Document ID: EPA-HQ-OAR-2003-0048-0095
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2004-02-25T05:00Z

Teresa
Clemons
To:
Edmond_
Toy@
omb.
eop.
gov
02/
09/
2004
02:
36
PM
cc:
(
bcc:
Mary
Kissell/
RTP/
USEPA/
US)
Subject:
Re:
Advance
Copy
of
Industrial
Boilers
MACT
(
Document
link:
Mary
Tom
Kissell)

Here
are
the
files
in
word.
Let
me
know
if
you
still
encounter
problems.

For
Boilers:

(
See
attached
file:
Preamble
Boilers.
doc)(
See
attached
file:
rule
text
boilers.
doc)(
See
attached
file:
Appendix
A
boilers.
doc)

For
Plywood:

(
See
attached
file:
pcwp_
appB
06feb04.
doc)(
See
attached
file:
plywood
risk
preamble.
doc)

THANKS!
Teresa
Clemons
Emission
Standards
Division
919­
541­
0252
919­
541­
0072
(
Fax)

Edmond_
Toy@
omb.
eop.
gov
To:
Teresa
Clemons/
RTP/
USEPA/
US@
EPA
02/
09/
2004
01:
55
PM
cc:
Subject:
Re:
Advance
Copy
of
Industrial
Boilers
MACT
Teresa...
thanks
for
both
the
boilers
and
plywood
documents.

However,
some
folks
here
are
having
problems
opening
up
WordPerferct
docs.
Could
you
please
resend
the
docs
in
either
Word
or
pdf
formats
as
soon
as
possible?

Thanks.

­
Edmond
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,
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
risk­
based
alternative
compliance
options
for
the
hydrogen
chloride
and
total
selected
metals
emission
limits.
This
action
is
being
taken
in
part
to
respond
to
comments
submitted
by
the
American
Forest
&
Paper
Association
(
AF&
PA),
the
American
Furniture
Manufactures
Association
(
AFMA),
and
in
part
upon
the
Administrator's
own
motion.
This
action
is
based
on
EPA's
evaluation
of
the
available
information
concerning
the
potential
hazards
from
exposure
to
hydrogen
chloride
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.

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
this
regulation
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
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
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
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
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
THIS
FINAL
RULE
IN
THE
FEDERAL
REGISTER].
Only
those
objections
to
the
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.

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
background
information
document
(
BID)
("
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Industrial,

Commercial,
and
Institutional
Boilers
and
Process
Heaters,
Summary
of
Public
Comments
and
Responses,"
December
2003,

EPA­
453/
R­
03­___)
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
risk­
based
provisions
and
how
do
I
demonstrate
eligibility?
III.
What
are
the
significant
changes
since
proposal?
A.
Definition
of
Affected
Source
B.
Sources
Not
Covered
by
the
NESHAP
C.
Emission
Limits
D.
Definitions
Added
and
Revised
E.
Requirements
for
Sources
in
Subcategories
Without
Emission
Limit
or
Work
Practice
Requirements
F.
CO
Work
Practice
Emission
Level
and
Requirements
G.
Fuel
Analysis
Option
H.
Emissions
Averaging
I.
Opacity
Limit
J.
Operating
Limit
Determination
K.
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
risk­
based
exemption
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
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
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
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
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
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
waste
incinerators
covered
by
the
NSPS
in
40
CFR
part
60,
subparts
Ce
or
Ec;
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,

subpart
MM.

Fossil
fuel­
fired
utility
boilers
are
exempt
from
the
final
rule.
Non­
fossil
fuel­
fired
utility
boilers
are
covered
by
the
final
rule.
A
fossil
fuel­
fired
utility
boiler
is
a
fossil
fuel­
fired
combustion
unit
of
more
than
25
megawatts
that
serves
a
generator
that
produces
electricity
for
sale.
A
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.

In
1986,
EPA
codified
the
NSPS
for
industrial
boilers
(
40
CFR
part
60,
subparts
Db
and
Dc)
and
revised
portions
of
them
in
1999.
The
NSPS
regulates
emissions
of
particulate
matter
(
PM),
sulfur
dioxide,
and
nitrogen
1
Please
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.
oxides
from
boilers
constructed
after
June
19,
1984.

Sources
subject
to
the
NSPS
are
still
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
from
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?

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
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.

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
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.
EPA
has
classified
benzene
as
a
Group
A,
known
human
carcinogen.

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
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
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
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
(
short­
term)
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
exposure.
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
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.
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.
Acute
(
short­
term)
inhalation
exposure
may
cause
eye,
nose,
and
respiratory
tract
irritation
and
inflammation
and
pulmonary
edema
in
humans.
Chronic
(
long­
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,

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
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
tremors.
The
EPA
has
not
classified
elemental
mercury
with
respect
to
cancer.

Acute
exposure
to
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.
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.

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
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.
Any
temporary
boiler
that
replaces
a
temporary
boiler
and
is
intended
to
perform
the
same
or
similar
function
will
be
included
in
the
determination
of
the
consecutive
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
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
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
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
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.
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
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
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
­­

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)
New
Boil
er
or
Proc
ess
Heat
er
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)

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
­­
­­
­­

Liquid
Fuel,
Large
Unit
­­
­­
­­
­­
­­
Exis
ting
Boil
er
or
Proc
ess
Heat
er
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
alternative
compliance
options
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
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
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
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).

G.
For
new
sources
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
carbon
monoxide
(
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.

(
8)
For
affected
sources
that
choose
to
meet
the
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)
or
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:

(
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
source
may
elect
to
operate
the
fabric
filter
such
that
an
installed
bag
leak
detection
system
alarm
does
not
sound
more
than
5
percent
of
the
operating
time
during
any
6­
month
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
hydrogen
chloride
content
level
in
the
input
fuel(
s)
during
the
HCl
performance
test.
This
is
your
maximum
hydrogen
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.

(
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.

(
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,
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
and
with
heat
input
capacities
less
than
100
MMBtu/
hr,
you
must
conduct
initial
test
of
CO
emissions
to
demonstrate
compliance
with
the
CO
work
practice
limit.

The
final
rule
also
provides
you
another
alternative
compliance
option.
You
may
demonstrate
compliance
by
emissions
averaging
for
existing
solid
fuel­
fired
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
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.

(
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.

(
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
with
the
alternate
selected
metals
emission
limit.

(
8)
For
boilers
and
process
heaters
that
choose
to
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.

(
5)
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
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
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
and
limited
use
gaseous
fuel­
fired
subcategories,

existing
large
and
limited
used
liquid
fuel­
fired
subcategories,
new
small
gaseous
fuel­
fired
subcategory,
or
new
small
liquid
fuel­
fired
units
that
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
fired
subcategories,
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
hydrogen
chloride
fuel
input,
as
required
in
the
final
rule.

(
7)
Calculations
and
supporting
information
of
total
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
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
emissions
average
(
6)
Compliance
reports
semi­
annually.

I.
What
are
the
risk­
based
alternative
compliance
options
and
how
do
I
demonstrate
eligibility?
As
an
alternative
to
the
requirement
for
each
large
solid
fuel
fired
boilers
to
demonstrate
compliance
with
the
HCl
emission
limit
in
the
final
rule,
you
may
demonstrate
compliance
with
a
risk­
based
facility­
wide
HCl
equivalent
allowable
emission
limit.

The
procedures
for
demonstrating
eligibility
for
HCl
alternative
compliance
option
are:

(
1)
You
must
include
every
appropriate
emission
point
within
the
facility
that
emits
HCl
and/
or
chlorine.

(
2)
You
must
conduct
HCl
and
chlorine
emissions
tests
for
every
appropriate
emission
point
that
emits
HCl
and/
or
chlorine.

(
3)
Determine
the
total
maximum
hourly
mass
HCl
and
chlorine
emission
rate
for
your
facility
by
summing
the
maximum
hourly
mass
HCl
and
chlorine
emission
rate
(
calculated
using
the
maximum
rated
capacities
of
the
units)
for
each
of
the
units.

(
4)
Use
the
look­
up
table
in
the
final
rule
to
determine
if
your
facility
is
in
compliance
with
risk­
based
HCl
emission
limit.

(
5)
Select
the
maximum
allowable
HCl
emission
rate
from
the
look­
up
table
for
you
facility
using
the
average
stack
height
of
your
HCl/
chlorine
emission
points
and
the
minimum
distance
between
any
HCl/
chlorine
emission
point
at
the
facility
and
the
closest
boundary
of
the
nearest
residential
(
or
residentially
zoned)
area
should
be
used
for
fenceline
distance.

(
6)
Your
facility
is
in
compliance
if
your
maximum
HCl/
chlorine
emission
rate
does
not
exceed
the
value
specified
in
the
look­
up
table.

(
7)
As
an
alternative
to
using
the
look­
up
table,
you
may
use
methodology
for
conducting
site­
specific
risk
assessment
specified
in
Appendix
A
of
the
final
rule.

(
8)
Alternatively,
you
can
choose
to
assess
only
the
emission
points
covered
by
final
rule.
If
you
choose
this
option
under
the
lookup
table
approach,
you
must
multiply
the
appropriate
value
in
the
lookup
table
by
0.5
to
arrive
at
your
allowable
HCl
emission
rate.
Under
the
sitespecific
risk
assessment
approach,
you
must
compare
the
Hazard
Index
to
the
limit
of
0.5.

In
lieu
of
complying
with
the
emission
standard
for
total
selected
metals
(
TSM)
in
the
final
based
on
the
sum
of
emissions
for
the
8
selected
metals,
you
may
be
eligible
for
complying
with
the
TSM
standard
based
on
excluding
manganese
emissions
from
the
summation
for
determining
selected
metals
emissions
for
the
affected
source
unit.

The
procedures
for
demonstrating
eligibility
for
the
TSM
alternative
compliance
option
are:

(
1)
You
must
include
every
appropriate
emission
point
within
the
facility
that
emits
manganese
in
the
eligibility
demonstration.

(
2)
You
must
conduct
manganese
emissions
tests
for
every
appropriate
emission
point
that
emits
manganese.

(
3)
Determine
the
total
maximum
hourly
mass
emission
rate
of
manganese
from
your
facility
by
summing
the
maximum
hourly
mass
manganese
emission
rate
(
calculated
using
the
maximum
rated
heat
input
capacities)
for
each
of
the
units.

(
4)
Use
the
look­
up
table
in
Appendix
A
of
the
final
rule
to
determine
if
your
facility
is
eligible
for
complying
with
the
TSM
limit
based
on
the
sum
of
emissions
for
7
metals
(
excluding
manganese)
for
the
affected
source
units.

(
5)
Select
the
maximum
allowable
manganese
emission
rate
from
the
look­
up
table
for
you
facility
using
the
average
stack
height
of
your
manganese
emission
points
and
the
minimum
distance
between
any
manganese
emission
point
at
the
facility
and
the
closest
boundary
of
the
nearest
residential
(
or
residentially
zoned)
area
should
be
used
for
fenceline
distance.

(
6)
Your
facility
is
eligible
if
your
maximum
manganese
emission
rate
does
not
exceed
the
value
specified
in
the
look­
up
table.

(
7)
As
an
alternative
to
using
look­
up
table
to
determine
if
your
facility
is
eligible
for
the
TSM
alternative
compliance
option,
you
may
use
methodology
for
conducting
site­
specific
risk
assessment
specified
in
Appendix
A
of
the
final
rule.

(
8)
Alternatively,
you
can
choose
to
assess
only
the
emission
points
covered
by
subpart
DDDDD.
If
you
choose
this
option
under
the
lookup
table
approach,
you
must
multiply
the
appropriate
value
in
the
lookup
table
by
0.5
to
arrive
at
your
allowable
manganese
emission
rate.
Under
the
site­
specific
risk
assessment
approach,
you
must
compare
the
Hazard
Index
to
the
limit
of
0.5.

If
you
elect
to
demonstrate
eligibility
for
the
riskbased
provisions,
you
must
submit
a
certified
documentation
supporting
compliance
with
the
procedures
at
least
one
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
fenceline
distances
to
each
on­
site
source
of
HCl/
Cl2
and/
or
manganese
emissions.

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

If
you
intend
to
change
key
parameters,
including
distance
of
stack
to
the
fence
line,
that
may
result
in
lower
allowable
risk­
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/
CL2
and/
or
manganese
emissions,
you
must
recalculate
the
total
maximum
hourly
mass
emission
rate
of
HCl/
CL2
and/
or
manganese
from
your
affected
source,
and
submit
certified
documentation
supporting
continued
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
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))
have
been
written
to
also
include:
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).

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
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
this
NESHAP.

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
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.
CO
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
(
CEMs).

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,

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
hydrogen
chloride,
mercury,
or
total
selected
metals
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
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
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
H.
Emissions
Averaging
We
have
included
an
option
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
average
basis,
determined
at
the
end
of
every
month.

If
you
elect
to
comply
with
the
emissions
averaging
option,

you
must
use
equations
provided
in
the
final
rule
to
demonstrate
that
particulate
matter
or
total
selected
metals,
hydrogen
chloride,
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
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.

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
demonstrate
compliance
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
sources
in
subcategories
that
do
not
have
any
emission
limitations
and
work
practices
should
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
to
these
units.
We
do
not
believe
the
SSM
plan
to
be
necessary
or
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,
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
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
facilities
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
exempt
temporary/
portable
units
from
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
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,
NSPS,

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.
We
do
not
feel
there
is
justification
for
developing
a
lower
size
cutoff
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
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
from
the
final
rule.

Response:
We
have
included
an
extensive
list
of
sources
that
are
exempt
from
the
final
rule.
The
final
rule
clarifies
that
boilers
and
process
heaters
that
are
included
as
part
of
the
affected
source
in
another
NESHAP
are
exempt
from
the
industrial
boilers
NESHAP.
However,
we
do
not
exempt
boilers
and
process
heaters
that
are
used
as
control
devices
unless
they
are
specifically
considered
part
of
another
NESHAP's
definition
of
affected
source.

Incinerators,
thermal
oxidizers,
and
flares
do
not
generally
fall
under
the
definition
of
a
boiler
or
process
heater
and
would
not
be
subject
to
this
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
industrial
boilers
NESHAP
unless
it
is
subject
to
another
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
another
NESHAP.
We
specifically
exempt
comfort
heaters
from
the
final
rule.
However,
this
exemption
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
be
exempt
from
this
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
this
NESHAP.
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
virtually
no
organic
HAP
are
generated
in
its
combustion.

As
a
result,
we
exempt
from
this
NESHAP
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
another
standard
under
40
CFR
part
63
in
addition
to
the
list
of
specific
exemptions.
In
addition,

research
and
development
(
R&
D)
operations
are
not
be
subject
to
the
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.
We
believe
that
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
is
much
more
narrow
than
that
in
the
General
Provisions,
even
though
the
General
Provisions
states
that
each
standard
will
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
for
affected
source
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).

Therefore,
the
definition
of
existing
affected
source
in
the
final
rule
is
the
collection
of
existing
industrial,

commercial,
or
institutional
boilers
and
process
heaters
located
at
a
major
source
of
HAP
emissions.

B.
Format
Comment:
Several
commenters
opposed
using
one
or
more
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,
we
feel
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
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
NESHAPs
as
a
technique
to
reduce
the
performance
testing
costs
and
believe
that
the
use
of
surrogates
is
appropriate
in
this
NESHAP.

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
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
a
technology­
based
standard,
the
technologies
that
have
been
developed
and
implemented
to
control
particulate
matter,

also
control
non­
mercury
metallic
HAP.
Furthermore,
since
non­
mercury
metallic
HAP
is
a
component
of
particulate
matter,
we
continue
to
believe
that
we
can
use
particulate
matter
as
a
surrogate
for
the
purposes
of
this
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.

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
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.
We
believe
that
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
available
that
indicated
a
relationship
between
the
GCP's
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.
Many
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
does
not
allow
an
extra
year
for
existing
sources
to
comply
with
the
final
rule.
Section
112(
i)(
3)(
B)
allows
EPA,
on
a
case­
by­
case
basis
to
grant
an
extension
permitting
an
existing
source
up
to
one
additional
year
to
comply
with
standards
if
such
additional
period
is
necessary
for
the
installation
of
controls.
The
EPA
feels
that
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
section
112
standards
into
a
cost­
benefit
program
and
that
is
not
legally
defensible.
The
commenter
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,
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
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
neither
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
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
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
develop
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
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
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
of
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
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
that
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
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,

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
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
controls
(
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
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
(
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
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
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
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
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
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
section
112(
d)
allows
EPA
to
use
information
from
similar
sources
to
set
the
MACT
floor
when
no
information
from
the
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
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
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
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
gas
and
liquid
fuel­
fired
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
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
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
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
was
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
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
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,

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
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
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
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
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
"
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
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
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
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
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
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
by
the
opacity
operating
limit,
the
final
rule
provides
two
options.
As
the
commenters
suggested,
existing
units
can
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
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
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.

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).