Document ID: EPA-HQ-OAR-2002-0058-0013
Agency: epa
Document Type: Proposed Rule
Title: National Emission Standards for Hazardous Air Pollutants for Industrial/Commercial/Institutional Boilers and Process Heaters; Proposed Rule
Posted Date: 2003-01-13T05:00Z

Monday,

January
13,
2003
Part
II
Environmental
Protection
Agency
40
CFR
Part
63
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Industrial/
Commercial/
Institutional
Boilers
and
Process
Heaters;
Proposed
Rule
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Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
63
[
OAR
 
2002
 
0058;
FRL
 
7418
 
9]

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

SUMMARY:
The
EPA
is
proposing
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
for
industrial/
commercial/
institutional
boilers
and
process
heaters.
The
EPA
has
identified
industrial/
commercial/
institutional
boilers
and
process
heaters
as
major
sources
of
hazardous
air
pollutants
(
HAP)
emissions.
The
proposed
rule
would
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
proposed
rule
would
reduce
HAP
emissions
by
58,000
tons
per
year,
hydrogen
chloride
 
a
substance
that
is
not
considered
to
be
a
carcinogen
 
accounts
for
42,000
tons
per
year
(
72
percent)
of
total
HAP
emissions
reductions.
The
proposed
rule
would
protect
air
quality
and
promote
the
public
health
by
reducing
emissions
of
some
of
the
HAP
listed
in
section
112(
b)(
1)
of
the
CAA.
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,
and
nickel.
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.
The
adverse
health
effects
associated
with
the
exposure
to
these
specific
HAP
are
further
described
in
this
preamble.
In
general,
these
findings
have
only
been
shown
with
concentrations
higher
than
those
typically
in
the
ambient
air.
DATES:
Comments.
Submit
comments
on
or
before
March
14,
2003.
Public
Hearing.
If
anyone
contacts
EPA
requesting
to
speak
at
a
public
hearing
by
February
3,
2003,
a
public
hearing
will
be
held
on
February
12,
2003.
ADDRESSES:
Comments.
Comments
may
be
submitted
by
mail
(
in
duplicate,
if
possible)
to
EPA
Docket
Center
(
Air
Docket),
U.
S.
EPA
West
(
MD
 
6102T),
Room
B
 
108,
1200
Pennsylvania
Avenue,
NW,
Washington,
DC
20460,
Attention
Docket
ID
No.
OAR
 
2002
 
0058.
By
hand
delivery/
courier,
comments
may
be
submitted
(
in
duplicate,
if
possible)
to
EPA
Docket
Center,
Room
B
 
108,
U.
S.
EPA
West,
1301
Constitution
Avenue,
NW,
Washington,
DC
20460,
Attention
Docket
ID
No.
OAR
 
2002
 
0058.
Also,
comments
may
be
submitted
electronically
according
to
the
detailed
instructions
as
provided
in
the
SUPPLEMENTARY
INFORMATION
section.
Public
Hearing.
If
a
public
hearing
is
held,
it
will
be
held
at
the
new
EPA
facility
complex
in
Research
Triangle
Park,
North
Carolina,
or
an
alternate
site
nearby.
Docket.
Docket
ID
No.
OAR
 
2002
 
0058
contains
supporting
information
used
in
developing
the
proposed
rule.
The
docket
is
located
at
the
U.
S.
EPA,
1301
Constitution
Avenue,
NW,
Washington,
DC
20460
in
room
B108,
and
may
be
inspected
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.

FOR
FURTHER
INFORMATION
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,
e­
mail:
eddinger.
jim@
epa.
gov.

SUPPLEMENTARY
INFORMATION:
Regulated
Entities.
The
promulgation
of
the
proposed
rule
would
affect
the
following
North
American
Industrial
Classification
System
(
NAICS)
and
Standard
Industrial
Classification
(
SIC)
codes.

Category
NAICS
code
SIC
code
Examples
of
potentially
regulated
entities
Any
industry
using
a
boiler
or
process
heater
as
defined
in
the
proposed
rule.
211
...........................
13
Extractors
of
crude
petroleum
and
natural
gas.

321
...........................
24
Manufacturers
of
lumber
and
wood
products.
322
...........................
26
Pulp
and
paper
mills.
325
...........................
28
Chemical
manufacturers.
324
...........................
29
Petroleum
refineries,
and
manufacturers
of
coal
products.
316,
326,
339
..........
30
Manufacturers
of
rubber
and
miscellaneous
plastic
products.
331
...........................
33
Steel
works,
blast
furnaces.
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
proposed
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.
How
Can
I
Get
Copies
of
This
Document
and
Other
Related
Information?

Docket.
The
EPA
has
established
an
official
public
docket
for
this
action
under
Docket
ID
No.
OAR
 
2002
 
0058.
The
official
public
docket
consists
of
the
documents
specifically
referenced
in
this
action,
any
public
comments
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/
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68,
No.
8
/
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January
13,
2003
/
Proposed
Rules
received,
and
other
information
related
to
this
action.
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
Air
and
Radiation
Docket
in
the
EPA
Docket
Center,
(
EPA/
DC)
EPA
West,
Room
B108,
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
submit
or
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.
Certain
types
of
information
will
not
be
placed
in
the
EPA
Dockets.
Information
claimed
as
CBI
and
other
information
whose
disclosure
is
restricted
by
statute,
which
is
not
included
in
the
official
public
docket,
will
not
be
available
for
public
viewing
in
EPA's
electronic
public
docket.
The
EPA's
policy
is
that
copyrighted
material
will
not
be
placed
in
EPA's
electronic
public
docket
but
will
be
available
only
in
printed
paper
form
in
the
official
public
docket.
To
the
extent
feasible,
publicly
available
docket
materials
will
be
made
available
in
EPA's
electronic
public
docket.
When
a
document
is
selected
from
the
index
list
in
EPA
Dockets,
the
system
will
identify
whether
the
document
is
available
for
viewing
in
EPA's
electronic
public
docket.
Although
not
all
docket
materials
may
be
available
electronically,
you
may
still
access
any
of
the
publicly
available
docket
materials
through
the
docket
facility
identified
above.
The
EPA
intends
to
work
towards
providing
electronic
access
to
all
of
the
publicly
available
docket
materials
through
EPA's
electronic
public
docket.
For
public
commenters,
it
is
important
to
note
that
EPA's
policy
is
that
public
comments,
whether
submitted
electronically
or
on
paper,
will
be
made
available
for
public
viewing
in
EPA's
electronic
public
docket
as
EPA
receives
them
and
without
change,
unless
the
comment
contains
copyrighted
material,
CBI,
or
other
information
whose
disclosure
is
restricted
by
statute.
When
EPA
identifies
a
comment
containing
copyrighted
material,
EPA
will
provide
a
reference
to
that
material
in
the
version
of
the
comment
that
is
placed
in
EPA's
electronic
public
docket.
The
entire
printed
comment,
including
the
copyrighted
material,
will
be
available
in
the
public
docket.
Public
comments
submitted
on
computer
disks
that
are
mailed
or
delivered
to
the
docket
will
be
transferred
to
EPA's
electronic
public
docket.
Public
comments
that
are
mailed
or
delivered
to
the
Docket
will
be
scanned
and
placed
in
EPA's
electronic
public
docket.
Where
practical,
physical
objects
will
be
photographed,
and
the
photograph
will
be
placed
in
EPA's
electronic
public
docket
along
with
a
brief
description
written
by
the
docket
staff.
For
additional
information
about
EPA's
electronic
public
docket,
visit
EPA
Dockets
online
or
see
67
FR
38102,
May
31,
2002.
You
may
submit
comments
electronically,
by
mail,
or
through
hand
delivery/
courier.
To
ensure
proper
receipt
by
EPA,
identify
the
appropriate
docket
identification
number
in
the
subject
line
on
the
first
page
of
your
comment.
Please
ensure
that
your
comments
are
submitted
within
the
specified
comment
period.
Comments
received
after
the
close
of
the
comment
period
will
be
marked
``
late.''
The
EPA
is
not
required
to
consider
these
late
comments.
However,
late
comments
may
be
considered
if
time
permits.
Electronically.
If
you
submit
an
electronic
comment
as
prescribed
below,
EPA
recommends
that
you
include
your
name,
mailing
address,
and
an
e­
mail
address
or
other
contact
information
in
the
body
of
your
comment.
Also
include
this
contact
information
on
the
outside
of
any
disk
or
CD
ROM
you
submit,
and
in
any
cover
letter
accompanying
the
disk
or
CD
ROM.
This
ensures
that
you
can
be
identified
as
the
submitter
of
the
comment
and
allows
EPA
to
contact
you
in
case
EPA
cannot
read
your
comment
due
to
technical
difficulties
or
needs
further
information
on
the
substance
of
your
comment.
The
EPA's
policy
is
that
EPA
will
not
edit
your
comment,
and
any
identifying
or
contact
information
provided
in
the
body
of
a
comment
will
be
included
as
part
of
the
comment
that
is
placed
in
the
official
public
docket
and
made
available
in
EPA's
electronic
public
docket.
If
EPA
cannot
read
your
comment
due
to
technical
difficulties
and
cannot
contact
you
for
clarification,
EPA
may
not
be
able
to
consider
your
comment.
Your
use
of
EPA's
electronic
public
docket
to
submit
comments
to
EPA
electronically
is
EPA's
preferred
method
for
receiving
comments.
Go
directly
to
EPA
Dockets
at
http://
www.
epa.
gov/
edocket,
and
follow
the
online
instructions
for
submitting
comments.
To
access
EPA's
electronic
public
docket
from
the
EPA
Internet
Home
Page,
select
``
Information
Sources,''
``
Dockets,''
and
``
EPA
Dockets.''
Once
in
the
system,
select
``
search,''
and
then
key
in
Docket
ID
No.
OAR
 
2002
 
0058.
The
system
is
an
anonymous
access
system,
which
means
EPA
will
not
know
your
identity,
e­
mail
address,
or
other
contact
information
unless
you
provide
it
in
the
body
of
your
comment.
Comments
may
be
sent
by
electronic
mail
(
e­
mail)
to
a­
and­
r­
docket@
epa.
gov,
Attention
Docket
ID
No.
OAR
 
2002
 
0058.
In
contrast
to
EPA's
electronic
public
docket,
EPA's
e­
mail
system
is
not
an
anonymous
access
system.
If
you
send
an
e­
mail
comment
directly
to
the
Docket
without
going
through
EPA's
electronic
public
docket,
EPA's
e­
mail
system
automatically
captures
your
email
address.
E­
mail
addresses
that
are
automatically
captured
by
EPA's
e­
mail
system
are
included
as
part
of
the
comment
that
is
placed
in
the
official
public
docket
and
made
available
in
EPA's
electronic
public
docket.
You
may
submit
comments
on
a
disk
or
CD
ROM
that
you
mail
to
the
mailing
address
identified
below.
These
electronic
submissions
will
be
accepted
in
WordPerfect
or
ASCII
file
format.
Avoid
the
use
of
special
characters
and
any
form
of
encryption.
By
Mail.
Send
your
comments
(
in
duplicate
if
possible)
to:
Air
and
Radiation
Docket
and
Information
Center,
U.
S.
EPA,
Mailcode:
6102T,
1200
Pennsylvania
Ave.,
NW.,
Washington,
DC
20460,
Attention
Docket
ID
No.
OAR
 
2002
 
0058.
The
EPA
requests
a
separate
copy
also
be
sent
to
the
contact
person
listed
above
(
see
FOR
FURTHER
INFORMATION
CONTACT).
By
Hand
Delivery
or
Courier.
Deliver
your
comments
to:
EPA
Docket
Center,
Room
B108,
1301
Constitution
Ave.,
NW.,
Washington,
DC,
Attention
Docket
ID
No.
OAR
 
2002
 
0058.
Such
deliveries
are
only
accepted
during
the
Docket's
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/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
normal
hours
of
operation
as
identified
above.
Do
not
submit
information
that
you
consider
to
be
CBI
electronically
through
EPA's
electronic
public
docket
or
by
e­
mail.
Send
or
deliver
information
identified
as
CBI
only
to
the
following
address:
Mr.
Jim
Eddinger,
c/
o
OAQPS
Document
Control
Officer
(
Room
C404
 
2),
U.
S.
EPA,
Research
Triangle
Park,
27711,
Attention
Docket
ID
No.
OAR
 
2002
 
0058.
You
may
claim
information
that
you
submit
to
EPA
as
CBI
by
marking
any
part
or
all
of
that
information
as
CBI
(
if
you
submit
CBI
on
disk
or
CD
ROM,
mark
the
outside
of
the
disk
or
CD
ROM
as
CBI
and
then
identify
electronically
within
the
disk
or
CD
ROM
the
specific
information
that
is
CBI).
Information
so
marked
will
not
be
disclosed
except
in
accordance
with
procedures
set
forth
in
40
CFR
part
2.
In
addition
to
one
complete
version
of
the
comment
that
includes
any
information
claimed
as
CBI,
a
copy
of
the
comment
that
does
not
contain
the
information
claimed
as
CBI
must
be
submitted
for
inclusion
in
the
public
docket
and
EPA's
electronic
public
docket.
If
you
submit
the
copy
that
does
not
contain
CBI
on
disk
or
CD
ROM,
mark
the
outside
of
the
disk
or
CD
ROM
clearly
that
it
does
not
contain
CBI.
Information
not
marked
as
CBI
will
be
included
in
the
public
docket
and
EPA's
electronic
public
docket
without
prior
notice.
If
you
have
any
questions
about
CBI
or
the
procedures
for
claiming
CBI,
please
consult
the
person
identified
in
the
FOR
FURTHER
INFORMATION
CONTACT
section.
You
may
find
the
following
suggestions
helpful
for
preparing
your
comments:
1.
Explain
your
views
as
clearly
as
possible.
2.
Describe
any
assumptions
that
you
used.
3.
Provide
any
technical
information
and/
or
data
you
used
that
support
your
views.
4.
If
you
estimate
potential
burden
or
costs,
explain
how
you
arrived
at
your
estimate.
5.
Provide
specific
examples
to
illustrate
your
concerns.
6.
Offer
alternatives.
7.
Make
sure
to
submit
your
comments
by
the
comment
period
deadline
identified.
8.
To
ensure
proper
receipt
by
EPA,
identify
the
appropriate
docket
identification
number
in
the
subject
line
on
the
first
page
of
your
response.
It
would
also
be
helpful
if
you
provided
the
name,
date,
and
Federal
Register
citation
related
to
your
comments.
Public
Hearing.
Persons
interested
in
presenting
oral
testimony
or
inquiring
as
to
whether
a
hearing
is
to
be
held
should
contact
Ms.
Kelly
Hayes,
Combustion
Group,
Emission
Standards
Division
(
C439
 
01),
U.
S.
EPA,
Research
Triangle
Park,
North
Carolina
27711,
telephone
(
919)
541
 
5578
at
least
2
days
in
advance
of
the
public
hearing.
Persons
interested
in
attending
the
public
hearing
must
also
call
Ms.
Kelly
Hayes
to
verify
the
time,
date,
and
location
of
the
hearing.
The
public
hearing
will
provide
interested
parties
the
opportunity
to
present
data,
views,
or
arguments
concerning
the
proposed
rule.
If
a
public
hearing
is
requested
and
held,
EPA
will
ask
clarifying
questions
during
the
oral
presentation
but
will
not
respond
to
the
presentations
or
comments.
Written
statements
and
supporting
information
will
be
considered
with
equivalent
weight
as
any
oral
statement
and
supporting
information
presented
at
a
public
hearing,
if
held.
Outline.
The
information
presented
in
this
preamble
is
organized
as
follows:

I.
Background
Information
A.
What
criteria
are
used
in
the
development
of
NESHAP?
B.
What
is
the
regulatory
development
background
of
the
source
categories
in
the
proposed
rule?
C.
What
is
the
statutory
authority
for
the
proposed
rule?
D.
What
is
the
relationship
between
the
proposed
rule
and
other
combustion
rules?
E.
What
are
the
health
effects
of
pollutants
emitted
from
industrial/
commercial/
institutional
boilers
and
process
heaters?
II.
Summary
of
the
Proposed
Rule
A.
What
source
categories
and
subcategories
are
affected
by
the
proposed
rule?
B.
What
pollutants
are
emitted?
C.
What
is
the
affected
source?
D.
Does
the
proposed
rule
apply
to
me?
E.
What
emission
limitations
and
work
practice
standards
must
I
meet?
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?
III.
Rationale
of
the
Proposed
Rule
A.
How
did
EPA
determine
which
pollution
sources
would
be
regulated
under
the
proposed
rule?
B.
How
did
EPA
select
the
format
for
the
proposed
rule?
C.
How
did
EPA
determine
the
proposed
emission
limitations
for
existing
units?
D.
How
did
EPA
determine
the
MACT
floor
for
existing
units?
E.
How
did
EPA
consider
beyond­
the­
floor
for
existing
units?
F.
Should
EPA
consider
different
subcategories
for
solid
fuel
boilers
and
process
heaters?
G.
How
did
EPA
determine
the
proposed
emission
limitations
for
new
units?
H.
How
did
EPA
determine
the
MACT
floor
for
new
units?
I.
How
did
EPA
consider
beyond­
the­
floor
for
new
units?
J.
How
did
EPA
determine
testing
and
monitoring
requirements
for
the
proposed
rule?
K.
How
did
EPA
determine
compliance
times
for
the
proposed
rule?
L.
How
did
EPA
determine
the
required
records
and
reports
for
the
proposed
rule?
M.
How
does
the
proposed
rule
affect
permits?
N.
What
alternative
provisions
are
being
considered?
IV.
Impacts
of
the
Proposed
Rule
A.
What
are
the
air
impacts?
B.
What
are
the
water
and
solid
waste
impacts?
C.
What
are
the
energy
impacts?
D.
What
are
the
control
costs?
E.
Can
we
achieve
the
goals
of
the
proposed
rule
in
a
less
costly
manner?
F.
What
are
the
economic
impacts?
G.
What
are
the
social
costs
and
benefits
of
the
proposed
rule?
V.
Public
Participation
and
Requests
for
Comment
VI.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
B.
Executive
Order
13132,
Federalism
C.
Executive
Order
13175,
Consultation
and
Coordination
with
Indian
Tribal
Governments
D.
Executive
Order
13045,
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
E.
Unfunded
Mandates
Reform
Act
of
1995
F.
Regulatory
Flexibility
Act
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.
G.
Paperwork
Reduction
Act
H.
National
Technology
Transfer
and
Advancement
Act
I.
Executive
Order
13211,
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
I.
Background
Information
A.
What
Criteria
Are
Used
in
the
Development
of
NESHAP?
Section
112
of
the
CAA
requires
EPA
to
promulgate
regulations
for
the
control
of
HAP
emissions
from
each
source
category
listed
under
section
112(
c)
of
the
CAA.
The
statute
requires
the
regulations
to
reflect
the
maximum
degree
of
reductions
in
emissions
of
HAP
that
is
achievable
taking
into
consideration
the
cost
of
achieving
emissions
reductions,
any
nonair
quality
health
and
environmental
impacts,
and
energy
requirements.
This
level
of
control
is
commonly
referred
to
as
MACT.
The
MACT
based
regulation
can
be
based
on
the
emissions
reductions
achievable
through
application
of
measures,
processes,
methods,
systems,
or
techniques
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/
Vol.
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No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
including,
but
not
limited
to:
(
1)
Reducing
the
volume
of,
or
eliminating
emissions
of,
such
pollutants
through
process
changes,
substitutions
of
materials,
or
other
modifications;
(
2)
enclosing
systems
or
processes
to
eliminate
emissions;
(
3)
collecting,
capturing,
or
treating
such
pollutants
when
released
from
a
process,
stack,
storage
or
fugitive
emission
point;
(
4)
design,
equipment,
work
practices,
or
operational
standards
as
provided
in
subsection
112(
h)
of
the
CAA;
or
(
5)
a
combination
of
the
above.
For
new
sources,
MACT
based
standards
cannot
be
less
stringent
than
the
emission
control
achieved
in
practice
by
the
best­
controlled
similar
source.
The
MACT
based
standards
for
existing
sources
can
be
less
stringent
than
standards
for
new
sources,
but
they
cannot
be
less
stringent
than
the
average
emission
limitation
achieved
by
the
best
performing
12
percent
of
existing
sources
for
categories
and
subcategories
with
30
or
more
sources,
or
the
best
performing
5
sources
for
categories
or
subcategories
with
fewer
than
30
sources.
In
essence,
these
MACT
based
standards
would
ensure
that
all
major
sources
of
toxic
air
emissions
achieve
the
level
of
control
already
being
achieved
by
the
better­
controlled
and
lower­
emitting
sources
in
each
category.
This
approach
provides
assurance
to
citizens
that
each
major
source
of
toxic
air
pollution
will
be
required
to
effectively
control
its
emissions.
A
major
source
of
HAP
emissions
is
any
stationary
source
or
group
of
stationary
sources
located
within
a
contiguous
area
and
under
common
control
that
emits
or
has
the
potential
to
emit
any
single
HAP
at
a
rate
of
10
tons
or
more
per
year
or
any
combination
of
HAP
at
a
rate
of
25
tons
or
more
a
year.
At
the
same
time,
this
approach
provides
a
level
economic
playing
field,
ensuring
that
facilities
that
employ
cleaner
processes
and
good
emission
controls
are
not
disadvantaged
relative
to
competitors
with
poorer
controls.

B.
What
Is
the
Regulatory
Development
Background
of
the
Source
Categories
in
the
Proposed
Rule?
In
September
1996,
EPA
chartered
the
Industrial
Combustion
Coordinated
Rulemaking
(
ICCR)
advisory
committee
under
the
Federal
Advisory
Committee
Act
(
FACA).
The
committee's
objective
was
to
develop
recommendations
for
regulations
for
several
combustion
source
categories
under
sections
112
and
129
of
the
CAA.
The
ICCR
advisory
committee,
known
as
the
Coordinating
Committee,
formed
Source
Work
Groups
for
the
various
combustion
types
covered
under
the
ICCR.
One
of
the
work
groups
was
formed
to
research
issues
related
to
boilers;
another
was
formed
to
research
issues
related
to
process
heaters.
The
Boiler
and
Process
Heater
Work
Groups
submitted
recommendations,
information,
and
data
analysis
results
to
the
Coordinating
Committee,
which
in
turn
considered
them
and
submitted
recommendations
and
information
to
EPA.
The
Committee's
recommendations
were
considered
by
EPA
in
developing
the
proposed
rule
for
boilers
and
process
heaters.
The
Committee's
2­
year
charter
expired
in
September
1998.
Following
the
expiration
of
the
ICCR
FACA
charter,
EPA
decided
to
combine
boilers
with
units
in
the
process
heater
source
category
covering
indirect­
fired
units,
and
to
regulate
both
under
the
proposed
NESHAP.
This
was
done
because
indirect­
fired
process
heaters
and
boilers
are
similar
devices,
burn
similar
fuel,
have
similar
emission
characteristics,
and
emissions
from
each
can
be
controlled
using
similar
control
devices
or
techniques.

C.
What
Is
the
Statutory
Authority
for
the
Proposed
Rule?

Section
112
of
the
CAA
requires
that
EPA
promulgate
regulations
requiring
the
control
of
HAP
emissions
from
major
sources
and
certain
area
sources.
The
control
of
HAP
is
achieved
through
promulgation
of
emission
standards
under
sections
112(
d)
and
(
f)
of
the
CAA
and,
in
appropriate
circumstances,
work
practice
standards
under
section
112(
h)
of
the
CAA.
An
initial
list
of
categories
of
major
and
area
sources
of
HAP
selected
for
regulation
in
accordance
with
section
112(
c)
of
the
CAA
was
published
in
the
Federal
Register
on
July
16,
1992
(
57
FR
31576).
Industrial
boilers,
commercial
and
institutional
boilers,
and
process
heaters
are
three
of
the
listed
174
categories
of
sources.
The
listing
was
based
on
the
Administrator's
determination
that
they
may
reasonably
be
anticipated
to
emit
several
of
the
188
listed
HAP
in
quantities
sufficient
to
designate
them
as
major
sources.

D.
What
Is
the
Relationship
Between
the
Proposed
Rule
and
Other
Combustion
Rules?

The
proposed
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
today's
proposed
rule
any
units
that
are
already
or
will
be
subject
to
regulation
under
another
MACT
standard.
The
commercial
and
industrial
solid
waste
incinerators
(
CISWI)
standards
(
40
CFR
60,
subparts
CCCC
and
DDDD)
regulate
commercial
and
industrial
nonhazardous
solid
waste
incinerators.
Sources
subject
to
the
CISWI
rules
are
exempt
from
the
requirements
of
the
proposed
rule.
The
utility
HAP
study
Report
to
Congress
provides
information
used
to
determine
whether
fossil
fuel­
fired
utility
boilers
should
be
regulated
in
a
future
MACT
standard.
A
fossil
fuelfired
utility
boiler
is
a
fossil
fuel­
fired
combustion
unit
with
a
heat
input
greater
than
25
megawatts
that
serves
a
generator
producing
electricity
for
sale.
Fossil
fuel­
fired
utility
boilers
are
exempt
from
the
proposed
rule.
Nonfossil
fuel­
fired
utility
boilers
are
covered
by
the
proposed
rule.
The
EPA's
Office
of
Solid
Waste
is
in
the
process
of
developing
MACT
based
standards
for
hazardous
waste
boilers.
Boilers
burning
hazardous
waste
are
not
included
in
the
proposed
rule.
In
1986,
EPA
had
codified
new
source
performance
standards
(
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
oxides
from
boilers
constructed
after
June
19,
1984.
Sources
subject
to
the
NSPS
are
still
subject
to
the
proposed
rule
because
the
proposed
rule
regulates
sources
of
hazardous
air
pollutants
while
the
NSPS
does
not.
However,
in
developing
the
proposed
rule
for
industrial/
commercial/
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
proposed
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
proposed
rule
refining
kettles
subject
to
the
secondary
lead
MACT
rule
(
40
CFR
63,
subpart
X).
This
is
one
combustion
unit
meeting
the
definition
of
a
process
heater,
that
we
are
specifically
aware
of,
that
is
covered
by
another
MACT
standard.
Therefore,
we
are
requesting
comments
on
other
process
heaters
that
are
already
or
will
be
subject
to
regulation
under
another
MACT
standard.

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Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
E.
What
Are
the
Health
Effects
of
Pollutants
Emitted
From
Industrial/
Commercial/
Institutional
Boilers
and
Process
Heaters?

Today's
proposed
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
hydrogen
chloride
emissions
represent
the
predominant
HAP
emitted
by
industrial
boilers,
accounting
for
59
percent
of
the
total
HAP
emissions.
Industrial
boilers
and
process
heaters
also
emit
lesser
amounts
of
hydrogen
fluoride,
accounting
for
about
5
percent
of
total
HAP
emissions,
and
metals
(
arsenic,
cadmium,
chromium,
mercury,
manganese,
nickel,
and
lead),
accounting
for
about
4
percent
of
total
HAP
emissions.
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
two
of
the
HAP
as
human
carcinogens
and
three
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,
today's
proposed
rule
would
reduce
emissions
and
subsequent
exposures.

1.
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.

2.
Cadmium
The
acute
(
short­
term)
effects
of
cadmium
inhalation
in
humans
consist
mainly
of
effects
on
the
lung,
such
as
pulmonary
irritation.
Chronic
(
longterm
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.

3.
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
(
longterm
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.
4.
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.

5.
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.

6.
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
(
short­
term)
exposure
to
high
levels
of
lead
in
humans.
Chronic
(
longterm
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
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exposure
by
the
oral
route.
The
EPA
has
classified
lead
as
a
Group
B2,
probable
human
carcinogen.

7.
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.
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
masklike
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.

8.
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
(
longterm
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.

9.
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
Proposed
Rule
A.
What
Source
Categories
and
Subcategories
Are
Affected
by
the
Proposed
Rule?

The
proposed
rule
affects
industrial
boilers,
institutional
and
commercial
boilers,
and
process
heaters.
In
the
proposed
rule
process
heaters
are
defined
as
units
in
which
the
combustion
gases
do
not
directly
come
into
contact
with
process
gases
in
the
combustion
chamber
(
e.
g.,
indirect
fired).
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.
Combustion
units
are
not
subject
to
the
proposed
rule
simply
by
virtue
of
having
a
waste
heat
boiler.
A
waste
heat
boiler
(
or
heat
recovery
steam
generator)
is
a
device
that
recovers
normally
unused
energy
and
converts
it
to
usable
heat.
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
today's
proposed
rule.
A
hot
water
heater
is
a
closed
vessel
in
which
water
is
heated
by
combustion
of
gaseous
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.

B.
What
Pollutants
Are
Emitted?
Boilers
and
process
heaters
emit
PM,
volatile
organic
compounds,
and
hazardous
air
pollutants,
depending
on
the
material
burned.
Solid
and
liquid
fuel­
fired
units
emit
metals,
halogenated
compounds
and
organic
compounds.
Gas
fuel­
fired
units
emit
mostly
organic
compounds.

C.
What
Is
the
Affected
Source?
The
affected
source
is
each
individual
industrial,
commercial,
or
institutional
boiler
or
process
heater
located
at
a
major
facility.
The
affected
source
does
not
include
units
that
are
municipal
waste
combustors
(
40
CFR
part
60,
subparts
AAAA,
BBBB,
Eb
or
Cb),
medical
waste
incinerators
(
40
CFR
part
60,
subpart
Ce
and
Ec),
fossil
fuel­
fired
electric
utility
steam
generating
units,
commercial
and
industrial
solid
waste
incineration
units
(
40
CFR
part
60,
subparts
CCCC
or
DDDD),
recovery
boilers
or
furnaces
(
40
CFR
part
63,
subpart
MM),
ethylene
cracking
furnaces
(
40
CRF
part
63,
subpart
YY),
or
hazardous
waste
combustion
units
required
to
have
a
permit
under
section
3005
of
the
Solid
Waste
Disposal
Act
or
are
subject
to
40
CFR
part
63,
subpart
EEE.

D.
Does
the
Proposed
Rule
Apply
to
Me?
The
proposed
rule
applies
to
you
if
you
own
or
operate
a
boiler
or
process
heater
at
a
major
source
meeting
the
requirements
discussed
previously
in
this
preamble.
A
major
source
of
HAP
emissions
is
any
stationary
source
or
group
of
stationary
sources
located
within
a
contiguous
area
and
under
common
control
that
emits
or
has
the
potential
to
emit
any
single
HAP
at
a
rate
of
10
tons
or
more
per
year
or
any
combination
of
HAP
at
a
rate
of
25
tons
or
more
a
year.

E.
What
Emission
Limitations
and
Work
Practice
Standards
Must
I
Meet?
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
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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.
If
your
new
or
existing
boiler
or
process
heater
burns
a
gaseous
fuel
only,
the
unit
is
in
the
gas
subcategory.

TABLE
1.
 
EMISSION
LIMITS
AND
WORK
PRACTICE
STANDARDS
FOR
BOILERS
AND
PROCESS
HEATERS
[
Pounds
per
million
British
thermal
units]

Source
Subcategory
Particulate
matter
(
PM)
or
Total
selected
metals
Hydrogen
chloride
(
HCl)
Mercury
(
Hg)
Carbon
Monoxide
(
CO)(
ppm@
3%
oxygen)

New
Boiler,
or
Process
Heater.
Solid
Fuel,
Large
Unit
0.026
or
0.0001
0.02
0.000003
400
Solid
Fuel,
Small
Unit
0.026
or
0.0001
0.02
0.000003
.....................................
Solid
Fuel,
Limited
Use.
0.026
or
0.0001
0.02
0.000003
400
Liquid
Fuel,
Large
Unit.
0.03
........
......................
0.0005
......................
400
Liquid
Fuel,
Small
Unit
0.03
........
0.0009
......................
......................
Liquid
Fuel,
Limited
Use.
0.03
........
......................
0.0009
......................
400
Gaseous
Fuel
Large
Unit.
......................
........
......................
......................
......................
400
Gaseous
Fuel
Small
Unit.
......................
........
......................
......................

Gaseous
Fuel
Limited
Use.
......................
........
......................
......................
......................
400
Existing
Boiler
or
Process
Heater.
Solid
Fuel,
Large
Unit
0.07
or
0.001
0.09
0.000007
.....................................

Solid
Fuel,
Small
Unit
......................
........
......................
......................
......................
.....................................
Solid
Fuel,
Limited
Used.
0.2
or
0.001
......................
......................
.....................................

Liquid
Fuel,
Large
Unit.
......................
........
......................
......................
......................
.....................................

Liquid
Fuel,
Small
Unit
......................
........
......................
......................
......................
.....................................
Liquid
Fuel,
Limited
Use.
......................
........
......................
......................
......................
.....................................

Gaseous
Fuel
............
......................
........
......................
......................
......................
.....................................

For
solid
fuel­
fired
boilers
or
process
heaters,
we
are
proposing
to
allow
sources
to
choose
one
of
two
emission
limit
options:
(
1)
Existing
and
new
affected
sources
may
choose
to
limit
PM
emissions
to
the
level
listed
in
Table
1
of
this
preamble
or
(
2)
existing
and
new
affected
sources
may
choose
to
limit
total
selected
metals
emissions
to
the
level
listed
in
Table
1
of
this
preamble.
If
you
do
not
use
an
add­
on
control
or
use
an
add­
on
control
other
than
a
wet
scrubber,
you
must
maintain
opacity
level
to
less
than
or
equal
to
the
level
established
during
the
compliance
test
for
mercury
and
PM
or
total
selected
metals,
and
maintain
the
fuel
chlorine
content
to
less
than
or
equal
to
the
operating
level
established
during
the
HCl
compliance
test.
If
you
use
a
wet
scrubber,
you
must
maintain
the
minimum
pH,
pressure
drop
and
liquid
flow­
rate
above
the
operating
levels
established
during
the
performance
tests.
If
you
use
a
dry
scrubber,
you
must
maintain
opacity
level
and
the
minimum
sorbent
injection
rate
established
during
the
performance
test.
If
you
use
an
electrostatic
precipitator
(
ESP)
in
combination
with
a
wet
scrubber
and
cannot
monitor
the
opacity,
you
must
maintain
the
average
secondary
current
and
voltage
or
total
power
input
established
during
the
performance
test.
There
is
an
alternative
compliance
procedure
and
operating
limit
for
meeting
the
total
selected
metals
emission
limit
option
or
the
mercury
emission
limit
option.
If
you
have
no
control
or
do
not
want
to
take
credit
of
metals
reductions
with
your
existing
control
device,
and
can
show
that
total
metals
in
the
fuel
would
be
less
than
the
metals
emission
level,
then
you
can
monitor
the
metals
fuel
analysis
to
meet
the
metals
emissions
limitations.
Similarly,
if
you
do
not
have
an
emission
control
device
or
you
otherwise
would
rather
comply
by
limiting
the
mercury
input
at
your
facility,
and
can
show
that
mercury
in
the
fuel
would
be
less
than
the
mercury
emission
level,
then
you
can
monitor
the
mercury
fuel
analysis
to
meet
the
mercury
emission
limitations.
If
your
unit
is
a
new
source
in
the
large
or
limited
use
subcategories,
it
must
meet
a
carbon
monoxide
(
CO)
emission
limit
of
400
parts
per
million
corrected
to
3
percent
oxygen.
If
your
new
or
existing
source
is
controlled
with
a
fabric
filter,
then
you
must
install
a
bag
leak
detection
system
such
that
the
bag
detection
system
alarm
does
not
sound
more
than
5
percent
of
the
operating
time
during
a
6­
month
period.

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
to
demonstrate
compliance
with
any
applicable
emission
limits.
The
applicable
emission
limits
and,

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8
/
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13,
2003
/
Proposed
Rules
therefore,
the
required
performance
tests
are
different
depending
on
the
subcategory
classification
of
the
unit.
Existing
units
in
the
small
solid
fuel
subcategory
and
in
any
of
the
liquid
or
gaseous
fuel
subcategories
do
not
have
applicable
emission
limits
and,
therefore,
are
not
required
to
conduct
stack
tests.
Other
units
are
required
to
conduct
the
following
compliance
tests
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
then
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
(
for
boilers
with
rated
heat
input
capacities
of
less
than
250
MMBtu
per
hour)
or
the
draft
ASTM
Z65907,
``
Standard
Method
for
Both
Speciated
and
Elemental
Mercury
Determination,''
(
for
boilers
with
rated
heat
input
capacities
of
greater
than
250
MMBtu
per
hour).
(
4)
Conduct
initial
and
annual
stack
tests
to
determine
compliance
with
the
HCl
emission
limits
using
EPA
Method
26
in
appendix
A
to
part
60
of
this
chapter
(
for
boilers
without
wet
scrubbers)
or
EPA
Method
26A
in
appendix
A
to
part
60
of
this
chapter
(
for
boilers
with
wet
scrubbers).
(
5)
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.
(
6)
For
new
units
in
any
of
the
liquid
fuel
subcategories
that
do
not
burn
residual
oil,
instead
of
conducting
an
initial
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.
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
1­
hour
test
run
over
the
3­
hour
performance
test.
The
minimum
or
maximum
of
the
three
average
values
(
depending
on
the
parameter
measured)
for
each
applicable
parameter
is
established
as
a
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
the
following
units:
(
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
measure
opacity
during
the
performance
test
and
calculate
the
6­
minute
averages.
The
maximum
1­
hour
average
measured
establishes
your
sitespecific
opacity
operating
limit.
Or,
if
the
unit
is
controlled
with
a
fabric
filter,
instead
of
setting
an
opacity
operating
limit,
the
fabric
filter
must
be
operated
such
that
the
required
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
measure
the
average
chlorine
content
level
in
the
input
fuel(
s)
during
the
HCl
performance
test.
This
is
your
maximum
chlorine
input
operating
limit.
If
you
plan
to
burn
a
new
fuel,
a
fuel
from
a
new
mixture,
or
a
fuel
from
a
new
supplier
than
what
was
burned
during
the
initial
performance
test,
then
you
must
recalculate
the
maximum
chlorine
input
anticipated
from
the
new
fuels
based
on
supplier
data
or
own
fuel
analysis.
If
the
results
of
recalculating
the
chlorine
input
exceeds
the
average
chlorine
content
level
established
during
the
initial
test
then
you
must
conduct
a
new
performance
test
to
demonstrate
compliance
with
the
HCl
emission
limit.
(
3)
For
boilers
and
process
heaters
with
wet
scrubbers
that
must
comply
with
a
mercury,
PM
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
average
values
becomes
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
a
PM
or
mercury
emission
limit,
you
must
measure
opacity
during
the
PM
performance
test
as
described
above.
If
you
must
also
comply
with
an
HCl
emission
limit,
you
must
measure
the
sorbent
injection
rate
during
the
performance
test
for
HCl,
and
calculate
the
average
for
each
test
run.
The
minimum
test
run
average
established
during
the
performance
test
is
your
sitespecific
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
emission
limit
and/
or
an
HCl
emission
limit,
you
must
measure
the
pH,
pressure
drop,
and
liquid
flow­
rate
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
flow­
rate
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
ESP
in
combination
with
wet
scrubbers
that
must
comply
with
a
mercury,
PM
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
current
of
the
ESP
collection
plates
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
flow­
rate
operating
limit
for
the
wet
scrubber
and
the
minimum
voltage
and
current
operating
limits
for
the
ESP
plates.
(
7)
For
boilers
that
choose
to
comply
with
the
alternative
total
selected
metals
emission
limit
instead
of
PM
and
have
either
no
add­
on
controls
or
add­
on
controls
for
which
you
do
not
want
to
take
credit
for
any
emission
reduction
of
metals,
you
must
measure
the
total
selected
metals
content
of
the
inlet
fuel
that
was
burned
during
the
total
selected
metals
performance
test.
This
value
is
your
maximum
fuel
inlet
metals
content
operating
limit.
If
you
plan
to
burn
a
new
fuel,
a
fuel
from
a
new
mixture,
or
a
fuel
from
a
new
supplier
than
what
was
burned
during
the
initial
performance
test,
then
you
must
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/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
recalculate
the
maximum
metals
input
anticipated
from
the
new
fuels
based
on
supplier
data
or
own
fuel
analysis.
If
the
results
of
recalculating
the
metals
input
exceeds
the
average
metals
content
level
established
during
the
initial
test
then
you
must
conduct
a
new
performance
test
to
demonstrate
compliance
with
the
alternate
total
selected
metals
emission
limit.
(
8)
For
boilers
that
choose
to
demonstrate
compliance
with
the
mercury
emission
limit
on
the
basis
of
fuel
analysis
and
have
no
add­
on
controls
or
add­
on
controls
for
which
you
do
not
want
to
take
credit
for
any
emission
reduction
of
mercury,
you
must
measure
the
mercury
content
of
the
inlet
fuel
that
was
burned
during
the
mercury
performance
test.
This
value
is
your
maximum
fuel
inlet
mercury
operating
limit.
If
you
plan
to
burn
a
new
fuel,
a
fuel
from
a
new
mixture,
or
a
fuel
from
a
new
supplier
than
what
was
burned
during
the
initial
performance
test,
then
you
must
recalculate
the
maximum
mercury
input
anticipated
from
the
new
fuels
based
on
supplier
data
or
own
fuel
analysis.
If
the
results
of
recalculating
the
mercury
input
exceeds
the
average
mercury
content
level
established
during
the
initial
test
then
you
must
conduct
a
new
performance
test
to
demonstrate
compliance
with
the
mercury
emission
limit.
(
9)
For
new
boilers
and
process
heaters
in
any
of
the
large
or
limited
use
subcategories,
you
must
monitor
CO
during
the
performance
tests
for
PM
(
or
metals)
and/
or
HCl
to
demonstrate
that
average
CO
emissions
are
at
or
below
an
exhaust
concentration
of
400
parts
per
million
(
ppm)
by
volume
on
a
dry
basis
corrected
to
3
percent
oxygen.

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
following
performance
tests:
(
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
3­
hour
block
average
at
or
below
your
site­
specific
opacity
operating
limit.
Or,
if
the
unit
is
controlled
with
a
fabric
filter,
instead
of
continuous
monitoring
opacity,
the
fabric
filter
must
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
daily
records
of
fuel
use
that
demonstrate
that
you
have
burned
no
new
fuels
such
that
you
have
maintained
the
fuel
chlorine
content
level
at
or
below
your
site­
specific
maximum
chlorine
input
operating
limit.
If
you
plan
to
burn
a
new
fuel,
a
fuel
from
a
new
mixture,
or
a
fuel
from
a
new
supplier
than
what
was
burned
during
the
initial
performance
test,
then
you
must
recalculate
the
maximum
chlorine
input
anticipated
from
the
new
fuels
based
on
supplier
data
or
own
fuel
analysis.
If
the
results
of
recalculating
the
chlorine
input
exceeds
the
average
chlorine
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
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
mercury
emission
limit,
you
must
monitor
and
maintain
opacity
levels
as
described
above
to
demonstrate
continuous
compliance
with
the
PM
emission
limits.
If
you
must
also
comply
with
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
flow­
rate
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
and
you
must
monitor
the
voltage
and
current
of
the
ESP
collection
plates
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
that
choose
to
comply
with
the
alternative
total
selected
metals
limit
instead
of
PM
emission
limit
based
on
fuel
analysis
rather
than
on
performance
testing,
you
must
maintain
daily
fuel
records
that
demonstrate
that
you
burned
no
new
fuels
or
fuels
from
a
new
supplier
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,
a
fuel
from
a
new
mixture,
or
a
fuel
from
a
new
supplier
than
what
was
burned
during
the
initial
performance
test,
then
you
must
recalculate
the
maximum
metals
input
anticipated
from
the
new
fuels
based
on
supplier
data
or
own
fuel
analysis.
If
the
results
of
recalculating
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
that
choose
to
comply
with
the
mercury
emission
limit
based
on
fuel
analysis
rather
than
on
performance
testing,
you
must
maintain
daily
fuel
records
that
demonstrate
that
you
burned
no
new
fuels
or
fuels
from
a
new
supplier
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,
a
fuel
from
a
new
mixture,
or
a
fuel
from
a
new
supplier
than
what
was
burned
during
the
initial
performance
test,
then
you
must
recalculate
the
maximum
mercury
input
anticipated
from
the
new
fuels
based
on
supplier
data
or
own
fuel
analysis.
If
the
results
of
recalculating
the
mercury
input
exceeds
the
average
mercury
content
level
established
during
the
initial
test
then
you
must
conduct
a
new
performance
test
to
demonstrate
continuous
compliance
with
the
mercury
emission
limit.
(
9)
For
new
boilers
and
process
heaters
in
any
of
the
large
or
limited
use
subcategories,
you
must
continuously
monitor
CO
and
maintain
the
average
CO
emissions
at
or
below
400
ppm
by
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Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
volume
on
a
dry
basis
corrected
to
3
percent
oxygen
to
demonstrate
compliance
with
the
work
practice
standards.
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.
If
a
control
device
other
than
the
ones
specified
in
this
section
is
used
to
comply
with
the
proposed
rule,
you
must
establish
site­
specific
operating
limits
and
establish
appropriate
continuous
monitoring
requirements,
as
approved
by
the
Administrator.

H.
What
Are
the
Notification,
Recordkeeping
and
Reporting
Requirements?

You
must
keep
the
following
records:
(
1)
All
reports
and
notifications
submitted
to
comply
with
the
proposed
rule.
(
2)
Continuous
monitoring
data
as
required
in
the
proposed
rule.
(
3)
Each
instance
in
which
you
did
not
meet
each
emission
limit
and
each
operating
limit,
including
periods
of
startup,
shutdown,
and
malfunction
(
i.
e.,
deviations
from
the
proposed
rule).
(
4)
Daily
hours
of
operation
by
each
source.
(
5)
Total
fuel
use
by
each
affected
source
electing
to
comply
with
an
emission
limit
based
on
fuel
analysis
for
each
30­
day
period
along
with
a
description
of
the
fuel,
the
total
fuel
usage
amounts
and
units
of
measure,
and
information
on
the
supplier
and
original
source
of
the
fuel.
(
6)
Calculations
and
supporting
information
of
chlorine
fuel
input,
as
required
in
the
proposed
rule.
(
7)
Calculations
and
supporting
information
of
total
selected
metals
and
mercury
fuel
input,
as
required
in
the
proposed
rule,
if
applicable.
(
8)
A
signed
statement,
as
required
in
the
proposed
rule,
indicating
you
burned
no
new
fuels,
no
fuels
from
a
new
supplier,
or
no
new
fuel
mixture
or
the
recalculation
of
chlorine
input
to
demonstrate
that
the
new
fuel,
new
mixture,
new
source
still
meets
chlorine
fuel
input
levels.
(
9)
A
signed
statement,
as
required
in
the
proposed
rule,
indicating
you
burned
no
new
fuels,
no
fuels
from
a
new
supplier,
or
no
new
fuel
mixture
or
the
recalculation
of
total
selected
metals
fuel
input
to
demonstrate
that
the
new
fuel,
new
fuel
mixture,
or
fuel
from
a
new
source
still
meets
the
total
selected
metals
fuel
input
levels.
(
10)
A
signed
statement,
as
required
in
the
proposed
rule,
indicating
you
burned
no
new
fuels,
no
fuels
from
a
new
supplier,
or
no
new
fuel
mixture
or
the
recalculation
of
mercury
fuel
input
to
demonstrate
that
the
new
fuel,
new
fuel
mixture,
or
fuel
from
a
new
source
still
meets
the
mercury
fuel
input
levels.
(
11)
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
proposed
rule.
(
12)
A
copy
of
any
Federally
enforceable
permit
that
limits
the
annual
capacity
factor
of
the
source
to
less
than
or
equal
to
10
percent.
(
13)
A
copy
of
your
site­
specific
startup,
shutdown,
and
malfunction
plan.
(
14)
A
copy
of
your
site­
specific
monitoring
plan
developed
for
the
proposed
rule,
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
60
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)
Compliance
reports
semi­
annually.

III.
Rationale
of
the
Proposed
Rule
A.
How
Did
EPA
Determine
Which
Pollution
Sources
Would
Be
Regulated
Under
the
Proposed
Rule?

The
proposed
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
today's
proposed
rule
any
units
that
are
already
or
will
be
subject
to
regulation
under
another
MACT
standard.
A
list
of
combustion
units
excluded
from
the
proposed
rule
is
discussed
previously
in
this
preamble.
The
CAA
specifically
requires
that
fossil
fuel­
fired
steam
generating
units
of
more
than
25
megawatts
that
produce
electricity
for
sale
(
i.
e.,
utility
boilers)
be
reviewed
separately
by
EPA.
Consequently,
the
proposed
rule
does
not
regulate
fossil
fuel­
fired
utility
boilers
greater
than
25
megawatts,
but
does
regulate
fossil
fuelfired
units
less
than
25
megawatts
and
all
nonfossil
fuel­
fired
utility
boilers.
The
proposed
rule
also
does
not
regulate
emissions
from
combustion
units
with
waste
heat
boilers,
unless
such
units
would
otherwise
be
subject
to
the
emission
limitations
in
today's
proposed
rule.
For
example,
emissions
from
any
commercial
or
industrial
solid
waste
incinerator
(
CISWI)
or
other
incinerator
unit
that
has
a
waste
heat
boiler
will
be
covered
by
regulations
promulgated
under
section
129
of
the
CAA.
During
the
ICCR
FACA,
the
scope
of
the
process
heater
source
category
was
limited
to
regulate
only
indirect­
fired
units.
Direct­
fired
units
are
covered
in
other
MACT
standards
or
rulemakings
pertaining
to
industrial
process
operations.
For
example,
lime
kilns
are
covered
by
the
Pulp
and
Paper
NESHAP
(
40
CFR
part
63,
subpart
S).
Indirectfired
process
heaters
are
similar
to
boilers
in
fuel
use,
emissions,
and
applicable
controls,
and,
therefore,
it
is
appropriate
for
EPA
to
combine
this
category
of
units
with
industrial,
commercial
and
institutional
boilers
for
purposes
of
developing
emission
standards.
Also
during
the
ICCR
FACA
process,
EPA
received
comments
from
stakeholders
regarding
the
potential
for
the
proposed
rule
to
regulate
small
hot
water
heaters
located
at
major
source
facilities.
Many
industrial
facilities
have
office
buildings
located
onsite
which
use
hot
water
heaters.
Such
hot
water
heaters,
by
their
design
and
operation,
could
be
considered
boilers.
However,
since
hot
water
heaters
generally
are
small
and
use
natural
gas
as
fuel,
their
emissions
are
negligible
compared
to
the
emissions
from
the
industrial
operations
that
make
such
facilities
major
sources,
and
compared
to
boilers
that
are
used
for
industrial,
commercial,
or
institutional
purposes.
Moreover,
such
hot
water
heaters
are
more
appropriately
described
as
residentialtype
boilers,
not
industrial,
commercial
or
institutional
boilers.
Consequently,
we
are
including
a
definition
of
hot
water
heaters
that
includes
fuel,
size,
pressure
and
temperature
limitations
that
we
believe
are
appropriate
to
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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
distinguish
between
residential­
type
units
and
industrial,
commercial
or
institutional
units.
Therefore,
the
proposed
rule
regulates
industrial,
commercial,
and
institutional
boilers
and
process
heaters
located
at
major
source
facilities
but
excludes
residential­
type
hot
water
heaters.
The
Clean
Air
Act
allows
EPA
to
divide
source
categories
into
subcategories
when
differences
between
given
types
of
units
lead
to
corresponding
differences
in
the
nature
of
emissions
and
the
technical
feasibility
of
applying
emission
control
techniques.
The
design,
operating,
and
emissions
information
that
EPA
has
reviewed
indicates
the
need
to
subcategorize
boilers
and
process
heaters
based
on
the
physical
state
of
the
fuel
burned,
i.
e.,
solid,
liquid,
or
gas.
Data
indicate
that
there
are
significant
design
and
operational
differences
between
units
that
burn
solid,
liquid
and
gaseous
fuels.
Boiler
systems
are
designed
for
specific
fuel
types
and
will
encounter
problems
if
a
fuel
with
characteristics
other
than
those
originally
specified
is
fired.
While
many
boilers
in
the
population
database
are
indicated
to
cofire
liquids
or
gases
with
solid
fuels,
in
actuality
most
of
these
commonly
use
fuel
oil
or
natural
gas
as
a
startup
fuel
only.
Other
co­
fired
units
are
specifically
designed
to
fire
combinations
of
solids,
liquids,
and
gases.
Changes
to
the
fuel
type
(
solid,
liquid,
or
gas)
would
require
extensive
changes
to
the
fuel
handling
and
feeding
system
(
e.
g.,
a
stoker
using
wood
as
fuel
would
need
to
be
redesigned
to
handle
fuel
oil
or
gaseous
fuel).
Additionally,
the
burners
and
combustion
chamber
would
need
to
be
redesigned
and
modified
to
handle
different
fuel
types
and
account
for
increases
or
decreases
in
the
fuel
volume
and
shape.
In
some
cases,
the
changes
may
reduce
the
capacity
and
efficiency
of
the
boiler
or
process
heater.
An
additional
effect
of
these
changes
would
be
extensive
retrofit
costs.
Emissions
from
boilers
and
process
heaters
burning
solids,
liquids,
and
gaseous
fuels
will
also
differ.
Boilers
and
process
heaters
emit
a
number
of
different
types
of
HAP
emissions.
In
general,
their
formation
is
dependent
upon
the
composition
of
the
fuel.
The
combustion
quality
and
temperature
may
also
play
an
important
role.
The
fuel
dependent
HAP
emissions
from
boilers
and
process
heaters
are
metals,
including
mercury,
and
acid
gases.
These
fuel
dependent
HAP
emissions
generally
can
be
controlled
by
either
changing
the
fuel
property
before
combustion
or
by
removing
the
HAP
from
the
flue
gas
after
combustion.
Organic
HAP,
on
the
other
hand,
are
formed
from
incomplete
combustion
and
are
much
less
influenced
by
the
characteristics
of
the
fuel
being
burned.
The
degree
of
combustion
may
be
greatly
influenced
by
three
general
factors:
time,
turbulence,
and
temperature.
These
factors
are
a
function
of
the
design
of
the
boiler
or
process
heater
which
is
dependent
in
part
on
the
type
of
fuel
being
burned.
Solid
fuel­
fired
units
will
emit
larger
amounts
of
PM
and
metals
depending
on
the
solid
fuel
burned.
Liquid
and
gaseous
fuel­
fired
units
generally
emit
larger
amounts
of
organic
HAP.
Because
these
different
types
of
units
have
different
emission
characteristics
which
may
influence
the
feasibility
of
effectiveness
of
emission
control,
they
should
be
regulated
separately
(
i.
e.,
subcategorized).
Thus,
these
categories
appropriately
identify
distinctly
different
types
of
units
subject
to
regulation.
Accordingly,
EPA
decided
to
subcategorize
boilers
and
process
heaters
into
solid,
liquid
and
gaseous
fuel
subcategories
in
order
to
account
for
these
differences
in
emissions
and
applicable
controls.
The
solid
fuel
subcategory
includes
boilers
and
process
heaters
burning
any
amount
of
solid
fuel
(
including
units
burning
a
combination
of
solid
fuel
and
liquid
or
gaseous
fuel).
The
gaseous
fuel
subcategory
includes
units
only
burning
gaseous
fuel.
The
liquid
fuel
subcategory
includes
all
remaining
boilers
and
process
heaters.
Small
boilers
and
process
heaters
were
also
identified
as
a
subcategory.
These
small
units
typically
are
package
units
having
capacities
less
than
10
MMBtu/
hr
heat
input
or
use
a
combustor
design
(
i.
e.,
firetube
or
cast
iron)
which
is
not
common
in
large
units.
Large
boilers
generally
are
fielderected
using
the
watertube
combustor
design
with
capacities
above
10
MMBtu/
hr.
As
discussed
above,
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
vast
majority
of
these
small
units
use
natural
gas
as
fuel.
Additionally,
most
existing
State
and
Federal
regulations
for
boilers
and
process
heaters
do
not
regulate
units
with
a
heat
input
capacity
of
less
than
10
MMBtu/
hr,
due
to
their
low
emissions.
Consequently,
we
decided
to
further
subcategorize
boilers
and
process
heaters
within
each
fuel
category
by
creating
subcategories
for
large
units
(
watertube
boilers
and
process
heaters
greater
than
10
MMBtu/
hr
capacity)
and
small
units
(
all
firetube
boilers
and
boilers
and
process
heaters
of
any
other
type
with
less
than
or
equal
to
10
MMBtu/
hr
capacity).
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.
Back­
up
or
emergency
units
only
operate
if
another
boiler
that
is
the
regular
source
of
energy
or
steam
is
not
operating
(
for
example
due
to
a
shutdown
for
maintenance
and
repair).
Peaking
units
operate
only
during
peak
energy
use
periods,
typically
in
the
summer
months.
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.
While
these
are
potential
sources
of
emissions,
and
it
is
appropriate
for
EPA
to
address
them
in
the
proposal,
the
Agency
believes
that
their
use
and
operation
are
different
compared
to
typical
industrial,
commercial,
and
institutional
boilers.
Consequently,
we
decided
that
such
limited
use
units
should
have
their
own
subcategory.
Therefore,
the
proposed
rule
has
subcategories
for
boilers
and
process
heaters
having
a
capacity
utilization
of
less
than
10
percent.
In
summary,
we
have
identified
nine
subcategories
of
boilers
and
process
heaters
located
at
major
sources:
(
1)
Large
solid
fuel­
fired
boilers
and
process
heaters
(
sizes
greater
than
10
MMBtu/
hr),
(
2)
large
liquid
fuel­
fired
boilers
and
process
heaters
(
sizes
greater
than
10
MMBtu/
hr),
(
3)
large
gaseous
fuel­
fired
boilers
and
process
heaters
(
sizes
greater
than
10
MMBtu/
hr),
(
4)
small
solid
fuel­
fired
boilers
and
process
heaters
(
firetubes
or
any
unit
less
than
or
equal
to
10
MMBtu/
hr),
(
5)
small
liquid
fuel­
fired
boilers
and
process
heaters
(
sizes
less
than
or
equal
to
10
MMBtu/
hr),
(
6)
small
gaseous
fuelfired
boilers
and
process
heaters
(
sizes
less
than
or
equal
to
10
MMBtu/
hr),
(
7)
limited
use
solid
fuel­
fired
boilers
and
process
heaters
(
large
units
with
capacity
utilization
less
than
or
equal
to
10
percent),
(
8)
limited
use
liquid
fuelfired
boilers
and
process
heaters
(
large
units
with
capacity
utilization
less
than
or
equal
to
10
percent),
and
(
9)
limited
use
gaseous
fuel­
fired
boilers
and
process
heaters
(
large
units
with
capacity
utilization
less
than
or
equal
to
10
percent).

B.
How
Did
EPA
Select
the
Format
for
the
Proposed
Rule?
The
proposed
rule
includes
emission
limits
for
PM,
selected
metallic
HAP,

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Proposed
Rules
mercury,
and
HCl
for
six
of
the
nine
subcategories.
The
selection
of
emission
limitations
as
the
format
for
the
proposed
rule
provides
flexibility
for
the
regulated
community
by
allowing
a
regulated
source
to
choose
any
control
technology
or
technique
to
meet
the
emission
limits,
rather
than
requiring
each
unit
to
use
a
prescribed
method
that
may
not
be
appropriate
in
each
case.
This
is
particularly
relevant
for
boilers
and
process
heaters,
because
they
can
burn
many
different
types
of
fuels
with
greatly
varying
emission
profiles
and
owners
need
flexibility
to
use
the
control
devices
that
are
best
for
their
particular
emission
characteristics.
The
EPA
selected
an
outlet
emission
rate
format
because
outlet
data
are
available
for
boilers
and
process
heaters
that
use
the
control
techniques
that
provide
the
greatest
reduction
in
HAP
emissions.
The
individual
limits
reflect
the
achievable
performance
of
boilers
and
process
heaters
using
the
appropriate
controls
for
each
type
of
emissions.
The
EPA
is
proposing
numerical
emission
rate
limits
as
a
mass
of
pollutant
emitted
per
heat
energy
input
to
the
boiler
or
process
heater.
The
most
typical
units
for
the
limits
are
pounds
of
pollutant
emitted
per
million
Btu
of
heat
input.
The
mass
per
heat
input
units
are
consistent
with
other
Federal
and
many
State
boiler
regulations
and
allows
easy
comparison
between
such
requirements.
Additionally,
the
proposed
rule
contains
an
option
to
monitor
inlet
chlorine,
mercury,
and
metals
content
in
the
fuel
to
meet
outlet
emission
rate
limits.
This
option
can
only
be
done
on
a
mass
basis.
The
EPA
considered
percent
reduction
and
outlet
concentration
as
alternative
formats
for
the
pollutants
regulated.
However,
an
outlet
concentration
limit
could
not
be
accurately
correlated
to
the
chlorine
content
in
the
inlet
fuel.
An
outlet
concentration
limit
would
also
not
be
consistent
with
the
format
of
other
regulations.
Affected
units
would
already
be
complying
with
a
mass
per
heat
input
limit,
so
EPA
did
not
believe
that
a
concentration
limit
would
provide
any
additional
benefits
or
flexibility.
Additionally,
data
were
insufficient
to
determine
percent
reductions
that
control
devices
achieve.
Furthermore,
a
percent
reduction
requirement
would
limit
the
flexibility
of
the
regulated
community
by
requiring
the
use
of
a
control
device.
Therefore,
neither
alternative
was
selected
as
the
format
for
the
proposed
rule.
The
EPA
requests
comments
on
the
appropriateness
of
percent
reduction
requirements
and
outlet
concentration
limit
requirements,
and
any
data
upon
which
those
requirements
could
be
based.
Boilers
and
process
heaters
can
emit
a
wide
variety
of
compounds,
depending
on
the
fuel
burned.
The
boiler
emissions
test
database
lists
over
100
possible
HAP.
Because
of
the
large
number
of
HAP
potentially
present
and
the
disparity
in
the
quantity
and
quality
of
the
emissions
information
available,
EPA
grouped
the
HAP
into
four
common
categories:
mercury,
nonmercury
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.
For
example,
non­
mercury
metallic
HAP
can
be
controlled
with
PM
controls.
The
EPA
chose
to
look
at
mercury
separately
from
other
metallic
HAP
due
to
its
different
chemical
characteristics
and
applicable
controls.
Next,
EPA
identified
compounds
that
could
be
used
as
surrogates
for
all
the
compounds
in
each
pollutant
category.
For
the
non­
mercury
metallic
HAP,
EPA
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
that
includes
some
amount
and
combination
of
metallic
HAP.
The
use
of
PM
as
a
surrogate
will
also
eliminate
the
cost
of
performance
testing
to
comply
with
numerous
standards
for
individual
metals.
However,
the
Agency
is
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,
the
Agency
is
also
proposing
an
alternative
metals
emission
limit.
A
source
may
choose
to
comply
with
the
alternative
metals
emissions
limit
instead
of
the
PM
limit
to
meet
the
proposed
rule.
The
metals
emission
limit
is
for
the
sum
of
emissions
of
eight
selected
metals:
arsenic,
beryllium,
cadmium,
chromium,
lead,
manganese,
nickel,
and
selenium.
The
eight
represent
the
most
common
and
the
largest
emitted
metallic
HAP
from
boilers
and
process
heaters.
For
inorganic
HAP,
EPA
chose
to
use
HCl
as
a
surrogate.
The
emissions
test
information
available
to
EPA
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,
EPA
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.
In
addition
to
meeting
emission
limits,
today's
proposal
would
also
require
sources
to
establish
control
device
operating
parameter
limits
and
continuously
monitor
control
device
operating
parameters.
Each
source
would
establish
site­
specific
values
for
the
relevant
parameters
during
performance
tests,
and
use
the
parameter
values
to
demonstrate
compliance
with
the
emission
limits.
We
selected
different
operating
parameters
for
each
type
of
potential
control
device.
The
parameters
were
selected
because
they
are
good
indicators
of
proper
control
device
operation
and
performance,
are
consistent
with
other
standards,
and
are
feasible
to
monitor.
The
operating
limits
reasonably
assure
that
the
control
devices
continue
to
operate
in
a
manner
that
will
achieve
the
same
level
of
control
as
during
the
performance
test.

C.
How
Did
EPA
Determine
the
Proposed
Emission
Limitations
for
Existing
Units?
All
standards
established
pursuant
to
section
112(
d)(
2)
of
the
CAA
must
reflect
MACT,
the
maximum
degree
of
reduction
in
emissions
of
air
pollutants
that
the
Administrator,
taking
into
consideration
the
cost
of
achieving
such
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13,
2003
/
Proposed
Rules
emissions
reductions,
and
any
nonair
quality
health
and
environmental
impacts
and
energy
requirements,
determined
is
achievable
for
each
category.
For
existing
sources,
MACT
cannot
be
less
stringent
than
the
average
emission
limitation
achieved
by
the
best
performing
12
percent
of
existing
sources
for
categories
and
subcategories
with
30
or
more
sources.
This
requirement
constitutes
the
MACT
floor
for
existing
boilers
and
process
heaters.
However,
EPA
may
not
consider
costs
or
other
impacts
in
determining
the
MACT
floor.
The
EPA
must
consider
cost,
nonair
quality
health
and
environmental
impacts,
and
energy
requirements
in
connection
with
any
standards
that
are
more
stringent
than
the
MACT
floor
(
beyond­
the­
floor
controls).

D.
How
Did
EPA
Determine
the
MACT
Floor
for
Existing
Units?
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.
Using
such
an
approach,
EPA
might
calculate
the
MACT
floor
for
a
category
of
sources
by
ranking
the
emission
test
results
from
units
within
the
category
from
lowest
to
highest,
and
then
taking
the
numerical
average
of
the
test
results
from
the
best
performing
(
lowest
emitting)
12
percent
of
sources.
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
cannot
reasonably
be
replicated
by
other
units
in
the
category
or
subcategory.
In
fact,
we
expect
just
this
kind
of
variability
in
emission
rates
given
the
variety
of
fuel
types
included
within
each
subcategory
of
boilers
and
process
heaters.
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.
Some
fuels
even
have
pollutant
concentration
levels
below
the
detection
limit
of
the
applicable
analytical
test
method.
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
be
unachievable
for
many
existing
units,
even
those
that
employ
the
most
effective
available
emission
control
technology.
For
example,
an
uncontrolled
boiler
burning
wood
may
have
lower
emissions
of
mercury
than
a
well
controlled
boiler
burning
coal.
In
fact,
coal
burning
boilers
may
never
be
able
to
achieve
the
mercury
HAP
level
of
the
wood­
fired
unit,
no
matter
what
add­
on
controls
are
used.
In
this
instance,
establishing
a
MACT
standard
based
on
emission
data
alone
would
force
the
coal
units
to
switch
to
different
fuels
to
achieve
the
MACT
limits.
As
discussed
later
in
this
section,
fuel
switching
is
not
an
appropriate
or
available
control
option
for
identifying
the
MACT
floors
for
boilers
and
process
heaters.
Another
problem
with
using
only
emissions
data
is
that
there
is
no
HAP
emissions
information
available
to
the
Agency
for
some
of
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
that
specifically
limit
HAP
emissions
from
these
sources.
Consequently,
we
concluded
that
the
most
appropriate
approach
for
determining
MACT
floors
for
boilers
and
process
heaters
was
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
considered
first
whether
fuel
switching
would
be
an
appropriate
control
option
for
sources
in
each
subcategory.
We
considered
the
feasibility
of
fuel
switching
to
other
fuels
used
in
the
subcategory
and
to
fuels
from
other
subcategories.
This
consideration
included
determining
whether
switching
fuels
would
achieve
lower
HAP
emissions.
A
second
consideration
was
whether
fuel
switching
could
be
technically
achieved
by
boilers
and
process
heaters
in
the
subcategory
considering
the
existing
design
of
boilers
and
process
heaters.
We
also
considered
the
availability
of
various
types
of
fuel.
After
considering
these
factors,
we
determined
that
fuel
switching
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
discussed
previously
in
this
preamble,
and
concerns
about
fuel
availability.
Based
on
the
data
available
in
the
emissions
database,
we
determined
that
while
fuel
switching
from
solid
fuels
to
gaseous
or
liquid
fuels
would
decrease
PM
and
some
metals
emissions,
emissions
of
some
organic
HAP
would
increase,
resulting
in
uncertain
benefits.
This
determination
is
discussed
in
the
memorandum
``
Development
of
Fuel
Switching
Costs
and
Emission
Reductions
for
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
National
Emission
Standards
for
Hazardous
Air
Pollutants''
located
in
the
docket.
We
believe
that
it
is
inappropriate
in
a
MACT
rulemaking
to
consider
as
MACT
a
control
option
that
potentially
will
decrease
emissions
of
one
HAP
while
increasing
emissions
of
another
HAP.
In
order
to
adopt
such
a
strategy,
EPA
would
need
to
assess
the
relative
risk
associated
with
each
HAP
emitted,
and
determine
whether
requiring
the
control
in
question
would
result
in
overall
lower
risk.
Such
an
analysis
is
not
appropriate
at
this
stage
in
the
regulatory
process.
A
similar
determination
was
made
when
considering
fuel
switching
to
cleaner
fuels
within
a
subcategory.
For
example,
the
term
``
clean
coal''
refers
to
coal
that
is
lower
in
sulfur
content
and
not
necessarily
lower
in
HAP
content.
Data
gathered
by
EPA
also
indicates
that
within
specific
coal
types
HAP
content
can
vary
significantly.
Switching
to
a
low
sulfur
coal
may
actually
increase
emissions
of
some
HAP.
Therefore,
it
is
not
appropriate
for
EPA
to
include
fuel
switching
to
a
low
sulfur
coal
as
part
of
the
MACT
standards
for
boilers
and
process
heaters.
Fuel
switching
from
coal
to
biomass
would
result
in
similar
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Proposed
Rules
impacts
on
HAP
emissions.
While
this
would
reduce
metallic
HAP
emissions,
it
would
likely
increase
emissions
of
organics
based
on
information
in
the
emissions
database.
Another
factor
considered
was
the
availability
of
alternative
fuel
types.
Natural
gas
pipelines
are
not
available
in
all
regions
of
the
U.
S.,
and
natural
gas
is
simply
not
available
as
a
fuel
for
many
industrial,
commercial,
and
institutional
boilers
and
process
heaters.
Moreover,
even
where
pipelines
provide
access
to
natural
gas,
supplies
of
natural
gas
may
not
be
adequate.
For
example,
it
is
common
practice
in
cities
during
winter
months
(
or
periods
of
peak
demand)
to
prioritize
natural
gas
usage
for
residential
areas
before
industrial
usage.
Requiring
EPA
regulated
combustion
units
to
switch
to
natural
gas
would
place
an
even
greater
strain
on
natural
gas
resources.
Consequently,
even
where
pipelines
exist,
some
units
would
not
be
able
to
run
at
normal
or
full
capacity
during
these
times
if
shortages
were
to
occur.
Therefore,
under
any
circumstances,
there
would
be
some
units
that
could
not
comply
with
a
requirement
to
switch
to
natural
gas.
Similar
problems
for
fuel
switching
to
biomass
could
arise.
Existing
sources
burning
biomass
generally
are
combusting
a
recovered
material
from
the
manufacturing
or
agriculture
process.
Industrial,
commercial,
and
institutional
facilities
that
are
not
associated
with
the
wood
products
industry
or
agriculture
may
not
have
access
to
a
sufficient
supply
of
biomass
materials
to
replace
their
fossil
fuel.
As
discussed
previously
in
this
preamble,
there
is
a
significant
concern
that
switching
fuels
would
be
infeasible
for
sources
designed
and
operated
to
burn
specific
fuel
types.
Changes
in
the
type
of
fuel
burned
by
a
boiler
or
process
heater
(
solid,
liquid,
or
gas)
may
require
extensive
changes
to
the
fuel
handling
and
feeding
system
(
e.
g.,
a
stoker
using
wood
as
fuel
would
need
to
be
redesigned
to
handle
fuel
oil
or
gaseous
fuel).
Additionally,
burners
and
combustion
chamber
designs
are
generally
not
capable
of
handling
different
fuel
types,
and
generally
cannot
accommodate
increases
or
decreases
in
the
fuel
volume
and
shape.
Design
changes
to
allow
different
fuel
use,
in
some
cases,
may
reduce
the
capacity
and
efficiency
of
the
boiler
or
process
heater.
Reduced
efficiency
may
result
in
less
complete
combustion
and,
thus,
an
increase
in
organic
HAP
emissions.
For
the
reasons
discussed
above,
we
decided
that
fuel
switching
to
cleaner
solid
fuels
or
to
liquid
or
gaseous
fuels
is
not
an
appropriate
criteria
for
identifying
the
MACT
floor
level
of
control
for
units
in
the
boilers
and
process
heaters
category.
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
primarily
dependent
upon
the
composition
of
the
fuel.
Fuel
dependent
HAP
are
metals,
including
mercury,
and
acid
gases.
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
fuel­
related
HAP
emissions.
On
the
other
hand,
organic
HAP
can
be
formed
from
incomplete
combustion
of
the
fuel.
Combustion
is
defined
as
the
rapid
chemical
combination
of
oxygen
with
the
combustible
elements
of
a
fuel.
The
objective
of
good
combustion
is
to
release
all
the
energy
in
the
fuel
while
minimizing
losses
from
combustion
imperfections
and
excess
air.
The
combination
of
the
fuel
with
the
oxygen
requires
temperature
(
high
enough
to
ignite
the
fuel
constituents),
mixing
or
turbulence
(
to
provide
intimate
oxygenfuel
contact),
and
sufficient
time
(
to
complete
the
process),
sometimes
referred
to
the
three
Ts
of
combustion.
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.
The
GCP
control
strategy
could
include
a
number
of
combustion
conditions
and
work
practices
which
are
applied
collectively
to
achieve
this
goal.
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.
Therefore,
we
considered
whether
existing
CO
monitoring
requirements
and
emission
limits
might
be
used
to
establish
good
combustion
practice
standards
for
boilers
and
process
heaters.
(
As
discussed
previously
in
this
preamble,
CO
is
also
a
surrogate
for
organic
HAP
emissions
in
the
proposed
rule.)
The
population
databases
did
not
contain
information
regarding
whether
existing
units
monitored
CO
emissions.
Therefore,
we
reviewed
State
regulations
applicable
to
boilers
and
process
heaters,
and
then
for
each
subcategory
we
matched
the
applicability
of
State
CO
monitoring
requirements
or
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
monitoring
requirements
or
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.
Consequently,
EPA
was
unable
to
identify
any
uniform
requirements
or
set
of
work
practices
that
would
meaningfully
reflect
the
use
of
good
combustion
practices,
or
that
could
be
meaningfully
implemented
across
any
subcategory
of
boilers
and
process
heaters.
Therefore,
EPA
is
not
establishing
combustion
practice
requirements
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
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.
We
request
comment,
and
emissions
information,
regarding
whether
there
are
any
uniform
GCP
practices
that
would
be
appropriate
for
minimizing
organic
HAP
emissions
from
any
subcategory
of
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Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
industrial,
commercial,
and
institutional
boilers
and
process
heaters.
As
a
result
of
the
preceding
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.
In
order
to
determine
the
MACT
floor
based
primarily
on
addon
control
technologies,
we
first
examined
the
population
database
of
existing
sources.
Units
not
meeting
the
definition
of
an
industrial,
commercial,
or
institutional
boiler
or
process
heater,
and
units
located
at
area
sources
were
removed
from
the
database.
The
remaining
units
were
divided
first
into
three
subcategories
based
on
fuel
state:
gaseous
fuel­
fired,
liquid
fuel­
fired,
and
solid
fuel­
fired
units.
Each
of
these
three
subcategories
was
then
further
divided
into
subcategories
based
on
capacity:
(
1)
Large
units
(
watertube
boilers
and
process
heaters
with
heat
inputs
greater
than
10
MMBtu/
hr);
(
2)
small
units
(
firetube
boilers
and
any
boiler
and
process
heater
with
a
maximum
rated
heat
input
capacity
of
10
MMBtu/
hr
or
less);
and
(
3)
limited
use
units
with
capacity
utilization
less
than
10
percent.
We
identified
the
types
of
air
pollution
control
techniques
currently
used
by
existing
boilers
and
process
heaters
in
each
subcategory.
We
ranked
those
controls
according
to
their
effectiveness
in
removing
the
different
categories
of
pollutants;
including
metallic
HAP
and
PM,
inorganic
HAP
such
as
acid
gases,
mercury,
and
organic
HAP.
The
EPA
ranked
these
existing
control
technologies
by
incorporating
recommendations
made
by
the
ICCR,
and
by
reviewing
emissions
test
data,
previous
EPA
studies,
and
other
literature,
as
well
as
by
using
engineering
judgement.
Based
upon
the
emissions
reduction
potential
of
existing
air
pollution
control
techniques,
we
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
these
units.
The
last
part
in
the
process
described
above,
involving
the
calculation
of
numerical
emission
limits,
was
a
twostep
analysis.
The
first
step
involved
calculating
a
numerical
average
of
an
appropriate
subset
of
the
emission
test
data
from
units
using
the
same
technology,
or
technologies,
as
the
units
in
the
top
12
percent.
Based
on
the
initial
ranking,
we
determined
what
proportion
of
the
units
using
a
particular
technology
were
among
the
top
12
percent
of
units
in
the
subcategory.
Then
we
looked
at
a
corresponding
proportion
of
the
emission
test
data
from
units
using
that
type
of
control
technology,
and
produced
an
overall
average
measured
performance
level.
For
example,
in
the
large
solid­
fuel
subcategory,
approximately
14
percent
of
units
used
the
best
performing
control
technology
for
PM/
metallic
HAP
(
baghouses).
In
order
to
rank
the
units
using
the
best
technology
for
which
we
had
emission
test
data,
we
generated
unit
by
unit
measured
performance
levels
by
averaging
the
multiple
tests
from
each
individual
unit
(
if
multiple
tests
were
available).
Then
we
looked
at
the
best
12/
14
of
the
units
for
which
we
generated
such
individual
averages,
and
averaged
the
unit
by
unit
averages
from
all
of
these
units.
This
resulted
in
an
overall
average
measured
emissions
performance
level
for
units
representative
of
the
top
12
percent
of
units
in
the
subcategory.
The
second
step
in
this
part
of
the
process
involved
generating
and
applying
an
appropriate
variability
factor
to
account
for
unavoidable
variations
in
emissions
due
primarily
to
uncontrollable
differences
in
fuel
characteristics
and
ordinary
operational
variability.
First,
we
identified
all
the
units
for
which
we
had
emission
test
data
using
the
same
technology,
or
technologies,
as
units
in
the
top
12
percent.
Then,
for
each
such
unit
with
multiple
emission
tests,
we
calculated
the
variability
in
the
measured
emissions
from
that
unit
by
dividing
the
highest
three­
run
test
result
by
the
lowest
three­
run
test
result.
Finally,
we
calculated
the
overall
variability
in
the
measured
emissions
from
these
units
by
averaging
all
the
individual
unit
variability
factors,
and
we
applied
this
overall
variability
factor
to
the
overall
average
measured
emissions
performance
level
(
as
described
above)
to
derive
a
emission
limit
representative
of
the
average
emission
limitation
achieved
by
the
top
12
percent
of
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,
considering
ordinary
operational
variability.
Both
the
analysis
of
the
measured
emissions
from
units
representative
of
the
top
12
percent,
and
the
variability
analysis,
are
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.
Using
such
an
approach,
including
a
variability
factor,
is
reasonable
because
the
estimated
performance
of
the
best
controlled
units
must
account
for
variability
in
the
performance
of
the
units
over
time
and
under
different
operational
conditions.
Absent
comprehensive
emission
data,
there
is
no
reason
to
believe
that
any
individual
unit
could
consistently
achieve
the
emission
performance
demonstrated
by
a
limited
set
of
emission
tests.
Because,
each
emission
test
is
but
a
snapshot
of
actual
and
ongoing
performance,
taken
at
one
moment
in
time,
evaluating
the
snapshots
collectively
is
the
best
way
to
estimate
the
unavoidable
variation
in
emissions
expected
to
occur
and
recur
over
time
at
similarly
controlled
units
in
the
category
(
or
subcategory).
As
a
result,
the
most
reasonable
methodology
for
determining
the
variability
among
the
best
controlled
units
is
to
evaluate
the
overall
variability
in
the
performance
of
the
particular
control
technology
that
those
units
use,
by
examining
the
variability
among
the
emission
test
results
(
the
performance
snapshots)
for
all
similarly
controlled
units
(
excluding
any
emission
values
from
tests
that
did
not
represent
a
proper
functioning
system).
Accordingly,
we
have
used
the
available
emissions
data
to
reasonably
estimate
the
variability
of
the
top
performing
units
in
each
subcategory.
The
EPA's
review
of
emissions
data
indicates
that
some
boilers
and
process
heaters
within
each
subcategory
may
be
able
to
meet
the
floor
emission
levels
without
using
the
air
pollution
control
technology
that
is
used
by
the
top
12
percent
of
units
in
the
subcategory.
This
is
to
be
expected
given
the
variety
of
fuel
types,
fuel
input
rates,
and
boiler
designs
included
within
each
subcategory
and
the
resulting
variability
in
emission
rates.
Thus,
for
instance,
boilers
or
process
heaters
within
the
large
unit
solid
fuel
subcategory
that
burn
lower
percentages
of
solid
fuels
may
be
able
to
achieve
the
emission
levels
for
the
large
unit
solid
fuel
subcategory
without
the
need
for
additional
control
devices.
Furthermore,
solid
fuels,
especially
coal,
are
very
heterogeneous
and
can
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Proposed
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1
The
speciation
of
mercury
in
the
flue
gas
is
believed
to
affect
the
amount
of
mercury
captured
by
control
devices.
Mercury
can
be
present
in
both
vapor
form
(
as
insoluble
elemental
mercury
and
as
soluble
oxidized
mercury
(
such
as,
mercury
chloride))
and
in
particulate
form.
The
capture
of
elemental
mercury
is
reportedly
more
difficult
than
the
capture
of
oxidized
mercury
or
mercury
in
particulate
form.
vary
in
composition
by
location.
Coal
analysis
data
obtained
from
the
electric
utility
industry
in
another
rulemaking
contained
information
on
the
mercury,
chlorine,
and
ash
content
of
various
coals.
A
preliminary
review
of
this
data
indicate
that
the
composition
can
vary
greatly
from
location
to
location,
and
also
within
a
particular
location.
Based
on
the
range
of
variation
of
mercury,
chlorine,
and
ash
content
in
coal,
it
is
possible
for
a
unit
with
a
lower
performing
control
system
to
have
emission
levels
lower
than
a
unit
considered
to
be
included
in
the
best
performing
12
percent
of
the
units.
This
situation
is
reflected
in
the
emissions
information
used
to
set
the
MACT
floor
emission
limits.
In
some
instances
there
are
boilers
with
ESP
or
other
controls
that
achieve
similar,
or
lower,
outlet
emission
levels
of
nonmercury
metallic
HAP,
PM,
or
mercury
than
fabric
filters.
In
most
cases,
this
is
due
to
concentrations
entering
these
other
control
devices
being
lower,
even
though
the
percent
reduction
achieved
is
lower
than
fabric
filters.
Additionally,
the
design
of
some
control
devices
may
have
a
substantial
effect
on
their
emissions
reductions
capability.
For
example,
fabric
filters
are
largely
insensitive
to
the
physical
characteristics
of
the
inlet
gas
stream.
Thus,
their
design
does
not
vary
widely,
and
emissions
reductions
are
expected
to
be
similar
(
e.
g.
99
percent
reduction
of
PM).
However,
ESP
design
can
vary
significantly.
Some
ESP
are
two
fields,
others
may
have
three
or
four.
The
more
fields
the
larger
the
emissions
reductions
for
PM.
Similarly,
other
devices
can
be
designed
to
achieve
higher
emissions
reductions.
This
level
of
detail
was
not
available
for
the
information
used
to
develop
the
MACT
floor
emission
limits.
Consequently,
since
fuel
substitution
has
been
determined
not
to
be
an
appropriate
MACT
floor
control
technology,
EPA
still
considers
the
fabric
filter
to
be
the
best
performing
control
for
non­
mercury
metallic
HAP,
PM,
and
mercury
and
only
emissions
information
for
fabric
filters
was
used
to
develop
emission
limits.
For
existing
unit
subcategories
where
less
than
12
percent
of
units
in
the
subcategory
use
any
type
of
control
technology,
we
could
not
use
the
same
approach
to
identify
the
average
level
of
control
achieved
by
the
top
12
percent.
Therefore,
we
looked
to
see
if
we
could
estimate
the
central
tendency
of
the
best
controlled
units
by
looking
at
the
median
unit
of
the
top
12
percent
(
the
unit
at
the
94th
percentile).
Under
such
circumstances,
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
where
even
the
median
unit
is
using
no
control
technology,
the
average
control
of
the
top
12
percent
of
units
is
no
emissions
reductions.
A
detailed
discussion
of
the
MACT
floor
methodology
is
presented
in
the
memorandum
``
MACT
Floor
Analysis
for
the
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
National
Emission
Standards
for
Hazardous
Air
Pollutants''
in
the
docket.

1.
Existing
Solid
Fuel
Boilers
and
Process
Heaters
a.
Large
Units
 
Heat
Inputs
Greater
than
10
MMBtu/
hr.
The
most
effective
control
technologies
identified
for
removing
non­
mercury
metallic
HAP
and
PM
are
fabric
filters.
About
14
percent
of
solid
fuel­
fired
boilers
and
process
heaters
use
fabric
filters.
Because
greater
than
12
percent
of
units
in
the
category
use
this
technology,
and
because
there
are
no
options
reasonably
available
for
reducing
HAP
emissions
other
than
add­
on
control,
we
consider
sources
with
fabric
filters
to
be
the
best
controlled
sources
in
this
subcategory
for
purposes
of
metallic
HAP
and
PM
emissions.
Thus,
it
is
appropriate
to
use
the
measured
performance
of
sources
with
fabric
filters
as
the
basis
for
establishing
the
MACT
floor
for
nonmercury
metallic
HAP
and
PM
for
existing
boilers
and
process
heaters
in
this
subcategory.
As
described
earlier,
a
PM
level
is
set
as
a
surrogate
for
non­
mercury
metallic
HAP.
The
MACT
floor
emission
level
based
on
PM
test
data
from
the
solid
fuel
units
with
fabric
filters
representing
the
top
12
percent,
and
incorporating
operational
variability
(
using
results
from
multiple
tests
on
best
performing
units),
is
0.07
lb
PM/
MMBtu.
We
are
also
providing
an
alternative
metals
limit
of
0.001
lb
metals/
MMBtu
which
can
be
used
to
show
compliance
in
cases
where
metal
HAP
emissions
are
low
in
proportion
to
PM
emissions.
This
is
because,
according
to
the
emissions
database,
some
biomass
units
have
low
metals
content
but
high
PM
emissions.
The
emission
level
for
metals
was
selected
from
metals
test
data
associated
with
PM
emission
tests
from
fabric
filters
that
met
the
MACT
floor
PM
emission
level.
The
most
effective
control
technologies
identified
for
removing
inorganic
HAP
that
are
acid
gases,
such
as
HCl,
are
wet
scrubbers
and
packed
bed
scrubbers.
These
technologies
are
used
by
about
13
percent
of
the
boilers
and
process
heaters
in
the
large
solid
fuel
subcategory.
About
12
percent
of
solid
fuel­
fired
boilers
and
process
heaters
use
wet
or
dry
scrubbers,
and
approximately
1
percent
use
packed
bed
scrubbers.
Because
greater
than
12
percent
of
units
in
the
category
use
this
technology,
and
because
there
are
no
options
reasonably
available
for
reducing
HAP
emission
other
than
addon
control,
we
consider
sources
with
wet
or
dry
scrubbers
and
packed
bed
scrubbers
to
be
the
best
controlled
sources
in
this
subcategory
for
purposes
of
inorganic
HAP
emissions.
Thus,
it
is
appropriate
to
use
the
measured
performance
of
sources
with
wet
or
dry
scrubbers
and
packed
bed
scrubbers
as
the
basis
for
establishing
the
MACT
floor
for
inorganic
HAP
for
existing
boilers
and
process
heaters
in
this
subcategory.
The
MACT
floor
emission
level
based
on
HCl
emissions
test
data
from
units
using
wet
or
dry
scrubbers
and
packed
bed
scrubbers
representing
the
top
12
percent,
and
incorporating
operational
variability,
is
0.09
lb
HCl/
MMBtu.
Based
on
test
information
on
utility
boilers,
we
have
concluded
that
fabric
filters
are
the
most
effective
technology
for
controlling
mercury
emissions.
As
discussed
previously,
approximately
14
percent
of
sources
in
the
subcategory
use
fabric
filters.
The
MACT
floor
emission
level
for
mercury,
based
on
the
measured
performance
of
units
with
fabric
filters
representing
the
top
12
percent,
and
incorporating
operational
variability,
is
0.000007
lb
mercury/
MMBtu.
Although
EPA
used
information
from
utility
boilers
to
conclude
that
fabric
filters
are
the
most
effective
control
technology
for
controlling
mercury
emissions,
this
same
information
suggests
that
different
fuel
characteristics
(
e.
g.
mercury
and
chlorine
content
of
the
fuel
burned)
can
lead
to
both
different
outlet
mercury
(
Hg)
concentrations
and
different
control
efficiencies
for
equivalent
control
devices.
1
We
have
emissions
test
results
for
mercury
emissions
from
seven
industrial
boilers
and
process
heaters
equipped
with
fabric
filters.
The
Agency
has
information
about
the
general
type
of
fuel
being
burned
during
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13,
2003
/
Proposed
Rules
the
emission
tests,
such
as
coal,
wood,
or
some
mixture
of
fuel
types.
However,
we
have
no
detailed
information
about
the
specific
characteristics
(
such
as
mercury
or
chlorine
content)
of
the
fuel
being
burned
during
those
emissions
tests.
Nonetheless,
we
believe
that
the
use
of
variability
factors
adequately
accounts
for
potential
variations
in
fuel
mercury
and
chloride
content.
However,
because
we
have
very
limited
data
on
actual
emissions
from
industrial
boilers
and
process
heaters,
the
Agency
is
soliciting
comment
on
whether
the
variability
analysis
in
the
current
proposal
adequately
addresses
the
impact
that
fuel
characteristics
(
such
as
mercury
and
chlorine
content)
can
have
on
mercury
emissions
from
a
source
equipped
with
fabric
filters.
As
discussed
earlier,
the
Agency
is
not
currently
considering
fuel
switching
as
a
control
option
in
setting
the
MACT
floor.
Therefore,
the
Agency
requests
specific
information
regarding
both
the
mercury
and
chlorine
content
characteristics
of
the
fuel
used
in,
and
the
mercury
emissions
from,
industrial
boilers
and
process
heaters
equipped
with
well
designed
and
operated
fabric
filters.
Comments
on
this
issue
should
include
specific
data
regarding
both
the
characteristics
of
the
fuel
burned
(
including
mercury
and
chlorine
content
along
with
any
other
pertinent
characteristics)
and
current
mercury
emissions
of
these
industrial
boilers
and
process
heaters.
For
organic
HAP,
we
attempted
to
determine
the
level
of
control
being
achieved
by
the
top
12
percent
of
units
within
the
subcategory,
however,
less
than
6
percent
of
the
units
in
this
subcategory
use
any
type
of
organic
HAP
control
(
by
limiting
CO
emissions).
Thus,
while
a
small
proportion
of
units
in
the
subcategory
monitor
and
control
their
CO
emissions
(
and,
therefore,
limit
emissions
of
organic
HAP),
the
majority
of
units
in
the
subcategory
(
and
in
the
top
12
percent)
do
not
control
these
emissions.
Because
so
few
units
control
emissions
of
organic
HAP,
we
could
not
calculate
an
average
limitation
achieved
by
the
top
12
percent
as
we
did
for
metallic
HAP/
PM,
inorganic
HAP/
HCl,
and
mercury.
We
looked
then
at
whether
the
median
unit
of
the
top
12
percent
might
provide
some
indication
of
the
central
tendency
of
the
top
12
percent.
However,
because
fewer
than
6
percent
of
units
are
controlled,
the
median
unit
reflects
no
emissions
reductions
for
organic
HAP.
Therefore,
we
concluded
that
the
MACT
floor
for
existing
sources
in
this
subcategory
is
no
emissions
reductions
for
organic
HAP.
Consequently,
EPA
determined
that,
in
general,
the
combination
of
fabric
filter
and
wet
scrubber
control
technologies
forms
the
basis
for
the
MACT
floor
level
of
control
for
existing
large
solid
fuel
boilers
or
process
heaters.
We
recognize
that
some
boilers
and
process
heaters
that
use
technologies
other
than
those
used
as
the
basis
of
the
MACT
floor
can
achieve
the
MACT
floor
emission
levels.
For
example,
emission
test
data
show
that
many
boilers
with
well
designed
and
operated
ESP
can
meet
the
MACT
floor
emission
levels
for
non­
mercury
metallic
HAP
and
PM,
even
though
the
floor
emission
level
for
these
pollutants
is
based
on
units
using
a
fabric
filters
(
however,
we
would
not
expect
that
all
units
using
ESP
would
be
able
to
meet
the
emission
limits
in
the
proposed
rule).
b.
Small
Units
 
Heat
Inputs
Less
than
or
Equal
to
10
MMBtu/
hr.
For
each
pollutant
group
(
non­
mercury
metallic
HAP
and
PM,
mercury,
inorganic
HAP/
HCl,
and
organic
HAP),
less
than
6
percent
of
the
units
in
this
subcategory
used
control
techniques
that
limit
emissions.
Because
so
few
units
in
the
subcategory
control
emissions
of
HAP,
we
could
not
calculate
an
average
limitation
achieved
by
the
top
12
percent
for
any
HAP
grouping.
We
looked
then
at
whether
the
median
unit
of
the
top
12
percent
might
provide
some
indication
of
the
central
tendency
of
the
top
12
percent
for
any
HAP
grouping.
However,
because
fewer
than
6
percent
of
units
in
each
HAP
grouping
used
controls
or
limited
emissions,
the
median
unit
for
each
HAP
grouping
reflects
no
emissions
reduction.
Therefore,
we
determined
that
the
MACT
floor
emission
level
for
existing
units
for
each
of
the
pollutant
categories
in
this
subcategory
is
no
emissions
reductions.
c.
Limited
Use
Units
 
Capacity
Utilizations
Less
than
or
Equal
to
10
Percent.
The
most
effective
control
technologies
identified
for
removing
non­
mercury
metallic
HAP
and
PM
are
ESP
and
fabric
filters.
Less
than
2
percent
of
limited
use
solid
fuel­
fired
boilers
and
process
heaters
use
fabric
filters,
and
14
percent
use
ESP.
Therefore,
we
used
the
measured
performance
of
units
using
ESP
and
fabric
filters
as
the
basis
for
the
MACT
floor
for
non­
mercury
metallic
HAP
and
PM.
We
established
a
PM
level
as
a
surrogate
for
non­
mercury
metallic
HAP
control,
reflecting
the
emission
test
data
from
units
using
ESP
and
fabric
filters
that
were
representative
of
the
top
12
percent
of
units
in
the
subcategory.
The
emissions
test
database
did
not
contain
test
data
for
limited
use
boilers
and
process
heaters.
In
order
to
develop
emission
levels
for
this
subcategory,
we
decided
to
use
information
from
units
in
the
large
solid
fuel
subcategory.
We
considered
this
to
be
an
appropriate
methodology
because
although
the
units
in
this
subcategory
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
(
HCl
and
non­
mercury
metals)
are
expected
to
be
related
more
to
the
type
of
fuel
burned
and
the
type
of
control
used,
than
to
unit
operation.
Consequently,
we
determined
that
emissions
information
from
the
large
solid
fuel
subcategory
could
be
used
to
establish
MACT
floor
levels
for
this
subcategory
because
the
fuels
and
controls
are
similar.
The
MACT
floor
emission
level
based
on
this
test
data,
considering
operational
variability,
is
0.02
lb
PM/
MMBtu.
We
are
also
providing
an
alternative
metals
limit
of
0.001
lb
metals/
MMBtu
which
can
be
used
to
show
compliance
in
cases
where
metal
HAP
emissions
are
low
in
proportion
to
PM
emissions.
The
emissions
database
indicates
that
some
biomass
units
have
low
metals
content
but
high
PM
emissions.
The
emission
level
for
metals
was
selected
from
metals
test
data
associated
with
PM
emission
tests
from
fabric
filters
that
met
the
MACT
floor
PM
emission
level.
Similar
control
technology
analyses
were
done
for
the
boilers
and
process
heaters
in
this
subcategory
for
the
other
pollutant
groups
of
interest,
including
inorganic
HAP,
organic
HAP
and
mercury.
For
each
of
these
pollutant
groups,
less
than
6
percent
of
the
units
in
this
subcategory
used
control
techniques
that
limit
emissions.
Because
so
few
units
in
the
subcategory
control
emissions
of
these
HAP,
we
could
not
calculate
an
average
limitation
achieved
by
the
top
12
percent
for
inorganic
HAP,
organic
HAP
and
mercury.
We
looked
then
at
whether
the
median
unit
of
the
top
12
percent
might
provide
some
indication
of
the
central
tendency
of
the
top
12
percent
for
any
of
these
HAP
groupings.
However,
because
fewer
than
6
percent
of
units
in
each
HAP
grouping
used
controls
or
limited
emissions,
the
median
unit
for
each
HAP
grouping
reflects
no
emission
reductions.
Therefore,
we
concluded
that
the
MACT
floor
for
inorganic
HAP,
organic
HAP
and
mercury
in
this
subcategory
is
no
emissions
reductions.
Consequently,
we
determined
that
ESP
and
fabric
filters,
which
achieve
non­
mercury
metallic
HAP
and
PM
control,
form
the
basis
for
the
MACT
floor
level
of
control
for
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/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
existing
solid
fuel
boilers
and
process
heaters
in
this
subcategory.

2.
Existing
Liquid
Fuel
Boilers
and
Process
Heaters
Emission
data
for
liquid
subcategories
were
inadequate
to
identify
the
best
performing
sources
for
reasons
described
previously
in
this
preamble.
We
also
found
no
State
regulations
or
permits
which
specifically
limit
HAP
emissions
from
these
sources.
Therefore,
we
examined
control
technology
information
to
identify
a
MACT
floor.
We
found
that
less
than
6
percent
of
the
units
in
each
of
the
liquid
subcategories
used
control
techniques
that
would
reduce
non­
mercury
metallic
HAP
and
PM,
mercury,
organic
HAP,
or
acid
gases,
(
such
as
HCl).
Therefore,
we
concluded,
for
each
subcategory
of
liquid
fueled
boilers
and
process
heaters,
that
the
MACT
floor
is
no
emission
reductions
for
non­
mercury
metallic
HAP,
mercury,
inorganic
HAP,
and
organic
HAP.

3.
Existing
Gaseous
Fuel
Boilers
and
Process
Heaters
Emission
data
for
gas
subcategories
were
inadequate
to
identify
the
best
performing
sources
for
reasons
described
in
section
III.
D
of
this
preamble.
We
also
found
no
State
regulations
or
permits
that
specifically
limit
HAP
emissions
from
these
sources.
Therefore,
we
examined
control
technology
information
to
identify
a
MACT
floor.
We
found
that
no
existing
units
in
the
gaseous
fuel­
fired
subcategories
were
using
control
technologies
that
achieve
consistently
lower
emission
rates
than
uncontrolled
sources
for
any
of
the
pollutant
groups
of
interest.
Therefore,
we
are
unable
to
identify
the
best
performing
12
percent
of
units
in
the
subcategories.
Consequently,
EPA
determined
that
no
existing
source
MACT
floor
based
on
control
technologies
could
be
identified
for
gaseous
fuel­
fired
units.
Therefore,
we
concluded
the
MACT
floor
for
existing
sources
in
this
subcategory
is
no
emissions
reductions
for
nonmercury
metallic
HAP,
mercury,
inorganic
HAP,
and
organic
HAP.

E.
How
Did
EPA
Consider
Beyond­
the­
Floor
Options
for
Existing
Units?
Once
the
MACT
floor
determinations
were
done
for
each
subcategory,
EPA
considered
various
regulatory
options
more
stringent
than
the
MACT
floor
level
of
control
(
i.
e.,
technologies
or
other
work
practices
that
could
result
in
lower
emissions)
for
the
different
subcategories.
Maintaining
and
monitoring
CO
levels
was
identified
as
a
possible
control
for
organic
HAP.
In
addition
to
looking
at
whether
CO
limits
should
be
a
part
of
the
MACT
floor,
we
looked
at
this
option
as
a
beyond­
the­
floor
option.
However,
information
was
not
available
to
estimate
the
HAP
emissions
reductions
that
would
be
associated
with
CO
monitoring
and
emission
limits.
This
option
would
also
require
a
high
cost
to
install
and
operate
CO
monitors.
Given
the
cost
and
the
uncertain
emissions
reductions
that
might
be
achieved,
we
chose
to
not
require
CO
monitoring
and
emission
limits
as
MACT.
The
following
sections
discuss
the
beyond­
the­
floor
options
analyzed
to
control
emissions
of
metallic
HAP,
mercury,
and
inorganic
HAP.
Based
on
the
analysis
in
these
sections,
EPA
decided
to
not
go
beyond
the
MACT
floor
level
of
control
for
the
proposed
rule
for
any
of
the
subcategories
of
existing
sources.
A
detailed
description
of
the
beyond­
the­
floor
consideration
is
in
the
memorandum
``
Methodology
for
Estimating
Cost
and
Emissions
Impacts
for
Industrial,
Commercial,
Institutional
Boilers
and
Process
Heaters
National
Emission
Standards
for
Hazardous
Air
Pollutants''
in
the
docket.

1.
Existing
Solid
Fuel
Units
a.
Large
Units
 
Heat
Inputs
Greater
than
10
MMBtu/
hr.
Besides
fuel
switching,
we
identified
a
better
designed
and
operated
fabric
filter
(
the
MACT
floor
for
new
units)
as
a
control
technology
that
could
achieve
greater
emissions
reductions
of
metallic
HAP
and
PM
emissions
than
the
MACT
floor
level
of
control.
Consequently,
EPA
analyzed
the
emissions
reductions
and
additional
cost
of
adopting
an
emission
limit
representative
of
the
performance
of
a
unit
with
a
better
designed
and
operated
fabric
filter.
The
additional
annualized
cost
to
comply
with
this
emission
limit
was
estimated
to
be
approximately
500
million
dollars
with
an
additional
emission
reduction
of
approximately
100
tons
of
metallic
HAP.
The
results
indicated
that
while
additional
emissions
reductions
would
be
realized,
the
costs
would
be
too
high
to
consider
it
a
feasible
beyond­
the­
floor
option.
Nonair
quality
health,
environmental
impacts,
and
energy
effects
were
not
significant
factors,
because
there
would
be
little
difference
in
the
nonair
quality
health
and
environmental
impacts
of
replacing
existing
fabric
filters
with
improved
performance
fabric
filters.
Therefore,
we
did
not
select
these
controls
as
MACT.
Fuel
switching
was
not
considered
a
feasible
beyond­
the­
floor
option
for
the
same
reasons
described
previously
in
this
preamble.
We
identified
packed
bed
scrubbers
as
a
control
technology
that
could
achieve
greater
emissions
reductions
of
inorganic
HAP,
like
HCl,
than
the
MACT
floor
level
of
control.
Consequently,
EPA
analyzed
the
emissions
reductions
and
additional
cost
of
adopting
an
emission
limit
representative
of
the
performance
of
a
unit
with
a
packed
bed
scrubber.
The
additional
annualized
cost
to
comply
with
this
emission
limit
(
using
a
packed
bed
scrubber)
was
estimated
to
be
approximately
900
million
dollars
with
an
additional
emission
reduction
of
approximately
20,000
tons
of
HCl.
The
results
indicated
that
while
additional
emissions
reductions
would
be
realized,
the
costs
would
be
too
high
to
consider
it
a
feasible
beyond­
the­
floor
option.
Nonair
quality
health,
environmental
impacts,
and
energy
effects
were
not
significant
factors,
because
there
would
be
little
difference
in
the
nonair
quality
health
and
environmental
impacts
between
packed
bed
scrubbers
and
the
technology
that
is
likely
to
be
used
to
meet
the
MACT
floor
level
of
control.
Therefore,
we
did
not
select
these
controls
as
MACT.
In
reviewing
potential
regulatory
options
for
existing
sources,
EPA
identified
one
existing
industrial
boiler
that
was
using
a
technology,
carbon
injection,
used
in
other
industries
to
achieve
greater
control
of
mercury
emissions
than
the
MACT
floor
level
of
control.
However,
emission
data
indicated
that
this
unit
was
not
achieving
mercury
emission
reduction.
The
EPA
does
not
have
information
that
would
show
carbon
injection
is
effective
for
reducing
mercury
emissions
from
industrial,
commercial,
and
institutional
boilers
and
process
heaters.
Therefore,
carbon
injection
was
not
evaluated
as
a
regulatory
options.
However,
EPA
requests
comments
on
whether
carbon
injection
should
be
considered
as
a
beyond­
the­
floor
option
and
whether
existing
industrial,
commercial,
or
institutional
boilers
and
process
heaters
could
use
carbon
injection
technology,
or
other
control
techniques
to
consistently
achieve
mercury
emission
levels
that
are
lower
than
levels
from
similar
sources
with
the
MACT
floor
level
of
control.
Comments
should
include
information
on
emissions,
current
demonstrated
applications,
and
costs,
including
retrofit
costs.
The
EPA
is
aware
that
research
continues
on
ways
to
improve
mercury
capture
by
PM
controls,
sorbent
injection,
and
the
development
of
novel
techniques.
The
EPA
requests
comment
and
information
on
the
effectiveness
of
such
control
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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
technologies
in
reducing
mercury
emissions.
b.
Small
Units
 
Heat
Inputs
Less
than
or
Equal
to
10
MMBtu/
hr.
The
MACT
floor
for
this
subcategory
is
no
emission
reductions.
To
control
non­
mercury
metallic
HAP
and
mercury,
we
analyzed
the
beyond­
the­
floor
option
of
a
fabric
filter
which
was
identified,
generally,
as
the
most
effective
control
device
for
non­
mercury
metallic
HAP
and
mercury.
To
control
inorganic
HAP
such
as
HCl,
we
analyzed
the
beyond­
thefloor
option
of
a
wet
scrubber
since
it
was
identified
as
the
least
cost
option.
The
total
annualized
cost
of
complying
with
the
fabric
filter
option
was
estimated
to
be
10
million
dollars,
with
an
estimated
emission
reduction
of
1.9
tons
per
year
of
non­
mercury
metallic
HAP
and
0.003
tons
of
mercury.
The
annualized
cost
of
complying
with
the
wet
scrubber
option
was
estimated
to
be
11
million
dollars,
with
an
emission
reduction
of
48
tons
per
year
of
HCl.
The
results
of
this
analysis
indicated
that
while
additional
emissions
reductions
could
be
realized,
the
costs
would
be
too
high
to
consider
them
feasible
options.
Therefore,
we
did
not
select
these
controls
as
MACT.
Nonair
quality
health,
environmental
impacts,
and
energy
effects
were
not
significant
factors.
c.
Limited
Use
Units
 
Capacity
Utilizations
Less
than
or
Equal
to
10
Percent.
The
MACT
floor
level
for
this
subcategory
for
non­
mercury
metallic
HAP
control
is
0.2
lb
PM/
MMBtu
(
this
level
of
control
can
generally
be
achieved
by
using
an
ESP
or
fabric
filter).
Although
fabric
filters
were
identified
as
being
more
effective,
many
ESP
can
achieve
similar
levels.
Any
additional
emission
reduction
from
using
a
fabric
filter
would
be
minimal
and
costly
considering
retrofit
costs
for
existing
units
that
already
have
ESP.
Therefore,
a
beyond­
the­
floor
option
for
metallic
HAP
was
not
analyzed
in
detail.
However,
a
beyond­
the­
floor
option
based
on
the
level
of
performance
of
a
fabric
filter
was
analyzed
for
mercury
control.
The
total
annualized
costs
of
the
fabric
filter
option
was
estimated
to
be
an
additional
21
million
dollars,
with
an
estimated
emission
reduction
of
0.04
tons
of
mercury.
The
MACT
floor
for
inorganic
HAP
in
this
subcategory
was
no
emission
reductions.
For
beyond­
the­
floor
control
of
inorganic
HAP,
we
analyzed
the
level
of
performance
generally
achievable
by
a
wet
scrubber
since
it
was
identified
as
the
least
cost
option.
The
total
annualized
costs
of
the
wet
scrubber
option
was
estimated
to
be
49
million
dollars,
with
an
estimated
emission
reduction
of
463
tons
per
year
of
HCl.
The
results
of
the
beyond­
the­
floor
analyses
indicated
that
while
additional
emissions
reductions
could
be
realized,
the
costs
would
be
too
high
to
consider
them
feasible
options.
Therefore,
we
did
not
select
these
controls
as
MACT.
Nonair
quality
health,
environmental
impacts,
and
energy
effects
were
not
significant
factors.

2.
Existing
Liquid
Fuel
Units
The
MACT
floor
for
each
liquid
fuel
subcategory
is
no
emission
reductions.
For
beyond­
the­
floor
options
for
the
liquid
subcategory,
EPA
identified
several
PM
controls
(
e.
g.,
fabric
filters,
ESP,
and
venturi
scrubbers)
that
would
reduce
non­
mercury
metallic
HAP
emissions.
For
the
beyond­
the­
floor
analysis,
we
analyzed
the
cost
and
emission
reduction
of
applying
a
high
efficiency
PM
control
device,
such
as
a
fabric
filter,
since
these
would
be
more
likely
to
be
installed
for
units
firing
liquid
fuel.
We
identified
wet
scrubbers
as
a
technology
beyond­
the­
floor
option
for
reduction
of
inorganic
HAP,
such
as
HCl.
We
identified
fabric
filters
as
a
beyond­
the­
floor
technology
option
for
reduction
of
mercury.
Consequently,
EPA
analyzed
the
emissions
reductions
and
additional
cost
of
applying
high
efficiency
PM
controls
and
wet
scrubbers
on
liquid
fuel­
fired
units.
The
additional
total
annualized
cost
of
a
high
efficiency
PM
control
device
(
such
as
a
fabric
filter)
was
estimated
to
be
460
million
dollars,
with
an
additional
estimated
emission
reduction
of
1,500
tons
per
year
for
non­
mercury
metallic
HAP
and
3
tons
per
year
for
mercury.
The
annualized
cost
of
a
wet
scrubbers
was
estimated
to
be
an
additional
480
million
dollars,
with
an
additional
HCl
reduction
of
30
tons
per
year.
The
results
indicated
that
while
additional
emissions
reductions
would
be
realized,
the
costs
would
be
too
high
to
consider
them
feasible
options.
Nonair
quality
health,
environmental
impacts,
and
energy
effects
were
not
significant
factors.
Therefore,
EPA
chose
to
not
select
these
controls
as
MACT
for
existing
liquid
units.

3.
Existing
Gas­
Fired
Units
The
MACT
floor
for
each
gaseous
fuel
subcategory
is
no
emission
reductions.
The
great
majority,
if
not
all,
of
the
emissions
from
gas­
fired
units
are
organic
HAP.
As
discussed
previously
in
this
preamble,
CO
monitoring
and
emission
limits
were
considered
as
a
beyond­
the­
floor
option,
but
were
not
selected
as
MACT
given
the
costs
and
uncertain
HAP
reductions
achieved.
Therefore,
no
beyond­
the­
floor
control
technique
was
analyzed
for
organic
HAP,
and
MACT
is
no
emission
reduction
of
non­
mercury
metallic
HAP,
mercury,
inorganic
HAP,
and
organic
HAP.

4.
Fuel
Switching
as
a
Beyond­
the­
Floor
Option
For
the
solid
fuel
and
liquid
fuel
subcategories,
fuel
switching
to
natural
gas
is
a
regulatory
option
more
stringent
than
the
MACT
floor
level
of
control
that
would
reduce
mercury,
metallic
HAP,
and
inorganic
HAP
emissions.
We
determined
that
fuel
switching
was
not
an
appropriate
beyond­
the­
floor
option
for
the
reasons
discussed
previously
in
this
preamble.
For
example,
natural
gas
supplies
are
not
available
in
some
areas,
and
supplies
to
industrial
customers
can
be
limited
during
periods
when
natural
gas
demand
exceeds
supply.
Furthermore,
in
some
cases,
organic
HAP
would
be
increased
by
fuel
switching.
Additionally,
the
estimated
emissions
reductions
that
would
be
achieved
if
solid
and
liquid
fuel
units
switched
to
natural
gas
were
compared
with
the
estimated
cost
of
converting
existing
solid
fuel
and
liquid
fuel
units
to
fire
natural
gas.
The
annualized
cost
of
fuel
switching
was
estimated
to
be
$
12
billion.
The
additional
emission
reduction
associated
with
fuel
switching
was
estimated
to
be
1,500
tons
per
year
for
metallic
HAP,
11
tons
per
year
for
mercury,
and
13,000
tons
per
year
for
inorganic
HAP.
Additional
detail
on
the
calculation
procedures
is
provided
in
the
memorandum
``
Development
of
Fuel
Switching
Costs
and
Emissions
Reductions
for
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
National
Emission
Standards
for
Hazardous
Air
Pollutants''
in
the
docket.

F.
Should
EPA
Consider
Different
Subcategories
for
Solid
Fuel
Boilers
and
Process
Heaters?
The
boilers
and
process
heaters
source
category
is
tremendously
heterogeneous.
The
EPA
has
attempted
to
identify
subcategories
that
provide
the
most
reasonable
basis
for
grouping
and
estimating
the
performance
of
generally
similar
units
using
the
available
data.
We
believe
that
the
subcategories
we
selected
are
appropriate,
given
the
variety
and
combination
of
fuels
that
sources
in
the
category
burn
and
the
fact
that
any
individual
unit
may
use
a
different
combination
of
fuels
over
time.
However,
among
the
solid
fuel
units,
the
available
emission
test
data
could
suggest
that
units
burning
only
wood
might
perform
sufficiently
similar
to
each
other,
and
sufficiently
differently
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2003
/
Proposed
Rules
from
other
(
fossil
fuel
burning)
solid
fuel
units,
to
warrant
additional
subcategorization.
Nonetheless,
we
believe,
for
purposes
of
today's
proposal,
that
it
is
appropriate
to
treat
wood
burning
and
non­
wood
burning
solid
fuel
units
as
a
single
category.
We
believe,
given
the
available
data,
that
this
approach
most
reasonably
accounts
for
variations
in
emissions
that
can
occur
as
a
result
of
different
fuels
and/
or
fuel
combinations,
and
changes
in
fuel
use
over
time,
and
that
it
provides
a
reasonable
basis
for
establishing
an
appropriate
standard.
However,
if
we
were
to
create
a
separate
subcategory
for
wood
burning
units,
we
would
establish
MACT
in
a
manner
consistent
with
the
approach
taken
for
other
solid
fuel
units.
We
would
identify
the
types
of
emission
control
used
by
the
best
controlled
source
(
and
the
top
12
percent
of
units
in
the
subcategory),
and
we
would
estimate
the
performance
of
the
best
controlled
units
by
looking
at
representative
emission
test
data
and
applying
an
appropriate
variability
factor.
A
preliminary
review
of
the
wood
burning
units
in
the
database
suggests
that
the
MACT
floors
for
such
units
would
probably
be
related
to
the
performance
of
ESP
and/
or
scrubbers.
The
EPA
requests
comments
on
whether
additional
or
different
subcategories
should
be
considered.
Comments
should
include
detailed
information
regarding
why
a
new
or
different
subcategory
is
appropriate
(
based
on
the
available
data
or
adequate
data
submitted
with
the
comment),
how
EPA
should
define
any
additional/
different
subcategories,
how
EPA
should
account
for
varied
or
changing
fuel
mixtures,
and
how
EPA
should
use
the
available
data
to
determine
the
MACT
floor
for
any
new
or
different
categories.

G.
How
Did
EPA
Determine
the
Proposed
Emission
Limitations
for
New
Units?
All
standards
established
pursuant
to
section
112
of
the
CAA
must
reflect
MACT,
the
maximum
degree
of
reduction
in
emissions
of
air
pollutants
that
the
Administrator,
taking
into
consideration
the
cost
of
achieving
such
emissions
reductions,
and
any
nonair
quality
health
and
environmental
impacts
and
energy
requirements,
determines
is
achievable
for
each
category.
The
CAA
specifies
that
MACT
for
new
boilers
and
process
heaters
shall
not
be
less
stringent
than
the
emission
control
that
is
achieved
in
practice
by
the
best­
controlled
similar
source
 
this
minimum
level
of
stringency
is
the
MACT
floor
for
new
units.
However,
EPA
may
not
consider
costs
or
other
impacts
in
determining
the
MACT
floor.
The
EPA
must
consider
cost,
nonair
quality
health
and
environmental
impacts,
and
energy
requirements
in
connection
with
any
standards
that
are
more
stringent
than
the
MACT
floor
(
beyond­
the­
floor
controls).

H.
How
Did
EPA
Determine
the
MACT
Floor
for
New
Units?
Similar
to
the
MACT
floor
process
used
for
existing
units,
we
considered
several
approaches
to
identifying
MACT
floors
for
new
industrial,
commercial,
and
institutional
boilers
and
process
heaters.
First,
we
considered
using
only
the
emission
test
data
from
boilers
and
process
heaters
to
set
the
MACT
floor.
However,
as
discussed
previously
in
this
preamble,
we
determined
that
it
was
inappropriate
in
the
proposed
rulemaking
to
develop
MACT
floor
emission
limits
based
on
HAP
emissions
test
information
alone.
We
then
considered
using
HAP
emission
limits
contained
in
State
regulations
and
permits
as
a
surrogate
to
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
identifying
the
top
performing
units
in
each
subcategory
of
boilers
and
process
heaters
is
to
look
at
the
control
technologies
used
by
the
units
within
each
subcategory.
Information
was
available
on
the
add­
on
control
technologies
employed
by
the
population
of
boilers
identified
by
the
EPA.
We
considered
several
possible
control
options
(
i.
e.,
factors
that
influence
emissions),
including
fuel
substitution,
process
changes
and
work
practices,
and
add­
on
control
technologies.
We
considered
first
whether
fuel
switching
would
be
an
appropriate
control
option
for
sources
in
each
subcategory.
We
considered
the
feasibility
of
both
fuel
switching
to
other
fuels
used
in
the
subcategory
and
to
fuels
from
other
subcategories.
This
consideration
included
determining
whether
switching
fuels
would
achieve
lower
HAP
emissions.
A
second
consideration
was
whether
fuel
switching
could
be
technically
achieved
by
boilers
and
process
heaters
in
the
subcategory
based
on
design
considerations.
We
also
considered
the
availability
of
various
types
of
fuel.
As
discussed
previously
in
this
preamble,
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
discussed
previously
in
this
preamble,
and
concerns
about
fuel
availability.
Additional
discussion
of
fuel
switching
is
presented
previously
in
this
preamble
and
in
the
memorandum
``
Development
of
Fuel
Switching
Costs
and
Emission
Reductions
for
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
National
Emission
Standards
for
Hazardous
Air
Pollutants''
located
in
the
docket.
Based
on
the
data
available
in
the
emissions
database,
we
determined
that
while
fuel
switching
would
decrease
some
HAP,
emissions
of
some
organic
HAP
would
increase,
resulting
in
uncertain
benefits.
We
believe
that
it
is
inappropriate
in
a
MACT
rulemaking
to
consider
as
MACT
a
control
option
that
potentially
will
decrease
emissions
of
one
HAP
while
increasing
emissions
of
another
HAP.
A
detailed
discussion
of
the
consideration
of
fuel
switching
is
discussed
previously
in
this
preamble.
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
primarily
dependent
upon
the
composition
of
the
fuel.
Fuel
dependent
HAP
are
metals,
including
mercury,
and
acid
gases.
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
fuel­
related
emissions.
On
the
other
hand,
organic
HAP
can
be
formed
from
incomplete
combustion
of
the
fuel.
Combustion
is
defined
as
the
rapid
chemical
combination
of
oxygen
with
the
combustible
elements
of
a
fuel.
The
objective
of
good
combustion
is
to
release
all
the
energy
in
the
fuel
while
minimizing
losses
from
combustion
imperfections
and
excess
air.
The
combination
of
the
fuel
with
the
oxygen
requires
temperature
(
high
enough
to
ignite
the
fuel
constituents),
mixing
or
turbulence
(
to
provide
intimate
oxygenfuel
contact),
and
sufficient
time
(
to
complete
the
process),
sometimes
referred
to
the
three
Ts
of
combustion.
Good
combustion
practice,
in
terms
of
boilers
and
process
heaters,
could
be
defined
as
the
system
design
and
work
practices
expected
to
minimize
organic
HAP
emissions.
The
GCP
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/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
strategy
could
include
a
number
of
combustion
conditions
and
work
practices
which
are
applied
collectively
to
achieve
this
goal.
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.
Consequently,
EPA
was
unable
to
identify
any
uniform
requirements
or
set
of
work
practices
that
would
meaningfully
reflect
the
use
of
good
combustion
practices,
or
that
could
be
meaningfully
implemented
across
any
subcategory
of
boilers
and
process
heaters.
Therefore,
EPA
is
not
establishing
combustion
practice
requirements
as
a
part
of
the
MACT
floor
for
new
units.
However,
we
have
considered
the
appropriateness
of
such
requirements
in
the
context
of
evaluating
possible
above
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
as
high
efficiency
control
devices
to
control
(
reduce)
emission
streams
containing
organic
compounds
from
various
process
operations.
Therefore,
EPA's
inability
to
establish
a
combustion
practice
requirements
as
a
part
of
the
MACT
floor
for
new
sources
in
this
category
should
not
reduce
the
incentive
for
owners
and
operators
to
run
their
boilers
and
process
heaters
at
top
efficiency.
Nonetheless,
we
consider
monitoring
and
maintaining
CO
emission
levels
to
be
associated
with
minimizing
emissions
of
organic
HAP.
Carbon
monoxide
is
generally
an
indicator
of
incomplete
combustion
because
CO
will
burn
to
carbon
dioxide
if
adequate
oxygen
is
available.
Therefore,
controlling
CO
emissions
can
be
a
mechanism
for
ensuring
combustion
efficiency
and
may
be
viewed
as
a
kind
of
GCP.
As
discussed
previously
in
this
preamble,
CO
is
considered
a
surrogate
for
organic
HAP
emissions
in
the
proposed
rule.
To
determine
if
CO
monitoring
would
be
the
basis
of
the
new
source
MACT
floor
for
organic
emissions
control,
we
examined
available
information.
The
population
databases
did
not
contain
information
on
existing
units
monitoring
CO
emissions.
We
reviewed
State
regulations
applicable
to
boilers
and
process
heaters
that
required
the
use
of
CO
monitoring
to
maintain
a
specific
CO
limit.
We
then
matched
the
applicability
of
each
of
the
State
regulations
with
information
on
the
locations
and
characteristics
of
the
boilers
and
process
heaters
in
the
population
database
for
each
subcategory
to
determine
if
each
subcategory
would
have
at
least
one
unit
that
would
be
required
to
meet
the
CO
requirements.
The
analysis
of
the
State
regulations
indicated
that
at
least
one
of
the
boilers
and
process
heaters
in
the
large
and
limited
use
subcategories
for
solid
fuel,
liquid
fuel,
and
gaseous
fuel
were
required
to
monitor
CO
emissions
and
meet
a
CO
limit
of
400
parts
per
million.
Therefore,
the
new
source
MACT
floor
level
of
control
includes
a
CO
work
practice
standard
of
400
parts
per
million
for
large
and
limited
use
units,
reflecting
the
MACT
floor
level
of
control
for
emissions
of
organic
HAP.
We
concluded
for
new
units
that,
except
for
CO
monitoring
for
organic
HAP,
add­
on
control
technology
is
the
only
factor
that
significantly
controls
emissions.
To
determine
the
MACT
floor
for
new
sources,
EPA
reviewed
the
population
database
of
existing
major
sources.
Data
for
units
not
meeting
the
definition
of
an
industrial,
commercial,
or
institutional
boiler
or
process
heater
were
removed
from
the
database.
Also,
boilers
and
process
heaters
that
would
not
be
covered
by
the
proposed
rule,
including
units
located
at
area
source
facilities,
were
not
included
in
the
analyses.
As
with
the
existing
source
analysis,
the
remaining
units
in
the
population
database
were
first
divided
into
three
subcategories:
gaseous
fuelfired
units,
liquid
fuel­
fired
units,
and
solid
fuel­
fired
units.
They
were
further
divided
into
normal
use
units
(
units
with
greater
than
10
percent
capacity
utilization)
and
limited
use
units
(
units
with
less
than
or
equal
to
10
percent
capacity
utilization)
based
on
hours
of
operation
and
additional
descriptions
provided
in
the
population
database.
Units
were
further
divided
into
large
units
(
greater
than
10
MMBtu/
hr
heat
input)
and
small
units
(
less
than
or
equal
to
10
MMBtu/
hr
heat
input).
Based
upon
the
emission
reduction
potential
of
existing
air
pollution
control
devices,
EPA
listed
all
the
boilers
and
process
heaters
in
the
population
database
in
order
of
decreasing
control
device
effectiveness
for
each
subcategory
and
each
type
of
pollutant.
Once
the
ranking
of
all
existing
boilers
and
process
heaters
was
completed
for
each
subcategory
and
type
of
pollutant,
EPA
identified,
for
each
grouping,
the
control
technology
used
by
the
best
controlled
unit.
Then,
for
each
pollutant
type
in
each
subcategory,
we
used
the
available
emission
test
data
from
units
using
the
best
control
technology
to
identify
the
single
unit
with
the
best
average
measured
performance.
We
then
calculated
an
emission
limit,
based
on
the
measured
performance
of
this
single
unit,
by
applying
an
appropriate
variability
factor
to
account
for
unavoidable
variations
in
emissions
due
to
uncontrollable
variations
in
fuel
characteristics.
The
approach
that
we
use
to
calculate
the
MACT
floors
for
new
sources
is
somewhat
different
from
the
approach
that
we
use
to
calculate
the
MACT
floors
for
existing
sources.
While
the
MACT
floors
for
existing
units
are
intended
to
reflect
the
average
performance
achieved
by
a
representative
group
of
sources,
the
MACT
floors
for
new
units
are
meant
to
reflect
the
emission
control
that
is
achieved
in
practice
by
the
best
controlled
source.
Thus,
for
existing
units,
we
are
concerned
about
estimating
the
central
tendency
of
a
set
of
multiple
units,
while
for
new
units,
we
are
concerned
about
estimating
the
level
of
control
that
is
representative
of
that
achieved
by
a
single
best
controlled
source.
As
with
the
analysis
for
existing
sources
the
new
unit
analysis
must
account
for
variability.
To
accomplish
this
for
new
sources,
for
the
fuel
dependent
HAP
emissions,
we
attempt
to
determine
what
the
best
controlled
source
can
achieve
in
light
of
the
inherent
and
unavoidable
variations
in
the
HAP
content
of
the
fuel
that
such
unit
might
potentially
use.
For
non­
fuel
dependent
HAP
emissions,
on
the
other
hand,
we
look
at
the
inherent
variability
of
the
control
technology
used
by
sources
in
the
category.
These
approaches,
respectively,
represent
the
most
reasonable
way
to
estimate
performance
for
purposes
of
establishing
MACT
floors
for
new
units,
given
the
data
available.
Thus,
for
new
units,
after
identifying
the
best
control
technology
for
each
pollutant
group
within
each
subcategory
(
based
on
the
control
technology
rankings),
EPA
examined
the
emissions
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13,
2003
/
Proposed
Rules
data
available
for
boilers
and
process
heaters
controlled
by
these
technologies
to
determine
achievable
emission
levels
for
PM
(
as
a
surrogate
for
non­
mercury
metallic
HAP),
total
selected
nonmercury
metallic
HAP,
mercury,
HCl
(
as
a
surrogate
for
inorganic
HAP),
and
CO
(
as
a
surrogate
for
organic
HAP).
First,
we
identified
the
units
using
the
best
control
technology
for
which
we
had
emissions
data.
We
then
averaged
the
emission
data
for
any
unit
with
multiple
test
results,
and
rank
these
units
based
on
the
unit
by
unit
average
measured
emissions
performance.
Then,
we
identified
the
unit
with
the
best
average
measured
emissions
performance.
Finally,
to
estimate
the
emission
control
achievable
by
this
unit,
we
applied
a
variability
factor
to
the
average
measured
emissions
performance
of
the
best
unit.
For
fuel
dependent
HAP
emissions
(
mercury
and
HCl),
we
calculated
the
variability
factor
by
looking
at
data
on
HAP
variability
in
coal
from
an
analysis
of
coal
properties
obtained
through
a
utility­
related
information
collection
request.
We
derived
the
fuel
dependent
variability
factor
by
dividing
the
highest
observed
HAP
concentration
by
the
lowest
observed
HAP
concentration
from
the
utility
coal
analysis.
There
is
no
reason
to
expect
that
utilities
use
significantly
different
coal
than
is
available
to
industrial
boilers
and
process
heaters,
and
coal
is
the
solid
fuel
that
is
routinely
used
in
such
units
that
has
generally
the
greatest
degree
of
HAP
variability.
Once
we
calculated
the
fuel
dependent
variability
factors,
we
applied
these
factors
to
the
average
measured
emissions
performance
of
the
unit
with
the
best
data
to
derive
the
MACT
floor
level
of
control.
This
approach
reasonably
estimates
the
best
source's
level
of
control,
adjusted
for
unavoidable
variation
in
fuel
characteristics
which
have
a
direct
impact
on
emissions.
For
non­
fuel
dependent
HAP
emissions
(
PM/
metallic
HAP),
we
calculated
the
appropriate
variability
factor
in
the
same
general
manner
as
we
did
for
existing
units.
We
calculated
a
variability
factor
for
each
unit
using
the
same
control
technology
as
the
unit
with
the
best
emissions
data,
and
then
calculated
the
overall
variability
in
the
measured
emissions
from
units
using
this
technology
by
averaging
all
the
individual
unit
variability
factors.
Finally,
we
applied
this
overall
variability
factor
to
the
average
measured
emissions
performance
of
the
unit
with
the
best
emissions
data.
For
new
unit
subcategories
where
no
units
in
the
subcategory
employed
any
type
of
control
technology,
we
could
not
identify
data
to
represent
the
level
of
control
of
the
best
controlled
similar
unit.
Accordingly,
the
MACT
floor
level
of
control
for
such
subcategories
is
no
emissions
reductions.
A
detailed
description
of
the
MACT
floor
determination
is
in
the
memorandum
``
MACT
Floor
Analysis
for
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
National
Emission
Standards
for
Hazardous
Air
Pollutants''
in
the
docket.

1.
New
Solid
Fuel­
Fired
Units
a.
Large
Units
 
Heat
Inputs
Greater
than
10
MMBtu/
hr.
The
most
effective
control
technology
identified
for
removing
non­
mercury
metallic
HAP
and
PM
is
fabric
filters.
Therefore,
because
there
are
no
options
reasonably
available
for
reducing
non­
mercury
metallic
HAP
emissions
other
than
addon
control,
we
consider
a
source
with
a
fabric
filter
to
be
the
best
controlled
similar
unit
in
this
subcategory
for
purposes
of
non­
mercury
metallic
HAP
and
PM
emissions.
Thus,
it
is
appropriate
to
use
the
measured
performance
of
the
best
controlled
source
with
a
fabric
filter
as
the
basis
for
establishing
the
MACT
floor
for
nonmercury
metallic
HAP
and
PM
for
new
boilers
and
process
heaters
in
this
subcategory.
As
described
earlier,
a
PM
level
is
set
as
a
surrogate
for
non­
mercury
metallic
HAP.
The
MACT
floor
emission
level
based
on
PM
test
data
from
the
solid
fuel
unit
with
a
fabric
filter
representing
the
best
controlled
similar
unit,
and
incorporating
operational
variability,
is
0.026
lb
PM/
MMBtu.
We
are
also
providing
an
alternative
metals
limit
of
0.0001
lb
metals/
MMBtu
which
can
be
used
to
show
compliance
in
cases
where
metals
HAP
emissions
are
low
in
proportion
to
PM
emissions.
This
is
because,
according
to
the
emissions
database,
some
biomass
units
have
low
metals
content
but
high
PM
emissions.
The
emission
level
for
metals
was
selected
from
metals
test
data
associated
with
PM
emission
tests
from
fabric
filters
that
met
the
MACT
floor
PM
emission
level.
The
most
effective
control
technologies
identified
for
removing
inorganic
HAP
including
acid
gases,
such
as
HCl,
are
wet
or
dry
scrubbers.
Wet
scrubbers
is
a
generic
term
that
is
most
often
used
to
describe
venturi
scrubbers,
but
can
include
packed
bed
scrubbers,
impingement
scrubbers,
etc.
One
percent
of
boilers
and
process
heaters
in
this
subcategory
reported
using
a
packed
bed
scrubber.
Emission
test
data
from
other
industries
suggests
that
packed
bed
scrubbers
achieve
consistently
lower
emission
levels
than
other
types
of
wet
scrubbers.
Because
there
are
no
options
reasonably
available
for
reducing
HCl
emissions
other
than
add­
on
control,
we
consider
a
source
with
a
packed
bed
scrubber
to
be
the
best
controlled
similar
source
in
this
subcategory
for
purpose
of
HCl
emissions.
The
MACT
floor
emission
level
based
on
HCl
test
data
from
the
solid
fuel
unit
with
a
wet
scrubber
representing
the
best
controlled
similar
unit,
and
incorporating
operational
variability,
is
0.02
lb
HCl/
MMBtu.
For
mercury
control,
one
technology,
carbon
injection,
that
has
demonstrated
mercury
reductions
in
other
source
categories
(
i.
e.,
municipal
waste
combustors),
was
identified
as
being
used
on
one
existing
industrial
boiler.
However,
test
data
on
this
carbon
injection
system
indicated
that
this
unit
was
not
achieving
mercury
emissions
reductions.
Therefore,
we
did
not
consider
carbon
injection
to
be
a
MACT
floor
control
technology
for
industrial,
commercial,
and
institutional
boilers
and
process
heaters.
Data
from
electric
utility
boilers
indicate
that
fabric
filters
are
the
most
effective
technology
for
controlling
mercury
emissions.
Therefore,
we
consider
a
source
with
a
fabric
filter
to
be
the
best
controlled
similar
source
in
this
subcategory
for
purpose
of
mercury
emissions.
The
MACT
floor
emission
level
based
on
mercury
test
data
from
the
solid
fuel
unit
with
a
fabric
filter
representing
the
best
controlled
similar
unit,
and
incorporating
operational
variability,
is
0.000003
lb
mercury/
MMBtu.
Although
EPA
used
information
from
utility
boilers
to
conclude
that
fabric
filters
are
the
most
effective
control
technology
for
controlling
mercury
emissions,
this
same
information
suggests
that
different
fuel
characteristics
(
e.
g.
mercury
and
chlorine
content
of
the
fuel
burned)
can
lead
to
different
outlet
Hg
concentrations
and
different
control
efficiencies
for
equivalent
control
devices.
We
have
information
about
the
general
type
of
fuel
being
burned
during
the
emission
tests.
However,
we
have
no
detailed
information
about
the
specific
characteristics
(
such
as
mercury
or
chlorine
content)
of
the
fuel
being
burned
during
the
emissions
tests
for
the
best
controlled
source.
Nonetheless,
EPA
believes
that
the
use
of
variability
factors
adequately
accounts
for
potential
variations
in
fuel
mercury
and
chloride
content.
However,
because
we
have
very
limited
data
on
actual
emissions
from
industrial
boilers
and
process
heaters,
the
Agency
is
soliciting
comment
on
whether
the
variability
analysis
in
the
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/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
current
proposal
adequately
addresses
the
impact
that
fuel
characteristics
(
such
as
mercury
and
chlorine
content)
can
have
on
mercury
emissions
from
sources
equipped
with
fabric
filters.
As
discussed
earlier,
the
Agency
is
not
currently
considering
fuel
switching
as
a
control
option
in
setting
the
MACT
floor.
Therefore,
the
Agency
requests
specific
information
regarding
both
the
mercury
and
chlorine
content
characteristics
of
the
fuel
used
in,
and
the
mercury
emissions
from,
industrial
boilers
and
process
heaters
equipped
with
well
designed
and
operated
fabric
filters.
Comments
on
this
issue
should
include
specific
data
regarding
both
the
characteristics
of
the
fuel
burned
(
including
mercury
and
chlorine
content
along
with
any
other
pertinent
characteristics)
and
current
mercury
emissions
of
these
industrial
boilers
and
process
heaters.
Similar
control
technology
analysis
was
done
for
the
boilers
and
process
heaters
in
this
subcategory
for
organic
HAP.
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.
Inlet
and
outlet
dioxins
test
data
were
available
on
four
boilers
controlled
with
PM
control
devices.
In
all
cases,
no
increase
in
dioxins
emissions
were
indicated
across
the
PM
control
device
even
at
high
inlet
temperatures.
However,
we
are
requesting
comment
on
controls
that
would
achieve
reductions
of
organic
HAP,
including
any
additional
data
that
might
be
available.
The
EPA
did
find
that
CO
monitoring
can
reduce
organic
HAP
emissions,
and
has
included
it
in
the
new
source
MACT
floors
as
described
previously
in
this
preamble.
In
light
of
this
analysis,
EPA
determined
that,
in
general,
the
combination
of
a
fabric
filter,
a
packed
bed
scrubber,
and
CO
monitoring
forms
the
basis
for
the
MACT
floor
level
of
control
for
new
solid
fuel
boilers
and
process
heaters
in
this
subcategory.
b.
Small
Units
 
Heat
Inputs
Less
than
or
Equal
to
10
MMBtu/
hr.
The
most
effective
control
technology
identified
for
removing
non­
mercury
metallic
HAP
and
PM
is
fabric
filters.
Because
there
are
no
options
reasonably
available
for
reducing
non­
mercury
metallic
HAP
emissions
other
than
add­
on
control,
we
consider
a
source
with
a
fabric
filter
to
be
the
best
controlled
similar
unit
in
this
subcategory
for
purposes
of
nonmercury
metallic
HAP
and
PM
emissions.
The
most
effective
control
technology
identified
for
units
in
this
subcategory
for
removing
acid
gases,
such
as
HCl,
is
wet
scrubbers.
The
most
effective
control
technology
identified
for
removing
mercury
is
fabric
filters.
The
EPA
identified
no
control
technology
being
used
in
the
existing
population
of
boilers
and
process
heaters
that
consistently
achieved
lower
emission
rates
than
uncontrolled
levels,
such
that
a
best
controlled
similar
source
for
organic
HAP
could
be
identified.
Therefore,
we
concluded
that
the
MACT
floor
for
new
sources
in
this
subcategory
is
no
emissions
reductions
for
organic
HAP.
Furthermore,
CO
monitoring
is
not
required
for
small
boilers
and
process
heaters
by
any
State
rules.
Consequently,
EPA
determined
that
the
combination
of
a
fabric
filter
and
a
wet
scrubber
forms
the
basis
for
the
MACT
floor
level
of
control
for
new
solid
fuel
boilers
and
process
heaters
in
this
subcategory.
The
emissions
database
did
not
contain
test
data
for
boilers
and
process
heaters
less
than
10
MMBtu/
hr
heat
input.
In
order
to
develop
emission
levels
for
this
subcategory,
we
decided
to
use
test
data
from
units
in
the
large
solid
subcategory.
We
considered
this
to
be
an
appropriate
methodology
because
although
the
units
in
this
subcategory
are
different
enough
to
warrant
their
own
subcategory
(
i.
e.,
different
designs
and
emissions),
emissions
of
the
specific
HAP
for
which
limits
are
being
proposed
(
HCl,
mercury,
PM
and
metals)
are
expected
to
be
related
more
to
the
type
of
fuel
burned
and
the
type
of
control
used
than
to
the
unit
design.
Consequently,
we
determined
that
emissions
test
data
from
units
greater
than
10
MMBtu/
hr
heat
input
could
be
used
to
establish
the
MACT
floor
levels
for
this
subcategory
for
HCl,
PM,
nonmercury
metallic
HAP
(
using
PM
as
a
surrogate),
and
mercury
because
the
fuels
and
controls
are
similar.
The
MACT
floor
emission
levels
based
on
emissions
data
from
the
unit
representing
the
best
controlled
similar
source,
and
incorporating
operational
variability,
are
0.026
lb
PM/
MMBtu
or
0.0001
lb
selected
non­
mercury
metals/
MMBtu,
0.000003
lb
mercury/
MMBtu,
and
0.02
lb
HCl/
MMBtu.
We
are
requesting
comment
on
using
emission
data
from
another
subcategory
to
develop
emission
levels
for
this
subcategory.
We
are
also
requesting
any
available
emissions
information
for
this
subcategory.
c.
Limited
Use
Units
 
Capacity
Utilizations
Less
than
or
Equal
to
10
Percent.
The
most
effective
control
technology
identified
for
removing
nonmercury
metallic
HAP,
PM,
and
mercury
is
fabric
filters.
Therefore,
we
consider
a
source
with
a
fabric
filter
to
be
the
best
controlled
similar
unit
in
this
subcategory
for
purposes
of
nonmercury
metallic
HAP,
PM,
and
mercury
emissions.
The
most
effective
control
technology
identified
for
units
in
this
subcategory
for
removing
acid
gases,
such
as
HCl,
is
wet
scrubbers.
The
EPA
did
find
that
monitoring
CO
is
used
by
at
least
one
unit
and
can
minimize
organic
HAP
emissions,
and
has
included
it
in
the
new
source
MACT
floor
for
this
subcategory
as
described
previously
in
this
preamble.
Therefore,
based
on
this
analysis,
EPA
determined
that
the
combination
of
a
fabric
filter,
a
wet
scrubber,
and
CO
monitoring
forms
the
basis
for
the
MACT
floor
level
of
control
for
new
solid
fuel
boilers
and
process
heaters
in
this
subcategory.
The
emissions
test
database
did
not
contain
test
data
for
limited
use
boilers
and
process
heaters.
In
order
to
develop
emission
levels
for
this
subcategory,
we
decided
to
use
test
data
from
units
in
the
large
solid
fuel
subcategory.
We
considered
this
to
be
an
appropriate
methodology
because
although
the
units
in
this
subcategory
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
(
HCl,
mercury,
and
metals)
are
expected
to
be
related
more
to
the
type
of
fuel
burned
and
the
type
of
control
used,
than
to
unit
operation.
Consequently,
we
determined
that
emissions
information
from
the
large
solid
fuel
subcategory
could
be
used
to
establish
MACT
floor
levels
for
this
subcategory
because
the
fuels
and
controls
are
similar.
The
MACT
floor
emission
levels
based
on
test
data
from
unit
representing
the
best
controlled
similar
source,
and
incorporating
operational
variability,
are
0.026
lb
PM/
MMBtu
or
0.0001
lb
metals/
MMBtu,
0.000003
lb
mercury/
MMBtu,
and
0.02
lb
HCl/
MMBtu.
We
are
requesting
comment
on
using
emission
data
from
another
subcategory
to
develop
emission
levels
for
this
subcategory.
We
are
also
requesting
any
available
emissions
information
for
this
subcategory.

2.
New
Liquid
Fuel­
Fired
Units
a.
Large
Units
 
Heat
Inputs
Greater
than
10
MMBtu/
hr.
The
most
effective
control
technology
identified
for
removing
non­
mercury
metallic
HAP
and
PM
is
ESP.
Therefore,
because
there
are
no
options
reasonably
available
for
reducing
non­
mercury
metallic
HAP
emissions
other
than
add­
on
control,
we
consider
a
source
with
an
ESP
to
be
the
best
controlled
similar
unit
in
this
subcategory
for
purposes
of
non­

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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
mercury
metallic
HAP
and
PM
emissions.
As
discussed
earlier,
a
PM
level
is
set
as
a
surrogate
for
non­
mercury
metallic
HAP.
The
emissions
database
did
not
contain
test
data
for
boilers
and
process
heaters
with
ESP.
In
order
to
develop
a
PM
emission
level
for
this
subcategory,
we
decided
to
use
test
data
from
oilfired
utility
boilers
controlled
with
ESP.
We
considered
this
to
be
an
appropriate
methodology
because
although
the
units
in
this
subcategory
are
generally
smaller
than
utility
boilers,
emissions
of
the
specific
HAP
for
which
limits
are
being
proposed
(
PM
as
a
surrogate
for
metals)
are
expected
to
be
related
more
to
the
type
of
fuel
burned
and
the
type
of
control
used
than
to
the
size
of
the
unit.
Consequently,
we
determined
that
emissions
test
data
from
oil­
fired
utility
boilers
could
be
used
to
establish
the
MACT
floor
levels
for
this
subcategory
for
non­
mercury
metallic
HAP
(
using
PM
as
a
surrogate)
because
the
fuels
and
controls
are
similar.
The
MACT
floor
emission
level
based
on
PM
emissions
data
from
the
unit
representing
the
best
controlled
similar
source,
and
incorporating
operational
variability,
is
0.03
lb
PM/
MMBtu.
Unlike
for
solid
fuel
subcategories,
we
are
not
aware
of
any
liquid
fuels
that
are
low
in
metals
but
would
have
high
PM
emissions.
Therefore,
we
are
not
proposing
an
alternative
metals
standard
for
the
liquid
subcategories.
The
most
effective
control
technology
identified
for
removing
inorganic
HAP
that
are
acid
gases,
such
as
HCl,
are
packed
bed
scrubbers.
Because
there
are
no
options
reasonably
available
for
reducing
HCl
emissions
other
than
addon
control,
we
consider
a
source
with
a
packed
bed
scrubber
to
be
the
best
controlled
similar
source
in
this
subcategory
for
purpose
of
HCl
emissions.
The
emissions
database
did
not
contain
HCl
test
data
for
liquid
fuel
boilers
and
process
heaters.
In
order
to
develop
a
HCl
emission
level
for
this
subcategory,
we
decided
to
use
available
fuel
analysis
data
from
oil­
fired
units
and
emission
reduction
performance
of
well
designed
and
operated
packed
bed
scrubbers.
We
considered
this
to
be
an
appropriate
methodology
because
this
approach
reasonably
estimates
the
best
source's
level
of
control,
adjusted
for
unavoidable
variation
in
fuel
characteristics
which
have
a
direct
impact
on
emissions.
The
MACT
floor
emission
level
based
on
the
estimated
performance
from
a
liquid
fuel
unit
with
a
packed
scrubber
representing
the
best
controlled
similar
unit,
and
incorporating
operational
variability,
is
0.0005
lb
HCl/
MMBtu.
Similar
control
technology
analyses
were
done
for
the
boilers
and
process
heaters
in
this
subcategory
for
mercury
and
organic
HAP.
Information
in
the
emissions
database
or
from
other
source
categories
does
not
show
that
control
technologies,
such
as
fabric
filters,
ESP,
or
wet
scrubbers,
achieve
reductions
in
mercury
emissions
from
liquid
fuel­
fired
industrial,
commercial,
and
institutional
boilers
and
process
heaters.
Therefore,
EPA
identified
no
control
technology
being
used
in
the
existing
population
of
boilers
and
process
heaters
in
these
subcategories
that
consistently
achieved
lower
emission
rates
than
uncontrolled
levels,
such
that
a
best
controlled
similar
source
for
organic
HAP
could
be
identified.
However,
we
did
find
that
monitoring
CO
is
a
good
combustion
practice
that
can
reduce
organic
HAP
emissions,
and
have
included
it
in
the
new
source
MACT
floor
as
described
previously
in
this
preamble.
We
concluded
the
MACT
floor
for
new
sources
in
this
subcategory
is
no
emissions
reductions
for
mercury.
In
light
of
this
analysis,
the
EPA
determined
that,
in
general,
the
combination
of
an
ESP,
a
packed
bed
scrubber,
and
CO
monitoring
forms
the
basis
for
the
MACT
floor
level
of
control
for
new
liquid
fuel
boilers
and
process
heaters
in
this
subcategory.
b.
Small
Units
 
Heat
Inputs
Less
than
or
Equal
to
10
MMBtu/
hr.
The
most
effective
control
technology
identified
for
removing
non­
mercury
metallic
HAP
used
by
units
in
this
subcategory
is
ESP.
Therefore,
because
there
are
no
options
reasonably
available
for
reducing
nonmercury
metallic
HAP
emissions
other
than
add­
on
control,
we
consider
a
source
with
an
ESP
to
be
the
best
controlled
similar
unit
in
this
subcategory
for
purposes
of
nonmercury
metallic
HAP
and
PM
emissions.
The
most
effective
control
technology
identified
for
units
in
this
subcategory
for
removing
acid
gases,
such
as
HCl,
is
wet
scrubbers.
Information
in
the
emissions
database
or
from
other
source
categories
does
not
show
that
control
technologies,
such
as
fabric
filters,
ESP,
or
wet
scrubbers,
achieve
reductions
in
mercury
emissions
from
liquid
fuel­
fired
industrial,
commercial,
and
institutional
boilers
and
process
heaters.
Therefore,
EPA
could
not
identify
a
control
technology
being
used
in
the
existing
population
of
boilers
and
process
heaters
that
consistently
achieved
lower
emission
rates
than
uncontrolled
levels,
such
that
a
best
controlled
similar
source
for
mercury
or
organic
HAP
could
be
identified.
We
concluded
the
MACT
floor
for
new
sources
in
this
subcategory
is
no
emissions
reductions
for
mercury
or
organic
HAP.
Thus,
EPA
determined
that
the
combination
of
a
fabric
filter
and
a
wet
scrubber
forms
the
basis
for
the
MACT
floor
level
of
control
for
new
liquid
fuel
boilers
and
process
heaters
in
this
subcategory.
The
emissions
test
database
did
not
contain
test
data
for
liquid
fuel
boilers
and
process
heaters
less
than
10
MMBtu/
hr
heat
input
capacity.
In
order
to
develop
emission
levels
for
this
subcategory,
we
decided
to
use
information
from
units
in
the
large
liquid
fuel
subcategory.
We
considered
this
to
be
an
appropriate
methodology
because
although
the
units
in
this
subcategory
are
different
enough
to
warrant
their
own
subcategory
(
i.
e.,
different
designs
and
emissions),
emissions
of
the
specific
types
of
HAP
for
which
limits
are
being
proposed
(
HCl
and
metals)
are
expected
to
be
more
related
to
the
type
of
fuel
burned
and
the
type
of
control
than
to
unit
design.
Consequently,
we
determined
that
emissions
information
from
units
greater
than
10
MMBtu/
hr
heat
input
capacity
could
be
used
to
establish
MACT
floor
levels
for
this
subcategory
because
the
fuels
and
controls
are
similar.
The
MACT
floor
emission
level
based
on
PM
test
data
from
a
liquid
fuel
unit
with
an
ESP
representing
the
best
controlled
similar
unit,
and
incorporating
operational
variability,
is
0.03
lb
PM/
MMBtu.
The
MACT
floor
emission
level
based
on
a
liquid
fuel
unit
with
a
wet
scrubber
representing
the
best
controlled
similar
unit,
and
incorporating
operational
variability,
is
0.0009
lb
HCl/
MMBtu.
We
are
requesting
comment
on
using
emission
data
from
another
subcategory
to
develop
emission
levels
for
this
subcategory.
We
are
also
requesting
any
available
emissions
information
for
this
subcategory.
c.
Limited
Use
Units
 
Capacity
Utilizations
Less
than
or
Equal
to
10
Percent.
The
most
effective
control
technology
identified
for
removing
nonmercury
metallic
HAP
used
by
units
in
this
subcategory
is
ESP.
Therefore,
because
there
are
no
options
reasonably
available
for
reducing
non­
mercury
metallic
HAP
emissions
other
than
addon
control,
we
consider
a
source
with
an
ESP
to
be
the
best
controlled
similar
unit
in
this
subcategory
for
purposes
of
non­
mercury
metallic
HAP
and
PM
emissions.
The
most
effective
control
technology
identified
for
units
in
this
subcategory
for
removing
acid
gases,
such
as
HCl,
is
wet
scrubbers.
Information
in
the
emissions
database
or
from
other
source
categories
does
not
show
that
other
control
technologies,

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2002
19:
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2003
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00000
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FR\
FM\
13JAP2.
SGM
13JAP2
1684
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
such
as
fabric
filters,
ESP,
or
wet
scrubbers,
achieve
reductions
in
mercury
emissions
from
liquid
fuelfired
industrial,
commercial,
and
institutional
boilers
and
process
heaters.
The
EPA
identified
no
control
technology
being
used
in
the
existing
population
of
boilers
and
process
heaters
that
consistently
achieved
lower
emission
rates
than
uncontrolled
levels,
such
that
a
best
controlled
similar
source
for
mercury
could
be
identified.
We
concluded
the
MACT
floor
for
new
sources
in
this
subcategory
is
no
emissions
reductions
for
mercury.
We
did
find
that
monitoring
CO
can
reduce
organic
HAP
emissions
and
is
used
by
at
least
one
unit
in
this
subcategory,
and
have
included
it
in
the
new
source
MACT
floor
as
described
previously
in
this
preamble.
Therefore,
based
on
this
analysis,
EPA
determined
that
the
combination
of
a
fabric
filter,
a
wet
scrubber,
and
CO
monitoring
forms
the
basis
for
the
MACT
floor
level
of
control
for
new
liquid
fuel
boilers
and
process
heaters
in
this
subcategory.
The
emissions
test
database
did
not
contain
test
data
for
limited
use
liquid
fuel
boilers
and
process
heaters.
In
order
to
develop
emission
levels
for
this
subcategory,
we
decided
to
use
information
from
units
in
the
large
liquid
fuel
subcategory.
We
considered
this
to
be
an
appropriate
methodology
because
although
the
units
in
this
subcategory
are
different
enough
to
warrant
their
own
subcategory
(
i.
e.,
different
purposes
and
operation),
emissions
of
the
specific
HAP
for
which
limits
are
being
proposed
(
HCl
and
metals)
are
more
related
to
the
type
of
fuel
burned
and
the
type
of
control
used
than
to
unit
operation.
Consequently,
we
determined
that
emissions
information
from
units
greater
than
10
MMBtu/
hr
heat
input
capacity
could
be
used
to
establish
MACT
floor
levels
for
this
subcategory
because
the
fuels
and
controls
are
similar.
The
MACT
floor
emission
level
based
on
PM
test
data
from
a
liquid
fuel
unit
with
an
ESP
representing
the
best
controlled
similar
unit,
and
incorporating
operational
variability,
is
0.03
lb
PM/
MMBtu.
The
MACT
floor
emission
level
based
on
a
liquid
fuel
unit
with
a
wet
scrubber
representing
the
best
controlled
similar
unit,
and
incorporating
operational
variability,
is
0.0009
lb
HCl/
MMBtu.
We
are
requesting
comment
on
using
emission
data
from
another
subcategory
to
develop
emission
levels
for
this
subcategory.
We
are
also
requesting
any
available
emissions
information
for
this
subcategory.
3.
Gaseous
Fuel
Subcategories
No
existing
units
were
using
control
technologies
that
achieve
consistently
lower
emission
rates
than
uncontrolled
sources
for
any
of
the
pollutant
groups
of
interest,
except
organic
HAP.
At
least
one
unit
in
the
population
database
in
the
large
and
limited
use
gaseous
fuel
subcategories
is
required
to
monitor
CO.
Therefore,
the
MACT
floor
for
gaseous
fuel­
fired
units
includes
a
CO
monitoring
requirement
and
emission
limit,
as
described
previously
in
this
preamble,
but
it
does
not
include
any
emission
limits
for
PM,
metallic
HAP,
mercury,
or
inorganic
HAP
based
on
the
utilization
of
add­
on
control
technology.

I.
How
Did
EPA
Consider
Beyond­
the­
Floor
for
New
Units?

The
MACT
floor
level
of
control
for
new
units
is
based
on
the
emission
control
that
is
achieved
in
practice
by
the
best
controlled
similar
source
within
each
of
the
subcategories.
No
technologies
were
identified
that
would
achieve
non­
mercury
metals
reduction
greater
than
the
new
source
floors
for
the
liquid
and
solid
subcategories
or
CO
monitoring
for
the
solid,
liquid,
and
gaseous
subcategories.
For
inorganic
HAP
control,
we
determined
that
packed
bed
scrubbers
achieve
higher
emissions
reductions
than
MACT
floors
consisting
of
a
wet
scrubber.
Packed
bed
scrubbers
are
the
technology
basis
of
the
MACT
floor
for
the
large
unit
subcategory,
but
wet
scrubbers
were
the
technology
basis
of
the
floors
for
the
small
unit
and
limited
unit
subcategories.
Therefore,
we
examined
the
cost
and
emission
reduction
benefits
of
applying
a
packed
bed
scrubber
as
a
beyond­
the­
floor
option
for
new
solid
and
liquid
units
within
the
small
and
limited
use
subcategories.
The
results
of
this
analysis
indicated
that
annualized
costs
would
be
an
additional
2
million
dollars
per
year
for
additional
reductions
of
approximately
three
tons
of
HCl
per
year.
We
determined
that
costs
were
excessive
for
the
limited
emissions
reductions
that
would
be
achieved.
Nonair
quality
health,
environmental
impacts,
and
energy
effects
were
not
significant
factors,
because
there
would
be
little
difference
in
the
nonair
quality
health
and
environmental
impacts
between
packed
bed
scrubbers
and
wet
scrubbers.
Therefore,
EPA
did
not
select
this
beyond­
the­
floor
option,
and
the
proposed
new
source
MACT
level
of
control
for
PM,
metallic
HAP,
and
inorganic
HAP
(
HCl)
is
the
same
as
the
MACT
floor
level
of
control
for
all
of
the
subcategories.
In
reviewing
potential
regulatory
options
beyond
the
new
source
MACT
floor
level
of
control,
EPA
identified
one
existing
solid
fuel­
fired
industrial
boiler
that
was
using
carbon
injection
technology
for
mercury
control.
However,
emission
data
obtained
from
this
unit
indicated
that
it
was
not
achieving
mercury
emission
reduction
from
the
uncontrolled
levels.
Moreover,
we
do
not
have
information
to
otherwise
show
that
carbon
injection
is
effective
for
reducing
mercury
emissions
from
industrial,
commercial,
and
institutional
boilers
and
process
heaters.
Information
in
the
emissions
database
or
from
other
source
categories
does
not
show
that
other
control
technologies,
such
as
fabric
filters,
ESP,
or
wet
scrubbers,
achieve
reductions
in
mercury
emissions
from
liquid
fuel­
fired
industrial,
commercial,
and
institutional
boilers
and
process
heaters.
Therefore,
carbon
injection,
for
solid
fuel
units,
and
other
control
techniques,
for
liquid
fuel
units,
were
not
evaluated
as
regulatory
options.
However,
EPA
requests
comments
on
whether
carbon
injection
and/
or
other
control
techniques
should
be
considered
as
beyond­
the­
floor
options
and
whether
new
industrial,
commercial,
or
institutional
boilers
and
process
heaters
could
use
carbon
injection
technology,
or
other
control
techniques
to
consistently
achieve
mercury
emission
levels
that
are
lower
than
levels
from
similar
sources
without
such
controls.
Comments
should
include
information
on
emissions,
current
demonstrated
applications,
and
costs.
For
the
solid
fuel
and
liquid
fuel
subcategories,
fuel
switching
to
natural
gas
is
a
potential
regulatory
option
beyond
the
new
source
floor
level
of
control
that
would
reduce
mercury
and
metallic
HAP
emissions.
However,
based
on
current
trends
within
the
industry,
EPA
projects
that
the
majority
of
new
boilers
and
process
heaters
will
be
built
to
fire
natural
gas
as
opposed
to
solid
and
liquid
fuels
such
that
the
overall
emissions
reductions
associated
with
this
option
would
be
minimal
while
the
total
cost
of
fuel
switching
would
be
approximately
600
million
dollars.
The
additional
emissions
reductions
would
be
30
tons
per
year
of
HCl,
90
tons
per
year
of
inorganic
HAP
and
120
tons
per
year
of
total
nonmercury
metallic
HAP.
Section
III.
D
of
this
preamble
provides
additional
rationale
for
not
going
beyond
the
floor
to
require
fuel
switching.
For
example,
natural
gas
supplies
are
not
available
in
some
areas,
and
supplies
to
industrial
customers
can
be
limited
during
periods
when
natural
gas
demand
exceeds
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Proposed
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supply.
Thus,
this
potential
control
option
may
be
unavailable
to
many
sources
in
practice.
Furthermore,
organic
HAP
may
be
increased
by
fuel
switching.
Limited
emissions
reductions
in
combination
with
the
high
cost
of
fuel
switching
and
considerations
about
the
availability
and
technical
feasibility
of
fuel
switching
makes
this
an
unreasonable
regulatory
option
that
was
not
considered
further.
Nonair
quality
health,
environmental
impacts,
and
energy
effects
were
not
significant
factors.
No
beyond­
the­
floor
options
for
gas­
fired
boilers
were
identified.
Based
on
the
analysis
discussed
above,
EPA
decided
to
not
go
beyond
the
MACT
floor
level
of
control
for
new
sources
for
MACT
in
the
proposed
rule.
A
detailed
description
of
the
beyondthe
floor
consideration
is
in
the
memorandum
``
Methodology
for
Estimating
Cost
and
Emissions
Impacts
for
Industrial,
Commercial,
Institutional
Boilers
and
Process
Heaters
National
Emission
Standards
for
Hazardous
Air
Pollutants''
in
the
docket.

J.
How
Did
EPA
Determine
Testing
and
Monitoring
Requirements
for
the
Proposed
Rule?
The
CAA
requires
us
to
develop
regulations
that
include
monitoring
and
testing
requirements.
The
purpose
of
these
requirements
is
to
allow
us
to
determine
whether
an
affected
source
is
operating
in
compliance
with
the
proposed
rule.
The
proposed
monitoring
and
testing
requirements
are
discussed
below.

1.
Testing
The
proposed
rule
requires
you
to
perform
an
initial
performance
test
for
PM
(
or
total
selected
metals),
mercury,
and
HCl
if
you
are
required
to
meet
an
emission
limit.
Additionally,
the
proposed
rule
requires
annual
performance
tests
to
ensure
on
an
ongoing
basis
that
the
air
pollution
control
device
is
operating
properly
and
its
performance
has
not
deteriorated.
The
majority
of
emissions
tests
upon
which
the
proposed
emission
limits
are
based
were
conducted
using
approved
EPA
test
methods.
If
you
conduct
a
performance
test,
you
would
also
determine
parameter
operating
limits
during
the
tests.
The
majority
of
test
methods
that
the
proposed
rule
would
require
for
the
performance
tests
have
been
required
under
many
other
EPA
standards.
No
applicable
voluntary
consensus
standards
were
identified.
If
you
are
required
to
meet
an
HCl
emission
limit
and
do
not
have
a
scrubber
or
elect
to
take
no
credit
for
the
scrubber
emissions
reductions,
you
must
record
the
average
chlorine
content
level
in
the
input
fuel
as
an
operating
limit.
However,
if
you
plan
to
burn
a
new
fuel,
a
fuel
from
a
new
mixture,
or
a
fuel
from
a
new
supply
than
what
was
burned
during
the
initial
performance
test,
then
you
must
recalculate
the
chlorine
input.
If
the
results
of
recalculating
the
chlorine
input
exceeds
the
average
chlorine
level
established
during
the
initial
performance
test,
you
must
conduct
a
new
performance
test
to
demonstrate
compliance
with
the
emission
level.
We
are
also
allowing
you
to
record
the
mercury
in
the
input
fuels
as
an
operating
limit
if
you
elect
to
take
no
credit
for
the
control
device
emission
reduction.
However,
if
you
plan
to
burn
a
new
fuel,
a
fuel
from
a
new
mixture,
or
a
fuel
from
a
new
supply
than
what
was
burned
during
the
initial
performance
test,
then
you
must
recalculate
the
mercury
input.
If
the
results
of
the
recalculation
exceed
the
average
level
established
during
the
initial
performance
test,
you
must
conduct
a
new
performance
test
to
demonstrate
compliance
with
the
mercury
emission
level.
We
are
also
allowing
you
to
record
the
total
selected
metals
in
the
input
fuels
as
an
operating
limit
if
you
choose
to
comply
with
the
metals
emission
limit
instead
of
the
PM
limit.
However,
if
you
plan
to
burn
a
new
fuel,
a
fuel
from
a
new
mixture,
or
a
fuel
from
a
new
supply
than
what
was
burned
during
the
initial
performance
test,
then
you
must
recalculate
the
total
selected
metals
input.
If
the
results
of
the
recalculation
exceed
the
average
level
established
during
the
initial
performance
test,
you
must
conduct
a
new
performance
test
to
demonstrate
compliance
with
the
metals
emission
level.

2.
Continuous
Monitoring
The
most
direct
means
of
ensuring
compliance
with
emission
limits
is
the
use
of
continuous
emission
monitoring
systems
(
CEMS).
We
consider
other
options
when
CEMS
are
not
available
or
when
the
impacts
of
including
such
requirements
are
considered
unreasonable.
When
monitoring
options
other
than
CEMS
are
considered,
it
is
often
necessary
for
us
to
balance
more
reasonable
costs
against
the
quality
or
accuracy
of
the
actual
emissions
monitoring
data.
Although
monitoring
of
operating
parameters
cannot
provide
a
direct
measurement
of
emissions,
it
is
often
a
suitable
substitute
for
CEMS.
The
information
provided
can
be
used
to
ensure
that
air
pollution
control
equipment
is
operating
properly.
Because
the
parameter
requirements
are
calibrated
during
the
initial
and
annual
stack
tests,
they
provide
a
reasonable
surrogate
for
direct
monitoring
of
emissions.
This
information
reasonably
assures
the
public
that
the
reductions
envisioned
by
the
proposed
rule
are
being
achieved.
The
EPA
evaluated
the
cost
of
applying
HCl
CEMS
to
boilers
and
process
heaters.
For
HCl
CEM
monitoring,
capital
costs
were
estimated
to
be
$
88,000
per
unit
and
annualized
costs
were
estimated
to
be
$
33,000
per
unit.
We
determined
the
costs
would
make
them
an
unreasonable
monitoring
option.
In
addition,
toxic
metals
are
not
directly
measurable
with
CEMS,
and
CEMS
for
PM
have
not
been
demonstrated
in
the
United
States
for
the
purpose
of
determining
compliance.
To
ensure
continuous
compliance
with
the
proposed
emission
limits
and/
or
operating
limits,
the
proposed
rule
would
require
continuous
parameter
monitoring
of
control
devices
and
recordkeeping.
We
selected
the
following
requirements
based
on
reasonable
cost,
ease
of
execution,
and
usefulness
of
the
resulting
data
to
both
the
owners
or
operators
and
EPA
for
ensuring
continuous
compliance
with
the
emission
limits
and/
or
operating
limits.
We
are
proposing
that
certain
parameters
be
continuously
monitored
for
the
types
of
control
devices
commonly
used
in
the
industry.
These
parameters
include
opacity
monitoring
except
for
wet
scrubbers;
pH,
pressure
drop
and
liquid
flow­
rate
for
wet
scrubbers;
and
sorbent
injection
rate
for
dry
scrubbers.
You
must
also
install
a
bag
leak
detection
system
for
fabric
filters.
If
you
cannot
monitor
opacity
for
control
systems
with
an
ESP
then
you
must
monitor
the
secondary
current
and
voltage
or
total
power
input
for
the
ESP.
These
monitoring
parameters
have
been
used
in
other
standards
for
similar
industries.
The
values
of
these
parameters
are
established
during
the
initial
or
most
recent
performance
test
that
demonstrates
compliance.
These
values
are
your
operating
limits
for
the
control
device.
You
would
be
required
to
set
parameters
based
on
1­
hour
block
averages
during
the
compliance
test,
and
demonstrate
continuous
compliance
by
monitoring
3­
hour
block
average
values
for
most
parameters.
We
selected
this
averaging
period
to
reflect
operating
conditions
during
the
performance
test
to
ensure
the
control
system
is
continuously
operating
at
the
same
or
better
level
as
during
a
performance
test
demonstrating
compliance
with
the
emission
limits.

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2003
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Proposed
Rules
To
demonstrate
continuous
compliance
with
the
emission
and
operating
limits,
you
would
also
need
daily
records
of
the
quantity,
type,
and
origin
of
each
fuel
burned
and
hours
of
operation
of
the
affected
source.
If
you
are
complying
with
the
chlorine
or
total
selected
metals
fuel
input
option,
you
must
keep
records
of
the
calculations
supporting
your
determination
of
the
chlorine
and
total
selected
metals
content
in
the
fuel.

K.
How
Did
EPA
Determine
Compliance
Times
for
the
Proposed
Rule?
Section
112
of
the
CAA
specifies
the
dates
by
which
affected
sources
must
comply
with
the
emission
standards.
New
or
reconstructed
units
must
be
in
compliance
with
the
proposed
rule
immediately
upon
startup
or
[
DATE
THE
FINAL
RULE
IS
PUBLISHED
IN
THE
FEDERAL
REGISTER],
whichever
is
later.
Existing
sources
are
allowed
3
years
to
comply
with
the
final
rule.
This
is
the
maximum
period
allowed
by
the
CAA.
We
believe
that
3
years
for
compliance
is
necessary
to
allow
adequate
time
to
design,
install
and
test
control
systems
that
will
be
retrofitted
onto
existing
boilers,
as
well
as
obtain
permits
for
the
use
of
add­
on
controls.

L.
How
Did
EPA
Determine
the
Required
Records
and
Reports
for
the
Proposed
Rule?
You
would
be
required
to
comply
with
the
applicable
requirements
in
the
NESHAP
General
Provisions,
subpart
A
of
40
CFR
part
63,
as
described
in
Table
10
of
the
proposed
subpart
DDDDD.
We
evaluated
the
General
Provisions
requirements
and
included
those
we
determined
to
be
the
minimum
notification,
recordkeeping,
and
reporting
necessary
to
ensure
compliance
with,
and
effective
enforcement
of,
the
proposed
rule.
We
are
also
requiring
that
you
keep
daily
records
of
the
total
fuel
use
by
each
affected
source,
subject
to
an
emission
limit
or
work
practice
standard,
along
with
a
description
of
the
fuel,
the
total
fuel
usage
amounts
and
units
of
measure,
and
information
on
the
supplier
and
original
source
of
the
fuel.
This
information
is
necessary
to
ensure
that
the
affected
source
is
complying
with
the
emission
limits
from
the
correct
subcategory.
We
are
requiring
additional
recordkeeping
if
you
choose
to
comply
with
the
chlorine,
mercury
or
total
selected
metals
fuel
input
option.
You
will
need
to
keep
records
of
the
calculations
and
supporting
information
used
to
develop
the
chlorine,
mercury,
or
total
selected
metals
fuel
input
operating
limit.
M.
How
Does
the
Proposed
Rule
Affect
Permits?

The
CAA
requires
that
sources
subject
to
the
proposed
rule
be
operated
pursuant
to
a
permit
issued
under
EPAapproved
State
operating
permit
program.
The
operating
permit
programs
are
developed
under
title
V
of
the
CAA
and
the
implementing
regulations
under
40
CFR
parts
70
and
71.
If
you
are
operating
in
the
first
3
years
of
your
operating
permit,
you
will
need
to
obtain
a
revised
permit
to
incorporate
the
proposed
rule.
If
you
are
in
the
last
2
years
of
your
operating
permit,
you
will
need
to
incorporate
the
proposed
rule
into
the
next
renewal
of
your
permit.

N.
What
Alternative
Provisions
Are
Being
Considered?

The
EPA
is
considering
a
bubbling
compliance
alternative
for
determining
compliance
with
the
non­
mercury
metallic
HAP,
HCl,
mercury,
and
PM
standards
for
existing
sources.
The
bubbling
compliance
alternative
would
allow
owners
and
operators
to
set
nonmercury
metals,
mercury,
HCl,
and
PM
emissions
limits
for
each
existing
boiler
or
process
heater
in
the
same
subcategory
such
that
if
these
limits
are
met,
the
total
emissions
from
all
existing
boilers
or
process
heaters
in
the
subcategory
are
less
than
or
equal
to
a
subcategory
specific
bubble
limit.
The
subcategory
specific
bubble
limit
would
be
the
proposed
emissions
limits
for
non­
mercury
metallic
HAP,
mercury,
HCl,
and
PM.
The
bubbling
compliance
alternative
would
not
be
applicable
to
new
sources
and
could
only
be
used
between
boilers
and
process
heaters
in
the
same
subcategory.
For
example,
bubbling
between
a
solid
fuel­
fired
boiler
greater
than
10
million
Btu/
hour
could
only
be
conducted
with
other
solid
fuel­
fired
boilers
or
process
heaters
with
heat
input
capacities
greater
than
10
million
Btu/
hour.
Also,
owners
or
owners
of
existing
sources
subject
to
the
Industrial
Boiler
New
Source
Performance
Standards
(
NSPS)
(
40
CFR
part
60,
subparts
Db
and
Dc)
would
be
required
to
continue
to
meet
the
PM
emission
standard
of
that
NSPS
regardless
of
whether
they
are
complying
with
the
bubbling
alternative
or
not
(
because
the
NSPS
is
a
separate
regulatory
requirement
which
remains
in
place).
Owners
or
operators
that
would
choose
to
comply
with
the
HAP
metals,
mercury,
HCl,
or
PM
standards
using
the
bubbling
compliance
alternative
would
be
required
to
submit
HAP
metals,
mercury,
HCl,
and/
or
PM
emissions
limits
to
the
Administrator
for
approval
for
each
existing
source
included
in
the
bubbling
compliance
alternative.
Before
emissions
limits
would
be
approved,
the
owner
or
operator
would
need
to
submit
documentation
demonstrating
that
if
the
emissions
limits
for
each
source
(
e.
g.,
each
boiler
or
heater)
are
met,
the
entire
group
of
sources
within
the
bubbling
compliance
alternative
would
be
in
compliance
with
the
subcategory­
wide
allowable
non­
mercury
metallic
HAP,
mercury,
HCl,
and
PM
emission
levels.
Once
approved
by
the
Administrator,
the
non­
mercury
metallic
HAP,
mercury,
HCl,
and
PM
emissions
levels
would
be
incorporated
into
the
operating
permit
for
the
source.
Thereafter,
the
owner
and
operator
of
the
facility
would
demonstrate
compliance
with
the
standards
by
demonstrating
that
each
boiler
or
process
heater
included
in
the
bubbling
compliance
alternative
emits
less
than
or
equal
to
the
approved
non­
mercury
metallic
HAP,
mercury,
HCl,
and
PM
emissions
limits
for
that
source.
The
EPA
is
considering
this
bubbling
compliance
alternative
as
part
of
the
EPA's
general
policy
of
encouraging
the
use
of
flexible
compliance
approaches
where
they
can
be
properly
monitored
and
enforced.
Emissions
averaging
can
provide
sources
the
flexibility
to
comply
in
the
least
costly
manner
while
still
maintaining
regulation
that
is
workable
and
enforceable.
However,
to
implement
this
alternative,
the
final
rule
will
need
to
define
the
affected
source
more
broadly
to
include
all
the
existing
boilers
and
process
heaters
for
each
subcategory
located
at
the
same
facility.
Therefore,
EPA
is
soliciting
comments
on
the
bubbling
compliance
alternative,
whether
EPA
should
specify
this
bubbling
compliance
alternative
in
the
final
rule,
and
whether
new
units
added
to
an
existing
affected
source
should
be
included
as
part
of,
and
applicable
to,
the
existing
source
bubble
limit.
Comments
should
include
information
on
the
potential
cost
savings
a
facility
could
expect
from
implementation
of
the
bubbling
compliance
provision,
along
with
supporting
documentation
for
this
estimated
cost
saving.

IV.
Impacts
of
the
Proposed
Rule
A.
What
Are
the
Air
Impacts?
Table
2
of
this
preamble
illustrates,
for
each
subcategory,
the
emissions
reductions
achieved
by
the
proposed
rule
(
i.
e.,
the
difference
in
emissions
between
a
boiler
or
process
heater
controlled
to
the
floor
level
of
control
and
boilers
or
process
heaters
at
the
current
baseline)
for
new
and
existing
sources.
Nationwide
emissions
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Proposed
Rules
selected
HAP
(
i.
e.,
HCl,
hydrogen
fluoride,
lead,
and
nickel)
will
be
reduced
by
58,500
tons
per
year
for
existing
units
and
73
tons
per
year
for
new
units.
Emissions
of
HCl
will
be
reduced
by
42,000
tons
per
year
for
existing
units
and
72
tons
per
year
for
new
units.
Emissions
of
mercury
will
be
reduced
by
1.9
tons
per
year
for
existing
units
and
0.006
tons
per
year
for
new
units.
Emissions
of
PM
will
be
reduced
by
565,000
tons
per
year
for
existing
units
and
480
tons
per
year
for
new
units.
Emissions
of
total
selected
nonmercury
metals
(
i.
e.,
arsenic,
beryllium,
cadmium,
chromium,
lead,
manganese,
nickel,
and
selenium)
will
be
reduced
by
1,100
tons
per
year
for
existing
units
and
will
be
reduced
by
1.4
tons
per
year
for
new
units.
In
addition,
emissions
of
sulfur
dioxide
are
established
to
be
reduced
by
113,000
tons
per
year
for
existing
sources
and
110
tons
per
year
for
new
sources.
A
discussion
of
the
methodology
used
to
estimate
emissions
and
emissions
reductions
is
presented
in
``
Estimation
of
Baseline
Emissions
and
Emissions
Reductions
for
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters''
in
the
docket.

TABLE
2.
 
SUMMARY
OF
EMISSIONS
REDUCTIONS
FOR
EXISTING
AND
NEW
SOURCES
[
Tons/
yr]

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

B.
What
Are
the
Water
and
Solid
Waste
Impacts?
The
EPA
estimated
the
additional
water
usage
that
would
result
from
the
MACT
floor
level
of
control
to
be
110
million
gallons
per
year
for
existing
sources
and
0.6
million
gallons
per
year
for
new
sources.
In
addition
to
the
increased
water
usage,
an
additional
3.7
million
gallons
per
year
of
wastewater
would
be
produced
for
existing
sources
and
0.6
million
gallons
per
year
for
new
sources.
The
costs
of
treating
the
additional
wastewater
are
$
18,000
for
existing
sources
and
$
2,300
for
new
sources.
These
costs
are
accounted
for
in
the
control
costs
estimates.
The
EPA
estimated
the
additional
solid
waste
that
would
result
from
the
MACT
floor
level
of
control
to
be
102,000
tons
per
year
for
existing
sources
and
1
ton
per
year
for
new
sources.
The
costs
of
handling
the
additional
solid
waste
generated
are
$
1.5
million
for
existing
sources
and
$
17,000
for
new
sources.
These
costs
are
also
accounted
for
in
the
control
costs
estimates.
A
discussion
of
the
methodology
used
to
estimate
impacts
is
presented
in
``
Estimation
of
Impacts
for
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
NESHAP''
in
the
Docket.

C.
What
Are
the
Energy
Impacts?

The
EPA
expects
an
increase
of
approximately
1,130
million
kilowatt
hours
(
kWh)
in
national
annual
energy
usage
as
a
result
of
the
proposed
rule.
Of
this
amount,
1,120
million
kWh
would
be
from
existing
sources
and
13
million
kWh
are
estimated
from
new
sources.
The
increase
results
from
the
electricity
required
to
operate
control
devices
installed
to
meet
the
proposed
rule,
such
as
wet
scrubbers
and
fabric
filters.

D.
What
Are
the
Control
Costs?

To
estimate
the
national
cost
impacts
of
the
proposed
rule
for
existing
sources,
EPA
developed
several
model
boilers
and
process
heaters
and
determined
the
cost
of
control
equipment
for
these
model
boilers.
The
EPA
assigned
a
model
boiler
or
heater
to
each
existing
unit
in
the
database
based
on
the
fuel,
size,
design,
and
current
controls.
The
analysis
considered
all
air
pollution
control
equipment
currently
in
operation
at
existing
boilers
and
process
heaters.
Model
costs
were
then
assigned
to
all
existing
units
that
could
not
otherwise
meet
the
proposed
emission
limits.
The
resulting
total
national
cost
impact
of
the
proposed
rule
is
1,790
million
dollars
in
capital
expenditures
and
860
million
dollars
per
year
in
total
annual
costs.
The
total
capital
and
annual
costs
include
costs
for
testing,
monitoring,
and
recordkeeping
and
reporting.
Table
3
of
this
preamble
shows
the
capital
and
annual
cost
impacts
for
each
subcategory.
Costs
include
testing
and
monitoring
costs,
but
not
recordkeeping
and
reporting
costs.

TABLE
3.
 
SUMMARY
OF
CAPITAL
AND
ANNUAL
COSTS
FOR
NEW
AND
EXISTING
SOURCES
Source
Subcategory
Estimated/
projected
number
of
affected
units
Annualized
cost
(
106
$/
yr)
Capital
costs
(
106
$)

Existing
Units
........................................................
Large
solid
units
...................................................
3,481
814
1,605
Small
solid
units
...................................................
327
0
0
Limited
use
solid
units
..........................................
249
23
105
Liquid
units
...........................................................
7,251
0
0
Gaseous
units
......................................................
46,892
0
0
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13,
2003
/
Proposed
Rules
TABLE
3.
 
SUMMARY
OF
CAPITAL
AND
ANNUAL
COSTS
FOR
NEW
AND
EXISTING
SOURCES
 
Continued
Source
Subcategory
Estimated/
projected
number
of
affected
units
Annualized
cost
(
106
$/
yr)
Capital
costs
(
106
$)

New
Units
.............................................................
Large
solid
units
...................................................
211
10
21
Small
solid
units
...................................................
25
3
3
Limited
use
solid
units
..........................................
11
1
1
Large
liquid
units
..................................................
90
1
3
Small
liquid
units
..................................................
164
0
0
Limited
use
liquid
units
.........................................
51
0.3
2
Gaseous
units
......................................................
3,463
11
51
Using
Department
of
Energy
projections
on
fuel
expenditures,
the
number
of
additional
boilers
that
could
be
potentially
constructed
was
estimated.
The
resulting
total
national
cost
impact
of
the
proposed
rule
in
the
5th
year
is
58
million
dollars
in
capital
expenditures
and
18.6
million
dollars
per
year
in
total
annual
costs.
Costs
are
mainly
for
testing
and
monitoring.
A
discussion
of
the
methodology
used
to
estimate
cost
impacts
is
presented
in
``
Methodology
and
Results
of
Estimating
the
Cost
of
Complying
with
the
Industrial,
Commercial,
and
Institutional
Boiler
and
Process
Heater
NESHAP''
in
the
Docket.

E.
Can
We
Achieve
the
Goals
of
the
Proposed
Rule
in
a
Less
Costly
Manner?
We
have
made
every
effort
in
developing
this
proposal
to
minimize
the
cost
to
the
regulated
community
and
allow
maximum
flexibility
in
compliance
options
consistent
with
our
statutory
obligations.
We
recognize,
however,
that
the
proposal
may
still
require
some
facilities
to
take
costly
steps
to
further
control
emissions
even
though
those
emissions
may
not
result
in
exposures
which
could
pose
an
excess
individual
lifetime
cancer
risk
greater
than
one
in
one
million
or
which
exceed
thresholds
determined
to
provide
an
ample
margin
of
safety
for
protecting
public
health
and
the
environment
from
the
effects
of
hazardous
air
pollutants.
We
are,
therefore,
specifically
soliciting
comment
on
whether
there
are
further
ways
to
structure
the
proposed
rule
to
focus
on
the
facilities
which
pose
significant
risks
and
avoid
the
imposition
of
high
costs
on
facilities
that
pose
little
risk
to
public
health
and
the
environment.
Representatives
of
the
plywood
and
composite
wood
products
industry
provided
EPA
with
descriptions
of
three
mechanisms
that
they
believed
could
be
used
to
implement
more
cost­
effective
reductions
in
risk.
The
docket
for
today's
proposed
rule
contains
white
papers
prepared
by
industry
that
outline
their
proposed
approaches.
These
approaches
could
be
effective
in
focusing
regulatory
controls
on
facilities
that
pose
significant
risks
and
avoiding
the
imposition
of
high
costs
on
facilities
that
pose
little
risk
to
public
health
or
the
environment,
and
we
are
seeking
public
comment
on
the
utility
of
each
of
these
approaches
with
respect
to
this
rule.
One
of
the
approaches,
an
applicability
cutoff
for
threshold
pollutants,
would
be
implemented
under
the
authority
of
CAA
section
112(
d)(
4);
the
second
approach,
subcategorization
and
delisting,
would
be
implemented
under
the
authority
of
CAA
sections
112(
c)(
1)
and
112(
c)(
9);
and,
the
third
approach,
would
involve
the
use
of
a
concentration­
based
applicability
threshold.
We
are
seeking
comment
on
whether
these
approaches
are
legally
justified
and,
if
so,
we
ask
for
information
that
could
be
used
to
support
such
approaches.
The
maximum
achievable
control
technology,
or
MACT,
program
outlined
in
CAA
section
112(
d)
is
intended
to
reduce
emissions
of
HAP
through
the
application
of
MACT
to
major
sources
of
toxic
air
pollutants.
Section
112(
c)(
9)
of
the
CAA
is
intended
to
allow
EPA
to
avoid
setting
MACT
standards
for
categories
or
subcategories
of
sources
that
pose
less
than
a
specified
level
of
risk
to
public
health
and
the
environment.
The
EPA
requests
comment
on
whether
the
proposals
described
here
appropriately
rely
on
these
provisions
of
CAA
section
112.
While
both
approaches
focus
on
assessing
the
inhalation
exposures
of
HAP
emitted
by
a
source,
EPA
specifically
requests
comment
on
the
appropriateness
and
necessity
of
extending
these
approaches
to
account
for
non­
inhalation
exposures
or
to
account
for
adverse
environmental
impacts.
In
addition
to
the
specific
requests
for
comment
noted
in
this
section,
we
are
also
interested
in
any
information
or
comment
concerning
technical
limitations,
environmental
and
cost
impacts,
compliance
assurance,
legal
rationale,
and
implementation
relevant
to
the
identified
approaches.
We
also
request
comment
on
appropriate
practicable
and
verifiable
methods
to
ensure
that
sources'
emissions
remain
below
levels
that
protect
public
health
and
the
environment.
We
will
evaluate
all
comments
before
determining
whether
either
of
the
three
approaches
will
be
included
in
the
final
rule.

1.
Industry
Emissions
and
Potential
Health
Effects
To
estimate
the
potential
baseline
risks
posed
by
the
Industrial
Boiler
and
Process
Heater
source
category,
EPA
performed
a
crude
risk
analysis
of
the
source
category
that
focused
only
on
cancer
risks.
The
results
of
the
analysis
are
based
on
approaches
for
estimating
cancer
incidence
that
carry
significant
assumptions,
uncertainties,
and
limitations.
Based
on
the
assessment,
if
the
proposed
rule
is
implemented
at
all
facilities
in
the
source
category,
cancer
incidence
in
the
U.
S.
may
be
reduced
by
as
many
as
tens
of
cases
per
year.
Due
to
the
uncertainties
associated
with
the
analysis,
this
analysis
should
be
regarded
as
one
perspective
on
the
estimate
of
annual
cancer
incidence
reduction;
the
true
risk
reductions
are
unknown.
(
Details
of
this
assessment
are
available
in
two
memoranda
in
the
docket:
Memorandum
on
``
Method
for
Approximate
(``
Top
Down'')
Estimates
of
Aggregate
Cancer
Risk
Associated
with
Two
Maximum
Achievable
Control
Technology
(
MACT)
Source
Categories:
Reciprocating
Internal
Combustion
Engines
(
RICE)
and
Industrial/
Commercial/
Institutional
Boilers''
and
Memorandum
on
``
Additional
Perspectives
on
(``
Top
Down'')
Estimates
of
Aggregate
Cancer
Risk
Associated
with
Industrial/
Commercial/
Institutional
Boilers''.)

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/
Proposed
Rules
2
See
63
FR
18754,
18765
 
66
(
April
15,
1998)
(
Pulp
and
Paper
Combustion
Sources
Proposal
NESHAP).
3
``
Methods
for
Derivation
of
Inhalation
Reference
Concentrations
and
Applications
of
Inhalation
Dosimetry.''
EPA
 
600/
8
 
90
 
066F,
Office
of
Research
and
Development,
USEPA,
October
1994.
4
``
Supplementary
Guidance
for
Conducting
Health
Risk
Assessment
of
Chemical
Mixtures.
Risk
Assessment
Forum
Technical
Panel,''
EPA/
630/
R
 
00/
002.
USEPA,
August
2000.
http://
www.
epa.
gov/
nceawww1/
pdfs/
chem
mix/
chem
mix
08
2001.
pdf.
2.
Applicability
Cutoffs
for
Threshold
Pollutants
Under
Section
112(
d)(
4)
of
the
CAA
The
first
approach
is
an
applicability
cutoff
for
threshold
pollutants
that
is
based
on
EPA's
authority
under
CAA
section
112(
d)(
4)
to
establish
standards
for
HAP
which
are
threshold
pollutants.
A
threshold
pollutant
is
one
for
which
there
is
a
concentration
or
dose
below
which
adverse
effects
are
not
expected
to
occur
over
a
lifetime
of
exposure.
For
such
pollutants,
CAA
section
112(
d)(
4)
allows
EPA
to
consider
the
threshold
level,
with
an
ample
margin
of
safety,
when
establishing
emission
standards.
Specifically,
CAA
section
112(
d)(
4)
allows
EPA
to
establish
emission
standards
that
are
not
based
upon
the
maximum
achievable
control
technology
specified
under
CAA
section
112(
d)(
2)
for
pollutants
for
which
a
health
threshold
has
been
established.
Such
standards
may
be
less
stringent
than
MACT.
Historically,
EPA
has
interpreted
CAA
section
112(
d)(
4)
to
allow
categories
of
sources
that
emit
only
threshold
pollutants
to
avoid
further
regulation
if
those
emissions
result
in
ambient
levels
that
do
not
exceed
the
threshold,
with
an
ample
margin
of
safety.
2
A
different
interpretation
would
allow
us
to
exempt
individual
facilities
within
a
source
category
that
meet
the
CAA
section
112(
d)(
4)
requirements.
There
are
three
potential
scenarios
under
this
interpretation
of
the
CAA
section
112(
d)(
4)
provision.
One
scenario
would
allow
an
exemption
for
individual
facilities
that
emit
only
threshold
pollutants
and
can
demonstrate
that
their
emissions
of
threshold
pollutants
would
not
result
in
air
concentrations
above
the
threshold
levels,
with
an
ample
margin
of
safety,
even
if
the
category
is
otherwise
subject
to
MACT.
A
second
scenario
would
allow
the
CAA
section
112(
d)(
4)
provision
to
be
applied
to
both
threshold
and
nonthreshold
pollutants,
using
the
one
in
a
million
cancer
risk
level
for
decision
making
for
nonthreshold
pollutants.
A
third
scenario
would
allow
a
CAA
section
112(
d)(
4)
exemption
at
a
facility
that
emits
both
threshold
and
nonthreshold
pollutants.
For
those
emission
points
where
only
threshold
pollutants
are
emitted
and
where
emissions
of
the
threshold
pollutants
would
not
result
in
air
concentrations
above
the
threshold
levels,
with
an
ample
margin
of
safety,
those
emission
points
could
be
exempt
from
the
MACT
standard.
The
MACT
standard
would
still
apply
to
nonthreshold
emissions
from
other
emission
points
at
the
source.
For
this
third
scenario,
emission
points
that
emit
a
combination
of
threshold
and
nonthreshold
pollutants
that
are
co­
controlled
by
MACT
would
still
be
subject
to
the
MACT
level
of
control.
However,
any
threshold
HAP
eligible
for
exemption
under
CAA
section
112(
d)(
4)
that
are
controlled
by
control
devices
different
from
those
controlling
non­
threshold
HAP
would
be
able
to
use
the
exemption,
and
the
facility
would
still
be
subject
to
the
parts
of
the
standard
that
control
nonthreshold
pollutants
or
that
control
both
threshold
and
nonthreshold
pollutants.
a.
Estimation
of
hazard
quotients
and
hazard
indices.
Under
the
CAA
section
112(
d)(
4)
approach,
EPA
would
have
to
determine
that
emissions
of
each
of
the
threshold
pollutants
emitted
by
industrial
boiler
and
process
heater
sources
at
the
facility
do
not
result
in
exposures
which
exceed
the
threshold
levels,
with
an
ample
margin
of
safety.
The
common
approach
for
evaluating
the
potential
hazard
of
a
threshold
air
pollutant
is
to
calculate
a
hazard
quotient
by
dividing
the
pollutant's
inhalation
exposure
concentration
(
often
assumed
to
be
equivalent
to
its
estimated
concentration
in
air
at
a
location
where
people
could
be
exposed)
by
the
pollutant's
inhalation
Reference
Concentration
(
RfC).
An
RfC
is
defined
as
an
estimate
(
with
uncertainty
spanning
perhaps
an
order
of
magnitude)
of
a
continuous
inhalation
exposure
that,
over
a
lifetime,
likely
would
not
result
in
the
occurrence
of
adverse
health
effects
in
humans,
including
sensitive
individuals.
The
EPA
typically
establishes
an
RfC
by
applying
uncertainty
factors
to
the
critical
toxic
effect
derived
from
the
lowest­
or
noobserved
adverse­
effect
level
of
a
pollutant.
3
A
hazard
quotient
less
than
one
means
that
the
exposure
concentration
of
the
pollutant
is
less
than
the
RfC,
and,
therefore,
presumed
to
be
without
appreciable
risk
of
adverse
health
effects.
A
hazard
quotient
greater
than
one
means
that
the
exposure
concentration
of
the
pollutant
is
greater
than
the
RfC.
Further,
EPA
guidance
for
assessing
exposures
to
mixtures
of
threshold
pollutants
recommends
calculating
a
hazard
index
(
HI)
by
summing
the
individual
hazard
quotients
for
those
pollutants
in
the
mixture
that
affect
the
same
target
organ
or
system
by
the
same
mechanism.
4
Hazard
index
values
would
be
interpreted
similarly
to
hazard
quotients;
values
below
one
would
generally
be
considered
to
be
without
appreciable
risk
of
adverse
health
effects,
and
values
above
one
would
generally
be
cause
for
concern.
For
the
determinations
discussed
herein,
EPA
would
generally
plan
to
use
RfC
values
contained
in
EPA's
toxicology
database,
the
Integrated
Risk
Information
System
(
IRIS).
When
a
pollutant
does
not
have
an
approved
RfC
in
IRIS,
or
when
a
pollutant
is
a
carcinogen,
EPA
would
have
to
determine
whether
a
threshold
exists
based
upon
the
availability
of
specific
data
on
the
pollutant's
mode
or
mechanism
of
action,
potentially
using
a
health
threshold
value
from
an
alternative
source,
such
as
the
Agency
for
Toxic
Substances
and
Disease
Registry
(
ATSDR)
or
the
California
Environmental
Protection
Agency
(
CalEPA).
Table
4
of
this
preamble
provides
RfC,
as
well
as
unit
risk
estimates,
for
the
HAP
emitted
by
facilities
in
the
industrial
boiler
and
process
heater
source
category.
A
unit
risk
estimate
is
defined
as
the
upperbound
excess
lifetime
cancer
risk
estimated
to
result
from
continuous
exposure
to
an
agent
at
a
concentration
of
1
microgram
per
cubic
meter
(
µ
g/
m3)
in
air.

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13,
2003
/
Proposed
Rules
TABLE
4.
 
DOSE­
RESPONSE
ASSESSMENT
VALUES
FOR
HAP
REPORTED
EMITTED
BY
THE
INDUSTRIAL
BOILER
AND
PROCESS
HEATER
SOURCE
CATEGORY
Chemical
name
CAS
No.
Reference
concentration
a
(
mg/
m3)
Unit
risk
estimate
b
(
1/(
µ
g/
m
3))

Acetaldehyde
.....................................................................................................
75
 
07
 
0
9.0E
 
IRIS
03
2.2E
 
06
IRIS
Acrolein
..............................................................................................................
107
 
02
 
8
2.0E
 
IRIS
05
Arsenic
compounds
...........................................................................................
7440
 
38
 
2
3.0E
 
CAL
05
4.3E
 
03
IRIS
Benzene
.............................................................................................................
71
 
43
 
2
6.0E
 
CAL
02
7.8E
 
06
IRIS
Beryllium
compounds
.........................................................................................
7440
 
41
 
7
2.0E
 
IRIS
05
2.4E
 
03
IRIS
Cadmium
compounds
........................................................................................
7440
 
43
 
9
2.0E
 
CAL
05
1.8E
 
03
IRIS
Chromium
(
VI)
compounds
................................................................................
18540
 
29
 
9
1.0E
 
IRIS
04
1.2E
 
02
IRIS
Dibenzofuran
......................................................................................................
132
 
64
 
9
Dibutylphthalate
.................................................................................................
84
 
74
 
2
p­
Dichlorobenzene
.............................................................................................
106
 
46
 
7
8.0E
 
IRIS
01
1.1E
 
05
CAL
Ethyl
benzene
....................................................................................................
100
 
41
 
4
1.0E+
0
IRIS
0
Formaldehyde
....................................................................................................
50
 
00
 
0
9.8E
 
ATSDR
03
1.3E
 
05
IRIS
Hydrochloric
acid
...............................................................................................
7647
 
01
 
0
2.0E
 
IRIS
02
Hydrogen
fluoride
...............................................................................................
7664
 
39
 
3
3.0E
 
P
 
CAL
02
Lead
compounds
...............................................................................................
7439
 
92
 
1
1.5E
 
EPA
03
ORD
1.2E
 
05
CAL
Manganese
compounds
.....................................................................................
7439
 
96
 
5
5.0E
 
IRIS
05
Mercury
compounds
..........................................................................................
HG_
CMPDS
9.0E
 
CAL
05
Methyl
chloroform
..............................................................................................
71
 
55
 
6
1.0E+
0
CAL
0
Methyl
ethyl
ketone
............................................................................................
78
 
93
 
3
1.0E+
0
IRIS
0
Methylene
chloride
.............................................................................................
75
 
09
 
2
1.0E+
0
ATSDR
0
4.7E
 
07
IRIS
Nickel
compounds
..............................................................................................
7440
 
02
 
0
2.0E
 
ATSDR
04
Nickel
subsulfide
................................................................................................
12035
 
72
 
2
4.8E
 
04
IRIS
PAHs
(
shown
below
as
7­
PAH)
Benzo
(
a)
anthracene
........................................................................................
56
 
55
 
3
1.1E
 
04
CAL
Benzo
(
b)
fluoranthene
......................................................................................
205
 
99
 
2
1.1E
 
04
CAL
Benzo
(
k)
fluoranthene
......................................................................................
207
 
08
 
9
1.1E
 
04
CAL
Benzo
(
a)
pyrene
...............................................................................................
50
 
32
 
8
1.1E
 
03
CAL
Chrysene
............................................................................................................
218
 
01
 
9
1.1E
 
05
CAL
Dibenz
(
a,
h)
anthracene
....................................................................................
53
 
70
 
3
1.2E
 
03
CAL
Indeno
(
1,2,3­
cd)
pyrene
...................................................................................
193
 
39
 
5
1.4E
 
04
CAL
Phosphorus
c
2,3,7,8­
Tetrachlorodibenzo­
p­
dioxin
..................................................................
1746
 
01
 
6
4.0E
 
CAL
08
3.3E+
01
EPA
ORD
Toluene
..............................................................................................................
108
 
88
 
3
4.0E
 
IRIS
01
m­
Xylene
c
..........................................................................................................
108
 
38
 
3
o­
Xylene
c
...........................................................................................................
95
 
47
 
6
Xylenes
(
mixed)
.................................................................................................
1330
 
20
 
7
4.3E
 
ATSDR
01
a
Reference
Concentration:
An
estimate
(
with
uncertainty
spanning
perhaps
an
order
of
magnitude)
of
a
continuous
inhalation
exposure
to
the
human
population
(
including
sensitive
subgroups
which
include
children,
asthmatics
and
the
elderly)
that
is
likely
to
be
without
an
appreciable
risk
of
deleterious
effects
during
a
lifetime.
It
can
be
derived
from
various
types
of
human
or
animal
data,
with
uncertainty
factors
generally
applied
to
reflect
limitations
of
the
data
used.
b
Unit
Risk
Estimate:
The
upper­
bound
excess
lifetime
cancer
risk
estimated
to
result
from
continuous
exposure
to
an
agent
at
a
concentration
of
1
µ
g/
m
3
in
air.
The
interpretation
of
the
Unit
Risk
Estimate
would
be
as
follows:
if
the
Unit
Risk
Estimate
=
1.5
×
10
 
6
per
µ
g/
m
3,
1.5
excess
tumors
are
expected
to
develop
per
1,000,000
people
if
exposed
daily
for
a
lifetime
to
1
µ
g
of
the
chemical
in
1
cubic
meter
of
air.
Unit
Risk
Estimates
are
considered
upper
bound
estimates,
meaning
they
represent
a
plausible
upper
limit
to
the
true
value.
(
Note
that
this
is
usually
not
a
true
statistical
confidence
limit.)
The
true
risk
is
likely
to
be
less,
but
could
be
greater.
c
No
dose­
response
assessment
is
available.
Sources:
IRIS
=
EPA
Integrated
Risk
Information
System
(
http://
www.
epa.
gov/
iris/
subst/
index.
html).
ATSDR
=
U.
S.
Agency
for
Toxic
Substances
and
Disease
Registry
(
http://
www.
atsdr.
cdc.
gov/
mrls.
html).
CAL
=
California
Office
of
Environmental
Health
Hazard
Assessment
(
http://
www.
oehha.
ca.
gov/
air/
hot_
spots/
index.
html).

To
establish
an
applicability
cutoff
under
CAA
section
112(
d)(
4),
EPA
would
need
to
define
ambient
air
exposure
concentration
limits
for
any
threshold
pollutants
involved.
There
are
several
factors
to
consider
when
establishing
such
concentrations.
First,
we
would
need
to
ensure
that
the
concentrations
that
would
be
established
would
protect
public
health
with
an
ample
margin
of
safety.
As
discussed
above,
the
approach
EPA
commonly
uses
when
evaluating
the
potential
hazard
of
a
threshold
air
pollutant
is
to
calculate
the
pollutant's
hazard
quotient,
which
is
the
exposure
concentration
divided
by
the
RfC.
EPA's
``
Supplementary
Guidance
for
Conducting
Health
Risk
Assessment
of
Chemical
Mixtures''
suggests
that
the
noncancer
health
effects
associated
with
a
mixture
of
pollutants
ideally
are
assessed
by
considering
the
pollutants'
common
mechanisms
of
toxicity.
The
guidance
also
suggests,
however,
that
when
exposures
to
mixtures
of
pollutants
are
being
evaluated,
the
risk
assessor
may
calculate
a
HI.
The
recommended
method
is
to
calculate
multiple
hazard
indices
for
each
exposure
route
of
interest,
and
for
a
single
specific
toxic
effect
or
toxicity
to
a
single
target
organ.
The
default
approach
recommended
by
the
guidance
is
to
sum
the
hazard
quotients
for
those
pollutants
that
induce
the
same
toxic
effect
or
affect
the
same
target
organ.
A
mixture
is
then
assessed
by
several
HI,
each
representing
one
toxic
effect
or
target
organ.
The
guidance
notes
that
the
pollutants
included
in
the
HI
calculation
are
any
pollutants
that
show
the
effect
being
assessed,
regardless
of
the
critical
effect
upon
which
the
RfC
is
based.
The
guidance
cautions
that
if
the
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/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
5
Senate
Debate
on
Conference
Report
(
October
27,
1990),
reprinted
in
``
A
Legislative
History
of
the
Clean
Air
Act
Amendments
of
1990,''
Comm.
Print
S.
Prt.
103
 
38
(
1993)
(``
Legis.
Hist.'')
at
868.
6
See
http://
www.
epa.
gov/
ttn/
atw/
nata.
7
See
http://
www.
atsdr.
cdc.
gov/
toxpro2.
html.
8
``
A
Tiered
Modeling
Approach
for
Assessing
the
Risks
due
to
Sources
of
Hazardous
Air
Pollutants.''
EPA
 
450/
4
 
92
 
001.
David
E.
Guinnup,
Office
of
Air
Quality
Planning
and
Standards,
USEPA,
March
1992.
target
organ
or
toxic
effect
for
which
the
HI
is
calculated
is
different
from
the
RfC's
critical
effect,
then
the
RfC
for
that
chemical
will
be
an
overestimate,
that
is,
the
resultant
HI
potentially
may
be
overprotective.
Conversely,
since
the
calculation
of
an
HI
does
not
account
for
the
fact
that
the
potency
of
a
mixture
of
HAP
can
be
more
potent
than
the
sum
of
the
individual
HAP
potencies,
an
HI
may
potentially
be
underprotective
in
some
situations.
b.
Options
for
establishing
a
hazard
index
limit.
One
consideration
in
establishing
a
hazard
index
limit
is
whether
the
analysis
considers
the
total
ambient
air
concentrations
of
all
the
emitted
HAP
to
which
the
public
is
exposed.
5
There
are
at
least
several
options
for
establishing
a
hazard
index
limit
for
the
CAA
section
112(
d)(
4)
analysis
that
reflect,
to
varying
degrees,
public
exposure.
One
option
is
to
allow
the
hazard
index
posed
by
all
threshold
HAP
emitted
from
sources
at
the
facility
to
be
no
greater
than
one.
This
approach
is
protective
if
no
additional
threshold
HAP
exposures
would
be
anticipated
from
other
sources
in
the
vicinity
of
the
facility
or
through
other
routes
of
exposure
(
e.
g.,
through
ingestion).
A
second
option
is
to
adopt
a
default
percentage
approach,
whereby
the
hazard
index
limit
of
the
HAP
emitted
by
the
facility
is
set
at
some
percentage
of
one
(
e.
g.,
20
percent
or
0.2).
This
approach
recognizes
the
fact
that
the
facility
in
question
is
only
one
of
many
sources
of
threshold
HAP
to
which
people
are
typically
exposed
every
day.
Because
noncancer
risk
assessment
is
predicated
on
total
exposure
or
dose,
and
because
risk
assessments
focus
only
on
an
individual
source,
establishing
a
hazard
index
limit
of
0.2
would
account
for
an
assumption
that
20
percent
of
an
individual's
total
exposure
is
from
that
individual
source.
For
the
purposes
of
this
discussion,
we
will
call
all
sources
of
HAP,
other
than
the
facility
in
question,
background
sources.
If
the
facility
is
allowed
to
emit
HAP
such
that
its
own
impacts
could
result
in
HI
values
of
one,
total
exposures
to
threshold
HAP
in
the
vicinity
of
the
facility
could
be
substantially
greater
than
one
due
to
background
sources,
and
this
would
not
be
protective
of
public
health,
since
only
HI
values
below
one
are
considered
to
be
without
appreciable
risk
of
adverse
health
effects.
Thus,
setting
the
hazard
index
limit
for
the
facility
at
some
default
percentage
of
one
will
provide
a
buffer
which
would
help
to
ensure
that
total
exposures
to
threshold
HAP
near
the
facility
(
i.
e.,
in
combination
with
exposures
due
to
background
sources)
will
generally
not
exceed
one,
and
can
generally
be
considered
to
be
without
appreciable
risk
of
adverse
health
effects.
The
EPA
requests
comment
on
using
the
default
percentage
approach
and
on
setting
the
default
hazard
index
limit
at
0.2.
The
EPA
is
also
requesting
comment
on
whether
an
alternative
HI
limit,
in
some
multiple
of
one
would
be
a
more
appropriate
applicability
cutoff.
A
third
option
is
to
use
available
data
(
from
scientific
literature
or
EPA
studies,
for
example)
to
determine
background
concentrations
of
HAP,
possibly
on
a
national
or
regional
basis.
These
data
would
be
used
to
estimate
the
exposures
to
HAP
from
nonindustrial
boiler
and
process
heater
sources
in
the
vicinity
of
an
individual
facility.
For
example,
the
EPA's
National­
scale
Air
Toxics
Assessment
(
NATA)
6
and
ATSDR's
Toxicological
Profiles
7
contain
information
about
background
concentrations
of
some
HAP
in
the
atmosphere
and
other
media.
The
combined
exposures
from
these
sources
and
from
other
sources
(
as
determined
from
the
literature
or
studies)
would
then
not
be
allowed
to
exceed
a
hazard
index
limit
of
one.
The
EPA
requests
comment
on
the
appropriateness
of
setting
the
hazard
index
limit
at
one
for
such
an
analysis.
A
fourth
option
is
to
allow
facilities
to
estimate
or
measure
their
own
facility­
specific
background
HAP
concentrations
for
use
in
their
analysis.
With
regard
to
the
third
and
fourth
options,
the
EPA
requests
comment
on
how
these
analyses
could
be
structured.
Specifically,
EPA
requests
comment
on
how
the
analyses
should
take
into
account
background
exposure
levels
from
air,
water,
food
and
soil
encountered
by
the
individuals
exposed
to
emissions
from
industrial
boilers
and
process
heaters.
In
addition,
we
request
comment
on
how
such
analyses
should
account
for
potential
increases
in
exposures
due
to
the
use
of
new
HAP
or
the
increased
use
of
a
previously
emitted
HAP,
or
the
effect
of
other
nearby
sources
that
release
HAP.
EPA
requests
comment
on
the
feasibility
and
scientific
validity
of
each
of
these
or
other
approaches.
Finally,
EPA
requests
comment
on
how
we
should
implement
the
CAA
section
112(
d)(
4)
applicability
cutoffs,
including
appropriate
mechanisms
for
applying
cutoffs
to
individual
facilities.
For
example,
would
the
title
V
permit
process
provide
an
appropriate
mechanism?
c.
Tiered
analytical
approach
for
predicting
exposure.
Establishing
that
a
facility
meets
the
cutoffs
established
under
CAA
section
112(
d)(
4)
will
necessarily
involve
combining
estimates
of
pollutant
emissions
with
air
dispersion
modeling
to
predict
exposures.
The
EPA
envisions
that
we
would
promote
a
tiered
analytical
approach
for
these
determinations.
A
tiered
analysis
involves
making
successive
refinements
in
modeling
methodologies
and
input
data
to
derive
successively
less
conservative,
more
realistic
estimates
of
pollutant
concentrations
in
air
and
estimates
of
risk.
As
a
first
tier
of
analysis,
EPA
could
develop
a
series
of
simple
look­
up
tables
based
on
the
results
of
air
dispersion
modeling
conducted
using
conservative
input
assumptions.
By
specifying
a
limited
number
of
input
parameters,
such
as
stack
height,
distance
to
property
line,
and
emission
rate,
a
facility
could
use
these
look­
up
tables
to
determine
easily
whether
the
emissions
from
their
sources
might
cause
a
hazard
index
limit
to
be
exceeded.
A
facility
that
does
not
pass
this
initial
conservative
screening
analysis
could
implement
increasingly
more
sitespecific
but
more
resource­
intensive
tiers
of
analysis
using
EPA­
approved
modeling
procedures,
in
an
attempt
to
demonstrate
that
exposure
to
emissions
from
the
facility
does
not
exceed
the
hazard
index
limit.
The
EPA's
guidance
could
provide
the
basis
for
conducting
such
a
tiered
analysis.
8
The
EPA
requests
comment
on
methods
for
constructing
and
implementing
a
tiered
analytical
approach
for
determining
applicability
of
the
CAA
section
112(
d)(
4)
criterion
to
specific
industrial
boiler
and
process
heater
sources.
It
is
also
possible
that
ambient
monitoring
data
could
be
used
to
supplement
or
supplant
the
tiered
modeling
approach
described
above.
It
is
envisioned
that
the
appropriate
monitoring
to
support
such
a
determination
could
be
extensive.
The
EPA
requests
comment
on
the
appropriate
use
of
monitoring
in
the
determinations
described
above.
d.
Accounting
for
dose­
response
relationships.
In
the
past,
EPA
routinely
treated
carcinogens
as
nonthreshold
pollutants.
The
EPA
recognizes
that
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/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
9
``
Draft
Revised
Guidelines
for
Carcinogen
Risk
Assessment.''
NCEA
 
F
 
0644.
USEPA,
Risk
Assessment
Forum,
July
1999.
pp
3
 
9ff.
http://
www.
epa.
gov/
ncea/
raf/
pdfs/
cancer_
gls.
pdf.
advances
in
risk
assessment
science
and
policy
may
affect
the
way
EPA
differentiates
between
threshold
and
nonthreshold
HAP.
The
EPA's
draft
Guidelines
for
Carcinogen
Risk
Assessment
9
suggest
that
carcinogens
be
assigned
non­
linear
dose­
response
relationships
where
data
warrant.
Moreover,
it
is
possible
that
doseresponse
curves
for
some
pollutants
may
reach
zero
risk
at
a
dose
greater
than
zero,
creating
a
threshold
for
carcinogenic
effects.
It
is
possible
that
future
evaluations
of
the
carcinogens
emitted
by
this
source
category
would
determine
that
one
or
more
of
the
carcinogens
in
the
category
is
a
threshold
carcinogen
or
is
a
carcinogen
that
exhibits
a
non­
linear
dose­
response
relationship
but
does
not
have
a
threshold.
The
dose­
response
assessments
for
formaldehyde
and
acetaldehyde
are
currently
undergoing
revision
by
the
EPA.
As
part
of
this
revision
effort,
EPA
is
evaluating
formaldehyde
and
acetaldehyde
as
potential
non­
linear
carcinogens.
The
revised
dose­
response
assessments
will
be
subject
to
review
by
the
EPA
Science
Advisory
Board,
followed
by
full
consensus
review,
before
adoption
into
the
EPA
Integrated
Risk
Information
System.
At
this
time,
EPA
estimates
that
the
consensus
review
will
be
completed
by
the
end
of
2003.
The
revision
of
the
dose­
response
assessments
could
affect
the
potency
factors
of
these
HAP,
as
well
as
their
status
as
threshold
or
nonthreshold
pollutants.
At
this
time,
the
outcome
is
not
known.
In
addition
to
the
current
reassessment
by
EPA,
there
have
been
several
reassessments
of
the
toxicity
and
carcinogenicity
of
formaldehyde
in
recent
years,
including
work
by
the
World
Health
Organization
and
the
Canadian
Ministry
of
Health.
The
EPA
requests
comment
on
how
we
should
consider
the
state
of
the
science
as
it
relates
to
the
treatment
of
threshold
pollutants
when
making
determinations
under
CAA
section
112(
d)(
4).
In
addition,
EPA
requests
comment
on
whether
there
is
a
level
of
emissions
of
a
nonthreshold
carcinogenic
HAP
(
e.
g.,
benzene,
methylene
chloride)
at
which
it
would
be
appropriate
to
allow
a
facility
to
use
the
approaches
discussed
in
this
section.
If
the
CAA
section
112(
d)(
4)
approach
were
adopted,
the
proposed
rulemaking
would
likely
indicate
that
the
requirements
of
the
rule
do
not
apply
to
any
source
that
demonstrates,
based
on
a
tiered
approach
that
includes
EPAapproved
modeling
of
the
affected
source's
emissions,
that
the
anticipated
HAP
exposures
do
not
exceed
the
specified
hazard
index
limit.

3.
Applicability
Cutoffs
From
Hydrogen
Chloride
Controls
Under
CAA
Section
112(
d)(
4)
of
the
CAA
This
approach
is
an
applicability
cutoff
for
the
threshold
pollutant
hydrogen
chloride
that
is
based
on
EPA's
authority
under
CAA
section
112(
d)(
4).
Industry's
suggested
approach
interprets
this
provision
to
allow
EPA
to
exempt,
from
the
hydrogen
chloride
controls,
individual
facilities
that
can
demonstrate
that
their
emissions
of
hydrogen
chloride
will
not
result
in
air
concentrations
above
the
inhalation
reference
concentration
for
hydrogen
chloride,
even
if
the
category
is
otherwise
subject
to
MACT.
If
this
approach
were
adopted,
the
proposed
rulemaking
would
likely
indicate
that
the
requirements
of
the
rule
pertaining
to
hydrochloric
acid
do
not
apply
to
any
source
that
demonstrates,
based
on
EPA­
approved
modeling
of
the
affected
source's
emissions,
that
the
anticipated
hydrochloric
acid
exposures
do
not
exceed
the
inhalation
reference
concentration
for
hydrochloric
acid.

4.
Subcategory
Delisting
Under
Section
112(
c)(
9)(
B)
of
the
CAA
The
EPA
is
authorized
to
establish
categories
and
subcategories
of
sources,
as
appropriate,
pursuant
to
CAA
section
112(
c)(
1),
in
order
to
facilitate
the
development
of
MACT
standards
consistent
with
section
112
of
the
CAA.
Further,
CAA
section
112(
c)(
9)(
B)
allows
EPA
to
delete
a
category
(
or
subcategory)
from
the
list
of
major
sources
for
which
MACT
standards
are
to
be
developed
when
the
following
can
be
demonstrated:
(
1)
In
the
case
of
carcinogenic
pollutants,
that
``
no
source
in
the
category
*
*
*
emits
(
carcinogenic)
air
pollutants
in
quantities
which
may
cause
a
lifetime
risk
of
cancer
greater
than
one
in
one
million
to
the
individual
in
the
population
who
is
most
exposed
to
emissions
of
such
pollutants
from
the
source'';
(
2)
in
the
case
of
pollutants
that
cause
adverse
noncancer
health
effects,
that
``
emissions
from
no
source
in
the
category
or
subcategory
*
*
*
exceed
a
level
which
is
adequate
to
protect
public
health
with
an
ample
margin
of
safety'';
and
(
3)
in
the
case
of
pollutants
that
cause
adverse
environmental
effects,
that
``
no
adverse
environmental
effect
will
result
from
emissions
from
any
source.''
Given
these
authorities
and
the
suggestions
from
the
white
paper
prepared
by
industry
representatives
(
see
docket
number
OAR
 
2002
 
0058),
EPA
is
considering
whether
it
would
be
possible
to
establish
a
subcategory
of
facilities
within
the
larger
industrial
boiler
and
process
heater
source
category
that
would
meet
the
risk­
based
criteria
for
delisting.
Such
criteria
would
likely
include
the
same
requirements
as
described
previously
for
the
second
scenario
under
the
CAA
section
112(
d)(
4)
approach,
whereby
a
facility
would
be
in
the
low­
risk
subcategory
if
its
emissions
of
threshold
pollutants
do
not
result
in
exposures
which
exceed
the
HI
limits
and
if
its
emissions
of
nonthreshold
pollutants
do
not
result
in
exposures
which
exceed
a
cancer
risk
level
of
10
¥
6.
The
EPA
requests
comment
on
what
an
appropriate
HI
limit
would
be
for
a
determination
that
a
facility
be
included
in
the
low­
risk
subcategory.
Since
each
facility
in
such
a
subcategory
would
be
a
low­
risk
facility
(
i.
e.,
if
each
met
these
criteria),
the
subcategory
could
be
delisted
in
accordance
with
CAA
section
112(
c)(
9),
thereby
limiting
the
costs
and
impacts
of
the
proposed
rule
to
only
those
facilities
that
do
not
qualify
for
subcategorization
and
delisting.
Facilities
seeking
to
be
included
in
the
delisted
subcategory
would
be
responsible
for
providing
all
data
required
to
determine
whether
they
are
eligible
for
inclusion.
Facilities
that
could
not
demonstrate
that
they
are
eligible
to
be
included
in
the
low­
risk
subcategory
would
be
subject
to
MACT
and
possible
future
residual
risk
standards.
The
EPA
solicits
comment
on
implementing
a
risk­
based
approach
for
establishing
subcategories
of
industrial
boiler
and
process
heater
facilities.
Establishing
that
a
facility
qualifies
for
the
low­
risk
subcategory
under
CAA
section
112(
c)(
9)
will
necessarily
involve
combining
estimates
of
pollutant
emissions
with
air
dispersion
modeling
to
predict
exposures.
The
EPA
envisions
that
we
would
employ
the
same
tiered
analytical
approach
described
earlier
in
the
CAA
section
112(
d)(
4)
discussion
for
these
determinations.
One
concern
that
EPA
has
with
respect
to
this
CAA
section
112(
c)(
9)
approach
is
the
effect
that
it
could
have
on
the
MACT
floors.
If
many
of
the
facilities
in
the
low­
risk
subcategory
are
well­
controlled,
that
could
make
the
MACT
floor
less
stringent
for
the
remaining
facilities.
One
approach
that
has
been
suggested
to
mitigate
this
effect
would
be
to
establish
the
MACT
floor
now
based
on
controls
in
place
for
the
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Proposed
Rules
entire
category
and
to
allow
facilities
to
become
part
of
the
low­
risk
subcategory
in
the
future,
after
the
MACT
based
standards
are
established.
This
would
allow
low
risk
facilities
to
use
the
CAA
section
112(
c)(
9)
exemption
without
affecting
the
MACT
floor
calculation.
The
EPA
requests
comment
on
this
suggested
approach.
Another
approach
under
CAA
section
112(
c)(
9)
would
be
to
define
a
subcategory
of
facilities
within
the
industrial
boiler
and
process
heater
source
category
based
upon
technological
differences,
such
as
differences
in
production
rate,
emission
vent
flow­
rates,
overall
facility
size,
emissions
characteristics,
processes,
or
air
pollution
control
device
viability.
The
EPA
requests
comment
on
how
we
might
establish
industrial
boiler
and
process
heater
subcategories
based
on
these,
or
other,
source
characteristics.
If
it
could
then
be
determined
that
each
source
in
this
technologically­
defined
subcategory
presents
a
low
risk
to
the
surrounding
community,
the
subcategory
could
then
be
delisted
in
accordance
with
CAA
section
112(
c)(
9).
The
EPA
requests
comment
on
the
concept
of
identifying
technologicallybased
subcategories
that
may
include
only
low­
risk
facilities
within
this
source
category.
If
this
CAA
section
112(
c)(
9)
approach
were
adopted,
the
rulemaking
would
likely
indicate
that
the
rule
does
not
apply
to
any
source
that
demonstrates
that
it
belongs
in
a
subcategory
which
has
been
delisted
under
CAA
section
112(
c)(
9).

F.
What
Are
the
Economic
Impacts?

The
economic
impact
analysis
shows
that
the
expected
price
increase
for
output
in
the
40
affected
industries
would
be
no
more
than
0.04
percent
as
a
result
of
the
proposed
rule
for
industrial
boilers
and
process
heaters.
The
expected
change
in
production
of
affected
output
is
a
reduction
of
only
0.03
percent
or
less
in
the
same
industries.
In
addition,
impacts
to
affected
energy
markets
show
that
prices
of
petroleum,
natural
gas,
electricity
and
coal
should
increase
by
no
more
than
0.05
percent
as
a
result
of
implementation
of
the
proposed
rule,
and
output
of
these
types
of
energy
should
decrease
by
no
more
than
0.01
percent.
Therefore,
it
is
likely
that
there
is
no
adverse
impact
expected
to
occur
for
those
industries
that
produce
output
affected
by
the
proposed
rule,
such
as
lumber
and
wood
products,
chemical
manufacturers,
petroleum
refining,
and
furniture
manufacturing.
G.
What
Are
the
Social
Costs
and
Benefits
of
the
Proposed
Rule?

Our
assessment
of
costs
and
benefits
of
the
proposed
rule
is
detailed
in
the
``
Regulatory
Impact
Analysis
for
the
Proposed
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
MACT.''
The
Regulatory
Impact
Analysis
(
RIA)
is
located
in
the
Docket.
It
is
estimated
that
3
years
after
implementation
of
the
proposed
requirements,
HAP
would
be
reduced
by
58,500
tons/
yr
(
53,200
megagrams
per
year
(
Mg/
yr))
due
to
reductions
in
hydrochloric
acid,
arsenic,
mercury,
hydrofluoric
acid,
and
several
other
HAP
from
existing
affected
emission
sources.
Of
these
reductions,
42,000
tons/
yr
(
38,200
Mg/
yr)
are
of
hydrochloric
acid.
In
addition
to
these
reductions,
there
are
73
tons/
yr
(
66
Mg/
yr)
of
HAP
reductions
expected
from
new
sources.
Of
these
reductions,
virtually
all
of
them
are
of
hydrochloric
acid.
The
health
effects
associated
with
these
HAP
are
discussed
earlier
in
this
preamble.
While
it
is
beneficial
to
society
to
reduce
these
HAP,
we
are
unable
to
quantify
and
provide
a
monetized
estimate
of
the
benefits
at
this
time.
Despite
our
inability
to
quantify
and
provide
monetized
benefit
estimates
from
HAP
reductions,
it
is
possible
to
derive
rough
estimates
for
one
of
the
more
important
benefit
categories,
i.
e.,
the
potential
number
of
cancer
cases
avoided
and
cancer
risk
reduced
as
a
result
of
the
imposition
of
the
MACT
level
of
control
on
this
source
category.
Our
analysis
suggests
that
imposition
of
the
MACT
level
of
control
would
reduce
cancer
cases
by
possibly
tens
of
cases
per
year,
on
average,
starting
some
years
after
implementation
of
the
standard.
This
risk
reduction
estimate
is
uncertain
and
should
be
regarded
as
an
extremely
rough
estimate,
and
should
be
viewed
in
the
context
of
the
full
spectrum
of
unquantified
noncancer
effects
associated
with
the
HAP
reductions.
Noncancer
effects
associated
with
the
HAP
are
presented
earlier
in
this
preamble.
The
control
technologies
used
to
reduce
the
level
of
HAP
emitted
from
affected
sources
are
also
expected
to
reduce
emissions
of
PM
(
PM10,
PM2.5),
and
sulfur
dioxide
(
SO2).
It
is
estimated
that
PM10
emissions
reductions
total
approximately
562,000
tons/
yr
(
510,000
Mg/
yr),
PM2.5
emissions
reductions
total
approximately
159,000
tons/
yr
(
145,000
Mg/
yr),
and
SO2
emissions
reductions
total
approximately
102,670
Mg/
yr
(
113,000
tons/
yr).
These
estimated
reductions
occur
from
existing
sources
in
operation
3
years
after
the
implementation
of
the
requirements
of
the
proposed
rule
and
are
expected
to
continue
throughout
the
life
of
the
sources.
Human
health
effects
associated
with
exposure
to
PM10
and
PM2.5
include
premature
mortality
(
short­
term
exposure
to
PM10
and
long­
term
exposure
to
PM2.5),
chronic
bronchitis,
additional
hospital
admissions
from
respiratory
and
cardiovascular
causes,
acute
respiratory
symptoms,
and
other
effects.
Welfare
effects
associated
with
PM10
and
PM2.5
emissions
include
impaired
recreational
and
residential
visibility,
household
soiling,
and
materials
damage.
As
SO2
emissions
transform
into
PM,
they
can
lead
to
the
same
health
and
welfare
effects
listed
above.
For
PM10
and
PM2.5,
we
did
provide
a
monetary
estimate
for
the
benefits
associated
with
the
reduction
of
the
emissions,
and
we
have
conducted
several
analyses
recently
that
estimate
the
monetized
benefits
of
PM
reductions,
including:
the
RIA
of
the
PM/
Ozone
national
ambient
air
quality
standards
(
NAAQS)
(
1997),
the
Nitrogen
Oxide
(
NOX)
State
Implementation
Plan
(
SIP)
Call
(
1998),
the
CAA
section
126
RIA
(
1999),
a
study
conducted
for
section
812(
b)
of
the
CAA
(
1999),
the
Tier
2/
Gasoline
Sulfur
Standards
(
1999),
and
the
Heavy
Duty
Engine/
Diesel
Fuel
Standards
(
2000).
On
September
26,
2002,
the
National
Academy
of
Sciences
(
NAS)
released
a
report
on
its
review
of
the
Agency's
methodology
for
analyzing
the
health
benefits
of
measures
taken
to
reduce
air
pollution.
The
report
focused
on
EPA's
approach
for
estimating
the
health
benefits
of
regulations
designed
to
reduce
concentrations
of
airborne
particulate
matter
(
PM).
In
its
report,
the
NAS
said
that
EPA
has
generally
used
a
reasonable
framework
for
analyzing
the
health
benefits
of
PM­
control
measures.
It
recommended,
however,
that
the
Agency
take
a
number
of
steps
to
improve
its
benefits
analysis.
In
particular,
the
NAS
stated
that
the
Agency
should:
 
Include
benefits
estimates
for
a
range
of
regulatory
options;
 
Estimate
benefits
for
intervals,
such
as
every
5
years,
rather
than
a
single
year;
 
Clearly
state
the
projected
baseline
statistics
used
in
estimating
health
benefits,
including
those
for
air
emissions,
air
quality,
and
health
outcomes;
 
Examine
whether
implementation
of
proposed
regulations
might
cause
unintended
impacts
on
human
health
or
the
environment;

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Proposed
Rules
 
When
appropriate,
use
data
from
non­
U.
S.
studies
to
broaden
age
ranges
to
which
current
estimates
apply
and
to
include
more
types
of
relevant
health
outcomes;
and
 
Begin
to
move
the
assessment
of
uncertainties
from
its
ancillary
analyses
into
its
primary
analyses
by
conducting
probabilistic,
multiplesource
uncertainty
analyses.
This
assessment
should
be
based
on
available
data
and
expert
judgment.
Although
the
NAS
made
a
number
of
recommendations
for
improvement
in
EPA's
approach,
it
found
that
the
studies
selected
by
EPA
for
use
in
its
benefits
analysis
were
generally
reasonable
choices.
In
particular,
the
NAS
agreed
with
EPA's
decision
to
use
cohort
studies
to
derive
benefits
estimates.
It
also
concluded
that
the
Agency's
selection
of
the
American
Cancer
Society
(
ACS)
study
for
the
evaluation
of
PM­
related
premature
mortality
was
reasonable,
although
it
noted
the
publication
of
new
cohort
studies
that
should
be
evaluated
by
the
Agency.
Several
of
the
NAS
recommendations
addressed
the
issue
of
uncertainty
and
how
the
Agency
can
better
analyze
and
communicate
the
uncertainties
associated
with
its
benefits
assessments.
In
particular,
the
Committee
expressed
concern
about
the
Agency's
reliance
on
a
single
value
from
its
analysis
and
suggested
that
EPA
develop
a
probabilistic
approach
for
analyzing
the
health
benefits
of
proposed
regulatory
actions.
The
Agency
agrees
with
this
suggestion
and
is
working
to
develop
such
an
approach
for
use
in
future
rulemakings.
In
this
benefits
analysis
for
the
proposed
rule,
the
Agency
has
used
an
interim
approach
that
shows
the
impact
of
several
important
alternative
assumptions
about
the
estimation
and
valuation
of
reductions
in
premature
mortality
and
chronic
bronchitis.
This
approach,
which
was
developed
in
the
context
of
the
Agency's
Clear
Skies
analysis,
provides
an
alternative
estimate
of
health
benefits
using
the
time
series
studies
in
place
of
cohort
studies,
as
well
as
alternative
valuation
methods
for
mortality
and
chronic
bronchitis
risk
reductions.
For
the
proposed
rule,
we
conducted
an
air
quality
assessment
to
determine
the
change
in
ambient
concentrations
of
PM10
and
PM2.5
that
result
from
reductions
of
PM
and
SO2
at
existing
affected
facilities.
Our
air
quality
analysis
was
conducted
using
the
source­
receptor
(
S
 
R)
matrix
model,
a
model
that
provides
changes
in
PM10
and
PM2.5
concentrations
based
on
changes
in
PM
and/
or
PM
precursor
emissions.
Unfortunately,
our
data
is
not
able
to
define
the
exact
location
of
the
reductions
for
every
affected
boiler
and
process
heater.
The
air
quality
analysis
was
conducted
for
emissions
reductions
from
those
emissions
sources
that
have
a
known
link
to
a
specific
control
device,
which
represents
approximately
50
percent
of
the
total
emissions
reductions
mentioned
above.
Using
this
subset
of
information,
we
utilized
the
S
 
R
matrix
to
determined
the
air
quality
change
nationwide.
The
results
of
the
air
quality
assessment
served
as
input
to
a
model
that
estimates
the
total
monetary
value
of
benefits
of
the
health
effects
listed
above.
Total
benefits
associated
with
this
portion
of
the
analysis
are
$
8.2
billion
in
the
year
2005
(
presented
in
1999
dollars).
For
those
emissions
reductions
from
affected
sources
that
do
not
have
a
known
link
to
a
specific
control
device,
the
results
of
the
air
quality
analysis
serve
as
a
reasonable
approximation
of
air
quality
changes
to
transfer
to
the
remaining
emissions
reductions
of
the
proposed
rule.
Because
there
is
not
a
reasonable
way
to
apportion
the
total
benefits
of
the
combined
impact
of
the
PM
and
SO2
reductions
from
the
air
quality
and
benefit
analyses
completed
above,
we
performed
two
additional
S
 
R
matrix
analyses.
One
analysis
was
performed
to
evaluate
the
impact
on
air
quality
of
the
PM
reductions
alone
(
holding
SO2
unchanged),
and
one
to
evaluate
the
impact
on
air
quality
from
the
SO2
reductions
alone
(
holding
PM
unchanged).
With
independent
PM
and
SO2
air
quality
assessments,
we
can
determine
the
total
benefit
associated
with
each
component
of
total
pollutant
reductions.
The
total
benefit
associated
with
the
PM
and
SO2
reductions
with
unspecified
location
are
$
7.9
billion.
Every
benefit­
cost
analysis
examining
the
potential
effects
of
a
change
in
environmental
protection
requirements
is
limited
to
some
extent
by
data
gaps,
limitations
in
model
capabilities
(
such
as
geographic
coverage),
and
uncertainties
in
the
underlying
scientific
and
economic
studies
used
to
configure
the
benefit
and
cost
models.
Deficiencies
in
the
scientific
literature
often
result
in
the
inability
to
estimate
changes
in
health
and
environmental
effects,
such
as
potential
increases
in
premature
mortality
associated
with
increased
exposure
to
carbon
monoxide.
Deficiencies
in
the
economics
literature
often
result
in
the
inability
to
assign
economic
values
even
to
those
health
and
environmental
outcomes
which
can
be
quantified.
While
these
general
uncertainties
in
the
underlying
scientific
and
economics
literatures
are
discussed
in
detail
in
the
RIA
and
its
supporting
documents
and
references,
the
key
uncertainties
which
have
a
bearing
on
the
results
of
the
benefit­
cost
analysis
of
today's
action
are
the
following:
1.
The
exclusion
of
potentially
significant
benefit
categories
(
e.
g.,
health
and
ecological
benefits
of
reduction
in
hazardous
air
pollutants
emissions);
2.
Errors
in
measurement
and
projection
for
variables
such
as
population
growth;
3.
Uncertainties
in
the
estimation
of
future
year
emissions
inventories
and
air
quality;
4.
Uncertainties
associated
with
the
extrapolation
of
air
quality
monitoring
data
to
some
unmonitored
areas
required
to
better
capture
the
effects
of
the
standards
on
the
affected
population;
5.
Variability
in
the
estimated
relationships
of
health
and
welfare
effects
to
changes
in
pollutant
concentrations;
and
6.
Uncertainties
associated
with
the
benefit
transfer
approach.
Despite
these
uncertainties,
we
believe
the
benefit­
cost
analysis
provides
a
reasonable
indication
of
the
expected
economic
benefits
of
the
industrial
boilers
and
process
heaters
MACT
under
two
different
sets
of
assumptions.
We
have
used
two
approaches
(
base
and
alternative
estimates)
to
provide
benefits
in
health
effects
and
in
monetary
terms.
They
differ
in
the
method
used
to
estimate
and
value
reduced
incidences
of
mortality
and
chronic
bronchitis,
which
is
explained
in
detail
in
the
RIA.
While
there
is
a
substantial
difference
in
the
specific
estimates,
both
approaches
show
that
the
industrial
boilers
and
process
heaters
MACT
may
provide
benefits
to
public
health,
whether
expressed
as
health
improvements
or
as
economic
benefits.
These
include
prolonging
lives,
reducing
cases
of
chronic
bronchitis
and
hospital
admissions,
and
reducing
thousands
of
cases
in
other
indicators
of
adverse
health
effects,
such
as
work
loss
days,
restricted
activity
days,
and
days
with
asthma
attacks.
In
addition,
there
are
a
number
of
health
and
environmental
effects
which
we
were
unable
to
quantify
or
monetize.
These
effects,
denoted
by
``
B''
are
additive
to
the
both
the
base
and
alternative
estimates
of
benefits.
Results
also
reflect
the
use
of
two
different
discount
rates
for
the
valuation
of
reduced
incidences
of
mortality;
a
3
percent
rate
which
is
recommended
by
EPA's
Guidelines
for
Preparing
Economic
Analyses
(
U.
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EPA,
2000a),
and
7
percent
which
is
recommended
by
OMB
Circular
A
 
94
(
OMB,
1992).
More
specifically,
the
base
estimate
of
benefits
reflects
the
use
of
peerreviewed
methodologies
developed
for
earlier
risk
and
benefit­
cost
assessments
related
to
the
Clean
Air
Act,
such
as
the
regulatory
assessments
of
the
Heavy
Duty
Diesel
and
Tier
II
rules
and
the
section
812
Report
to
Congress.
The
alternative
estimate
explores
important
aspects
of
the
key
elements
underlying
estimates
of
the
benefits
of
reducing
PM
and
SO2
emissions,
specifically
focusing
on
estimation
and
valuation
of
mortality
risk
reduction
and
valuation
of
chronic
bronchitis.
The
alternative
estimate
of
mortality
reduction
relies
on
recent
scientific
studies
finding
an
association
between
increased
mortality
and
shortterm
exposure
to
particulate
matter
over
days
to
weeks,
while
the
base
estimate
relies
on
a
recent
reanalysis
of
earlier
studies
that
associate
long­
term
exposure
to
fine
particles
with
increased
mortality.
The
alternative
estimate
differs
in
the
following
ways:
it
explicitly
omits
any
impact
of
long­
term
exposure
on
premature
mortality,
it
uses
different
data
on
valuation
and
makes
adjustments
relating
to
the
health
status
and
potential
longevity
of
the
populations
most
likely
affected
by
PM,
it
also
uses
a
cost­
of­
illness
method
to
value
reductions
in
cases
of
chronic
bronchitis
while
the
base
estimate
is
based
on
individual's
willingness
to
pay
(
WTP)
to
avoid
a
case
of
chronic
bronchitis.
In
addition,
one
key
area
of
uncertainty
is
the
value
of
a
statistical
life
(
VSL)
for
risk
reductions
in
mortality,
which
is
also
the
category
of
benefits
that
accounts
for
a
large
portion
of
the
total
benefit
estimate.
The
adoption
of
a
value
for
the
projected
reduction
in
the
risk
of
premature
mortality
is
the
subject
of
continuing
discussion
within
the
economic
and
public
policy
analysis
community.
There
is
general
agreement
that
the
value
to
an
individual
of
a
reduction
in
mortality
risk
can
vary
based
on
several
factors,
including
the
age
of
the
individual,
the
type
of
risk,
the
level
of
control
the
individual
has
over
the
risk,
the
individual's
attitude
toward
risk,
and
the
health
status
of
the
individual.
The
Environmental
Economics
Advisory
Committee
(
EEAC)
of
the
EPA
Science
Advisory
Board
(
SAB)
recently
issued
an
advisory
report
which
states
that
``
the
theoretically
appropriate
method
is
to
calculate
willingness
to
pay
for
individuals
whose
ages
correspond
to
those
of
the
affected
population,
and
that
it
is
preferable
to
base
these
calculations
on
empirical
estimates
of
WTP
by
age.''
(
EPA
 
SAB
 
EEAC
 
00
 
013).
In
developing
our
base
estimate
of
the
benefits
of
premature
mortality
reductions,
we
have
appropriately
discounted
over
the
lag
period
between
exposure
and
premature
mortality.
However,
the
empirical
basis
for
adjusting
the
current
$
6
million
VSL
for
other
factors
does
not
yet
justify
including
these
in
our
base
estimate.
A
discussion
of
these
factors
is
contained
in
the
RIA
and
supporting
documents.
The
EPA
recognizes
the
need
for
additional
research
by
the
scientific
community
to
develop
additional
empirical
support
for
adjustments
to
VSL
for
the
factors
mentioned
above.
Furthermore,
EPA
prefers
not
to
draw
distinctions
in
the
monetary
value
assigned
to
the
lives
saved
even
if
they
differ
in
age,
health
status,
socioeconomic
status,
gender
or
other
characteristic
of
the
adult
population.
Given
the
advice
from
the
SAB,
we
employed
the
suggested
approach
for
the
benefit
analysis
of
the
Heavy
Duty
Engine/
Diesel
Fuel
standards
conducted
in
2000
to
the
Industrial,
Commercial,
and
Institutional
Boiler
and
Process
Heater
MACT
discussed
in
this
preamble.
A
full
discussion
of
considerations
made
in
our
presentation
of
benefits
is
summarized
in
the
preamble
of
the
Final
Heavy
Duty
Diesel
Program
issued
in
December
2000,
and
in
all
supporting
documentation
and
analyses
of
the
Heavy
Duty
Diesel
Program,
and
in
the
RIA
for
the
proposed
rulemaking.
In
addition
to
the
presentation
of
mortality
valuation,
our
estimate
also
includes
a
``
B''
to
represent
those
additional
health
and
environmental
benefits
which
could
not
be
expressed
in
quantitative
incidence
and/
or
economic
value
terms.
A
full
listing
of
the
benefit
categories
that
could
not
be
quantified
or
monetized
in
our
estimate
are
provided
in
the
RIA
for
the
proposed
rule.
A
full
appreciation
of
the
overall
economic
consequences
of
the
proposed
industrial
boiler
and
process
heater
standards
requires
consideration
of
all
benefits
and
costs
expected
to
result
from
today's
proposed
rule,
not
just
those
benefits
and
costs
which
could
be
expressed
here
in
dollar
terms.
A
full
listing
of
the
benefit
categories
that
could
not
be
quantified
or
monetized
in
our
estimate
are
provided
in
Table
5
of
this
preamble.

TABLE
5.
 
UNQUANTIFIED
BENEFIT
CATEGORIES
Unquantified
benefit
categories
associated
with
HAP
Unquantified
benefit
categories
associated
with
PM
Health
Categories
..............................................
Airway
responsiveness
Pulmonary
inflammation
Increased
susceptibility
to
respiratory
infection
Acute
inflammation
and
respiratory
cell
damage
Chronic
respiratory
damage/
Premature
aging
of
lungs
Emergency
room
visits
for
asthma
Changes
in
pulmonary
function.
Morphological
changes.
Altered
host
defense
mechanisms.
Cancer.
Other
chronic
respiratory
disease.
Emergency
room
visits
for
asthma.
Emergency
room
visits
for
non­
asthma
respiratory
and
cardiovascular
causes.
Lower
and
upper
respiratory
symptoms.
Acute
bronchitis.
Shortness
of
breath.
Increased
school
absence
rates.
Welfare
Categories
............................................
Ecosystem
and
vegetation
effects
Damage
to
urban
ornamentals
(
e.
g.,
grass,
flowers,
shrubs,
and
trees
in
urban
areas)
Commercial
field
crops
Fruit
and
vegetable
crops
Reduced
yields
of
tree
seedlings,
commercial
and
non­
commercial
forests
Damage
to
ecosystems
Materials
damage
Materials
damage.
Damage
to
ecosystems
(
e.
g.,
acid
sulfate
deposition).
Nitrates
in
drinking
water.
Visibility
in
recreational
and
residential
areas.

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2003
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Proposed
Rules
In
summary,
the
base
estimate
using
the
VSL
approach
yields
a
total
monetized
benefit
estimate
of
$
16.1
billion
+
B
(
1999
dollars)
in
2005
when
using
a
3
percent
interest
rate
(
or
approximately
$
15.4
billion
+
B
when
using
a
7
percent
interest
rate).
The
alternative
estimate
totals
approximately
$
2.4
billion
+
B
when
using
a
3
percent
interest
rate
(
or
approximately
$
2.6
billion
+
B
when
using
a
7
percent
interest
rate).
Using
the
results
of
the
benefit
analysis,
we
can
use
benefit­
cost
comparison
(
or
net
benefits)
as
another
tool
to
evaluate
the
reallocation
of
society's
resources
needed
to
address
the
pollution
externality
created
by
the
operation
of
industrial
boilers
and
process
heaters.
The
additional
costs
of
internalizing
the
pollution
produced
at
major
sources
of
emissions
from
industrial
boilers
and
process
heaters
are
compared
to
the
improvement
in
society's
well­
being
from
a
cleaner
and
healthier
environment.
Comparing
benefits
of
the
proposed
rule
to
the
costs
imposed
by
alternative
ways
to
control
emissions
optimally
identifies
a
strategy
that
results
in
the
highest
net
benefit
to
society.
In
the
case
of
the
proposed
rule,
we
are
proposing
only
one
option,
the
minimal
level
of
control
mandated
by
the
CAA,
or
the
MACT
floor.
Other
alternatives
that
lead
to
higher
levels
of
control
(
or
beyond­
the­
floor
alternatives)
lead
to
higher
estimates
of
benefits
net
of
costs,
but
also
lead
to
additional
economic
impacts
including
more
substantial
impacts
to
small
entities.
For
more
details,
please
refer
to
the
RIA
for
the
proposed
rule.
Table
6
of
this
preamble
presents
a
summary
of
costs,
benefits,
and
net
benefits
(
i.
e.,
benefits
minus
costs).
Based
on
estimated
compliance
costs
associated
with
the
proposed
rule
and
the
predicted
change
in
prices
and
production
in
the
affected
industries,
the
estimated
social
costs
of
the
proposed
rule
are
$
780
million
(
1999
dollars).
Social
costs
are
different
from
compliance
costs
in
that
social
costs
take
into
account
the
interactions
between
affected
producers
and
the
consumers
of
affected
products
in
response
to
the
imposition
of
the
compliance
costs.
Therefore,
the
Agency's
base
estimate
of
monetized
benefits
net
of
costs
is
$
15.2
billion
+
B
(
1999
dollars)
in
2005
when
using
a
3
percent
discount
rate
(
or
approximately
$
15
billion
+
B
when
using
a
7
percent
discount
rate).
However,
using
the
more
conservative
alternative
estimate
of
benefits,
net
benefits
are
$
1.5
billion
+
B
(
1999
dollars)
under
a
3
percent
discount
rate
(
or
approximately
$
1.7
billion
+
B
when
using
a
7
percent
discount
rate).
In
both
cases,
net
benefits
would
be
greater
if
all
the
benefits
of
the
HAP
and
other
pollutant
reductions
could
be
quantified.
Notable
omissions
to
the
net
benefits
include
all
benefits
of
HAP
reductions,
including
reduced
cancer
incidences,
toxic
morbidity
effects,
and
cardiovascular
and
CNS
effects.
It
is
also
important
to
note
that
not
all
benefits
of
SO2
and
PM
reductions
have
been
monetized.

TABLE
6.
 
ANNUAL
NET
BENEFITS
OF
THE
INDUSTRIAL
BOILERS
AND
PROCESS
HEATERS
NESHAP
IN
2005
A
MACT
floor
(
million
1999$)
Beyond
the
MACT
floor
(
million
1999$)

Social
Costs
B
...............................................................................................................
$
837
..........................................................
$
1,923
Social
Benefits:
B,
C,
D
HAP­
related
health
and
welfare
benefits
...............................................................
Not
monetized
...........................................
Not
monetized
PM­
related
welfare
benefits
...................................................................................
Not
monetized
...........................................
Not
monetized
SO2
¥
and
PM­
related
health
benefits:
Primary
Estimate
 
Using
3%
Discount
Rate
....................................................................................
$
16,300
+
B
..............................................
$
17,230
+
B.
Using
7%
Discount
Rate
.......................................................................................
$
15,430
+
B
..............................................
$
16,310
+
B.
Alternative
Estimate
 
Using
3%
Discount
Rate
....................................................................................
$
2,350
+
B
................................................
$
2,380
+
B.
 
Using
7%
Discount
Rate
....................................................................................
$
2,585
+
B
................................................
$
2,620
+
B.
Net
Benefits
(
Benefits
¥
Costs):
C,
D
Primary
Estimate
 
Using
3%
Discount
Rate
....................................................................................
$
15,465
.....................................................
$
15,305
+
B.
 
Using
7%
Discount
Rate
....................................................................................
$
14,595
.....................................................
$
14,385
+
B.
Alternative
Estimate
 
Using
3%
Discount
Rate
....................................................................................
$
1,515
.......................................................
$
455
+
B.
 
Using
7%
Discount
Rate
....................................................................................
$
1,750
.......................................................
$
700
+
B.

A
All
costs
and
benefits
are
rounded
to
the
nearest
$
5
million.
Thus,
figures
presented
in
this
table
may
not
exactly
equal
benefit
and
cost
numbers
presented
in
earlier
sections
of
the
chapter.
B
Note
that
costs
are
the
total
costs
of
reducing
all
pollutants,
including
HAP
as
well
as
SO2
and
PM10.
Benefits
in
this
table
are
associated
only
with
PM
and
SO2
reductions.
C
Not
all
possible
benefits
or
disbenefits
are
quantified
and
monetized
in
this
analysis.
Potential
benefit
categories
that
have
not
been
quantified
and
monetized
are
listed
in
Table
8
 
13.
B
is
the
sum
of
all
unquantified
benefits
and
disbenefits.
D
Monetized
benefits
are
presented
using
two
different
discount
rates.
Results
calculated
using
3
percent
discount
rate
are
recommended
by
EPA's
Guidelines
for
Preparing
Economic
Analyses
(
U.
S.
EPA,
2000a).
Results
calculated
using
7
percent
discount
rate
are
recommended
by
OMB
Circular
A
 
94
(
OMB,
1992).

V.
Public
Participation
and
Requests
for
Comment
The
ICCR
Federal
Advisory
Committee
(
i.
e.,
the
Coordinating
Committee),
which
is
discussed
previously
in
this
preamble,
was
designed
and
created
to
foster
active
participation
from
stakeholders,
including
environmental
groups,
regulated
industries,
local
governments,
Federal
agencies,
and
State
and
local
regulatory
agencies.
The
stakeholders
were
able
to
participate
in
the
development
of
FACA
committee
recommendations
on
many
regulatory
issues.
The
ICCR
Coordinating
Committee
also
encouraged
the
public
to
provide
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/
Proposed
Rules
input
on
its
data
and
recommendations
throughout
the
2­
year
charter.
To
enhance
the
public's
ability
to
participate,
EPA
maintained
a
bulletin
board
on
the
Technology
Transfer
Network
to
disseminate
information
on
the
ICCR
Coordinating
Committee
and
Work
Group
meeting
schedules
and
minutes,
works
in
progress,
and
final
recommendations.
The
public
could
submit
comments
on
any
information
posted
on
the
bulletin
board
to
members
of
the
ICCR
Coordinating
Committee
or
Work
Group.
Individuals
could
also
attend
the
ICCR
Coordinating
Committee
and
Work
Group
meetings
and
comment
on
the
information
being
presented
and
discussed.
After
the
FACA
charter
expired,
individual
stakeholders
and
members
of
the
public
were
encourage
to
submit
individual
comments
and
information
to
EPA
staff.
On
several
occasions
after
the
FACA
charter
expired,
EPA
met
with
individual
stakeholder
groups
to
discuss
the
status
of
the
proposed
rulemaking
and
to
hear
their
concerns
and
comments
regarding
the
proposed
rulemaking.
To
continue
participation
of
stakeholders
in
the
rulemaking
process,
EPA
is
requesting
comments
and
data
to
support
the
proposed
rule.
The
EPA
requests
comments
on
all
aspects
of
the
proposed
rule
from
all
interested
parties.

VI.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,
1993),
the
Agency
must
determine
whether
a
regulatory
action
is
``
significant''
and,
therefore,
subject
to
review
by
the
Office
of
Management
and
Budget
(
OMB)
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,
competition,
jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
tribal
governments
or
communities;
(
2)
Create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;
(
3)
Materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs,
or
the
rights
and
obligation
of
recipients
thereof;
or
(
4)
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
Executive
Order
12866,
the
Agency
has
determined
that
the
proposed
rule
is
a
``
significant
regulatory
action''
because
it
has
an
annual
effect
on
the
economy
of
over
$
100
million.
As
such,
this
proposed
action
was
submitted
to
OMB
for
review.

B.
Executive
Order
13132,
Federalism
Executive
Order
13132
(
64
FR
43255,
August
10,
1999),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.
The
proposed
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
The
agency
is
required
by
section
112
of
the
CAA,
to
establish
the
standards
in
the
proposed
rule.
The
proposed
rule
primarily
affects
private
industry,
and
does
not
impose
significant
economic
costs
on
State
or
local
governments.
The
proposed
rule
does
not
include
an
express
provision
preempting
State
or
local
regulations.
Thus,
the
requirements
of
section
6
of
the
Executive
Order
do
not
apply
to
the
proposed
rule.
Although
section
6
of
Executive
Order
13132
does
not
apply
to
the
proposed
rule,
we
consulted
with
representatives
of
State
and
local
governments
to
enable
them
to
provide
meaningful
and
timely
input
into
the
development
of
the
proposed
rule.
This
consultation
took
place
during
the
ICCR
FACA
committee
meetings
where
members
representing
State
and
local
governments
participated
in
developing
recommendations
for
EPA's
combustion­
related
rulemakings,
including
the
proposed
rule.
The
concerns
raised
by
representatives
of
State
and
local
governments
were
considered
during
the
development
of
the
proposed
rule.
In
the
spirit
of
Executive
Order
13132,
and
consistent
with
EPA
policy
to
promote
communications
between
EPA
and
State
and
local
governments,
EPA
specifically
solicits
comment
on
the
proposed
rule
from
State
and
local
officials.

C.
Executive
Order
13175,
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175
(
65
FR
67249,
November
9,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.''
The
proposed
rule
does
not
have
tribal
implications,
as
specified
in
Executive
Order
13175.
The
proposed
rule
does
not
significantly
or
uniquely
affect
the
communities
of
Indian
tribal
governments.
We
do
not
know
of
any
industrial­
commercial­
institutional
boilers
or
process
heaters
owned
or
operated
by
Indian
tribal
governments.
However,
if
there
are
any,
the
effect
of
the
proposed
rule
on
communities
of
tribal
governments
would
not
be
unique
or
disproportionate
to
the
effect
on
other
communities.
Thus,
Executive
Order
13175
does
not
apply
to
the
proposed
rule.
The
EPA
specifically
solicits
additional
comment
on
the
proposed
rule
from
tribal
officials.

D.
Executive
Order
13045,
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that:
(
1)
Is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
we
have
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
the
Agency
must
evaluate
the
environmental
health
or
safety
effects
of
the
proposed
rule
on
children,
and
explain
why
the
proposed
rule
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives.
The
EPA
interprets
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5
 
501
of
the
Executive
Order
has
the
potential
to
influence
the
regulation.
The
proposed
rule
is
not
subject
to
Executive
Order
13045
because
it
is
based
on
technology
performance
and
not
on
health
or
safety
risks.

E.
Unfunded
Mandates
Reform
Act
of
1995
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Pub.
L.

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13,
2003
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Proposed
Rules
104
 
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
we
generally
must
prepare
a
written
statement,
including
a
cost­
benefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
to
State,
local,
and
tribal
governments,
in
the
aggregate,
or
to
the
private
sector,
of
$
100
million
or
more
in
any
1
year.
Before
promulgating
a
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
us
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
cost­
effective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
us
to
adopt
an
alternative
other
than
the
least
costly,
most
cost­
effective
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
we
establish
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
we
must
develop
a
small
government
agency
plan
under
section
203
of
the
UMRA.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
We
have
determined
that
the
proposed
rule
contains
a
Federal
mandate
that
may
result
in
expenditures
of
$
100
million
or
more
for
State,
local,
and
Tribal
governments,
in
the
aggregate,
or
the
private
sector
in
any
1
year.
Accordingly,
we
have
prepared
a
written
statement
entitled
``
Unfunded
Mandates
Reform
Act
Analysis
for
the
Proposed
Industrial
Boilers
and
Process
Heaters
NESHAP''
under
section
202
of
the
UMRA
which
is
summarized
below.

1.
Statutory
Authority
As
discussed
in
section
I
of
this
preamble,
the
statutory
authority
for
the
proposed
rulemaking
is
section
112
of
the
CAA.
Title
III
of
the
CAA
Amendments
was
enacted
to
reduce
nationwide
air
toxic
emissions.
Section
112(
b)
of
the
CAA
lists
the
188
chemicals,
compounds,
or
groups
of
chemicals
deemed
by
Congress
to
be
HAP.
These
toxic
air
pollutants
are
to
be
regulated
by
NESHAP.
Section
112(
d)
of
the
CAA
directs
us
to
develop
NESHAP
which
require
existing
and
new
major
sources
to
control
emissions
of
HAP
using
MACT
based
standards.
This
NESHAP
applies
to
all
industrial,
commercial,
and
institutional
boilers
and
process
heaters
located
at
major
sources
of
HAP
emissions.
In
compliance
with
section
205(
a)
of
the
UMRA,
we
identified
and
considered
a
reasonable
number
of
regulatory
alternatives.
Additional
information
on
the
costs
and
environmental
impacts
of
these
regulatory
alternatives
is
presented
in
the
docket.
The
regulatory
alternative
upon
which
the
proposed
rule
is
based
represents
the
MACT
floor
for
industrial
boilers
and
process
heaters
and,
as
a
result,
it
is
the
least
costly
and
least
burdensome
alternative.

2.
Social
Costs
and
Benefits
The
regulatory
impact
analysis
prepared
for
the
proposed
rule
including
the
Agency's
assessment
of
costs
and
benefits,
is
detailed
in
the
``
Regulatory
Impact
Analysis
for
the
Proposed
Industrial
Boilers
and
Process
Heaters
MACT''
in
the
docket.
Based
on
estimated
compliance
costs
associated
with
the
proposed
rule
and
the
predicted
change
in
prices
and
production
in
the
affected
industries,
the
estimated
social
costs
of
the
proposed
rule
are
$
780
million
(
1999
dollars).
It
is
estimated
that
5
years
after
implementation
of
the
proposed
rule,
HAP
will
be
reduced
by
58,500
tons
per
year
due
to
reductions
in
arsenic,
beryllium,
dioxin,
hydrochloric
acid,
and
several
other
HAP
from
industrial
boilers
and
process
heaters.
Studies
have
determined
a
relationship
between
exposure
to
these
HAP
and
the
onset
of
cancer,
however,
there
are
some
questions
remaining
on
how
cancers
that
may
result
from
exposure
to
these
HAP
can
be
quantified
in
terms
of
dollars.
Therefore,
the
Agency
is
unable
to
provide
a
monetized
estimate
of
the
benefits
of
the
HAP
reduced
by
the
proposed
rule
at
this
time.
However,
there
are
significant
reductions
in
PM
and
in
SO2
that
occur.
Reductions
of
560,000
tons
of
PM
with
a
diameter
of
less
than
or
equal
to
10
micrometers
(
PM10),
159,000
tons
of
PM
with
a
diameter
of
less
than
or
equal
to
2.5
micrometers
(
PM10),
and
112,000
tons
of
SO2
are
expected
to
occur.
These
reductions
occur
from
existing
sources
in
operation
5
years
after
the
implementation
of
the
regulation
and
are
expected
to
continue
throughout
the
life
of
the
affected
sources.
The
major
health
effect
that
results
from
these
PM
and
SO2
emissions
reductions
is
a
reduction
in
premature
mortality.
Other
health
effects
that
occur
are
reductions
in
chronic
bronchitis,
asthma
attacks,
and
work­
lost
days
(
i.
e.,
days
when
employees
are
unable
to
work).
While
we
are
unable
to
monetize
the
benefits
associated
with
the
HAP
emissions
reductions,
we
are
able
to
monetize
the
benefits
associated
with
the
PM
and
SO2
emissions
reductions.
For
SO2
and
PM,
we
estimated
the
benefits
associated
with
health
effects
of
PM
but
were
unable
to
quantify
all
categories
of
benefits
(
particularly
those
associated
with
ecosystem
and
environmental
effects).
Unquantified
benefits
are
noted
with
``
B''
in
the
estimates
presented
below.
Our
base
estimate
of
the
monetized
benefits
in
2005
associated
with
the
implementation
of
the
proposed
alternative
is
$
16.1
billion
(
1999
dollars)
when
using
a
3
percent
discount
rate
(
or
approximately
$
15.4
billion
+
B
when
using
a
7
percent
discount
rate).
This
estimate,
at
a
3
percent
discount
rate,
is
about
$
15
billion
(
1999
dollars)
higher
than
the
estimated
social
costs
shown
earlier
in
this
section.
The
alternative
estimate
of
benefits
is
$
2.4
billion
(
1999
dollars)
when
using
a
3
percent
discount
rate
(
or
approximately
$
2.6
billion
+
B
when
using
a
7
percent
discount
rate).
This
estimate,
at
a
3
percent
discount
rate,
is
about
$
1.5
billion
higher
than
the
estimated
social
costs.
The
general
approach
to
value
benefits
is
discussed
in
more
detail
earlier
in
this
preamble.
For
more
detailed
information
on
the
benefits
estimated
for
the
proposed
rulemaking,
refer
to
the
RIA
in
the
docket.

3.
Future
and
Disproportionate
Costs
The
Unfunded
Mandates
Act
requires
that
we
estimate,
where
accurate
estimation
is
reasonably
feasible,
future
compliance
costs
imposed
by
the
proposed
rule
and
any
disproportionate
budgetary
effects.
Our
estimates
of
the
future
compliance
costs
of
the
proposed
rule
are
discussed
previously
in
this
preamble.
We
do
not
believe
that
there
will
be
any
disproportionate
budgetary
effects
of
the
proposed
rule
on
any
particular
areas
of
the
country,
State
or
local
governments,
types
of
communities
(
e.
g.,
urban,
rural),
or
particular
industry
segments.
This
is
true
for
the
257
facilities
owned
by
54
different
government
bodies
and
is
borne
out
by
the
results
of
the
``
Economic
Impact
Analysis
of
the
Proposed
Industrial
Boilers
and
Process
Heaters
NESHAP,''

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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
the
results
of
which
are
discussed
previously
in
this
preamble.

4.
Effects
on
the
National
Economy
The
Unfunded
Mandates
Act
requires
that
we
estimate
the
effect
of
the
proposed
rule
on
the
national
economy.
To
the
extent
feasible,
we
must
estimate
the
effect
on
productivity,
economic
growth,
full
employment,
creation
of
productive
jobs,
and
international
competitiveness
of
the
U.
S.
goods
and
services,
if
we
determine
that
accurate
estimates
are
reasonably
feasible
and
that
such
effect
is
relevant
and
material.
The
nationwide
economic
impact
of
the
proposed
rule
is
presented
in
the
``
Economic
Impact
Analysis
for
the
Industrial
Boilers
and
Process
Heaters
MACT''
in
the
docket.
This
analysis
provides
estimates
of
the
effect
of
the
proposed
rule
on
some
of
the
categories
mentioned
above.
The
results
of
the
economic
impact
analysis
are
summarized
previously
in
this
preamble.
The
results
show
that
there
will
be
little
impact
on
prices
and
output
from
the
affected
industries,
and
little
impact
on
communities
that
may
be
affected
by
the
proposed
rule.
In
addition,
there
should
be
little
impact
on
energy
markets
(
in
this
case,
coal,
natural
gas,
petroleum
products,
and
electricity).
Hence,
the
potential
impacts
on
the
categories
mentioned
above
should
be
minimal.

5.
Consultation
with
Government
Officials
The
Unfunded
Mandates
Act
requires
that
we
describe
the
extent
of
the
Agency's
prior
consultation
with
affected
State,
local,
and
tribal
officials,
summarize
the
officials'
comments
or
concerns,
and
summarize
our
response
to
those
comments
or
concerns.
In
addition,
section
203
of
the
UMRA
requires
that
we
develop
a
plan
for
informing
and
advising
small
governments
that
may
be
significantly
or
uniquely
impacted
by
a
proposal.
Although
the
proposed
rule
does
not
affect
any
State,
local,
or
Tribal
governments,
we
have
consulted
with
State
and
local
air
pollution
control
officials.
We
also
have
held
meetings
on
the
proposed
rule
with
many
of
the
stakeholders
from
numerous
individual
companies,
environmental
groups,
consultants
and
vendors,
labor
unions,
and
other
interested
parties.
We
have
added
materials
to
the
Air
Docket
to
document
these
meetings.
In
addition,
we
have
determined
that
the
proposed
rule
contains
no
regulatory
requirements
that
might
significantly
or
uniquely
affect
small
governments.
While
some
small
governments
may
have
some
sources
affected
by
the
proposed
rule,
the
impacts
are
not
expected
to
be
significant.
Therefore,
today's
proposed
rule
is
not
subject
to
the
requirements
of
section
203
of
the
UMRA.

F.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.

The
RFA
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedure
Act
or
any
other
statute
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
purposes
of
assessing
the
impacts
of
today's
proposed
rule
on
small
entities,
small
entity
is
defined
as:
(
1)
A
small
business
according
to
Small
Business
Administration
(
SBA)
size
standards
by
the
North
American
Industry
Classification
System
category
of
the
owning
entity.
The
range
of
small
business
size
standards
for
the
40
affected
industries
ranges
from
500
to
1,000
employees,
except
for
petroleum
refining
and
electric
utilities.
In
these
latter
two
industries,
the
size
standard
is
1,500
employees
and
a
mass
throughput
of
75,000
barrels/
day
or
less,
and
4
million
kilowatt­
hours
of
production
or
less,
respectively;
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not­
forprofit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
After
considering
the
economic
impact
of
the
proposed
rule
on
small
entities,
EPA
certifies
that
this
action
will
not
have
a
significant
impact
on
a
substantial
number
of
small
entities.
Based
on
SBA
size
definitions
for
the
affected
industries
and
reported
sales
and
employment
data,
the
Agency
identified
185
of
the
576
companies,
or
32
percent,
owning
affected
facilities
as
small
businesses.
Although
small
businesses
represent
32
percent
of
the
companies
within
the
source
category,
they
are
expected
to
incur
4
percent
of
the
total
compliance
costs
of
$
862.7
million
(
1998
dollars).
There
are
only
ten
small
firms
with
compliance
costs
equal
to
or
greater
than
3
percent
of
their
sales.
In
addition,
there
are
24
small
firms
with
cost­
to­
sales
ratios
between
1
and
3
percent.
An
economic
impact
analysis
was
performed
to
estimate
the
changes
in
product
price
and
production
quantities
for
the
proposed
rule.
As
mentioned
in
the
summary
of
economic
impacts,
the
estimated
changes
in
prices
and
output
for
affected
firms
is
no
more
than
0.05
percent.
This
analysis
indicates
that
the
proposed
rule
should
not
generate
a
significant
impact
on
a
substantial
number
of
small
entities
for
following
reasons.
First,
there
are
34
small
firms
(
or
18
percent
of
all
affected
small
firms)
with
compliance
costs
equal
to
or
greater
than
1
percent
of
their
sales.
Of
these,
ten
small
firms
(
or
5
percent
of
all
affected
small
firms)
with
compliance
costs
equal
to
or
greater
than
3
percent
of
their
sales.
Second,
the
results
of
the
economic
impact
analysis
show
minimal
impacts
on
prices
and
output
from
affected
firms,
including
small
entities,
due
to
the
implementation
of
the
proposed
rule.
For
more
information,
consult
the
docket
for
the
proposed
rule.
The
proposed
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities
as
a
result
of
several
decisions
EPA
made
regarding
the
development
of
the
rule
which
resulted
in
limiting
the
impact
of
the
rule
on
small
entities.
First,
as
mentioned
earlier
in
this
preamble,
EPA
identified
small
units
(
heat
input
of
10
MMBtu/
hr
or
less)
and
limited
use
boilers
(
operate
less
than
10
percent
of
the
time)
as
separate
subcategories
different
from
large
units.
Many
small
and
limited
use
units
are
located
at
small
entities.
As
also
discussed
earlier,
the
results
of
the
MACT
floor
analysis
for
these
subcategories
of
existing
sources
was
that
no
MACT
floor
could
be
identified
except
for
the
limited
use
solid
fuel
subcategory
which
is
less
stringent
than
the
MACT
floor
for
large
units.
Furthermore,
the
results
of
the
beyond­
the­
floor
analysis
for
these
subcategories
indicated
that
the
costs
would
be
too
high
to
consider
them
feasible
options.
Consequently,
the
proposed
rule
contains
no
emission
limitations
for
any
of
the
existing
small
and
limited
use
subcategories
except
the
existing
limited
use
solid
fuel
subcategory.
In
addition,
the
proposed
alternative
metals
emission
limit
resulted
in
minimizing
the
impacts
on
small
entities
since
some
of
the
potential
entities
burning
a
fuel
containing
very
little
metals
are
small
entities.
We
continue
to
be
interested
in
the
potential
impacts
of
the
proposed
rule
on
small
entities
and
welcome
comments
on
issues
related
to
such
impacts.

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Proposed
Rules
G.
Paperwork
Reduction
Act
The
information
collection
requirements
in
the
proposed
rule
will
be
submitted
for
approval
to
the
Office
of
Management
and
Budget
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
An
Information
Collection
Request
(
ICR)
document
has
been
prepared
by
EPA
(
ICR
No.
2028.01)
and
a
copy
may
be
obtained
from
Susan
Auby
by
mail
at
the
Collection
Strategies
Division,
U.
S.
Environmental
Protection
Agency
(
2822),
1200
Pennsylvania
Avenue
NW.,
Washington,
DC
20460,
by
e­
mail
at
auby.
susan@
epa.
gov,
or
by
calling
(
202)
566
 
1672.
A
copy
may
also
be
downloaded
off
the
Internet
at
http://
www.
epa.
gov/
icr.
The
information
requirements
are
based
on
notification,
recordkeeping,
and
reporting
requirements
in
the
NESHAP
General
Provisions
(
40
CFR
part
63,
subpart
A),
which
are
mandatory
for
all
operators
subject
to
national
emission
standards.
These
recordkeeping
and
reporting
requirements
are
specifically
authorized
by
section
114
of
the
CAA
(
42
U.
S.
C.
7414).
All
information
submitted
to
EPA
pursuant
to
the
recordkeeping
and
reporting
requirements
for
which
a
claim
of
confidentiality
is
made
is
safeguarded
according
to
Agency
policies
set
forth
in
40
CFR
part
2,
subpart
B.
The
proposed
rule
would
require
maintenance
inspections
of
the
control
devices
but
would
not
require
any
notifications
or
reports
beyond
those
required
by
the
General
Provisions.
The
recordkeeping
requirements
require
only
the
specific
information
needed
to
determine
compliance.
The
annual
monitoring,
reporting,
and
recordkeeping
burden
for
this
collection
(
averaged
over
the
first
3
years
after
the
effective
date
of
the
standards)
is
estimated
to
be
$
165
million.
This
includes
2.7
million
labor
hours
per
year
at
a
total
labor
cost
of
$
142
million
per
year,
and
total
non­
labor
capital
costs
of
$
24
million
per
year.
This
estimate
includes
a
one­
time
performance
test,
semiannual
excess
emission
reports,
maintenance
inspections,
notifications,
and
recordkeeping.
Monitoring
costs
were
also
included
in
the
cost
estimates
presented
in
the
control
costs
impacts
estimates
in
section
IV.
D
of
this
preamble.
The
total
burden
for
the
Federal
government
(
averaged
over
the
first
3
years
after
the
effective
date
of
the
standard)
is
estimated
to
be
346,000
hours
per
year
at
a
total
labor
cost
of
$
14
million
per
year.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
Agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
our
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
Comments
are
requested
on
the
Agency's
need
for
this
information,
the
accuracy
of
the
provided
burden
estimates,
and
any
suggested
methods
for
minimizing
respondent
burden,
including
through
the
use
of
automated
collection
techniques.
Send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division,
U.
S.
Environmental
Protection
Agency
(
2822),
1200
Pennsylvania
Ave.,
NW.,
Washington,
DC
20460;
and
to
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
725
17th
St.,
NW.,
Washington,
DC
20503,
marked
``
Attention:
Desk
Officer
for
EPA.''
Include
the
ICR
number
in
any
correspondence.
Since
OMB
is
required
to
make
a
decision
concerning
the
ICR
between
30
and
60
days
after
January
13,
2003,
a
comment
to
OMB
is
best
assured
of
having
its
full
effect
if
OMB
receives
it
by
February
12,
2003.
The
final
rule
will
respond
to
any
OMB
or
public
comments
on
the
information
collection
requirements
contained
in
the
proposed
rule.

H.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
(
NTTAA)
of
1995
(
Public
Law
104
 
113;
15
U.
S.
C.
272
note)
directs
the
EPA
to
use
voluntary
consensus
standards
in
their
regulatory
and
procurement
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(
e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
business
practices)
developed
or
adopted
by
one
or
more
voluntary
consensus
bodies.
The
NTTAA
directs
EPA
to
provide
Congress,
through
annual
reports
to
the
Office
of
Management
and
Budget,
with
explanations
when
an
agency
does
not
use
available
and
applicable
voluntary
consensus
standards.
This
rulemaking
involves
technical
standards.
The
EPA
cites
the
following
standards
in
the
proposed
rule:
EPA
Methods
1,
2,
2F,
2G,
3A,
3B,
4,
5,
5D,
17,
19,
26,
26A,
29
of
40
CFR
part
60.
Consistent
with
the
NTTAA,
EPA
conducted
searches
to
identify
voluntary
consensus
standards
in
addition
to
these
EPA
methods.
No
applicable
voluntary
consensus
standards
were
identified
for
EPA
Methods
2F,
2G,
5D,
and
19.
The
search
and
review
results
have
been
documented
and
are
placed
in
the
docket
for
the
proposed
rule.
The
three
voluntary
consensus
standards
described
below
were
identified
as
acceptable
alternatives
to
EPA
test
methods
for
the
purposes
of
the
proposed
rule.
The
voluntary
consensus
standard
ASME
PTC
19
 
10
 
1981
 
Part
10,
``
Flue
and
Exhaust
Gas
Analyses,''
is
cited
in
the
proposed
rule
for
its
manual
method
for
measuring
the
oxygen,
carbon
dioxide,
and
carbon
monoxide
content
of
exhaust
gas.
This
part
of
ASME
PTC
19
 
10
 
1981
 
Part
10
is
an
acceptable
alternative
to
Method
3B.
The
voluntary
consensus
standard
ASTM
D6522
 
00,
``
Standard
Test
Method
for
the
Determination
of
Nitrogen
Oxides,
Carbon
Monoxide,
and
Oxygen
Concentrations
in
Emissions
from
Natural
Gas­
Fired
Reciprocating
Engines,
Combustion
Turbines,
Boilers
and
Process
Heaters
Using
Portable
Analyzers''
is
an
acceptable
alternative
to
EPA
Method
3A
for
identifying
carbon
monoxide
and
oxygen
concentrations
for
the
proposed
rule
when
the
fuel
is
natural
gas.
The
voluntary
consensus
standard
ASTM
Z65907,
``
Standard
Method
for
Both
Speciated
and
Elemental
Mercury
Determination,''
is
an
acceptable
alternative
to
EPA
Method
29
(
portion
for
mercury
only)
for
the
purpose
of
the
proposed
rule.
This
standard
can
be
used
in
the
proposed
rule
to
determine
the
mercury
concentration
in
stack
gases
for
boilers
with
rated
heat
input
capacities
of
greater
than
250
MMBtu
per
hour.
In
addition
to
the
voluntary
consensus
standards
EPA
uses
in
the
proposed
rule,
the
search
for
emissions
measurement
procedures
identified
15
other
voluntary
consensus
standards.

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13,
2003
/
Proposed
Rules
The
EPA
determined
that
13
of
these
15
standards
identified
for
measuring
emissions
of
the
HAP
or
surrogates
subject
to
emission
standards
in
the
proposed
rule
were
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
the
rule.
Therefore,
EPA
does
not
intend
to
adopt
these
standards
for
this
purpose.
The
reasons
for
this
determination
for
the
13
methods
are
discussed
below.
The
voluntary
consensus
standard
ASTM
D3154
 
00,
``
Standard
Method
for
Average
Velocity
in
a
Duct
(
Pitot
Tube
Method),''
is
impractical
as
an
alternative
to
EPA
Methods
1,
2,
3B,
and
4
for
the
purposes
of
the
proposed
rulemaking
since
the
standard
appears
to
lack
in
quality
control
and
quality
assurance
requirements.
Specifically,
ASTM
D3154
 
00
does
not
include
the
following:
(
1)
Proof
that
openings
of
standard
pitot
tube
have
not
plugged
during
the
test;
(
2)
if
differential
pressure
gauges
other
than
inclined
manometers
(
e.
g.,
magnehelic
gauges)
are
used,
their
calibration
must
be
checked
after
each
test
series;
and
(
3)
the
frequency
and
validity
range
for
calibration
of
the
temperature
sensors.
The
voluntary
consensus
standard
ASTM
D3464
 
96
(
2001),
``
Standard
Test
Method
Average
Velocity
in
a
Duct
Using
a
Thermal
Anemometer,''
is
impractical
as
an
alternative
to
EPA
Method
2
for
the
purposes
of
the
proposed
rule
primarily
because
applicability
specifications
are
not
clearly
defined,
e.
g.,
range
of
gas
composition,
temperature
limits.
Also,
the
lack
of
supporting
quality
assurance
data
for
the
calibration
procedures
and
specifications,
and
certain
variability
issues
that
are
not
adequately
addressed
by
the
standard
limit
EPA's
ability
to
make
a
definitive
comparison
of
the
method
in
these
areas.
The
voluntary
consensus
standard
ISO
10780:
1994,
``
Stationary
Source
Emissions­
Measurement
of
Velocity
and
Volume
Flow­
Rate
of
Gas
Streams
in
Ducts,''
is
impractical
as
an
alternative
to
EPA
Method
2
in
the
proposed
rule.
The
standard
recommends
the
use
of
an
L­
shaped
pitot,
which
historically
has
not
been
recommended
by
EPA.
The
EPA
specifies
the
S­
type
design
which
has
large
openings
that
are
less
likely
to
plug
up
with
dust.
The
voluntary
consensus
standard,
CAN/
CSA
Z223.2
 
M86
(
1999),
``
Method
for
the
Continuous
Measurement
of
Oxygen,
Carbon
Dioxide,
Carbon
Monoxide,
Sulphur
Dioxide,
and
Oxides
of
Nitrogen
in
Enclosed
Combustion
Flue
Gas
Streams,''
is
unacceptable
as
a
substitute
for
EPA
Method
3A
since
it
does
not
include
quantitative
specifications
for
measurement
system
performance,
most
notably
the
calibration
procedures
and
instrument
performance
characteristics.
The
instrument
performance
characteristics
that
are
provided
are
nonmandatory
and
also
do
not
provide
the
same
level
of
quality
assurance
as
the
EPA
methods.
For
example,
the
zero
and
span/
calibration
drift
is
only
checked
weekly,
whereas
the
EPA
methods
requires
drift
checks
after
each
run.
Two
very
similar
voluntary
consensus
standards,
ASTM
D5835
 
95
(
2001),
``
Standard
Practice
for
Sampling
Stationary
Source
Emissions
for
Automated
Determination
of
Gas
Concentration,''
and
ISO
10396:
1993,
``
Stationary
Source
Emissions:
Sampling
for
the
Automated
Determination
of
Gas
Concentrations,''
are
impractical
alternatives
to
EPA
Method
3A
for
the
purposes
of
the
proposed
rule
because
they
lack
in
detail
and
quality
assurance/
quality
control
requirements.
Specifically,
these
two
standards
do
not
include
the
following:
(
1)
Sensitivity
of
the
method;
(
2)
acceptable
levels
of
analyzer
calibration
error;
(
3)
acceptable
levels
of
sampling
system
bias;
(
4)
zero
drift
and
calibration
drift
limits,
time
span,
and
required
testing
frequency;
(
5)
a
method
to
test
the
interference
response
of
the
analyzer;
(
6)
procedures
to
determine
the
minimum
sampling
time
per
run
and
minimum
measurement
time;
and
(
7)
specifications
for
data
recorders,
in
terms
of
resolution
(
all
types)
and
recording
intervals
(
digital
and
analog
recorders,
only).
The
voluntary
consensus
standard
ISO
12039:
2001,
``
Stationary
Source
Emissions
 
Determination
of
Carbon
Monoxide,
Carbon
Dioxide,
and
Oxygen
 
Automated
Methods,''
is
not
acceptable
as
an
alternative
to
EPA
Method
3A.
This
ISO
standard
is
similar
to
EPA
Method
3A,
but
is
missing
some
key
features.
In
terms
of
sampling,
the
hardware
required
by
ISO
12039:
2001
does
not
include
a
3­
way
calibration
valve
assembly
or
equivalent
to
block
the
sample
gas
flow
while
calibration
gases
are
introduced.
In
its
calibration
procedures,
ISO
12039:
2001
only
specifies
a
two­
point
calibration
while
EPA
Method
3A
specifies
a
three­
point
calibration.
Also,
ISO
12039:
2001
does
not
specify
performance
criteria
for
calibration
error,
calibration
drift,
or
sampling
system
bias
tests
as
in
the
EPA
method,
although
checks
of
these
quality
control
features
are
required
by
the
ISO
standard.
The
voluntary
consensus
standard
ASME
PTC
 
38
 
80
R85
(
1985),
``
Determination
of
the
Concentration
of
Particulate
Matter
in
Gas
Streams,''
is
not
acceptable
as
an
alternative
for
EPA
Method
5
because
ASTM
PTC
 
38
 
80
is
not
specific
about
equipment
requirements,
and
instead
presents
the
options
available
and
the
pro's
and
con's
of
each
option.
The
key
specific
differences
between
ASME
PTC
 
38
 
80
and
the
EPA
methods
are
that
the
ASME
standard:
(
1)
Allows
in­
stack
filter
placement
as
compared
to
the
out­
ofstack
filter
placement
in
EPA
Methods
5
and
17;
(
2)
allows
many
different
types
of
nozzles,
pitots,
and
filtering
equipment;
(
3)
does
not
specify
a
filter
weighing
protocol
or
a
minimum
allowable
filter
weight
fluctuation
as
in
the
EPA
methods;
and
(
4)
allows
filter
paper
to
be
only
99
percent
efficient,
as
compared
to
the
99.95
percent
efficiency
required
by
the
EPA
methods.
The
voluntary
consensus
standard
ASTM
D3685/
D3685M
 
98,
``
Test
Methods
for
Sampling
and
Determination
of
Particulate
Matter
in
Stack
Gases,''
is
similar
to
EPA
Methods
5
and
17,
but
is
lacking
in
the
following
areas
that
are
needed
to
produce
quality,
representative
particulate
data:
(
1)
Requirement
that
the
filter
holder
temperature
should
be
between
120
°
C
and
134
°
C,
and
not
just
``
above
the
acid
dew­
point;''
(
2)
detailed
specifications
for
measuring
and
monitoring
the
filter
holder
temperature
during
sampling;
(
3)
procedures
similar
to
EPA
Methods
1,
2,
3,
and
4,
that
are
required
by
EPA
Method
5;
(
4)
technical
guidance
for
performing
the
Method
5
sampling
procedures,
e.
g.,
maintaining
and
monitoring
sampling
train
operating
temperatures,
specific
leak
check
guidelines
and
procedures,
and
use
of
reagent
blanks
for
determining
and
subtracting
background
contamination;
and
(
5)
detailed
equipment
and/
or
operational
requirements,
e.
g.,
component
exchange
leak
checks,
use
of
glass
cyclones
for
heavy
particulate
loading
and/
or
water
droplets,
operating
under
a
negative
stack
pressure,
exchanging
particulate
loaded
filters,
sampling
preparation
and
implementation
guidance,
sample
recovery
guidance,
data
reduction
guidance,
and
particulate
sample
calculations
input.
The
voluntary
consensus
standard
ISO
9096:
1992,
``
Determination
of
Concentration
and
Mass
Flow­
Rate
of
Particulate
Matter
in
Gas
Carrying
Ducts
 
Manual
Gravimetric
Method,''
is
not
acceptable
as
an
alternative
for
EPA
Method
5.
Although
sections
of
ISO
9096
incorporate
EPA
Methods
1,
2,
and
5
to
some
degree,
this
ISO
standard
is
not
equivalent
to
EPA
Method
5
for
collection
of
particulate
matter.
The
standard
ISO
9096
does
not
provide
applicable
technical
guidance
for
performing
many
of
the
integral
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68,
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8
/
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January
13,
2003
/
Proposed
Rules
procedures
specified
in
Methods
1,
2,
and
5.
Major
performance
and
operational
details
are
lacking
or
nonexistent,
and
detailed
quality
assurance/
quality
control
guidance
for
the
sampling
operations
required
to
produce
quality,
representative
particulate
data
(
e.
g.,
guidance
for
maintaining
and
monitoring
train
operating
temperatures,
specific
leak
check
guidelines
and
procedures,
and
sample
preparation
and
recovery
procedures)
are
not
provided
by
the
standard,
as
in
EPA
Method
5.
Also,
details
of
equipment
and/
or
operational
requirements,
such
as
those
specified
in
EPA
Method
5,
are
not
included
in
the
ISO
standard,
e.
g.,
stack
gas
moisture
measurements,
data
reduction
guidance,
and
particulate
sample
calculations.
The
voluntary
consensus
standard
CAN/
CSA
Z223.1
 
M1977,
``
Method
for
the
Determination
of
Particulate
Mass
Flows
in
Enclosed
Gas
Streams,''
is
not
acceptable
as
an
alternative
for
EPA
Method
5.
Detailed
technical
procedures
and
quality
control
measures
that
are
required
in
EPA
Methods
1,
2,
3,
and
4
are
not
included
in
CAN/
CSA
Z223.1.
Second,
CAN/
CSA
Z223.1
does
not
include
the
EPA
Method
5
filter
weighing
requirement
to
repeat
weighing
every
6
hours
until
a
constant
weight
is
achieved.
Third,
EPA
Method
5
requires
the
filter
weight
to
be
reported
to
the
nearest
0.1
mg,
while
CAN/
CSA
Z223.1
requires
only
to
the
nearest
0.5
mg.
Also,
CAN/
CSA
Z223.1
allows
the
use
of
a
standard
pitot
for
velocity
measurement
when
plugging
of
the
tube
opening
is
not
expected
to
be
a
problem.
Whereas,
EPA
Method
5
requires
an
S­
shaped
pitot.
The
voluntary
consensus
standard
EN
1911
 
1,2,3
(
1998),
``
Stationary
Source
Emissions
 
Manual
Method
of
Determination
of
HCl
 
Part
1:
Sampling
of
Gases
Ratified
European
Text
 
Part
2:
Gaseous
Compounds
Absorption
Ratified
European
Text
 
Part
3:
Adsorption
Solutions
Analysis
and
Calculation
Ratified
European
Text,''
is
impractical
as
an
alternative
to
EPA
Methods
26
and
26A.
Part
3
of
this
standard
cannot
be
considered
equivalent
to
EPA
Method
26
or
26A
because
the
sample
absorbing
solution
(
water)
would
be
expected
to
capture
both
HCl
and
chlorine
gas,
if
present,
without
the
ability
to
distinguish
between
the
two.
The
EPA
Methods
26
and
26A
use
an
acidified
absorbing
solution
to
first
separate
HCl
and
chlorine
gas
so
that
they
can
be
selectively
absorbed,
analyzed,
and
reported
separately.
In
addition,
in
EN
1911
the
absorption
efficiency
for
chlorine
gas
would
be
expected
to
vary
as
the
pH
of
the
water
changed
during
sampling.
The
voluntary
consensus
standard
EN
13211
(
1998),
is
not
acceptable
as
an
alternative
to
the
mercury
portion
of
EPA
Method
29
primarily
because
it
is
not
validated
for
use
with
impingers,
as
in
the
EPA
method,
although
the
method
describes
procedures
for
the
use
of
impingers.
This
European
standard
is
validated
for
the
use
of
fritted
bubblers
only
and
requires
the
use
of
a
side
(
split)
stream
arrangement
for
isokinetic
sampling
because
of
the
low
sampling
rate
of
the
bubblers
(
up
to
3
liters
per
minute,
maximum).
Also,
only
two
bubblers
(
or
impingers)
are
required
by
EN
13211,
whereas
EPA
Method
29
require
the
use
of
six
impingers.
In
addition,
EN
13211
does
not
include
many
of
the
quality
control
procedures
of
EPA
Method
29,
especially
for
the
use
and
calibration
of
temperature
sensors
and
controllers,
sampling
train
assembly
and
disassembly,
and
filter
weighing.
Two
of
the
15
voluntary
consensus
standards
identified
in
this
search
were
not
available
at
the
time
the
review
was
conducted
for
the
purposes
of
the
proposed
rule
because
they
are
under
development
by
a
voluntary
consensus
body:
ASME/
BSR
MFC
13M,
``
Flow
Measurement
by
Velocity
Traverse,''
for
EPA
Method
2
(
and
possibly
1);
and
ASME/
BSR
MFC
12M,
``
Flow
in
Closed
Conduits
Using
Multiport
Averaging
Pitot
Primary
Flowmeters,''
for
EPA
Method
2.
Section
63.7520
and
Tables
4A
through
4D
to
subpart
DDDDD,
40
CFR
part
63,
list
the
EPA
testing
methods
included
in
the
proposed
rule.
Under
§
63.7(
f)
and
§
63.8(
f)
of
subpart
A
of
the
General
Provisions,
a
source
may
apply
to
EPA
for
permission
to
use
alternative
test
methods
or
alternative
monitoring
requirements
in
place
of
any
of
the
EPA
testing
methods,
performance
specifications,
or
procedures.

I.
Executive
Order
13211,
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
Executive
Order
13211,
(
66
FR
28355,
May
22,
2001),
provides
that
agencies
shall
prepare
and
submit
to
the
Administrator
of
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
a
Statement
of
Energy
Effects
for
certain
actions
identified
as
significant
energy
actions.
Section
4(
b)
of
Executive
Order
13211
defines
``
significant
energy
actions''
as
``
any
action
by
an
agency
(
normally
published
in
the
Federal
Register)
that
promulgates
or
is
expected
to
lead
to
the
promulgation
of
a
final
rule
or
regulation,
including
notices
of
inquiry,
advance
notices
of
proposed
rulemaking,
and
notices
of
proposed
rulemaking:
(
1)(
i)
that
is
a
significant
regulatory
action
under
Executive
Order
12866
or
any
successor
order,
and
(
ii)
is
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy;
or
(
2)
that
is
designated
by
the
Administrator
of
the
Office
of
Information
and
Regulatory
Affairs
as
a
significant
energy
action.''
The
proposed
rule
is
not
a
``
significant
regulatory
action''
because
it
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy.
The
basis
for
the
determination
is
as
follows.
The
reduction
in
petroleum
product
output,
which
includes
reductions
in
fuel
production,
is
estimated
at
only
0.001
percent,
or
about
68
barrels
per
day
based
on
2000
U.
S.
fuel
production
nationwide.
That
is
a
minimal
reduction
in
nationwide
petroleum
product
output.
The
reduction
in
coal
production
is
estimated
at
only
0.014
percent,
or
about
3.5
million
tons
per
year
(
or
less
than
1,000
tons
per
day)
based
on
2000
U.
S.
coal
production
nationwide.
The
combination
of
the
increase
in
electricity
usage
estimated
in
section
IV.
C
of
this
preamble
with
the
effect
of
the
increased
price
of
affected
output
yields
an
increase
in
electricity
output
estimated
at
only
0.012
percent,
or
about
0.72
billion
kilowatt­
hours
per
year
based
on
2000
U.
S.
electricity
production
nationwide.
All
energy
price
changes
estimated
show
no
increase
in
price
more
than
0.05
percent
nationwide,
and
a
similar
result
occurs
for
energy
distribution
costs.
We
also
expect
that
there
will
be
no
discernable
impact
on
the
import
of
foreign
energy
supplies,
and
no
other
adverse
outcomes
are
expected
to
occur
with
regards
to
energy
supplies.
All
of
the
results
presented
above
account
for
the
pass
through
of
costs
to
consumers,
as
well
as
the
cost
impact
to
producers.
For
more
information
on
the
estimated
energy
effects,
please
refer
to
the
economic
impact
analysis
for
the
proposed
rule.
The
analysis
is
available
in
the
public
docket.
Therefore,
we
conclude
that
the
proposed
rule
when
implemented
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy.

List
of
Subjects
in
40
CFR
Part
63
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Hazardous
substances,
Intergovernmental
relations,
Reporting
and
recordkeeping
requirements.

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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
Dated:
November
26,
2002.
Christine
Todd
Whitman,
Administrator.

For
the
reasons
stated
in
the
preamble,
title
40,
chapter
I,
part
63
of
the
Code
of
the
Federal
Regulations
is
proposed
to
be
amended
as
follows:

PART
63
 
[
AMENDED]

1.
The
authority
citation
for
part
63
continues
to
read
as
follows:

Authority:
42
U.
S.
C.
7401,
et
seq.

2.
Part
63
is
amended
by
adding
subpart
DDDDD
to
read
as
follows:

Subpart
DDDDD
 
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
What
This
Subpart
Covers
Sec.
63.7480
What
is
the
purpose
of
this
subpart?
63.7485
Am
I
subject
to
this
subpart?
63.7490
What
parts
of
my
facility
does
this
subpart
cover?
63.7495
When
do
I
have
to
comply
with
this
subpart?

Emission
Limitations
and
Work
Practice
Standards
63.7500
What
emission
limitations
and
work
practice
standards
must
I
meet?

General
Compliance
Requirements
63.7505
What
are
my
general
requirements
for
complying
with
this
subpart?

Testing
and
Initial
Compliance
Requirements
63.7510
By
what
date
must
I
conduct
performance
tests
or
other
initial
compliance
demonstrations?
63.7515
When
must
I
conduct
subsequent
performance
tests?
63.7520
What
performance
tests,
design
evaluations,
and
other
procedures
must
I
use?
63.7525
What
are
my
monitoring,
installation,
operation,
and
maintenance
requirements?
63.7530
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations
and
work
practice
standards?

Continuous
Compliance
Requirements
63.7535
How
do
I
monitor
and
collect
data
to
demonstrate
continuous
compliance?
63.7540
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations
and
work
practice
standards?

Notifications,
Reports,
and
Records
63.7545
What
notifications
must
I
submit
and
when?
63.7550
What
reports
must
I
submit
and
when?
63.7555
What
records
must
I
keep?
63.7560
In
what
form
and
how
long
must
I
keep
my
records?

Other
Requirements
and
Information
63.7565
What
parts
of
the
General
Provisions
apply
to
me?
63.7570
Who
implements
and
enforces
this
subpart?
63.7575
What
definitions
apply
to
this
subpart?

Tables
to
Subpart
DDDDD
of
Part
63
Table
1
to
Subpart
DDDDD
of
Part
63
 
Emission
Limits
Table
2.
A
to
Subpart
DDDDD
of
Part
63
 
Operating
Limits
for
Boilers
and
Process
Heaters
in
the
Large,
Limited
Use,
or
Small
Solid
Fuel
Subcategories
Table
2.
B
to
Subpart
DDDDD
of
Part
63
 
Operating
Limits
for
Boilers
and
Process
Heaters
in
the
Large,
Limited
Use,
or
Small
Liquid
Fuel
Subcategories
Table
3
to
Subpart
DDDDD
of
Part
63
 
Work
Practice
Standards
Table
4.
A
to
Subpart
DDDDD
of
Part
63
 
Requirements
for
Performance
Tests
for
Particulate
Matter
Emissions
or
Total
Selected
Metals
Emissions
from
Boilers
or
Process
Heaters
in
Large,
Limited
Use,
or
Small
Solid
Fuel
Subcategories
Table
4.
B
to
Subpart
DDDDD
of
Part
63
 
Requirements
for
Performance
Tests
for
Particulate
Matter
Emissions
from
Boilers
or
Process
Heaters
in
Large,
Limited
Use,
or
Small
Liquid
Fuel
Subcategories
Table
4.
C
to
Subpart
DDDDD
of
Part
63
 
Requirements
for
Performance
Tests
for
Hydrogen
Chloride
Emissions
from
Boilers
or
Process
Heaters
in
Large,
Limited
Use,
or
Small
Solid
Fuel
Subcategories
Table
4.
D
to
Subpart
DDDDD
of
Part
63
 
Requirements
for
Performance
Tests
for
Hydrogen
Chloride
Emissions
from
Boilers
or
Process
Heaters
in
Large,
Limited
Use,
or
Small
Liquid
Fuel
Subcategories
Table
4.
E
to
Subpart
DDDDD
of
Part
63
 
Requirements
for
Performance
Tests
for
Mercury
Emissions
from
Boilers
or
Process
Heaters
in
Large,
Limited
Use,
or
Small
Solid
Fuel
Subcategories
Table
5.
A
to
Subpart
DDDDD
of
Part
63
 
Initial
Compliance
With
Emission
Limitations
for
Particulate
Matter
or
Total
Selected
Metals
for
Boilers
or
Process
Heaters
in
Large,
Limited
Use,
or
Small
Solid
Fuel
Subcategories
Table
5.
B
to
Subpart
DDDDD
of
Part
63
 
Initial
Compliance
With
Emission
Limitations
for
Particulate
Matter
for
Boilers
or
Process
Heaters
in
Large,
Limited
Use,
or
Small
Liquid
Fuel
Subcategories
Table
5.
C
to
Subpart
DDDDD
of
Part
63
 
Initial
Compliance
With
Emission
Limitations
for
Hydrogen
Chloride
for
Boilers
or
Process
Heaters
in
Large,
Limited
Use,
or
Small
Solid
Fuel
Subcategories
Table
5.
D
to
Subpart
DDDDD
of
Part
63
 
Initial
Compliance
With
Emission
Limitations
for
Hydrogen
Chloride
for
Boilers
or
Process
Heaters
in
Large,
Limited
Use,
or
Small
Liquid
Fuel
Subcategories
Table
5.
E
to
Subpart
DDDDD
of
Part
63
 
Initial
Compliance
With
Emission
Limitations
for
Mercury
for
Boilers
or
Process
Heaters
in
Large,
Limited
Use,
or
Small
Solid
Fuel,
Subcategories
Table
6
to
Subpart
DDDDD
of
Part
63
 
Initial
Compliance
with
Work
Practice
Standards
Table
7.
A
to
Subpart
DDDDD
of
Part
63
 
Continuous
Compliance
with
Emission
Limitations
for
Boilers
or
Process
Heaters
in
Large,
Limited
Use,
or
Small
Solid
Fuel
Subcategories
Table
7.
B
to
Subpart
DDDDD
of
Part
63
 
Continuous
Compliance
with
Emission
Limitations
for
Boilers
or
Process
Heaters
in
Large,
Limited
Use,
or
Small
Liquid
Fuel
Subcategories
Table
8
to
Subpart
DDDDD
of
Part
63
 
Continuous
Compliance
with
Work
Practice
Standards
Table
9
to
Subpart
DDDDD
of
Part
63
 
Requirements
for
Reports
Table
10
to
Subpart
DDDDD
of
Part
63
 
Applicability
of
General
Provisions
to
Subpart
DDDDD
Subpart
DDDDD
 
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Industrial,
Commercial,
and
Institutional
Boilers
and
Process
Heaters
What
This
Subpart
Covers
§
63.7480
What
is
the
purpose
of
this
subpart?

This
subpart
establishes
national
emission
limitations
and
work
practice
standards
for
hazardous
air
pollutants
emitted
from
industrial,
commercial,
and
institutional
boilers
and
process
heaters.
This
subpart
also
establishes
requirements
to
demonstrate
initial
and
continuous
compliance
with
the
emission
limitations
and
work
practice
standards.

§
63.7485
Am
I
subject
to
this
subpart?

You
are
subject
to
this
subpart
if
you
own
or
operate
an
industrial,
commercial,
or
institutional
boiler
or
process
heater
that
is
located
at,
or
is
part
of,
a
major
source
of
hazardous
air
pollutants
(
HAP)
emissions,
except
as
specifically
exempted
in
§
63.7490.
(
a)
An
industrial,
commercial,
or
institutional
boiler
is
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.
A
process
heater
is
an
enclosed
device
using
controlled
flame
with
the
unit's
primary
purpose
being
to
transfer
heat
indirectly
to
process
streams
(
liquids,
gases,
or
solids)
instead
of
generating
steam.
(
b)
A
major
source
of
HAP
emissions
is
any
stationary
source
or
group
of
stationary
sources
located
within
a
contiguous
area
and
under
common
control
that
emits
or
has
the
potential
to
emit
any
single
HAP
at
a
rate
of
9.07
megagrams
(
10
tons)
or
more
per
year
or
any
combination
of
HAP
at
a
rate
of
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22.68
megagrams
(
25
tons)
or
more
per
year.

§
63.7490
What
parts
of
my
facility
does
this
subpart
cover?

(
a)
This
subpart
applies
to
each
new,
reconstructed,
or
existing
affected
source.
(
b)
The
affected
source
is
each
industrial,
commercial,
or
institutional
boiler
or
process
heater,
as
defined
in
§
63.7485
that
is
not
one
of
the
types
of
combustion
units
listed
in
§
63.7490(
b)(
1)
through
(
10).
(
1)
A
municipal
waste
combustor
covered
by
40
CFR
part
60,
subpart
AAAA,
subpart
BBBB,
subpart
Eb
or
subpart
Cb.
(
2)
A
hospital/
medical/
infectious
waste
incinerator
covered
by
40
CFR
part
60,
subpart
Ce
or
subpart
Ec.
(
3)
An
electric
utility
steam
generating
unit
that
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.
(
4)
A
boiler
or
process
heater
required
to
have
a
permit
under
section
3005
of
the
Solid
Waste
Disposal
Act
or
covered
by
40
CFR
part
63,
subpart
EEE
(
e.
g.,
hazardous
waste
combustors).
(
5)
A
commercial
and
industrial
solid
waste
incineration
unit
covered
by
40
CFR
part
60,
subpart
CCCC
or
subpart
DDDD.
(
6)
A
recovery
boiler
or
furnace
covered
by
40
CFR
part
63,
subpart
MM.
(
7)
A
boiler
or
process
heater
that
is
used
specifically
for
research
and
development.
This
does
not
include
units
that
only
provide
steam
to
a
process
at
a
research
and
development
facility.
(
8)
A
hot
water
heater
as
defined
in
this
subpart.
(
9)
A
refining
kettle
covered
by
40
CFR
part
63,
subpart
X.
(
10)
An
ethylene
cracking
furnace
covered
by
40
CFR
part
63,
subpart
YY.
(
c)
An
affected
source
is
a
new
affected
source
if
you
commenced
construction
of
the
affected
source
after
January
13,
2003
and
you
meet
the
applicability
criteria
at
the
time
you
commenced
construction.
(
d)
An
affected
source
is
reconstructed
if
you
meet
the
criteria
as
defined
in
§
63.2.
(
e)
An
affected
source
is
existing
if
it
is
not
new
or
reconstructed.
§
63.7495
When
do
I
have
to
comply
with
this
subpart?

(
a)
If
you
have
a
new
or
reconstructed
affected
source,
you
must
comply
with
this
subpart
according
to
paragraph
(
a)(
1)
or
(
2)
of
this
section.
(
1)
If
you
start
up
your
affected
source
before
[
DATE
THE
FINAL
RULE
IS
PUBLISHED
IN
THE
FEDERAL
REGISTER],
then
you
must
comply
with
the
emission
limitations
and
work
practice
standards
for
new
and
reconstructed
sources
in
this
subpart
no
later
than
[
DATE
THE
FINAL
RULE
IS
PUBLISHED
IN
THE
FEDERAL
REGISTER].
(
2)
If
you
startup
your
affected
source
after
[
DATE
THE
FINAL
RULE
IS
PUBLISHED
IN
THE
FEDERAL
REGISTER],
then
you
must
comply
with
the
emission
limitations
and
work
practice
standards
for
new
and
reconstructed
sources
in
this
subpart
upon
startup
of
your
affected
source.
(
b)
If
you
have
an
existing
affected
source,
you
must
comply
with
the
emission
limitations
for
existing
sources
no
later
than
3
years
after
[
DATE
THE
FINAL
RULE
IS
PUBLISHED
IN
THE
FEDERAL
REGISTER].
(
c)
If
you
have
an
area
source
that
increases
its
emissions
or
its
potential
to
emit
such
that
it
becomes
a
major
source
of
HAP,
paragraphs
(
c)(
1)
and
(
2)
of
this
section
apply
to
you.
(
1)
Any
new
or
reconstructed
boiler
or
process
heater
at
the
existing
facility
must
be
in
compliance
with
this
subpart
upon
startup.
(
2)
Any
existing
boiler
or
process
heater
at
the
existing
facility
must
be
in
compliance
with
this
subpart
within
3
years
after
the
facility
becomes
a
major
source.
(
d)
You
must
meet
the
notification
requirements
in
§
63.7545
according
to
the
schedule
in
§
63.7545
and
in
subpart
A
of
this
part.
Some
of
the
notifications
must
be
submitted
before
you
are
required
to
comply
with
the
emission
limitations
and
work
practice
standards
in
this
subpart.

Emission
Limitations
and
Work
Practice
Standards
§
63.7500
What
emission
limitations
and
work
practice
standards
must
I
meet?

(
a)
You
must
meet
the
requirements
in
paragraphs
(
a)(
1)
through
(
3)
of
this
section.
(
1)
You
must
meet
each
emission
limit
in
Table
1
to
this
subpart
that
applies
to
you.
(
2)
You
must
meet
each
operating
limit
in
Tables
2.
A
and
2.
B
to
this
subpart
that
applies
to
you.
If
you
use
a
control
device
or
combination
of
control
devices
not
covered
in
Tables
2.
A
or
2.
B
to
this
subpart,
or
you
wish
to
establish
and
monitor
an
alternative
operating
limit
and
alternative
monitoring
parameters,
you
must
apply
to
the
Administrator
for
approval
of
alternative
monitoring
under
§
63.8(
f).
(
3)
You
must
meet
each
work
practice
standard
in
Table
3
to
this
subpart
that
applies
to
you.
(
b)
If
your
new
or
reconstructed
boiler
or
process
heater
is
in
one
of
the
liquid
fuel
subcategories
(
the
large
liquid
fuel
subcategory,
the
limited
use
liquid
fuel
subcategory,
or
the
small
liquid
fuel
subcategory)
and
burns
only
fossil
fuels
and
other
gases
and
does
not
burn
any
residual
oil,
you
are
subject
to
the
emission
limits
in
Table
1
to
this
subpart,
but
you
are
not
required
to
conduct
a
performance
test
to
demonstrate
compliance
with
the
emission
limits.
However,
you
must
meet
all
applicable
requirements
in
§
§
63.7530
and
63.7535.
(
c)
As
provided
in
§
63.6(
g),
the
Environmental
Protection
Agency
(
EPA)
may
choose
to
grant
you
permission
to
use
an
alternative
to
the
work
practice
standards
in
this
section.

General
Compliance
Requirements
§
63.7505
What
are
my
general
requirements
for
complying
with
this
subpart?
(
a)
You
must
be
in
compliance
with
the
emission
limitations
(
including
operating
limits)
and
the
work
practice
standards
in
this
subpart
at
all
times,
except
during
periods
of
startup,
shutdown,
and
malfunction.
(
b)
You
must
always
operate
and
maintain
your
affected
source,
including
air
pollution
control
and
monitoring
equipment,
according
to
the
provisions
in
§
63.6(
e)(
1)(
i).
(
c)
You
must
develop
a
site­
specific
monitoring
plan
according
to
the
requirements
in
paragraphs
(
c)(
1)
through
(
4)
of
this
section.
(
1)
For
each
monitoring
system
required
in
this
section,
you
must
develop
and
submit
for
approval
a
sitespecific
monitoring
plan
that
addresses
paragraphs
(
c)(
1)(
i)
through
(
iii)
of
this
section.
(
i)
Installation
of
the
continuous
monitoring
system
(
CMS)
sampling
probe
or
other
interface
at
a
measurement
location
relative
to
each
affected
process
unit
such
that
the
measurement
is
representative
of
control
of
the
exhaust
emissions
(
e.
g.,
on
or
downstream
of
the
last
control
device);
(
ii)
Performance
and
equipment
specifications
for
the
sample
interface,
the
pollutant
concentration
or
parametric
signal
analyzer,
and
the
data
collection
and
reduction
systems;
and
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/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
(
iii)
Performance
evaluation
procedures
and
acceptance
criteria
(
e.
g.,
calibrations).
(
2)
In
your
site­
specific
monitoring
plan,
you
must
also
address
paragraphs
(
c)(
2)(
i)
through
(
iii)
of
this
section.
(
i)
Ongoing
operation
and
maintenance
procedures
in
accordance
with
the
general
requirements
of
§
63.8(
c)(
1),
(
c)(
3),
and
(
c)(
4)(
ii);
(
ii)
Ongoing
data
quality
assurance
procedures
in
accordance
with
the
general
requirements
of
§
63.8(
d);
and
(
iii)
Ongoing
recordkeeping
and
reporting
procedures
in
accordance
with
the
general
requirements
of
§
63.10(
c),
(
e)(
1)
and
(
e)(
2)(
i).
(
3)
You
must
conduct
a
performance
evaluation
of
each
CMS
in
accordance
with
your
site­
specific
monitoring
plan.
(
4)
You
must
operate
and
maintain
the
CMS
in
continuous
operation
according
to
the
site­
specific
monitoring
plan.
(
d)
You
must
develop
and
implement
a
written
startup,
shutdown,
and
malfunction
plan
(
SSMP)
according
to
the
provisions
in
§
63.6(
e)(
3).

Testing
and
Initial
Compliance
Requirements
§
63.7510
By
what
date
must
I
conduct
performance
tests
or
other
initial
compliance
demonstrations?

(
a)
For
each
existing
affected
source,
you
must
conduct
performance
tests,
set
operating
limits,
and
conduct
monitoring
equipment
performance
evaluations
by
the
compliance
date
that
is
specified
for
your
source
in
§
63.7495
and
according
to
the
applicable
provisions
in
§
63.7(
a)(
2)
as
cited
in
Table
10
to
this
subpart.
(
b)
For
each
new
or
reconstructed
affected
source,
you
must
conduct
performance
tests,
set
operating
limits,
and
conduct
monitoring
equipment
performance
evaluations
within
180
calendar
days
after
the
compliance
date
that
is
specified
for
your
source
in
§
63.7495
and
according
to
the
provisions
in
§
63.7(
a)(
2)
as
cited
in
Table
10
to
this
subpart.

§
63.7515
When
must
I
conduct
subsequent
performance
tests?

(
a)
You
must
conduct
all
applicable
performance
tests
according
to
the
procedures
in
§
63.7520
on
an
annual
basis
unless
you
follow
the
requirements
listed
in
paragraphs
(
b)
through
(
h)
of
this
section.
The
first
subsequent
performance
tests
must
be
completed
within
12
months
of
the
initial
performance
test
but
no
earlier
than
10
months
after
the
initial
performance
test
and
every
12
months
thereafter,
unless
you
follow
the
requirements
listed
in
paragraphs
(
b)
through
(
h)
of
this
section.
(
b)
You
can
conduct
performance
tests
less
often
for
a
given
pollutant
if
you
have
test
data
for
at
least
3
years,
and
all
stack
tests
for
the
pollutant
(
particulate
matter,
hydrogen
chloride,
mercury,
or
total
selected
metals)
for
over
3
consecutive
years
show
that
you
comply
with
the
emission
limit.
In
this
case,
you
do
not
have
to
conduct
a
stack
test
for
that
pollutant
for
the
next
2
years.
You
must
do
a
stack
test
during
the
third
year
and
no
more
than
36
months
following
the
previous
stack
test.
(
c)
If
your
boiler
or
process
heater
continues
to
meet
the
emission
limit
for
particulate
matter,
hydrogen
chloride,
mercury,
or
total
selected
metals,
you
may
choose
to
conduct
stack
tests
for
these
pollutants
every
third
year,
but
each
such
test
must
be
within
36
months
of
the
previous
stack
test.
(
d)
If
a
stack
test
shows
noncompliance
with
an
emission
limit
for
particulate
matter,
hydrogen
chloride,
mercury,
or
total
selected
metals,
you
must
conduct
annual
stack
tests
for
that
pollutant
until
all
stack
tests
over
a
3­
year
period
show
compliance.
(
e)
You
are
not
required
to
conduct
a
performance
test
for
total
selected
metals
annually
if
you
choose
to
comply
with
the
alternative
total
selected
metals
emission
limit
instead
of
particulate
matter,
and
your
operating
limit
is
the
total
selected
metals
fuel
input.
You
must
still
meet
all
applicable
continuous
compliance
requirements
in
§
63.7540.
(
f)
You
are
not
required
to
conduct
a
performance
test
for
hydrogen
chloride
annually
if
your
operating
limit
for
hydrogen
chloride
is
chlorine
fuel
input.
You
must
still
meet
all
applicable
continuous
compliance
requirements
in
§
63.7540.
(
g)
You
are
not
required
to
conduct
a
performance
test
for
mercury
annually
if
your
operating
limit
for
mercury
is
mercury
fuel
input.
You
must
still
meet
all
applicable
continuous
compliance
requirements
in
§
63.7540.
(
h)
You
must
report
the
results
of
annual
performance
tests
within
60
days
after
the
completion
of
the
tests.
This
report
should
also
verify
that
the
operating
limits
for
your
affected
source
have
not
changed
or
provide
documentation
of
revised
operating
parameters
established
as
specified
in
Tables
4.
A
through
4.
E
to
this
subpart.
The
reports
for
all
subsequent
performance
tests
should
include
all
applicable
information
required
in
§
63.7550.
§
63.7520
What
performance
tests,
design
evaluations,
and
other
procedures
must
I
use?

(
a)
You
must
conduct
all
performance
tests
according
to
§
63.7(
c),
(
d),
(
f),
and
(
h).
You
must
also
develop
a
sitespecific
test
plan
according
to
the
requirements
in
§
63.7(
c).
(
b)
You
must
conduct
each
performance
test
in
Tables
4.
A
through
4.
E
to
this
subpart
that
applies
to
you.
(
c)
For
boilers
or
process
heaters
in
one
of
the
liquid
fuel
subcategories
that
burn
only
fossil
fuels
and
other
gases
and
do
not
burn
any
residual
oil,
you
are
not
required
to
conduct
a
performance
test
to
demonstrate
compliance
with
the
emission
limits.
(
d)
You
must
conduct
each
performance
test
under
the
specific
conditions
listed
in
Tables
4.
A
through
4.
E
to
this
subpart.
You
must
conduct
performance
tests
at
the
representative
process
operating
conditions
that
are
expected
to
result
in
the
highest
emissions
of
hydrogen
chloride,
particulate
matter,
and
mercury,
and
you
must
demonstrate
initial
compliance
and
establish
your
operating
limits
based
on
this
test.
This
requirement
could
result
in
the
need
to
conduct
more
than
one
performance
test.
If
you
choose
to
comply
with
the
alternative
total
selected
metals
emission
limit
instead
of
particulate
matter,
you
must
conduct
all
performance
tests
at
the
representative
process
operating
conditions
that
are
expected
to
result
in
the
highest
emissions
of
hydrogen
chloride,
total
selected
metals
and
mercury.
(
e)
You
may
not
conduct
performance
tests
during
periods
of
startup,
shutdown,
or
malfunction.
(
f)
You
must
conduct
three
separate
test
runs
for
each
performance
test
required
in
this
section,
as
specified
in
§
63.7(
e)(
3).
Each
test
run
must
last
at
least
1
hour.
(
g)
To
determine
compliance
with
the
emission
limits,
you
must
use
the
FFactor
methodology
and
equations
in
sections
12.2
and
12.3
of
EPA
Method
19
of
appendix
A
of
this
part
to
convert
the
measured
particulate
matter
concentrations,
the
measured
hydrogen
chloride
concentrations,
the
measured
total
selected
metals
concentrations,
and
the
measured
mercury
concentrations
that
result
from
the
initial
performance
test
to
pound
per
million
British
thermal
unit
(
MMBtu)
heat
input
emission
rates.
Method
26A
of
appendix
A
of
this
part
must
be
used
for
the
hydrogen
chloride
performance
test
for
those
boilers
and
process
heaters
with
wet
scrubbers.
All
other
boilers
and
process
heaters
must
use
Method
26
of
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Federal
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/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
appendix
A
of
this
part
for
the
hydrogen
chloride
performance
test.
(
h)
For
performance
tests
using
Method
5,
Method
29,
Method
26A
and
Method
17
of
appendix
A
of
this
part,
use
Method
1
of
appendix
A
of
this
part
to
select
the
sampling
location
and
number
of
traverse
points.
For
Method
26
of
appendix
A
of
this
part,
you
must
use
a
minimum
of
three
traverse
points.
(
i)
If
you
use
a
control
device
or
combination
of
control
devices
not
covered
in
Tables
4.
A
through
4.
E
to
this
subpart,
or
you
wish
to
establish
and
monitor
an
alternative
operating
limit,
you
must
apply
to
the
Administrator
for
approval
of
alternative
monitoring
under
§
63.8(
f).

§
63.7525
What
are
my
monitoring,
installation,
operation,
and
maintenance
requirements?

(
a)
Each
continuous
emissions
monitoring
system
(
CEMS)
for
carbon
monoxide
must
be
installed,
operated,
and
maintained
according
to
the
procedures
in
paragraphs
(
a)(
1)
through
(
4)
of
this
section
by
the
compliance
date.
(
1)
Each
CEMS
must
be
installed,
operated,
and
maintained
according
to
Performance
Specification
(
PS)
4A
of
40
CFR
part
60,
appendix
B,
and
according
to
the
site­
specific
monitoring
plan
developed
according
to
§
63.7505(
c).
(
2)
You
must
conduct
a
performance
evaluation
of
each
CEMS
according
to
the
requirements
in
§
63.8
and
according
to
PS
4A
of
40
CFR
part
60,
appendix
B.
(
3)
Each
CEMS
must
complete
a
minimum
of
one
cycle
of
operation
(
sampling,
analyzing,
and
data
recording)
for
each
successive
15­
minute
period.
(
4)
The
CEMS
data
must
be
reduced
as
specified
in
§
63.8(
g)(
2).
(
b)
Each
continuous
opacity
monitoring
system
(
COMS)
must
be
installed,
operated,
certified
and
maintained
according
to
the
procedures
in
paragraphs
(
b)(
1)
through
(
7)
of
this
section
by
the
compliance
date.
(
1)
Each
COMS
must
be
installed,
operated,
and
maintained
according
to
PS
1
of
40
CFR
part
60,
appendix
B.
(
2)
You
must
conduct
a
performance
evaluation
of
each
COMS
according
to
the
requirements
in
§
63.8
and
according
to
PS
1
of
40
CFR
part
60,
appendix
B.
(
3)
As
specified
in
§
63.8(
c)(
4)(
i),
each
COMS
must
complete
a
minimum
of
one
cycle
of
sampling
and
analyzing
for
each
successive
10­
second
period
and
one
cycle
of
data
recording
for
each
successive
6­
minute
period.
(
4)
The
COMS
data
must
be
reduced
as
specified
in
§
63.8(
g)(
2).
(
5)
You
must
include
in
your
sitespecific
monitoring
plan
procedures
and
acceptance
criteria
for
operating
and
maintaining
each
COMS
according
to
the
requirements
in
§
63.8(
d).
At
a
minimum,
the
monitoring
plan
must
include
a
daily
calibration
drift
assessment,
a
quarterly
performance
audit,
and
an
annual
zero
alignment
audit
of
each
COMS.
(
6)
You
must
operate
and
maintain
each
COMS
according
to
the
requirements
in
the
monitoring
plan
and
the
requirements
of
§
63.8(
e).
Identify
periods
the
COMS
is
out­
ofcontrol
including
any
periods
that
the
COMS
fails
to
pass
a
daily
calibration
drift
assessment,
a
quarterly
performance
audit,
or
an
annual
zero
alignment
audit.
(
7)
You
must
determine
and
record
all
the
6­
minute
averages
and
3­
hour
block
averages
collected
for
periods
during
which
the
COMS
is
not
out­
of­
control.
(
c)
You
must
install,
operate,
and
maintain
each
continuous
parameter
monitoring
system
(
CPMS)
according
to
the
requirements
in
§
63.8
and
the
procedures
in
paragraphs
(
c)(
1)
through
(
5)
of
this
section
by
the
compliance
date
specified
in
§
63.7495.
(
1)
The
CPMS
must
complete
a
minimum
of
one
cycle
of
operation
for
each
successive
15­
minute
period.
You
must
have
a
minimum
of
four
successive
cycles
of
operation
to
have
a
valid
hour
of
data.
(
2)
Except
for,
monitoring
malfunctions,
associated
repairs
and
required
quality
assurance
or
control
activities
(
including,
as
applicable,
calibration
checks
and
required
zero
and
span
adjustments),
you
must
conduct
all
monitoring
in
continuous
operation
at
all
times
that
the
unit
is
operating.
A
monitoring
malfunction
is
any
sudden,
infrequent,
not
reasonably
preventable
failure
of
the
monitoring
system
to
provide
valid
data.
Monitoring
failures
that
are
caused
in
part
by
poor
maintenance
or
careless
operation
are
not
malfunctions.
(
3)
For
purposes
of
calculating
data
averages,
you
must
not
use
data
recorded
during
monitoring
malfunctions,
associated
repairs,
out­
ofcontrol
periods,
or
required
quality
assurance
or
control
activities.
You
must
use
all
the
data
collected
during
all
other
periods
in
assessing
compliance.
Any
period
for
which
the
monitoring
system
is
out­
of­
control
and
data
are
not
available
for
required
calculations
constitutes
a
deviation
from
the
monitoring
requirements.
(
4)
Determine
the
3­
hour
block
average
of
all
recorded
readings,
except
as
provided
in
paragraph
(
c)(
3)
of
this
section.
(
5)
Record
the
results
of
each
inspection,
calibration,
and
validation
check.
(
d)
For
the
equipment
to
monitor
voltage
and
secondary
current
(
or
total
power
input)
of
the
electrostatic
precipitator
(
ESP),
you
must
meet
the
requirements
in
paragraphs
(
c)
and
(
d)(
1)
and
(
2)
of
this
section.
(
1)
Use
the
ESP
manufacturer's
installed
voltage
and
secondary
current
monitoring
equipment
to
measure
voltage
and
secondary
current
to
the
ESP.
(
2)
At
least
monthly,
inspect
all
components
of
the
CPMS
for
integrity
and
all
electrical
connections
for
continuity.
(
e)
For
the
equipment
to
monitor
sorbent
injection
rate
(
e.
g.,
weigh
belt,
weigh
hopper,
or
hopper
flow
measurement
device),
you
must
meet
the
requirements
in
paragraphs
(
c)
and
(
e)(
1)
through
(
4)
of
this
section.
(
1)
Locate
the
device
in
a
position(
s)
that
provides
a
representative
measurement
of
the
total
sorbent
injection
rate.
(
2)
Install
and
calibrate
the
device
in
accordance
with
manufacturer's
procedures
and
specifications.
(
3)
At
least
monthly,
inspect
all
components
for
integrity
and
all
electrical
connections
for
continuity.
(
4)
At
least
annually,
calibrate
the
device
in
accordance
with
the
manufacturer's
procedures
and
specifications.
(
f)
If
you
use
a
fabric
filter
to
comply
with
the
requirements
of
this
subpart,
you
must
install,
calibrate,
maintain,
and
continuously
operate
a
bag
leak
detection
system
as
specified
in
paragraphs
(
f)(
1)
through
(
8)
of
this
section.
(
1)
You
must
install
and
operate
a
bag
leak
detection
system
for
each
exhaust
stack
of
the
fabric
filter.
(
2)
Each
bag
leak
detection
system
must
be
installed,
operated,
calibrated,
and
maintained
in
a
manner
consistent
with
the
manufacturer's
written
specifications
and
recommendations
and
in
accordance
with
the
guidance
provided
in
``
Fabric
Filter
Bag
Leak
Detection
Guidance,''
EPA
 
454/
R
 
98
 
015,
September
1997.
(
3)
The
bag
leak
detection
system
must
be
certified
by
the
manufacturer
to
be
capable
of
detecting
particulate
matter
emissions
at
concentrations
of
10
milligrams
per
actual
cubic
meter
or
less.
(
4)
The
bag
leak
detection
system
sensor
must
provide
output
of
relative
or
absolute
particulate
matter
loadings.
(
5)
The
bag
leak
detection
system
must
be
equipped
with
a
device
to
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FM\
13JAP2.
SGM
13JAP2
1707
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
continuously
record
the
output
signal
from
the
sensor.
(
6)
The
bag
leak
detection
system
must
be
equipped
with
an
alarm
system
that
will
sound
automatically
when
an
increase
in
relative
particulate
matter
emissions
over
a
preset
level
is
detected.
The
alarm
must
be
located
where
it
is
easily
heard
by
plant
operating
personnel.
(
7)
For
positive
pressure
fabric
filter
systems,
a
bag
leak
detection
system
must
be
installed
in
each
baghouse
compartment
or
cell.
For
negative
pressure
or
induced
air
fabric
filters,
the
bag
leak
detector
must
be
installed
downstream
of
the
fabric
filter.
(
8)
Where
multiple
detectors
are
required,
the
system's
instrumentation
and
alarm
may
be
shared
among
detectors.

§
63.7530
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations
and
work
practice
standards?

(
a)
You
must
demonstrate
initial
compliance
with
each
emission
limitation
and
work
practice
standard
that
applies
to
you
according
to
Tables
5.
A
through
5.
E
and
6
to
this
subpart.
(
b)
For
new
or
reconstructed
boilers
or
process
heaters
in
one
of
the
liquid
fuel
subcategories
that
burn
only
fossil
fuels
and
other
gases
and
do
not
burn
any
residual
oil,
you
are
not
required
to
conduct
a
performance
test
to
demonstrate
compliance
with
the
emission
limits.
(
1)
To
demonstrate
initial
compliance,
you
must
include
a
signed
statement
in
the
Notification
of
Compliance
Status
report
required
in
§
63.7545(
e)
that
indicates
you
burn
only
liquid
fossil
fuels
other
than
residual
oils
either
alone
or
in
combination
with
gaseous
fuels.
(
2)
You
must
also
keep
records,
as
required
in
§
63.7555,
that
demonstrate
that
you
burn
only
liquid
fossil
fuels
other
than
residual
oils
either
alone
or
in
combination
with
gaseous
fuels.
(
c)
You
must
establish
each
sitespecific
operating
limit
in
Tables
2.
A
and
2.
B
to
this
subpart
that
applies
to
you
according
to
the
requirements
in
§
63.7520,
Tables
4.
A
through
4.
E
to
this
subpart,
and
paragraphs
(
c)(
1)
through
(
6)
of
this
section,
as
applicable.
(
1)
If
you
do
not
use
a
wet
or
dry
scrubber,
you
must
set
your
operating
limit
for
hydrogen
chloride
emissions
based
on
the
chlorine
fuel
input
established
during
the
initial
performance
test
according
to
the
procedures
in
paragraphs
(
c)(
1)(
i)
and
(
ii)
of
this
section.
(
i)
During
the
initial
performance
test
for
hydrogen
chloride,
you
must
measure
the
average
hourly
fuel
input,
average
chlorine
concentration,
and
average
heat
input
of
each
fuel
burned
during
the
3­
hour
performance
test.
(
ii)
You
must
set
your
operating
limit
for
hydrogen
chloride
using
Equation
1
of
this
section:

Cl
C
Q
H
(
Eq.
1)
input
i
i
v,
i
i=
1
n
=
(
)(
)
 
 
 
 
 
 
 
 
 

Where:
Clinput
=
Average
amount
of
chlorine
entering
the
boiler
or
process
heater
through
fuels
burned
in
units
of
pounds
per
Btu.
This
is
the
operating
limit.
Ci
=
Average
concentration
of
chlorine
in
fuel,
i,
during
each
of
the
three
1­
hour
test
periods
as
measured
using
the
test
methods
specified
in
Tables
4.
C
and
4.
D
to
this
subpart,
in
units
of
pound
per
pound
for
solid
fuels,
pounds
per
gallon
for
liquid
fuels,
or
pound
per
dry
standard
cubic
foot
for
gaseous
fuels.
Qi
=
Average
hourly
input
of
fuel,
i,
during
each
of
the
three
1­
hour
test
periods
in
units
of
pound
per
hour
for
solid
fuels,
gallons
per
hour
for
liquid
fuels,
or
dry
standard
cubic
feet
per
hour
for
gaseous
fuels.
If
you
do
not
burn
multiple
fuels
during
the
performance
test,
it
is
not
necessary
to
determine
the
value
of
this
term.
Insert
a
value
of
``
1''
for
Qi.
Hv,
i
=
Average
heat
input
of
fuel,
i,
during
each
of
the
three
1­
hour
test
periods
in
units
of
Btu
per
hour
as
measured
by
the
test
methods
indicated
in
Tables
4.
C
and
4.
D
to
this
subpart.
n
=
Number
of
different
fuel
types
in
the
worst­
case
fuel
input
stream
burned
during
each
of
the
three
1­
hour
performance
tests.

(
2)
If
you
do
not
use
a
wet
scrubber,
you
must
establish
an
opacity
operating
limit
during
the
initial
performance
test
for
particulate
matter
or
total
selected
metals
and
mercury.
This
opacity
level
must
not
exceed
20
percent.
(
3)
If
you
use
a
wet
scrubber
and
you
conduct
separate
performance
tests
for
particulate
matter,
hydrogen
chloride,
and
mercury
emissions,
you
must
establish
one
set
of
operating
limits
for
pH,
liquid
flow­
rate,
and
pressure
drop.
The
pH
must
be
the
level
established
during
the
hydrogen
chloride
performance
test.
The
liquid
flow­
rate
and
pressure
drop
operating
limits
must
be
the
highest
of
the
values
established
during
the
performance
tests.
(
4)
If
you
do
not
use
a
control
device
or
do
not
want
to
take
credit
for
the
control
device
and
you
choose
to
comply
with
the
alternative
total
selected
metals
emission
limit
instead
of
particulate
matter,
you
must
set
your
operating
limit
for
total
selected
metals
emissions
based
on
the
metals
fuel
input
established
during
the
initial
performance
test
according
to
the
procedures
in
paragraphs
(
c)(
4)(
i)
and
(
ii)
of
this
section.
(
i)
During
the
initial
performance
test
for
total
selected
metals,
you
must
measure
the
average
hourly
fuel
input
if
you
burn
a
combination
of
multiple
fuels,
average
total
selected
metals
concentration
of
the
fuel
input,
and
average
heat
input
of
each
fuel
burned
during
the
3­
hour
performance
test.
(
ii)
You
must
set
your
operating
limit
for
total
selected
metals
using
Equation
2
of
this
section:

Metals
M
Q
H
(
Eq.
2)
input
i
i
v,
i
i=
1
n
=
(
)(
)
 
 
 
 
 
 
 
 
 

Where:

Metalsinput
=
Average
amount
of
total
selected
metals
entering
the
boiler
or
process
heater
through
fuels
burned
in
units
of
pounds
per
Btu.
This
is
the
operating
limit.
Mi
=
Average
concentration
of
total
selected
metals
in
fuel,
i,
during
each
of
the
three
1­
hour
test
periods
as
measured
using
the
test
methods
specified
in
Table
4.
E
to
this
subpart,
in
units
of
pound
per
pound
for
solid
fuels,
pound
per
gallon
for
liquid
fuels,
or
pound
per
dry
standard
cubic
foot
for
gaseous
fuels.
Qi
=
Average
hourly
input
of
fuel,
i,
during
each
of
the
three
1­
hour
test
periods
in
units
of
pounds
per
hour
for
solid
fuels,
gallons
per
hour
for
liquid
fuels,
or
dry
standard
cubic
feet
per
hour
for
gaseous
fuels.
If
you
do
not
burn
multiple
fuels
during
the
performance
test,
it
is
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1708
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
not
necessary
to
determine
the
value
of
this
term.
Insert
a
value
of
``
1''
for
Qi.
Hv,
i
=
Average
heat
input
of
fuel,
i,
during
each
of
the
three
1­
hour
test
periods
in
units
of
Btu
per
hour
as
measured
by
the
test
methods
indicated
in
Table
4.
E
to
this
subpart.
n
=
Number
of
different
fuel
types
in
the
worst­
case
fuel
input
stream
burned
during
the
3­
hour
performance
test.
(
5)
If
you
do
not
use
a
control
device
or
do
not
want
to
take
credit
for
the
control
device,
you
must
set
your
operating
limit
for
mercury
emissions
based
on
the
mercury
fuel
input
established
during
the
initial
performance
test
according
to
the
procedures
in
paragraphs
(
c)(
5)(
i)
and
(
ii)
of
this
section.
(
i)
During
the
initial
performance
test
for
mercury,
you
must
measure
the
average
hourly
fuel
input
if
you
burn
a
combination
of
multiple
fuels,
average
mercury
concentration
of
the
fuel
input,
and
average
heat
input
of
each
fuel
burned
during
the
3­
hour
performance
test.
(
ii)
You
must
set
your
operating
limit
for
mercury
using
Equation
3
of
this
section:

Mercury
Q
H
Eq.
3)
input
i
v,
i
=
(
)(
)
 
 
 
 
 
 
 
 
=
 
HGi
i
n
(

1
Where:
Mercuryinput
=
Average
amount
of
mercury
entering
the
boiler
or
process
heater
through
fuels
burned
in
units
of
pounds
per
Btu.
This
is
the
operating
limit.
HGi
=
Average
concentration
of
mercury
in
fuel,
i,
during
each
of
the
three
1­
hour
test
periods
as
measured
using
the
test
methods
specified
in
Table
4.
E
to
this
subpart,
in
units
of
pound
per
pound
for
solid
fuels,
pound
per
gallon
for
liquid
fuels,
or
pound
per
dry
standard
cubic
foot
for
gaseous
fuels.
Qi
=
Average
hourly
input
of
fuel,
i,
during
each
of
the
three
1­
hour
test
periods
in
units
of
pounds
per
hour
for
solid
fuels,
gallons
per
hour
for
liquid
fuels,
or
dry
standard
cubic
feet
per
hour
for
gaseous
fuels.
If
you
do
not
burn
multiple
fuels
during
the
performance
test,
it
is
not
necessary
to
determine
the
value
of
this
term.
Insert
a
value
of
``
1''
for
Qi.
Hv,
i
=
Average
heat
input
of
fuel,
i,
during
each
of
the
three
1­
hour
test
periods
in
units
of
Btu
per
hour
as
measured
by
the
test
methods
indicated
in
Table
4.
E
to
this
subpart.
n
=
Number
of
different
fuel
types
in
the
worst­
case
fuel
input
stream
burned
during
the
3­
hour
performance
test.
(
6)
You
must
establish
parameter
operating
limits
according
to
paragraphs
(
c)(
6)(
i)
through
(
v)
of
this
section.
(
i)
To
establish
an
opacity
operating
limit,
you
must
set
the
maximum
opacity
operating
limit
equal
to
the
maximum
1­
hour
average
opacity
value
measured
during
the
three­
run
performance
test
for
particulate
matter
or
total
selected
metals
and
mercury,
or
20
percent,
whichever
is
lower.
(
ii)
To
establish
operating
limits
for
a
wet
scrubber,
you
must
set
the
minimum
operating
limits
for
pH,
liquid
flow­
rate,
and
pressure
drop
equal
to
the
minimum
1­
hour
average
values
measured
during
the
three­
run
performance
test.
(
iii)
To
establish
operating
limits
for
an
electrostatic
precipitator,
you
must
set
the
minimum
operating
limits
for
voltage
and
secondary
current
(
or
total
power
input)
equal
to
the
minimum
1­
hour
average
values
measured
during
the
three­
run
performance
test.
(
iv)
To
establish
operating
limits
for
a
dry
scrubber,
you
must
set
the
minimum
sorbent
injection
rate
operating
limit
equal
to
the
minimum
1­
hour
average
value
measured
during
the
three­
run
performance
test.
(
v)
The
operating
limit
for
fabric
filters
requires
that
a
bag
leak
detection
system
be
installed
according
to
the
requirements
in
§
63.7525,
and
that
each
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
a
6­
month
period.
(
d)
You
must
submit
the
Notification
of
Compliance
Status
report
containing
the
results
of
the
initial
compliance
demonstration
according
to
the
requirements
in
§
63.7545(
e).

Continuous
Compliance
Requirements
§
63.7535
How
do
I
monitor
and
collect
data
to
demonstrate
continuous
compliance?
(
a)
You
must
monitor
and
collect
data
according
to
this
section.
(
b)
Except
for
monitor
malfunctions,
associated
repairs,
and
required
quality
assurance
or
control
activities
(
including,
as
applicable,
calibration
checks
and
required
zero
and
span
adjustments),
you
must
monitor
continuously
(
or
collect
data
at
all
required
intervals)
at
all
times
that
the
affected
source
is
operating.
(
c)
You
may
not
use
data
recorded
during
monitoring
malfunctions,
associated
repairs,
or
required
quality
assurance
or
control
activities,
in
data
averages
and
calculations
used
to
report
emission
or
operating
levels.
You
must
use
all
the
data
collected
during
all
other
periods
in
assessing
the
operation
of
the
control
device
and
associated
control
system.

§
63.7540
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations
and
work
practice
standards?

(
a)
You
must
demonstrate
continuous
compliance
with
each
emission
limit,
operating
limit,
and
work
practice
standard
in
Tables
1
through
3
to
this
subpart
that
applies
to
you
according
to
the
methods
specified
in
Tables
7.
A,
7.
B,
and
8
to
this
subpart
and
paragraphs
(
a)(
1)
through
(
9)
of
this
section.
(
1)
For
affected
sources
electing
to
comply
with
an
emission
limit
based
on
fuel
analysis,
you
must
keep
records
of
all
fuels
burned
in
each
boiler
or
process
heater
during
the
reporting
period
to
demonstrate
that
all
fuels
used
would
result
in
lower
emissions
of
particulate
matter
or
total
selected
metals,
lower
emissions
of
hydrogen
chloride,
and
lower
emissions
of
mercury
than
the
emissions
from
the
worst­
case
fuel
input
that
was
burned
during
the
initial
performance
test.
You
must
also
keep
records
that
demonstrate
that
all
fuels
burned
during
the
reporting
period
were
obtained
from
the
same
suppliers
as
those
fuels
burned
during
the
performance
test.
(
2)
For
new
or
reconstructed
boilers
or
process
heaters
in
one
of
the
liquid
fuel
subcategories
that
burn
only
fossil
fuels
and
other
gases
and
do
not
burn
any
residual
oil,
you
are
not
required
to
set
and
maintain
operating
limits
to
demonstrate
continuous
compliance
with
the
emission
limits.
To
demonstrate
continuous
compliance
with
the
emission
limits,
you
must
include
a
signed
statement
in
each
semiannual
compliance
report
required
in
§
63.7550
that
indicates
you
burned
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EP13JA03.002</
GPH>
1709
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
only
liquid
fossil
fuels
other
than
residual
oils,
either
alone
or
in
combination
with
gaseous
fuels,
during
the
reporting
period;
and
you
must
also
keep
records,
as
required
in
paragraph
(
a)(
1)
of
this
section
and
§
63.7555,
that
demonstrate
that
you
burn
only
liquid
fossil
fuels
other
than
residual
oils,
either
alone
or
in
combination
with
gaseous
fuels.
(
3)
If
you
plan
to
burn
a
new
type
of
fuel,
a
fuel
from
a
new
supplier,
or
a
new
mixture
of
fuels
and
your
operating
limit
for
hydrogen
chloride
is
chlorine
input,
you
must
demonstrate
continuous
compliance
by
recalculating
the
chlorine
input
using
Equation
1
of
§
63.7530
according
to
the
procedures
specified
in
paragraphs
(
a)(
3)(
i)
through
(
iii)
of
this
section.
(
i)
Determine
for
any
new
fuel
the
heating
value
and
the
chlorine
concentration,
based
on
supplier
data
or
own
fuel
analysis,
according
to
the
provisions
in
the
site­
specific
test
plan
developed
according
to
the
requirements
in
§
63.7520(
a).
(
ii)
Estimate
the
maximum
hourly
input
at
which
each
fuel
will
be
burned.
(
iii)
Recalculate
the
amount
of
chlorine
that
would
be
put
into
the
boiler
or
process
heater
during
an
hour
under
these
new
conditions
using
Equation
1
of
§
63.7530.
(
4)
If
you
plan
to
burn
a
new
type
of
fuel,
a
fuel
from
a
new
supplier
or
a
new
mixture
of
fuels,
your
operating
limit
for
hydrogen
chloride
is
chlorine
input,
and
the
results
of
recalculating
the
chlorine
input
using
Equation
1
of
§
63.7530
are
higher
than
the
chlorine
input
operating
limit
established
during
the
initial
performance
test,
then
you
must
conduct
a
new
performance
test
according
to
the
procedures
in
§
63.7520
to
demonstrate
that
the
hydrogen
chloride
emissions
do
not
exceed
the
emission
limitation.
You
must
also
establish
a
new
operating
limit
based
on
this
performance
test
according
to
the
procedures
in
§
63.7530(
c).
(
5)
If
you
plan
to
burn
a
new
type
of
fuel,
a
fuel
from
a
new
supplier,
or
a
new
mixture
of
fuels
and
you
choose
to
comply
with
the
alternative
total
selected
metals
emission
limit
instead
of
particulate
matter
and
your
operating
limit
is
the
total
selected
metals
fuel
content,
you
must
demonstrate
continuous
compliance
with
your
operating
limit
by
recalculating
the
total
selected
metals
input
using
Equation
2
of
§
63.7530
according
to
the
procedures
specified
in
paragraphs
(
a)(
5)(
i)
through
(
iii)
of
this
section.
(
i)
Determine
for
any
new
fuel
the
heating
value
and
the
total
selected
metals
concentration,
based
on
supplier
data
or
own
fuel
analysis,
according
to
the
provisions
in
the
site­
specific
test
plan
developed
according
to
the
requirements
in
§
63.7520(
a).
(
ii)
Estimate
the
maximum
hourly
input
at
which
each
fuel
will
be
burned.
(
iii)
Recalculate
the
amount
of
total
selected
metals
that
would
be
put
into
the
boiler
or
process
heater
during
an
hour
under
these
new
conditions
using
Equation
2
of
§
63.7530.
(
6)
If
you
plan
to
burn
a
new
type
of
fuel,
a
fuel
from
a
new
supplier
or
a
new
mixture
of
fuels,
you
choose
to
comply
with
the
alternative
total
selected
metals
emission
limit
instead
of
particulate
matter,
and
the
results
of
recalculating
the
total
selected
metals
input
using
Equation
2
of
§
63.7530
are
higher
than
the
total
selected
metals
operating
limit
established
during
the
initial
performance
test,
then
you
must
conduct
a
new
performance
test
according
to
the
procedures
in
§
63.7520
to
demonstrate
that
the
total
selected
metals
emissions
do
not
exceed
the
emission
limit.
You
must
also
establish
a
new
operating
limit
based
on
this
performance
test
according
to
the
procedures
in
§
63.7530(
c).
(
7)
If
you
plan
to
burn
a
new
type
of
fuel,
a
fuel
from
a
new
supplier,
or
a
new
mixture
of
fuels
and
your
operating
limit
for
mercury
emissions
is
the
mercury
fuel
content,
you
must
demonstrate
continuous
compliance
with
your
operating
limit
by
recalculating
the
mercury
input
using
Equation
3
of
§
63.7530
according
to
the
procedures
specified
in
paragraphs
(
a)(
7)(
i)
through
(
iii)
of
this
section.
(
i)
Determine
for
any
new
fuel
the
heating
value
and
the
mercury
concentration,
based
on
supplier
data
or
own
fuel
analysis,
according
to
the
provisions
in
the
site­
specific
test
plan
developed
according
to
the
requirements
in
§
63.7520(
a).
(
ii)
Estimate
the
maximum
hourly
input
at
which
each
fuel
will
be
burned.
(
iii)
Recalculate
the
amount
of
mercury
that
would
be
put
into
the
boiler
or
process
heater
during
an
hour
under
these
new
conditions
using
Equation
3
of
§
63.7530.
(
8)
If
you
plan
to
burn
a
new
type
of
fuel,
a
fuel
from
a
new
supplier
or
a
new
mixture
of
fuels,
and
the
results
of
recalculating
the
mercury
input
using
Equation
3
of
§
63.7530
are
higher
than
the
mercury
operating
limit
established
during
the
initial
performance
test,
then
you
must
conduct
a
new
performance
test
according
to
the
procedures
in
§
63.7520
to
demonstrate
that
the
mercury
emissions
do
not
exceed
the
emission
limit.
You
must
also
establish
a
new
operating
limit
based
on
this
performance
test
according
to
the
procedures
in
§
63.7530(
c).
(
9)
If
your
unit
is
controlled
with
a
fabric
filter,
you
must
demonstrate
continuous
compliance
with
the
operating
limits
for
fabric
filters
by
operating
each
fabric
filter
system
such
that
the
bag
leak
detection
system
does
not
sound
more
than
5
percent
of
the
operating
time
during
a
6­
month
period
and
by
keeping
records
of
the
date,
time,
and
duration
of
each
alarm,
the
time
corrective
action
was
initiated
and
completed,
a
brief
description
of
the
cause
of
the
alarm
and
the
corrective
action
taken.
You
must
also
record
the
percent
of
the
operating
time
during
each
6­
month
period
that
the
alarm
sounds.
In
calculating
this
operating
time
percentage,
if
inspection
of
the
fabric
filter
demonstrates
that
no
corrective
action
is
required,
no
alarm
time
is
counted.
If
corrective
action
is
required,
each
alarm
shall
be
counted
as
a
minimum
of
1
hour.
If
you
take
longer
than
1
hour
to
initiate
corrective
action,
the
alarm
time
shall
be
counted
as
the
actual
amount
of
time
taken
to
initiate
corrective
action.
(
b)
You
must
report
each
instance
in
which
you
did
not
meet
each
emission
limit
and
each
operating
limit
in
Tables
7.
A
and
7.
B
to
this
subpart
that
apply
to
you.
This
includes
periods
of
startup,
shutdown,
and
malfunction.
You
must
also
report
each
instance
in
which
you
did
not
meet
the
work
practice
requirements
in
Table
8
to
this
subpart
that
apply
to
you.
These
instances
are
deviations
from
the
emission
limitations
and
work
practice
standards
in
this
subpart.
These
deviations
must
be
reported
according
to
the
requirements
in
§
63.7550.
(
c)
During
periods
of
startup,
shutdown,
and
malfunction,
you
must
operate
in
accordance
with
the
startup,
shutdown,
and
malfunction
plan
as
required
in
§
63.7505(
d).
(
d)
Consistent
with
§
§
63.6(
e)
and
63.7(
e)(
1),
deviations
that
occur
during
a
period
of
startup,
shutdown,
or
malfunction
are
not
violations
if
you
demonstrate
to
the
Administrator's
satisfaction
that
you
were
operating
in
accordance
with
the
startup,
shutdown,
and
malfunction
plan.
The
Administrator
will
determine
whether
deviations
that
occur
during
a
period
of
startup,
shutdown,
or
malfunction
are
violations,
according
to
the
provisions
in
§
63.6(
e).

Notifications,
Reports,
and
Records
§
63.7545
What
notifications
must
I
submit
and
when?

(
a)
You
must
submit
all
of
the
notifications
in
§
§
63.6(
h)(
4)
and
(
5),
63.7(
b)
and
(
c),
63.8
(
e),
63.8(
f)(
4)
and
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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
(
6),
and
63.9
(
b)
through
(
h)
that
apply
to
you
by
the
dates
specified.
(
b)
As
specified
in
§
63.9(
b)(
2),
if
you
startup
your
affected
source
before
[
DATE
OF
PUBLICATION
OF
THE
FINAL
RULE
IN
THE
FEDERAL
REGISTER],
you
must
submit
an
Initial
Notification
not
later
than
120
calendar
days
after
[
DATE
THE
FINAL
RULE
IS
PUBLISHED
IN
THE
FEDERAL
REGISTER].
The
Initial
Notification
must
include
the
information
required
in
paragraphs
(
b)(
1)
and
(
2)
of
this
section,
as
applicable.
(
1)
If
your
affected
source
has
an
annual
capacity
factor
of
greater
than
10
percent,
your
Initial
Notification
must
include
the
information
required
by
§
63.9(
b)(
2).
(
2)
If
your
affected
source
has
a
federally
enforceable
permit
that
limits
the
annual
capacity
factor
to
less
than
or
equal
to
10
percent
such
that
the
unit
is
in
one
of
the
limited
use
subcategories
(
the
limited
use
solid
fuel
subcategory,
the
limited
use
liquid
fuel
subcategory,
or
the
limited
use
gaseous
fuel
subcategory),
your
Initial
Notification
must
include
the
information
required
by
§
63.9(
b)(
2)
and
also
a
signed
statement
indicating
your
affected
source
has
a
federally
enforceable
permit
that
limits
the
annual
capacity
factor
to
less
than
or
equal
to
10
percent.
(
c)
As
specified
in
§
63.9(
b)(
3),
if
you
startup
your
new
or
reconstructed
affected
source
on
or
after
[
DATE
THE
FINAL
RULE
IS
PUBLISHED
IN
THE
FEDERAL
REGISTER],
you
must
submit
an
Initial
Notification
not
later
than
120
calendar
days
after
you
become
subject
to
this
subpart.
The
Initial
Notification
must
include
the
information
required
in
paragraphs
(
c)(
1)
and
(
2)
of
this
section,
as
applicable.
(
1)
If
your
affected
source
has
an
annual
capacity
factor
of
greater
than
10
percent,
your
Initial
Notification
must
include
the
information
required
by
§
63.9(
b)(
3).
(
2)
If
your
affected
source
has
a
federally
enforceable
permit
that
limits
the
annual
capacity
factor
to
less
than
or
equal
to
10
percent
such
that
the
unit
is
in
one
of
the
limited
use
subcategories,
your
Initial
Notification
must
include
the
information
required
by
§
63.9(
b)(
3)
and
also
a
signed
statement
indicating
your
affected
source
has
a
federally
enforceable
permit
that
limits
the
annual
capacity
factor
to
less
than
or
equal
to
10
percent.
(
d)
If
you
are
required
to
conduct
a
performance
test,
you
must
submit
a
notification
of
intent
to
conduct
a
performance
test
at
least
60
calendar
days
before
the
performance
test
is
scheduled
to
begin
as
required
in
§
63.7(
b)(
1).
(
e)
If
you
are
required
to
conduct
a
performance
test
or
other
initial
compliance
demonstration
as
specified
in
Tables
4.
A
through
4.
E,
5.
A
through
5.
E,
or
6
to
this
subpart,
you
must
submit
a
Notification
of
Compliance
Status
report
according
to
§
63.9(
h)(
2)(
ii)
and
the
requirements
specified
in
paragraphs
(
e)(
1)(
i)
through
(
e)(
1)(
vii)
of
this
section.
(
1)
For
each
initial
compliance
demonstration,
you
must
submit
the
Notification
of
Compliance
Status
report,
including
all
performance
test
results,
before
the
close
of
business
on
the
60th
calendar
day
following
the
completion
of
the
performance
test
and/
or
other
initial
compliance
demonstrations
according
to
§
63.10(
d)(
2).
The
Notification
of
Compliance
Status
report
must
contain
all
the
information
specified
in
paragraphs
(
e)(
l)(
i)
through
(
vii)
of
this
section,
as
applicable.
(
i)
A
description
of
the
affected
source(
s)
including
identification
of
which
subcategory
the
source
is
in,
the
capacity
of
the
source,
a
description
of
the
add­
on
controls
used
on
the
source
description
of
the
fuel(
s)
burned,
and
justification
for
the
worst­
case
fuel
burned
during
the
performance
test.
(
ii)
Summary
of
the
results
of
all
performance
tests,
fuel
analyses,
and
calculations
conducted
to
demonstrate
initial
compliance
including
all
established
operating
limits.
(
iii)
Identification
of
whether
you
are
complying
with
the
particulate
matter
emission
limit
or
the
alternative
total
selected
metals
emission
limit.
(
iv)
A
signed
certification
that
you
have
met
all
applicable
emission
limitations
and
work
practice
standards.
(
v)
A
summary
of
the
carbon
monoxide
emissions
monitoring
data
recorded
during
the
performance
test
to
show
that
you
have
met
the
work
practice
standard
in
Table
6
to
this
subpart,
if
applicable.
(
vi)
If
your
new
or
reconstructed
boiler
or
process
heater
is
in
one
of
the
liquid
fuel
subcategories
and
burns
only
liquid
fossil
fuels
other
than
residual
oil
either
alone
or
in
combination
with
gaseous
fuels,
you
must
submit
a
signed
statement
certifying
this
in
your
Notification
of
Compliance
Status
report.
(
vii)
If
you
had
a
deviation
from
any
emission
limitation
or
work
practice
standard,
you
must
also
submit
a
description
of
the
deviation,
the
duration
of
the
deviation,
and
the
corrective
action
taken
in
the
Notification
of
Compliance
Status
report.
§
63.7550
What
reports
must
I
submit
and
when?
(
a)
You
must
submit
each
report
in
Table
9
to
this
subpart
that
applies
to
you.
(
b)
Unless
the
Administrator
has
approved
a
different
schedule
for
submission
of
reports
under
§
63.10(
a),
you
must
submit
each
report
by
the
date
in
Table
9
to
this
subpart
and
according
to
the
requirements
in
paragraphs
(
b)(
1)
through
(
5)
of
this
section.
(
1)
The
first
compliance
report
must
cover
the
period
beginning
on
the
compliance
date
that
is
specified
for
your
affected
source
in
§
63.7495
and
ending
on
June
30
or
December
31,
whichever
date
is
the
first
date
following
the
end
of
the
first
calendar
half
after
the
compliance
date
that
is
specified
for
your
source
in
§
63.7495.
(
2)
The
first
compliance
report
must
be
postmarked
or
delivered
no
later
than
July
31
or
January
31,
whichever
date
is
the
first
date
following
the
end
of
the
first
calendar
half
after
the
compliance
date
that
is
specified
for
your
source
in
§
63.7495.
(
3)
Each
subsequent
compliance
report
must
cover
the
semiannual
reporting
period
from
January
1
through
June
30
or
the
semiannual
reporting
period
from
July
1
through
December
31.
(
4)
Each
subsequent
compliance
report
must
be
postmarked
or
delivered
no
later
than
July
31
or
January
31,
whichever
date
is
the
first
date
following
the
end
of
the
semiannual
reporting
period.
(
5)
For
each
affected
source
that
is
subject
to
permitting
regulations
pursuant
to
40
CFR
part
70
or
40
CFR
part
71,
and
if
the
permitting
authority
has
established
dates
for
submitting
semiannual
reports
pursuant
to
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A),
you
may
submit
the
first
and
subsequent
compliance
reports
according
to
the
dates
the
permitting
authority
has
established
instead
of
according
to
the
dates
in
paragraphs
(
b)
(
1)
through
(
4)
of
this
section.
(
c)
The
compliance
report
must
contain
the
information
required
in
paragraphs
(
c)
(
1)
through
(
11)
of
this
section.
(
1)
Company
name
and
address.
(
2)
Statement
by
a
responsible
official
with
that
official's
name,
title,
and
signature,
certifying
the
truth,
accuracy,
and
completeness
of
the
content
of
the
report.
(
3)
Date
of
report
and
beginning
and
ending
dates
of
the
reporting
period.
(
4)
The
total
fuel
use
by
each
affected
source
electing
to
comply
with
an
emission
limit
based
on
fuel
analysis
for
each
calendar
month
within
the
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/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
semiannual
reporting
period
including,
but
not
limited
to,
a
description
of
the
fuel,
the
total
fuel
usage
amount
with
units
of
measure,
and
information
on
the
supplier
of
the
fuel
and
original
source
location
of
the
fuel.
(
5)
A
summary
of
the
results
of
the
annual
performance
tests
and
documentation
of
any
operating
limits
that
were
reestablished
during
this
test,
if
applicable.
(
6)
A
signed
statement
indicating
that
you
burned
no
new
types
of
fuel,
no
fuels
from
a
new
supplier,
or
no
new
fuel
mixture.
Or,
if
you
did
burn
a
new
type
of
fuel,
a
fuel
from
a
new
supplier,
or
a
new
fuel
mixture
and
your
operating
limit
for
hydrogen
chloride
is
fuel
chlorine
input,
you
must
submit
the
calculation
of
chlorine
input,
using
Equation
1
of
§
63.7530,
that
demonstrates
that
your
source
is
still
within
its
operating
limit
for
hydrogen
chloride
emissions.
If
you
burned
a
new
type
of
fuel,
fuel
from
a
new
supplier,
or
a
new
fuel
mixture
and
your
operating
limit
for
the
alternative
total
selected
metals
emission
limit
is
fuel
total
selected
metals
input,
you
must
submit
the
calculation
of
total
selected
metals
input,
using
Equation
2
of
§
63.7530,
that
demonstrates
that
your
source
is
still
within
its
operating
limit
for
total
selected
metals
emissions.
If
you
burned
a
new
type
of
fuel,
fuel
from
a
new
supplier,
or
a
new
fuel
mixture
and
your
operating
limit
for
mercury
is
fuel
mercury
input,
you
must
submit
the
calculation
of
mercury
input,
using
Equation
3
of
§
63.7530,
that
demonstrates
that
your
source
is
still
within
its
operating
limit
for
mercury
emissions.
(
7)
If
you
wish
to
burn
a
new
type
of
fuel,
a
fuel
from
a
new
supplier,
or
a
new
fuel
mixture,
and
you
cannot
demonstrate
compliance
with
the
hydrogen
chloride
operating
limit
using
Equation
1
of
§
63.7530,
the
total
selected
metals
operating
limit
using
Equation
2
of
§
63.7530,
or
the
mercury
operating
limit
using
Equation
3
of
§
63.7530,
you
must
include
in
the
compliance
report
a
statement
indicating
the
intent
to
conduct
a
new
performance
test
under
the
new
worstcase
conditions.
(
8)
The
average
daily
hours
of
operation
by
each
source
for
each
calendar
month
within
the
semiannual
reporting
period.
(
9)
If
you
had
a
startup,
shutdown,
or
malfunction
during
the
reporting
period
and
you
took
actions
consistent
with
your
startup,
shutdown,
and
malfunction
plan,
the
compliance
report
must
include
the
information
in
§
63.10(
d)(
5)(
i).
(
10)
If
there
are
no
deviations
from
any
emission
limitations
(
emission
limits
or
operating
limits)
in
this
subpart
that
apply
to
you
and
there
are
no
deviations
from
the
requirements
for
work
practice
standards
in
Table
8
to
this
subpart,
a
statement
that
there
were
no
deviations
from
the
emission
limitations
or
work
practice
standards
during
the
reporting
period.
(
11)
If
there
were
no
periods
during
which
the
CMS,
including
CEMS,
COMS,
and
CPMS,
were
out­
of­
control
as
specified
in
§
63.8(
c)(
7),
a
statement
that
there
were
no
periods
during
which
the
CMS
were
out­
of­
control
during
the
reporting
period.
(
d)
For
each
deviation
from
an
emission
limitation
(
emission
limits
or
operating
limits)
in
this
subpart
and
for
each
deviation
from
the
requirements
for
work
practice
standards
in
Table
8
to
this
subpart
that
occurs
at
an
affected
source
where
you
are
not
using
CMS
to
comply
with
that
emission
limitation
or
work
practice
standard,
the
compliance
report
must
contain
the
information
in
paragraphs
(
c)
(
1)
through
(
11)
of
this
section
and
the
information
required
in
paragraphs
(
d)
(
1)
through
(
4)
of
this
section.
This
includes
periods
of
startup,
shutdown,
and
malfunction.
(
1)
The
total
operating
time
of
each
affected
source
during
the
reporting
period.
(
2)
A
description
of
the
deviation
and
which
limitation
you
deviated
from.
(
3)
Information
on
the
number,
duration,
and
cause
of
deviations
(
including
unknown
cause),
as
applicable,
and
the
corrective
action
taken.
(
4)
A
copy
of
the
test
report
if
the
annual
performance
test
showed
a
deviation
from
the
emission
limit
for
particulate
matter
or
the
alternative
total
selected
metals
limit,
a
deviation
from
the
hydrogen
chloride
emission
limit,
or
a
deviation
from
the
mercury
emission
limit.
(
e)
For
each
deviation
from
an
emission
limitation
(
emission
limitation
and
operating
limit)
or
work
practice
standard
in
this
subpart
occurring
at
an
affected
source
where
you
are
using
a
CMS
to
comply
with
that
emission
limitation
or
work
practice
standard,
you
must
include
the
information
in
paragraphs
(
c)
(
1)
through
(
11)
of
this
section
and
the
information
required
in
paragraphs
(
e)
(
1)
through
(
12)
of
this
section.
This
includes
periods
of
startup,
shutdown,
and
malfunction
and
any
deviations
from
your
site­
specific
monitoring
plan
as
required
in
§
63.7505(
c).
(
1)
The
date
and
time
that
each
malfunction
started
and
stopped
and
description
of
the
nature
of
the
deviation
(
i.
e.,
what
you
deviated
from).
(
2)
The
date
and
time
that
each
CMS
was
inoperative,
except
for
zero
(
lowlevel
and
high­
level
checks.
(
3)
The
date,
time,
and
duration
that
each
CMS
was
out­
of­
control,
including
the
information
in
§
63.8(
c)(
8).
(
4)
The
date
and
time
that
each
deviation
started
and
stopped,
and
whether
each
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction
or
during
another
period.
(
5)
A
summary
of
the
total
duration
of
the
deviation
during
the
reporting
period
and
the
total
duration
as
a
percent
of
the
total
source
operating
time
during
that
reporting
period.
(
6)
A
breakdown
of
the
total
duration
of
the
deviations
during
the
reporting
period
into
those
that
are
due
to
startup,
shutdown,
control
equipment
problems,
process
problems,
other
known
causes,
and
other
unknown
causes.
(
7)
A
summary
of
the
total
duration
of
CMS
downtime
during
the
reporting
period
and
the
total
duration
of
CMS
downtime
as
a
percent
of
the
total
source
operating
time
during
that
reporting
period.
(
8)
An
identification
of
each
parameter
that
was
monitored
at
the
affected
source
for
which
there
was
a
deviation,
including
opacity,
carbon
monoxide,
and
operating
parameters
for
wet
scrubbers
and
other
control
devices.
(
9)
A
brief
description
of
the
source
for
which
there
was
a
deviation.
(
10)
A
brief
description
of
each
CMS
for
which
there
was
a
deviation.
(
11)
The
date
of
the
latest
CMS
certification
or
audit
for
the
system
for
which
there
was
a
deviation.
(
12)
A
description
of
any
changes
in
CMSs,
processes,
or
controls
since
the
last
reporting
period
for
the
source
for
which
there
was
a
deviation.
(
f)
Each
affected
source
that
has
obtained
a
title
V
operating
permit
pursuant
to
40
CFR
part
70
or
40
CFR
part
71
must
report
all
deviations
as
defined
in
this
subpart
in
the
semiannual
monitoring
report
required
by
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A).
If
an
affected
source
submits
a
compliance
report
pursuant
to
Table
9
to
this
subpart
along
with,
or
as
part
of,
the
semiannual
monitoring
report
required
by
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A),
and
the
compliance
report
includes
all
required
information
concerning
deviations
from
any
emission
limitation
(
including
any
operating
limit),
or
work
practice
standard
in
this
subpart,
submission
of
the
compliance
report
satisfies
any
obligation
to
report
the
same
deviations
in
the
semiannual
monitoring
report.

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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
However,
submission
of
a
compliance
report
does
not
otherwise
affect
any
obligation
the
affected
source
may
have
to
report
deviations
from
permit
requirements
to
the
permit
authority.

§
63.7555
What
records
must
I
keep?
(
a)
You
must
keep
records
according
to
paragraphs
(
a)
(
1)
through
(
3)
of
this
section.
(
1)
A
copy
of
each
notification
and
report
that
you
submitted
to
comply
with
this
subpart,
including
all
documentation
supporting
any
Initial
Notification
or
Notification
of
Compliance
Status
or
semiannual
compliance
report
that
you
submitted,
according
to
the
requirements
in
§
63.10(
b)(
2)(
xiv).
(
2)
The
records
in
§
63.6(
e)(
3)(
iii)
through
(
v)
related
to
startup,
shutdown,
and
malfunction.
(
3)
Records
of
performance
tests
or
other
compliance
demonstrations,
performance
evaluations,
and
opacity
observations
as
required
in
§
63.10(
b)(
2)(
viii).
(
b)
For
each
CEMS,
CPMS,
and
COMS,
you
must
keep
records
according
to
paragraphs
(
b)
(
1)
through
(
5)
of
this
section.
(
1)
Records
described
in
§
63.10(
b)(
2)
(
vi)
through
(
xi).
(
2)
Monitoring
data
for
COMS
during
a
performance
evaluation
as
required
in
§
63.6(
h)(
7)
(
i)
and
(
ii).
(
3)
Previous
(
i.
e.,
superseded)
versions
of
the
performance
evaluation
plan
as
required
in
§
63.8(
d)(
3).
(
4)
Request
for
alternatives
to
relative
accuracy
test
for
CEMS
as
required
in
§
63.8(
f)(
6)(
i).
(
5)
Records
of
the
date
and
time
that
each
deviation
started
and
stopped,
and
whether
the
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction
or
during
another
period.
(
c)
You
must
keep
the
records
required
in
Tables
7.
A,
7.
B,
and
8
to
this
subpart
including
records
of
all
monitoring
data
and
calculated
averages
for
applicable
operating
limits
such
as
opacity,
pressure
drop,
carbon
monoxide,
and
pH
to
show
continuous
compliance
with
each
emission
limitation,
operating
limit
and
work
practice
standard
that
applies
to
you.
(
d)
You
must
also
keep
the
records
in
paragraphs
(
d)
(
1)
through
(
5)
of
this
section.
(
1)
You
must
keep
records
of
daily
fuel
use
by
each
source
electing
to
comply
with
an
emission
limit
based
on
fuel
analysis,
including
the
type(
s)
of
fuel,
amount(
s)
used,
and
the
supplier(
s)
and
original
source
location(
s).
(
2)
You
must
keep
records
of
daily
hours
of
operation
by
each
source.
(
3)
A
copy
of
all
calculations
and
supporting
documentation
of
chlorine
fuel
input,
using
Equation
1
of
§
63.7530,
that
were
done
to
demonstrate
continuous
compliance
with
the
hydrogen
chloride
emission
limitation.
Supporting
documentation
should
include
results
of
any
fuel
analyses
and
basis
for
the
estimates
of
maximum
fuel
input.
(
4)
A
copy
of
all
calculations
and
supporting
documentation
of
total
selected
metals
fuel
input,
using
Equation
2
of
§
63.7530,
that
were
done
to
demonstrate
continuous
compliance
with
the
total
selected
metals
emission
limitation.
Supporting
documentation
should
include
results
of
any
fuel
analyses
and
basis
for
the
estimates
of
maximum
fuel
input.
(
5)
A
copy
of
all
calculations
and
supporting
documentation
of
mercury
fuel
input,
using
Equation
3
of
§
63.7530,
that
were
done
to
demonstrate
continuous
compliance
with
the
mercury
emission
limitation.
Supporting
documentation
should
include
results
of
any
fuel
analyses
and
basis
for
the
estimates
of
maximum
fuel
input.
(
e)
If
your
boiler
or
process
heater
has
a
federally
enforceable
permit
that
limits
the
annual
capacity
factor
to
less
than
or
equal
to
10
percent
such
that
the
unit
is
in
one
of
the
limited
use
subcategories,
you
must
keep
the
records
in
paragraphs
(
e)
(
1)
and
(
2)
of
this
section.
(
1)
A
copy
of
the
federally
enforceable
permit
that
limits
the
annual
capacity
factor
of
the
source
to
less
than
or
equal
to
10
percent.
(
2)
Fuel
use
records
for
the
days
the
boiler
or
process
heater
was
operating.

§
63.7560
In
what
form
and
how
long
must
I
keep
my
records?

(
a)
Your
records
must
be
in
a
form
suitable
and
readily
available
for
expeditious
review,
according
to
§
63.10(
b)(
1).
(
b)
As
specified
in
§
63.10(
b)(
1),
you
must
keep
each
record
for
5
years
following
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record.
(
c)
You
must
keep
each
record
on
site
for
at
least
2
years
after
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record,
according
to
§
63.10(
b)(
1).
You
can
keep
the
records
offsite
for
the
remaining
3
years.

Other
Requirements
and
Information
§
63.7565
What
parts
of
the
General
Provisions
apply
to
me?

Table
10
to
this
subpart
shows
which
parts
of
the
General
Provisions
in
§
§
63.1
through
63.15
apply
to
you.
§
63.7570
Who
implements
and
enforces
this
subpart?

(
a)
This
subpart
can
be
implemented
and
enforced
by
the
U.
S.
EPA,
or
a
delegated
authority
such
as
your
State,
local,
or
tribal
agency.
If
the
Administrator
has
delegated
authority
to
your
State,
local,
or
tribal
agency,
then
that
agency
has
the
authority
to
implement
and
enforce
this
subpart.
You
should
contact
your
EPA
Regional
Office
to
find
out
if
this
subpart
is
delegated
to
your
State,
local,
or
tribal
agency.
(
b)
In
delegating
implementation
and
enforcement
authority
to
this
subpart
to
a
State,
local,
or
tribal
agency
under
40
CFR
part
63,
subpart
E,
the
authorities
contained
in
paragraph
(
c)
of
this
section
are
retained
by
the
Administrator
and
are
not
transferred
to
the
State,
local,
or
tribal
agency.
The
U.
S.
EPA
retains
oversight
of
this
rule
and
can
take
enforcement
actions,
as
appropriate.
(
c)
The
authorities
that
will
not
be
delegated
to
State,
local,
or
tribal
agencies
are
listed
in
paragraphs
(
c)(
1)
through
(
5)
of
this
section.
(
1)
Approval
of
alternatives
to
the
non­
opacity
emission
limits
and
work
practice
standards
in
§
63.7500(
a)
through
(
c)
under
§
63.6(
g).
(
2)
Approval
of
alternative
opacity
emission
limits
in
§
63.7500(
a)
under
§
63.6(
h)(
9).
(
3)
Approval
of
major
alternatives
to
test
methods
under
§
63.7(
e)(
2)(
ii)
and
(
f)
and
as
defined
in
§
63.90.
(
4)
Approval
of
major
alternatives
to
monitoring
under
§
63.8(
f)
and
as
defined
in
§
63.90.
(
5)
Approval
of
major
alternatives
to
recordkeeping
and
reporting
under
§
63.10(
f)
and
as
defined
in
§
63.90.

§
63.7575
What
definitions
apply
to
this
subpart?

Terms
used
in
this
subpart
are
defined
in
the
Clean
Air
Act,
in
§
63.2,
and
in
this
section
as
follows:
Annual
capacity
factor
means
the
ratio
between
the
actual
heat
input
to
a
boiler
or
process
heater
from
the
fuels
burned
during
a
calendar
year
and
the
potential
heat
input
to
the
boiler
or
process
heater
had
it
been
operated
for
8,760
hours
during
a
calendar
year
at
the
maximum
steady
state
design
heat
input
capacity.
Bag
leak
detection
system
means
an
instrument
that
is
capable
of
monitoring
particulate
matter
loadings
in
the
exhaust
of
a
fabric
filter
(
i.
e.,
baghouse)
in
order
to
detect
bag
failures.
A
bag
leak
detection
system
includes,
but
is
not
limited
to,
an
instrument
that
operates
on
electrodynamic,
triboelectric,
light
scattering,
light
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transmittance,
or
other
principle
to
monitor
relative
particulate
matter
loadings.
Biomass
fuel
means
wood,
wood
residue,
and
wood
products
(
e.
g.,
trees,
tree
stumps,
tree
limbs,
bark,
lumber,
sawdust,
sanderdust,
chips,
scraps,
slabs,
millings,
and
shavings);
vegetative
agricultural
and
silvicultural
materials,
such
as
logging
residues
(
slash),
nut
and
grain
hulls
and
chaff
(
e.
g.,
almond,
walnut,
peanut,
rice,
and
wheat),
bagasse,
orchard
prunings,
corn
stalks,
coffee
bean
hulls
and
grounds.
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
this
definition.
Coal
means
all
solid
fuels
classifiable
as
anthracite,
bituminous,
subbituminous
or
lignite
by
the
American
Society
for
Testing
and
Materials
in
ASTM
D388
 
77,
``
Standard
Specification
for
Classification
of
Coals
by
Rank,''
coal
refuse,
and
petroleum
coke.
Synthetic
fuels
derived
from
coal
for
the
purpose
of
creating
useful
heat
including,
but
not
limited
to,
solventrefined
coal,
coal­
oil
mixtures,
and
coalwater
mixtures,
are
included
in
this
definition
for
the
purposes
to
this
subpart.
Coal
refuse
means
any
by­
product
of
coal
mining
or
coal
cleaning
operations
with
an
ash
content
greater
than
50
percent
(
by
weight)
and
a
heating
value
less
than
13,900
kilojoules
per
kilogram
(
6,000
Btu
per
pound)
on
a
dry
basis.
Commercial/
Institutional
boiler
means
a
boiler
used
in
commercial
establishments
or
institutional
establishments
such
as
medical
centers,
research
centers,
institutions
of
higher
education,
hotels,
and
laundries
to
provide
electricity,
steam,
and/
or
hot
water.
Deviation
means
any
instance
in
which
an
affected
source
subject
to
this
subpart,
or
an
owner
or
operator
of
such
a
source:
(
1)
Fails
to
meet
any
requirement
or
obligation
established
by
this
subpart
including,
but
not
limited
to,
any
emission
limitation
(
including
any
operating
limit)
or
work
practice
standard;
(
2)
Fails
to
meet
any
term
or
condition
that
is
adopted
to
implement
an
applicable
requirement
in
this
subpart
and
that
is
included
in
the
operating
permit
for
any
affected
source
required
to
obtain
such
a
permit;
or
(
3)
Fails
to
meet
any
emission
limitation
(
including
any
operating
limit)
or
work
practice
standard
in
this
subpart
during
startup,
shutdown,
or
malfunction,
regardless
of
whether
or
not
such
failure
is
permitted
by
this
subpart.
Distillate
oil
means
fuel
oils
that
contain
0.05
weight
percent
nitrogen
or
less
and
comply
with
the
specifications
for
fuel
oil
numbers
1
and
2,
as
defined
by
the
American
Society
for
Testing
and
Materials
in
ASTM
D396
 
78,
``
Standard
Specifications
for
Fuel
Oils.''
Dry
scrubber
means
an
add­
on
air
pollution
control
system
that
injects
dry
alkaline
sorbent
(
dry
injection)
or
sprays
an
alkaline
sorbent
(
spray
dryer)
to
react
with
and
neutralize
acid
gas
in
the
exhaust
stream
forming
a
dry
powder
material.
Electric
utility
steam
generating
unit
means
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.
Electrostatic
precipitator
means
an
add­
on
air
pollution
control
device
used
to
capture
particulate
matter
by
charging
the
particles
using
an
electrostatic
field,
collecting
the
particles
using
a
grounded
collecting
surface,
and
transporting
the
particles
into
a
hopper.
Emission
limitation
means
any
emission
limit
or
operating
limit.
Fabric
filter
means
an
add­
on
air
pollution
control
device
used
to
capture
particulate
matter
by
filtering
gas
streams
through
filter
media,
also
known
as
a
baghouse.
Federally
enforceable
means
all
limitations
and
conditions
that
are
enforceable
by
the
Administrator,
including
the
requirements
of
40
CFR
parts
60
and
61,
requirements
within
any
applicable
State
implementation
plan,
and
any
permit
requirements
established
under
40
CFR
52.21
or
51.18
and
51.24.
Firetube
boiler
means
a
boiler
in
which
hot
gases
of
combustion
pass
through
the
tubes
and
water
contacts
the
outside
surfaces
of
the
tubes.
Fossil
fuel
means
natural
gas,
petroleum,
coal,
and
any
form
of
solid,
liquid,
or
gaseous
fuel
derived
from
such
materials.
Gaseous
fuel
includes,
but
is
not
limited
to,
natural
gas,
process
gas,
refinery
gas
and
biogas.
Heat
input
means
heat
derived
from
combustion
of
fuel
in
a
boiler
or
process
heater
and
does
not
include
the
heat
input
from
preheated
combustion
air,
recirculated
flue
gases,
or
exhaust
gases
from
other
sources
such
as
gas
turbines,
internal
combustion
engines,
kilns,
etc.
Hot
water
heater
means
a
closed
vessel
in
which
water
is
heated
by
combustion
of
gaseous
fuel
and
is
withdrawn
for
use
external
to
the
vessel
at
pressures
not
exceeding
160
pounds
per
square
inch
gauge
(
psig),
including
the
apparatus
by
which
the
heat
is
generated
and
all
controls
and
devices
necessary
to
prevent
water
temperatures
from
exceeding
210
°
F
(
99
°
C).
Industrial
boiler
means
a
boiler
used
in
manufacturing,
processing,
mining,
and
refining
or
any
other
industry
to
provide
steam,
hot
water,
and/
or
electricity.
Large
gaseous
fuel
subcategory
means
any
boiler
or
process
heater
that
burns
only
gaseous
fuels
not
combined
with
any
liquid
or
solid
fuels,
has
a
rated
capacity
of
greater
than
10
MMBtu
per
hour
heat
input,
and
has
an
annual
capacity
factor
of
greater
than
10
percent.
Large
liquid
fuel
subcategory
means
any
boiler
or
process
heater
that
does
not
burn
any
solid
fuel
and
burns
any
liquid
fuel
either
alone
or
in
combination
with
gaseous
fuels,
has
a
rated
capacity
of
greater
than
10
MMBtu
per
hour
heat
input,
and
has
an
annual
capacity
factor
of
greater
than
10
percent.
Large
solid
fuel
subcategory
means
any
watertube
boiler
or
process
heater
that
burns
any
amount
of
solid
fuel
either
alone
or
in
combination
with
liquid
or
gaseous
fuels,
has
a
rated
capacity
of
greater
than
10
MMBtu
per
hour
heat
input,
and
has
an
annual
capacity
factor
of
greater
than
10
percent.
Limited
use
gaseous
fuel
subcategory
includes
any
boiler
or
process
heater
that
burns
only
gaseous
fuels
not
combined
with
any
liquid
or
solid
fuels,
has
a
rated
capacity
of
greater
than
10
MMBtu
per
hour
heat
input,
and
has
a
federally
enforceable
annual
average
capacity
factor
of
equal
to
or
less
than
10
percent.
Limited
use
liquid
fuel
subcategory
includes
any
boiler
or
process
heater
that
does
not
burn
any
solid
fuel
and
burns
any
liquid
fuel
either
alone
or
in
combination
with
gaseous
fuels,
has
a
rated
capacity
of
greater
than
10
MMBtu
per
hour
heat
input,
and
has
a
federally
enforceable
annual
average
capacity
factor
of
equal
to
or
less
than
10
percent.
Limited
use
solid
fuel
subcategory
includes
any
boiler
or
process
heater
that
burns
any
amount
of
solid
fuel
either
alone
or
in
combination
with
liquid
or
gaseous
fuels,
has
a
rated
capacity
of
greater
than
10
MMBtu
per
hour
heat
input,
and
has
a
federally
enforceable
annual
average
capacity
factor
of
equal
to
or
less
than
10
percent.

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Liquid
fossil
fuel
means
petroleum,
distillate
oil,
residual
oil
and
any
form
of
liquid
fuel
derived
from
such
material.
Liquid
fuel
includes,
but
is
not
limited
to,
distillate
oil,
residual
oil,
waste
oil,
and
process
liquids.
Natural
gas
means:
(
1)
A
naturally
occurring
mixture
of
hydrocarbon
and
nonhydrocarbon
gases
found
in
geologic
formations
beneath
the
earth's
surface,
of
which
the
principal
constituent
is
methane;
or
(
2)
Liquid
petroleum
gas,
as
defined
by
the
American
Society
for
Testing
and
Materials
in
ASTM
D1835
 
82,
``
Standard
Specification
for
Liquid
Petroleum
Gases.''
Opacity
means
the
degree
to
which
emissions
reduce
the
transmission
of
light
and
obscure
the
view
of
an
object
in
the
background.
Particulate
matter
means
any
finely
divided
solid
or
liquid
material,
other
than
uncombined
water,
as
measured
by
the
test
methods
specified
under
this
subpart,
or
an
alternative
method.
Process
heater
means
an
enclosed
device
using
controlled
flame,
and
the
unit's
primary
purpose
is
to
transfer
heat
indirectly
to
a
process
stream
(
liquid,
gas,
or
solid)
or
to
a
heat
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.
Residual
oil
means
crude
oil,
fuel
oil
numbers
1
and
2
that
have
a
nitrogen
content
greater
than
0.05
weight
percent,
and
all
fuel
oil
numbers
4,
5
and
6,
as
defined
by
the
American
Society
for
Testing
and
Materials
in
ASTM
D396
 
78,
``
Standard
Specifications
for
Fuel
Oils.''
Responsible
official
means
responsible
official
as
defined
in
§
70.2.
Small
gaseous
fuel
subcategory
includes
any
boiler
or
process
heater
that
burns
only
gaseous
fuels
not
combined
with
any
liquid
or
solid
fuels,
and
has
a
rated
capacity
of
less
than
or
equal
to
10
MMBtu
per
hour
heat
input.
Small
liquid
fuel
subcategory
includes
any
boiler
or
process
heater
that
does
not
burn
any
solid
fuel,
and
burns
any
liquid
fuel
either
alone
or
in
combination
with
gaseous
fuels,
and
has
a
rated
capacity
of
less
than
or
equal
to
10
MMBtu
per
hour
heat
input.
Small
solid
fuel
subcategory
includes
any
firetube
boiler
that
burns
any
amount
of
solid
fuel
either
alone
or
in
combination
with
liquid
or
gaseous
fuels,
and
any
other
boiler
or
process
heater
that
burns
any
amount
of
solid
fuel
either
alone
or
in
combination
with
liquid
or
gaseous
fuels,
and
has
a
rated
capacity
of
less
than
or
equal
to
10
MMBtu
per
hour
heat
input.
Solid
fuel
includes,
but
is
not
limited
to,
coal,
wood,
biomass,
tires,
plastics,
and
other
nonfossil
solid
materials.
Total
selected
metals
means
the
combination
of
the
following
metallic
hazardous
air
pollutants:
arsenic,
beryllium,
cadmium,
chromium,
lead,
manganese,
nickel
and
selenium.
Waste
heat
boiler
means
a
device
that
recovers
normally
unused
energy
and
converts
it
to
usable
heat.
Waste
heat
boilers
are
also
referred
to
as
heat
recovery
steam
generators.
Watertube
boiler
means
a
boiler
in
which
water
passes
through
the
tubes
and
hot
gases
of
combustion
pass
over
the
outside
surfaces
of
the
tubes.
Wet
scrubber
means
any
add­
on
air
pollution
control
device
that
mixes
an
aqueous
stream
or
slurry
with
the
exhaust
gases
from
a
boiler
or
process
heater
to
control
emissions
of
particulate
matter
and/
or
to
absorb
and
neutralize
acid
gases,
such
as
hydrogen
chloride.
Work
practice
standard
means
any
design,
equipment,
work
practice,
or
operational
standard,
or
combination
thereof,
that
is
promulgated
pursuant
to
section
112(
h)
of
the
Clean
Air
Act.

Tables
to
Subpart
DDDDD
of
Part
63
As
stated
in
§
63.7500,
you
must
comply
with
the
following
applicable
emission
limits:

TABLE
1
TO
SUBPART
DDDDD
OF
PART
63
 
EMISSION
LIMITS
For
.
.
.
You
must
meet
these
emission
limits
.
.
.

1.
Each
new
or
reconstructed
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory.
a.
Emissions
of
particulate
matter
must
not
exceed
0.026
lb
per
MMBtu
of
heat
input;
or
b.
Emissions
of
total
selected
metals
must
not
exceed
0.0001
lb
per
MMBtu
of
heat
input.
c.
Emissions
of
hydrogen
chloride
must
not
exceed
0.02
lb
per
MMBtu
of
heat
input.
d.
Emissions
of
mercury
must
not
exceed
0.000003
lb
per
MMBtu
of
heat
input.

2.
Each
new
or
reconstructed
industrial,
commercial,
institutional
boiler
or
process
heater
in
the
large
liquid
fuel
subcategory.
a.
Emissions
of
particulate
matter
must
not
exceed
0.03
lb
per
MMBtu
of
heat
input.
b.
emissions
of
hydrogen
chloride
must
not
exceed
0.0005
lb
per
MMBtu
of
heat
input.

3.
Each
new
or
reconstructed
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
limited
use
solid
fuel
subcategory.
a.
Emissions
of
particulate
matter
must
not
exceed
0.026
lb
per
MMBtu
of
heat
input;
or
b.
Emissions
of
total
selected
metals
must
not
exceed
0.0001
lb
per
MMBtu
of
heat
input
c.
Emissions
of
hydrogen
chloride
must
not
exceed
0.02
lb
per
MMBtu
of
heat
input.
d.
Emissions
of
mercury
must
not
exceed
0.000003
lb
per
MMBtu
of
heat
input.

4.
Each
new
or
reconstructed
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
limited
use
liquid
fuel
subcategory.
a.
Emissions
of
particulate
matter
must
not
exceed
0.03
lb
per
MMBtu
of
heat
input.
b.
Emissions
of
hydrogen
chloride
must
not
exceed
0.0009
lb
per
MMBtu
of
heat
input.

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Monday,
January
13,
2003
/
Proposed
Rules
TABLE
1
TO
SUBPART
DDDDD
OF
PART
63
 
EMISSION
LIMITS
 
Continued
For
.
.
.
You
must
meet
these
emission
limits
.
.
.

5.
Each
new
or
reconstructed
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
small
solid
fuel
subcategory.
a.
Emissions
of
particulate
matter
must
not
exceed
0.026
lb
per
MMBtu
of
heat
input;
or
b.
Emissions
of
total
selected
metals
must
not
exceed
0.0001
lb
per
MMBtu
of
heat
input.
c.
Emissions
of
hydrogen
chloride
must
not
exceed
0.02
lb
per
MMBtu
of
heat
input.
d.
Emissions
of
mercury
must
not
exceed
0.000003
lb
per
MMBtu
of
heat
input.

6.
Each
new
or
reconstructed
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
small
liquid
fuel
subcategory.
a.
Emissions
of
particulate
matter
must
not
exceed
0.03
lb
per
MMBtu
of
heat
input.
b.
emissions
of
hydrogen
chloride
must
not
exceed
0.0009
lb
per
MMBtu
of
heat
input.

7.
Each
existing
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory..
a.
Emissions
of
particulate
matter
must
not
exceed
0.07
lb
per
MMBtu
of
heat
input;
or
b.
Emissions
of
total
selected
metals
must
not
exceed
0.001
lb
per
MMBtu
of
heat
input.
c.
Emissions
of
hydrogen
chloride
must
not
exceed
0.09
lb
per
MMBtu
of
heat
input.
d.
Emissions
of
mercury
must
not
exceed
0.000007
lb
per
MMBtu
of
heat
input.

8.
Each
existing
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
limited
use
solid
fuel
subcategory.
a.
Emissions
of
particulate
matter
must
not
exceed
0.21
lb
per
MMBtu
of
heat
input;
or
b.
Emissions
of
total
selected
metals
must
not
exceed
0.001
lb
per
MMBtu
of
heat
input.

As
stated
in
§
63.7500,
you
must
comply
with
the
applicable
operating
limits:

TABLE
2.
A
TO
SUBPART
DDDDD
OF
PART
63
 
OPERATING
LIMITS
FOR
BOILERS
AND
PROCESS
HEATERS
IN
THE
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
For
.
.
.
That
is
controlled
with
.
.
.
You
must
meet
these
operating
limits
.
.
.

1.
Each
new
or
reconstructed
industrial,
commercial
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
limited
use
solid
fuel
subcategory,
or
the
small
solid
fuel
subcategory.
a.
An
add­
on
contol
other
than
a
wet
scrubber
or
a
dry
scrubber
i.
Maintain
opacity
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
particulate
matter
and
mercury
or
the
opacity
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
alternative
emission
limitation
for
total
selected
metals
and
the
mercury
emission
limit;
and
ii.
Maintain
the
fuel
chlorine
content
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
hydrogen
chloride.
b.
A
fabric
filter
either
alone
or
in
combination
with
an
add­
on
control
other
than
a
wet
scrubber
or
a
dry
scrubber.
i.
Maintain
the
fabric
filter
operation
such
that
the
operating
limit
established
for
fabric
filters
in
§
63.7530(
c)(
6)(
v)
is
maintained;
and
ii.
Maintain
the
fuel
chlorine
content
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
hydrogen
chloride.

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/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
2.
A
TO
SUBPART
DDDDD
OF
PART
63
 
OPERATING
LIMITS
FOR
BOILERS
AND
PROCESS
HEATERS
IN
THE
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
You
must
meet
these
operating
limits
.
.
.

c.
A
wet
scrubber
.............................................
Maintain
the
minimum
pH,
pressure
drop,
and
liquid
flow­
rate
at
or
above
the
operating
levels
established
during
the
performance
test
according
to
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
particulate
matter,
mercury
and
hydrogen
chloride
or
the
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
hydrogen
chloride,
mercury
and
the
alternative
total
selected
metals
emission
limit.
d.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
Maintain
the
minimum
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
at
or
above
the
operating
levels
established
during
the
performance
test
according
to
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
particulate
matter,
hydrogen
chloride,
and
mercury
or
the
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
hydrogen
chloride,
mercury,
and
the
alternative
total
selected
metals
emission
limit;
and
ii.
Maintain
the
fabric
filter
operation
such
that
the
operating
limit
established
for
fabric
filters
in
§
63.7530(
c)(
6)(
v)
is
maintained.
e.
A
wet
scrubber
in
combination
with
an
electrostatic
precipitator.
Maintain
the
minimum
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
minimum
voltage
and
secondary
current
or
total
power
input
of
the
electrostatic
precipitator
at
or
above
the
operating
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
particulate
matter,
hydrogen
chloride
and
mercury
or
the
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
hydrogen
chloride,
mercury,
and
the
alternative
total
selected
metals
emission
limit.
f.
A
dry
scrubber
..............................................
i.
Maintain
the
minimum
sorbent
injection
rate
of
the
dry
scrubber
at
or
above
the
operating
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
hydrogen
chloride
emissions;
and
ii.
Maintain
opacity
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
particulate
matter
and
mercury
emissions
or
the
opacity
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
alternative
emission
limits
for
total
selected
metals
and
the
mercury
emission
limit.

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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
2.
A
TO
SUBPART
DDDDD
OF
PART
63
 
OPERATING
LIMITS
FOR
BOILERS
AND
PROCESS
HEATERS
IN
THE
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
You
must
meet
these
operating
limits
.
.
.

g.
A
dry
scrubber
in
combination
with
a
fabric
filter.
i.
Maintain
minimum
sorbent
injection
rate
of
the
dry
scrubber
at
or
above
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
hydrogen
chloride
emissions;
and
ii.
Maintain
the
fabric
filter
operation
such
that
the
operating
limit
established
for
fabric
filters
in
§
63.7530(
c)(
6)(
v)
is
maintained.

2.
Each
new
or
reconstructed
industrial,
commercial
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
limited
use
solid
fuel
subcategory,
or
the
small
solid
fuel
subcategory
that
is
complying
with
the
alternative
total
selected
metals
emission
limit
instead
of
the
particulate
matter
emission
limit
(
this
is
an
option
for
those
units
that
can
demonstrate
compliance
on
the
basis
of
fuel
analysis
without
controls).
a.
Either
no
add­
on
controls
or
add­
on
controls
for
which
you
do
not
wish
to
take
credit
for
any
emission
reduction
of
total
selected
metals
or
mercury.
i.
Maintain
the
fuel
total
selected
metals
content
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
total
selected
metals;
and
ii.
Maintain
the
fuel
chlorine
content
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
hydrogen
chloride;
and
iii.
Maintain
the
fuel
mercury
content
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
mercury.

3.
Each
existing
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory.
a.
An
add­
on
control
other
than
a
wet
scrubber
or
a
dry
scrubber.
i.
Maintain
opacity
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
particulate
matter
and
mercury
or
the
opacity
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
alternative
emission
limit
for
total
selected
metals
and
the
mercury
emission
limit;
and
ii.
Maintain
the
fuel
chlorine
content
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
hydrogen
chloride.
b.
A
fabric
filter
either
alone
or
in
combination
with
an
add­
on
control
other
than
a
wet
scrubber
or
a
dry
scrubber.
i.
Maintain
the
fabric
filter
operation
such
that
the
operating
limit
established
for
fabric
filters
in
§
63.7530(
c)(
6)(
v)
is
maintained;
and
ii.
Maintain
the
fuel
chlorine
content
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
hydrogen
chloride.
c.
A
wet
scrubber
.............................................
Maintain
the
minimum
pH,
pressure
drop,
and
liquid
flow­
rate
at
or
above
the
operating
levels
established
during
the
performance
test
according
to
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
particulate
matter,
hydrogen
chloride,
and
mercury
emissions
or
the
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
hydrogen
chloride
mercury,
and
the
alternative
total
selected
metals
emission
limit.

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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
2.
A
TO
SUBPART
DDDDD
OF
PART
63
 
OPERATING
LIMITS
FOR
BOILERS
AND
PROCESS
HEATERS
IN
THE
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
You
must
meet
these
operating
limits
.
.
.

d.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
Maintain
the
minimum
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
at
or
above
the
operating
levels
established
during
the
performance
test
according
to
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
particulate
matter,
hydrogen
chloride,
and
mercury
emissions
or
the
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
hydrogen
chloride,
mercury,
and
the
alternative
total
selected
metals
emission
limit;
and
ii.
Maintain
the
fabric
filter
operation
such
that
the
operating
limit
established
for
fabric
filters
in
§
63.7530(
c)(
6)(
v)
is
maintained.
e.
A
wet
scrubber
in
combination
with
an
electrostatic
precipitator.
Maintain
the
minimum
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
minimum
voltage
and
secondary
current
or
total
power
input
of
the
electrostatic
precipitator
at
or
above
the
operating
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
particulate
matter,
hydrogen
chloride
and
mercury
emissions
or
the
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
hydrogen
chloride,
mercury
and
the
alternative
total
selected
metals
emission
limit.
f.
A
dry
scrubber
..............................................
i.
Maintain
the
minimum
sorbent
injection
rate
of
the
dry
scrubber
at
or
above
the
operating
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
hydrogen
chloride
emissions;
and
ii.
Maintain
opacity
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
particulate
matter
and
mercury
or
the
opacity
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
alternative
emission
limit
for
total
selected
metals
and
the
mercury
emission
limit.
g.
A
dry
scrubber
in
combination
with
a
fabric
filter.
i.
Maintain
minimum
sorbent
injection
rate
of
the
dry
scrubber
at
or
above
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
hydrogen
chloride
emissions;
and
ii.
Maintain
the
fabric
filter
operation
such
that
the
operating
limit
established
for
fabric
filters
in
§
63.7530(
c)(
6)(
v)
is
maintained.

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E:\
FR\
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13JAP2.
SGM
13JAP2
1719
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
2.
A
TO
SUBPART
DDDDD
OF
PART
63
 
OPERATING
LIMITS
FOR
BOILERS
AND
PROCESS
HEATERS
IN
THE
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
You
must
meet
these
operating
limits
.
.
.

4.
Each
existing
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory
that
is
complying
with
the
alternative
total
selected
metals
emission
limit
instead
of
the
particulate
matter
emission
limit
(
this
is
an
option
for
those
units
that
can
demonstrate
compliance
on
the
basis
of
fuel
analysis
without
controls).
a.
Either
no
add­
on
controls
or
add­
on
controls
for
which
you
do
not
wish
to
take
credit
for
any
emission
reduction
of
total
selected
metals
or
mercury.
i.
Maintain
the
fuel
total
selected
metals
content
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
total
selected
metals;
and
ii.
Maintain
the
fuel
chlorine
content
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
hydrogen
chloride;
and
iii.
Maintain
the
fuel
mercury
content
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
mercury.

5.
Each
existing
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
limited
use
solid
fuel
subcategory.
a.
An
add­
on
control
other
than
a
wet
scrubber
Maintain
opacity
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
particulate
matter
or
the
operating
level
established
during
the
performance
test
that
demonstrated
compliance
with
the
alternative
emission
limit
for
total
selected
metals.
b.
A
fabric
filter
either
alone
or
in
combination
with
an
add­
on
control
other
than
a
wet
scrubber.
i.
Maintain
opacity
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
particulate
matter
or
the
operating
level
established
during
the
performance
test
that
demonstrated
compliance
with
the
alternative
emission
limit
for
total
selected
metals;
and
ii.
Maintain
the
fabric
filter
operation
such
that
the
operating
limit
established
for
fabric
filters
in
§
63.7530(
c)(
6)(
v)
is
maintained.
c.
A
wet
scrubber
.............................................
Maintain
the
minimum
pressure
drop
and
liquid
flow­
rate
at
or
above
the
operating
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
particulate
matter
emissions
or
the
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
alternative
total
selected
metals
emission
limit.
d.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
Maintain
the
minimum
pressure
drop
and
liquid
flow­
rate
at
or
above
the
operating
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
particulate
matter
emissions
or
the
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
alternative
total
selected
metals
emission
limit;
and
ii.
Maintain
the
fabric
filter
operation
such
that
the
operating
limit
established
for
fabric
filters
in
§
63.7530(
c)(
6)(
v)
is
maintained.

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8
/
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January
13,
2003
/
Proposed
Rules
TABLE
2.
A
TO
SUBPART
DDDDD
OF
PART
63
 
OPERATING
LIMITS
FOR
BOILERS
AND
PROCESS
HEATERS
IN
THE
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
You
must
meet
these
operating
limits
.
.
.

e.
A
wet
scrubber
in
combination
with
an
electrostatic
c
precipitator.
Maintain
the
minimum
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
minimum
voltage
and
secondary
current
of
the
electrostatic
precipitator
at
or
above
the
operating
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
particulate
matter
emissions
or
the
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
alternative
total
selected
metals
emission
limit.

6.
Each
existing
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
limited
use
solid
fuel
subcategory
that
is
complying
with
the
alternative
total
selected
metals
emission
limit
instead
of
the
particulate
matter
emission
limit
(
this
is
an
option
for
those
units
that
can
demonstrate
compliance
on
the
basis
of
fuel
analysis
without
controls).
Either
no
add­
on
controls
for
which
you
do
not
wish
to
take
credit
for
any
emission
reduction
of
total
selected
metals.
Maintain
the
fuel
total
selected
metals
content
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
total
selected
metals.

As
stated
in
§
63.7500,
you
must
comply
with
the
following
applicable
operating
limits:

TABLE
2.
B
TO
SUBPART
DDDDD
OF
PART
63
 
OPERATING
LIMITS
FOR
BOILERS
AND
PROCESS
HEATERS
IN
THE
LARGE,
LIMITED
USE,
OR
SMALL
LIQUID
FUEL
SUBCATEGORIES
For
.
.
.
That
is
controlled
with
.
.
.
You
must
meet
these
operating
limits
.
.
.

1.
Each
new
or
reconstructed
industrial,
commercial
institutional
boiler
or
process
heater
in
the
large
liquid
fuel
subcategory,
the
limited
use
liquid
fuel
subcategory,
or
the
small
liquid
fuel
subcategory
(
boilers
or
process
heaters
in
one
of
the
liquid
fuel
subcategories
that
burn
only
fossil
fuels
and
gases
and
do
not
burn
any
residual
oil
are
excluded
from
this
operating
limit).
a.
An
add­
on
control
other
than
a
wet
scrubber
or
a
dry
scrubber.
i.
Maintain
opacity
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
particulate
matter;
and
ii.
Maintain
the
fuel
chlorine
content
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
hydrogen
chloride.
b.
A
fabric
filter
either
alone
or
in
combination
with
an
add­
on
control
other
than
a
wet
scrubber
or
a
dry
scrubber.
i.
Maintain
the
fabric
filter
operation
such
that
the
operating
limit
established
for
fabric
filters
in
§
63.7530(
c)(
6)(
v)
is
maintained;
and
ii.
Maintain
the
fuel
chlorine
content
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
hydrogen
chloride.
c.
A
wet
scrubber
.............................................
Maintain
the
minimum
pH,
pressure
drop,
and
liquid
flow­
rate
at
or
above
the
operating
levels
established
during
the
performance
test
according
to
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
particulate
matter
emissions
and
hydrogen
chloride
emissions.
d.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
Maintain
the
minimum
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
at
or
above
the
operating
levels
established
during
the
performance
test
according
to
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
particulate
matter
emissions
and
hydrogen
chloride
emissions;
and
ii.
Maintain
the
fabric
filter
operation
such
that
the
operating
limit
established
for
fabric
filters
in
§
63.7530(
c)(
6)(
v)
is
maintained.

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Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
2.
B
TO
SUBPART
DDDDD
OF
PART
63
 
OPERATING
LIMITS
FOR
BOILERS
AND
PROCESS
HEATERS
IN
THE
LARGE,
LIMITED
USE,
OR
SMALL
LIQUID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
You
must
meet
these
operating
limits
.
.
.

e.
A
wet
scrubber
in
combination
with
an
electrostatic
precipitator.
Maintain
the
minimum
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
minimum
voltage
and
secondary
current
or
total
power
input
of
the
electrostatic
precipitator
at
or
above
the
operating
levels
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
particulate
matter
emissions
and
hydrogen
chloride
emissions.
f.
A
dry
scrubber
..............................................
i.
Maintain
the
minimum
sorbent
injection
rate
of
the
dry
scrubber
at
or
above
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limits
for
hydrogen
chloride
emissions;
and
ii.
maintain
opacity
to
less
than
or
equal
to
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
particulate
matter
emissions.
g.
A
dry
scrubber
in
combination
with
a
fabric
filter.
i.
Maintain
the
minimum
sorbent
injection
rate
of
the
dry
scrubber
at
or
above
the
operating
level
established
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
c)
that
demonstrated
compliance
with
the
emission
limit
for
hydrogen
chloride
emissions;
and
ii.
Maintain
the
fabric
filter
operation
such
that
the
operating
limit
established
for
fabric
filters
in
§
63.7530(
c)(
6)(
v)
is
maintained.

As
stated
in
§
63.7500,
you
must
comply
with
the
following
applicable
work
practice
standards:

TABLE
3
TO
SUBPART
DDDDD
OF
PART
63
 
WORK
PRACTICE
STANDARDS
For
each
.
.
.
You
must
.
.
.

1.
New
or
reconstructed
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
large
liquid
fuel
subcategory,
or
the
large
gaseous
fuel
subcategory.
Continuously
monitor
carbon
monoxide
emissions
according
to
the
procedures
in
§
63.7525(
a)
to
maintain
carbon
monoxide
emissions
at
or
below
an
exhaust
concentration
of
400
ppm
by
volume
on
a
dry
basis
corrected
to
3
percent
oxygen.
The
averaging
time
shall
be
1
calendar
day.

2.
New
or
reconstructed
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
limited
use
solid
fuel
subcategory,
the
limited
use
liquid
fuel
subcategory,
or
the
limited
use
gaseous
fuel
subcategory
Continuously
monitor
carbon
monoxide
emissions
according
to
the
procedures
in
§
63.7525(
a)
to
maintain
carbon
monoxide
emissions
at
or
below
an
exhaust
concentration
of
400
ppm
by
volume
on
a
dry
basis
corrected
to
3
percent
oxygen.
The
averaging
time
shall
be
1
calendar
day.

As
stated
in
§
63.7520,
you
must
comply
with
the
following
requirements
for
performance
test
for
existing,
new
or
reconstructed
affected
sources:

TABLE
4.
A
TO
SUBPART
DDDDD
OF
PART
63
 
REQUIREMENTS
FOR
PERFORMANCE
TESTS
FOR
PARTICULATE
MATTER
EMISSIONS
OR
TOTAL
SELECTED
METALS
EMISSIONS
FROM
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
For
.
.
.
That
is
controlled
with
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.

1.
Each
new
reconstructed,
or
existing
industrial,
commercial
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
limited
use
solid
fuel
subcategory
or
the
small
solid
fuel
subcategory.
a.
Any
type
of
device
...............
1.
Select
sampling
ports
location
and
the
number
of
traverse
points.
Method
1
of
40
CFR
part
60,
appendix
A.

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/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
4.
A
TO
SUBPART
DDDDD
OF
PART
63
 
REQUIREMENTS
FOR
PERFORMANCE
TESTS
FOR
PARTICULATE
MATTER
EMISSIONS
OR
TOTAL
SELECTED
METALS
EMISSIONS
FROM
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.

ii.
Determine
velocity
and
volumetric
flow­
rate
of
the
stack
gas.
Either
Method
2
in
appendix
A
to
part
60
of
this
chapter,
Method
2F
in
appendix
A
to
part
60
of
this
chapter,
or
Method
2G
of
appendix
A
to
part
60
of
this
chapter..
iii.
Determine
oxygen
and
carbon
dioxide
concentrations
of
the
stack
gas.
Method
3A
or
3B
in
appendix
A
to
part
60
of
this
chapter.

iv.
Measure
moisture
content
of
the
stack
gas.
Method
4
in
appendix
A
to
part
60
of
this
chapter.
b.
Any
type
of
device
except
positive
pressure
fabric
filters
Measure
the
particulate
matter
emission
concentrations.
Method
5
in
appendix
A
to
part
60
of
this
chapter
or
Method
17
in
appendix
A
to
part
60
of
this
chapter.
c.
Positive
pressure
fabric
filters
Measure
the
particulate
matter
emission
concentrations.
Method
5D
in
appendix
A
to
part
60
of
this
chapter
d.
Any
type
of
device
...............
Convert
emissions
concentrations
to
lb
per
MMBtu
emission
rates.
The
F­
factor
methodology
in
Method
19
in
appendix
A
to
part
60
of
this
chapter.

2.
Each
new
reconstructed,
or
existing
industrial,
commercial
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
limited
use
solid
fuel
subcategory
or
the
small
solid
fuel
subcategory
that
is
complying
with
the
alternative
total
selected
metals
emission
limit
instead
of
particulate
matter.
Any
type
of
device
...................
Measure
the
total
selected
metals
emissions
concentrations
Method
29
in
appendix
A
to
part
60
of
this
chapter.

3.
Each
new
or
reconstructed
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
limited
use
solid
fuel
subcategory,
or
the
small
solid
fuel
subcategory.
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber.
i.
Establish
a
site­
specific
maximum
opacity
level
according
to
provisions
in
§
63.7530(
c).
(
1)
Data
from
the
continuous
opacity
monitoring
system
and
the
PM
or
total
selected
metals
performance
test.
(
a)
You
must
collect
opacity
monitoring
data
every
10
seconds
during
the
entire
period
of
the
three­
run
PM
or
total
selected
metals
performance
test;
and
(
b)
Determine
the
maximum
opacity
level
of
all
the
1­
hour
averages
taken
during
the
three­
run
performance
test.
b.
A
wet
scrubber
....................
i.
Establish
a
site­
specific
minimum
pressure
drop
and
minimum
liquid
flow­
rate
operating
limit
for
the
wet
scrubber
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pressure
drop
and
liquid
flow­
rate
monitors
and
the
PM
or
total
selected
metals
performance
test.
(
a)
You
must
collect
pressure
drop
and
liquid
flow­
rate
data
every
15
minutes
during
the
entire
period
of
the
three­
run
PM
or
total
selected
metals
performance
test;
and
(
b)
determine
the
average
pressure
drop
and
liquid
flow­
rate
for
each
individual
test
run
in
the
three­
run
performance
test
by
computing
the
average
of
all
the
15­
minute
readings
taken
during
the
test
run.
c.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
Establish
a
site­
specific
minimum
pressure
drop
and
liquid
flow­
rate
operating
limit
for
the
wet
scrubber
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pressure
drop
and
liquid
flow­
rate
monitors
and
the
PM
or
total
selected
metals
performance
test.
(
a)
You
must
collect
pressure
drop
and
liquid
flow­
rate
data
for
the
wet
scrubber
every
15
minutes
during
the
entire
period
of
the
three­
run
PM
or
total
selected
metals
performance
test;
and
(
b)
Determine
the
average
pressure
drop
and
liquid
flow­
rate
for
each
individual
test
run
in
the
three­
run
performance
test
by
computing
the
average
of
all
the
15­
minute
readings
taken
during
the
test
run.

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13JAP2
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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
4.
A
TO
SUBPART
DDDDD
OF
PART
63
 
REQUIREMENTS
FOR
PERFORMANCE
TESTS
FOR
PARTICULATE
MATTER
EMISSIONS
OR
TOTAL
SELECTED
METALS
EMISSIONS
FROM
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.

d.
A
wet
scrubber
in
combination
with
an
electrostatic
precipitator
i.
Establish
a
site­
specific
minimum
pressure
drop
and
liquid
flow­
rate
for
the
wet
scrubber
and
minimum
voltage
and
secondary
current
or
total
power
input
of
the
electrostatic
precipitator
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pressure
drop
and
liquid
flow­
rate
monitors
for
the
wet
scrubber
and
from
total
current
and
voltage
monitors
for
the
electrostatic
precipitator
or
and
the
PM
or
total
selected
metals
performance
test.
(
a)
You
must
collect
pressure
drop
and
liquid
flow­
rate
data
for
the
wet
scrubber
and
secondary
current
and
voltage
or
total
power
input
for
the
electrostatic
precipitator
every
15
minutes
during
the
entire
period
of
the
three­
run
PM
or
total
selected
metals
performance
test;
and
(
b)
Determine
the
average
for
each
by
computing
the
average
of
all
15­
minute
readings
taken
during
the
test
run.

4.
Each
new
or
reconstructed
industrial,
commercial,
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
limited
use
solid
fuel
subcategory,
or
the
small
solid
fuel
subcategory
that
is
complying
with
the
alternative
total
selected
metals
emission
limit
instead
of
the
particulate
matter
emission
limit
(
this
is
an
option
for
those
units
that
can
demonstrate
compliance
on
the
basis
of
fuel
analysis
without
controls).
a.
Either
no
add­
on
controls
or
an
add­
on
control
for
which
you
do
not
wish
to
take
credit
for
reductions
in
total
selected
metals.
i.
Establish
a
site­
specific
maximum
inlet
fuel
total
selected
metals
content
operating
limit
according
to
the
provisions
in
§
63.7530(
c).
(
1)
The
fuel
total
selected
metals
content
analysis
results
and
the
calculations
done
according
to
the
provisions
in
§
63.7530(
c).
(
a)
You
must
collect
one
sample
of
the
worst­
case
fuel
stream
entering
the
boiler
or
process
heater
for
each
test
run
during
the
three­
run
performance
test;
and
(
b)
Determine
the
total
selected
metals
content
and
heating
value
of
the
sample
according
to
your
site­
specific
test
plan
as
required
in
§
63.7520(
a);
and
(
c)
Determine
the
maximum
total
selected
metals
content
operating
limit
according
to
the
procedures
in
§
63.7530(
c).

5.
Each
existing
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory
or
the
limited
use
solid
fuel
subcategory.
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber.
i.
Establish
a
site­
specific
maximum
opacity
level
according
to
provisions
in
§
63.7530(
c).
(
1)
Data
from
the
continuous
opacity
monitoring
system
and
the
PM
or
total
selected
metals
performance
test.
(
a)
You
must
collect
opacity
monitoring
data
every
10
seconds
during
the
entire
period
of
the
three­
run
PM
or
total
selected
metals
performance
test;
and
(
b)
Determine
the
maximum
opacity
level
for
all
the
1­
hour
averages
taken
during
the
three­
run
performance
test.
b.
A
wet
scrubber
....................
i.
Establish
a
site­
specific
minimum
pressure
drop
and
minimum
liquid
flow­
rate
operating
limit
for
the
wet
scrubber
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pressure
drop
and
liquid
flow­
rate
monitors
and
the
PM
or
total
selected
metals
performance
test.
(
a)
You
must
collect
pressure
drop
and
liquid
flow­
rate
data
every
15
minutes
during
the
entire
period
of
the
three­
run
PM
or
total
selected
metals
performance
test;
and
(
b)
Determine
the
average
pressure
drop
and
liquid
flow­
rate
for
each
individual
test
run
in
the
three­
run
performance
test
by
computing
the
average
of
all
the
15­
minute
readings
taken
during
the
test
run.
c.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
Establish
a
site­
specific
minimum
pressure
drop
and
liquid
flow­
rate
operating
limit
for
the
wet
scrubber
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pressure
drop
liquid
flow­
rate
monitors
and
the
PM
or
total
selected
metals
performance
test.
(
a)
You
must
collect
pressure
drop
and
liquid
flow­
rate
data
for
the
wet
scrubber
every
15
minutes
during
the
entire
period
of
the
three­
run
PM
or
total
selected
metals
performance
test;
and
(
b)
Determine
the
average
pressure
drop
and
liquid
flow­
rate
for
each
individual
test
run
in
the
three­
run
performance
test
by
computing
the
average
of
all
the
15­
minute
readings
taken
during
the
test
run.

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E:\
FR\
FM\
13JAP2.
SGM
13JAP2
1724
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
4.
A
TO
SUBPART
DDDDD
OF
PART
63
 
REQUIREMENTS
FOR
PERFORMANCE
TESTS
FOR
PARTICULATE
MATTER
EMISSIONS
OR
TOTAL
SELECTED
METALS
EMISSIONS
FROM
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.

d.
A
wet
scrubber
in
combination
with
an
electro­
static
precipitator.
i.
Establish
a
site­
specific
minimum
pressure
drop
and
liquid
flow­
rate
for
the
wet
scrubber
and
minimum
voltage
and
secondary
current
or
total
power
input
of
the
electrostatic
precipitator
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pressure
drop
and
liquid
flow­
rate
monitors
for
the
wet
scrubber
and
from
the
current
and
voltage
monitors
for
the
electrostatic
precipitator
and
the
PM
or
total
selected
metals
performance
test.
(
a)
You
must
collect
pressure
drop
and
liquid
flow­
rate
data
for
the
wet
scrubber
and
secondary
current
and
voltage
or
total
power
input
for
the
electrostatic
precipitator
every
15
minutes
during
the
entire
period
of
the
three­
run
PM
or
total
selected
metals
performance
test;
and
b.
Determine
the
average
for
each
by
computing
the
average
of
all
15­
minute
readings
taken
during
each
test
run.

6.
Each
existing
industrial,
commercial
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory
or
the
limited
use
solid
fuel
subcategory
that
is
complying
with
the
alternative
total
selected
metals
emission
limit
instead
of
the
particulate
matter
emission
limit
(
this
is
an
option
for
those
units
that
can
demonstrate
compliance
on
the
basis
of
fuel
analysis
without
controls).
a.
Either
no
add­
on
controls
or
an
add­
on
control
for
which
you
do
not
wish
to
take
credit
for
reductions
in
total
selected
metals.
i.
Establish
a
site­
specific
maximum
inlet
fuel
total
selected
metals
content
operating
limit
according
to
the
provisions
in
§
63.7530(
c).
(
1)
The
fuel
total
selected
metals
content
analysis
results
and
the
calculations
done
according
to
the
provisions
in
§
63.7530(
c).
(
a)
You
must
collect
one
sample
of
the
worst­
case
fuel
stream
entering
the
boiler
or
process
heater
for
each
test
run
during
the
three­
run
performance
test;
and
(
b)
Determine
the
total
selected
metals
content
and
heating
value
of
the
sample
according
to
your
site­
specific
test
plan
as
required
in
§
63.7520(
a);
and
(
c)
Determine
the
maximum
total
selected
metals
content
operating
limit
according
to
the
procedures
in
§
63.7530(
c).

As
stated
in
§
63.7520,
you
must
comply
with
the
following
requirements
for
performance
tests
for
new
or
reconstructed
affected
sources:

TABLE
4.
B
TO
SUBPART
DDDDD
OF
PART
63
 
REQUIREMENTS
FOR
PERFORMANCE
TESTS
FOR
PARTICULATE
MATTER
EMISSIONS
FROM
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
LIQUID
FUEL
SUBCATEGORIES
For
.
.
.
That
is
controlled
with
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.

1.
Each
new
or
reconstructed
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
large
liquid
fuel
subcategory,
the
limited
use
liquid
fuel
subcategory,
or
the
small
liquid
fuel
subcategory
(
boilers
or
process
heaters
in
one
of
the
liquid
fuel
subcategories
that
burn
only
fossil
fuels
and
other
gases
and
do
not
burn
residual
oil
are
excluded
from
this
performance
test).
a.
Any
type
of
device
...............
i.
Select
sampling
ports
location
and
the
number
of
traverse
points.
Method
1
of
40
CFR
part
60
appendix
A.

ii.
Determine
velocity
and
volumetri
c
flow­
rate
of
the
stack
gas.
Either
Method
2
in
appendix
A
to
part
60
of
this
chapter,
Method
2F
in
appendix
A
to
part
60
of
this
chapter
or
Method
2G
of
appendix
A
to
part
60
of
this
chapter..
iii.
Determine
oxygen
and
carbon
dioxide
concentrations
of
the
stack
gas.
Method
3A
or
3B
in
appendix
A
to
part
60
of
this
chapter.

iv.
Measure
moisture
content
of
the
stack
gas.
Method
4
in
appendix
A
to
part
60
of
this
chapter.
v.
Measure
the
particulate
matter
emission
concentrations.
Method
5
in
appendix
A
to
part
60
of
this
chapter
or
Method
17
in
appendix
A
to
part
60
of
this
chapter.
vi.
Convert
emissions
concentrations
to
lb
per
MMBtu
emission
rates.
The
F­
factor
methodology
in
Method
19
in
appendix
A
to
part
60
of
this
chapter.

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E:\
FR\
FM\
13JAP2.
SGM
13JAP2
1725
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
4.
B
TO
SUBPART
DDDDD
OF
PART
63
 
REQUIREMENTS
FOR
PERFORMANCE
TESTS
FOR
PARTICULATE
MATTER
EMISSIONS
FROM
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
LIQUID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.

b.
Positive
pressure
fabric
filters
Measure
the
particulate
matter
emission
concentrations.
Method
5D
in
appendix
A
to
part
60
of
this
chapter.
c.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber.
i.
Establish
a
site­
specific
maximum
opacity
level
according
to
the
provisions
in
§
63.7530(
c).
(
1)
Data
from
the
continuous
opacity
monitoring
system
and
the
PM
performance
test.
(
a)
You
must
collect
opacity
monitoring
data
every
10
seconds
during
the
entire
period
of
the
three­
run
PM
performance
test;
and
(
b)
Determine
the
maximum
opacity
level
for
all
the
1­
hour
averages
taken
during
the
three­
run
performance
test.
d.
A
wet
scrubber
....................
i.
Establish
a
site­
specific
minimum
pressure
drop
and
minimum
liquid
flow­
rate
operating
limit
for
the
web
scrubber
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pressure
drop
and
liquid
flow­
rate
monitors
and
the
PM
performance
test.
(
a)
You
must
collect
pressure
drop
and
liquid
flow­
rate
data
every
15
minutes
during
the
entire
period
of
the
three­
run
PM
performance
test;
and
(
b)
Determine
the
average
pressure
drop
and
liquid
flow­
rate
for
each
individual
test
run
in
the
three­
run
performance
test
by
computing
the
average
of
all
the
15­
minute
readings
taken
during
the
test
run.
e.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
Establish
a
site­
specific
minimum
pressure
drop
and
liquid
flow­
rate
operating
limit
for
the
set
scrubber
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pressure
drop
and
liquid
flow­
rate
monitors
and
the
PM
performance
test.
(
a)
You
must
collect
pressure
drop
and
liquid
flow­
rate
data
for
the
wet
scrubber
every
15
minutes
during
the
entire
period
of
the
three­
run
PM
performance
test;
and
(
b)
Determine
the
average
pressure
drop
and
liquid
flow­
rate
for
each
individual
test
run
in
the
three­
run
performance
test
by
computing
the
average
of
all
the
15­
minute
readings
taken
during
the
test
run.
f.
A
wet
scrubber
in
combination
with
an
electrostatic
precipitator
i.
Establish
a
site­
specific
minimum
pressure
drop
and
liquid
flow­
rate
operating
limit
for
the
wet
scrubber
and
a
site­
specific
minimum
voltage
and
secondary
or
total
power
input
current
operating
limit
for
the
electrostatic
precipitator
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pressure
drop
and
liquid
flow­
rate
monitors
for
the
wet
scrubber
and
from
the
current
and
voltage
monitors
for
the
electrostatic
precipitator
and
the
PM
performance
test.
(
a)
You
must
collect
pressure
drop
and
liquid
flow­
rate
data
for
the
wet
scrubber
and
secondary
current
and
voltage
data
or
total
power
input
for
the
electrostatic
precipitator
every
15
minutes
during
the
entire
period
of
the
three­
run
PM
performance
test;
(
b)
Determine
the
average
for
each
by
computing
the
average
of
all
15­
minute
readings
taken
during
each
test
run.

As
stated
in
§
63.7520,
you
must
comply
with
the
following
requirements
for
performance
tests
for
existing,
new
or
reconstructed
affected
sources:

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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
4.
C
TO
SUBPART
DDDDD
OF
PART
63
 
REQUIREMENTS
FOR
PERFORMANCE
TESTS
FOR
HYDROGEN
CHLORIDE
EMISSIONS
FROM
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USED,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
For
.
.
.
That
is
controlled
with
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.

1.
Each
new
or
reconstructed
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
limited
use
solid
fuel
subcategory,
or
small
solid
fuel
subcategory
and
each
existing
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory
a.
Any
type
of
device
...............
i.
Select
sampling
ports
location
and
the
number
of
traverse
points.
Method
1
of
40
CFR
part
60
appendix
A.

ii.
Determine
velocity
and
volumetric
flow­
rate
of
the
stack
gas.
Either
Method
2
in
appendix
A
to
part
60
of
this
chapter,
Method
2F
in
appendix
A
to
part
60
of
this
chapter
or
Method
2G
of
appendix
A
to
part
60
of
this
chapter.
iii.
Determine
oxygen
and
carbon
dioxide
concentrations
of
the
stack
gas.
Method
3A
or
3B
in
appendix
A
to
part
60
of
this
chapter.

iv.
Measure
moisture
content
of
the
stack
gas.
Method
4
in
appendix
A
to
part
60
of
this
chapter.
b.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber.
Measure
the
hydrogen
chloride
emissions
concentrations.
Method
26
in
appendix
A
to
part
60
of
this
chapter.

c.
A
wet
scrubber
.....................
Measure
the
hydrogen
chloride
emissions
concentrations.
Method
26A
in
appendix
A
to
part
60
of
this
chapter.
d.
Any
type
of
device
...............
Convert
emissions
concentrations
to
lb
per
MMBtu
emission
rates.
The
F­
factor
methodology
in
Method
19
in
appendix
A
to
part
60
of
this
chapter.
2.
Each
new
or
reconstructed
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
limited
use
solid
fuel
subcategory,
or
the
small
solid
fuel
subcategory.
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber
or
a
dry
scrubber.
i.
Establish
a
site­
specific
maximum
inlet
fuel
chlorine
content
operating
limit
according
to
the
provisions
in
§
63.7530(
c).
(
1)
The
fuel
chlorine
content
analysis
results
and
data
from
the
hydrogen
chloride
performance
test.
(
a)
You
must
collect
one
sample
of
the
fuel
stream
entering
the
boiler
or
process
heater
for
each
test
run
during
the
three­
run
hydrogen
chloride
performance
test;
and
(
b)
Determine
the
chlorine
content
and
heating
value
of
each
fuel
sample;
and
(
c)
Determine
the
maximum
chlorine
content
operating
limit
according
to
the
procedures
in
§
63.7530(
c)
and
the
procedures
in
your
sitespecific
test
plan
as
required
in
§
63.7520(
a).
b.
A
wet
scrubber
....................
i.
Establish
site­
specific
minimum
pH,
pressure
drop,
and
liquid
flow­
rate
operating
limits
for
the
wet
scrubber
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pH,
presure
drop,
and
liquid
flow­
rate
monitors
and
the
hydrogen
chloride
performance
test.
(
a)
You
must
collect
pH,
pressure
drop,
and
liquid
flowrate
data
every
15
minutes
during
the
entire
period
of
the
three­
run
hydrogen
chloride
performance
test;
and
(
b)
Determine
the
average
pH,
pressure
drop,
and
liquid
flow­
rate
for
each
individual
test
run
in
the
three­
run
performance
test
by
computing
the
average
of
all
the
15­
minute
readings
taken
during
the
test
run.
c.
A
dry
scrubber
.....................
i.
Establish
site­
specific
minimum
sorbent
injection
rate
operating
limit
for
the
dry
scrubber
according
to
the
provisions
in
§
63.7530(
c).
(
1)
Data
from
the
sorbent
injection
rate
monitors
and
the
hydrogen
chloride
performance
test.
(
a)
You
must
collect
sorbent
injection
rate
data
every
15
minutes
during
the
entire
period
of
the
three­
run
hydrogen
chloride
performance
test;
and
(
b)
Determine
the
average
sorbent
injection
rate
of
each
individual
test
run
in
the
three­
run
performance
test
by
computing
the
average
of
all
the
15­
minute
readings
taken
during
the
test
run.

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FR\
FM\
13JAP2.
SGM
13JAP2
1727
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
4.
C
TO
SUBPART
DDDDD
OF
PART
63
 
REQUIREMENTS
FOR
PERFORMANCE
TESTS
FOR
HYDROGEN
CHLORIDE
EMISSIONS
FROM
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USED,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.

3.
Each
existing
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber
or
a
dry
scrubber.
i.
Establish
a
site­
specific
maximum
inlet
fuel
chlorine
content
operating
limit
according
to
the
provisions
in
§
63.7530(
c).
(
1)
The
fuel
chlorine
content
analysis
results
and
data
from
the
hydrogen
chloride
performance
test.
(
a)
You
must
collect
one
sample
of
the
fuel
stream
entering
the
boiler
or
process
heater
for
each
test
run
during
the
three­
run
hydrogen
chloride
performance
test;
and
(
b)
Determine
the
chlorine
content
and
heating
value
of
each
fuel
sample;
and
(
c)
Determine
the
maximum
chlorine
content
operating
limit
according
to
the
procedures
in
§
63.7530(
c)
and
the
procedures
in
your
sitespecific
test
plan
as
required
in
§
63.7520(
a).
b.
A
wet
scrubber
....................
i.
Establish
site­
specific
minimum
pH,
pressure
drop,
and
liquid
flow­
rate
operating
limits
for
the
wet
scrubber
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pH,
pressure
drop,
and
liquid
flow­
rate
monitors
and
the
hydrogen
chloride
performance
test.
(
a)
You
must
collect
pH,
pressure
drop,
and
liquid
flowrate
data
every
15
minutes
during
the
entire
period
of
the
three­
run
hydrogen
chloride
performance
test;
and
(
b)
Determine
the
average
pH,
pressure
drop,
and
liquid
flow­
rate
for
each
individual
test
run
in
the
three­
run
performance
test
by
computing
the
average
of
all
the
15­
minute
readings
taken
during
the
test
run.
c.
A
dry
scrubber
.....................
i.
Establish
site­
specific
minimum
sorbent
injection
rate
operating
limits
for
the
dry
scrubber
according
to
the
provisions
in
§
63.7530(
c).
(
1)
Data
from
the
sorbent
injection
rate
monitors
and
the
hydrogen
chloride
performance
test.
(
a)
You
must
collect
sorbent
injection
rate
data
every
15
minutes
during
the
entire
period
of
the
three­
run
hydrogen
chloride
performance
test;
and
(
b)
Determine
the
average
sorbent
injection
rate
for
each
individual
test
run
in
the
three­
run
performance
test
by
computing
the
average
of
all
the
15­
minute
readings
taken
during
the
test
run.

As
stated
in
§
63.7520,
you
must
comply
with
the
following
requirements
for
performance
tests
for
new
or
reconstructed
affected
sources:

TABLE
4.
D
TO
SUBPART
DDDDD
OF
PART
63
 
REQUIREMENTS
FOR
PERFORMANCE
TESTS
FOR
HYDROGEN
CHLORIDE
EMISSIONS
FROM
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
LIQUID
FUEL
SUBCATEGORIES
For
.
.
.
That
is
controlled
with
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.

1.
Each
new
or
reconstructed
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
large
liquid
fuel
subcategory,
the
limited
use
liquid
fuel
subcategory,
or
the
small
liquid
fuel
subcategory
(
boilers
or
process
heaters
in
one
of
the
liquid
fuel
subcategories
that
burn
only
fossil
fuels
and
other
gases
and
do
not
burn
residual
oil
are
excluded
from
this
performance
test).
a.
Any
type
of
device
...............
i.
Select
sampling
ports
location
and
the
number
of
traverse
points.
Method
1
of
40
CFR
part
60
appendix
A.

ii.
Determine
velocity
and
volumetric
flow­
rate
of
the
stack
gas.
Either
Method
2
in
appendix
A
to
part
60
of
this
chapter,
Method
2F
in
appendix
A
to
part
60
of
this
chapter
or
Method
2G
of
appendix
A
to
part
60
of
this
chapter.

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E:\
FR\
FM\
13JAP2.
SGM
13JAP2
1728
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
4.
D
TO
SUBPART
DDDDD
OF
PART
63
 
REQUIREMENTS
FOR
PERFORMANCE
TESTS
FOR
HYDROGEN
CHLORIDE
EMISSIONS
FROM
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
LIQUID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.

iii.
Determine
oxygen
and
carbon
dioxide
concentrations
of
the
stack
gas.
Method
3A
or
3B
in
appendix
A
to
part
60
of
this
chapter.

iv.
Measure
moisture
content
of
the
stack
gas.
Method
4
in
appendix
A
to
part
60
of
this
chapter.
b.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber.
Measure
the
hydrogen
chloride
emissions
concentrations.
Method
26
in
appendix
A
to
part
60
of
this
chapter.

c.
A
wet
scrubber
.....................
Measure
the
hydrogen
chloride
emissions
concentrations.
Method
26A
in
appendix
A
to
part
60
of
this
chapter.
d.
Any
type
of
device
...............
Convert
emissions
concentrations
to
lb
per
MMBtu
emission
rates.
The
F­
factor
methodology
in
Method
19
in
appendix
A
to
part
60
of
this
chapter..
e.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber
or
a
dry
scrubber.
i.
Establish
a
site­
specific
maximum
inlet
fuel
chlorine
content
operating
limit
according
to
the
provisions
in
§
63.7530(
c).
(
1)
The
fuel
chlorine
content
analysis
results
and
data
from
the
hydrogen
chloride
performance
test.
(
a)
You
must
collect
one
sample
of
the
fuel
stream
entering
the
boiler
or
process
heater
from
each
test
run
during
the
three­
run
hydrogen
chloride
performance
test;
and
(
b)
Determine
the
chlorine
content
and
heating
value
of
each
fuel
sample;
and
(
c)
Determine
the
average
chlorine
content
operating
limit
according
to
the
procedures
in
§
63.7530(
c)
and
the
procedures
in
your
sitespecific
test
plan
as
required
in
§
63.7520(
a).
f.
A
wet
scrubber
.....................
i.
Establish
site­
specific
minimum
pH,
pressure
drop,
and
liquid
flow­
rate
operating
limits
for
the
wet
scrubber
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pH,
pressure
drop,
and
liquid
flow­
rate
monitors
and
the
hydrogen
chloride
performance
test.
(
a)
You
must
collect
pH,
pressure
drop,
and
liquid
flowrate
data
every
15
minutes
during
the
entire
period
of
the
three­
run
hydrogen
chloride
performance
test;
and
(
b)
Determine
the
average
pH,
pressure
drop,
and
liquid
flow­
rate
for
each
individual
test
run
in
the
three­
run
performance
test
by
computing
the
average
of
all
the
15­
minute
readings
taken
during
the
test
run.
g.
A
dry
scrubber
.....................
i.
Establish
site­
specific
minimum
sorbent
injection
rate
operating
limit
for
the
dry
scrubber
according
to
the
provisions
in
§
63.7530(
c).
(
1)
Data
from
the
sorbent
injection
rate
monitors
and
the
hydrogen
chloride
performance
test.
(
a)
You
must
collect
sorbent
injection
rate
data
every
15
minutes
during
the
entire
period
of
the
three­
run
hydrogen
chloride
performance
test;
and
(
b)
Determine
the
average
sorbent
injection
rate
for
each
individual
test
run
in
the
three­
run
performance
test
by
computing
the
average
of
all
the
15­
minute
readings
taken
during
the
test
run.

As
stated
in
§
63.7520,
you
must
comply
with
the
following
requirements
for
performance
test
for
existing,
new
or
reconstructed
affected
sources:

TABLE
4.
E
TO
SUBPART
DDDDD
OF
PART
63
 
REQUIREMENTS
FOR
PERFORMANCE
TESTS
FOR
MERCURY
EMISSIONS
FROM
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE
OF
SMALL
SOLID
FUEL
SUBCATERGORIES
For
.
.
.
That
is
controlled
with
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.

1.
Each
new
reconstructed,
or
existing
industrial,
commercial
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
limited
use
solid
fuel
subcategory
or
the
small
solid
fuel
subcategory.
a.
Any
type
of
device
...............
i.
Select
sampling
ports
location
and
the
number
of
traverse
points.
Method
1
of
40
CFR
part
60,
appendix
A.

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19:
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2003
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E:\
FR\
FM\
13JAP2.
SGM
13JAP2
1729
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
4.
E
TO
SUBPART
DDDDD
OF
PART
63
 
REQUIREMENTS
FOR
PERFORMANCE
TESTS
FOR
MERCURY
EMISSIONS
FROM
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE
OF
SMALL
SOLID
FUEL
SUBCATERGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.

ii.
Determine
velocity
and
volumetric
flow­
rate
of
the
stack
gas.
Either
Method
2
in
appendix
A
to
part
60
of
this
chapter,
Method
2F
in
appendix
A
to
part
60
of
this
chapter,
or
Method
2G
of
appendix
A
to
part
60
of
this
chapter.
iii.
Determine
oxygen
and
carbon
dioxide
concentrations
of
the
stack
gas.
Method
3A
or
3B
in
appendix
A
to
part
60
of
this
chapter.

iv.
Measure
moisture
content
of
the
stack
gas.
Method
4
in
appendix
A
to
part
60
of
this
chapter.
v.
Convert
emissions
concentrations
to
lb
per
MMBtu
emission
rates.
The
F­
factor
methodology
in
Method
19
in
appendix
A
to
part
60
of
this
chapter.

2.
each
new
reconstructed,
or
existing
industrial,
commercial
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
limited
use
solid
fuel
subcategory
or
the
small
solid
fuel
subcategory
that
has
a
rated
heat
input
capacity
of
less
than
250
MMBtu
per
hour.
Any
type
of
device
...................
Measure
the
mercury
emissions
concentrations.
Method
29
in
appendix
A
to
part
60
of
this
chapter.

3.
Each
new
reconstructed,
or
existing
industrial,
commercial
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory
or
limited
use
solid
fuel
subcategory
that
has
a
rated
heat
input
capacity
of
greater
than
250
MMBtu
per
hour.
Any
type
of
device
...................
Measure
the
mercury
emissions
concentrations.
..................................................
DRAFT
ASTM
Z65907
``
Standard
Method
for
Both
Speciated
and
Elemental
Mercury
Determination.

4.
Each
new
reconstructed
industrial
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
limited
use
solid
fuel
subcategory,
or
the
small
solid
fuel
subcategory.
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber.
i.
Establish
a
site­
specific
maximum
opacity
level
according
to
provisions
in
§
63.7530(
c).
(
1)
Data
from
the
continuous
opacity
monitoring
system
and
the
mercury
performance
test.
(
a)
You
must
collect
opacity
monitoring
data
every
10
seconds
during
the
entire
period
of
the
three­
run
mercury
performance
test;
and
(
b)
determine
the
maximum
opacity
level
of
all
the
1­
hour
averages
taken
during
the
three­
run
performance
test.
b.
A
wet
scrubber
....................
i.
Establish
a
site­
specific
minimum
pressure
drop
and
minimum
liquid
flow­
rate
operating
limit
for
the
wet
scrubber
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pressure
drop
and
liquid
flow­
rate
monitors
and
the
mercury
performance
test.
(
a)
You
must
collect
pressure
drop
and
liquid
flow­
rate
data
every
15
minutes
during
the
entire
period
of
the
three­
run
mercury
performance
test;
and
(
b)
Determine
the
average
pressure
drop
and
liquid
flow­
rate
for
each
individual
test
run
in
the
three­
run
performance
test
by
computing
the
average
of
all
the
15­
minute
readings
taken
during
the
test
run.
c.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
Establish
a
site­
specific
minimum
pressure
drop
and
liquid
flow­
rate
operating
limit
for
the
wet
scrubber
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pressure
drop
and
liquid
flow­
rate
monitors
and
the
mercury
performance
test.
(
a)
You
must
collect
pressure
drop
and
liquid
flow­
rate
data
for
the
wet
scrubber
every
15
minutes
during
the
entire
period
of
the
three­
run
mercury
performance
test;
and
(
b)
Determine
the
average
pressure
drop
and
liquid
flow­
rate
for
each
individual
test
run
in
the
three­
run
performance
test
by
computing
the
average
of
all
the
15­
minute
readings
taken
during
the
test
run.

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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
4.
E
TO
SUBPART
DDDDD
OF
PART
63
 
REQUIREMENTS
FOR
PERFORMANCE
TESTS
FOR
MERCURY
EMISSIONS
FROM
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE
OF
SMALL
SOLID
FUEL
SUBCATERGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.

d.
A
wet
scrubber
in
combination
with
an
electrostatic
precipitator
i.
Establish
a
site­
specific
minimum
pressure
drop
and
liquid
flow­
rate
for
the
wet
scrubber
and
minimum
voltage
and
secondary
current
or
total
power
input
of
the
electrostatic
precipitator
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pressure
drop
and
liquid
flow­
rate
monitors
for
the
wet
scrubber
and
from
the
current
and
voltage
monitors
for
the
electrostatic
precipitator
and
the
mercury
performance
test.
(
a)
You
must
collect
pressure
drop
and
liquid
flow­
rate
data
for
the
wet
scrubber
and
secondary
current
and
voltage
or
total
power
input
for
the
electrostatic
precipitator
every
15
minutes
during
the
entire
period
of
the
three­
run
mercury
performance
test;
and
(
b)
Determine
the
average
for
each
by
computing
the
average
of
all
15­
minute
readings
taken
during
the
test
run.

5.
Each
new
or
reconstructed
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
limited
use
solid
fuel
subcategory,
or
the
small
solid
fuel
subcategory
that
is
complying
with
the
alternative
total
selected
metals
emission
limit
instead
of
the
particulate
matter
emission
limit
(
this
is
an
option
for
those
units
that
can
demonstrate
compliance
on
the
basis
of
fuel
analysis
without
controls).
a.
Either
no
add­
on
controls
or
an
add­
on
control
for
which
you
do
not
wish
to
take
credit
for
reductions
in
mercury
i.
Establish
a
site­
specific
maximum
inlet
fuel
mercury
content
operating
limit
according
to
the
provisions
in
§
63.7530(
c).
(
1)
The
fuel
mercury
content
analysis
results
and
the
calculations
done
according
to
the
provisions
in
§
63.7530(
c).
(
a)
You
must
collect
one
sample
of
the
worst­
case
fuel
stream
entering
the
boiler
or
process
heater
for
each
test
run
during
the
three­
run
performance
test;
and
(
b)
Determine
the
mercury
content
and
heating
value
of
the
sample
according
to
your
site­
specific
test
plan
as
required
in
§
63.7520(
a);
and
(
c)
Determine
the
maximum
mercury
content
operating
limit
according
to
the
procedures
in
§
63.7530(
c).

6.
Each
existing
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber.
i.
Establish
a
site­
specific
maximum
opacity
level
according
to
provisions
in
§
63.7530
(
c).
(
1)
Data
from
the
continuous
opacity
monitoring
system
and
the
mercury
performance
test.
(
a)
You
must
collect
opacity
monitoring
data
every
10
seconds
during
the
entire
period
of
the
three­
run
mercury
performance
test;
and
(
b)
Determine
the
maximum
opacity
level
for
all
the
1­
hour
averages
taken
during
the
three­
run
performance
test.
b.
A
wet
scrubber
....................
i.
Establish
a
site­
specific
minimum
pressure
drop
and
minimum
liquid
flow­
rate
operating
limit
for
the
wet
scrubber
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pressure
drop
and
liquid
flow­
rate
monitors
and
the
mercury
performance
test.
(
a)
You
must
collect
pressure
drop
and
liquid
flow­
rate
data
every
15
minutes
during
the
entire
period
of
the
three­
run
mercury
performance
test;
and
(
b)
Determine
the
average
pressure
drop
and
liquid
flow­
rate
for
each
individual
test
run
in
the
three­
run
performance
test
by
computing
the
average
of
all
the
15­
minute
readings
taken
during
the
test
run.
c.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
Establish
a
site­
specific
minimum
pressure
drop
and
liquid
flow­
rate
operating
limit
for
the
wet
scrubber
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pressure
drop
and
liquid
flow­
rate
monitors
and
the
mercury
performance
test.
(
a)
You
must
collect
pressure
drop
and
liquid
flow­
rate
data
for
the
wet
scrubber
every
15
minutes
during
the
entire
period
of
the
three­
run
mercury
performance
test;
and
(
b)
Determine
the
average
pressure
drop
and
liquid
flow­
rate
for
each
individual
test
run
in
the
three­
run
performance
test
by
computing
the
average
of
all
the
15­
minute
readings
taken
during
the
test
run.

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E:\
FR\
FM\
13JAP2.
SGM
13JAP2
1731
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
4.
E
TO
SUBPART
DDDDD
OF
PART
63
 
REQUIREMENTS
FOR
PERFORMANCE
TESTS
FOR
MERCURY
EMISSIONS
FROM
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE
OF
SMALL
SOLID
FUEL
SUBCATERGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.

d.
A
wet
scrubber
in
combination
with
an
electro­
static
precipitator.
i.
Establish
a
site­
specific
minimum
pressure
drop
and
liquid
flow­
rate
for
the
wet
scrubber
and
minimum
voltage
and
secondary
current
or
total
power
input
of
the
electrostatic
precipitator
according
to
the
provisions
in
§
63.7530(
c)(
3).
(
1)
Data
from
the
pressure
drop
and
liquid
flow­
rate
monitors
for
the
wet
scrubber
and
from
the
current
and
voltage
monitors
for
the
electrostatic
precipitator
and
the
mercury
performance
test.
(
a)
You
must
collect
pressure
drop
and
liquid
flow­
rate
data
for
the
wet
scrubber
and
secondary
current
and
voltage
or
total
power
input
for
the
electrostatic
precipitator
every
15
minutes
during
the
entire
period
of
the
three­
run
mercury
performance
test;
and
(
b)
Determine
the
average
for
each
by
computing
the
average
of
all
15­
minute
readings
taken
during
each
test
run.
e.
Either
no
add­
on
controls
or
an
add­
on
control
for
which
you
do
not
wish
to
take
credit
for
reductions
in
mercury
i.
Establish
a
site­
specific
maximum
inlet
fuel
mercury
content
operating
limit
according
to
the
provisions
in
§
63.7530(
c).
(
1)
The
fuel
mercury
content
analysis
results
and
the
calculations
done
according
to
the
provisions
in
§
63.7530(
c).
(
a)
You
must
collect
one
sample
of
the
worst­
case
fuel
stream
entering
the
boiler
or
process
heater
for
each
test
run
during
the
three­
run
performance
test;
and
(
b)
Determine
the
mercury
content
and
heating
value
of
the
sample
according
to
your
site­
specific
test
plan
as
required
in
§
63.7520(
a);
and
(
c)
Determine
the
maximum
mercury
content
operating
limit
according
to
the
procedures
in
§
63.7530(
c).

As
stated
in
§
63.7530,
you
must
show
initial
compliance
with
the
emission
limitations
for
affected
sources
according
to
the
following:

TABLE
5.
A
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
PARTICULATE
MATTER
OR
TOTAL
SELECTED
METALS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

1.
Each
new
or
reconstructed
industrial
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
limited
use
solid
fuel
subcategory
or
the
small
solid
fuel
subcategory.
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber.
i.
0.026
lb
particulate
matter
per
MMBtu
heat
input
or
0.0001
lb
total
selected
metals
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
particulate
matter
per
MMBtu
heat
input,
measured
using
PM
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
or
the
average
emissions
in
units
of
lb
total
selected
metals
per
MMBtu
heat
input
measured
using
total
selected
metals
emission
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
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13JAP2
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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
5.
A
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
PARTICULATE
MATTER
OR
TOTAL
SELECTED
METALS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

(
2)
You
keep
a
record
of
the
average
site­
specific
opacity
level
for
each
test
run
over
the
threerun
performance
test
during
which
particulate
matter
or
total
selected
metals
emissions
did
not
exceed
the
emissions
limit;
or
if
the
unit
is
controlled
with
a
fabric
filter,
instead
of
establishing
a
site­
specific
opacity
level
you
keep
records
of
the
installation
and
calibration
data
and
the
manufacturer's
certification
of
the
bag
leak
detection
system
as
required
in
§
63.7525(
i).
b.
A
wet
scrubber
.........................
i.
0.026
lb
particulate
matter
per
MMBtu
heat
input
or
0.0001
lb
total
selected
metals
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
particulate
matter
per
MMBtu
heat
input,
measured
using
PM
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
or
the
average
emissions
in
units
of
lb
total
selected
metals
per
MMBtu
heat
input
measured
using
total
selected
metals
emission
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
particulate
matter
or
total
selected
metals
emissions
did
not
exceed
the
emissions
limit.
c.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
0.026
lb
particulate
matter
per
MMBtu
heat
input
or
0.0001
lb
total
selected
metals
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
particulate
matter
per
MMBtu
heat
input,
measured
using
PM
emissions
concentrations
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
or
the
average
emissions
in
units
of
lb
total
selected
metals
per
MMBtu
heat
input
measured
using
total
selected
metals
emission
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period
do
not
exceed
the
emission
limit;
and
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/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
5.
A
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
PARTICULATE
MATTER
OR
TOTAL
SELECTED
METALS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
particulate
matter
or
total
selected
metals
emissions
did
not
exceed
the
emissions
limit;
and
(
3)
You
keep
records
of
the
installation
and
calibration
data
and
the
manufacturers
certification
of
the
bag
leak
detection
system
as
required
in
§
63.7525(
i).
d.
A
wet
scrubber
in
combination
with
an
electrostatic
precipitator.
i.
0.026
lb
particulate
matter
per
MMBtu
heat
input
or
0.0001
lb
total
selected
metals
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
particulate
matter
per
MMBtu
heat
input,
measured
using
PM
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
or
the
average
emissions
in
units
of
lb
total
selected
metals
per
MMBtu
heat
input
measured
using
total
selected
metals
emission
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
average
secondary
current
and
voltage
or
total
power
input
of
the
electrostatic
precipitator
for
each
test
run.

2.
Each
new
or
reconstructed
industrial
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
limited
use
solid
fuel
subcategory
or
the
small
solid
fuel
subcategory
that
is
complying
with
the
alternative
total
selected
metals
emission
limit
instead
of
the
particulate
matter
emission
limit
(
this
is
an
option
for
those
units
that
can
demonstrate
compliance
on
the
basis
of
fuel
analysis
without
controls).
a.
Either
no
add­
on
controls
or
an
add­
on
control
for
which
you
do
not
wish
to
take
credit
for
reductions
in
total
selected
metals.
i.
0.0001
lb
total
selected
metals
per
MMBtu
heat
input.
(
1)
The
calculated
emissions
using
Equation
2
of
§
63.7530(
c)
and
converted
to
lb
total
selected
metals
per
MMBtu
heat
input
does
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
fuel
analysis,
calculations,
and
the
maximum
fuel
total
selected
metals
input
at
which
you
demonstrated
compliance.

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FR\
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13JAP2.
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13JAP2
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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
5.
A
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
PARTICULATE
MATTER
OR
TOTAL
SELECTED
METALS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

3.
Each
existing
industrial,
or
commercial
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory.
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber.
i.
0.07
lb
particulate
matter
per
MMBtu
heat
input
or
0.001
lb
total
selected
metals
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
particulate
matter
per
MMBtu
heat
input,
measured
using
PM
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
or
the
average
emissions
in
units
of
lb
total
selected
metals
per
MMBtu
heat
input
measured
using
total
selected
metals
emission
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limits;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
opacity
level
for
each
test
run
over
the
3­
hour
performance
test
during
which
particulate
matter
or
total
selected
metals
emissions
did
not
exceed
the
emissions
limit;
or
if
the
unit
is
controlled
with
a
fabric
filter,
instead
of
establishing
a
site­
specific
opacity
level
you
keep
records
of
the
installation
and
calibration
data
and
the
manufacturer's
certification
of
the
bag
leak
detection
system
as
required
in
§
63.7525(
i).
b.
A
wet
scrubber
.........................
i.
0.07
lb
particulate
matter
per
MMBtu
heat
input
or
0.001
lb
total
selected
metals
per
MMBtu
heat
input
or
0.001
lb
total
selected
metals
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
particulate
matter
per
MMBtu
heat
input,
measured
using
PM
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
or
the
average
emissions
in
units
of
lb
total
selected
metals
per
MMBtu
heat
input
measured
using
total
selected
metals
emission
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
particulate
matter
or
total
selected
metals
emissions
did
not
exceed
the
emissions
limit.

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E:\
FR\
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13JAP2.
SGM
13JAP2
1735
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
5.
A
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
PARTICULATE
MATTER
OR
TOTAL
SELECTED
METALS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

c.
Wet
scrubber
in
combination
with
a
fabric
filter.
i.
0.07
lb
particulate
matter
per
MMBtu
heat
input
or
0.001
lb
total
selected
metals
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
particulate
matter
per
MMBtu
heat
input,
measured
using
PM
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
or
the
average
emissions
in
units
of
lb
total
selected
metals
per
MMBtu
heat
input
measured
using
total
selected
metals
emission
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
particulate
matter
or
total
selected
metals
emissions
did
not
exceed
the
emissions
limit;
and
(
3)
You
keep
records
of
the
installation
and
calibration
data
and
the
manufacturer's
certification
of
the
bag
leak
detection
system
as
required
in
§
63.7525(
i).
d.
A
wet
scrubber
in
combination
with
an
electrostatic
precipitator.
i.
0.07
lb
particulate
matter
per
MMBtu
heat
input
or
0.001
lb
total
selected
metals
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
particulate
matter
per
MMBtu
heat
input,
measured
using
PM
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
or
the
average
emissions
in
units
of
lb
total
selected
metals
per
MMBtu
heat
input
measured
using
total
selected
metals
emission
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
average
secondary
current
and
voltage
or
total
power
input
of
the
electrostatic
precipitator
for
each
test
run.

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E:\
FR\
FM\
13JAP2.
SGM
13JAP2
1736
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
5.
A
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
PARTICULATE
MATTER
OR
TOTAL
SELECTED
METALS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

e.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber.
i.
0.21
lb
particulate
matter
per
MMBtu
heat
input
or
0.001
lb
total
selected
metals
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
particulate
matter
per
MMBtu
heat
input,
measured
using
PM
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
or
the
average
emissions
in
units
of
lb
total
selected
metals
per
MMBtu
heat
input
measured
using
total
selected
metals
emission
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
opacity
level
for
each
test
run
over
the
3­
hour
performance
test
during
which
particulate
matter
or
total
selected
metals
emissions
did
not
exceed
the
emissions
limit;
or
if
the
unit
is
controlled
with
a
fabric
filter,
instead
of
establishing
a
site­
specific
opacity
level
you
keep
records
of
the
installation
and
calibration
data
and
the
manufacturer's
certification
of
the
bag
leak
detection
system
as
required
in
§
63.7525(
i).
f.
A
wet
scrubber
..........................
i.
0.21
lb
particulate
matter
per
MMBtu
heat
input
or
0.001
lb
total
selected
metals
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
particulate
matter
per
MMBtu
heat
input,
measured
using
PM
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
or
the
average
emissions
in
units
of
lb
total
selected
metals
per
MMBtu
heat
input
measured
using
total
selected
metals
emission
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
particulate
matter
or
total
selected
metals
emissions
did
not
exceed
the
emissions
limit.

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19:
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E:\
FR\
FM\
13JAP2.
SGM
13JAP2
1737
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
5.
A
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
PARTICULATE
MATTER
OR
TOTAL
SELECTED
METALS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

g.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
0.21
lb
particulate
matter
per
MMBtu
heat
input
or
0.001
lb
total
selected
metals
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
particulate
matter
per
MMBtu
heat
input,
measured
using
PM
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
or
the
average
emissions
in
units
of
lb
total
selected
metals
per
MMBtu
heat
input
measured
using
total
selected
metals
emission
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
particulate
matter
of
total
selected
metals
emissions
did
not
exceed
the
emissions
limit;
and
(
3)
You
keep
records
of
the
installation
and
calibration
data
and
the
manufacture's
certification
of
the
bag
leak
detection
system
as
required
in
§
63.7525(
i).
h.
A
wet
scrubber
in
combination
with
an
electrostatic
precipitator.
i.
0.21
lb
particulate
matter
per
MMBtu
heat
input
or
0.001
lb
total
selected
metals
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
particulate
matter
per
MMBtu
heat
input,
measured
using
PM
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
or
the
average
emissions
in
units
of
lb
total
selected
metals
per
MMBtu
heat
input
measured
using
total
selected
metals
emission
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
average
secondary
current
and
voltage
or
total
power
input
of
the
electrostatic
precipitator
for
each
test
run.

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/
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No.
8
/
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January
13,
2003
/
Proposed
Rules
TABLE
5.
A
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
PARTICULATE
MATTER
OR
TOTAL
SELECTED
METALS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

4.
Each
existing
industrial,
commercial
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory
or
the
limited
use
solid
fuel
subcategory
that
is
complying
with
the
alternative
total
selected
metals
emission
limit
instead
of
the
particulate
matter
emission
limit
(
this
is
an
option
for
those
units
that
can
demonstrate
compliance
on
the
basis
of
fuel
analysis
without
controls).
a.
Either
no
add­
on
controls
or
an
add­
on
control
for
which
you
do
not
wish
to
take
credit
for
reductions
in
total
selected
metals.
i.
0.001
lb
total
selected
metals
per
MMBtu
heat
input.
(
1)
The
calculated
emissions
using
Equation
2
of
§
63.7530(
c)
and
converted
to
lb
total
selected
metals
per
MMBtu
heat
input
does
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
fuel
analysis,
calculations,
and
the
maximum
fuel
total
selected
metals
input
at
which
you
demonstrated
compliance.

As
stated
in
§
63.7530,
you
must
show
initial
compliance
with
the
emission
limitations
for
affected
sources
according
to
the
following:

TABLE
5.
B
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
PARTICULATE
MATTER
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
LIQUID
FUEL
SUBCATEGORIES
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

1.
Each
new
or
reconstructed
industrial
commercial,
or
institutional
boiler
or
process
heater
in
the
large
liquid
fuel
subcategory,
the
limited
use
liquid
fuel
subcategory
or
the
small
liquid
fuel
subcategory
(
boilers
or
process
heaters
in
one
of
the
liquid
fuel
subcategories
that
burn
only
fossil
fuels
and
other
gases
and
do
not
burn
any
residual
oil
are
excluded
from
this
requirement).
a.
Either
no
reconstructed
add­
on
controls
or
an
add­
on
control
other
than
a
scrubber.
i.
0.03
lb
particulate
matter
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
particulate
matter
per
MMBTU
heat
input,
measured
using
PM
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
opacity
level
for
each
test
run
over
the
threerun
performance
test
during
which
particulate
matter
emissions
did
not
exceed
the
emissions
limit;
or
if
the
unit
is
controlled
with
a
fabric
filter,
instead
of
establishing
a
site­
specific
opacity
level
you
keep
records
of
the
installation
and
calibration
data
and
the
manufacturer's
certification
of
the
bag
leak
detection
system
as
required
in
§
63.7525(
i).
b.
A
wet
scrubber
.........................
i.
0.03
lb
particulate
matter
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
particulate
matter
per
MMBtu
heat
input,
measured
using
PM
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
particulate
matter
emissions
did
not
exceed
the
emissions
limit.

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Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
5.
B
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
PARTICULATE
MATTER
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
LIQUID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

c.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
0.03
lb
particulate
matter
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
particulate
matter
per
MMBtu
heat
input,
measured
using
PM
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
particulate
matter
emissions
did
not
exceed
the
emissions
limit;
and
(
3)
You
keep
records
of
the
installation
and
calibration
data
and
the
manufacturer's
certification
of
the
bag
leak
detection
system
as
required
in
§
63.7525(
i).
d.
A
wet
scrubber
in
combination
with
an
electrostatic
precipitator.
i.
0.03
lb
particulate
matter
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
particulate
matter
per
MMBtu
heat
input,
measured
using
PM
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
average
secondary
current
and
voltage
or
total
power
input
of
the
electrostatic
precipitator
for
each
test
run
over
the
three­
run
performance
test
during
which
particulate
matter
emissions
did
not
exceed
the
emissions
limit.

2.
Each
new
or
reconstructed
industrial
commercial,
or
institutional
boiler
or
process
heater
in
one
of
the
liquid
fuel
subcategories
that
burns
only
liquid
fossil
fuels
other
than
residual
oil
either
alone
or
in
combination
with
gaseous
fuels.
a.
Any
type
of
device
....................
i.
0.03
lb
particulate
matter
per
MMBtu
heat
input.
(
1)
You
submit
a
signed
statement
in
the
Notification
of
Compliance
Status
report
required
in
§
63.7545(
e)
that
indicated
you
burn
only
liquid
fossil
fuels
other
than
residual
oil
either
alone
or
in
combination
with
gaseous
fuels;
and
(
2)
You
keep
records,
as
required
in
§
63.7555,
that
demonstrate
that
you
burn
only
liquid
fossil
fuels
other
than
residual
oil
either
alone
or
in
combination
with
gaseous
fuels.

As
stated
in
§
63.7530,
you
must
show
initial
compliance
with
the
emission
limitations
for
affected
sources
according
to
the
following:

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Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
5.
C
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
HYDROGEN
CHLORIDE
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

1.
Each
new
or
reconstructed
industrial
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory.
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber
or
a
dry
scrubber.
i.
0.02
lb
hydrogen
chloride
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
hydrogen
chloride
per
MMBtu
heat
input,
measured
using
hydrogen
chloride
emissions
concentration
and
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
fuel
chlorine
content
level
for
each
test
run
over
the
three­
run
performance
test
during
which
hydrogen
chloride
emissions
did
not
exceed
the
emissions
limit.
b.
A
wet
scrubber
.........................
i.
0.02
lb
hydrogen
chloride
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
hydrogen
chloride
per
MMBtu
heat
input,
measured
using
hydrogen
chloride
emissions
concentration
and
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
hydrogen
chloride
emissions
did
not
exceed
the
emissions
limit.
c.
A
dry
scrubber
..........................
i.
0.02
lb
hydrogen
chloride
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
hydrogen
chloride
per
MMBtu
heat
input,
measured
using
hydrogen
chloride
emissions
concentration
and
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
sorbent
injection
rate
of
the
dry
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
hydrogen
chloride
emissions
did
not
exceed
the
emissions
limit.

2.
Each
new
or
reconstructed
industrial
commercial,
or
institutional
boiler
or
process
heater
in
the
limited
use
solid
fuel
subcategory
or
the
small
solid
fuel
subcategory.
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber
or
a
dry
scrubber.
i.
0.02
lb
hydrogen
chloride
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
hydrogen
chloride
per
MMBtu
heat
input,
measured
using
hydrogen
chloride
emissions
concentration
and
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
fuel
chlorine
content
level
for
each
test
run
over
the
three­
run
performance
test
during
which
hydrogen
chloride
emissions
did
not
exceed
the
emissions
limit.

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FR\
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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
5.
C
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
HYDROGEN
CHLORIDE
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

b.
A
wet
scrubber
.........................
i.
0.02
lb
hydrogen
chloride
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
hydrogen
chloride
per
MMBtu
heat
input,
measured
using
hydrogen
chloride
emissions
concentration
and
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
hydrogen
chloride
emissions
did
not
exceed
the
emissions
limit.
c.
A
dry
scrubber
..........................
i.
0.02
lb
hydrogen
chloride
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
hydrogen
chloride
per
chloride
per
MMBtu
heat
input,
measured
using
hydrogen
chloride
emissions
concentration
and
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
sorbent
injection
rate
of
the
dry
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
hydrogen
chloride
emissions
did
not
exceed
the
emissions
limit.

3.
Each
existing
industrial,
commercial
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory.
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber
or
a
dry
scrubber.
i.
0.09
lb
hydrogen
chloride
per
MMBtu
per
heat
input.
(
1)
The
average
emissions
in
units
of
lb
hydrogen
chloride
per
MMBtu
heat
input,
measured
using
hydrogen
chloride
emissions
concentration
and
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
fuel
chlorine
content
level
for
each
test
run
over
the
three­
run
performance
test
during
which
hydrogen
chloride
emissions
did
not
exceed
the
emissions
limit.
b.
A
wet
scrubber
.........................
i.
0.09
lb
hydrogen
chloride
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
hydrogen
chloride
per
MMBtu
heat
input,
measured
using
hydrogen
chloride
emissions
concentration
and
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
hydrogen
chloride
emissions
did
not
exceed
the
emissions
limit.

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FR\
FM\
13JAP2.
SGM
13JAP2
1742
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
5.
C
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
HYDROGEN
CHLORIDE
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

c.
A
dry
scrubber
..........................
i.
0.09
lb
hydrogen
chloride
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
hydrogen
chloride
per
MMBtu
heat
input,
measured
using
hydrogen
chloride
emissions
concentration
and
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
sorbent
injection
rate
of
the
dry
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
hydrogen
chloride
emissions
did
not
exceed
the
emissions
limit.

As
stated
in
§
63.7530,
you
must
show
initial
compliance
with
the
emission
limitations
for
affected
sources
according
to
the
following:

TABLE
5.
D
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
HYDROGEN
CHLORIDE
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
LIQUID
FUEL
SUBCATEGORIES
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

1.
Each
new
or
reconstructed
commercial
or
industrial,
boiler
or
process
heater
in
the
liquid
fuel
subcategory
(
boilers
or
process
heaters
in
one
of
the
liquid
fuel
subcategories
that
burn
only
fossil
fuels
and
other
gases
and
do
not
burn
any
residual
oil
are
excluded
from
this
requirement).
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber
or
a
dry
scrubber.
i.
0.0005
lb
hydrogen
chloride
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
hydrogen
chloride
per
MMBtu
heat
input,
measured
using
hydrogen
chloride
emissions
concentration
and
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
fuel
chlorine
content
level
for
each
test
run
over
the
three­
run
performance
test
during
which
hydrogen
chloride
emissions
did
not
exceed
the
emissions
limit.
b.
A
wet
scrubber
.........................
i.
0.0005
lb
hydrogen
chloride
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
hydrogen
chloride
per
MMBtu
heat
input,
measured
using
hydrogen
chloride
emissions
concentration
and
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
hydrogen
chloride
emissions
did
not
exceed
the
emissions
limit.

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FR\
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13JAP2.
SGM
13JAP2
1743
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
5.
D
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
HYDROGEN
CHLORIDE
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
LIQUID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

c.
A
dry
scrubber
..........................
i.
0.0005
lb
hydrogen
chloride
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
hydrogen
chloride
per
MMBtu
heat
input,
measured
using
hydrogen
chloride
emissions
concentration
and
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
sorbent
injection
rate
of
the
dry
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
hydrogen
chloride
emissions
did
not
exceed
the
emissions
limit.

2.
Each
new
or
reconstructed
industrial
commercial,
or
institutional
boiler
or
process
heater
in
the
large
limited
use
liquid
fuel
subcategory
or
the
small
liquid
fuel
subcategory
(
boilers
or
process
heaters
in
one
of
the
liquid
fuel
subcategories
that
burn
only
fossil
fuels
and
other
gases
and
do
not
burn
any
residual
oil
are
excluded
from
this
requirement).
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
web
scrubber
or
a
dry
scrubber.
i.
0.0009
lb
hydrogen
chloride
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
hydrogen
chloride
per
MMBtu
heat
input,
measured
using
hydrogen
chloride
emissions
concentration
and
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
fuel
chlorine
content
level
for
each
test
run
over
the
three­
run
performance
test
during
which
hydrogen
chloride
emissions
did
not
exceed
the
emissions
limit.

3.
Each
new
or
reconstructed
industrial
commercial,
or
institutional
boiler
or
process
heater
in
the
limited
use
liquid
fuel
subcategory
or
the
small
liquid
fuel
subcategory
(
boilers
or
process
heaters
in
one
of
the
liquid
fuel
subcategories
that
burn
only
fossil
fuels
and
other
gases
and
do
not
burn
any
residual
oil
are
excluded
from
this
requirement).
a.
A
wet
scrubber
.........................
i.
0.0009
lb
hydrogen
chloride
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
hydrogen
per
MMBtu
heat
input,
measured
using
hydrogen
chloride
emissions
concentration
and
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
hydrogen
chloride
emissions
did
not
exceed
the
emissions
limit.

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E:\
FR\
FM\
13JAP2.
SGM
13JAP2
1744
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
5.
D
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
HYDROGEN
CHLORIDE
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
LIQUID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

b.
A
dry
scrubber
..........................
i.
0.0009
lb
hydrogen
chloride
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
hydrogen
chloride
per
MMBtu
heat
input,
measured
using
hydrogen
chloride
emissions
concentration
and
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
sorbent
injection
rate
of
the
dry
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
hydrogen
chloride
emissions
did
not
exceed
the
emissions
limit.

4.
Each
new
or
reconstructed
industrial
commercial,
or
institutional
boiler
or
process
heater
in
one
of
the
liquid
fuel
subcategories
that
burns
only
liquid
fossil
fuels
other
than
residual
oil
either
alone
or
in
combination
with
gaseous
fuels.
a.
Any
type
of
device
....................
i.
0.0005
lb
hydrogen
chloride
per
MMBtu
heat
input
for
units
in
the
large
liquid
fuel
subcategory
or
0.0009
lb
hydrogen
chloride
per
MMBtu
heat
input
for
units
in
the
limited
use
or
small
liquid
fuel
subcategories.
(
1)
You
submit
a
signed
statement
in
the
Notification
of
Compliance
Status
report
required
in
§
63.7545(
e)
that
indicates
you
burn
only
liquid
fossil
fuels
other
than
residual
oil
either
alone
or
in
combination
with
gaseous
fuels;
and
(
2)
You
keep
records,
as
required
in
§
63.7555,
that
demonstrate
that
you
burn
only
liquid
fossil
fuels
other
than
residual
oil
either
alone
or
in
combination
with
gaseous
fuels.

As
stated
in
§
63.7530,
you
must
show
initial
compliance
with
the
emission
limitations
for
affected
sources
according
to
the
following:

TABLE
5.
E
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
MERCURY
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

1.
Each
new
or
reconstructed
industrial
commercial
or
institutional
boiler
or
process
heater
in
large
solid
fuel
subcategory,
the
limited
use
solid
fuel
subcategory
or
the
small
solid
fuel
subcategory.
a.
Either
no
add­
on
control
or
an
add­
on
control
other
than
wet
scrubber.
i.
0.000003
lb
merecury
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
mercury
per
MMBtu
heat
input,
measured
using
mercury
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
opacity
level
for
each
test
run
over
the
three­
run
performance
test
during
which
mercury
emissions
did
not
exceed
the
emissions
limit;
or
if
the
unit
is
controlled
with
a
fabric
filter,
instead
of
establishing
a
site­
specific
opacity
level
you
keep
records
of
the
installation
and
calibration
data
and
the
manufacturer's
certification
of
the
bag
leak
detection
system
as
required
in
§
63.7525(
i).

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FR\
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13JAP2.
SGM
13JAP2
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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
5.
E
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
MERCURY
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

b.
A
wet
scrubber
.........................
i.
0.000003
lb
mercury
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
mercury
per
MMBtu
heat
input,
measured
using
mercury
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
mercury
emissions
did
not
exceed
the
emissions
limit.
c.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
0.000003
lb
mercury
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
mercury
per
MMBtu
heat
input,
measured
using
mercury
emissions
concentrations
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
mercury
emissions
did
not
exceed
the
emissions
limit;
and
(
3)
You
keep
records
of
the
installation
and
calibration
data
and
the
manufacturers
certification
of
the
bag
leak
detection
system
as
required
in
§
63.7525(
i).
d.
A
wet
scrubber
in
combination
with
an
electrostatic
precipitator.
i.
0.000003
lb
mercury
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
mercury
per
MMBtu
heat
input,
measured
using
mercury
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
average
secondary
current
and
voltage
or
total
power
input
of
the
electrostatic
precipitator
for
each
test
run.

2.
Each
new
or
reconstructed
industrial
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
limited
use
solid
fuel
subcategory
or
the
small
solid
fuel
subcategory
(
this
is
an
option
for
those
units
that
can
demonstrate
compliance
on
the
basis
of
fuel
analysis
without
controls).
a.
Either
no
add­
on
controls
or
an
add­
on
control
for
which
you
do
not
wish
to
take
credit
for
reductions
in
mercury.
i.
0.000003
lb
mercury
per
MMBtu
heat
input.
(
1)
The
calculated
emissions
using
Equation
3
of
§
63.7530(
c)
and
converted
to
lb
mercury
per
MMBtu
heat
input
does
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
fuel
analysis,
calculations,
and
the
maximum
fuel
mercury
input
at
which
you
demonstrated
compliance

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13>
2002
19:
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10,
2003
Jkt
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00000
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Fmt
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4702
E:\
FR\
FM\
13JAP2.
SGM
13JAP2
1746
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
5.
E
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
MERCURY
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

3.
Each
existing
industrial,
commercial
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory.
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber.
i.
0.000007
lb
mercury
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
mercury
per
MMBtu
heat
input,
measured
using
mercury
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
opacity
level
for
each
test
run
over
the
3­
hour
performance
test
during
which
mercury
emissions
did
not
exceed
the
emissions
limit;
or
if
the
unit
is
controlled
with
a
fabric
filter,
instead
of
establishing
a
site­
specific
opacity
level
you
keep
records
of
the
installation
and
calibration
data
and
the
manufacturer's
certification
of
the
bag
leak
detection
system
as
required
in
§
63.7525(
i).
b.
A
wet
scrubber
.........................
i.
0.000007
lb
mercury
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
mercury
per
MMBtu
heat
input,
measured
using
mercury
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
mercury
metals
emissions
did
not
exceed
the
emissions
limit.
c.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
0.000007
lb
mercury
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
mercury
per
MMBtu
heat
input,
measured
using
mercury
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
for
each
test
run
over
the
three­
run
performance
test
during
which
mercury
emissions
did
not
exceed
the
emissions
limit;
and
(
3)
You
keep
records
of
the
installation
and
calibration
data
and
the
manufacturer's
certification
of
the
bag
leak
detection
system
as
required
in
§
63.7525(
i).

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No.
8
/
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January
13,
2003
/
Proposed
Rules
TABLE
5.
E
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
MERCURY
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

d.
A
wet
scrubber
in
combination
with
an
electrostatic
precipitator.
i.
0.000007
lb
mercury
per
MMBtu
heat
input.
(
1)
The
average
emissions
in
units
of
lb
mercury
per
MMBtu
heat
input,
measured
using
mercury
emissions
concentration
and
sections
12.2
and
12.3
of
Method
19
of
appendix
A
over
the
three­
run
performance
test
period,
do
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
average
site­
specific
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
average
secondary
current
and
voltage
or
total
power
input
of
the
electrostatic
precipitator
for
each
test
run.

4.
Each
existing
industrial,
commercial
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory
(
this
is
an
option
for
those
units
that
can
demonstrate
compliance
on
the
basis
of
fuel
analysis
without
controls).
a.
Either
no
add­
on
controls
or
an
add­
on
control
for
which
you
do
not
wish
to
take
credit
for
reductions
in
mercury.
i.
0.000007
per
mercury
per
MMBtu
heat
input.
(
1)
The
calculated
mercury
emissions
using
Equation
3
of
§
63.7530(
c)
and
converted
to
lb
mercury
per
MMBtu
heat
input
does
not
exceed
the
emission
limit;
and
(
2)
You
keep
a
record
of
the
fuel
analysis,
calculations,
and
maximum
fuel
mercury
input
at
which
you
demonstrated
compliance

As
stated
in
§
63.7530,
you
must
show
initial
compliance
with
the
applicable
work
practice
standards
for
affected
sources
according
to
the
following:

TABLE
6
TO
SUBPART
DDDDD
OF
PART
63
 
INITIAL
COMPLIANCE
WITH
WORK
PRACTICE
STANDARDS
For
each
.
.
.
For
the
following
work
practice
standard
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

1.
New
or
reconstructed
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
large
liquid
fuel
subcategory,
or
the
large
gaseous
fuel
subcategory.
a.
Continuously
monitor
carbon
monoxide
emissions
according
to
the
procedures
in
§
63.7525(
a)
to
maintain
carbon
monoxide
emissions
at
or
below
an
exhaust
concentration
of
400
ppm
by
volume
on
a
dry
basis
corrected
to
3
percent
oxygen
(
the
averaging
time
shall
be
one
calendar
day).
i.
You
have
met
work
practice
standard;
and
ii.
As
part
of
the
Notification
of
Compliance
Status,
you
submit
the
carbon
monoxide
emissions
monitoring
data
recorded
during
the
performance
test
collected
according
to
the
procedures
required
in
§
63.7525(
a);
and
iii.
Report
the
maximum
carbon
monoxide
emissions
levels
that
occurred
during
the
test
that
demonstrates
the
carbon
monoxide
concentrations
were
below
the
400
ppm
concentration.

2.
New
or
reconstructed
industrial,
commercial,
or
institutional
boiler
or
process
heater
in
the
limited
use
solid
fuel
subcategory,
the
limited
use
liquid
fuel
subcategory,
or
the
limited
use
gaseous
fuel
subcategory.
a.
Continuously
monitor
carbon
monoxide
emissions
according
to
the
procedures
in
§
63.7525(
a)
to
maintain
carbon
monoxide
emissions
at
or
below
an
exhaust
concentration
of
400
ppm
by
volume
on
a
dry
basis
corrected
to
3
percent
oxygen.
The
average
time
shall
be
1
calendar
day.
i.
You
have
met
the
work
practice
standard;
and
ii.
As
part
of
the
Notification
of
Compliance
Status,
you
submit
the
carbon
monoxide
emissions
monitoring
data
recorded
during
the
performance
test
collected
according
to
the
procedures
required
in
§
63.7525(
a);
and
iii.
Report
the
maximum
carbon
monoxide
emissions
levels
that
occurred
during
the
test
that
demonstrates
the
carbon
monoxide
concentrations
were
below
the
400
ppm
concentration.

As
stated
in
§
63.7540,
you
must
show
continuous
compliance
with
the
emission
limitations
for
affected
sources
according
to
the
following:

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/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
7.
A
TO
SUBPART
DDDDD
OF
PART
63
 
CONTINUOUS
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
must
demonstrate
continuous
compliance
by
.
.
.

1.
Each
new
or
reconstructed
industrial
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
limited
use
solid
fuel
subcategory
or
the
small
solid
fuel
subcategory.
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber
or
dry
scrubber.
i.
Opacity
levels
must
not
exceed
the
operating
limit
set
during
the
PM
or
total
selected
metals
and
mercury
performance
tests
and
fuel
chlorine
content
must
not
exceed
the
maximum
operating
limit
set
during
the
hydrogen
chloride
performance
test
according
to
the
procedures
in
§
63.7530(
c).
(
1)
Collecting
the
opacity
monitoring
system
data
according
to
§
§
63.7525(
b)
and
63.7535;
and
(
2)
Reducing
the
opacity
monitoring
data
to
6­
minute
averages
and
(
3)
Maintaining
the
3­
hour
block
average
opacity
levels
at
or
below
the
limit
established
during
the
performance
test;
or
if
the
unit
is
controlled
with
a
fabric
filter,
instead
of
maintaining
opacity
maintaining
the
operation
of
the
fabric
filter
such
that
the
requirements
in
§
63.7540(
a)(
9)
are
met;
and
(
4)
Keeping
daily
records
of
fuel
use
and
following
the
procedures
in
§
63.7540(
a)
and,
therefore,
maintaining
the
fuel
chlorine
content
level
at
or
below
the
limit
set
during
the
performance
test.
b.
A
wet
scrubber
.........................
i.
pH,
pressure
drop,
and
liquid
flow­
rate
must
be
greater
than
or
equal
to
the
minimum
operating
limits
set
during
the
performance
test.
(
1)
Collecting
the
pH,
pressure
drop,
and
liquid
flow­
rate
monitoring
system
data
according
to
§
§
63.7525
and
63.7535;
and
(
2)
Reducing
the
data
to
3­
hour
block
averages;
and
(
3)
Maintaining
the
3­
hour
average
pH,
pressure
drop,
and
liquid
flow­
rate
levels
at
or
above
the
limits
established
during
the
performance
test.
c.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
pH,
pressure
drop,
and
liquid
flow­
rate
for
the
wet
scrubber
and
pressure
drop
for
the
fabric
filter
must
be
greater
than
or
equal
to
the
minimum
operating
limits
set
during
the
performance
test.
(
1)
Collecting
the
pH,
pressure
drop,
and
liquid
flow­
rate
monitoring
system
data
for
the
wet
scrubber
and
the
pressure
drop
monitoring
system
data
for
the
fabric
filter
according
to
§
§
63.7525
and
63.7535;
and
(
2)
Reducing
the
data
to
3­
hour
block
averages;
and
(
3)
Maintaining
the
3­
hour
average
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
3­
hour
average
pressure
drop
of
the
fabric
filter
at
or
above
the
limits
established
during
the
performance
test;
and
(
4)
Maintaining
the
fabric
filter
operation
such
that
the
requirements
in
63.7540(
a)(
9)
are
met.

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FR\
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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
7.
A
TO
SUBPART
DDDDD
OF
PART
63
 
CONTINUOUS
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
must
demonstrate
continuous
compliance
by
.
.
.

d.
A
wet
scrubber
in
combination
with
an
electrostatic
precipitator.
i.
pH,
pressure
drop,
and
liquid
flow­
rate
for
the
wet
scrubber
and
secondary
current
and
voltage
or
total
power
input
for
the
electrostatic
precipitator
must
be
greater
than
or
equal
to
the
minimum
operating
limits
set
during
the
performance
test.
(
1)
Collecting
the
pH,
pressure
drop,
and
liquid
flow­
rate
monitoring
system
data
for
the
wet
scrubber
and
the
secondary
current
and
voltage
monitoring
system
data
or
total
power
input
data
for
the
electrostatic
precipitator
according
to
§
§
63.7525
and
63.7535;
and
(
2)
Reducing
the
data
to
3­
hour
block
averages;
and
(
3)
Maintaining
the
3­
hour
average
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
3­
hour
average
secondary
current
and
voltage
or
total
power
input
of
the
electrostatic
precipitator
at
or
above
the
limits
established
during
the
performance
test.
e.
A
dry
scrubber
..........................
i.
Opacity
levels
must
not
exceed
the
operating
limit
set
during
the
performance
test
and
sorbent
injection
rate
of
the
dry
scrubber
must
be
greater
than
or
equal
to
the
minimum
operating
limits
set
during
the
performance
test.
(
1)
Collecting
the
opacity
monitoring
system
data
according
to
§
§
63.7525(
b)
and
63.7535;
and
(
2)
Reducing
the
opacity
monitoring
data
to
6­
minute
averages
and
(
3)
Maintaining
the
3­
hour
block
average
opacity
levels
at
or
below
the
limit
established
during
the
performance
test;
and
(
4)
Collecting
the
sorbent
injection
rate
monitoring
system
data
for
the
dry
scrubber
according
to
§
§
63.7525
and
63.7535;
and
(
5)
Reducing
the
data
to
3­
hour
block
averages;
and
(
6)
Maintaining
the
3­
hour
average
sorbent
injection
rate
level
at
or
above
the
limits
established
during
the
performance
test.

2.
Each
new
or
reconstructed
industrial
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
limited
use
solid
fuel
subcategory
or
the
small
solid
fuel
subcategory
that
is
complying
with
the
alternative
total
selected
metals
emission
limit
instead
of
the
particulate
matter
emission
limit
(
this
is
an
option
for
those
that
can
demonstrate
compliance
on
the
basis
of
fuel
analysis
without
controls).
Either
no
add­
on
controls
or
an
add­
on
control
for
which
you
do
not
wish
to
take
credit
for
reductions
in
total
selected
metals.
Fuel
total
selected
metals
content
must
not
exceed
the
operating
limit
set
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
a).
Keeping
daily
records
of
fuel
use
and
follow
the
procedures
in
§
63.7540(
a)
and,
therefore,
maintain
the
fuel
total
selected
metals
content
level
at
or
below
the
limit
set
during
the
performance
test.

3.
Each
new
or
reconstructed
industrial
commercial,
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory,
the
limited
use
solid
fuel
subcategory
or
the
small
solid
fuel
subcategory
that
can
demonstrate
compliance
with
the
mercury
emission
limit
on
the
basis
of
fuel
analysis
without
controls).
Either
no
add­
on
controls
or
an
add­
on
control
for
which
you
do
not
wish
to
take
credit
for
reductions
in
mercury.
Fuel
mercury
content
must
not
exceed
the
operating
limit
set
during
the
performance
test
according
to
the
provisions
in
§
63.7530)(
a).
Keeping
daily
records
of
fuel
use
and
follow
the
procedures
in
§
63.7540(
a)
and,
therefore,
maintain
the
fuel
mercury
content
level
at
or
below
the
limit
set
during
the
performance
test.

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FR\
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13JAP2
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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
7.
A
TO
SUBPART
DDDDD
OF
PART
63
 
CONTINUOUS
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
must
demonstrate
continuous
compliance
by
.
.
.

4.
Each
existing
industrial,
commercial
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory.
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber
or
dry
scrubber.
i.
Opacity
levels
must
not
exceed
the
operating
limit
set
during
the
PM
or
total
selected
metals
and
mercury
performance
test
and
fuel
chlorine
content
must
not
exceed
the
maximum
operating
limit
set
during
the
hydrogen
chloride
performance
test
according
to
the
procedures
in
§
63.7530(
c).
(
1)
Collecting
the
opacity
monitoring
system
data
according
to
§
§
63.7525(
b)
and
63.7535;
and
(
2)
Reducing
the
opacity
monitoring
data
to
6­
minute
averages
and
(
3)
Maintaining
the
3­
hour
block
average
opacity
levels
at
or
below
the
limit
established
during
the
performance
test;
or
if
the
unit
is
controlled
with
a
fabric
filter,
instead
of
maintaining
opacity
maintaining
the
operation
of
the
fabric
filter
such
that
the
requirements
in
§
63.7540(
a)(
9)
are
met;
and
(
4)
Keeping
daily
records
of
fuel
use
and
following
the
procedures
in
§
63.7540(
a)
and,
therefore,
maintaining
the
fuel
chlorine
content
level
at
or
below
the
limit
set
during
the
performance
test.
b.
A
wet
scrubber
.........................
i.
pH,
pressure
drop,
and
liquid
flow­
rate
must
be
greater
than
or
equal
to
the
minimum
operating
limits
set
during
the
performance
test.
(
1)
Collecting
the
pH,
pressure
drop,
and
liquid
flow­
rate
monitoring
system
data
according
to
§
§
63.7525
and
63.7535;
and
(
2)
Reducing
the
data
to
3­
hour
block
averages;
and
(
3)
Maintaining
the
3­
hour
average
pH,
pressure
drop,
and
liquid
flow­
rate
levels
at
or
above
the
limits
established
during
the
performance
test.
c.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
pH,
pressure
drop,
and
liquid
flow­
rate
for
the
wet
scrubber
and
pressure
drop
for
the
fabric
filter
must
be
greater
than
or
equal
to
minimum
operating
limits
set
during
the
performance
test.
(
1)
Collecting
the
pH,
pressure
drop,
and
liquid
flow­
rate
monitoring
system
data
for
the
wet
scrubber
and
the
pressure
drop
monitoring
system
data
for
the
fabric
filter
according
to
§
§
63.7525
and
63.7535;
and
(
2)
Reducting
the
data
to
3­
hour
block
averages;
and
(
3)
Maintaining
the
3­
hour
average
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
3­
hour
average
pressure
drop
of
the
fabric
filter
at
or
above
the
limits
established
during
the
performance
test;
and
(
4)
Maintaining
the
fabric
filter
operation
such
that
the
requirements
in
§
63.7540(
a)(
9)
are
met.

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FR\
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13JAP2
1751
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
7.
A
TO
SUBPART
DDDDD
OF
PART
63
 
CONTINUOUS
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
must
demonstrate
continuous
compliance
by
.
.
.

d.
A
wet
scrubber
in
combination
with
an
electrostatic
precipitator.
i.
pH,
pressure
drop,
and
liquid
flow­
rate
for
the
wet
scrubber
and
secondary
current
and
voltage
or
total
power
input
for
the
electrostatic
precipitator
must
be
greater
than
or
equal
to
the
minimum
operating
limits
set
during
the
performance
test.
(
1)
Collecting
the
pH,
pressure
drop,
and
liquid
flow­
rate
monitoring
system
data
for
the
wet
scrubber
and
the
secondary
current
and
voltage
monitoring
system
data
or
total
power
input
data
for
electrostatic
precipitator
according
to
§
§
63.7525
and
63.7535;
and
(
2)
Reducing
the
data
to
3­
hour
block
averages;
and
(
3)
Maintaining
the
3­
hour
average
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
3­
hour
average
secondary
current
and
voltage
or
total
power
input
of
the
electrostatic
precipitator
at
or
above
the
limits
established
during
the
performance
test.
e.
A
dry
scrubber
..........................
i.
Opacity
levels
must
not
exceed
the
operating
limit
set
during
the
performance
test
and
sorbent
injection
rate
of
the
dry
scrubber
must
be
greater
than
or
equal
to
the
minimum
operating
limits
set
during
the
performance
test.
(
1)
Collecting
the
opacity
monitoring
system
data
according
to
§
§
63.7525(
b)
and
63.7535;
and
(
2)
Reducing
the
opacity
monitoring
data
to
6­
minute
averages
and
(
3)
Maintaining
the
3­
hour
block
average
opacity
levels
at
or
below
the
limit
established
during
the
performance
test;
and
(
4)
Collecting
the
sorbent
injection
rate
monitoring
system
data
for
the
dry
scrubber
according
to
§
§
63.7525
and
63.7535;
and
(
5)
Reducing
the
data
to
3­
hour
block
averages;
and
(
6)
Maintaining
the
3­
hour
average
sorbent
injection
rate
levels
at
or
above
the
limits
established
during
the
performance
test.

5.
Each
existing
industrial,
commercial
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory
that
is
complying
with
the
alternative
total
selected
metals
emission
limit
instead
of
the
particulate
matter
emission
limit
(
this
is
an
option
for
those
that
can
demonstrate
compliance
on
the
basis
of
fuel
analysis
without
controls).
Either
no
add­
on
controls
or
an
add­
on
control
for
which
you
do
not
wish
to
take
credit
for
reductions
in
total
selected
metals.
Fuel
total
selected
metals
content
must
not
exceed
the
operating
limit
set
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
a)
keeping
daily
records
of
fuel
use
and
following
the
procedures
in
§
63.7540(
a)
and,
therefore,
maintaining
the
fuel
total
selected
metals
content
level
at
or
below
the
limit
set
during
the
performance
tests.

6.
Each
existing
industrial,
commercial
or
institutional
boiler
or
process
heater
in
the
large
solid
fuel
subcategory
that
can
demonstrate
compliance
with
the
mercury
emission
limit
on
the
basis
of
fuel
analysis
without
controls.
Either
no
add­
on
controls
or
an
add­
on
control
for
which
you
do
not
wish
to
take
credit
for
reductions
in
mercury.
Fuel
mercury
content
must
not
exceed
the
operating
limit
set
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
a).
Keeping
daily
records
of
fuel
use
and
following
the
procedures
in
§
63.7540(
a)
and,
therefore,
maintaining
the
fuel
mercury
content
level
at
or
below
the
limit
set
during
the
performance
test.

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FR\
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13JAP2.
SGM
13JAP2
1752
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
7.
A
TO
SUBPART
DDDDD
OF
PART
63
 
CONTINUOUS
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
must
demonstrate
continuous
compliance
by
.
.
.

7.
Each
existing
industrial,
commercial
or
institutional
boiler
or
process
heater
in
the
limited
use
solid
fuel
subcategory.
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber
or
dry
scrubber.
i.
Opacity
levels
must
not
exceed
the
operating
limit
set
during
the
PM
or
total
selected
metals
performance
test
according
to
the
procedures
in
§
63.7530(
c).
(
1)
Collecting
the
opacity
monitoring
system
data
according
to
§
§
63.7525(
b)
and
63.7535;
and
(
2)
Reducing
the
opacity
monitoring
data
to
6­
minute
averages
and
(
3)
Maintaining
the
3­
hour
block
average
opacity
levels
at
or
below
the
limit
established
during
the
performance
test;
and
(
4)
If
the
unit
is
controlled
with
a
fabric
filter,
maintaining
the
operation
of
the
fabric
filter
such
that
the
requirements
in
§
63.7540(
a)(
9)
are
met.
b.
A
wet
scrubber
.........................
i.
Pressure
drop
and
liquid
flowrate
must
be
greater
than
or
equal
to
the
minimum
operating
limits
set
during
the
performance
test.
(
1)
Collecting
the
pressure
drop
and
liquid
flow­
rate
monitoring
system
data
according
to
§
§
63.7525
and
63.7535;
and
(
2)
Reducing
the
data
to
3­
hour
block
averages;
and
(
3)
Maintaining
the
3­
hour
average
pressure
drop
and
liquid
flow­
rate
levels
at
or
above
the
limits
established
during
the
performance
test.
c.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
Pressure
drop
and
liquid
flowrate
for
the
wet
scrubber
and
pressure
drop
for
the
fabric
filter
must
be
greater
than
or
equal
to
the
minimum
operating
limits
set
during
the
performance
test.
(
1)
Collecting
the
pressure
drop
and
liquid
flow­
rate
monitoring
system
data
for
the
wet
scrubber
and
the
pressure
drop
monitoring
system
data
for
the
fabric
filter
according
to
§
§
63.7525
and
63.7535;
and
(
2)
Reducing
the
data
to
3­
hour
block
averages;
and
(
3)
Maintaining
the
3­
hour
average
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
3­
hour
average
pressure
drop
of
the
fabric
filter
at
or
above
the
limits
established
during
the
performance
test;
and
(
4)
Maintaining
the
fabric
filter
operation
such
that
the
requirements
in
§
63.7540(
a)(
9)
are
met.
d.
A
wet
scrubber
in
combination
with
an
electrostatic
precipitator.
i.
Pressure
drop
and
liquid
flowrate
for
the
wet
scrubber
and
secondary
current
and
voltage
or
total
power
input
for
the
electrostatic
precipitator
must
be
greater
than
or
equal
to
the
minimum
operating
limits
set
during
the
performance
test.
(
1)
Collecting
the
pressure
drop
and
liquid
flow­
rate
monitoring
system
data
for
the
wet
scrubber
and
the
secondary
current
and
voltage
monitoring
system
data
or
total
power
input
data
for
the
electrostatic
precipitator
according
to
§
§
63.7525
and
63.7535;
and
(
2)
Reducing
the
data
to
3­
hour
block
averages;
and
(
3)
Maintaining
the
3­
hour
average
pressure
drop
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
3­
hour
average
secondary
current
and
voltage
or
total
power
input
of
the
electrostatic
precipitator
at
or
above
the
limits
established
during
the
performance
test.

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E:\
FR\
FM\
13JAP2.
SGM
13JAP2
1753
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
7.
A
TO
SUBPART
DDDDD
OF
PART
63
 
CONTINUOUS
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
SOLID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
must
demonstrate
continuous
compliance
by
.
.
.

e.
A
dry
scrubber
..........................
i.
Opacity
levels
must
not
exceed
the
operating
limit
set
during
the
performance
test.
(
1)
Collecting
the
opacity
monitoring
system
data
according
to
§
§
63.7525(
b)
and
63.7535;
and
(
2)
Reducing
the
opacity
monitoring
data
to
6­
minute
averages
and
(
3)
Maintaining
the
3­
hour
block
average
opacity
levels
at
or
below
the
limit
established
during
the
performance
test.

8.
Each
existing
industrial
commercial
and
institutional
boiler
or
process
in
the
limited
use
solid
fuel
subcategory
that
is
complying
with
the
alternative
total
selected
metals
emission
limit
instead
of
the
particulate
matter
emission
limit
(
this
is
an
option
for
those
that
can
demonstrate
compliance
on
the
basis
of
fuel
analysis
without
controls).
Either
no
add­
on
controls
or
an
add­
on
control
for
which
you
do
not
wish
to
take
credit
for
reductions
in
total
selected
metals.
Fuel
total
selected
metals
content
must
not
exceed
the
operating
limit
set
during
the
performance
test
according
to
the
provisions
in
§
63.7530(
a).
Keeping
daily
records
of
fuel
use
and
following
the
procedures
in
§
63.7540(
a)
and,
therefore,
maintaining
the
fuel
total
selected
metals
content
level
at
or
below
the
limit
set
during
the
performance
test.

As
stated
in
§
63.7540,
you
must
show
continuous
compliance
with
the
emission
limitation
for
affected
sources
according
to
the
following:

TABLE
7.
B
TO
SUBPART
DDDDD
OF
PART
63
 
CONTINUOUS
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
LIQUID
FUEL
SUBCATEGORIES
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
must
demonstrate
continuous
compliance
by.
.
.

1.
Each
new
or
reconstructed
industrial
commercial,
or
institutional
boiler
or
process
heater
in
the
large
liquid
fuel
subcategory,
the
limited
use
liquid
fuel
subcategory
or
the
small
liquid
fuel
subcategory
(
boilers
or
process
heaters
in
one
of
the
liquid
fuel
subcategories
that
burn
only
fossil
fuels
and
gases
and
do
not
burn
any
residual
oil
are
excluded
from
this
requirement).
a.
Either
no
add­
on
controls
or
an
add­
on
control
other
than
a
wet
scrubber
or
a
dry
scrubber.
i.
Opacity
levels
must
not
exceed
the
operating
limit
set
during
the
performance
test
and
fuel
chlorine
content
must
not
exceed
the
maximum
operating
limit
set
during
the
performance
test
according
to
the
procedures
in
§
63.7530(
c).
(
1)
Collecting
the
opacity
monitoring
system
data
according
to
§
§
63.7525(
b)
and
63.7535;
and
(
2)
Reducing
the
opacity
monitoring
data
to
6­
minute
averages
and
(
3)
Maintaining
the
3­
hour
block
average
opacity
levels
at
or
below
the
limit
established
during
the
performance
test;
or
if
the
unit
is
controlled
with
a
fabric
filter,
instead
of
maintaining
opacity
maintaining
the
operation
of
the
fabric
filter
such
that
the
requirements
in
§
63.7540(
a)(
9)
are
met;
and
(
4)
Keeping
daily
records
of
fuel
use
and
following
the
procedures
in
§
63.7540(
a)
and,
therefore,
maintaining
the
fuel
chlorine
content
level
at
or
below
the
limit
set
during
the
performance
test.
b.
A
wet
scrubber
.........................
i.
pH,
pressure
drop,
and
liquid
flow­
rate
must
be
greater
than
or
equal
to
the
minimum
operating
limits
set
during
the
performance
test.
(
1)
Collecting
the
pH,
pressure
drop,
and
liquid
flow­
rate
monitoring
system
data
according
to
§
§
63.7525
and
63.7535;
and
(
2)
Reducing
the
data
to
3­
hour
block
averages;
and
(
3)
Maintaining
the
3­
hour
average
pH,
pressure
drop,
and
liquid
flow­
rate
levels
at
or
above
the
limits
established
during
the
performance
test.

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13JAP2.
SGM
13JAP2
1754
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
7.
B
TO
SUBPART
DDDDD
OF
PART
63
 
CONTINUOUS
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
LIQUID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
must
demonstrate
continuous
compliance
by.
.
.

c.
A
wet
scrubber
in
combination
with
a
fabric
filter.
i.
pH,
pressure
drop,
and
liquid
flow­
rate
for
the
wet
scrubber
and
pressure
drop
for
the
fabric
filter
must
be
greater
than
or
equal
to
the
minimum
operating
limits
set
during
the
performance
test.
(
1)
Collecting
the
pH,
pressure
drop,
and
liquid
flow­
rate
monitoring
system
data
for
the
wet
scrubber
and
the
pressure
drop
monitoring
system
data
for
the
fabric
filter
according
to
§
§
63.7525
and
63.7535;
and
(
2)
Reducing
the
data
to
3­
hour
block
averages;
and
(
3)
Maintaining
the
3­
hour
average
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
3­
hour
average
pressure
drop
of
the
fabric
filter
at
or
above
the
limits
established
during
the
performance
test;
and
(
4)
Maintaining
the
operation
of
the
fabric
filter
such
that
the
requirements
in
§
63.7540(
a)(
9)
are
met.

d.
A
wet
scrubber
in
combination
with
an
electrostatic
precipitator.
i.
pH,
pressure
drop,
and
liquid
flow­
rate
for
the
wet
scrubber
and
secondary
current
and
voltage
or
total
power
input
for
the
electrostatic
precipitator
must
be
greater
than
or
equal
to
the
minimum
operating
limits
set
during
the
performance
test.
(
1)
Collecting
the
pH,
pressure
drop,
and
liquid
flow­
rate
monitoring
system
data
for
the
wet
scrubber
and
the
secondary
current
and
voltage
monitoring
system
data
or
total
power
input
data
for
the
electrostatic
precipitator
according
to
§
§
63.7525
and
63.7535;
and
(
2)
Reducing
the
data
to
3­
hour
block
averages;
and
(
3)
Maintaining
the
3­
hour
average
pH,
pressure
drop,
and
liquid
flow­
rate
of
the
wet
scrubber
and
the
3­
hour
average
secondary
current
and
voltage
or
total
power
input
of
the
electrostatic
precipitator
at
or
above
the
limits
established
during
the
performance
test.
e.
A
dry
scrubber
..........................
i.
Sorbent
injection
rate
of
the
dry
scrubber
must
be
greater
than
or
equal
to
the
minimum
operating
limits
set
during
the
performance
test
and
opacity
levels
must
not
exceed
the
operating
limit
set
during
the
performance
test.
(
1)
Collecting
the
sorbent
injection
rate
monitoring
system
data
according
to
§
§
63.7525
and
63.7535;
and
(
2)
Reducing
the
data
to
3­
hour
block
averages;
and
(
3)
Maintaining
the
3­
hour
average
sorbent
injection
rate
levels
at
or
above
the
limits
established
during
the
performance
test;
and
(
4)
Collecting
the
opacity
monitoring
system
data
according
to
§
63.7525(
b)
and
reducing
the
opacity
monitoring
data
to
6­
minute
averages
and
maintaining
the
3­
hour
average
opacity
levels
at
or
below
the
limit
established
during
the
performance
test.

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FR\
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13JAP2.
SGM
13JAP2
1755
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
7.
B
TO
SUBPART
DDDDD
OF
PART
63
 
CONTINUOUS
COMPLIANCE
WITH
EMISSION
LIMITATIONS
FOR
BOILERS
OR
PROCESS
HEATERS
IN
LARGE,
LIMITED
USE,
OR
SMALL
LIQUID
FUEL
SUBCATEGORIES
 
Continued
For
.
.
.
That
is
controlled
with
.
.
.
For
the
following
emission
limitation
.
.
.
You
must
demonstrate
continuous
compliance
by.
.
.

2.
Each
new
or
reconstructed
industrial
commercial,
or
institutional
boiler
or
process
heater
in
one
of
the
liquid
fuel
subcategories
that
burns
only
liquid
fossil
fuels
other
than
residual
oil
either
alone
or
in
combination
with
gaseous
fuels.
a.
Any
type
of
device
....................
i.
0.03
lb
particulate
matter
per
MMBtu
heat
input.
(
1)
Including
a
signed
statement
in
each
semiannual
compliance
report
required
in
§
63.7550
that
indicates
you
burned
only
liquid
fossil
fuels
other
than
residual
oil
either
alone
or
in
combination
with
gaseous
fuels
during
the
compliance
period;
and
(
2)
By
keeping
records,
as
required
in
§
63.7555,
that
demonstrate
that
you
burn
only
liquid
fossil
fuels
other
than
residual
oil
either
alone
or
in
combination
with
gaseous
fuels.

As
stated
in
§
63.7540,
you
must
show
continuous
compliance
with
the
applicable
work
practice
standards
for
affected
sources
according
to
the
following:

TABLE
8
TO
SUBPART
DDDDD
OF
PART
63
 
CONTINUOUS
COMPLIANCE
WITH
WORK
PRACTICE
STANDARDS
For
the
following
work
practice
standard
.
.
.
You
must
demonstrate
continuous
compliance
by
.
.
.

1.
Carbon
monoxide
limit
for
new
or
reconstructed
industrial,
commercial
or
institutional
boilers
or
process
heaters
in
the
large
solid
fuel
subcategory,
the
large
liquid
fuel
subcategory,
the
large
gaseous
fuel
subcategory,
the
limited
use
solid
fuel
subcategory,
the
limited
use
liquid
fuel
subcategory,
or
the
limited
use
gaseous
fuel
subcategory.
a.
Continuously
monitoring
carbon
monoxide
levels
according
to
§
§
63.7525(
a)
and
63.7535;
and
b.
Maintaining
a
carbon
monoxide
level
below
an
exhaust
concentration
of
400
ppm
by
volume
on
a
dry
basis
at
all
times
except
during
startup,
shutdown,
or
malfunction;
and
c.
Keeping
records
of
carbon
monoxide
levels
as
required
in
§
63.7555(
b).
The
averaging
period
shall
be
a
calendar
day.

As
stated
in
§
63.7550,
you
must
comply
with
the
following
requirements
for
reports:

TABLE
9
TO
SUBPART
DDDDD
OF
PART
63
 
REQUIREMENTS
FOR
REPORTS
You
must
submit
a(
n)
The
report
must
contain
.
.
.
You
must
submit
the
report
.
.
.

1.
Compliance
report
..........................................
a.
Information
required
in
§
63.7550(
c)(
1)
 
(
11);
and
Semiannually
according
to
the
requirements
in
§
63.7550(
b).
b.
If
there
are
no
deviations
from
any
emission
limitation
(
emission
limit
and
operating
limit)
that
applies
to
you
and
there
are
no
deviations
from
the
requirements
for
work
practice
standards
in
Table
8
to
this
subpart
that
apply
to
you,
a
statement
that
there
were
no
deviations
from
the
emission
limitations
and
work
practice
standards
during
the
reporting
period.
If
there
were
no
periods
during
which
the
continuous
monitoring
systems,
including
continuous
emissions
monitoring
system,
continuous
opacity
monitoring
system,
and
operating
parameter
monitoring
systems,
were
out­
of­
control
as
specified
in
§
63.8(
c)(
7),
a
statement
that
there
were
no
periods
during
which
the
continuous
monitoring
systems
were
out­
ofcontrol
during
the
reporting
period;
and
See
item
1.
a
of
this
table.

c.
If
you
have
a
deviation
from
any
emission
limitation
(
emission
limit
and
operating
limit)
or
work
practice
standard
during
the
reporting
period,
the
report
must
contain
the
information
in
§
63.7550(
d).
If
there
were
periods
during
which
the
continuous
monitoring
systems,
including
continuous
emissions
monitoring
system,
continuous
opacity
monitoring
system,
and
operating
parameter
monitoring
systems,
were
out­
of­
control,
as
specified
in
§
63.8(
c)(
7),
the
report
must
contain
the
information
in
§
63.7550(
e);
and
See
item
1.
a
of
this
table.

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FR\
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13JAP2.
SGM
13JAP2
1756
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
9
TO
SUBPART
DDDDD
OF
PART
63
 
REQUIREMENTS
FOR
REPORTS
 
Continued
You
must
submit
a(
n)
The
report
must
contain
.
.
.
You
must
submit
the
report
.
.
.

d.
If
you
had
a
startup,
shutdown,
or
malfunction
during
the
reporting
period
and
you
took
actions
consistent
with
your
startup,
shutdown,
and
malfunction
plan,
the
compliance
report
must
include
the
information
in
§
63.10(
d)(
5)(
i).
See
item
1.
a
of
this
table.

2.
An
immediate
startup,
shutdown,
and
malfunction
report
if
you
had
a
startup,
shutdown
or
malfunction
during
the
reporting
period
that
is
not
consistent
with
your
startup,
shutdown,
and
malfunction
plan.
a.
Actions
taken
for
the
event
and
the
information
in
§
63.10(
d)(
5)(
ii).
i.
By
fax
or
telephone
within
2
working
days
after
starting
actions
inconsistent
with
the
plan;
and
ii.
By
letter
within
7
working
days
after
the
end
of
the
event
unless
you
have
made
alternative
arrangements
with
the
permitting
authority.
(
§
63.10(
d)(
5)(
ii)).

As
stated
in
§
63.7565,
you
must
comply
with
the
applicable
General
Provisions
according
to
the
following:

TABLE
10
TO
SUBPART
DDDDD
OF
PART
63
 
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
DDDDD
Citation
Subject
Brief
description
Explanation
§
63.1
.......................................
Applicability
............................................
Initial
Applicability
Determination;
Applicability
After
Standard
Established;
Permit
Requirements;
Extensions
Notifications.
Yes.

§
63.2
.......................................
Definitions
..............................................
Definitions
for
part
63
standards
.................................
Yes.

§
63.3
.......................................
Units
and
Abbreviations
.........................
Units
and
abbreviations
for
part
63
standards
............
Yes.

§
63.4
.......................................
Prohibited
Activities
................................
Prohibited
Activities;
Compliance
date;
Circumvention
Severability.
Yes.

§
63.5
.......................................
Construction/
Reconstruction
..................
Applicability;
applications;
approvals
...........................
Yes.

§
63.6(
a)
..................................
Applicability
............................................
i.
GP
apply
unless
compliance
extension;
and
Yes.
ii.
GP
apply
to
area
sources
that
become
major
........
Yes.

§
63.6(
b)(
1)
 
(
4)
........................
Compliance
Dates
for
New
and
Reconstructed
sources.
Standards
apply
at
effective
date;
3
years
after
effective
date;
upon
startup;
10
years
after
construction
or
reconstruction
commences
for
112(
f).
Yes.

§
63.6(
b)(
5)
..............................
Notification
.............................................
Must
notify
if
commenced
construction
or
reconstruction
after
proposal.
Yes.

§
63.6(
b)(
6)
..............................
[
Reserved].

§
63.6(
b)(
7)
..............................
Compliance
Dates
for
New
and
Reconstructed
Area
Sources
That
Become
Major.
Area
sources
that
become
major
must
comply
with
major
source
standards
immediately
upon
becoming
major,
regardless
of
whether
required
to
comply
when
they
were
an
area
source.
Yes.

§
63.6(
c)(
1)
 
(
2)
........................
Compliance
Dates
for
Existing
Sources
i.
Comply
according
to
date
in
subpart,
which
must
be
no
later
than
3
years
after
effective
date;
and
Yes.

ii.
For
112(
f)
standards,
comply
within
90
days
of
effective
date
unless
compliance
extension.
Yes.

§
63.6(
c)(
3)
 
(
4)
........................
[
Reserved].

§
63.6(
c)(
5)
..............................
Compliance
Dates
for
Existing
Area
Sources
That
Become
Major.
Area
sources
that
become
major
must
comply
with
major
source
standards
by
date
indicated
in
subpart
or
by
equivalent
time
period
(
for
example,
3
years).
Yes.

§
63.6(
d)
..................................
[
Reserved].

§
63.6(
e)(
1)
 
(
2)
........................
Operation
&
Maintenance
......................
i.
Operate
to
minimize
emissions
at
all
times;
and
Yes.

ii.
Correct
malfunctions
as
soon
as
practicable;
and
Yes.
iii.
Operation
and
maintenance
requirements
independently
enforceable
information
Administrator
will
use
to
determine
if
operation
and
maintenance
requirements
were
met.
Yes.

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E:\
FR\
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13JAP2.
SGM
13JAP2
1757
Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
10
TO
SUBPART
DDDDD
OF
PART
63
 
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
DDDDD
 
Continued
Citation
Subject
Brief
description
Explanation
§
63.6(
e)(
3)
..............................
Startup,
Shutdown,
and
Malfunction
Plan
(
SSMP).
Requirement
for
SSM
and
startup,
shutdown,
malfunction
plan.
Content
of
SSMP
.........................................................
Yes.

§
63.6(
f)(
1)
...............................
Compliance
Except
During
SSM
...........
Comply
with
emission
standards
at
all
times
except
during
SSM.
Yes.

§
63.6(
f)(
2)
 
(
3)
.........................
Methods
for
Determining
Compliance
...
Compliance
based
on
performance
test,
operation
and
maintenance
plans,
records,
inspection.
Yes.

§
63.6(
g)(
1)
 
(
3)
........................
Alternative
Standard
..............................
Procedures
for
getting
an
alternative
standard
...........
Yes.

§
63.6(
h)(
1)
..............................
Compliance
with
Opacity/
VE
Standards
Comply
with
opacity/
VE
emission
limitations
at
all
times
except
during
SSM.
Yes.

§
63.6(
h)(
2)(
i)
...........................
Determining
Compliance
with
Opacity/
Visible
Emission
(
VE)
Standards.
If
standard
does
not
state
test
method,
use
Method
9
for
opacity
and
Method
22
for
VE.
No.

§
63.6(
h)(
2)(
ii)
..........................
[
Reserved].

§
63.6(
h)(
2)(
iii)
.........................
Using
Previous
Tests
to
Demonstrate
Compliance
with
Opacity/
VE
Standards
Criteria
for
when
previous
opacity/
VE
testing
can
be
used
to
show
compliance
with
this
rule.
Yes.

§
63.6(
h)(
3)
..............................
[
Reserved].

§
63.6(
h)(
4)
..............................
Notification
of
Opacity/
VE
Observation
Date.
Notify
Administrator
of
anticipated
date
of
observation
No.

§
63.6(
h)(
5)(
i),
(
iii)
 
(
v)
..............
Conducting
Opacity/
VE
Observations
...
Dates
and
Schedule
for
conducting
opacity/
VE
observations
No.

§
63.6(
h)(
5)(
ii)
..........................
Opacity
Test
Duration
and
Averaging
Times.
Must
have
at
least
3
hours
of
observation
with
thirty,
6­
minute
averages.
No.

§
63.6(
h)(
6)
..............................
Records
of
Conditions
During
Opacity/
VE
Observations.
Keep
records
available
and
allow
Administrator
to
inspect
No.

§
63.6(
h)(
7)(
i)
...........................
Report
continuous
opacity
monitoring
system
Monitoring
Data
from
Performance
Test.
Submit
continuous
opacity
monitoring
system
data
with
other
performance
test
data.
Yes.

§
63.6(
h)(
7)(
ii)
..........................
Using
continuous
opacity
monitoring
system
instead
of
Method
9.
Can
submit
continuous
opacity
monitoring
system
data
instead
of
Method
9
results
even
if
rule
requires
Method
9,
but
must
notify
Administrator
before
performance
test.
No.

§
63.6(
h)(
7)(
iii)
.........................
Averaging
time
for
continuous
opacity
monitoring
system
during
performance
test.
To
determine
compliance,
must
reduce
continuous
opacity
monitoring
system
data
to
6­
minute
averages
Yes.

§
63.6(
h)(
7)(
iv)
.........................
Continuous
opacity
monitoring
system
requirements.
Demonstrate
that
continuous
opacity
monitoring
system
performance
evaluations
are
conducted
according
to
§
§
63.8(
e),
continuous
opacity
monitoring
system
are
properly
maintained
and
operated
according
to
63.8(
c)
and
data
quality
as
§
63.8(
d).
Yes.

§
63.6(
h)(
7)(
v)
..........................
Determining
Compliance
with
Opacity/
VE
Standards.
Continuous
opacity
monitoring
system
is
probative
but
not
conclusive
evidence
of
compliance
with
opacity
standard,
even
if
Method
9
observation
shows
otherwise.
Requirements
for
continuous
opacity
monitoring
system
to
be
probative
evidence
proper
maintenance,
meeting
PS
1,
and
data
have
not
been
altered.
Yes.

§
63.6(
h)(
8)
..............................
Determining
Compliance
with
Opacity/
VE
Standards.
Administrator
will
use
all
continuous
opacity
monitoring
system,
Method
9,
and
Method
22
results,
as
well
as
information
about
operation
and
maintenance
to
determine
compliance.
Yes.

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13,
2003
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Proposed
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TABLE
10
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SUBPART
DDDDD
OF
PART
63
 
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
DDDDD
 
Continued
Citation
Subject
Brief
description
Explanation
§
63.6(
h)(
9)
..............................
Adjusted
Opacity
Standard
....................
Procedures
for
Administrator
to
adjust
an
opacity
standard.
Yes.

§
63.6(
i)(
1)
 
(
14)
.......................
Compliance
Extension
...........................
Procedures
and
criteria
for
Administrator
to
grant
compliance
extension.
Yes.

§
63.6(
j)
....................................
Presidential
Compliance
Exemption
......
President
may
exempt
source
category
from
requirement
to
comply
with
rule.
Yes.

§
63.7(
a)(
1)
..............................
Performance
Test
Dates
........................
Dates
for
Conducting
Initial
Performance
Testing
and
Other
Compliance
Demonstrations.
Yes.

§
63.7(
a)(
2)(
i)
...........................
Performance
Test
Dates
........................
New
source
with
initial
startup
date
before
effective
date
has
180
days
after
effective
date
to
demonstrate
compliance.
Yes.

§
63.7(
a)(
2)(
ii)
..........................
Performance
Test
Dates
........................
New
source
with
initial
startup
date
after
effective
date
has
180
days
after
initial
startup
date
to
demonstrate
compliance.
Yes.

§
63.7(
a)(
2)(
iii)
.........................
Performance
Test
Dates
........................
i.
Existing
source
subject
to
standard
established
pursuant
to
112(
d)
has
180
days
after
compliance
date
to
demonstrate
compliance;
and
No.

ii.
Existing
source
with
startup
date
after
effective
date
has
180
days
after
startup
to
demonstrate
compliance.
Yes.

§
63.7(
a)(
2)(
iv)
.........................
Performance
Test
Dates
........................
Existing
source
subject
to
standard
established
pursuant
to
112(
f)
has
180
days
after
compliance
date
to
demonstrate
compliance.
No.

§
63.7(
a)(
2)(
v)
..........................
Performance
Test
Dates
........................
Existing
source
that
applied
for
extension
of
compliance
has
180
days
after
termination
date
of
extension
to
demonstrate
compliance.
Yes.

§
63.7(
a)(
2)(
vi)
.........................
Performance
Test
Dates
........................
New
source
subject
to
standard
established
pursuant
to
112(
f)
that
commenced
construction
after
proposal
date
of
112(
d)
standard
but
before
proposal
date
of
112(
f)
standard,
has
180
days
after
compliance
date
to
demonstrate
compliance.
No.

§
63.7(
a)(
2)(
vii
 
viii)
..................
[
Reserved].

§
63.7(
a)(
2)(
ix)
.........................
Performance
Test
Dates
........................
i.
New
source
that
commenced
construction
between
proposal
and
promulgation
dates,
when
promulgated
standard
is
more
stringent
than
proposed
standard,
has
180
days
after
effective
date
or
180
days
after
startup
of
source,
whichever
is
later,
to
demonstrate
compliance;
and.
Yes.

ii.
If
source
initially
demonstrates
compliance
with
less
stringent
proposed
standard,
it
has
3
years
and
180
days
after
the
effective
date
of
the
standard
or
180
days
after
startup
of
source,
whichever
is
later,
to
demonstrate
compliance
with
promulgated
standard.
No.

§
63.7(
a)(
3)
..............................
Section
114
Authority
.............................
Administrator
may
require
a
performance
test
under
CAA
Section
114
at
any
time.
Yes.

§
63.7(
b)(
1)
..............................
Notification
of
Performance
Test
...........
Must
notify
Administrator
60
days
before
the
test
......
Yes.

§
63.7(
b)(
2)
..............................
Notification
of
Rescheduling
..................
If
rescheduling
a
performance
test
is
necessary,
must
notify
Administrator
5
days
before
scheduled
date
of
rescheduled
date.
Yes.

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No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
10
TO
SUBPART
DDDDD
OF
PART
63
 
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
DDDDD
 
Continued
Citation
Subject
Brief
description
Explanation
§
63.7(
c)
...................................
Quality
Assurance/
Test
Plan
.................
Requirement
to
submit
site­
specific
test
plan
60
days
before
the
test
or
on
date
Administrator
agrees
with:
i.
Test
plan
approval
procedures;
and
ii.
Performance
audit
requirements;
and
iii.
Internal
and
External
QA
procedures
for
testing.
Yes.

§
63.7(
d)
..................................
Testing
Facilities
....................................
Requirements
for
test
facilities
....................................
Yes.

§
63.7(
e)(
1)
..............................
Conditions
for
Conducting
Performance
Tests.
i.
Performance
tests
must
be
conducted
under
representative
conditions;
and
No.

ii.
Cannot
conduct
performance
tests
during
SSM;
and
Yes.

iii.
Not
a
deviation
to
exceed
standard
during
SSM;
and
Yes.

iv.
Upon
request
of
Administrator,
make
available
records
necessary
to
determine
conditions
of
performance
tests
Yes.

§
63.7(
e)(
2)
..............................
Conditions
for
Conducting
Performance
Tests.
Must
conduct
according
to
rule
and
EPA
test
methods
unless
Administrator
approves
alternative.
Yes.

§
63.7(
e)(
3)
..............................
Test
Run
Duration
..................................
i.
Must
have
three
separate
test
runs;
and
Yes.
ii.
Compliance
is
based
on
arithmetic
mean
of
three
runs;
and
Yes.

iii.
Conditions
when
data
from
an
additional
test
run
can
be
used
Yes.

§
63.7(
f)
...................................
Alternative
Test
Method
.........................
Procedures
by
which
Administrator
can
grant
approval
to
use
an
alternative
test
method.
Yes.

§
63.7(
g)
..................................
Performance
Test
Data
Analysis
...........
i.
Must
include
raw
data
in
performance
test
report;
and
Yes.

ii.
Must
submit
performance
test
data
60
days
after
end
of
test
with
the
Notification
of
Compliance
Status
and
Yes.

iii.
Keep
data
for
5
years
.............................................
Yes.

§
63.7(
h)
..................................
Waiver
of
Tests
......................................
Procedures
for
Administrator
to
waive
performance
test.
Yes.

§
63.8(
a)(
1)
..............................
Applicability
of
Monitoring
Requirements
Subject
to
all
monitoring
requirements
in
standard
....
Yes.

§
63.8(
a)(
2)
..............................
Performance
Specifications
...................
Performance
Specifications
in
appendix
B
of
part
60
apply.
Yes.

§
63.8(
a)(
3)
..............................
[
Reserved].

§
63.8(
a)(
4)
..............................
Monitoring
with
Flares
............................
Unless
your
rule
says
otherwise,
the
requirements
for
flares
in
§
63.11
apply.
No.

§
63.8(
b)(
1)(
i)
 
(
ii)
.....................
Monitoring
..............................................
Must
conduct
monitoring
according
to
standard
unless
Administrator
approves
alternative.
Yes.

§
63.8(
b)(
1)(
iii)
.........................
Monitoring
..............................................
Flares
not
subject
to
this
section
unless
otherwise
specified
in
relevant
standard.
No.

§
63.8(
b)(
2)
 
(
3)
........................
Multiple
Effluents
and
Multiple
Monitoring
Systems.
i.
Specific
requirements
for
installing
monitoring
systems
and
Yes.

ii.
Must
install
on
each
effluent
before
it
is
combined
and
before
it
is
released
to
the
atmosphere
unless
Administrator
approves
otherwise;
and
Yes.

iii.
If
more
than
one
monitoring
system
on
an
emission
point,
must
report
all
monitoring
system
results
unless
one
monitoring
system
is
a
backup.
Yes.

§
63.8(
c)(
1)
..............................
Monitoring
System
Operation
and
Maintenance
Maintain
monitoring
system
in
a
manner
consistent
with
good
air
pollution
control
practices.
Yes.

§
63.8(
c)(
1)(
i)
...........................
Routine
and
Predictable
SSM
...............
i.
Follow
the
SSM
plan
for
routine
repairs.
Keep
parts
for
routine
repairs
readily
available.
Yes.

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68,
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8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
10
TO
SUBPART
DDDDD
OF
PART
63
 
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
DDDDD
 
Continued
Citation
Subject
Brief
description
Explanation
ii.
Reporting
requirements
for
SSM
when
action
is
described
in
SSM
plan.
Yes.

§
63.8(
c)(
1)(
ii)
..........................
SSM
not
in
SSMP
..................................
Reporting
requirements
SSM
when
action
is
not
described
in
SSM
plan.
Yes.

§
63.8(
c)(
1)(
iii)
.........................
Compliance
with
Operation
and
Maintenance
Requirements.
i.
How
Administrator
determines
if
source
complying
with
operation
and
maintenance
requirements;
and
Yes.

ii.
Review
of
source
O&
M
procedures,
records,
Manufacturer's
instructions,
recommendations,
and
inspection
of
monitoring
system.
Yes.

§
63.8(
c)(
2)
 
(
3)
........................
Monitoring
System
Installation
...............
i.
Must
install
to
get
representative
emission
and
parameter
measurements;
and
Yes.

ii.
Must
verify
operational
status
before
or
at
performance
test.
Yes.

§
63.8(
c)(
4)
..............................
Continuous
Monitoring
System
(
CMS)
Requirements.
Continuous
monitoring
systems
must
be
operating
except
during
breakdown,
out­
of­
control,
repair,
maintenance,
and
high­
level
calibration
drifts.
No.

§
63.8(
c)(
4)(
i)
...........................
Continuous
Monitoring
System
(
CMS)
Requirements.
Continuous
opacity
monitoring
system
must
have
a
minimum
of
one
cycle
of
sampling
and
analysis
for
each
successive
10­
second
period
and
one
cycle
of
data
recording
for
each
successive
6­
minute
period
Yes.

§
63.8(
c)(
4)(
ii)
..........................
Continuous
Monitoring
System
(
CMS)
Requirements.
Continuous
emissions
monitoring
system
must
have
a
minimum
of
one
cycle
of
operation
for
each
successive
15­
minute
period.
No.

§
63.8(
c)(
7)
 
(
8)
........................
Continuous
monitoring
systems
Requirements
Out­
of­
control
periods,
including
reporting
..................
Yes.

§
63.8(
d)
..................................
Continuous
monitoring
systems
Quality
Control.
i.
Requirements
for
continuous
monitoring
systems
quality
control,
including
calibration,
etc.;
and
Yes.

ii.
Must
keep
quality
control
plan
on
record
for
the
life
of
the
affected
source.
Keep
old
versions
for
5
years
after
revisions.
Yes.

§
63.8(
e)
..................................
Continuous
monitoring
systems
Performance
Evaluation.
Notification,
performance
evaluation
test
plan,
reports
Yes.

§
63.8(
f)(
1)
 
(
5)
.........................
Alternative
Monitoring
Method
...............
Procedures
for
Administrator
to
approve
alternative
monitoring.
Yes.

§
63.8(
f)(
6)
...............................
Alternative
to
Relative
Accuracy
Test
....
Procedures
for
Administrator
to
approve
alternative
relative
accuracy
tests
for
continuous
emissions
monitoring
system.
No.

§
63.8(
g)(
1)
 
(
4)
........................
Data
Reduction
......................................
i.
Continuous
opacity
monitoring
system
6­
minute
averages
calculated
over
at
least
36
evenly
spaced
data
points;
and
Yes.

ii.
Continuous
emissions
monitoring
system
1­
hour
averages
computed
over
at
least
4
equally
spaced
data
points.
Yes.

§
63.8(
g)(
5)
..............................
Data
Reduction
......................................
Data
that
cannot
be
used
in
computing
averages
for
continuous
emissions
monitoring
system
and
continuous
opacity
monitoring
system.
No.

§
63.9(
a)
..................................
Notification
Requirements
......................
Applicability
and
State
Delegation
...............................
Yes.

§
63.9(
b)(
1)
 
(
5)
........................
Initial
Notifications
..................................
i.
Submit
notification
120
days
after
effective
date;
and
Yes.

ii.
Notification
of
intent
to
construct/
reconstruct;
and
Yes.
iii.
Notification
of
commencement
of
construct/
reconstruct
Notification
of
startup;
and
Yes.

iv.
contents
of
each
.....................................................
Yes.

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Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
10
TO
SUBPART
DDDDD
OF
PART
63
 
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
DDDDD
 
Continued
Citation
Subject
Brief
description
Explanation
§
63.9(
c)
...................................
Request
for
Compliance
Extension
.......
Can
request
if
cannot
comply
by
date
or
if
installed
BACT/
LAER.
Yes.

§
63.9(
d)
..................................
Notification
of
Special
Compliance
Requirements
for
New
Source.
For
sources
that
commence
construction
between
proposal
and
promulgation
and
want
to
comply
3
years
after
effective
date.
Yes.

§
63.9(
e)
..................................
Notification
of
Performance
Test
...........
Notify
Administrator
60
days
prior
...............................
Yes.

§
63.9(
f)
...................................
Notification
of
VE/
Opacity
Test
..............
Notify
Administrator
30
days
prior
...............................
Yes.

§
63.9(
g)
..................................
Additional
Notifications
When
Using
Continuous
Monitoring
Systems.
i.
Notification
of
performance
evaluation;
and
ii.
Notification
using
continuous
opacity
monitoring
system
data;
and
iii.
Notification
that
exceeded
criterion
for
relative
accuracy
Yes.
Yes.

Yes.

§
63.9(
h)(
1)
 
(
6)
........................
Notification
of
Compliance
Status
..........
i.
Contents;
and
...........................................................
ii.
Due
60
days
after
end
of
performance
test
or
other
compliance
demonstration,
except
for
opacity/
VE,
which
are
due
30
days
after.
iii.
When
to
submit
to
Federal
vs.
State
authority
.......
Yes.
Yes.

Yes.

§
63.9(
i)
....................................
Adjustment
of
Submittal
Deadlines
........
Procedures
for
Administrator
to
approve
change
in
when
notifications
must
be
submitted.
Yes.

§
63.9(
j)
....................................
Change
in
Previous
Information
............
Must
submit
within
15
days
after
the
change
.............
Yes.

§
63.10(
a)
................................
Recordkeeping/
Reporting
......................
i.
Applies
to
all,
unless
compliance
extension;
and
ii.
When
to
submit
to
Federal
vx.
State
authority;
and
iii.
Procedures
for
owners
of
more
than
1
source
.......
Yes.
Yes.
Yes.

§
63.10(
b)(
1)
............................
Recordkeeping/
Reporting
......................
i.
General
Requirements;
and
.....................................
ii.
Keep
all
records
readily
available;
and
iii.
Keep
for
5
years
.....................................................
Yes.
Yes.
Yes.

§
63.10(
b)(
2)(
i)
 
(
v)
...................
Records
related
to
Startup,
Shutdown,
and
Malfunction.
i.
Occurrence
of
each
of
operation
(
process
equipment
and
Yes.

ii.
Occurrence
of
each
malfunction
of
air
pollution
equipment;
and
Yes.

iii.
Maintenance
on
air
pollution
control
equipment;
and
Yes.

iv.
Actions
during
startup,
shutdown,
and
malfunction.
Yes.

§
63.10(
b)(
2)(
vi)
and
(
x
 
xi)
......
Continuous
monitoring
systems
Records.
i.
Malfunctions,
inoperative,
out­
of­
control;
and
monitoring
inoperative,
out­
of­
systems
control;
and
Yes.

ii.
Calibration
checks;
and
...........................................
Yes.
iii.
Adjustments,
maintenance
......................................
Yes.

§
63.10(
b)(
2)(
vii)
 
(
ix)
...............
Records
..................................................
i.
Measurements
to
demonstrate
compliance
with
emission
limitations;
and
Yes.

ii.
Performance
test,
performance
evaluation,
and
visible
emission
observation
results;
and
Yes.

iii.
Measurements
to
determine
conditions
of
performance
tests
and
performance
evaluations.
Yes.

§
63.10(
b)(
2)(
xii)
......................
Records
..................................................
Records
when
under
waiver
........................................
Yes.

§
63.10(
b)(
2)(
xiii)
.....................
Records
..................................................
Records
when
using
alternative
to
relative
accuracy
test.
Yes.

§
63.10(
b)(
2)(
xiv)
.....................
Records
..................................................
All
documentation
supporting
Initial
Notification
and
Notification
of
Compliance
Status.
Yes.

§
63.10(
b)(
3)
............................
Records
..................................................
Applicability
Determinations
Yes.

§
63.10(
c)(
1)
 
(
6),
(
9)
 
(
15)
.......
Records
..................................................
Additional
Records
for
continuous
monitoring
systems
Yes.

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/
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Proposed
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PART
63
 
APPLICABILITY
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GENERAL
PROVISIONS
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Continued
Citation
Subject
Brief
description
Explanation
§
63.10(
c)(
7)
 
(
8)
......................
Records
..................................................
Records
of
excess
emissions
and
parameter
monitoring
exceedances
for
continuous
monitoring
systems
No.

§
63.10(
d)(
1)
............................
General
Reporting
Requirements
..........
Requirement
to
report
.................................................
Yes.

§
63.10(
d)(
2)
............................
Report
of
Performance
Test
Results
.....
When
to
submit
to
Federal
or
State
authority
.............
Yes.

§
63.10(
d)(
3)
............................
Reporting
Opacity
or
VE
Observations
..
What
to
report
and
when
.............................................
Yes.

§
63.10(
d)(
4)
............................
Progress
Reports
...................................
Must
submit
progress
reports
on
schedule
if
under
compliance
extension.
Yes.

§
63.10(
d)(
5)
............................
Startup,
Shutdown,
and
Malfunction
Reports
Contents
and
submission
............................................
Yes.

§
63.10(
e)(
1)
 
(
2)
......................
Additional
continuous
monitoring
systems
Reports.
i.
Must
report
results
for
each
CEM
on
a
unit;
and
Yes.

ii.
Written
copy
of
performance
evaluation;
and
Yes.
iii.
Three
copies
of
continuous
opacity
monitoring
system
performance
evaluation.
Yes.

§
63.10(
e)(
3)
............................
Reports
...................................................
Excess
Emission
Reports
............................................
No.

§
63.10(
e)(
3)(
i
 
iii)
....................
Reports
...................................................
Schedule
for
reporting
excess
emissions
and
parameter
monitor
exceedance
(
now
defined
as
deviations
No.

§
63.10(
e)(
3)(
iv
 
v)
...................
Excess
Emissions
Reports
....................
i.
Requirement
to
revert
to
quarterly
submission
if
there
is
an
excess
emissions
and
parameter
monitor
exceedance
(
now
defined
as
deviations);
and
No.

ii.
Provisions
to
request
semiannual
reporting
after
compliance
for
one
year;
and
No.

iii.
Submit
report
by
30th
day
following
end
of
quarter
or
calendar
half;
and
No.

iv.
If
there
has
not
been
an
exceedance
or
excess
emission
(
now
defined
as
deviations),
report
contents
is
a
statement
that
there
have
been
no
deviations
No.

§
63.10(
e)(
3)(
iv
 
v)
...................
Excess
Emissions
Reports
....................
Must
submit
report
containing
all
of
the
information
in
§
63.10(
c)(
5
 
13),
§
63.8(
c)(
7
 
8).
No.

§
63.10(
e)(
3)(
vi
 
viii)
.................
Excess
Emissions
Report
and
Summary
Report.
i.
Requirements
for
reporting
excess
emissions
for
continuous
monitoring
systems
(
now
called
deviations
No.

ii.
Requires
all
of
the
information
in
§
63.10(
c)(
5
 
13),
§
63.8(
c)(
7
 
8).
No.

§
63.10(
e)(
4)
............................
Reporting
continuous
opacity
monitoring
system
data.
Must
submit
continuous
opacity
monitoring
system
data
with
performance
test
data.
Yes.

§
63.10(
f)
.................................
Waiver
for
Recordkeeping/
Reporting
.....
Procedures
for
Administrator
to
waive
........................
Yes.

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E:\
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13JAP2.
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13JAP2
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Federal
Register
/
Vol.
68,
No.
8
/
Monday,
January
13,
2003
/
Proposed
Rules
TABLE
10
TO
SUBPART
DDDDD
OF
PART
63
 
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
DDDDD
 
Continued
Citation
Subject
Brief
description
Explanation
§
63.11
.....................................
Flares
.....................................................
Requirements
for
flares
...............................................
No.
§
63.12
.....................................
Delegation
..............................................
State
authority
to
enforce
standards
...........................
Yes.

§
63.13
.....................................
Addresses
..............................................
Addresses
where
reports,
notifications,
and
requests
are
sent.
Yes.

§
63.14
.....................................
Incorporation
by
Reference
...................
Test
methods
incorporated
by
reference
....................
Yes.

§
63.15
.....................................
Availability
of
Information
.......................
Public
and
confidential
information
.............................
Yes.

[
FR
Doc.
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85
Filed
1
 
10
 
03;
8:
45
am]

BILLING
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