFR
part
2,
subpart
B.

The
final
rule
requires
maintenance
inspections
of
the
control
devices,
but
does
not
require
any
notifications
or
reports
beyond
those
required
by
the
General
Provisions.

The
recordkeeping
requirements
require
only
the
specific
information
needed
to
determine
compliance.

The
annual
monitoring,
reporting,
and
recordkeeping
184
burden
for
this
collection
(
averaged
over
the
first
3
years
after
the
effective
date
of
the
standards)
is
estimated
to
be
$
165
million.
This
includes
2.7
million
labor
hours
per
year
at
a
total
labor
cost
of
$
142
million
per
year,
and
total
non­
labor
capital
costs
of
$
24
million
per
year.
This
estimate
includes
a
one­
time
performance
test,
semiannual
excess
emission
reports,
maintenance
inspections,

notifications,
and
recordkeeping.
The
total
burden
for
the
Federal
government
(
averaged
over
the
first
3
years
after
the
effective
date
of
the
standard)
is
estimated
to
be
346,000
hours
per
year
at
a
total
labor
cost
of
$
14
million
per
year.

Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,

or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,

validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
185
disclose
the
information.

An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9.
When
this
ICR
is
approved
by
OMB,
the
Agency
will
publish
a
technical
amendment
to
40
CFR
part
9
in
the
Federal
Register
to
display
the
OMB
control
number
for
the
approved
information
collection
requirements
contained
in
this
final
rule.

The
EPA
requested
comments
on
the
need
for
this
information,
the
accuracy
of
the
provided
burden
estimates,

and
any
suggested
methods
for
minimizing
respondent
burden,

including
through
the
use
of
automated
collection
techniques.

C.
Regulatory
Flexibility
Act
The
EPA
has
determined
that
it
is
not
necessary
to
prepare
a
regulatory
flexibility
analysis
in
connection
with
the
final
rule.
We
have
also
determined
that
the
final
rule
will
not
have
a
significant
impact
on
a
substantial
number
of
small
entities.

For
purposes
of
assessing
the
impacts
of
the
final
rule
on
small
entities,
small
entity
is
defined
as:

(
1)
A
small
business
according
to
Small
Business
Administration
size
standards
by
the
North
American
Industry
186
Classification
System
(
NAICS)
category
of
the
owning
entity.

The
range
of
small
business
size
standards
for
the
40
affected
industries
ranges
from
500
to
1,000
employees,

except
for
petroleum
refining
and
electric
utilities.
In
these
latter
two
industries,
the
size
standard
is
1,500
employees
and
a
mass
throughput
of
75,000
barrels/
day
or
less,
and
4
million
kilowatt­
hours
of
production
or
less,

respectively;

(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not­
for­
profit
enterprise
that
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.

After
considering
the
economic
impact
of
the
final
rule
on
small
entities,
we
have
determined
that
the
final
rule
will
not
have
a
significant
impact
on
a
substantial
number
of
small
entities.
Based
on
SBA
size
definitions
for
the
affected
industries
and
reported
sales
and
employment
data,

EPA
identified
185
of
the
576
entities,
or
32
percent,

owning
affected
facilities
as
small
entities.
Although
small
entities
represent
32
percent
of
the
entities
within
the
source
category,
they
are
expected
to
incur
only
4
percent
of
the
total
compliance
costs
of
$
862.7
million
(
1998
dollars).
There
are
only
ten
small
entities
with
187
compliance
costs
equal
to
or
greater
than
3
percent
of
their
sales.
In
addition,
there
are
only
24
small
entities
with
cost­
to­
sales
ratios
between
1
and
3
percent.

An
economic
impact
analysis
was
performed
to
estimate
the
changes
in
product
price
and
production
quantities
for
the
final
rule.
As
mentioned
in
the
summary
of
economic
impacts
earlier
in
this
preamble,
the
estimated
changes
in
prices
and
output
for
affected
entities
is
no
more
than
0.05
percent.

This
analysis
indicates
that
the
final
rule
should
not
generate
a
significant
impact
on
a
substantial
number
of
small
entities
for
following
reasons.
First,
there
are
only
34
small
entities
(
or
18
percent
of
all
affected
small
entities)
with
compliance
costs
equal
to
or
greater
than
1
percent
of
their
sales.
Of
these,
only
ten
small
entities
(
or
5
percent
of
all
affected
small
entities)
with
compliance
costs
equal
to
or
greater
than
3
percent
of
their
sales.
Second,
the
results
of
the
economic
impact
analysis
show
minimal
impacts
on
prices
and
output
from
affected
firms,
including
small
entities,
due
to
the
implementation
of
the
final
rule.
This
analysis,
therefore,
allows
us
to
certify
that
there
will
not
be
a
significant
impact
on
a
substantial
number
of
small
entities
from
the
implementation
of
the
final
rule.
For
more
information,
consult
the
docket
for
the
final
rule.
188
It
should
be
noted
that
these
small
entity
impacts
are
in
advance
of
any
facility
demonstrating
eligibility
for
the
health­
based
provisions.
The
estimated
changes
in
small
entity
impacts
associated
with
consideration
of
the
healthbased
provisions
are:
a
reduction
of
2
small
entities
with
compliance
costs
equal
to
or
greater
than
3
percent
of
their
sales,
and
a
reduction
of
10
small
entities
with
compliance
costs
between
1
and
3
percent
of
their
sales.
Therefore,

the
small
entity
impacts
associated
with
the
health­
based
provisions
are
8
small
entities
with
compliance
costs
equal
to
or
greater
than
3
percent
of
their
sales,
and
14
small
entities
with
compliance
costs
between
1
and
3
percent
of
their
sales.

The
final
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities
as
a
result
of
several
decisions
EPA
made
regarding
the
development
of
the
rule,
which
resulted
in
limiting
the
impact
of
the
rule
on
small
entities.
First,
as
mentioned
earlier
in
this
preamble,
EPA
identified
small
units
(
heat
input
of
10
MMBtu/
hr
or
less)
and
limited
use
boilers
(
operate
less
than
10
percent
of
the
time)
as
separate
subcategories
different
from
large
units.
Many
small
and
limited
use
units
are
located
at
small
entities.
As
also
discussed
earlier,
the
results
of
the
MACT
floor
analysis
for
these
subcategories
of
existing
sources
was
that
no
MACT
floor
could
be
189
identified
except
for
the
limited
use
solid
fuel
subcategory,
which
is
less
stringent
than
the
MACT
floor
for
large
units.
Furthermore,
the
results
of
the
beyond­

thefloor
analysis
for
these
subcategories
indicated
that
the
costs
would
be
too
high
to
consider
them
feasible
options.

Consequently,
the
final
rule
contains
no
emission
limitations
for
any
of
the
existing
small
and
limited
use
subcategories
except
the
existing
limited
use
solid
fuel
subcategory.
In
addition,
the
alternative
metals
emission
limit
resulted
in
minimizing
the
impacts
on
small
entities
since
some
of
the
potential
entities
burning
a
fuel
containing
very
little
metals
are
small
entities.

D.
Unfunded
Mandates
Reform
Act
of
1995
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Public
Law
104­
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
we
generally
must
prepare
a
written
statement,
including
a
cost­
benefit
analysis,
for
proposed
and
final
rules
with
"
Federal
mandates"
that
may
result
in
expenditures
to
State,
local,

and
tribal
governments,
in
the
aggregate,
or
to
the
private
sector,
of
$
100
million
or
more
in
any
1
year.
Before
promulgating
a
rule
for
which
a
written
statement
is
needed,

section
205
of
the
UMRA
generally
requires
us
to
identify
190
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
cost­
effective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
us
to
adopt
an
alternative
other
than
the
least
costly,
most
cost­
effective
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
we
establish
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
we
must
develop
a
small
government
agency
plan
under
section
203
of
the
UMRA.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
regulatory
promulgation
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.

We
determined
that
the
final
rule
contains
a
Federal
mandate
that
may
result
in
expenditures
of
$
100
million
or
more
for
State,
local,
and
Tribal
governments,
in
the
aggregate,
or
the
private
sector
in
any
1
year.

Accordingly,
we
have
prepared
a
written
statement
(
titled
"
Unfunded
Mandates
Reform
Act
Analysis
for
the
Industrial
191
Boilers
and
Process
Heaters
NESHAP)"
under
section
202
of
the
UMRA,
which
is
summarized
below.

Statutory
Authority
As
discussed
in
section
I
of
this
preamble,
the
statutory
authority
for
the
final
rulemaking
is
section
112
of
the
CAA.
Title
III
of
the
CAA
Amendments
was
enacted
to
reduce
nationwide
air
toxic
emissions.
Section
112(
b)
of
the
CAA
lists
the
188
chemicals,
compounds,
or
groups
of
chemicals
deemed
by
Congress
to
be
HAP.
These
toxic
air
pollutants
are
to
be
regulated
by
NESHAP.

Section
112(
d)
of
the
CAA
directs
us
to
develop
NESHAP,

which
require
existing
and
new
major
sources
to
control
emissions
of
HAP
using
MACT
based
standards.
The
final
rule
applies
to
all
industrial,
commercial,
and
institutional
boilers
and
process
heaters
located
at
major
sources
of
HAP
emissions.

In
compliance
with
section
205(
a)
of
the
UMRA,
we
identified
and
considered
a
reasonable
number
of
regulatory
alternatives.
Additional
information
on
the
costs
and
environmental
impacts
of
these
regulatory
alternatives
is
presented
in
the
docket.

The
regulatory
alternative
upon
which
the
final
rule
is
based
represents
the
MACT
floor
for
industrial
boilers
and
process
heaters
and,
as
a
result,
it
is
the
least
costly
and
least
burdensome
alternative.
192
Social
Costs
and
Benefits
The
regulatory
impact
analysis
prepared
for
the
final
rule
including
the
EPA's
assessment
of
costs
and
benefits,
is
detailed
in
the
"
Regulatory
Impact
Analysis
for
the
Industrial
Boilers
and
Process
Heaters
MACT"
in
the
docket.

Based
on
estimated
compliance
costs
associated
with
the
final
rule
and
the
predicted
change
in
prices
and
production
in
the
affected
industries,
the
estimated
social
costs
of
the
final
rule
are
$
863
million
(
1999
dollars).

It
is
estimated
that
5
years
after
implementation
of
the
final
rule,
HAP
will
be
reduced
by
58,500
tpy
due
to
reductions
in
arsenic,
beryllium,
dioxin,
hydrochloric
acid,

and
several
other
HAP
from
industrial
boilers
and
process
heaters.
Studies
have
determined
a
relationship
between
exposure
to
these
HAP
and
the
onset
of
cancer,
however,

there
are
some
questions
remaining
on
how
cancers
that
may
result
from
exposure
to
these
HAP
can
be
quantified
in
terms
of
dollars.
Therefore,
the
EPA
is
unable
to
provide
a
monetized
estimate
of
the
benefits
of
the
HAP
reduced
by
the
final
rule
at
this
time.
However,
there
are
significant
reductions
in
PM
and
in
SO2
that
occur.
Reductions
of
560,000
tons
of
PM
with
a
diameter
of
less
than
or
equal
to
10
micrometers
(
PM10),
159,000
tons
of
PM
with
a
diameter
of
less
than
or
equal
to
2.5
micrometers
(
PM2.5),
and
112,000
tons
of
SO2
are
expected
to
occur.
These
reductions
occur
193
from
existing
sources
in
operation
5
years
after
the
implementation
of
the
regulation
and
are
expected
to
continue
throughout
the
life
of
the
affected
sources.
The
major
health
effect
that
results
from
these
PM
and
SO2
emissions
reductions
is
a
reduction
in
premature
mortality.

Other
health
effects
that
occur
are
reductions
in
chronic
bronchitis,
asthma
attacks,
and
work­
lost
days
(
i.
e.,
days
when
employees
are
unable
to
work).

While
we
are
unable
to
monetize
the
benefits
associated
with
the
HAP
emissions
reductions,
we
are
able
to
monetize
the
benefits
associated
with
the
PM
and
SO2
emissions
reductions.
For
SO2
and
PM,
we
estimated
the
benefits
associated
with
health
effects
of
PM,
but
were
unable
to
quantify
all
categories
of
benefits
(
particularly
those
associated
with
ecosystem
and
environmental
effects).

Unquantified
benefits
are
noted
with
"
B"
in
the
estimates
presented
below.
Our
primary
estimate
of
the
monetized
benefits
in
2005
associated
with
the
implementation
of
the
proposed
alternative
is
$
16.3
billion
+
B
(
1999
dollars).

This
estimate
is
about
$
15.3
billion
+
B
(
1999
dollars)

higher
than
the
estimated
social
costs
shown
earlier
in
this
section.
These
benefit
estimates
are
in
advance
of
any
facility
demonstrating
eligibility
for
the
health­
based
provisions.
The
benefit
estimate
presuming
the
health­
based
provisions
are
$
14.5
billion
+
B,
which
is
$
1.7
billion
194
lower
than
the
estimate
for
the
final
rule.
This
estimate
is
$
13.8
billion
+
B
higher
than
the
estimated
social
costs
presuming
the
low­
risk
provisions.
The
general
approach
to
calculating
monetized
benefits
is
discussed
in
more
detail
earlier
in
this
preamble.
For
more
detailed
information
on
the
benefits
estimated
for
the
final
rule,
refer
to
the
RIA
in
the
docket.

Future
and
Disproportionate
Costs
The
Unfunded
Mandates
Act
requires
that
we
estimate,
where
accurate
estimation
is
reasonably
feasible,
future
compliance
costs
imposed
by
the
rule
and
any
disproportionate
budgetary
effects.
Our
estimates
of
the
future
compliance
costs
of
the
final
rule
are
discussed
previously
in
this
preamble.

We
do
not
feel
that
there
will
be
any
disproportionate
budgetary
effects
of
the
final
rule
on
any
particular
areas
of
the
country,
State
or
local
governments,
types
of
communities
(
e.
g.,
urban,
rural),
or
particular
industry
segments.
This
is
true
for
the
257
facilities
owned
by
54
different
government
bodies,
and
this
is
borne
out
by
the
results
of
the
"
Economic
Impact
Analysis
of
the
Industrial
Boilers
and
Process
Heaters
NESHAP,"
the
results
of
which
are
discussed
previously
in
this
preamble.

Effects
on
the
National
Economy
The
Unfunded
Mandates
Act
requires
that
we
estimate
the
195
effect
of
the
final
rule
on
the
national
economy.
To
the
extent
feasible,
we
must
estimate
the
effect
on
productivity,
economic
growth,
full
employment,
creation
of
productive
jobs,
and
international
competitiveness
of
the
U.
S.
goods
and
services,
if
we
determine
that
accurate
estimates
are
reasonably
feasible
and
that
such
effect
is
relevant
and
material.

The
nationwide
economic
impact
of
the
final
rule
is
presented
in
the
"
Economic
Impact
Analysis
for
the
Industrial
Boilers
and
Process
Heaters
MACT"
in
the
docket.

This
analysis
provides
estimates
of
the
effect
of
the
final
rule
on
some
of
the
categories
mentioned
above.
The
results
of
the
economic
impact
analysis
are
summarized
previously
in
this
preamble.
The
results
show
that
there
will
be
little
impact
on
prices
and
output
from
the
affected
industries,
and
little
impact
on
communities
that
may
be
affected
by
the
final
rule.
In
addition,
there
should
be
little
impact
on
energy
markets
(
in
this
case,
coal,
natural
gas,
petroleum
products,
and
electricity).
Hence,
the
potential
impacts
on
the
categories
mentioned
above
should
be
minimal.

Consultation
with
Government
Officials
The
Unfunded
Mandates
Act
requires
that
we
describe
the
extent
of
the
EPA's
prior
consultation
with
affected
State,

local,
and
tribal
officials,
summarize
the
officials'
196
comments
or
concerns,
and
summarize
our
response
to
those
comments
or
concerns.
In
addition,
section
203
of
the
UMRA
requires
that
we
develop
a
plan
for
informing
and
advising
small
governments
that
may
be
significantly
or
uniquely
impacted
by
a
rule.
Although
the
final
rule
does
not
significantly
affect
any
State,
local,
or
Tribal
governments,
we
have
consulted
with
State
and
local
air
pollution
control
officials.
We
also
have
held
meetings
on
the
final
rule
with
many
of
the
stakeholders
from
numerous
individual
companies,
environmental
groups,
consultants
and
vendors,
labor
unions,
and
other
interested
parties.
We
have
added
materials
to
the
docket
to
document
these
meetings.

In
addition,
we
have
determined
that
the
final
rule
contains
no
regulatory
requirements
that
might
significantly
or
uniquely
affect
small
governments.
While
some
small
governments
may
have
some
sources
affected
by
the
final
rule,
the
impacts
are
not
expected
to
be
significant.

Therefore,
the
final
rule
is
not
subject
to
the
requirements
of
section
203
of
the
UMRA.
However,
EPA
did
complete
a
report
containing
analyses
called
for
in
the
UMRA
as
a
response
to
comments
from
many
municipal
utilities
regarding
this
rule
and
its
potential
impacts.
This
report,
"
Unfunded
Mandates
Reform
Act
Analysis
for
the
Industrial
Boilers
and
Process
Heaters
NESHAP,"
is
in
the
docket.
197
E.
Executive
Order
13132:
Federalism
Executive
Order
13132
requires
EPA
to
develop
an
accountable
process
to
ensure
"
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications."

"
Policies
that
have
federalism
implications"
are
defined
in
the
Executive
Order
to
include
regulations
that
have
"
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,

or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.

The
final
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.

The
agency
is
required
by
section
112
of
the
CAA,
to
establish
the
standards
in
the
final
rule.
The
final
rule
primarily
affects
private
industry,
and
does
not
impose
significant
economic
costs
on
State
or
local
governments.

The
final
rule
does
not
include
an
express
provision
preempting
State
or
local
regulations.
Thus,
the
requirements
of
section
6
of
the
Executive
Order
do
not
apply
to
the
final
rule.
198
Although
section
6
of
Executive
Order
13132
does
not
apply
to
the
final
rule,
we
consulted
with
representatives
of
State
and
local
governments
to
enable
them
to
provide
meaningful
and
timely
input
into
the
development
of
the
final
rule.
This
consultation
took
place
during
the
ICCR
Federal
Advisory
Committee
Act
(
FACA)
committee
meetings
where
members
representing
State
and
local
governments
participated
in
developing
recommendations
for
EPA's
combustion­
related
rulemakings,
including
the
final
rule.

The
concerns
raised
by
representatives
of
State
and
local
governments
were
considered
during
the
development
of
the
final
rule.

In
the
spirit
of
Executive
Order
13132,
and
consistent
with
EPA
policy
to
promote
communications
between
EPA
and
State
and
local
governments,
EPA
specifically
solicited
comment
on
the
final
rule
from
State
and
local
officials.

F.
Executive
Order
13175:
Consultation
and
Coordination
with
Indian
Tribal
Governments
Executive
Order
13175
(
65
FR
67249,
November
9,
2000)

requires
EPA
to
develop
an
accountable
process
to
ensure
"
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications."
The
final
rule
does
not
have
tribal
implications,
as
specified
in
Executive
Order
13175.

The
final
rule
does
not
significantly
or
uniquely
affect
199
the
communities
of
Indian
tribal
governments.
We
do
not
know
of
any
industrial­
commercial­
institutional
boilers
or
process
heaters
owned
or
operated
by
Indian
tribal
governments.
However,
if
there
are
any,
the
effect
of
these
rules
on
communities
of
tribal
governments
would
not
be
unique
or
disproportionate
to
the
effect
on
other
communities.
Thus,
Executive
Order
13175
does
not
apply
to
the
final
rule.
The
EPA
specifically
solicited
additional
comment
on
the
final
rule
from
tribal
officials,
but
received
none.

G.
Executive
Order
13045:
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045
(
62
FR
19885,
April
23,
1997)

applies
to
any
regulation
that:
(
1)
Is
determined
to
be
"
economically
significant"
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
we
have
reason
to
believe
may
have
a
disproportionate
effect
on
children.

If
the
regulatory
action
meets
both
criteria,
the
EPA
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
regulation
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered
by
the
EPA.

The
EPA
interprets
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
200
safety
risks,
such
that
the
analysis
required
under
section
5­
501
of
the
Executive
Order
has
the
potential
to
influence
the
regulation.
The
final
rule
is
not
subject
to
Executive
Order
13045
because
it
is
based
on
technology
performance
and
not
on
health
or
safety
risks.

H.
Executive
Order
13211:
Actions
Concerning
Regulations
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
Executive
Order
13211
(
66
FR
28355,
May
22,
2001)
provides
that
agencies
shall
prepare
and
submit
to
the
Administrator
of
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
a
Statement
of
Energy
Effects
for
certain
actions
identified
as
"
significant
energy
actions."

Section
4(
b)
of
Executive
Order
13211
defines
"
significant
energy
actions"
as
"
any
action
by
an
agency
(
normally
published
in
the
Federal
Register)
that
promulgates
or
is
expected
to
lead
to
the
promulgation
of
a
final
rule
or
regulation,
including
notices
of
inquiry,
advance
notices
of
final
rulemaking,
and
notices
of
final
rulemaking:
(
1)
(
i)

That
is
a
significant
regulatory
action
under
Executive
Order
12866
or
any
successor
order,
and
(
ii)
is
likely
to
have
a
significant
adverse
effect
on
the
supply,

distribution,
or
use
of
energy;
or
(
2)
that
is
designated
by
the
Administrator
of
the
Office
of
Information
and
Regulatory
Affairs
as
a
"
significant
energy
action."
The
201
final
rule
is
not
a
"
significant
energy
action"
because
it
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy.
The
basis
for
the
determination
is
as
follows.

The
reduction
in
petroleum
product
output,
which
includes
reductions
in
fuel
production,
is
estimated
at
only
0.001
percent,
or
about
68
barrels
per
day
based
on
2000
U.
S.
fuel
production
nationwide.
That
is
a
minimal
reduction
in
nationwide
petroleum
product
output.
The
reduction
in
coal
production
is
estimated
at
only
0.014
percent,
or
about
3.5
million
tons
per
year
(
or
less
than
1,000
tons
per
day)

based
on
2000
U.
S.
coal
production
nationwide.
The
combination
of
the
increase
in
electricity
usage
estimated
with
the
effect
of
the
increased
price
of
affected
output
yields
an
increase
in
electricity
output
estimated
at
only
0.012
percent,
or
about
0.72
billion
kilowatt­
hours
per
year
based
on
2000
U.
S.
electricity
production
nationwide.
All
energy
price
changes
estimated
show
no
increase
in
price
more
than
0.05
percent
nationwide,
and
a
similar
result
occurs
for
energy
distribution
costs.
We
also
expect
that
there
will
be
no
discernable
impact
on
the
import
of
foreign
energy
supplies,
and
no
other
adverse
outcomes
are
expected
to
occur
with
regards
to
energy
supplies.
All
of
the
results
presented
above
account
for
the
pass
through
of
costs
to
consumers,
as
well
as
the
cost
impact
to
producers.
For
more
information
on
the
estimated
energy
effects,
please
refer
to
the
economic
impact
analysis
for
the
final
rule.

The
analysis
is
available
in
the
public
docket.
It
should
be
noted
that
these
energy
impact
estimates
are
in
advance
of
any
facility
demonstrating
eligibility
for
the
healthbased
provisions.

With
the
presumption
of
low­
risk
provisions,
the
reduction
in
petroleum
product
output,
which
includes
reductions
in
fuel
production,
is
now
65
barrels
per
day,
or
only
0.001
percent.
This
reduction
is
now
3
barrels
per
day
less
than
that
for
the
final
rule.
The
reduction
is
coal
production
is
estimated
at
only
0.010
percent,
or
about
2.5
million
tons
per
year
based
on
2000
U.
S.
coal
production
nationwide.

This
reduction
is
now
0.004
percent,
or
1.0
million
tons
per
year
less,
than
that
for
the
final
rule.
The
combination
of
the
increase
in
electricity
usage
estimated
with
the
effect
of
the
increased
price
of
affected
output
yields
an
increase
in
electricity
output
of
only
0.0067
percent,
or
about
0.40
billion
kilowatt­
hours
per
year
based
on
2000
U.
S.

electricity
production
nationwide.
This
increase
is
0.32
billion
kilowatt­
hours
per
year
less
than
that
for
the
final
rule.
All
energy
price
changes
are
estimated
show
no
increase
more
than
0.04
percent
nationwide,
which
is
smaller
by
0.01
percent
than
that
for
the
final
rule,
and
a
similar
result
occurs
for
energy
distribution
costs.
There
should
203
be
no
discernable
impact
on
import
of
foreign
energy
supplies,
and
no
other
adverse
outcomes
are
expected
to
occur
with
regards
to
energy
supplies.
All
of
the
results
presented
about
with
presumption
of
the
low­
risk
provisions
account
for
the
pass
through
of
costs
to
consumers
as
well
as
the
cost
impact
to
producers.

Therefore,
we
conclude
that
the
final
rule
when
implemented
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy.

I.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
(
NTTAA)
of
1995
(
Public
Law
No.
104­
113;

15
U.
S.
C.
272
note)
directs
the
EPA
to
use
voluntary
consensus
standards
in
their
regulatory
and
procurement
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(
e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
business
practices)
developed
or
adopted
by
one
or
more
voluntary
consensus
bodies.
The
NTTAA
directs
EPA
to
provide
Congress,
through
annual
reports
to
the
OMB,
with
explanations
when
an
agency
does
not
use
available
and
applicable
voluntary
consensus
standards.

The
final
rule
involves
technical
standards.
The
EPA
cites
the
following
standards
in
the
final
rule:
EPA
204
Methods
1,
2,
2F,
2G,
3A,
3B,
4,
5,
5D,
17,
19,
26,
26A,
29
of
40
CFR
part
60.
Consistent
with
the
NTTAA,
EPA
conducted
searches
to
identify
voluntary
consensus
standards
in
addition
to
these
EPA
methods.
No
applicable
voluntary
consensus
standards
were
identified
for
EPA
Methods
2F,
2G,

5D,
and
19.
The
search
and
review
results
have
been
documented
and
are
placed
in
the
docket
for
the
final
rule.

The
three
voluntary
consensus
standards
described
below
were
identified
as
acceptable
alternatives
to
EPA
test
methods
for
the
purposes
of
the
final
rule.

The
voluntary
consensus
standard
ASME
PTC
19­
10­
1981­
Part
10,
"
Flue
and
Exhaust
Gas
Analyses,"
is
cited
in
the
final
rule
for
its
manual
method
for
measuring
the
oxygen,
carbon
dioxide,
and
carbon
monoxide
content
of
exhaust
gas.
This
part
of
ASME
PTC
19­
10­
1981­
Part
10
is
an
acceptable
alternative
to
Method
3B.

The
voluntary
consensus
standard
ASTM
D6522­
00,
"
Standard
Test
Method
for
the
Determination
of
Nitrogen
Oxides,
Carbon
Monoxide,
and
Oxygen
Concentrations
in
Emissions
from
Natural
Gas­
Fired
Reciprocating
Engines,
Combustion
Turbines,
Boilers
and
Process
Heaters
Using
Portable
Analyzers"
is
an
acceptable
alternative
to
EPA
Method
3A
for
identifying
carbon
monoxide
and
oxygen
concentrations
for
the
final
rule
when
the
fuel
is
natural
gas.

The
voluntary
consensus
standard
ASTM
Z65907,
"
Standard
205
Method
for
Both
Speciated
and
Elemental
Mercury
Determination,"
is
an
acceptable
alternative
to
EPA
Method
29
(
portion
for
mercury
only)
for
the
purpose
of
the
final
rule.
This
standard
can
be
used
in
the
final
rule
to
determine
the
mercury
concentration
in
stack
gases
for
boilers
with
rated
heat
input
capacities
of
greater
than
250
MMBtu
per
hour.

In
addition
to
the
voluntary
consensus
standards
EPA
uses
in
the
final
rule,
the
search
for
emissions
measurement
procedures
identified
15
other
voluntary
consensus
standards.
The
EPA
determined
that
13
of
these
15
standards
identified
for
measuring
emissions
of
the
HAP
or
surrogates
subject
to
the
emission
standards
were
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
the
final
rule.
Therefore,
EPA
does
not
intend
to
adopt
these
standards
for
this
purpose.
(
See
Docket
ID
No.
OAR­
2002­

0058
for
further
information
on
the
methods.)

Two
of
the
15
voluntary
consensus
standards
identified
in
this
search
were
not
available
at
the
time
the
review
was
conducted
for
the
purposes
of
the
final
rule
because
they
are
under
development
by
a
voluntary
consensus
body:

ASME/
BSR
MFC
13M,
"
Flow
Measurement
by
Velocity
Traverse,"

for
EPA
Method
2
(
and
possibly
1);
and
ASME/
BSR
MFC
12M,

"
Flow
in
Closed
Conduits
Using
Multiport
Averaging
Pitot
Primary
Flowmeters,"
for
EPA
Method
2.
206
Section
63.7520
and
Tables
4A
through
4D
to
subpart
DDDDD
of
this
standard
list
the
EPA
testing
methods
included
in
the
final
rule.
Under
§
63.7(
f)
and
§
63.8(
f)
of
subpart
A,

40
CFR
part
63,
of
the
General
Provisions,
a
source
may
apply
to
EPA
for
permission
to
use
alternative
test
methods
or
alternative
monitoring
requirements
in
place
of
any
of
the
EPA
testing
methods,
performance
specifications,
or
procedures.

J.
Congressional
Review
Act
The
Congressional
Review
Act,
§
5
U.
S.
C.
801,
et
seq.,
as
added
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996,
generally
provides
that
before
a
rule
may
take
effect,
the
agency
promulgating
the
rule
must
submit
a
rule
report,
which
includes
a
copy
of
the
rule,
to
each
House
of
the
Congress
and
to
the
Comptroller
General
of
the
United
States.
The
EPA
will
submit
a
report
containing
the
final
rule
and
other
required
information
to
the
United
States
Senate,
the
United
States
House
of
Representatives,
and
the
Comptroller
General
of
the
United
States
prior
to
publication
of
the
final
rule
in
the
Federal
Register.
A
major
rule
cannot
take
effect
until
60
days
after
it
is
published
in
the
Federal
Register.
This
action
is
a
"
major
rule"
as
defined
by
5
U.
S.
C.
§
804(
2).
The
rule
will
be
effective
on
[
INSERT
DATE
60
DAYS
AFTER
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER].
207
NESHAP:
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
 
FINAL
RULE
­
Page
208
of
201
208
List
of
Subjects
in
40
CFR
part
63
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Hazardous
substances,

Intergovernmental
relations,
Reporting
and
recordkeeping
requirements.

______________________
Dated:

_______________________
Michael
O.
Leavitt,
Administrator.
place
rule
here............
km
