1
For
the
reasons
set
forth
in
the
preamble,
part
51
of
chapter
I
of
title
40
of
the
Code
of
Federal
Regulations
is
proposed
to
be
amended
as
follows:

PART
51­­
REQUIREMENTS
FOR
PREPARATION,
ADOPTION,
AND
SUBMITTAL
OF
IMPLEMENTATION
PLANS
1.
The
authority
citation
for
part
51
continues
to
read
as
follows:

Authority:
23
U.
S.
C.
101;
42
U.
S.
C.
7410­
7671q.

2.
Section
51.302
is
amended
by
revising
paragraph
(
c)(
4)(
iii)
to
read
as
follows:

§
51.302
Implementation
control
strategies
for
reasonably
attributable
visibility
impairment.

*
*
*
*
*

(
c)
*
*
*

(
4)
*
*
*

(
iii)
BART
must
be
determined
for
fossil­
fuel
fired
generating
plants
having
a
total
generating
capacity
in
excess
of
750
megawatts
pursuant
to
"
Guidelines
for
Determining
Best
Available
Retrofit
Technology
for
Coal­
fired
Power
Plants
and
Other
Existing
Stationary
Facilities"
(
1980),
which
is
incorporated
by
reference,
exclusive
of
appendix
E,
which
was
published
in
the
Federal
Register
on
February
6,
1980
(
45
FR
8210),
except
that
options
more
stringent
than
NSPS
must
be
2
considered.
Establishing
a
BART
emission
limitation
equivalent
to
the
NSPS
level
of
control
is
not
a
sufficient
basis
to
avoid
the
analysis
of
control
options
required
by
the
guidelines.
This
document
is
EPA
publication
No.
450/
3­
80­
009b
and
is
for
sale
from
the
U.
S.
Department
of
Commerce,
National
Technical
Information
Service,
5285
Port
Royal
Road,
Springfield,
Virginia
22161.

*
*
*
*
*

3.
Section
51.308
is
amended
by
revising
paragraphs
(
b),

(
c),
and
(
e)(
1)(
ii)
to
read
as
follows:

§
51.308
Regional
haze
program
requirements.

*
*
*
*
*

(
b)
When
are
the
first
implementation
plans
due
under
the
regional
haze
program?
Except
as
provided
in
§
51.309(
c),
each
State
identified
in
§
51.300(
b)(
3)
must
submit,
for
the
entire
State,
an
implementation
plan
for
regional
haze
meeting
the
requirements
of
paragraphs
(
d)
and
(
e)
of
this
section
no
later
than
December
17,
2007.

(
c)
[
Reserved]

*
*
*
*
*

(
e)
*
*
*

(
1)
*
*
*

(
ii)
A
determination
of
BART
for
each
BART­
eligible
source
in
the
State
that
emits
any
air
pollutant
which
may
reasonably
be
3
anticipated
to
cause
or
contribute
to
any
impairment
of
visibility
in
any
mandatory
Class
I
Federal
area.
All
such
sources
are
subject
to
BART.

(
A)
The
determination
of
BART
must
be
based
on
an
analysis
of
the
best
system
of
continuous
emission
control
technology
available
and
associated
emission
reductions
achievable
for
each
BART­
eligible
source
that
is
subject
to
BART
within
the
State.

In
this
analysis,
the
State
must
take
into
consideration
the
technology
available,
the
costs
of
compliance,
the
energy
and
nonair
quality
environmental
impacts
of
compliance,
any
pollution
control
equipment
in
use
at
the
source,
the
remaining
useful
life
of
the
source,
and
the
degree
of
improvement
in
visibility
which
may
reasonably
be
anticipated
to
result
from
the
use
of
such
technology.

(
B)
The
determination
of
BART
for
fossil­
fuel
fired
power
plants
having
a
total
generating
capacity
greater
than
750
megawatts
must
be
made
pursuant
to
the
guidelines
in
appendix
Y
of
this
part
(
Guidelines
for
BART
Determinations
Under
the
Regional
Haze
Rule).

(
iii)
*
*
*

(
A)
*
*
*

(
B)
Exception.
A
State
is
not
required
to
make
a
determination
of
BART
for
SO2
or
for
NOx
if
a
BART­
eligible
source
has
the
potential
to
emit
less
than
40
tons
per
year
of
such
4
pollutant(
s),
or
for
PM10
if
a
BART­
eligible
source
emits
less
than
15
tons
per
year
of
such
pollutant.

*
*
*
*
*

§
308(
e)

*
*
*
*

(
3)
A
State
which
opts
under
40
CFR
51.308(
e)(
2)
to
implement
an
emissions
trading
program
or
other
alternative
measure
rather
than
to
require
sources
subject
to
BART
to
install,
operate,
and
maintain
BART
may
satisfy
the
final
step
of
the
demonstration
required
by
that
section
by
conducting
dispersion
modeling
to
determine
the
visibility
impact
of
the
trading
alternative.
The
dispersion
modeling
should
determine
differences
in
visibility
between
BART
and
the
trading
program
for
each
impacted
Class
I
area,
for
the
worst
and
best
20
percent
of
days.
The
modeling
should
identify
the
estimated
difference
from
future
baseline
visibility
conditions
under
the
two
approaches
for
each
Class
I
area,
and
the
average
difference
in
visibility
over
all
Class
I
areas
impacted
by
the
region's
emissions.

The
modeling
would
demonstrate
"
greater
reasonable
progress"

if
both
of
the
following
two
criteria
are
met:

­­
visibility
does
not
decline
in
any
Class
I
area,
and
­­
there
is
an
overall
improvement
in
visibility,
determined
by
comparing
the
average
differences
over
all
affected
Class
I
areas.
5
(
4)
A
State
that
opts
to
participate
in
the
Clean
Air
Interstate
Rule
cap­
and­
trade
and
trade
program
under
part
96
AAA
 
EEE
need
not
require
affected
BART­
eligible
EGU's
to
install,
operate,
and
maintain
BART.
A
State
that
chooses
this
option
may
also
include
provisions
for
a
geographic
enhancement
to
the
program
to
address
the
requirement
under
§
51.302(
c)
related
to
BART
for
reasonably
attributable
impairment
from
the
pollutants
covered
by
the
CAIR
cap­
and­
trade
program.

(
5)
After
a
State
has
met
the
requirements
for
BART
or
implemented
emissions
trading
program
or
other
alternative
measure
that
achieves
more
reasonable
progress
than
the
installation
and
operation
of
BART,
BART­
eligible
sources
will
be
subject
to
the
requirements
of
§
51.308(
d)
in
the
same
manner
as
other
sources.

(
6)
Any
BART­
eligible
facility
subject
to
the
requirement
under
§
51.308(
e)
to
install,
operate,
and
maintain
BART
may
apply
to
the
Administrator
for
an
exemption
from
that
requirement.
An
application
for
an
exemption
will
be
subject
to
the
requirements
of
§
51.303(
a)(
2)
 
(
h).

5.
Appendix
Y
to
Part
51
is
added
to
read
as
follows:

Appendix
Y
to
Part
51
­
Guidelines
for
BART
Determinations
Under
the
Regional
Haze
Rule
Table
of
Contents:
6
I.
Introduction
and
Overview
A.
What
is
the
purpose
of
the
guidelines?

B.
What
does
the
CAA
require
generally
for
improving
visibility?

C.
What
is
the
BART
requirement
in
the
CAA?

D.
What
types
of
visibility
problems
does
EPA
address
in
its
regulations?

E.
What
are
the
BART
requirements
in
EPA's
regional
haze
regulations?

F.
What
is
included
in
the
guidelines?

G.
Who
is
the
target
audience
for
the
guidelines?

H.
Do
EPA
regulations
require
the
use
of
these
guidelines?

II.
How
to
Identify
BART­
eligible
Sources
A.
What
are
the
steps
in
identifying
BART­
eligible
sources?

1.
Step
1:
Identify
emission
units
in
the
BART
categories
2.
Step
2:
Identify
the
start­
up
dates
of
the
emission
units
3.
Step
3:
Compare
the
potential
emissions
to
the
250
ton/
yr
cutoff
4.
Final
step:
Identify
the
emission
units
and
pollutants
that
constitute
the
BART­
eligible
source.

III.
How
to
Identify
Sources
"
Subject
to
BART"

IV.
The
BART
Determination:
Analysis
of
BART
Options
7
A.
What
factors
must
I
address
in
the
BART
Analysis?

B.
What
is
the
scope
of
the
BART
review?

C.
How
does
a
BART
review
relate
to
maximum
achievable
control
technology
(
MACT)
standards
under
CAA
section
112?

D.
What
are
the
five
basic
steps
of
a
case­
by­
case
BART
analysis?

1.
Step
1:
How
do
I
identify
all
available
retrofit
emission
control
techniques?

2.
Step
2:
How
do
I
determine
whether
the
options
identified
in
Step
1
are
technically
feasible?

3.
Step
3:
How
do
I
evaluate
technically
feasible
alternatives?

4.
Step
4:
For
a
BART
review,
what
impacts
am
I
expected
to
calculate
and
report?
What
methods
does
EPA
recommend
for
the
impacts
analyses?

a.
Impact
analysis
part
1:
how
do
I
estimate
the
costs
of
control?

b.
What
do
we
mean
by
cost
effectiveness?

c.
How
do
I
calculate
average
cost
effectiveness?

d.
How
do
I
calculate
baseline
emissions?

e.
How
do
I
calculate
incremental
cost
effectiveness?

f.
What
other
information
should
I
provide
in
the
cost
impacts
analysis?

g.
What
other
things
are
important
to
consider
in
the
8
cost
impacts
analysis?

h.
Impact
analysis
part
2:
How
should
I
analyze
and
report
energy
impacts?

i.
Impact
analysis
part
3:
How
do
I
analyze
"
non­
air
quality
environmental
impacts?"

j.
Impact
analysis
part
4:
What
are
examples
of
nonair
quality
environmental
impacts?

k.
How
do
I
take
into
account
a
project's
"
remaining
useful
life"
in
calculating
control
costs?

5.
Step
5:
How
should
I
determine
visibility
impacts
in
the
BART
determination?

E.
How
do
I
select
the
"
best"
alternative,
using
the
results
of
Steps
1
through
5?

1.
Summary
of
the
impacts
analysis
2.
Selecting
a
"
best"
alternative
3.
In
selecting
a
"
best"
alternative,
should
I
consider
the
affordability
of
controls?

4.
SO2
limits
for
utility
boilers
5.
NOx
limits
for
utility
boilers
V.
Enforceable
Limits
/
Compliance
Date
I.
INTRODUCTION
AND
OVERVIEW
B.
What
is
the
purpose
of
the
guidelines?

The
Clean
Air
Act
(
CAA),
in
sections
169A
and
169B,
contains
requirements
for
the
protection
of
visibility
in
156
scenic
areas
9
across
the
United
States.
To
meet
the
CAA's
requirements,
we
published
regulations
to
protect
against
a
particular
type
of
visibility
impairment
known
as
"
regional
haze."
The
regional
haze
rule
is
found
in
this
part
at
40
CFR
51.300
through
51.309.

These
regulations
require,
in
40
CFR
51.308(
e),
that
certain
types
of
existing
stationary
sources
of
air
pollutants
install
best
available
retrofit
technology
(
BART).
The
guidelines
are
designed
to
help
States
and
others
(
1)
identify
those
sources
that
must
comply
with
the
BART
requirement,
and
(
2)
determine
the
level
of
control
technology
that
represents
BART
for
each
source.

B.
What
does
the
CAA
require
generally
for
improving
visibility?

Section
169A
of
the
CAA,
added
to
the
CAA
by
the
1977
amendments,
requires
States
to
protect
and
improve
visibility
in
certain
scenic
areas
of
national
importance.
The
scenic
areas
protected
by
section
169A
are
"
the
mandatory
Class
I
Federal
Areas
.
.
.
where
visibility
is
an
important
value."
In
these
guidelines,
we
refer
to
these
as
"
Class
I
areas."
There
are
156
Class
I
areas,
including
47
national
parks
(
under
the
jurisdiction
of
the
Department
of
Interior
­
National
Park
Service),
108
wilderness
areas
(
under
the
jurisdiction
of
the
Department
of
Interior
­
Fish
and
Wildlife
Service
or
the
Department
of
Agriculture
 
U.
S.
Forest
Service),
and
one
International
Park
(
under
the
jurisdiction
of
the
Roosevelt­
10
Campobello
International
Commission).
The
Federal
Agency
with
jurisdiction
over
a
particular
Class
I
area
is
referred
to
in
the
CAA
as
the
Federal
Land
Manager.
A
complete
list
of
the
Class
I
areas
is
contained
in
40
CFR
81.401
through
81.437,
and
you
can
find
a
map
of
the
Class
I
areas
at
the
following
internet
site:

http://
www.
epa.
gov/
ttn/
oarpg/
t1/
fr_
notices/
classimp.
gif
The
CAA
establishes
a
national
goal
of
eliminating
man­
made
visibility
impairment
from
all
Class
I
areas.
As
part
of
the
plan
for
achieving
this
goal,
the
visibility
protection
provisions
in
the
CAA
mandate
that
EPA
issue
regulations
requiring
that
States
adopt
measures
in
their
State
implementation
plans
(
SIPs),
including
long­
term
strategies,
to
provide
for
reasonable
progress
towards
this
national
goal.
The
CAA
also
requires
States
to
coordinate
with
the
Federal
Land
Managers
as
they
develop
their
strategies
for
addressing
visibility.

C.
What
is
the
BART
requirement
in
the
CAA?

1.
Under
section
169A(
b)(
2)(
A)
of
the
CAA,
States
must
require
certain
existing
stationary
sources
to
install
BART.
The
BART
provision
applies
to
"
major
stationary
sources"
from
26
identified
source
categories
which
have
the
potential
to
emit
250
tons
per
year
or
more
of
any
air
pollutant.
The
CAA
requires
only
sources
which
were
put
in
place
during
a
specific
15­
year
time
interval
to
be
subject
to
BART.
The
BART
provision
applies
11
to
sources
that
existed
as
of
the
date
of
the
1977
CAA
amendments
(
that
is,
August
7,
1977)
but
which
had
not
been
in
operation
for
more
than
15
years
(
that
is,
not
in
operation
as
of
August
7,

1962).

2.
The
CAA
requires
BART
review
when
any
source
meeting
the
above
description
"
emits
any
air
pollutant
which
may
reasonably
be
anticipated
to
cause
or
contribute
to
any
impairment
of
visibility"
in
any
Class
I
area.
In
identifying
a
level
of
control
as
BART,
States
are
required
by
section
169A(
g)
of
the
CAA
to
consider:

(
a)
the
costs
of
compliance,

(
b)
the
energy
and
non­
air
quality
environmental
impacts
of
compliance,

(
c)
any
existing
pollution
control
technology
in
use
at
the
source,

(
d)
the
remaining
useful
life
of
the
source,
and
(
e)
the
degree
of
visibility
improvement
which
may
reasonably
be
anticipated
from
the
use
of
BART.

3.
The
CAA
further
requires
States
to
make
BART
emission
limitations
part
of
their
SIPs.
As
with
any
SIP
revision,
States
must
provide
an
opportunity
for
public
comment
on
the
BART
determinations,
and
EPA's
action
on
any
SIP
revision
will
be
subject
to
judicial
review.

D.
What
types
of
visibility
problems
does
EPA
address
in
its
12
regulations?

1.
We
addressed
the
problem
of
visibility
in
two
phases.
In
1980,
we
published
regulations
addressing
what
we
termed
"
reasonably
attributable"
visibility
impairment.
Reasonably
attributable
visibility
impairment
is
the
result
of
emissions
from
one
or
a
few
sources
that
are
generally
located
in
close
proximity
to
a
specific
Class
I
area.
The
regulations
addressing
reasonably
attributable
visibility
impairment
are
published
in
40
CFR
51.300
through
51.307.

2.
On
July
1,
1999,
we
amended
these
regulations
to
address
the
second,
more
common,
type
of
visibility
impairment
known
as
"
regional
haze."
Regional
haze
is
the
result
of
the
collective
contribution
of
many
sources
over
a
broad
region.
The
regional
haze
rule
slightly
modified
40
CFR
51.300
through
51.307,

including
the
addition
of
a
few
definitions
in
§
51.301,
and
added
new
§
§
51.308
and
51.309.

E.
What
are
the
BART
requirements
in
EPA's
regional
haze
regulations?

1.
In
the
July
1,
1999
rulemaking,
we
added
a
BART
requirement
for
regional
haze.
We
amended
the
BART
requirements
in
2005.

You
will
find
the
BART
requirements
in
40
CFR
51.308(
e).

Definitions
of
terms
used
in
40
CFR
51.308(
e)(
1)
are
found
in
40
CFR
51.301.

2.
As
we
discuss
in
detail
in
these
guidelines,
the
regional
13
haze
rule
codifies
and
clarifies
the
BART
provisions
in
the
CAA.

The
rule
requires
that
States
identify
and
list
"
BART­
eligible
sources,"
that
is,
that
States
identify
and
list
those
sources
that
fall
within
the
26
source
categories,
were
put
in
place
during
the
15­
year
window
of
time
from
1962
to
1977,
and
have
potential
emissions
greater
than
250
tons
per
year.
Once
the
State
has
identified
the
BART­
eligible
sources,
the
next
step
is
to
identify
those
BART­
eligible
sources
that
may
"
emit
any
air
pollutant
which
may
reasonably
be
anticipated
to
cause
or
contribute
to
any
impairment
of
visibility."
Under
the
rule,
a
source
which
fits
this
description
is
"
subject
to
BART."
For
each
source
subject
to
BART,
40
CFR
308(
e)(
1)(
ii)(
A)
requires
that
States
identify
the
level
of
control
representing
BART
after
considering
the
factors
set
out
in
CAA
section
169A(
g),
as
follows:

­­
States
must
identify
the
best
system
of
continuous
emission
control
technology
for
each
source
subject
to
BART
taking
into
account
the
technology
available,
the
costs
of
compliance,
the
energy
and
non­
air
quality
environmental
impacts
of
compliance,
any
pollution
control
equipment
in
use
at
the
source,
the
remaining
useful
life
of
the
source,

and
the
degree
of
visibility
improvement
that
may
be
expected
from
available
control
technology.

3.
After
a
State
has
identified
the
level
of
control
14
representing
BART
(
if
any),
it
must
establish
an
emission
limit
representing
BART
and
must
ensure
compliance
with
that
requirement
no
later
than
5
years
after
EPA
approves
the
SIP.

States
may
establish
design,
equipment,
work
practice
or
other
operational
standards
when
limitations
on
measurement
technologies
make
emission
standards
infeasible.

F.
What
is
included
in
the
guidelines?

1.
The
guidelines
provide
a
process
for
making
BART
determinations
that
States
can
use
in
implementing
the
regional
haze
BART
requirements
on
a
source­
by­
source
basis,
as
provided
in
40
CFR
51.308(
e)(
1).
States
must
follow
the
guidelines
in
making
BART
determinations
on
a
source­
by­
source
basis
for
750
megawatt
(
MW)
power
plants
but
are
not
required
to
use
the
process
in
the
guidelines
when
making
BART
determinations
for
other
types
of
sources.

2.
The
BART
analysis
process,
and
the
contents
of
these
guidelines,
are
as
follows:

(
a)
Identification
of
all
BART­
eligible
sources.
Section
II
of
these
guidelines
outlines
a
step­
by­
step
process
for
identifying
BART­
eligible
sources.

(
b)
Identification
of
sources
subject
to
BART.
As
noted
above,
sources
"
subject
to
BART"
are
those
BARTeligible
sources
which
"
emit
a
pollutant
which
may
reasonably
be
anticipated
to
cause
or
contribute
to
any
15
impairment
of
visibility
in
any
Class
I
area."
We
discuss
considerations
for
identifying
sources
subject
to
BART
in
section
III
of
the
guidance.

(
c)
The
BART
determination
process.
For
each
source
subject
to
BART,
the
next
step
is
to
conduct
an
analysis
of
emissions
control
alternatives.
This
step
includes
the
identification
of
available,
technically
feasible
retrofit
technologies,
and
for
each
technology
identified,
an
analysis
of
the
cost
of
compliance,
the
energy
and
non­
air
quality
environmental
impacts,
and
the
degree
of
visibility
improvement
in
affected
Class
I
areas
resulting
from
the
use
of
the
control
technology.
As
part
of
the
BART
analysis,
the
State
should
also
take
into
account
the
remaining
useful
life
of
the
source
and
any
existing
control
technology
present
at
the
source.
For
each
source,
the
State
will
determine
a
"
best
system
of
continuous
emission
reduction"
based
upon
its
evaluation
of
these
factors.

Procedures
for
the
BART
determination
step
are
described
in
section
IV
of
these
guidelines.

(
d)
Emissions
limits.
States
must
establish
emission
limits,
including
a
deadline
for
compliance,
consistent
with
the
BART
determination
process,
for
each
source
subject
to
BART.
Considerations
related
to
these
16
limits
are
discussed
in
section
V
of
these
guidelines.

G.
Who
is
the
target
audience
for
the
guidelines?

1.
The
guidelines
are
written
primarily
for
the
benefit
of
State,
local
and
Tribal
agencies,
and
describe
a
process
for
making
the
BART
determinations
and
establishing
the
emission
limitations
that
must
be
included
in
their
SIPs
or
Tribal
implementation
plans
(
TIPs).
Throughout
the
guidelines,
which
are
written
in
a
question
and
answer
format,
we
ask
questions
"
How
do
I......?"
and
answer
with
phrases
"
you
should....,
you
must...."
The
"
you"
means
a
State,
local
or
Tribal
agency
conducting
the
analysis.
We
have
used
this
format
to
make
the
guidelines
simpler
to
understand,
but
we
recognize
that
States
have
the
authority
to
require
source
owners
to
assume
part
of
the
analytical
burden,
and
that
there
will
be
differences
in
how
the
supporting
information
is
collected
and
documented.
We
also
recognize
that
data
collection,
analysis,
and
rule
development
may
be
performed
by
Regional
Planning
Organizations,
for
adoption
within
each
SIP
or
TIP.

2.
The
preamble
to
the
1999
regional
haze
rule
discussed
at
length
the
issue
of
Tribal
implementation
of
the
requirements
to
submit
a
plan
to
address
visibility.
As
explained
there,

requirements
related
to
visibility
are
among
the
programs
for
which
Tribes
may
be
determined
eligible
and
receive
authorization
to
implement
under
the
"
Tribal
Authority
Rule"
("
TAR")
(
40
CFR
17
49.1
through
49.11).
Tribes
are
not
subject
to
the
deadlines
for
submitting
visibility
implementation
plans
and
may
use
a
modular
approach
to
CAA
implementation.
We
believe
there
are
very
few
BART­
eligible
sources
located
on
Tribal
lands.
Where
such
sources
exist,
the
affected
Tribe
may
apply
for
delegation
of
implementation
authority
for
this
rule,
following
the
process
set
forth
in
the
TAR.

H.
Do
EPA
regulations
require
the
use
of
these
guidelines?

Section
169A(
b)
requires
us
to
issue
guidelines
for
States
to
follow
in
establishing
BART
emission
limitations
for
fossilfuel
fired
power
plants
having
a
capacity
in
excess
of
750
megawatts.
This
document
fulfills
that
requirement,
which
is
codified
in
40
CFR
308(
e)(
1)(
ii)(
B).
The
guidelines
establish
an
approach
to
implementing
the
requirements
of
the
BART
provisions
of
the
regional
haze
rule;
we
believe
that
these
procedures
and
the
discussion
of
the
requirements
of
the
regional
haze
rule
and
the
CAA
should
be
useful
to
the
States.
For
sources
other
than
750
MW
power
plants,
however,
States
retain
the
discretion
to
adopt
approaches
that
differ
from
the
guidelines.

II.
HOW
TO
IDENTIFY
BART­
ELIGIBLE
SOURCES
This
section
provides
guidelines
on
how
to
identify
BARTeligible
sources.
A
BART­
eligible
source
is
an
existing
stationary
source
in
any
of
26
listed
categories
which
meets
criteria
for
startup
dates
and
potential
emissions.
18
A.
What
are
the
steps
In
identifying
BART­
eligible
sources?

Figure
1
shows
the
steps
for
identifying
whether
the
source
is
a
"
BART
eligible
source:"

Step
1:
Identify
the
emission
units
in
the
BART
categories,

Step
2:
Identify
the
start­
up
dates
of
those
emission
units,
and
Step
3:
Compare
the
potential
emissions
to
the
250
ton/
yr
cutoff.
19
Figure
1.
How
to
determine
whether
a
source
is
BARTeligible

Step
1:
Identify
emission
units
in
the
BART
categories
Does
the
plant
contain
emissions
units
in
one
or
more
of
the
26
source
categories?

No

Stop

Yes

Proceed
to
Step
2
Step
2:
Identify
the
start­
up
dates
of
these
emission
units
Do
any
of
these
emissions
units
meet
the
following
two
tests?

In
existence
on
August
7,
1977
AND
Began
operation
after
August
7,
1962

No

Stop

Yes

Proceed
to
Step
3
20
Step
3:
Compare
the
potential
emissions
from
these
emission
units
to
the
250
ton/
yr
cutoff
Identify
the
"
stationary
source"
that
includes
the
emission
units
you
identified
in
Step
2.

Add
the
current
potential
emissions
from
all
the
emission
units
identified
in
Steps
1
and
2
that
are
included
within
the
"
stationary
source"
boundary.

Are
the
potential
emissions
from
these
units
250
tons
per
year
or
more
for
any
visibility­
impairing
pollutant?


No

Stop

Yes

These
emissions
units
comprise
the
"
BART­
eligible
source."
21
1.
Step
1:
Identify
emission
units
in
the
BART
categories
1.
The
BART
requirement
only
applies
to
sources
in
specific
categories
listed
in
the
CAA.
The
BART
requirement
does
not
apply
to
sources
in
other
source
categories,
regardless
of
their
emissions.
The
listed
categories
are:

(
1)
Fossil­
fuel
fired
steam
electric
plants
of
more
than
250
million
British
thermal
units
(
BTU)
per
hour
heat
input,

(
2)
Coal
cleaning
plants
(
thermal
dryers),

(
3)
Kraft
pulp
mills,

(
4)
Portland
cement
plants,

(
5)
Primary
zinc
smelters,

(
6)
Iron
and
steel
mill
plants,

(
7)
Primary
aluminum
ore
reduction
plants,

(
8)
Primary
copper
smelters,

(
9)
Municipal
incinerators
capable
of
charging
more
than
250
tons
of
refuse
per
day,

(
10)
Hydrofluoric,
sulfuric,
and
nitric
acid
plants,

(
11)
Petroleum
refineries,

(
12)
Lime
plants,

(
13)
Phosphate
rock
processing
plants,

(
14)
Coke
oven
batteries,

(
15)
Sulfur
recovery
plants,

(
16)
Carbon
black
plants
(
furnace
process),

(
17)
Primary
lead
smelters,
22
(
18)
Fuel
conversion
plants,

(
19)
Sintering
plants,

(
20)
Secondary
metal
production
facilities,

(
21)
Chemical
process
plants,

(
22)
Fossil­
fuel
boilers
of
more
than
250
million
BTUs
per
hour
heat
input,

(
23)
Petroleum
storage
and
transfer
facilities
with
a
capacity
exceeding
300,000
barrels,

(
24)
Taconite
ore
processing
facilities,

(
25)
Glass
fiber
processing
plants,
and
(
26)
Charcoal
production
facilities.

2.
Some
plants
may
have
emission
units
from
more
than
one
category,
and
some
emitting
equipment
may
fit
into
more
than
one
category.
Examples
of
this
situation
are
sulfur
recovery
plants
at
petroleum
refineries,
coke
oven
batteries
and
sintering
plants
at
steel
mills,
and
chemical
process
plants
at
refineries.
For
Step
1,
you
identify
all
of
the
emissions
units
at
the
plant
that
fit
into
one
or
more
of
the
listed
categories.
You
do
not
identify
emission
units
in
other
categories.

Example:
A
mine
is
collocated
with
an
electric
steam
generating
plant
and
a
coal
cleaning
plant.
You
would
identify
emission
units
associated
with
the
electric
steam
generating
plant
and
the
coal
cleaning
plant,
because
they
are
listed
23
categories,
but
not
the
mine,
because
coal
mining
is
not
a
listed
category.

3.
The
category
titles
are
generally
clear
in
describing
the
types
of
equipment
to
be
listed.
Most
of
the
category
titles
are
very
broad
descriptions
that
encompass
all
emission
units
associated
with
a
plant
site
(
for
example,
"
petroleum
refining"

and
"
kraft
pulp
mills").
This
same
list
of
categories
appears
in
the
PSD
regulations.
States
and
source
owners
need
not
revisit
any
interpretations
of
the
list
made
previously
for
purposes
of
the
PSD
program.
We
provide
the
following
clarifications
for
a
few
of
the
category
titles:

(
1)
"
Steam
electric
plants
of
more
than
250
million
BTU/
hr
heat
input."
Because
the
category
refers
to
"
plants,"

we
interpret
this
category
title
to
mean
that
boiler
capacities
should
be
aggregated
to
determine
whether
the
250
million
BTU/
hr
threshold
is
reached.
This
definition
includes
only
those
plants
that
generate
electricity
for
sale.
Plants
that
cogenerate
steam
and
electricity
also
fall
within
the
definition
of
"
steam
electric
plants".
Similarly,
combined
cycle
turbines
are
also
considered
"
steam
electric
plants"
because
such
facilities
incorporate
heat
recovery
steam
generators.
Simple
cycle
turbines,
in
contrast,
are
not
"
steam
electric
plants"
because
these
turbines
24
typically
do
not
generate
steam.

Example:
A
stationary
source
includes
a
steam
electric
plant
with
three
100
million
BTU/
hr
boilers.

Because
the
aggregate
capacity
exceeds
250
million
BTU/
hr
for
the
"
plant,"
these
boilers
would
be
identified
in
Step
2.

(
2)
"
Fossil­
fuel
boilers
of
more
than
250
million
BTU/
hr
heat
input."
We
interpret
this
category
title
to
cover
only
those
boilers
that
are
individually
greater
than
250
million
BTU/
hr.
However,
an
individual
boiler
smaller
than
250
million
BTU/
hr
should
be
subject
to
BART
if
it
is
part
of
a
process
description
at
a
plant
that
is
in
a
different
BART
category
 
for
example,
a
boiler
at
a
Kraft
pulp
mill
that,
in
addition
to
providing
steam
or
mechanical
power,
uses
the
waste
liquor
from
the
process
as
a
fuel.
In
general,
if
the
process
uses
any
by­
product
of
the
boiler
and
the
boiler's
function
is
to
serve
the
process,
then
the
boiler
is
integral
to
the
process,
and
should
be
considered
to
be
part
of
the
process
description.

Also,
you
should
consider
a
multi­
fuel
boiler
to
be
a
"
fossil­
fuel
boiler"
if
it
burns
any
amount
of
fossil
fuel.
You
may
take
federally
and
State
enforceable
operational
limits
into
account
in
25
determining
whether
a
multi­
fuel
boiler's
fossil
fuel
capacity
exceeds
250
million
Btu/
hr.

(
3)
"
Petroleum
storage
and
transfer
facilities
with
a
capacity
exceeding
300,000
barrels."
The
300,000
barrel
cutoff
refers
to
total
facility­
wide
tank
capacity
for
tanks
that
were
put
in
place
within
the
1962­
1977
time
period,
and
includes
gasoline
and
other
petroleum­
derived
liquids.

(
4)
"
Phosphate
rock
processing
plants."
This
category
descriptor
is
broad,
and
includes
all
types
of
phosphate
rock
processing
facilities,
including
elemental
phosphorous
plants
as
well
as
fertilizer
production
plants.

(
5)
Charcoal
production
facilities."
We
interpret
this
category
to
include
charcoal
briquet
manufacturing
and
activated
carbon
production.

(
6)
"
Chemical
process
plants"
and
pharmaceutical
manufacturing.
Consistent
with
past
policy,
we
interpret
the
category
"
chemical
process
plants"
to
include
those
facilities
within
the
2­
digit
Standard
Industrial
Classification
(
SIC)
code
28.
Accordingly,

we
interpret
the
term
"
chemical
process
plants"
to
include
pharmaceutical
manufacturing
facilities.

(
7)
"
Secondary
metal
production."
We
interpret
this
26
category
to
include
nonferrous
metal
facilities
included
within
SIC
code
3341,
and
secondary
ferrous
metal
facilities
that
we
also
consider
to
be
included
within
the
category
"
iron
and
steel
mill
plants."

(
8)
"
Primary
aluminum
ore
reduction."
We
interpret
this
category
to
include
those
facilities
covered
by
40
CFR
60.190,
the
new
source
performance
standard
(
NSPS)
for
primary
alumimum
ore
reduction
plants.
This
definition
is
also
consistent
with
the
definition
at
40
CFR
63.840.

2.
Step
2:
Identify
the
start­
up
dates
of
the
emission
units
1.
Emissions
units
listed
under
Step
1
are
BART­
eligible
only
if
they
were
"
in
existence"
on
August
7,
1977
but
were
not
"
in
operation"
before
August
7,
1962.

What
does
"
in
existence
on
August
7,
1977"
mean?

2.
The
regional
haze
rule
defines
"
in
existence"
to
mean
that:

"
the
owner
or
operator
has
obtained
all
necessary
preconstruction
approvals
or
permits
required
by
Federal,

State,
or
local
air
pollution
emissions
and
air
quality
laws
or
regulations
and
either
has
(
1)
begun,
or
caused
to
begin,

a
continuous
program
of
physical
on­
site
construction
of
the
facility
or
(
2)
entered
into
binding
agreements
or
contractual
obligations,
which
cannot
be
canceled
or
modified
without
substantial
loss
to
the
owner
or
operator,
27
to
undertake
a
program
of
construction
of
the
facility
to
be
completed
in
a
reasonable
time."
40
CFR
51.301.

As
this
definition
is
essentially
identical
to
the
definition
of
"
commence
construction"
as
that
term
is
used
in
the
PSD
regulations,
the
two
terms
mean
the
same
thing.
See
40
CFR
51.165(
a)(
1)(
xvi)
and
40
CFR
52.21(
b)(
9).
Under
this
definition,

an
emissions
unit
could
be
"
in
existence"
even
if
it
did
not
begin
operating
until
several
years
after
1977
.

Example:
The
owner
of
a
source
obtained
all
necessary
permits
in
early
1977
and
entered
into
binding
construction
agreements
in
June
1977.
Actual
onsite
construction
began
in
late
1978,
and
construction
was
completed
in
mid­
1979.
The
source
began
operating
in
September
1979.
The
emissions
unit
was
"
in
existence"
as
of
August
7,

1977.

Major
stationary
sources
which
commenced
construction
AFTER
August
7,
1977
(
i.
e.,
major
stationary
sources
which
were
not
"
in
existence"
on
August
7,
1977)
were
subject
to
new
source
review
(
NSR)
under
the
PSD
program.
Thus,
the
August
7,
1977
"
in
existence"
test
is
essentially
the
same
thing
as
the
identification
of
emissions
units
that
were
grandfathered
from
the
NSR
review
requirements
of
the
1977
CAA
amendments.

3.
Sources
are
not
BART­
eligible
if
the
only
change
at
the
28
plant
during
the
relevant
time
period
was
the
addition
of
pollution
controls.
For
example,
if
the
only
change
at
a
copper
smelter
during
the
1962
through
1977
time
period
was
the
addition
of
acid
plants
for
the
reduction
of
SO2
emissions,
these
emission
controls
would
not
by
themselves
trigger
a
BART
review.

What
does
"
in
operation
before
August
7,
1962"
mean?

An
emissions
unit
that
meets
the
August
7,
1977
"
in
existence"
test
is
not
BART­
eligible
if
it
was
in
operation
before
August
7,
1962.
"
In
operation"
is
defined
as
"
engaged
in
activity
related
to
the
primary
design
function
of
the
source."

This
means
that
a
source
must
have
begun
actual
operations
by
August
7,
1962
to
satisfy
this
test.

Example:
The
owner
or
operator
entered
into
binding
agreements
in
1960.
Actual
on­
site
construction
began
in
1961,

and
construction
was
complete
in
mid­
1962.
The
source
began
operating
in
September
1962.
The
emissions
unit
was
not
"
in
operation"
before
August
7,
1962
and
is
therefore
subject
to
BART.

What
is
a
"
reconstructed
source?"

1.
Under
a
number
of
CAA
programs,
an
existing
source
which
is
completely
or
substantially
rebuilt
is
treated
as
a
new
source.

Such
"
reconstructed"
sources
are
treated
as
new
sources
as
of
the
time
of
the
reconstruction.
Consistent
with
this
overall
approach
to
reconstructions,
the
definition
of
BART­
eligible
29
facility
(
reflected
in
detail
in
the
definition
of
"
existing
stationary
facility")
includes
consideration
of
sources
that
were
in
operation
before
August
7,
1962,
but
were
reconstructed
during
the
August
7,
1962
to
August
7,
1977
time
period.

2.
Under
the
regional
haze
regulations
at
40
CFR
51.301,
a
reconstruction
has
taken
place
if
"
the
fixed
capital
cost
of
the
new
component
exceeds
50
percent
of
the
fixed
capital
cost
of
a
comparable
entirely
new
source."
The
rule
also
states
that
"[
a]
ny
final
decision
as
to
whether
reconstruction
has
occurred
must
be
made
in
accordance
with
the
provisions
of
§
§
60.15
(
f)(
1)

through
(
3)
of
this
title."
"[
T]
he
provisions
of
§
§
60.15(
f)(
1)

through
(
3)"
refers
to
the
general
provisions
for
New
Source
Performance
Standards
(
NSPS).
Thus,
the
same
policies
and
procedures
for
identifying
reconstructed
"
affected
facilities"

under
the
NSPS
program
must
also
be
used
to
identify
reconstructed
"
stationary
sources"
for
purposes
of
the
BART
requirement.

3.
You
should
identify
reconstructions
on
an
emissions
unit
basis,
rather
than
on
a
plantwide
basis.
That
is,
you
need
to
identify
only
the
reconstructed
emission
units
meeting
the
50
percent
cost
criterion.
You
should
include
reconstructed
emission
units
in
the
list
of
emission
units
you
identified
in
Step
1.
You
need
consider
as
possible
reconstructions
only
those
emissions
units
with
the
potential
to
emit
more
than
250
tons
per
30
year
of
any
visibility­
impairing
pollutant.

4.
The
"
in
operation"
and
"
in
existence"
tests
apply
to
reconstructed
sources.
If
an
emissions
unit
was
reconstructed
and
began
actual
operation
before
August
7,
1962,
it
is
not
BARTeligible
Similarly,
any
emissions
unit
for
which
a
reconstruction
"
commenced"
after
August
7,
1977,
is
not
BARTeligible

How
are
modifications
treated
under
the
BART
provision?

1.
The
NSPS
program
and
the
major
source
NSR
program
both
contain
the
concept
of
modifications.
In
general,
the
term
"
modification"
refers
to
any
physical
change
or
change
in
the
method
of
operation
of
an
emissions
unit
that
results
in
an
increase
in
emissions.

2.
The
BART
provision
in
the
regional
haze
rule
contains
no
explicit
treatment
of
modifications
or
how
modified
emissions
units,
previously
subject
to
the
requirement
to
install
best
available
control
technology
(
BACT),
lowest
achievable
emission
rate
(
LAER)
controls,
and/
or
NSPS
are
treated
under
the
rule.
As
the
BART
requirements
in
the
CAA
do
not
appear
to
provide
any
exemption
for
sources
which
have
been
modified
since
1977,
the
best
interpretation
of
the
CAA
visibility
provisions
is
that
a
subsequent
modification
does
not
change
a
unit's
construction
date
for
the
purpose
of
BART
applicability.
Accordingly,
if
an
emissions
unit
began
operation
before
1962,
it
is
not
BART­
31
eligible
if
it
was
modified
between
1962
and
1977,
so
long
as
the
modification
is
not
also
a
"
reconstruction."
On
the
other
hand,

an
emissions
unit
which
began
operation
within
the
1962­
1977
time
window,
but
was
modified
after
August
7,
1977,
is
BART­
eligible.

We
note,
however,
that
if
such
a
modification
was
a
major
modification
that
resulted
in
the
installation
of
controls,
the
State
will
take
this
into
account
during
the
review
process
and
may
find
that
the
level
of
controls
already
in
place
are
consistent
with
BART.

3.
Step
3:
Compare
the
potential
emissions
to
the
250
ton/
yr
cutoff
The
result
of
Steps
1
and
2
will
be
a
list
of
emissions
units
at
a
given
plant
site,
including
reconstructed
emissions
units,
that
are
within
one
or
more
of
the
BART
categories
and
that
were
placed
into
operation
within
the
1962­
1977
time
window.

The
third
step
is
to
determine
whether
the
total
emissions
represent
a
current
potential
to
emit
that
is
greater
than
250
tons
per
year
of
any
single
visibility
impairing
pollutant.

Fugitive
emissions,
to
the
extent
quantifiable,
must
be
counted.

In
most
cases,
you
will
add
the
potential
emissions
from
all
emission
units
on
the
list
resulting
from
Steps
1
and
2.
In
a
few
cases,
you
may
need
to
determine
whether
the
plant
contains
more
than
one
"
stationary
source"
as
the
regional
haze
rule
defines
that
term,
and
as
we
explain
further
below.
32
What
pollutants
should
I
address?

Visibility­
impairing
pollutants
include
the
following:

(
1)
Sulfur
dioxide
(
SO2),

(
2)
Nitrogen
oxides
(
NOx),
and
(
3)
Particulate
matter.

You
may
use
PM10
as
an
indicator
for
particulate
matter
in
this
intial
step.
[
Note
that
we
do
not
recommend
use
of
total
suspended
particulates
(
TSP)
as
in
indicator
for
particulate
matter.]
As
emissions
of
PM10
include
the
components
of
PM2.5
as
a
subset,
there
is
no
need
to
have
separate
250
ton
thresholds
for
PM10
and
PM2.5;
250
tons
of
PM10
represents
at
most
250
tons
of
PM2.5,
and
at
most
250
tons
of
any
individual
particulate
species
such
as
elemental
carbon,
crustal
material,
etc.

However,
if
you
determine
that
a
source
of
particulate
matter
is
BART­
eligible,
it
will
be
important
to
distinguish
between
the
fine
and
coarse
particle
components
of
direct
particulate
emissions
in
the
remainder
of
the
BART
analysis,

including
for
the
purpose
of
modeling
the
source's
impact
on
visibility.
This
is
because
although
both
fine
and
coarse
particulate
matter
contribute
to
visibility
impairment,
the
long­
range
transport
1
Fine
particles:
Overview
of
Atmospheric
Chemistry,
Sources
of
Emissions,
and
Ambient
Monitoring
Data,
Memorandum
to
Docket
OAR
2002­
0076,
April
1,
2005.

33
of
fine
particles
is
of
particular
concern
in
the
formation
of
regional
haze.
Thus,
for
example,

air
quality
modeling
results
used
in
the
BART
determination
will
provide
a
more
accurate
prediction
of
a
source's
impact
on
visibility
if
the
inputs
into
the
model
account
for
the
relative
particle
size
of
any
directly
emitted
particulate
matter
(
i.
e.
PM10
vs.
PM2.5).

You
should
exercise
judgment
in
deciding
whether
the
following
pollutants
impair
visibility
in
an
area:

(
4)
Volatile
organic
compounds
(
VOC),
and
(
5)
Ammonia
and
ammonia
compounds.

You
should
use
your
best
judgment
in
deciding
whether
VOC
or
ammonia
emissions
from
a
source
are
likely
to
have
an
impact
on
visibility
in
an
area.

Certain
types
of
VOC
emissions,
for
example,
are
more
likely
to
form
secondary
organic
aerosols
than
others.
1
Similarly,
controlling
ammonia
emissions
in
some
areas
may
not
have
a
significant
impact
on
visibility.
You
need
not
provide
a
formal
showing
of
an
individual
decision
that
a
34
source
of
VOC
or
ammonia
emissions
is
not
subject
to
BART
review.
Because
air
quality
modeling
may
not
be
feasible
for
individual
sources
of
VOC
or
ammonia,
you
should
also
exercise
your
judgement
in
assessing
the
degree
of
visibility
impacts
due
to
emisssions
of
VOC
and
emissions
of
ammonia
or
ammonia
compounds.
You
should
fully
document
the
basis
for
judging
that
a
VOC
or
ammonia
source
merits
BART
review,
including
your
assessment
of
the
source's
contribution
to
visibility
impairment.

What
does
the
term
"
potential"
emissions
mean?

The
regional
haze
rule
defines
potential
to
emit
as
follows:

"
Potential
to
emit"
means
the
maximum
capacity
of
a
stationary
source
to
emit
a
pollutant
under
its
physical
and
operational
design.
Any
physical
or
operational
limitation
on
the
capacity
of
the
source
to
emit
a
pollutant
including
air
pollution
control
equipment
and
restrictions
on
hours
of
operation
or
on
the
type
or
amount
of
material
combusted,
stored,
or
processed,
shall
be
treated
as
part
of
its
design
if
the
limitation
or
the
effect
it
would
have
on
emissions
is
federally
enforceable.
Secondary
emissions
do
not
35
count
in
determining
the
potential
to
emit
of
a
stationary
source.

The
definition
of
"
potential
to
emit"
means
that
a
source
which
actually
emits
less
than
250
tons
per
year
of
a
visibility­
impairing
pollutant
is
BART­
eligible
if
its
emissions
would
exceed
250
tons
per
year
when
operating
at
its
maximum
capacity
given
its
physical
and
operational
design
(
and
considering
all
federally
enforceable
and
State
enforceable
permit
limits.)

Example:
A
source,
while
operating
at
one­
fourth
of
its
capacity,
emits
75
tons
per
year
of
SO2.

If
it
were
operating
at
100
percent
of
its
maximum
capacity,
the
source
would
emit
300
tons
per
year.
Because
under
the
above
definition
such
a
source
would
have
"
potential"
emissions
that
exceed
250
tons
per
year,
the
source
(
if
in
a
listed
category
and
built
during
the
1962­
1977
time
window)

would
be
BART­
eligible.

How
do
I
identify
whether
a
plant
has
more
than
one
"
stationary
source?"

1.
The
regional
haze
rule,
in
40
CFR
51.301,
defines
a
stationary
source
as
a
"
building,
structure,
facility
or
2
Note:
Most
of
these
terms
and
definitions
are
the
same
for
regional
haze
and
the
1980
visibility
regulations.
For
the
regional
haze
rule
we
use
the
term
"
BART­
eligible
source"
rather
than
"
existing
stationary
facility"
to
clarify
that
only
a
limited
subset
of
existing
stationary
sources
are
subject
to
BART.

36
installation
which
emits
or
may
emit
any
air
pollutant."
2
The
rule
further
defines
"
building,
structure
or
facility"

as:

all
of
the
pollutant­
emitting
activities
which
belong
to
the
same
industrial
grouping,
are
located
on
one
or
more
contiguous
or
adjacent
properties,
and
are
under
the
control
of
the
same
person
(
or
persons
under
common
control).
Pollutant­
emitting
activities
must
be
considered
as
part
of
the
same
industrial
grouping
if
they
belong
to
the
same
Major
Group
(
i.
e.,
which
have
the
same
two­
digit
code)
as
described
in
the
Standard
Industrial
Classification
Manual,
1972
as
amended
by
the
1977
Supplement
(
U.
S.
Government
Printing
Office
stock
numbers
4101­
0066
and
003­
005­
00176­
0,

respectively).

2.
In
applying
this
definition,
it
is
necessary
to
determine
which
facilities
are
located
on
"
contiguous
or
adjacent
properties."
Within
this
contiguous
and
adjacent
area,
it
is
also
necessary
to
group
those
emission
units
that
are
under
"
common
control."
We
note
that
these
plant
3
We
recognize
that
we
are
in
a
transition
period
from
the
use
of
the
SIC
system
to
a
new
system
called
the
North
American
Industry
Classification
System
(
NAICS).
For
purposes
of
identifying
BART­
eligible
sources,
you
may
use
either
2­
digit
SICS
or
the
equivalent
in
the
NAICS
system.

4
Note:
The
concept
of
support
facility
used
for
the
NSR
program
applies
here
as
well.
Support
facilities,
that
is
facilities
that
convey,
store
or
otherwise
assist
in
the
production
of
the
principal
product,
must
be
grouped
with
primary
facilities
even
when
the
facilities
fall
within
separate
SIC
codes.
For
purposes
of
BART
reviews,
however,
such
support
facilities
(
a)
must
be
within
one
of
the
26
listed
source
categories
and
(
b)
must
have
been
in
existence
as
of
August
7,
1977,
and
(
c)
must
not
have
been
in
operation
as
of
August
7,
1962.

37
boundary
issues
and
"
common
control"
issues
are
very
similar
to
those
already
addressed
in
implementation
of
the
title
V
operating
permits
program
and
in
NSR.

3.
For
emission
units
within
the
"
contiguous
or
adjacent"

boundary
and
under
common
control,
you
must
group
emission
units
that
are
within
the
same
industrial
grouping
(
that
is,

associated
with
the
same
2­
digit
SIC
code)
in
order
to
define
the
stationary
source.
3
For
most
plants
on
the
BART
source
category
list,
there
will
only
be
one
2­
digit
SIC
that
applies
to
the
entire
plant.
For
example,
all
emission
units
associated
with
kraft
pulp
mills
are
within
SIC
code
26,
and
chemical
process
plants
will
generally
include
emission
units
that
are
all
within
SIC
code
28.
The
"
2­

digit
SIC
test"
applies
in
the
same
way
as
the
test
is
applied
in
the
major
source
NSR
programs.
4
38
4.
For
purposes
of
the
regional
haze
rule,
you
must
group
emissions
from
all
emission
units
put
in
place
within
the
1962­
1977
time
period
that
are
within
the
2­
digit
SIC
code,

even
if
those
emission
units
are
in
different
categories
on
the
BART
category
list.

Examples:
A
chemical
plant
which
started
operations
within
the
1962
to
1977
time
period
manufactures
hydrochloric
acid
(
within
the
category
title
"
Hydrochloric,
sulfuric,
and
nitric
acid
plants")
and
various
organic
chemicals
(
within
the
category
title
"
chemical
process
plants").
All
of
the
emission
units
are
within
SIC
code
28
and,

therefore,
all
the
emission
units
are
considered
in
determining
BART
eligibility
of
the
plant.
You
sum
the
emissions
over
all
of
these
emission
units
to
see
whether
there
are
more
than
250
tons
per
year
of
potential
emissions.

A
steel
mill
which
started
operations
within
the
1962
to
1977
time
period
includes
a
sintering
plant,
a
coke
oven
battery,
and
various
other
emission
units.
All
of
the
emission
units
are
within
SIC
code
33.
You
39
sum
the
emissions
over
all
of
these
emission
units
to
see
whether
there
are
more
than
250
tons
per
year
of
potential
emissions.

4.
Final
Step:
Identify
the
emissions
units
and
pollutants
that
constitute
the
BART­
eligible
source
If
the
emissions
from
the
list
of
emissions
units
at
a
stationary
source
exceed
a
potential
to
emit
of
250
tons
per
year
for
any
visibility­
impairing
pollutant,
then
that
collection
of
emissions
units
is
a
BART­
eligible
source.

Example:
A
stationary
source
comprises
the
following
two
emissions
units,
with
the
following
potential
emissions:

Emissions
unit
A
200
tons/
yr
SO2
150
tons/
yr
NOX
25
tons/
yr
PM
Emissions
unit
B
100
tons/
yr
SO2
75
tons/
yr
NOX
10
tons/
yr
PM
For
this
example,
potential
emissions
of
SO2
are
300
tons/
yr,

which
exceeds
the
250
tons/
yr
threshold.
Accordingly,
the
entire
"
stationary
source",
that
is,
emissions
units
A
and
B,
may
be
subject
to
a
BART
review
for
SO2,
NOX,
and
PM,
even
though
the
potential
emissions
of
PM
and
NOx
at
each
emissions
unit
are
less
than
250
tons/
yr
each.
40
Example:
The
total
potential
emissions,
obtained
by
adding
the
potential
emissions
of
all
emission
units
in
a
listed
category
at
a
plant
site,
are
as
follows:

200
tons/
yr
SO2
150
tons/
yr
NOX
25
tons/
yr
PM
Even
though
total
emissions
exceed
250
tons/
yr,
no
individual
regulated
pollutant
exceeds
250
tons/
yr
and
this
source
is
not
BART­
eligible.

Can
States
establish
de
minimis
levels
of
emissions
for
pollutants
at
BART­
eligible
sources?

In
order
to
simplify
BART
determinations,
States
may
choose
to
identify
de
minimis
levels
of
pollutants
at
BARTeligible
sources
(
but
are
not
required
to
do
so).
De
minimis
values
should
be
identified
with
the
purpose
of
excluding
only
those
emissions
so
minimial
that
they
are
unlikely
to
contribute
to
regional
haze.
Any
de
minimis
values
that
you
adopt
must
not
be
higher
than
the
PSD
applicability
levels:
40
tons/
yr
for
SO2,
NOX
and
VOC,
and
15
tons/
yr
for
PM1
0.
These
de
minimis
levels
may
only
be
applied
on
a
plant­
wide
basis.

III.
HOW
TO
IDENTIFY
SOURCES
"
SUBJECT
TO
BART"

Once
you
have
compiled
your
list
of
BART­
eligible
sources,

you
need
to
determine
whether
(
1)
to
make
BART
determinations
for
41
all
of
them
or
(
2)
to
consider
exempting
some
of
them
from
BART
because
they
may
not
reasonably
be
anticipated
to
cause
or
contribute
to
any
visibility
impairment
in
a
Class
I
area.
If
you
decide
to
make
BART
determinations
for
all
the
BART­
eligible
sources
on
your
list,
you
should
work
with
your
regional
planning
organization
(
RPO)
to
show
that,
collectively,
they
cause
or
contribute
to
visibility
impairment
in
at
least
one
Class
I
area.

You
should
then
make
individual
BART
determinations
by
applying
the
five
statutory
factors
discussed
in
Section
IV
below.

On
the
other
hand,
you
also
may
choose
to
perform
an
initial
examination
to
determine
whether
a
particular
BART­
eligible
source
or
group
of
sources
causes
or
contributes
to
visibility
impairment
in
nearby
Class
I
areas.
If
your
analysis,
or
information
submitted
by
the
source,
shows
that
an
individual
source
or
group
of
sources
(
or
certain
pollutants
from
those
sources)
is
not
reasonably
anticipated
to
cause
or
contribute
to
any
visibility
impairment
in
a
Class
I
area,
then
you
do
not
need
to
make
BART
determinations
for
that
source
or
group
of
sources
(
or
for
certain
pollutants
from
those
sources).
In
such
a
case,

the
source
is
not
"
subject
to
BART"
and
you
do
not
need
to
apply
the
five
statutory
factors
to
make
a
BART
determination.
This
section
of
the
Guideline
discusses
several
approaches
that
you
can
use
to
exempt
sources
from
the
BART
determination
process.

A.
What
Steps
Do
I
Follow
to
Determine
Whether
A
Source
or
Group
5
We
expect
that
regional
planning
organizations
will
have
modeling
information
that
identifies
sources
affecting
visibility
in
individual
class
I
areas.

42
of
Sources
Cause
or
Contribute
to
Visibility
Impairment
for
Purposes
of
BART?

1.
How
Do
I
Establish
a
Threshold?

One
of
the
first
steps
in
determining
whether
sources
cause
or
contribute
to
visibility
impairment
for
purposes
of
BART
is
to
establish
a
threshold
(
measured
in
deciviews)
against
which
to
measure
the
visibility
impact
of
one
or
more
sources.
A
single
source
that
is
responsible
for
a
1.0
deciview
change
or
more
should
be
considered
to
"
cause"
visibility
impairment;
a
source
that
causes
less
than
a
1.0
deciview
change
may
still
contribute
to
visibility
impairment
and
thus
be
subject
to
BART.

Because
of
varying
circumstances
affecting
different
Class
I
areas,
the
appropriate
threshold
for
determining
whether
a
source
"
contributes
to
any
visibility
impairment"
for
the
purposes
of
BART
may
reasonably
differ
across
States.
As
a
general
matter,

any
threshold
that
you
use
for
determining
whether
a
source
"
contributes"
to
visibility
impairment
should
not
be
higher
than
0.5
deciviews.

In
setting
a
threshold
for
"
contribution,"
you
should
consider
the
number
of
emissions
sources
affecting
the
Class
I
areas
at
issue
and
the
magnitude
of
the
individual
sources'

impacts.
5
In
general,
a
larger
number
of
sources
causing
impacts
6
Note
that
the
contribution
threshold
should
be
used
to
determine
whether
an
individual
source
is
reasonably
anticipated
to
contribute
to
visibility
impairment.
You
should
not
aggregate
the
visibility
effects
of
multiple
sources
and
compare
their
collective
effects
against
your
contribution
threshold
because
this
would
inappropriately
create
a
"
contribute
to
contribution"
test.

43
in
a
Class
I
area
may
warrant
a
lower
contribution
threshold.

States
remain
free
to
use
a
threshold
lower
than
0.5
deciviews
if
they
conclude
that
the
location
of
a
large
number
of
BARTeligible
sources
within
the
State
and
in
proximity
to
a
Class
I
area
justify
this
approach.
6
2.
What
Pollutants
Do
I
Need
to
Consider?

You
must
look
at
SO2,
NOx,
and
direct
particulate
matter
(
PM)

emissions
in
determining
whether
sources
cause
or
contribute
to
visibility
impairment,
including
both
PM10
and
PM2.5.
Consistent
with
the
approach
for
identifying
your
BART­
eligible
sources,
you
do
not
need
to
consider
less
than
de
minimis
emissions
of
these
pollutants
from
a
source.

As
explained
in
Section
II,
you
must
use
your
best
judgement
to
determine
whether
VOC
or
ammonia
emissions
are
likely
to
have
an
impact
on
visibility
in
an
area.
In
addition,
you
may
use
PM10
or
PM2.5
as
an
indicator
for
PM2.5
in
determining
whether
a
source
is
subject
to
BART.
In
determining
whether
a
source
contributes
to
visibility
impairment,
however,
you
should
distinguish
between
the
fine
and
coarse
particle
components
of
direct
particulate
emissions.
Although
both
fine
and
coarse
particulate
matter
44
contribute
to
visibility
impairment,
the
long­
range
transport
of
fine
particles
is
of
particular
concern
in
the
formation
of
regional
haze.
Air
quality
modeling
results
used
in
the
BART
determination
will
provide
a
more
accurate
prediction
of
a
source's
impact
on
visibility
if
the
inputs
into
the
model
account
for
the
relative
particle
size
of
any
directly
emitted
particulate
matter
(
i.
e.
PM10
vs.
PM2.5).

3.
What
Kind
of
Modeling
Should
I
Use
to
Determine
Which
Sources
and
Pollutants
Need
Not
Be
Subject
to
BART?

This
section
presents
several
options
for
determining
that
certain
sources
need
not
be
subject
to
BART.
These
options
rely
on
different
modeling
and/
or
emissions
analysis
approaches.
They
are
provided
for
your
guidance.
You
may
also
use
other
reasonable
approaches
for
analyzing
the
visibility
impacts
of
an
individual
source
or
group
of
sources.

Option
1:
Individual
Source
Attribution
Approach
(
Dispersion
Modeling)

You
can
use
dispersion
modeling
to
determine
that
an
individual
source
cannot
reasonably
be
anticipated
to
cause
or
contribute
to
visibility
impairment
in
a
Class
I
area
and
thus
is
not
subject
to
BART.
Under
this
option,
you
can
analyze
an
individual
source's
impact
on
visibility
as
a
result
of
its
emissions
of
SO2,
NOx
and
direct
PM
emissions.
Dispersion
modeling
cannot
currently
be
used
to
estimate
the
predicted
7
The
model
code
and
its
documentation
are
available
at
no
cost
for
download
from
http://
www.
epa.
gov/
scram001/
tt22.
htm#
calpuff.

8
The
Guideline
on
Air
Quality
Models
addresses
the
regulatory
application
of
air
quality
models
for
assessing
criteria
pollutants
under
the
CAA,
and
describes
further
the
procedures
for
using
the
CALPUFF
model,
as
well
as
for
obtaining
approval
for
the
use
of
other,
nonguideline
models.

45
impacts
on
visibility
from
an
individual
source's
emissions
of
VOC
or
ammonia.
You
may
use
a
more
qualitative
assessment
to
determine
on
a
case­
by­
case
basis
which
sources
of
VOC
or
ammonia
emissions
may
be
likely
to
impair
visibility
and
should
therefore
be
subject
to
BART
review,
as
explained
in
section
II.
A.
3.
above.

You
can
use
CALPUFF7,
or
another
EPA
approved
model,
to
predict
the
visibility
impacts
from
a
single
source
at
a
Class
I
area.
CALPUFF
is
the
best
regulatory
modeling
application
currently
available
for
predicting
a
single
source's
contribution
to
visibility
impairment
and
is
currently
the
only
EPA­
approved
model
for
use
in
estimating
single
source
pollutant
concentrations
resulting
from
the
long
range
transport
of
primary
pollutants.
8
It
can
also
be
used
for
some
other
purposes,
such
as
the
visibility
assessments
addressed
in
today's
rule,
to
account
for
the
chemical
transformation
of
SO2
and
NOx.

There
are
several
steps
for
making
an
individual
source
attribution
using
a
dispersion
model:

1.
Develop
a
modeling
protocol.
9
Interagency
Workgroup
on
Air
Quality
Modelig
(
IWAQM)
Phase
2
Summary
Report
and
Recommendations
for
Modeling
Long
Range
Transport
Impacts,
U.
S.
Environmental
Protection
Agency,
EPA­
454/
R­
98­
019,
December
1998.

46
Some
critical
items
to
include
in
the
protocol
are
the
meteorological
and
terrain
data
that
will
be
used,
as
well
as
the
source­
specific
information
(
stack
height,
temperature,
exit
velocity,
elevation,
and
emission
rates
of
applicable
pollutants)

and
receptor
data
from
appropriate
Class
I
areas.
We
recommend
following
EPA's
Interagency
Workgroup
on
Air
Quality
Modeling
(
IWAQM)
Phase
2
Summary
Report
and
Recommendations
for
Modeling
Long
Range
Transport
Impacts9
for
parameter
settings
and
meteorological
data
inputs.
You
may
use
other
settings
from
those
in
IWAQM,
but
you
should
identify
these
settings
and
explain
your
selection
of
these
settings.

One
important
element
of
the
protocol
is
in
establishing
the
receptors
that
will
be
used
in
the
model.
The
receptors
that
you
use
should
be
located
in
the
nearest
Class
I
area
with
sufficient
density
to
identify
the
likely
visibility
effects
of
the
source.

For
other
Class
I
areas
in
relatively
close
proximity
to
a
BARTeligible
source,
you
may
model
a
few
strategic
receptors
to
determine
whether
effects
at
those
areas
may
be
greater
than
at
the
nearest
Class
I
area.
For
example,
you
might
chose
to
locate
receptors
at
these
areas
at
the
closest
point
to
the
source,
at
the
highest
and
lowest
elevation
in
the
Class
I
area,
at
the
47
IMPROVE
monitor,
and
at
the
approximate
expected
plume
release
height.
If
the
highest
modeled
effects
are
observed
at
the
nearest
Class
I
area,
you
may
choose
not
to
analyze
the
other
Class
I
areas
any
further,
as
additional
analyses
might
be
unwarranted.

You
should
bear
in
mind
that
some
receptors
within
the
relevant
Class
I
area
may
be
less
than
50
km
from
the
source
while
other
receptors
within
that
same
Class
I
area
may
be
greater
than
50
km
from
the
same
source.
As
indicated
by
the
Guideline
on
Air
Quality
Models,
this
situation
may
call
for
the
use
of
two
different
modeling
approaches
for
the
same
Class
I
area
and
source,
depending
upon
the
State's
chosen
method
for
modeling
sources
less
than
50
km.
In
situations
where
you
are
assessing
visibility
impacts
for
source­
receptor
distances
less
than
50
km,
you
should
use
expert
modeling
judgment
in
determining
visibility
impacts,
giving
consideration
to
both
CALPUFF
and
other
EPA­
approved
methods.

In
developing
your
modeling
protocol,
you
may
want
to
consult
with
EPA
and
your
regional
planning
organization
(
RPO).

Up­
front
consultation
will
ensure
that
key
technical
issues
are
addressed
before
you
conduct
your
modeling.

2.
Run
the
model
in
accordance
with
the
accepted
protocol
and
compare
the
predicted
visibility
impacts
with
your
threshold
for
"
contribution."
48
You
should
calculate
daily
visibility
values
for
each
receptor
as
the
change
in
deciviews
compared
against
natural
visibility
conditions.
You
can
use
EPA's
"
Guidance
for
Estimating
Natural
Visibility
Conditions
Under
the
Regional
Haze
Rule,"
EPA­
454/
B­
03­
005
(
September
2003)
in
making
this
calculation.
To
determine
whether
a
source
may
reasonably
be
anticipated
to
cause
or
contribute
to
visibility
impairment
at
Class
I
area,
you
then
compare
the
impacts
predicted
by
the
model
against
the
threshold
that
you
have
selected.

The
emissions
estimates
used
in
the
models
are
intended
to
reflect
steady­
state
operating
conditions
during
periods
of
high
capacity
utilization.
We
do
not
generally
recommend
that
emissions
reflecting
periods
of
start­
up,
shutdown,
and
malfunction
be
used,
as
such
emission
rates
could
produce
higher
than
normal
effects
than
would
be
typical
of
most
facilities.
In
addition,
the
monthly
average
relative
humidity
is
used,
rather
than
the
daily
average
humidity
 
an
approach
that
effectively
lowers
the
peak
values
in
daily
model
averages.

For
these
reasons,
if
you
use
the
modeling
approach
we
recommend,
you
should
compare
your
"
contribution"
threshold
against
the
98th
percentile
of
values.
If
the
98th
percentile
value
from
your
modeling
is
less
than
your
contribution
threshold,
then
you
may
conclude
that
the
source
does
not
contribute
to
visibility
impairment
and
is
not
subject
to
BART.
49
Option
2:
Use
of
Model
Plants
to
Exempt
Individual
Sources
with
Common
Characteristics.

Under
this
option,
analysis
of
model
plants
could
be
used
to
exempt
certain
BART­
eligible
sources
that
share
specific
characteristics.
It
may
be
most
useful
to
use
this
type
of
analysis
to
identify
the
types
of
small
sources
that
do
not
cause
or
contribute
to
visibility
impairment
for
purposes
of
BART,
and
thus
should
not
be
subject
to
a
BART
review.
Different
Class
I
areas
may
have
different
characteristics,
however,
so
you
should
use
care
to
ensure
that
the
criteria
you
develop
are
appropriate
for
the
applicable
cases.

In
carrying
out
this
approach,
you
could
use
modeling
analyses
of
representative
plants
to
reflect
groupings
of
specific
sources
with
important
common
characteristics.
Based
on
these
analyses,
you
may
find
that
certain
types
of
sources
are
clearly
anticipated
to
cause
or
contribute
to
visibility
impairment.
You
could
then
choose
to
categorically
require
those
types
of
sources
to
undergo
a
BART
determination.
Conversely,

you
may
find
based
on
representative
plant
analyses
that
certain
types
of
sources
are
not
reasonably
anticipated
to
cause
or
contribute
to
visibility
impairment.
To
do
this,
you
may
conduct
your
own
modeling
to
establish
emission
levels
and
distances
from
Class
I
areas
on
which
you
can
rely
to
exempt
sources
with
those
characteristics.
For
example,
based
on
your
modeling
you
might
10
[
insert
reference
to
Mark's
docket
memo]

50
choose
to
exempt
all
NOx­
only
sources
that
emit
less
than
a
certain
amount
per
year
and
are
located
a
certain
distance
from
a
Class
I
area.
You
could
then
choose
to
categorically
exempt
such
sources
from
the
BART
determination
process.

Our
analyses
of
visibility
impacts
from
model
plants
provide
a
useful
example
of
the
type
of
analyses
that
can
be
used
to
exempt
categories
of
sources
from
BART.
10
In
our
analysis,
we
developed
model
plants
(
EGUs
and
non­
EGUs),
with
representative
plume
and
stack
characteristics,
for
use
in
considering
the
visibility
impact
from
emission
sources
of
different
sizes
and
compositions
at
distances
of
50,
100
and
200
kilometers
from
two
hypothetical
Class
I
areas
(
one
in
the
East
and
one
in
the
West).

Since
the
plume
and
stack
characteristics
of
these
model
plants
were
developed
considering
the
broad
range
of
sources
within
the
EGU
and
non­
EGU
categories,
they
do
not
necessarily
represent
any
specific
plant.
However,
the
results
of
these
analyses
are
instructive
in
the
development
of
an
exemption
process
for
any
Class
I
area.

In
preparing
our
analysis,
we
have
made
a
number
of
assumptions
and
exercised
certain
modeling
choices;
some
of
these
have
a
tendency
to
lend
conservatism
to
the
results,
overstating
the
likely
effects,
while
others
may
understate
the
likely
effects.
On
balance,
when
all
of
these
factors
are
considered,
51
we
believe
that
our
examples
reflect
realistic
treatments
of
the
situations
being
modeled.
Based
on
our
analysis,
we
believe
that
a
State
that
has
established
0.5
deciviews
as
a
contribution
threshold
could
reasonably
exempt
from
the
BART
review
process
sources
that
emit
less
than
500
tons
per
year
of
Nox
or
SO2
(
or
combined
Nox
and
SO2),
as
long
as
these
sources
are
located
more
than
50
kilometers
from
any
Class
I
area;
and
sources
that
emit
less
than
1000
tons
per
year
of
Nox
or
SO2
(
or
combined
Nox
and
SO2)
that
are
located
more
than
100
kilometers
from
any
Class
I
area.
You,
however,
have
the
option
of
showing
other
thresholds
might
also
be
appropriate
fiven
your
specific
circumstances.

Option
3:
Cumulative
Modeling
to
Show
that
No
sources
in
a
State
are
subject
to
BART
You
may
also
submit
to
EPA
a
demonstration,
based
on
an
analysis
of
overall
visibility
impacts,
that
emissions
from
BART­
eligible
sources
in
your
State,
considered
together,
are
not
reasonably
anticipated
to
cause
or
contribute
to
any
visibility
impairment
in
a
Class
I
area
and
thus
no
source
should
be
subject
to
BART.
You
may
do
this
on
a
pollutant
by
pollutant
basis
or
for
all
visibility­
impairing
pollutants
to
determine
if
emissions
from
these
sources
contribute
to
visibility
impairment.

For
example,
emissions
of
SO2
from
your
BART­
eligible
sources
may
clearly
cause
or
contribute
to
visibility
impairment,
while
direct
emissions
of
PM2.5
from
these
sources
may
not
contribute
to
52
impairment.
If
you
can
make
such
a
demonstration,
then
you
may
reasonably
conclude
that
none
of
your
BART­
eligible
sources
are
subject
to
BART
for
a
particular
pollutant
or
pollutants.
As
noted
above,
your
demonstration
should
take
into
account
the
interactions
among
pollutants
and
their
resulting
impacts
on
visibility
before
making
any
pollutant­
specific
determinations.

Analyses
may
be
conducted
using
several
alternative
modeling
approaches.
First,
you
may
use
the
CALPUFF
or
another
EPAapproved
model
as
described
in
Option
1
to
evaluate
the
impacts
of
individual
sources
on
downwind
Class
I
areas,
aggregating
those
impacts
to
determine
the
collective
contribution
of
all
BART­
eligible
sources
to
visibility
impairment.
You
may
also
use
a
photochemical
grid
model.
As
a
general
matter,
the
larger
the
number
of
sources
being
modeled,
the
more
appropriate
it
may
be
to
use
a
photochemical
grid
model.
However,
because
such
models
are
significantly
less
sensitive
than
dispersion
models
to
the
contributions
of
one
or
a
few
sources,
as
well
as
to
the
interactions
among
sources
that
are
widely
distributed
geographically,
if
you
wish
to
use
a
grid
model,
you
should
consult
with
the
appropriate
EPA
Regional
Office
to
develop
an
appropriate
modeling
protocol.

IV.
THE
BART
DETERMINATION:
ANALYSIS
OF
BART
OPTIONS
This
section
describes
the
process
for
the
analysis
of
control
options
for
sources
subject
to
BART.
53
A.
What
Factors
Must
I
Address
in
the
BART
review?

The
visibility
regulations
define
BART
as
follows:

Best
Available
Retrofit
Technology
(
BART)
means
an
emission
limitation
based
on
the
degree
of
reduction
achievable
through
the
application
of
the
best
system
of
continuous
emission
reduction
for
each
pollutant
which
is
emitted
by...
[
a
BART
­
eligible
source].
The
emission
limitation
must
be
established,
on
a
case­

bycase
basis,
taking
into
consideration
the
technology
available,
the
costs
of
compliance,
the
energy
and
nonair
quality
environmental
impacts
of
compliance,
any
pollution
control
equipment
in
use
or
in
existence
at
the
source,
the
remaining
useful
life
of
the
source,

and
the
degree
of
improvement
in
visibility
which
may
reasonably
be
anticipated
to
result
from
the
use
of
such
technology.

The
BART
analysis
identifies
the
best
system
of
continuous
emission
reduction
taking
into
account:

(
1)
the
available
retrofit
control
options,

(
2)
any
pollution
control
equipment
in
use
at
the
source
(
which
affects
the
availability
of
options
and
their
impacts),

(
3)
the
costs
of
compliance
with
control
options,

(
4)
the
remaining
useful
life
of
the
facility
,
11
That
is,
emission
units
that
were
in
existence
on
August
7,
1977
and
which
began
actual
operation
on
or
after
August
7,
1962.

54
(
5)
the
energy
and
non­
air
quality
environmental
impacts
of
control
options
(
6)
the
visibility
impacts
analysis.

B.
What
is
the
Scope
of
the
BART
Review?

Once
you
determine
that
a
source
is
subject
to
BART
for
a
particular
pollutant,
then
for
each
affected
emission
unit,
you
must
establish
BART
for
that
pollutant.
The
BART
determination
must
address
air
pollution
control
measures
for
each
emissions
unit
or
pollutant
emitting
activity
subject
to
review.

Example:
Plantwide
emissions
from
emission
units
within
the
listed
categories
that
began
operation
within
the
"
time
window"
for
BART11
are
300
tons/
yr
of
NOx,
200
tons/
yr
of
SO2,

and
150
tons/
yr
of
primary
particulate.
Emissions
unit
A
emits
200
tons/
yr
of
NOx,
100
tons/
yr
of
SO2,
and
100
tons/
yr
of
primary
particulate.
Other
emission
units,
units
B
through
H,
which
began
operating
in
1966,
contribute
lesser
amounts
of
each
pollutant.
For
this
example,
a
BART
review
is
required
for
NOx,
SO2,
and
primary
particulate,
and
control
options
must
be
analyzed
for
units
B
through
H
as
well
as
unit
A.

C.
How
Does
a
BART
Review
Relate
to
Maximum
Achievable
Control
Technology
(
MACT)
Standards
Under
CAA
Section
112,
or
to
55
Other
Emission
Limitations
Required
under
the
CAA?

For
VOC
and
PM
sources
subject
to
MACT
standards,
States
may
streamline
the
analysis
by
including
a
discussion
of
the
MACT
controls
and
whether
any
major
new
technologies
have
been
developed
subsequent
to
the
MACT
standards.
We
believe
that
there
are
many
VOC
and
PM
sources
that
are
well
controlled
because
they
are
regulated
by
the
MACT
standards,
which
EPA
developed
under
CAA
section
112.
For
a
few
MACT
standards,
this
may
also
be
true
for
SO2.
Any
source
subject
to
MACT
standards
must
meet
a
level
that
is
as
stringent
as
the
best­
controlled
12
percent
of
sources
in
the
industry.
Examples
of
these
hazardous
air
pollutant
sources
which
effectively
control
VOC
and
PM
emissions
include
(
among
others)
secondary
lead
facilities,

organic
chemical
plants
subject
to
the
hazardous
organic
NESHAP
(
HON),
pharmaceutical
production
facilities,
and
equipment
leaks
and
wastewater
operations
at
petroleum
refineries.
We
believe
that,
in
many
cases,
it
will
be
unlikely
that
States
will
identify
emission
controls
more
stringent
than
the
MACT
standards
without
identifying
control
options
that
would
cost
many
thousands
of
dollars
per
ton.
Unless
there
are
new
technologies
subsequent
to
the
MACT
standards
which
would
lead
to
costeffective
increases
in
the
level
of
control,
you
may
rely
on
the
MACT
standards
for
purposes
of
BART.

We
believe
that
the
same
rationale
also
holds
true
for
12
In
identifying
"
all"
options,
you
must
identify
the
most
stringent
option
and
a
reasonable
set
of
options
for
analysis
that
reflects
a
comprehensive
list
of
available
technologies.
It
is
not
necessary
to
list
all
permutations
of
available
control
levels
that
exist
for
a
given
technology
 
­
the
list
is
complete
if
it
includes
the
maximum
level
of
control
each
technology
is
capable
of
achieving.

56
emissions
standards
developed
for
municipal
waste
incinerators
under
CAA
section
111(
d),
and
for
many
NSR/
PSD
determinations
and
NSR/
PSD
settlement
agreements.
However,
we
do
not
believe
that
technology
determinations
from
the
1970s
or
early
1980s,

including
new
source
performance
standards
(
NSPS),
should
be
considered
to
represent
best
control
for
existing
sources,
as
best
control
levels
for
recent
plant
retrofits
are
more
stringent
than
these
older
levels.

Where
you
are
relying
on
these
standards
to
represent
a
BART
level
of
control,
you
should
provide
the
public
with
a
discussion
of
whether
any
new
technologies
have
subsequently
become
available..

D.
What
are
the
Five
Basic
Steps
of
a
Case­
by­
Case
BART
Analysis?

The
five
steps
are:

STEP
1
­­
Identify
All12
Available
Retrofit
Control
Technologies,

STEP
2­­
Eliminate
Technically
Infeasible
Options,

STEP
3­­
Evaluate
Control
Effectiveness
of
Remaining
57
Control
Technologies,

STEP
4­­
Evaluate
Impacts
and
Document
the
Results,
and
STEP
5
 
Evaluate
Visibility
Impacts.

1.
STEP
1:
How
do
I
identify
all
available
retrofit
emission
control
techniques?

1.
Available
retrofit
control
options
are
those
air
pollution
control
technologies
with
a
practical
potential
for
application
to
the
emissions
unit
and
the
regulated
pollutant
under
evaluation.
Air
pollution
control
technologies
can
include
a
wide
variety
of
available
methods,
systems,
and
techniques
for
control
of
the
affected
pollutant.
Technologies
required
as
BACT
or
LAER
are
available
for
BART
purposes
and
must
be
included
as
control
alternatives.
The
control
alternatives
can
include
not
only
existing
controls
for
the
source
category
in
question,
but
also
take
into
account
technology
transfer
of
controls
that
have
been
applied
to
similar
source
categories
and
gas
streams.

Technologies
which
have
not
yet
been
applied
to
(
or
permitted
for)
full
scale
operations
need
not
be
considered
as
available;

we
do
not
expect
the
source
owner
to
purchase
or
construct
a
process
or
control
device
that
has
not
already
been
demonstrated
in
practice.

2.
Where
a
NSPS
exists
for
a
source
category
(
which
is
the
case
for
most
of
the
categories
affected
by
BART),
you
should
include
a
level
of
control
equivalent
to
the
NSPS
as
one
of
the
control
13
In
EPA's
1980
BART
guidelines
for
reasonably
attributable
visibility
impairment,
we
concluded
that
NSPS
standards
generally,
at
that
time,
represented
the
best
level
sources
could
install
as
BART.
In
the
20
year
period
since
this
guidance
was
developed,
there
have
been
advances
in
SO2
control
technologies
as
well
as
technologies
for
the
control
of
other
pollutants,
confirmed
by
a
number
of
recent
retrofits
at
Western
power
plants.
Accordingly,
EPA
no
longer
concludes
that
the
NSPS
level
of
controls
automatically
represents
"
the
best
these
sources
can
install."
Analysis
of
the
BART
factors
could
result
in
the
selection
of
a
NSPS
level
of
control,
you
should
reach
this
conclusion
only
after
considering
the
full
range
of
control
options.

58
options.
13
The
NSPS
standards
are
codified
in
40
CFR
part
60.
We
note
that
there
are
situations
where
NSPS
standards
do
not
require
the
most
stringent
level
of
available
control
for
all
sources
within
a
category.
For
example,
post­
combustion
NOx
controls
(
the
most
stringent
controls
for
stationary
gas
turbines)
are
not
required
under
subpart
GG
of
the
NSPS
for
Stationary
Gas
Turbines.
However,
such
controls
must
still
be
considered
available
technologies
for
the
BART
selection
process.

3.
Potentially
applicable
retrofit
control
alternatives
can
be
categorized
in
three
ways.

!
Pollution
prevention:
use
of
inherently
lower­
emitting
processes/
practices,
including
the
use
of
control
techniques
(
e.
g.
low­
NOx
burners)
and
work
practices
that
prevent
emissions
and
result
in
lower
"
production­
specific"
emissions
(
note
that
it
is
not
our
intent
to
direct
States
to
switch
fuel
forms,
e.
g.
59
from
coal
to
gas),

!
Use
of
(
and
where
already
in
place,
improvement
in
the
performance
of)
add­
on
controls,
such
as
scrubbers,

fabric
filters,
thermal
oxidizers
and
other
devices
that
control
and
reduce
emissions
after
they
are
produced,
and
!
Combinations
of
inherently
lower­
emitting
processes
and
add­
on
controls.

4.
In
the
course
of
the
BART
review,
one
or
more
of
the
available
control
options
may
be
eliminated
from
consideration
because
they
are
demonstrated
to
be
technically
infeasible
or
to
have
unacceptable
energy,
cost,
or
non­
air
quality
environmental
impacts
on
a
case­
by­
case
(
or
site­
specific)
basis.
However,
at
the
outset,
you
should
initially
identify
all
control
options
with
potential
application
to
the
emissions
unit
under
review.

5.
We
do
not
consider
BART
as
a
requirement
to
redesign
the
source
when
considering
available
control
alternatives.
For
example,
where
the
source
subject
to
BART
is
a
coal­
fired
electric
generator,
we
do
not
require
the
BART
analysis
to
consider
building
a
natural
gas­
fired
electric
turbine
although
the
turbine
may
be
inherently
less
polluting
on
a
per
unit
basis.

6.
For
emission
units
subject
to
a
BART
review,
there
will
often
be
control
measures
or
devices
already
in
place.
For
such
emission
units,
it
is
important
to
include
control
options
that
60
involve
improvements
to
existing
controls,
and
not
to
limit
the
control
options
only
to
those
measures
that
involve
a
complete
replacement
of
control
devices.

Example:
For
a
power
plant
with
an
existing
wet
scrubber,

the
current
control
efficiency
is
66
percent.

Part
of
the
reason
for
the
relatively
low
control
efficiency
is
that
22
percent
of
the
gas
stream
bypasses
the
scrubber.
A
BART
review
identifies
options
for
improving
the
performance
of
the
wet
scrubber
by
redesigning
the
internal
components
of
the
scrubber
and
by
eliminating
or
reducing
the
percentage
of
the
gas
stream
that
bypasses
the
scrubber.
Four
control
options
are
identified:

(
1)
78
percent
control
based
upon
improved
scrubber
performance
while
maintaining
the
22
percent
bypass,
(
2)
83
percent
control
based
upon
improved
scrubber
performance
while
reducing
the
bypass
to
15
percent,
(
3)
93
percent
control
based
upon
improving
the
scrubber
performance
while
eliminating
the
bypass
entirely,
(
this
option
results
in
a
"
wet
stack"
operation
in
which
the
gas
leaving
the
stack
is
saturated
with
water)
and
(
4)
93
percent
as
in
option
3,
with
the
addition
of
an
indirect
reheat
system
to
reheat
the
stack
61
gas
above
the
saturation
temperature.
You
must
consider
each
of
these
four
options
in
a
BART
analysis
for
this
source.

7.
You
are
expected
to
identify
potentially
applicable
retrofit
control
technologies
that
represent
the
full
range
of
demonstrated
alternatives.
Examples
of
general
information
sources
to
consider
include:

!
The
EPA's
Clean
Air
Technology
Center,
which
includes
the
RACT/
BACT/
LAER
Clearinghouse
(
RBLC);

!
State
and
Local
Best
Available
Control
Technology
Guidelines
­
many
agencies
have
online
information
 
for
example
South
Coast
Air
Quality
Management
District,

Bay
Area
Air
Quality
Management
District,
and
Texas
Natural
Resources
Conservation
Commission;

!
Control
technology
vendors;

!
Federal/
State/
Local
NSR
permits
and
associated
inspection/
performance
test
reports;

!
Environmental
consultants;

!
Technical
journals,
reports
and
newsletters,
air
pollution
control
seminars;
and
!
The
EPA's
NSR
bulletin
board­­

http://
www.
epa.
gov/
ttn/
nsr;

!
Department
of
Energy's
Clean
Coal
Program
­­
technical
reports;
62
!
The
NOx
Control
Technology
"
Cost
Tool"
­
Clean
Air
Markets
Division
web
page
­­

http://
www.
epa.
gov/
airmarkets/
arp/
nox/
controltech.
html;

!
Performance
of
selective
catalytic
reduction
on
coalfired
steam
generating
units
­
final
report.
OAR/
ARD,

June
1997
(
also
available
at
http://
www.
epa.
gov/
airmarkets/
arp/
nox/
controltech.
html)

;

!
Cost
estimates
for
selected
applications
of
NOx
control
technologies
on
stationary
combustion
boilers.
OAR/
ARD
June
1997.
(
Docket
for
NOx
SIP
Call,
A­
96­
56,
item
IIA
03);

!
Investigation
of
performance
and
cost
of
NOx
controls
as
applied
to
group
2
boilers.
OAR/
ARD,
August
1996.

(
Docket
for
Phase
II
NOX
rule,
A­
95­
28,
item
IV­
A­
4);

!
Controlling
SO2
Emissions:
A
Review
of
Technologies.

EPA­
600/
R­
00­
093,
USEPA/
ORD/
NRMRL,
October
2000;
and
!
The
OAQPS
Control
Cost
Manual.

You
are
expected
to
compile
appropriate
information
fromthese
information
sources.

8.
There
may
be
situations
where
a
specific
set
of
units
within
a
fenceline
constitutes
the
logical
set
to
which
controls
would
apply,
and
that
set
of
units
may
or
may
not
all
be
BART­
eligible.

(
For
example,
some
units
in
that
set
may
not
have
been
63
constructed
between
1962
and
1977.)

9.
If
you
find
that
a
BART
source
has
controls
already
in
place
which
are
the
most
stringent
controls
available
(
note
that
this
means
that
all
possible
improvements
to
any
control
devices
have
been
made),
then
it
is
not
necessary
to
comprehensively
complete
each
following
step
of
the
BART
analysis
in
this
section.
As
long
these
most
stringent
controls
available
are
made
federally
enforceable
for
the
purpose
of
implementing
BART
for
that
source,

you
may
skip
the
remaining
analyses
in
this
section,
including
the
visibility
analysis
in
step
5.
Likewise,
if
a
source
commits
to
a
BART
determination
that
consists
of
the
most
stringent
controls
available,
then
there
is
no
need
to
complete
the
remaining
analyses
in
this
section.

2.
STEP
2:
How
do
I
determine
whether
the
options
identified
in
Step
1
are
technically
feasible?

In
Step
2,
you
evaluate
the
technical
feasibility
of
the
control
options
you
identified
in
Step
1.
You
should
document
a
demonstration
of
technical
infeasibility
and
should
explain,

based
on
physical,
chemical,
or
engineering
principles,
why
technical
difficulties
would
preclude
the
successful
use
of
the
control
option
on
the
emissions
unit
under
review.
You
may
then
eliminate
such
technically
infeasible
control
options
from
further
consideration
in
the
BART
analysis.

In
general,
what
do
we
mean
by
technical
feasibility?
64
Control
technologies
are
technically
feasible
if
either
(
1)
they
have
been
installed
and
operated
successfully
for
the
type
of
source
under
review
under
similar
conditions,
or
(
2)
the
technology
could
be
applied
to
the
source
under
review.
Two
key
concepts
are
important
in
determining
whether
a
technology
could
be
applied:
"
availability"
and
"
applicability."
As
explained
in
more
detail
below,
a
technology
is
considered
"
available"
if
the
source
owner
may
obtain
it
through
commercial
channels,
or
it
is
otherwise
available
within
the
common
sense
meaning
of
the
term.
An
available
technology
is
"
applicable"
if
it
can
reasonably
be
installed
and
operated
on
the
source
type
under
consideration.
A
technology
that
is
available
and
applicable
is
technically
feasible.

What
do
we
mean
by
"
available"
technology?

1.
The
typical
stages
for
bringing
a
control
technology
concept
to
reality
as
a
commercial
product
are:

!
concept
stage;

!
research
and
patenting;

!
bench
scale
or
laboratory
testing;

!
pilot
scale
testing;

!
licensing
and
commercial
demonstration;
and
!
commercial
sales.

2.
A
control
technique
is
considered
available,
within
the
65
context
presented
above,
if
it
has
reached
the
stage
of
licensing
and
commercial
availability.
Similarly,
we
do
not
expect
a
source
owner
to
conduct
extended
trials
to
learn
how
to
apply
a
technology
on
a
totally
new
and
dissimilar
source
type.
Consequently,
you
would
not
consider
technologies
in
the
pilot
scale
testing
stages
of
development
as
"
available"
for
purposes
of
BART
review.

3.
Commercial
availability
by
itself,
however,
is
not
necessarily
a
sufficient
basis
for
concluding
a
technology
to
be
applicable
and
therefore
technically
feasible.

Technical
feasibility,
as
determined
in
Step
2,
also
means
a
control
option
may
reasonably
be
deployed
on
or
"
applicable"

to
the
source
type
under
consideration.

Because
a
new
technology
may
become
available
at
various
points
in
time
during
the
BART
analysis
process,
we
believe
that
guidelines
are
needed
on
when
a
technology
must
be
considered.
For
example,
a
technology
may
become
available
during
the
public
comment
period
on
the
State's
rule
development
process.
Likewise,
it
is
possible
that
new
technologies
may
become
available
after
the
close
of
the
State's
public
comment
period
and
before
submittal
of
the
SIP
to
EPA,
or
during
EPA's
review
process
on
the
SIP
submittal.
In
order
to
provide
certainty
in
the
process,

all
technologies
should
be
considered
if
available
before
66
the
close
of
the
State's
public
comment
period.
You
need
not
consider
technologies
that
become
available
after
this
date.
As
part
of
your
analysis,
you
should
consider
any
technologies
brought
to
your
attention
in
public
comments.

If
you
disagree
with
public
comments
asserting
that
the
technology
is
available,
you
should
provide
an
explanation
for
the
public
record
as
to
the
basis
for
your
conclusion.

What
do
we
mean
by
"
applicable"
technology?

You
need
to
exercise
technical
judgment
in
determining
whether
a
control
alternative
is
applicable
to
the
source
type
under
consideration.
In
general,
a
commercially
available
control
option
will
be
presumed
applicable
if
it
has
been
used
on
the
same
or
a
similar
source
type.
Absent
a
showing
of
this
type,
you
evaluate
technical
feasibility
by
examining
the
physical
and
chemical
characteristics
of
the
pollutant­
bearing
gas
stream,
and
comparing
them
to
the
gas
stream
characteristics
of
the
source
types
to
which
the
technology
had
been
applied
previously.
Deployment
of
the
control
technology
on
a
new
or
existing
source
with
similar
gas
stream
characteristics
is
generally
a
sufficient
basis
for
concluding
the
technology
is
technically
feasible
barring
a
demonstration
to
the
contrary
as
described
below.

What
type
of
demonstration
is
required
if
I
conclude
that
an
option
is
not
technically
feasible?
67
1.
Where
you
conclude
that
a
control
option
identified
in
Step
1
is
technically
infeasible,
you
should
demonstrate
that
the
option
is
either
commercially
unavailable,
or
that
specific
circumstances
preclude
its
application
to
a
particular
emission
unit.
Generally,
such
a
demonstration
involves
an
evaluation
of
the
characteristics
of
the
pollutant­
bearing
gas
stream
and
the
capabilities
of
the
technology.
Alternatively,
a
demonstration
of
technical
infeasibility
may
involve
a
showing
that
there
are
unresolvable
technical
difficulties
with
applying
the
control
to
the
source
(
e.
g.,
size
of
the
unit,
location
of
the
proposed
site,
operating
problems
related
to
specific
circumstances
of
the
source,
space
constraints,
reliability,

and
adverse
side
effects
on
the
rest
of
the
facility).

Where
the
resolution
of
technical
difficulties
is
merely
a
matter
of
increased
cost,
you
should
consider
the
technology
to
be
technically
feasible.
The
cost
of
a
control
alternative
is
considered
later
in
the
process.

2.
The
determination
of
technical
feasibility
is
sometimes
influenced
by
recent
air
quality
permits.
In
some
cases,
an
air
quality
permit
may
require
a
certain
level
of
control,

but
the
level
of
control
in
a
permit
is
not
expected
to
be
achieved
in
practice
(
e.
g.,
a
source
has
received
a
permit
but
the
project
was
canceled,
or
every
operating
source
at
68
that
permitted
level
has
been
physically
unable
to
achieve
compliance
with
the
limit).
Where
this
is
the
case,
you
should
provide
supporting
documentation
showing
why
such
limits
are
not
technically
feasible,
and,
therefore,
why
the
level
of
control
(
but
not
necessarily
the
technology)
may
be
eliminated
from
further
consideration.
However,
if
there
is
a
permit
requiring
the
application
of
a
certain
technology
or
emission
limit
to
be
achieved
for
such
technology
,
this
usually
is
sufficient
justification
for
you
to
assume
the
technical
feasibility
of
that
technology
or
emission
limit.

3.
Physical
modifications
needed
to
resolve
technical
obstacles
do
not,
in
and
of
themselves,
provide
a
justification
for
eliminating
the
control
technique
on
the
basis
of
technical
infeasibility.
However,
you
may
consider
the
cost
of
such
modifications
in
estimating
costs.
This,

in
turn,
may
form
the
basis
for
eliminating
a
control
technology
(
see
later
discussion).

4.
Vendor
guarantees
may
provide
an
indication
of
commercial
availability
and
the
technical
feasibility
of
a
control
technique
and
could
contribute
to
a
determination
of
technical
feasibility
or
technical
infeasibility,
depending
on
circumstances.
However,
we
do
not
consider
a
vendor
guarantee
alone
to
be
sufficient
justification
that
a
control
option
will
work.
Conversely,
lack
of
a
vendor
69
guarantee
by
itself
does
not
present
sufficient
justification
that
a
control
option
or
an
emissions
limit
is
technically
infeasible.
Generally,
you
should
make
decisions
about
technical
feasibility
based
on
chemical,
and
engineering
analyses
(
as
discussed
above),
in
conjunction
with
information
about
vendor
guarantees.

5.
A
possible
outcome
of
the
BART
procedures
discussed
in
these
guidelines
is
the
evaluation
of
multiple
control
technology
alternatives
which
result
in
essentially
equivalent
emissions.
It
is
not
our
intent
to
encourage
evaluation
of
unnecessarily
large
numbers
of
control
alternatives
for
every
emissions
unit.
Consequently,
you
should
use
judgment
in
deciding
on
those
alternatives
for
which
you
will
conduct
the
detailed
impacts
analysis
(
Step
4
below).
For
example,
if
two
or
more
control
techniques
result
in
control
levels
that
are
essentially
identical,

considering
the
uncertainties
of
emissions
factors
and
other
parameters
pertinent
to
estimating
performance,
you
may
evaluate
only
the
less
costly
of
these
options.
You
should
narrow
the
scope
of
the
BART
analysis
in
this
way,
only
if
there
is
a
negligible
difference
in
emissions
and
energy
and
non­
air
quality
environmental
impacts
between
control
alternatives.

3.
STEP
3:
How
do
I
evaluate
technically
feasible
70
alternatives?

Step
3
involves
evaluating
the
control
effectiveness
ofall
the
technically
feasible
control
alternatives
identified
in
Step
2for
the
pollutant
and
emissions
unit
under
review.

Two
key
issues
in
this
process
include:

(
1)
Making
sure
that
you
express
the
degree
of
control
using
a
metric
that
ensures
an
"
apples
to
apples"
comparison
of
emissions
performance
levels
among
options,
and
(
2)
Giving
appropriate
treatment
and
consideration
of
control
techniques
that
can
operate
over
a
wide
range
of
emission
performance
levels.

What
are
the
appropriate
metrics
for
comparison?

This
issue
is
especially
important
when
you
compare
inherently
lower­
polluting
processes
to
one
another
or
to
add­
on
controls.
In
such
cases,
it
is
generally
most
effective
to
express
emissions
performance
as
an
average
steady
state
emissions
level
per
unit
of
product
produced
or
processed.

Examples
of
common
metrics:

!
pounds
of
SO2
emissions
per
million
Btu
heat
input,

and
!
pounds
of
NOx
emissions
per
ton
of
cement
produced.

How
do
I
evaluate
control
techniques
with
a
wide
range
of
emission
performance
levels?

1.
Many
control
techniques,
including
both
add­
on
controls
71
and
inherently
lower
polluting
processes,
can
perform
at
a
wide
range
of
levels.
Scrubbers
and
high
and
low
efficiency
electrostatic
precipitators
(
ESPs)
are
two
of
the
many
examples
of
such
control
techniques
that
can
perform
at
a
wide
range
of
levels.
It
is
not
our
intent
to
require
analysis
of
each
possible
level
of
efficiency
for
a
control
technique,
as
such
an
analysis
would
result
in
a
large
number
of
options.
It
is
important,
however,
that
in
analyzing
the
technology
you
take
into
account
the
most
stringent
emission
control
level
that
the
technology
is
capable
of
achieving.
You
should
consider
recent
regulatory
decisions
and
performance
data
(
e.
g.,
manufacturer's
data,

engineering
estimates
and
the
experience
of
other
sources)

when
identifying
an
emissions
performance
level
or
levels
to
evaluate.

2.
In
assessing
the
capability
of
the
control
alternative,

latitude
exists
to
consider
special
circumstances
pertinent
to
the
specific
source
under
review,
or
regarding
the
prior
application
of
the
control
alternative.
However,
you
should
explain
the
basis
for
choosing
the
alternate
level
(
or
range)
of
control
in
the
BART
analysis.
Without
a
showing
of
differences
between
the
source
and
other
sources
that
have
achieved
more
stringent
emissions
limits,
you
should
conclude
that
the
level
being
achieved
by
those
other
72
sources
is
representative
of
the
achievable
level
for
the
source
being
analyzed.

3.
You
may
encounter
cases
where
you
may
wish
to
evaluate
other
levels
of
control
in
addition
to
the
most
stringent
level
for
a
given
device.
While
you
must
consider
the
most
stringent
level
as
one
of
the
control
options,
you
may
consider
less
stringent
levels
of
control
as
additional
options.
This
would
be
useful,
particularly
in
cases
where
the
selection
of
additional
options
would
have
widely
varying
costs
and
other
impacts.

4.
Finally,
we
note
that
for
retrofitting
existing
sources
in
addressing
BART,
you
should
consider
ways
to
improve
the
performance
of
existing
control
devices,
particularly
when
a
control
device
is
not
achieving
the
level
of
control
that
other
similar
sources
are
achieving
in
practice
with
the
same
device.
For
example,
you
should
consider
requiring
those
sources
with
electrostatic
precipitators
(
ESPs)

performing
below
currently
achievable
levels
to
improve
their
performance.

4.
STEP
4:
For
a
BART
review,
what
impacts
am
I
expected
to
calculate
and
report?
What
methods
does
EPA
recommend
for
the
impacts
analysis?

After
you
identify
the
available
and
technically
feasible
control
technology
options,
you
are
expected
to
conduct
the
73
following
analyses
when
you
make
a
BART
determination:

Impact
analysis
part
1:
costs
of
compliance,

Impact
analysis
part
2:
energy
impacts,
and
Impact
analysis
part
3:
non­
air
quality
environmental
impacts.

Impact
analysis
part
4:
remaining
useful
life.

In
this
section,
we
describe
how
to
conduct
each
of
these
three
analyses.
You
are
responsible
for
presenting
an
evaluation
of
each
impact
along
with
appropriate
supporting
information.
You
should
discuss
and,
where
possible,
quantify
both
beneficial
and
adverse
impacts.
In
general,
the
analysis
should
focus
on
the
direct
impact
of
the
control
alternative.

a.
Impact
analysis
part
1:
How
do
I
estimate
the
costs
of
control?

1.
To
conduct
a
cost
analysis,
you:

(
1)
identify
the
emissions
units
being
controlled,

(
2)
identify
design
parameters
for
emission
controls,

and
(
3)
develop
cost
estimates
based
upon
those
design
parameters.

2.
It
is
important
to
identify
clearly
the
emission
units
being
controlled,
that
is,
to
specify
a
well­
defined
area
or
process
segment
within
the
plant.
In
some
cases,
multiple
emission
units
can
be
controlled
jointly.
However,
in
other
74
cases,
it
may
be
appropriate
in
the
cost
analysis
to
consider
whether
multiple
units
will
be
required
to
install
separate
and/
or
different
control
devices.
The
analysis
should
provide
a
clear
summary
list
of
equipment
and
the
associated
control
costs.
Inadequate
documentation
of
the
equipment
whose
emissions
are
being
controlled
is
a
potential
cause
for
confusion
in
comparison
of
costs
of
the
same
controls
applied
to
similar
sources.

3.
You
then
specify
the
control
system
design
parameters.

Potential
sources
of
these
design
parameters
include
equipment
vendors,
background
information
documents
used
to
support
NSPS
development,
control
technique
guidelines
documents,
cost
manuals
developed
by
EPA,
control
data
in
trade
publications,
and
engineering
and
performance
test
data.
The
following
are
a
few
examples
of
design
parameters
for
two
example
control
measures:
75
Control
Device
Examples
of
Design
Parameters
Wet
Scrubbers
Type
of
sorbent
used
(
lime,

limestone,
etc.)

Gas
pressure
drop
Liquid/
gas
ratio
Selective
Catalytic
Reduction
Ammonia
to
NOx
molar
ratio
Pressure
drop
Catalyst
life
4.
The
value
selected
for
the
design
parameter
should
ensure
that
the
control
option
will
achieve
the
level
of
emission
control
being
evaluated.
You
should
include
in
your
analysis
documentation
of
your
assumptions
regarding
design
parameters.
Examples
of
supporting
references
would
include
the
Office
of
Air
Quality
Planning
and
Standards
(
OAQPS)
Control
Cost
Manual
(
see
below)
and
background
information
documents
used
for
NSPS
and
hazardous
pollutant
emission
standards.
If
the
design
parameters
you
specified
differ
from
typical
designs,
you
should
document
the
difference
by
supplying
performance
test
data
for
the
14
The
Control
Cost
Manual
is
updated
periodically.
While
this
citation
refers
to
the
latest
version
at
the
time
this
guidance
was
written,
you
should
use
the
version
that
is
current
as
of
when
you
conduct
your
impact
analysis.
This
document
is
available
at
the
following
Web
site:
http://
www.
epa.
gov/
ttn/
catc/
dir1/
chpt2acr.
pdf
15
You
should
include
documentation
for
any
additional
information
you
used
for
the
cost
calculations,
including
any
information
supplied
by
vendors
that
affects
your
assumptions
regarding
purchased
equipment
costs,
equipment
life,
replacement
of
major
components,
and
any
other
element
of
the
calculation
that
differs
from
the
Control
Cost
Manual.

76
control
technology
in
question
applied
to
the
same
source
or
a
similar
source.

5.
Once
the
control
technology
alternatives
and
achievable
emissions
performance
levels
have
been
identified,
you
then
develop
estimates
of
capital
and
annual
costs.
The
basis
for
equipment
cost
estimates
also
should
be
documented,

either
with
data
supplied
by
an
equipment
vendor
(
i.
e.,

budget
estimates
or
bids)
or
by
a
referenced
source
(
such
as
the
OAQPS
Control
Cost
Manual,
Fifth
Edition,
February
1996,

EPA
453/
B­
96­
001).
14
In
order
to
maintain
and
improve
consistency,
cost
estimates
should
be
based
on
the
EPA/
OAQPS
Control
Cost
Manual,
where
possible.
15
The
Control
Cost
Manual
addresses
most
control
technologies
in
sufficient
detail
for
a
BART
analysis.
The
cost
analysis
should
also
take
into
account
any
site­
specific
design
or
other
conditions
identified
above
that
affect
the
cost
of
a
16
Whenever
you
calculate
or
report
annual
costs,
you
should
indicate
the
year
for
which
the
costs
are
estimated.
For
example,
if
you
use
the
year
2000
as
the
basis
for
cost
comparisons,
you
would
report
that
an
annualized
cost
of
$
20
million
would
be:
$
20
million
(
year
2000
dollars).

77
particular
BART
technology
option.

b.
What
do
we
mean
by
cost
effectiveness?

Cost
effectiveness,
in
general,
is
a
criterion
used
to
assess
the
potential
for
achieving
an
objective
in
the
most
economical
way.
For
purposes
of
air
pollutant
analysis,

"
effectiveness"
is
measured
in
terms
of
tons
of
pollutant
emissions
removed,
and
"
cost"
is
measured
in
terms
of
annualized
control
costs.
We
recommend
two
types
of
costeffectiveness
calculations
­­
average
cost
effectiveness,

and
incremental
cost
effectiveness.

c.
How
do
I
calculate
average
cost
effectiveness?

Average
cost
effectiveness
means
the
total
annualized
costs
of
control
divided
by
annual
emissions
reductions
(
the
difference
between
baseline
annual
emissions
and
the
estimate
of
emissions
after
controls),
using
the
following
formula:

Average
cost
effectiveness
(
dollars
per
ton
removed)
=

Control
option
annualized
cost16
Baseline
annual
emissions
­
Annual
emissions
with
Control
option
Because
you
calculate
costs
in
(
annualized)
dollars
per
78
year
($/
yr)
and
because
you
calculate
emissions
rates
in
tons
per
year
(
tons/
yr),
the
result
is
an
average
costeffectiveness
number
in
(
annualized)
dollars
per
ton
($/
ton)

of
pollutant
removed.

d.
How
do
I
calculate
baseline
emissions?

1.
The
baseline
emissions
rate
should
represent
a
realistic
depiction
of
anticipated
annual
emissions
for
the
source.
In
general,
for
the
existing
sources
subject
to
BART,
you
will
estimate
the
anticipated
annual
emissions
based
upon
actual
emissions
from
a
baseline
period.

2.
When
you
project
that
future
operating
parameters
(
e.
g.,
limited
hours
of
operation
or
capacity
utilization,

type
of
fuel,
raw
materials
or
product
mix
or
type)
will
differ
from
past
practice,
and
if
this
projection
has
a
deciding
effect
in
the
BART
determination,
then
you
must
make
these
parameters
or
assumptions
into
enforceable
limitations.
In
the
absence
of
enforceable
limitations,
you
calculate
baseline
emissions
based
upon
continuation
of
past
practice.

3.
For
example,
the
baseline
emissions
calculation
for
an
emergency
standby
generator
may
consider
the
fact
that
the
source
owner
would
not
operate
more
than
past
practice
of
2
weeks
a
year.
On
the
other
hand,
baseline
emissions
associated
with
a
base­
loaded
turbine
should
be
based
on
its
79
past
practice
which
would
indicate
a
large
number
of
hours
of
operation.
This
produces
a
significantly
higher
level
of
baseline
emissions
than
in
the
case
of
the
emergency/
standby
unit
and
results
in
more
cost­
effective
controls.
As
a
consequence
of
the
dissimilar
baseline
emissions,
BART
for
the
two
cases
could
be
very
different.

e.
How
do
I
calculate
incremental
cost
effectiveness?

1.
In
addition
to
the
average
cost
effectiveness
of
a
control
option,
you
should
also
calculate
incremental
cost
effectiveness.
You
should
consider
the
incremental
cost
effectiveness
in
combination
with
the
average
cost
effectiveness
when
considering
whether
to
eliminate
a
control
option.
The
incremental
cost
effectiveness
calculation
compares
the
costs
and
performance
level
of
a
control
option
to
those
of
the
next
most
stringent
option,
as
shown
in
the
following
formula
(
with
respect
80
to
cost
per
emissions
reduction):

Incremental
Cost
Effectiveness
(
dollars
per
incremental
ton
removed)

=

(
Total
annualized
costs
of
control
option)
­
(
Total
annualized
costs
of
next
control
option)

÷
(
Control
option
annual
emissions)
­
(
Next
control
option
annual
emissions)

Example
1:
Assume
that
Option
F
on
Figure
2
has
total
annualized
costs
of
$
1
million
to
reduce
2000
tons
of
a
pollutant,
and
that
Option
D
on
Figure
2
has
total
annualized
costs
of
$
500,000
to
reduce
1000
tons
of
the
same
pollutant.
The
incremental
cost
effectiveness
of
Option
F
relative
to
Option
D
is
($
1
million
­
$
500,000)
divided
by
(
2000
tons
­

1000
tons),
or
$
500,000
divided
by
1000
tons,

which
is
$
500/
ton.

Example
2:
Assume
that
two
control
options
exist:
Option
1
and
Option
2.
Option
1
achieves
a
1,000
ton/
yr
reduction
at
an
annualized
cost
of
$
1,900,000.

This
represents
an
average
cost
of
($
1,900,000
/

1,000
tons)
=
$
1,900/
ton.
Option
2
achieves
a
980
tons/
yr
reduction
at
an
annualized
cost
of
81
$
1,500,000.
This
represents
an
average
cost
of
($
1,500,000
/
980
tons)
=
$
1,531/
ton.
The
incremental
cost
effectiveness
of
Option
1
relative
to
Option
2
is
($
1,900,000
­
$
1,500,000)

divided
by
(
1,000
tons
­
980
tons).
The
adoption
of
Option
1
instead
of
Option
2
results
in
an
incremental
emission
reduction
of
20
tons
per
year
at
an
additional
cost
of
$
400,000
per
year.
The
incremental
cost
of
Option
1,
then,
is
$
20,000
per
ton
 
11
times
the
average
cost
of
$
1,900
per
ton.

While
$
1,900
per
ton
may
still
be
deemed
reasonable,
it
is
useful
to
consider
both
the
average
and
incremental
cost
in
making
an
overall
cost­
effectiveness
finding.
Of
course,
there
may
be
other
differences
between
these
options,
such
as,
energy
or
water
use,
or
non­
air
environmental
effects,
which
also
should
be
considered
in
selecting
a
BART
technology.

2.
You
should
exercise
care
in
deriving
incremental
costs
of
candidate
control
options.
Incremental
costeffectiveness
comparisons
should
focus
on
annualized
cost
and
emission
reduction
differences
between
"
dominant"

alternatives.
To
identify
dominant
alternatives,
you
generate
a
graphical
plot
of
total
annualized
costs
for
82
total
emissions
reductions
for
all
control
alternatives
identified
in
the
BART
analysis,
and
by
identifying
a
"
least­
cost
envelope"
as
shown
in
Figure
2.
(
A
"
least­
cost
envelope"
represents
the
set
of
options
that
should
be
dominant
in
the
choice
of
a
specific
option.)

Example:
Eight
technically
feasible
control
options
for
analysis
are
listed.
These
are
represented
as
A
through
H
in
Figure
2.
The
dominant
set
of
control
options,
B,
D,

F,
G,
and
H,
represent
the
least­
cost
envelope,
as
we
depict
by
the
cost
curve
connecting
them.
Points
A,
C
83
and
E
are
inferior
options,
and
you
should
not
use
them
in
calculating
incremental
cost
effectiveness.
Points
A,
C
and
E
represent
inferior
controls
because
B
will
buy
more
emissions
reductions
for
less
money
than
A;

and
similarly,
D
and
F
will
buy
more
reductions
for
less
money
than
C
and
E,
respectively.

3.
In
calculating
incremental
costs,
you:

(
1)
Array
the
control
options
in
ascending
order
of
annualized
total
costs,

(
2)
Develop
a
graph
of
the
most
reasonable
smooth
curve
of
the
control
options,
as
shown
in
Figure
2.
This
is
to
show
the
"
least­
cost
envelope"

discussed
above;
and
(
3)
Calculate
the
incremental
cost
effectiveness
for
each
dominant
option,
which
is
the
difference
in
total
annual
costs
between
that
option
and
the
next
most
stringent
option,
divided
by
the
difference
in
emissions,
after
controls
have
been
applied,
between
those
two
control
options.
For
example,
using
Figure
2,
you
would
calculate
incremental
cost
effectiveness
for
the
difference
between
options
B
and
D,
options
D
and
F,
options
F
and
G,
and
options
G
and
H.

4.
A
comparison
of
incremental
costs
can
also
be
useful
in
84
evaluating
the
viability
of
a
specific
control
option
over
a
range
of
efficiencies.
For
example,
depending
on
the
capital
and
operational
cost
of
a
control
device,
total
and
incremental
cost
may
vary
significantly
(
either
increasing
or
decreasing)
over
the
operational
range
of
a
control
device.
Also,
the
greater
the
number
of
possible
control
options
that
exist,
the
more
weight
should
be
given
to
the
incremental
costs
vs.
average
costs.
It
should
be
noted
that
average
and
incremental
cost
effectiveness
are
identical
when
only
one
candidate
control
option
is
known
to
exist.

5.
You
should
exercise
caution
not
to
misuse
these
techniques.
For
example,
you
may
be
faced
with
a
choice
between
two
available
control
devices
at
a
source,
control
A
and
control
B,
where
control
B
achieves
slightly
greater
emission
reductions.
The
average
cost
(
total
annual
cost/
total
annual
emission
reductions)
for
each
may
be
deemed
to
be
reasonable.
However,
the
incremental
cost
(
total
annual
costA­
B
/
total
annual
emission
reductionsA­
B)
of
the
additional
emission
reductions
to
be
achieved
by
control
B
may
be
very
great.
In
such
an
instance,
it
may
be
inappropriate
to
choose
control
B,
based
on
its
high
incremental
costs,
even
though
its
average
cost
may
be
considered
reasonable.
85
6.
In
addition,
when
you
evaluate
the
average
or
incremental
cost
effectiveness
of
a
control
alternative,
you
should
make
reasonable
and
supportable
assumptions
regarding
control
efficiencies.
An
unrealistically
low
assessment
of
the
emission
reduction
potential
of
a
certain
technology
could
result
in
inflated
cost­
effectiveness
figures.

f.
What
other
information
should
I
provide
in
the
cost
impacts
analysis?

You
should
provide
documentation
of
any
unusual
circumstances
that
exist
for
the
source
that
would
lead
to
cost­
effectiveness
estimates
that
would
exceed
that
for
recent
retrofits.
This
is
especially
important
in
cases
where
recent
retrofits
have
cost­
effectiveness
values
that
are
within
what
has
been
considered
a
reasonable
range,
but
your
analysis
concludes
that
costs
for
the
source
being
analyzed
are
not
considered
reasonable.
(
A
reasonable
range
would
be
a
range
that
is
consistent
with
the
range
of
cost
effectiveness
values
used
in
other
similar
permit
decisions
over
a
period
of
time.)

Example:
In
an
arid
region,
large
amounts
of
water
are
needed
for
a
scrubbing
system.
Acquiring
water
from
a
distant
location
could
greatly
increase
the
cost
per
ton
of
emissions
reduced
of
wet
scrubbing
as
a
control
option.
86
g.
What
other
things
are
important
to
consider
in
the
cost
impacts
analysis?

In
the
cost
analysis,
you
should
take
care
not
to
focus
on
incomplete
results
or
partial
calculations.
For
example,

large
capital
costs
for
a
control
option
alone
would
not
preclude
selection
of
a
control
measure
if
large
emissions
reductions
are
projected.
In
such
a
case,
low
or
reasonable
cost
effectiveness
numbers
may
validate
the
option
as
an
appropriate
BART
alternative
irrespective
of
the
large
capital
costs.
Similarly,
projects
with
relatively
low
capital
costs
may
not
be
cost
effective
if
there
are
few
emissions
reduced.

h.
Impact
analysis
part
2:
How
should
I
analyze
and
report
energy
impacts?

1.
You
should
examine
the
energy
requirements
of
the
control
technology
and
determine
whether
the
use
of
that
technology
results
in
energy
penalties
or
benefits.
A
source
owner
may,
for
example,
benefit
from
the
combustion
of
a
concentrated
gas
stream
rich
in
volatile
organic
compounds;
on
the
other
hand,
more
often
extra
fuel
or
electricity
is
required
to
power
a
control
device
or
incinerate
a
dilute
gas
stream.
If
such
benefits
or
penalties
exist,
they
should
be
quantified
to
the
extent
practicable.
Because
energy
penalties
or
benefits
can
87
usually
be
quantified
in
terms
of
additional
cost
or
income
to
the
source,
the
energy
impacts
analysis
can,
in
most
cases,
simply
be
factored
into
the
cost
impacts
analysis.

The
fact
of
energy
use
in
and
of
itself
does
not
disqualify
a
technology.

2.
Your
energy
impact
analysis
should
consider
only
direct
energy
consumption
and
not
indirect
energy
impacts.
For
example,
you
could
estimate
the
direct
energy
impacts
of
the
control
alternative
in
units
of
energy
consumption
at
the
source
(
e.
g.,
BTU,
kWh,
barrels
of
oil,
tons
of
coal).
The
energy
requirements
of
the
control
options
should
be
shown
in
terms
of
total
(
and
in
certain
cases,
also
incremental)

energy
costs
per
ton
of
pollutant
removed.
You
can
then
convert
these
units
into
dollar
costs
and,
where
appropriate,
factor
these
costs
into
the
control
cost
analysis.

3.
You
generally
do
not
consider
indirect
energy
impacts
(
such
as
energy
to
produce
raw
materials
for
construction
of
control
equipment).
However,
if
you
determine,
either
independently
or
based
on
a
showing
by
the
source
owner,

that
the
indirect
energy
impact
is
unusual
or
significant
and
that
the
impact
can
be
well
quantified,
you
may
consider
the
indirect
impact.

4.
The
energy
impact
analysis
may
also
address
concerns
88
over
the
use
of
locally
scarce
fuels.
The
designation
of
a
scarce
fuel
may
vary
from
region
to
region.
However,
in
general,
a
scarce
fuel
is
one
which
is
in
short
supply
locally
and
can
be
better
used
for
alternative
purposes,
or
one
which
may
not
be
reasonably
available
to
the
source
either
at
the
present
time
or
in
the
near
future.

5.
Finally,
the
energy
impacts
analysis
may
consider
whether
there
are
relative
differences
between
alternatives
regarding
the
use
of
locally
or
regionally
available
coal,

and
whether
a
given
alternative
would
result
in
significant
economic
disruption
or
unemployment.
For
example,
where
two
options
are
equally
cost
effective
and
achieve
equivalent
or
similar
emissions
reductions,
one
option
may
be
preferred
if
the
other
alternative
results
in
significant
disruption
or
unemployment.

i.
Impact
analysis
part
3:
How
do
I
analyze
"
non­
air
quality
environmental
impacts?"

1.
In
the
non­
air
quality
related
environmental
impacts
portion
of
the
BART
analysis,
you
address
environmental
impacts
other
than
air
quality
due
to
emissions
of
the
pollutant
in
question.
Such
environmental
impacts
include
solid
or
hazardous
waste
generation
and
discharges
of
polluted
water
from
a
control
device.

2.
You
should
identify
any
significant
or
unusual
89
environmental
impacts
associated
with
a
control
alternative
that
have
the
potential
to
affect
the
selection
or
elimination
of
a
control
alternative.
Some
control
technologies
may
have
potentially
significant
secondary
environmental
impacts.
Scrubber
effluent,
for
example,
may
affect
water
quality
and
land
use.
Alternatively,
water
availability
may
affect
the
feasibility
and
costs
of
wet
scrubbers.
Other
examples
of
secondary
environmental
impacts
could
include
hazardous
waste
discharges,
such
as
spent
catalysts
or
contaminated
carbon.
Generally,
these
types
of
environmental
concerns
become
important
when
sensitive
site­
specific
receptors
exist
or
when
the
incremental
emissions
reductions
potential
of
the
more
stringent
control
is
only
marginally
greater
than
the
next
most­
effective
option.
However,
the
fact
that
a
control
device
creates
liquid
and
solid
waste
that
must
be
disposed
of
does
not
necessarily
argue
against
selection
of
that
technology
as
BART,
particularly
if
the
control
device
has
been
applied
to
similar
facilities
elsewhere
and
the
solid
or
liquid
waste
is
similar
to
those
other
applications.
On
the
other
hand,
where
you
or
the
source
owner
can
show
that
unusual
circumstances
at
the
proposed
facility
create
greater
problems
than
experienced
elsewhere,
this
may
provide
a
basis
for
the
elimination
of
that
control
90
alternative
as
BART.

3.
The
procedure
for
conducting
an
analysis
of
non­
air
quality
environmental
impacts
should
be
made
based
on
a
consideration
of
site­
specific
circumstances.
If
you
propose
to
adopt
the
most
stringent
alternative,
then
it
is
not
necessary
to
perform
this
analysis
of
environmental
impacts
for
the
entire
list
of
technologies
you
ranked
in
Step
3.
In
general,
the
analysis
need
only
address
those
control
alternatives
with
any
significant
or
unusual
environmental
impacts
that
have
the
potential
to
affect
the
selection
of
a
control
alternative,
or
elimination
of
a
more
stringent
control
alternative.
Thus,
any
important
relative
environmental
impacts
(
both
positive
and
negative)
of
alternatives
can
be
compared
with
each
other.

4.
In
general,
the
analysis
of
impacts
starts
with
the
identification
and
quantification
of
the
solid,
liquid,
and
gaseous
discharges
from
the
control
device
or
devices
under
review.
Initially,
you
should
perform
a
qualitative
or
semi­
quantitative
screening
to
narrow
the
analysis
to
discharges
with
potential
for
causing
adverse
environmental
effects.
Next,
you
should
assess
the
mass
and
composition
of
any
such
discharges
and
quantify
them
to
the
extent
possible,
based
on
readily
available
information.
You
should
also
assemble
pertinent
information
about
the
public
91
or
environmental
consequences
of
releasing
these
materials.

j.
What
are
examples
of
non­
air
quality
environmental
impacts?

The
following
are
examples
of
how
to
conduct
non­
air
quality
environmental
impacts:

(
1)
Water
Impact
You
should
identify
the
relative
quantities
of
water
used
and
water
pollutants
produced
and
discharged
as
a
result
of
the
use
of
each
alternative
emission
control
system.
Where
possible,
you
should
assess
the
effect
on
ground
water
and
such
local
surface
water
quality
parameters
as
ph,
turbidity,
dissolved
oxygen,

salinity,
toxic
chemical
levels,
temperature,
and
any
other
important
considerations.
The
analysis
could
consider
whether
applicable
water
quality
standards
will
be
met
and
the
availability
and
effectiveness
of
various
techniques
to
reduce
potential
adverse
effects.

(
2)
Solid
Waste
Disposal
Impact
You
could
also
compare
the
quality
and
quantity
of
solid
waste
(
e.
g.,
sludges,
solids)
that
must
be
stored
and
disposed
of
or
recycled
as
a
result
of
the
application
of
each
alternative
emission
control
system.
You
should
consider
the
composition
and
various
other
characteristics
of
the
solid
waste
(
such
92
as
permeability,
water
retention,
rewatering
of
dried
material,
compression
strength,
leachability
of
dissolved
ions,
bulk
density,
ability
to
support
vegetation
growth
and
hazardous
characteristics)
which
are
significant
with
regard
to
potential
surface
water
pollution
or
transport
into
and
contamination
of
subsurface
waters
or
aquifers.

(
3)
Irreversible
or
Irretrievable
Commitment
of
Resources
You
may
consider
the
extent
to
which
the
alternative
emission
control
systems
may
involve
a
trade­
off
between
short­
term
environmental
gains
at
the
expense
of
long­
term
environmental
losses
and
the
extent
to
which
the
alternative
systems
may
result
in
irreversible
or
irretrievable
commitment
of
resources
(
for
example,
use
of
scarce
water
resources).

(
4)
Other
Adverse
Environmental
Impacts
You
may
consider
significant
differences
in
noise
levels,
radiant
heat,
or
dissipated
static
electrical
energy
of
pollution
control
alternatives.
Other
examples
of
non­
air
quality
environmental
impacts
would
include
hazardous
waste
discharges
such
as
spent
catalysts
or
contaminated
carbon.

j.
Impact
analysis
part
4:
How
do
I
take
into
account
a
93
project's
"
remaining
useful
life"
in
calculating
control
costs?

1.
You
may
decide
to
treat
the
requirement
to
consider
the
source's
"
remaining
useful
life"
of
the
source
for
BART
determinations
as
one
element
of
the
overall
cost
analysis.

The
"
remaining
useful
life"
of
a
source,
if
it
represents
a
relatively
short
time
period,
may
affect
the
annualized
costs
of
retrofit
controls.
For
example,
the
methods
for
calculating
annualized
costs
in
EPA's
Control
Cost
Manual
require
the
use
of
a
specified
time
period
for
amortization
that
varies
based
upon
the
type
of
control.
If
the
remaining
useful
life
will
clearly
exceed
this
time
period,

the
remaining
useful
life
has
essentially
no
effect
on
control
costs
and
on
the
BART
determination
process.
Where
the
remaining
useful
life
is
less
than
the
time
period
for
amortizing
costs,
you
should
use
this
shorter
time
period
in
your
cost
calculations.

2.
For
purposes
of
these
guidelines,
the
remaining
useful
life
is
the
difference
between:

(
1)
the
date
that
controls
will
be
put
in
place
(
capital
and
other
construction
costs
incurred
before
controls
are
put
in
place
can
be
rolled
into
the
first
year,
as
suggested
in
EPA's
Control
Cost
Manual);
you
are
conducting
the
BART
analysis;
and
94
(
2)
the
date
the
facility
permanently
stops
operations.

Where
this
affects
the
BART
determination,
this
date
should
be
assured
by
a
federally­
or
State­
enforceable
restriction
preventing
further
operation.

3.
We
recognize
that
there
may
be
situations
where
a
source
operator
intends
to
shut
down
a
source
by
a
given
date,
but
wishes
to
retain
the
flexibility
to
continue
operating
beyond
that
date
in
the
event,
for
example,
that
market
conditions
change.
Where
this
is
the
case,
your
BART
analysis
may
account
for
this,
but
it
must
maintain
consistency
with
the
statutory
requirement
to
install
BART
within
5
years.
Where
the
source
chooses
not
to
accept
a
federally
enforceable
condition
requiring
the
source
to
shut
down
by
a
given
date,
it
is
necessary
to
determine
whether
a
reduced
time
period
for
the
remaining
useful
life
changes
the
level
of
controls
that
would
have
been
required
as
BART.

If
the
reduced
time
period
does
change
the
level
of
BART
controls,
you
may
identify,
and
include
as
part
of
the
BART
emission
limitation,
the
more
stringent
level
of
control
that
would
be
required
as
BART
if
there
were
no
assumption
that
reduced
the
remaining
useful
life.
You
may
incorporate
into
the
BART
emission
limit
this
more
stringent
level,

which
would
serve
as
a
contingency
should
the
source
continue
operating
more
than
5
years
after
the
date
EPA
95
approves
the
relevant
SIP.
The
source
would
not
be
allowed
to
operate
after
the
5­
year
mark
without
such
controls.
If
a
source
does
operate
after
the
5­
year
mark
without
BART
in
place,
the
source
is
considered
to
be
in
violation
of
the
BART
emissions
limit
for
each
day
of
operation.

5.
Step
5:
How
should
I
determine
visibility
impacts
in
the
BART
determination?

The
following
is
an
approach
you
may
use
to
determine
visibility
impacts
(
the
degree
of
visibility
improvement
for
each
source
subject
to
BART)
for
the
BART
determination.
Once
you
have
determined
that
your
source
or
sources
are
subject
to
BART,

you
must
conduct
a
visibility
improvement
determination
for
the
source(
s)
as
part
of
the
BART
determination.
When
making
this
determination,
we
believe
you
have
flexibility
in
setting
absolute
thresholds,
target
levels
of
improvement,
or
de
minimis
levels
since
the
deciview
improvement
must
be
weighed
among
the
five
factors,
and
you
are
free
to
determine
the
weight
and
significance
to
be
assigned
to
each
factor.
For
example,
a
0.3
deciview
improvement
may
merit
a
stronger
weighting
in
one
case
versus
another,
so
one
"
bright
line"
may
not
be
appropriate.

[
Note
that
if
sources
have
elected
to
apply
the
most
stringent
controls
available,
consistent
with
the
discussion
in
section
E.

step
1.
below,
you
need
not
conduct,
or
require
the
source
to
conduct,
an
air
quality
modeling
analysis
for
the
purpose
of
17
The
model
code
and
its
documentation
are
available
at
no
cost
for
download
from
the
model
developers'
Internet
Web
site:
http://
www.
src.
com/
calpuff/
calpuff1.
htm.

18
Interagency
Workgroup
on
Air
Quality
Modelig
(
IWAQM)
Phase
2
Summary
Report
and
Recommendations
for
Modeling
Long
Range
Transport
Impacts,
U.
S.
Environmental
Protection
Agency,
EPA­
454/
R­
98­
019,
December
1998.

96
determining
its
visibility
impacts].

Use
the
CALPUFF17,
or
other
appropriate
dispersion
model
to
determine
the
visibility
improvement
expected
at
a
Class
I
area
from
the
potential
BART
control
technology
applied
to
the
source.

Modeling
should
be
conducted
for
SO2,
NOx,
and
direct
PM
emissions
(
PM2.5
and/
or
PM10).
If
the
source
is
making
the
visibility
determination,
you
should
review
and
approve
or
disapprove
of
the
source's
analysis
before
making
the
expected
improvement
determination.
For
the
Source
analysis:

!
Modeling
protocol
Some
critical
items
to
include
in
a
modeling
protocol
are
meteorological
and
terrain
data,
as
well
as
sourcespecific
information
(
stack
height,
temperature,
exit
velocity,
elevation,
and
allowable
and
actual
emission
rates
of
applicable
pollutants),
and
receptor
data
from
appropriate
Class
I
areas.
We
recommend
following
EPA's
Interagency
Workgroup
on
Air
Quality
Modeling
(
IWAQM)
Phase
2
Summary
Report
and
Recommendations
for
Modeling
Long
Range
Transport
Impacts18
for
parameter
97
settings
and
meteorological
data
inputs;
the
use
of
other
settings
from
those
in
IWAQM
should
be
identified
and
explained
in
the
protocol.

One
important
element
of
the
protocol
is
in
establishing
the
receptors
that
will
be
used
in
the
model.
The
receptors
that
you
use
should
be
located
in
the
nearest
Class
I
area
with
sufficient
density
to
identify
the
likely
visibility
effects
of
the
source.

For
other
Class
I
areas
in
relatively
close
proximity
to
a
BART­
eligible
source,
you
may
model
a
few
strategic
receptors
to
determine
whether
effects
at
those
areas
may
be
greater
than
at
the
nearest
Class
I
area.
For
example,
you
might
chose
to
locate
receptors
at
these
areas
at
the
closest
point
to
the
source,
at
the
highest
and
lowest
elevation
in
the
Class
I
area,

at
the
IMPROVE
monitor,
and
at
the
approximate
expected
plume
release
height.
If
the
highest
modeled
effects
are
observed
at
the
nearest
Class
I
area,
you
may
choose
not
to
analyze
the
other
Class
I
areas
any
further,
as
additional
analyses
might
be
unwarranted.

You
should
bear
in
mind
that
some
receptors
within
the
relevant
Class
I
area
may
be
less
than
50
km
from
the
source
while
other
receptors
within
that
same
Class
I
98
area
may
be
greater
than
50
km
from
the
same
source.

As
indicated
by
the
Guideline
on
Air
Quality
Models,

this
situation
may
call
for
the
use
of
two
different
modeling
approaches
for
the
same
Class
I
area
and
source,
depending
upon
the
State's
chosen
method
for
modeling
sources
less
than
50
km.
In
situations
where
you
are
assessing
visibility
impacts
for
sourcereceptor
distances
less
than
50
km,
you
should
use
expert
modeling
judgment
in
determining
visibility
impacts,
giving
consideration
to
both
CALPUFF
and
other
EPA­
approved
methods.

In
developing
your
modeling
protocol,
you
may
want
to
consult
with
EPA
and
your
regional
planning
organization
(
RPO).
Up­
front
consultation
will
ensure
that
key
technical
issues
are
addressed
before
you
conduct
your
modeling.

!
For
each
source,
run
CALPUFF,
or
other
EPA
approved
model,
at
pre­
control
and
post­
control
emission
rates
according
to
the
accepted
methodology
in
the
protocol.

Use
the
24­
hr
emission
rate
from
the
highest
emitting
day
of
they
meteorological
period
modeled
(
for
the
pre­
control
scenario).
Calculate
the
99
model
results
for
each
receptor
as
the
change
in
deciviews
compared
against
natural
visibility
conditions.
Post­
control
emission
rates
are
calculated
as
a
percentage
of
pre­
control
emission
rates.
For
example,
if
the
24­
hr
per­
control
emission
rate
is
100
lb/
hr
of
SO2,
then
the
post
control
rate
is
5
lb/
hr
if
the
control
efficiency
being
evaluated
is
95
percent.

!
Make
the
net
visibility
improvement
determination
Assess
the
visibility
improvement
based
on
the
modeled
change
in
visibility
impact
for
the
precontrol
and
post­
control
emission
scenarios.
You
have
flexibility
to
assess
visibility
improvements
due
to
BART
controls
by
one
or
more
methods.
You
may
consider
the
frequency,
magnitude,
and
duration
components
of
impairment.

Suggestions
for
making
the
determination
are:

°
use
of
a
comparison
threshold,
as
is
done
for
determining
if
BART­
eligible
sources
should
be
subject
to
a
BART
determination.
Comparison
thresholds
can
be
used
in
a
number
of
ways
in
evaluating
visibility
improvement
(
e.
g.

the
number
of
days
or
hours
that
the
100
threshold
was
exceeded,
a
single
threshold
for
determining
whether
a
change
in
impacts
is
significant,
a
threshold
representing
an
x
percent
change
in
improvement,
etc.).

°

°
Compare
the
98th
percent
days
for
the
pre­
and
post­
control
runs.

°

Note
that
each
of
the
modeling
options
may
be
supplemented
with
source
apportionment
data
or
source
apportionment
modeling.

E.
How
do
I
select
the
"
best"
alternative,
using
the
results
of
Steps
1
through
5?

1.
Summary
of
the
Impacts
Analysis
From
the
alternatives
you
evaluated
in
Step
3,
we
recommend
you
develop
a
chart
(
or
charts)
displaying
for
each
of
the
alternatives:

(
1)
expected
emission
rate
(
tons
per
year,
pounds
per
hour);

(
2)
emissions
performance
level
(
e.
g.,
percent
pollutant
removed,
emissions
per
unit
product,

lb/
MMbtu,
ppm);

(
3)
expected
emissions
reductions
(
tons
per
year);

(
4)
costs
of
compliance
­­
total
annualized
costs
($),
101
cost
effectiveness
($/
ton),
and
incremental
cost
effectiveness
($/
ton),
and/
or
any
other
costeffectiveness
measures
(
such
as
$/
deciview);

(
5)
energy
impacts;

(
6)
non­
air
quality
environmental
impacts;
and
(
7)
modeled
visibility
impacts.

2.
Selecting
a
"
best"
alternative
1.
You
have
discretion
to
determine
the
order
in
which
you
should
evaluate
control
options
for
BART.
Whatever
the
order
in
which
you
choose
to
evaluate
options,
you
should
always
(
1)
display
the
options
evaluated;
(
2)
identify
the
average
and
incremental
costs
of
each
option;
(
3)
consider
the
energy
and
non­
air
quality
environmental
impacts
of
each
option;
(
4)
consider
the
remaining
useful
life;
and
(
5)

consider
the
modeled
visibility
impacts.
You
should
provide
a
justification
for
adopting
the
technology
that
you
select
as
the
"
best"
level
of
control,
including
an
explanation
of
the
CAA
factors
that
led
you
to
choose
that
option
over
other
control
levels.

2.
In
the
case
where
you
are
conducting
a
BART
determination
for
two
regulated
pollutants
on
the
same
source,
if
the
result
is
two
different
BART
technologies
that
do
not
work
well
together,
you
could
then
substitute
a
different
technology
or
combination
of
technologies.
102
3.
In
selecting
a
"
best"
alternative,
should
I
consider
the
affordability
of
controls?

1.
Even
if
the
control
technology
is
cost
effective,
there
may
be
cases
where
the
installation
of
controls
would
affect
the
viability
of
continued
plant
operations.

2.
There
may
be
unusual
circumstances
that
justify
taking
into
consideration
the
conditions
of
the
plant
and
the
economic
effects
of
requiring
the
use
of
a
given
control
technology.
These
effects
would
include
effects
on
product
prices,
the
market
share,
and
profitability
of
the
source.

Where
there
are
such
unusual
circumstances
that
are
judged
affect
plant
operations,
you
may
take
into
consideration
the
conditions
of
the
plant
and
the
economic
effects
of
requiring
the
use
of
a
control
technology.
Where
these
effects
are
judged
to
have
a
severe
impact
on
plant
operations
you
may
consider
them
in
the
selection
process,

but
you
may
wish
to
provide
an
economic
analysis
that
demonstrates,
in
sufficient
detail
for
public
review,
the
specific
economic
effects,
parameters,
and
reasoning.
(
We
recognize
that
this
review
process
must
preserve
the
confidentiality
of
sensitive
business
information).
Any
analysis
may
also
consider
whether
other
competing
plants
in
the
same
industry
have
been
required
to
install
BART
controls,
if
this
information
is
available.
103
4.
Sulfur
dioxide
limits
for
utility
boilers
You
must
require
750
MW
power
plants
to
meet
specific
control
levels
for
SO2
of
either
95
percent
control
or
.15
lbs/
MMBtu,
for
each
EGU
greater
than
200
MW
that
is
currently
uncontrolled,
unless
you
determine
that
an
alternative
control
level
is
justified
based
on
a
careful
consideration
of
the
statutory
factors.
Thus,
for
example,

if
the
source
demonstrates
circumstances
affecting
its
ability
to
cost­
effectively
reduce
its
emissions,
you
should
take
that
into
account
in
determining
whether
the
presumptive
levels
of
control
are
appropriate
for
that
facility.
For
a
currently
uncontrolled
EGU
greater
than
200
MW
in
size,
but
located
at
a
power
plant
smaller
than
750
MW
in
size,
such
controls
are
generally
cost­
effective
and
could
be
used
in
your
BART
determination
considering
the
five
factors
specified
in
CAA
section
169A(
g)(
2).
While
these
levels
may
represent
current
control
capabilities,
we
expect
that
scrubber
technology
will
continue
to
improve
and
control
costs
continue
to
decline.
You
should
be
sure
to
consider
the
level
of
control
that
is
currently
best
achievable
at
the
time
that
you
are
conducting
your
BART
analysis.

For
coal­
fired
EGUs
with
existing
post­
combustion
SO2
controls
achieving
less
than
50
percent
removal
104
efficiencies,
we
recommend
that
you
evaluate
constructing
a
new
FGD
system
to
meet
the
same
emission
limits
as
above
(
95
percent
removal
or
0.15
lb/
mmBtu),
in
addition
to
the
evaluation
of
scrubber
upgrades
discussed
below.
For
oilfired
units,
regardless
of
size,
you
should
evaluate
limiting
the
sulfur
content
of
the
fuel
oil
burned
to
be
1
percent
or
less
by
weight.

For
those
BART­
eligible
EGUs
with
pre­
existing
postcombustion
SO2
controls
achieving
removal
efficiencies
of
at
least
50
percent,
your
BART
determination
should
consider
cost
effective
scrubber
upgrades
designed
to
improve
the
system's
overall
SO2
removal
efficiency.
There
are
numerous
scrubber
enhancements
available
to
upgrade
the
average
removal
efficiencies
of
all
types
of
existing
scrubber
systems.
We
recommend
that
as
you
evaluate
the
definition
of
"
upgrade,"
you
evaluate
options
that
not
only
improve
the
design
removal
efficiency
of
the
scrubber
vessel
itself,
but
also
consider
upgrades
that
can
improve
the
overall
SO2
removal
efficiency
of
the
scrubber
system.
Increasing
a
scrubber
system's
reliability,
and
conversely
decreasing
its
downtime,
by
way
of
optimizing
operation
procedures,

improving
maintenance
practices,
adjusting
scrubber
chemistry,
and
increasing
auxiliary
equipment
redundancy,

are
all
ways
to
improve
average
SO2
removal
efficiencies.
105
We
recommend
that
as
you
evaluate
the
performance
of
existing
wet
scrubber
systems,
you
consider
some
of
the
following
upgrades,
in
no
particular
order,
as
potential
scrubber
upgrades
that
have
been
proven
in
the
industry
as
cost
effective
means
to
increase
overall
SO2
removal
of
wet
systems:

(
a)
Elimination
of
Bypass
Reheat;

(
b)
Installation
of
Liquid
Distribution
Rings;

(
c)
Installation
of
Perforated
Trays;

(
d)
Use
of
Organic
Acid
Additives;

(
e)
Improve
or
Upgrade
Scrubber
Auxiliary
System
Equipment;

(
f)
Redesign
Spray
Header
or
Nozzle
Configuration.

We
recommend
that
as
you
evaluate
upgrade
options
for
dry
scrubber
systems,
you
should
consider
the
following
cost
effective
upgrades,
in
no
particular
order:

(
a)
Use
of
Performance
Additives;

(
b)
Use
of
more
Reactive
Sorbent;

(
c)
Increase
the
Pulverization
Level
of
Sorbent;

(
d)
Engineering
redesign
of
atomizer
or
slurry
injection
system.

You
should
evaluate
scrubber
upgrade
options
based
on
the
5
step
BART
analysis
process.

5.
Nitrogen
oxide
limits
for
utility
boilers
You
should
establish
specific
numerical
limits
for
NOx
106
control
for
each
BART
determination.
For
power
plants
with
a
generating
capacity
in
excess
of
750
MW
currently
using
selective
catalytic
reduction
(
SCR)
or
selective
non­
catalytic
reduction
(
SNCR)
for
part
of
the
year,
you
should
presume
that
use
of
those
same
controls
year­
round
is
BART.
For
other
sources
currently
using
SCR
or
SNCR
to
reduce
NOx
emissions
during
part
of
the
year,

you
should
carefully
consider
requiring
the
use
of
these
controls
year­
round
as
the
additional
costs
of
operating
the
equipment
throughout
the
year
would
be
relatively
modest.

For
coal­
fired
EGUs
greater
than
200
MW
located
at
greater
than
750
MW
power
plants
and
operating
without
postcombustion
controls
(
i.
e.
SCR
or
SNCR),
we
have
provided
presumptive
NOx
limits,
differentiated
by
boiler
design
and
type
of
coal
burned.
You
may
determine
that
an
alternative
control
level
is
appropriate
based
on
a
careful
consideration
of
the
statutory
factors.
For
coal­
fired
EGUs
greater
than
200
MW
located
at
power
plants
750
MW
or
less
in
size
and
operating
without
post­
combustion
controls,
you
should
likewise
presume
that
these
same
levels
are
costeffective
You
should
require
such
utility
boilers
to
meet
the
following
NOx
emission
limits,
unless
you
determine
that
an
alternative
control
level
is
justified
based
on
consideration
of
the
statutory
factors.
The
following
NOx
emission
rates
were
determined
based
on
a
number
of
19
No
Cell
burners,
dry­
turbo­
fired
units,
nor
wet­
bottom
tangential­
fired
units
burning
lignite
were
identified
as
BART­
eligible,
thus
no
presumptive
limit
was
determined.
Similarly,
no
wet­
bottom
tangential­
fired
units
burning
subbituminous
were
identified
as
BART­
eligible.

20
These
limits
reflect
the
design
and
technological
assumptions
discussed
in
the
technical
support
document
for
NOx
limits
for
these
guidelines.
See
Technical
Support
Document
for
BART
NOx
Limits
for
Electric
Generating
Units
and
Technical
Support
Document
for
BART
NOx
Limits
for
Electric
Generating
Units
Excel
Spreadsheet,
Memorandum
to
Docket
OAR
2002­
0076,
April
15,
2005.

107
assumptions,
including
that
the
EGU
boiler
has
enough
volume
to
allow
for
installation
and
effective
operation
of
separated
overfire
air
ports.
For
boilers
where
these
assumptions
are
incorrect,
these
emission
limits
may
not
be
cost­
effective.

Table
1:
Presumptive
NOx
emission
limits
for
BART­
eligible
coalfired
units.
19
Unit
type
Coal
type
NOx
presumptive
limit
(
lb/
mmbtu)
20
Dry­
bottom
wallfired
Bituminous
0.39
Sub­
bituminous
0.23
Lignite
0.29
Tangential­
fired
Bituminous
0.28
Sub­
bituminous
0.15
Lignite
0.17
Cell
Burners
Bituminous
0.40
Sub­
bituminous
0.45
Dry­
turbo­
fired
Bituminous
0.32
108
Sub­
bituminous
0.23
Wet­
bottom
tangential­
fired
Bituminous
0.62
Most
EGUs
can
meet
these
presumptive
NOx
limits
through
the
use
of
current
combustion
control
technology,
i.
e.
the
careful
control
of
combustion
air
and
low­
NOx
burners.
For
units
that
cannot
meet
these
limits
using
such
technologies,

you
should
consider
whether
advanced
combustion
control
technologies
such
as
rotating
opposed
fire
air
should
be
used
to
meet
these
limits.

Because
of
the
relatively
high
NOx
emission
rates
of
cyclone
units,
SCR
is
more
cost­
effective
than
the
use
of
current
combustion
control
technology
for
these
units.
The
use
of
SCRs
at
cyclone
units
burning
bituminous
coal,

subbituminous
coal,
and
lignite
should
enable
the
units
to
cost­
effectively
meet
NOx
rates
of
0.10
lbs/
mmbtu.
As
a
result,
we
are
establishing
a
presumptive
NOx
limit
of
O.
10
lbs/
mmbtu
based
on
the
use
of
SCR
for
coal­
fired
cyclone
units
greater
than
200
MW
located
at
750
MW
power
plants.

As
with
the
other
presumptive
limits
established
in
this
guideline,
you
may
determine
that
an
alternative
level
of
control
is
appropriate
based
on
your
consideration
of
the
relevant
statutory
factors.
For
other
cyclone
units,
you
should
review
the
use
of
SCR
and
consider
whether
these
21
See
Technical
Support
Document
for
BART
NOx
Limits
for
Electric
Generating
Units
and
Technical
Support
Document
for
BART
NOx
Limits
for
Electric
Generating
Units
Excel
Spreadsheet,
Memorandum
to
Docket
OAR
2002­
0076,
April
15,
2005.

109
post­
combustion
controls
should
be
required
as
BART.

For
oil­
fired
and
gas­
fired
EGUs
larger
than
200MW,
we
believe
that
installation
of
current
combustion
control
technology
to
control
NOx
is
generally
highly
cost­
effective
and
should
be
considered
in
your
determination
of
BART
for
these
sources.
Many
such
units
can
make
significant
reductions
in
NOx
emissions
which
are
highly
cost­
effective
through
the
application
of
current
combustion
control
technology.
21
V.
ENFORCEABLE
LIMITS/
COMPLIANCE
DATE
To
complete
the
BART
process,
you
must
establish
enforceable
emission
limits
that
reflect
the
BART
requirements
and
require
compliance
within
a
given
period
of
time.
In
particular,
you
must
establish
an
enforceable
emission
limit
for
each
subject
emission
unit
at
the
source
and
for
each
pollutant
subject
to
review
that
is
emitted
from
the
source.
In
addition,
you
must
require
compliance
with
the
BART
emission
limitations
no
later
than
5
years
after
EPA
approves
your
regional
haze
SIP.
If
technological
or
economic
limitations
in
the
application
of
a
measurement
methodology
to
a
particular
emission
unit
make
a
conventional
emissions
limit
infeasible,
you
may
instead
110
prescribe
a
design,
equipment,
work
practice,
operation
standard,

or
combination
of
these
types
of
standards.
You
should
consider
allowing
sources
to
"
average"
emissions
across
any
set
of
BARTeligible
emission
units
within
a
fenceline,
so
long
as
the
emission
reductions
from
each
pollutant
being
controlled
for
BART
would
be
equal
to
those
reductions
that
would
be
obtained
by
simply
controlling
each
of
the
BART­
eligible
units
that
constitute
BART­
eligible
source.

You
should
ensure
that
any
BART
requirements
are
written
in
a
way
that
clearly
specifies
the
individual
emission
unit(
s)

subject
to
BART
review.
Because
the
BART
requirements
themselves
are
"
applicable"
requirements
of
the
CAA,
they
must
be
included
as
title
V
permit
conditions
according
to
the
procedures
established
in
40
CFR
part
70
or
40
CFR
part
71.

Section
302(
k)
of
the
CAA
requires
emissions
limits
such
as
BART
to
be
met
on
a
continuous
basis.
Although
this
provision
does
not
necessarily
require
the
use
of
continuous
emissions
monitoring
(
CEMs),
it
is
important
that
sources
employ
techniques
that
ensure
compliance
on
a
continuous
basis.
Monitoring
requirements
generally
applicable
to
sources,
including
those
that
are
subject
to
BART,
are
governed
by
other
regulations.

See,
e.
g.,
40
CFR
part
64
(
compliance
assurance
monitoring);
40
CFR
70.6(
a)(
3)
(
periodic
monitoring);
40
CFR
70.6(
c)(
1)

(
sufficiency
monitoring).
Note
also
that
while
we
do
not
believe
22
70
FR
9705,
February
28,
2005.

111
that
CEMs
would
necessarily
be
required
for
all
BART
sources,
the
vast
majority
of
electric
generating
units
potentially
subject
to
BART
already
employ
CEM
technology
for
other
programs,
such
as
the
acid
rain
program.
In
addition,
emissions
limits
must
be
enforceable
as
a
practical
matter
(
contain
appropriate
averaging
times,
compliance
verification
procedures
and
recordkeeping
requirements).
In
light
of
the
above,
the
permit
must:

!
be
sufficient
to
show
compliance
or
noncompliance
(
i.
e.,
through
monitoring
times
of
operation,
fuel
input,
or
other
indices
of
operating
conditions
and
practices);
and
!
specify
a
reasonable
averaging
time
consistent
with
established
reference
methods,
contain
reference
methods
for
determining
compliance,
and
provide
for
adequate
reporting
and
recordkeeping
so
that
air
quality
agency
personnel
can
determine
the
compliance
status
of
the
source;
and
!
for
EGUS,
specify
an
averaging
time
of
a
30­
day
rolling
average,
and
contain
a
definition
of
"
boiler
operating
day"
that
is
consistent
with
the
definition
in
the
proposed
revisions
to
the
NSPS
for
utility
boilers
in
40
CFR
Part
60,
subpart
Da.
22
You
should
consider
a
boiler
operating
day
to
be
any
24­
hour
period
between
112
12:
00
midnight
and
the
following
midnight
during
which
any
fuel
is
combusted
at
any
time
at
the
steam
generating
unit.
This
would
allow
30­
day
rolling
average
emission
rates
to
be
calculated
consistently
across
sources.
