From:
Joan
Crawford
Sent:
10/
06/
2005
10:
41
AM
To:
Mary
Henigin
Subject:
As
Requested
OMB
received
on
the
5th.
This
is
from
the
ROCIS
system.

10/
05/
2005
10/
05/
2005
2060­
AN28
2060
EPA/
AR
Prevention
of
Significant
Deterioration
and
Nonattainment
New
Source
Review:
Alternative
Applicability
Test
for
Electric
Generating
Units
Proposed
Rule
Stage
SIGNIFICANT
RECEIVE
Joan
Crawford
SBREFA
Team
Leader
Regulatory
Management
Division
202
564­
6568;
Mail
code
1806A
Internal
and
Deliberative­
Do
Not
Quote,
Cite,
Copy,
or
Distribute
September
30,
2005
1
I.
General
Information
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7
A.
What
are
the
regulated
entities?
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7
B.
How
should
I
submit
CBI
to
the
Agency?
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8
C.
What
Should
I
Consider
as
I
prepare
My
Comments
for
EPA?
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8
D.
How
Can
I
Find
Information
About
a
Possible
Public
Hearing?
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9
E.
How
is
this
preamble
organized?
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10
II.
Overview
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11
III.
Background
on
EGU
Requirements
and
Emissions
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14
A.
SO2
and
NOx
Requirements
Before
1990
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14
B.
SO
2
and
NOx
Requirements
After
1990
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15
C.
Requirements
for
Pollutants
Other
Than
SO
2
and
NOx
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31
IV.
Today's
Proposed
Rule
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32
A.
Background
on
Existing
Regulations
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33
B.
What
We
Are
Proposing
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39
1.
Test
for
EGUs
Based
on
Maximum
Achievable
Hourly
Emissions
.
.
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39
2.
Test
for
EGUs
Based
on
Maximum
Achieved
Hourly
Emissions
.
.
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.
46
3.
Emissions
Test
Based
on
Energy
Output
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47
C.
Pollutants
to
Which
the
Revised
Applicability
Test
Applies
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49
D.
Significant
Emissions
Rates
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50
E.
Eliminating
Netting
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51
F.
Benefits
of
Maximum
Achievable
Hourly
Emissions
Test
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53
G.
Would
States
be
required
to
adopt
the
revised
emissions
test?
.
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59
V.
Statutory
and
Regulatory
History
and
Legal
Rationale
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60
A.
The
NSPS
Program
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60
B.
The
Major
NSR
Program
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69
C.
Legal
Rationale
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77
1.
Maximum
Achievable
Hourly
Emission
Test
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77
2.
Maximum
Achieved
Hourly
Emissions
Test
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87
VI.
Statutory
and
Executive
Order
Reviews
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88
A.
Executive
Order
12866
 
Regulatory
Planning
and
Review
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88
B.
Paperwork
Reduction
Act
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89
C.
Regulatory
Flexibility
Act
(
RFA)
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91
D.
Unfunded
Mandates
Reform
Act
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92
E.
Executive
Order
13132
 
Federalism
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94
F.
Executive
Order
13175
 
Consultation
and
Coordination
with
Indian
Internal
and
Deliberative­
Do
Not
Quote,
Cite,
Copy,
or
Distribute
September
30,
2005
2
Tribal
Governments
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95
G.
Executive
Order
13045
 
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
.
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96
H.
Executive
Order
13211
 
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
.
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97
I.
National
Technology
Transfer
and
Advancement
Act
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97
Internal
and
Deliberative­
Do
Not
Quote,
Cite,
Copy,
or
Distribute
September
30,
2005
3
6560­
50­
P
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Parts
51
and
52
[
FRL
­
______,
E­
Docket
ID
No.
OAR­
2005­
0163]

RINPrevention
of
Significant
Deterioration
and
Nonattainment
New
Source
Review:
Emissions
Test
for
Electric
Generating
Units
AGENCY:
Environmental
Protection
Agency
(
EPA).

ACTION:
Proposed
rule
SUMMARY:
The
EPA
(
we)
is
proposing
to
revise
the
emissions
test
for
existing
electric
generating
units
(
EGUs)
that
are
subject
to
the
regulations
governing
the
Prevention
of
Significant
Deterioration
(
PSD)
and
nonattainment
major
New
Source
Review
(
NSR)

programs
(
collectively
"
NSR")
mandated
by
parts
C
and
D
of
title
I
of
the
Clean
Air
Act
(
CAA
or
Act).
The
revised
emissions
test
is
the
same
as
that
in
the
New
Source
Performance
Standards
(
NSPS)
Program
under
CAA
Section
111(
a)(
4).
For
existing
EGUs,
we
are
proposing
to
compare
the
maximum
hourly
emissions
achievable
at
that
unit
during
the
past
5
years
to
the
maximum
hourly
emissions
achievable
at
that
unit
after
the
change
to
determine
whether
an
emissions
increase
would
occur.
Alternatively,
we
are
soliciting
public
comment
on
a
major
NSR
emissions
test
for
existing
EGUs
that
would
compare
maximum
hourly
emissions
achieved
before
a
change
to
the
maximum
hourly
emissions
achieved
after
the
change.
We
are
also
soliciting
public
comment
on
adopting
an
Internal
and
Deliberative­
Do
Not
Quote,
Cite,
Copy,
or
Distribute
September
30,
2005
4
NSR
emissions
test
based
on
mass
of
emissions
per
unit
of
energy
output.
Today's
proposal
would
not
affect
new
EGUs,
which
would
continue
to
be
subject
to
major
NSR
preconstruction
review.
The
proposed
rule
would
only
apply
prospectively
to
changes
at
existing
EGUs
potentially
covered
by
major
NSR.

These
proposed
regulations
interpret
CAA
section
111(
a)(
4),
in
the
context
of
NSR,
for
physical
changes
and
changes
in
the
method
of
operation
at
existing
EGUs.
The
proposed
regulations
would
establish
a
uniform
emissions
test
nationally
under
the
NSPS
and
NSR
programs
for
existing
EGUs.
The
proposed
regulations
would
also
promote
the
safety,
reliability,
and
efficiency
of
EGUs.

DATES:
Comments.
Comments
must
be
received
on
or
before
on
[
INSERT
DATE
60
DAYS
AFTER
PUBLICATION
IN
THE
FEDERAL
REGISTER.]

Public
Hearing.
If
anyone
contacts
us
requesting
to
speak
at
a
public
hearing
[
INSERT
20
DAYS
AFTER
PUBLICATION
IN
THE
FEDERAL
REGISTER],
we
will
hold
a
public
hearing
approximately
30
days
after
publication
in
the
Federal
Register.

ADDRESSES:
Submit
your
comments,
identified
by
Docket
ID
No.
OAR­
2005­
0163
by
one
of
the
following
methods:

°
Federal
eRulemaking
Portal:
http://
www.
regulations.
gov.
Follow
the
on­
line
instructions
for
submitting
comments.

°
Agency
Website:
http://
www.
epa.
gov/
edocket.
EDOCKET,
EPA's
electronic
public
docket
and
comment
system,
is
EPA's
preferred
method
for
receiving
comments.
Follow
the
on­
line
instructions
for
submitting
comments.
Internal
and
Deliberative­
Do
Not
Quote,
Cite,
Copy,
or
Distribute
September
30,
2005
5
°
E­
mail:
a­
and­
r­
docket@
epamail.
epa.
gov.

°
Fax:
202­
566­
1741.

°
Mail:
Attention
Docket
ID
No.
OAR­
2005­
0163,
U.
S.
Environmental
Protection
Agency,
EPA
West
(
Air
Docket),
1200
Pennsylvania
Avenue,
Northwest,
Mail
code:
6102T,
Washington,
DC
20460.
In
addition,
please
mail
a
copy
of
your
comments
on
the
information
collection
provisions
to
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Managment
and
Budget
(
OMB),
Attn:
Desk
Officer
for
OMB,
725
17th
Street,
Northwest,
Washington,
DC
20503.

°
Hand
Delivery:
U.
S.
Environmental
Protection
Agency,
EPA
West
(
Air
Docket),

1301
Constitution
Avenue,
Northwest,
Room
B102,
Washington,
DC
20004,

Attention
Docket
ID
No.
OAR­
2005­
0163.
Such
deliveries
are
only
accepted
during
the
Docket's
normal
hours
of
operation,
and
special
arrangements
should
be
made
for
deliveries
of
boxed
information.

Instructions:
Direct
your
comments
to
Docket
ID
No.
OAR­
2005­
0163.
EPA's
policy
is
that
all
comments
received
will
be
included
in
the
public
docket
without
change
and
may
be
made
available
online
at
http://
www.
epa.
gov/
edocket,
including
any
personal
information
provided,
unless
the
comment
includes
information
claimed
to
be
Confidential
Business
Information
(
CBI)
or
other
information
whose
disclosure
is
restricted
by
statute.
Do
not
submit
information
that
you
consider
to
be
CBI
or
otherwise
protected
through
EDOCKET,
regulations.
gov,
or
e­
mail.
The
EPA
EDOCKET
and
the
federal
regulations.
gov
websites
are
"
anonymous
access"
systems,
which
means
EPA
will
not
Internal
and
Deliberative­
Do
Not
Quote,
Cite,
Copy,
or
Distribute
September
30,
2005
6
know
your
identity
or
contact
information
unless
you
provide
it
in
the
body
of
your
comment.
If
you
send
an
e­
mail
comment
directly
to
EPA
without
going
through
EDOCKET
or
regulations.
gov,
your
e­
mail
address
will
be
automatically
captured
and
included
as
part
of
the
comment
that
is
placed
in
the
public
docket
and
made
available
on
the
Internet.
If
you
submit
an
electronic
comment,
EPA
recommends
that
you
include
your
name
and
other
contact
information
in
the
body
of
your
comment
and
with
any
disk
or
CDROM
you
submit.
If
EPA
cannot
read
your
comment
due
to
technical
difficulties
and
cannot
contact
you
for
clarification,
EPA
may
not
be
able
to
consider
your
comment.

Electronic
files
should
avoid
the
use
of
special
characters,
avoid
any
form
of
encryption,

and
be
free
of
any
defects
or
viruses.
For
additional
information
about
EPA's
public
docket
visit
EDOCKET
on­
line
or
see
the
Federal
Register
of
May
31,
2002
(
67
FR
38102).
For
additional
instructions
on
submitting
comments,
go
to
section
I..
B.
of
the
SUPPLEMENTARY
INFORMATION
section
of
this
document.

Docket:
All
documents
in
the
docket
are
listed
in
the
EDOCKET
index
at
http://
www.
epa.
gov/
edocket.
Although
listed
in
the
index,
some
information
is
not
publicly
available,
i.
e.,
CBI
or
other
information
whose
disclosure
is
restricted
by
statute.

Certain
other
material,
such
as
copyrighted
material,
is
not
placed
on
the
Internet
and
will
be
publicly
available
only
in
hard
copy
form.
Publicly
available
docket
materials
are
available
either
electronically
in
EDOCKET
or
in
hard
copy
at
the
U.
S.
Environmental
Protection
Agency,
EPA
West
(
Air
Docket),
1301
Constitution
Avenue,
Northwest,
Room
B102,
Washington,
DC.
Attention
Docket
ID
No.
OAR­
2005­
0163.
The
Public
Reading
Internal
and
Deliberative­
Do
Not
Quote,
Cite,
Copy,
or
Distribute
September
30,
2005
1
Establishments
owned
and
operated
by
Federal,
State,
or
local
government
are
classified
according
to
the
activity
in
which
they
are
engaged.

7
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Public
Reading
Room
is
(
202)
566­
1744,
and
the
telephone
number
for
the
Air
Docket
is
(
202)
566­
1742.

FOR
FURTHER
INFORMATION
CONTACT:
Ms.
Janet
McDonald,
Information
Transfer
and
Program
Integration
Division
(
C339­
03),
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
NC
27711,
telephone
number:
(
919)
541­
1450;
fax
number
:
(
919)
541­
5509,
or
electronic
mail
at
mcdonald.
janet@
epa.
gov.

SUPPLEMENTARY
INFORMATION:

I.
General
Information
A.
What
are
the
regulated
entities?

Entities
potentially
affected
by
the
subject
rule
for
today's
action
are
fossil­
fuel
fired
boilers,
turbines,
and
internal
combustion
engines,
including
those
that
serve
generators
producing
electricity,
generate
steam
or
cogenerate
electricity
and
steam.

Industry
Group
SICa
NAICSb
Electric
Services
491
221111,
221112,
221113,
221119,

221121,
221122
Federal
government
221121
Fossil­
fuel
fired
electric
utility
steam
generating
units
owned
by
the
Federal
government
Internal
and
Deliberative­
Do
Not
Quote,
Cite,
Copy,
or
Distribute
September
30,
2005
8
State/
local/
Tribal
government
22112
Fossil­
fuel
fired
electric
utility
steam
generating
units
owned
by
municipalities.
Fossil­
fuel
fired
electric
utility
steam
generating
units
in
Indian
country.
a
Standard
Industrial
Classification
b
North
American
Industry
Classification
System.

Entities
potentially
affected
by
the
subject
rule
for
today's
action
also
include
State,
local,

and
tribal
governments.

B.
How
should
I
submit
CBI
to
the
Agency?

1.
Submitting
CBI.
Do
not
submit
this
information
that
you
consider
to
be
CBI
electronically
through
EDOCKET,
regulations.
gov
or
e­
mail.
Clearly
mark
the
part
or
all
of
the
information
that
you
claim
to
be
CBI.
For
CBI
information
in
a
disk
or
CD
ROM
that
you
mail
to
EPA,
mark
on
the
CD
ROM
the
specific
information
that
is
claimed
as
CBI.
In
addition
to
one
complete
version
of
the
comment
that
includes
information
claimed
as
CBI,
a
copy
of
the
comment
that
does
not
contain
the
information
claimed
as
CBI
must
be
submitted
for
inclusion
in
the
public
docket.
Information
so
marked
will
not
be
disclosed
except
in
accordance
with
procedures
set
forth
in
40
CFR
part
2.
Also,
send
an
additional
copy
clearly
marked
as
above
not
only
to
the
Air
Docket
but
to:
Mr.
Roberto
Morales,
OAQPS
Document
Control
Officer,
(
C339­
03),
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
NC
27711,
Attention
Docket
ID
No.
OAR­
2005­
0163.

C.
What
Should
I
Consider
as
I
prepare
My
Comments
for
EPA?

When
submitting
comments,
remember
to:
Internal
and
Deliberative­
Do
Not
Quote,
Cite,
Copy,
or
Distribute
September
30,
2005
9
1.
Identify
the
rulemaking
by
docket
number
and
other
identifying
information
(
subject
heading,
Federal
Register
date
and
page
number).

2.
Follow
directions
­
The
agency
may
ask
you
to
respond
to
specific
questions
or
organize
comments
by
referencing
a
Code
of
Federal
Regulations
(
CFR)
part
or
section
number.

3.
Explain
why
you
agree
or
disagree;
suggest
alternatives
and
substitute
language
for
your
requested
changes.

4.
Describe
any
assumptions
and
provide
any
technical
information
and/
or
data
that
you
used.

5.
If
you
estimate
potential
costs
or
burdens,
explain
how
you
arrived
at
your
estimate
in
sufficient
detail
to
allow
for
it
to
be
reproduced.

6.
Provide
specific
examples
to
illustrate
your
concerns,
and
suggest
alternatives.

7.
Explain
your
views
as
clearly
as
possible,
avoiding
the
use
of
profanity
or
personal
threats.

8.
Make
sure
to
submit
your
comments
by
the
comment
period
deadline
identified.

D.
How
Can
I
Find
Information
About
a
Possible
Public
Hearing?

People
interested
in
presenting
oral
testimony
or
inquiring
as
to
whether
a
hearing
is
to
be
held
should
contact
Ms.
Chandra
Kennedy,
Integrated
Implementation
Group,

Information
Transfer
and
Program
Integration
Division
(
C339­
03),
U.
S.
Environmental
Internal
and
Deliberative­
Do
Not
Quote,
Cite,
Copy,
or
Distribute
September
30,
2005
10
Protection
Agency,
Research
Triangle
Park,
NC
27711,
telephone
number
(
919)
541­
5319,

at
least
2
days
in
advance
of
the
public
hearing.
People
interested
in
attending
the
public
hearing
should
also
contact
Ms.
Kennedy
to
verify
the
time,
date,
and
location
of
the
hearing.
The
public
hearing
will
provide
interested
parties
the
opportunity
to
present
data,

views,
or
arguments
concerning
these
proposed
changes.

E.
How
is
this
preamble
organized?

The
information
presented
in
this
preamble
is
organized
as
follows:

I.
General
Information
A.
What
are
the
regulated
entities?
B.
How
should
I
submit
CBI
material
to
the
Agency?
C.
What
should
I
consider
as
I
prepare
my
comments?
D.
How
can
I
find
information
about
a
possible
public
hearing?
E.
How
is
this
preamble
organized?
II.
Overview
III.
Background
on
EGU
Emissions
and
Requirements
A.
SO2
and
NOx
Requirements
Before
1990
B.
SO
2
and
NOx
Requirements
After
1990
C.
Requirements
for
Pollutants
Other
Than
SO
2
and
NOx
IV.
Today's
Proposed
Rule
A.
Background
on
Existing
Regulations
B.
What
We
Are
Proposing
1.
Test
for
EGUs
Based
on
Maximum
Achievable
Hourly
Emissions
2.
Test
for
EGUs
Based
on
Maximum
Achieved
Hourly
Emissions
3.
Emissions
Test
Based
on
Energy
Output
C.
Pollutants
to
Which
the
Revised
Applicability
Test
Applies
D.
Significant
Emissions
Rates
E.
Eliminating
Netting
F.
Benefits
of
Maximum
Achievable
Hourly
Emissions
Test
G.
Would
States
be
required
to
adopt
the
revised
Emissions
Test?
V.
Statutory
and
Regulatory
History
and
Legal
Rationale
A.
The
NSPS
Program
B.
The
Major
NSR
Program
C.
Legal
Rationale
1.
Maximum
Achievable
Hourly
Emission
Test
Internal
and
Deliberative­
Do
Not
Quote,
Cite,
Copy,
or
Distribute
September
30,
2005
11
2.
Maximum
Achieved
Hourly
Emissions
Test
VI.
Statutory
and
Executive
Order
Reviews
A.
Executive
Order
12866
 
Regulatory
Planning
and
Review
B.
Paperwork
Reduction
Act
C.
Regulatory
Flexibility
Act
(
RFA)
D.
Unfunded
Mandates
Reform
Act
E.
Executive
Order
13132
 
Federalism
F.
Executive
Order
13175
 
Consultation
and
Coordination
with
Indian
Tribal
Governments
G.
Executive
Order
13045
 
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
H.
Executive
Order
13211
 
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
I.
National
Technology
Transfer
and
Advancement
Act
II.
Overview
In
today's
action,
we
are
proposing
to
revise
the
emissions
test
for
existing
EGUs
that
are
subject
to
the
regulations
in
the
major
NSR
programs
mandated
by
parts
C
and
D
of
title
I
of
the
CAA.
The
revised
emissions
test
is
the
same
as
that
in
the
NSPS
under
CAA
Section
111.
For
existing
EGUs,
we
are
proposing
to
compare
the
maximum
hourly
emissions
achievable
at
that
unit
during
the
past
5
years
to
the
maximum
hourly
emissions
achievable
at
that
unit
after
the
change
to
determine
whether
an
emissions
increase
would
occur.
This
maximum
achievable
hourly
emissions
test
would
apply
to
emissions
from
existing
EGUs.
Today's
proposal
would
not
affect
new
EGUs,
which
would
continue
to
be
subject
to
major
NSR
preconstruction
review.
These
proposed
regulations
interpret
CAA
section
111(
a)(
4),
in
the
context
of
NSR,
for
physical
changes
and
changes
in
the
method
of
operation
at
existing
EGUs.

Alternatively,
we
are
soliciting
public
comment
on
a
major
NSR
emissions
test
for
Internal
and
Deliberative­
Do
Not
Quote,
Cite,
Copy,
or
Distribute
September
30,
2005
2
The
Court
allowed
for
the
possibility
that
EPA
may
change
the
test
that
applies
through
future
rulemaking.

12
existing
EGUs
that
would
compare
maximum
hourly
emissions
achieved
before
a
change
to
the
maximum
hourly
emissions
achieved
after
the
change.
The
test
based
on
maximum
achievable
hourly
emissions
is
our
preferred
test,
but
we
are
also
soliciting
comment
on
this
test
based
on
maximum
achieved
hourly
emissions.

We
also
request
comment
on
adopting
an
NSR
emissions
test
based
on
mass
of
emissions
per
unit
of
energy
output,
such
as
lb/
MW
hour
or
nanograms
per
Joule.
As
we
discuss
in
more
detail
in
Section
IV.
B.
3.
of
this
preamble,
an
output­
based
emissions
test
encourages
use
of
energy
efficient
EGU
that
displace
less
efficient,
more
polluting
units.

The
proposed
regulations
would
establish
a
uniform
emissions
test
nationally
under
the
NSPS
and
NSR
programs
for
existing
EGUs.
The
need
to
provide
national
consistency
for
EGUs
is
apparent
following
a
recent
Fourth
Circuit
Court
of
Appeals
decision.
On
June
15,
2005,
the
Fourth
Circuit
Court
of
Appeals
ruled
that
EPA
must
use
a
consistent
definition
of
the
term
"
modification"
for
the
purposes
of
both
the
NSPS
program
under
Section
111
of
the
Act
and
NSR
program
under
parts
C
and
D
of
the
Act.
The
court
further
ruled
that
because
EPA
had
promulgated
NSPS
regulations
with
a
test
based
on
increases
in
a
plant's
hourly
rate
of
emissions
prior
to
enactment
of
the
PSD
provision
of
the
statute,
and
the
PSD
regulations
had
to
be
interpreted
congruently
to
include
the
same
hourly
test.
22
See
United
States
v.
Duke
Energy
Corp.,
No.
04­
1763
(
4th
Cir.
June
15,

2005).
The
Fourth
Circuit
denied
the
United
States'
petition
for
rehearing
concerning
this
Internal
and
Deliberative­
Do
Not
Quote,
Cite,
Copy,
or
Distribute
September
30,
2005
3
We
continue
to
respectfully
disagree
with
the
Fourth
Circuit's
decision
in
Duke
Energy
and
continue
to
believe
that
we
have
the
authority
to
define
"
modification"
differently
in
the
NSPS
and
NSR
programs.
However,
we
believe
that
the
action
that
we
propose
today
is
an
appropriate
exercise
of
our
discretion.

13
decision,
although
the
deadline
for
filing
a
petition
for
certiorari
has
not
yet
run.
3
The
NSPS
program
applies
a
maximum
achievable
hourly
emissions
rate
test
to
determine
whether
a
physical
change
or
change
in
the
operation
(
physical
or
operational
change)

results
in
an
emissions
increase.
Once
the
mandate
is
issued
in
the
Duke
Energy
case,
the
NSPS
test
will
apply
in
all
Fourth
Circuit
States,
unless
the
NSR
test
in
those
States'

implementation
plans
is
more
stringent
than
the
NSPS
test.
This
holding
creates
a
potential
disparity
in
the
way
we
interpret
the
program
in
States
in
the
Fourth
Circuit
compared
to
States
in
other
Circuits
in
the
country.
By
finalizing
today's
proposed
rule,
we
would
provide
nationwide
consistency
in
how
States
implement
the
major
NSR
program
for
EGUs
and
establish
a
test
consistent
with
the
Fourth
Circuit's
holding
in
Duke
Energy.
We
would
also
make
a
uniform
emissions
test
under
the
NSPS
and
NSR
programs
for
existing
EGUs.

We
believe
a
uniform
national
emissions
test
has
particular
merit
considering
the
substantial
emissions
reductions
from
other
CAA
requirements
that
are
more
efficient
than
major
NSR,
which
we
describe
in
Section
III
of
this
preamble.
Furthermore,
the
proposed
regulations
allow
owner/
operators
to
make
changes
that,
without
increasing
existing
capacity,
promote
the
safety,
reliability,
and
efficiency
of
EGUs.
The
current
major
NSR
approach
discourages
sources
from
replacing
components,
and
encourages
them
to
replace
Internal
and
Deliberative­
Do
Not
Quote,
Cite,
Copy,
or
Distribute
September
30,
2005
14
components
with
inferior
components
or
to
artificially
constrain
production
in
other
ways.

This
behavior
does
not
advance
the
central
policy
goals
of
the
major
NSR
program
as
applied
to
existing
sources.
The
central
policy
goal
is
not
to
limit
productive
capacity
of
major
stationary
sources,
but
rather
to
ensure
that
they
will
install
state­
of­
the­
art
pollution
controls
at
a
juncture
where
it
otherwise
makes
sense
to
do
so.
We
also
do
not
believe
the
outcomes
produced
by
the
approach
we
have
been
taking
have
significant
environmental
benefits
compared
with
the
approach
we
are
proposing
today.

In
the
following
sections
of
this
preamble,
we
provide
details
on
the
EGU
requirements
and
emissions,
today's
proposed
rule,
and
the
legal
basis
for
our
proposal.

We
request
public
comment
on
all
aspects
of
today's
proposed
action.
We
intend
to
publish
a
supplemental
proposal
in
the
near
future
that
will
include
proposed
regulatory
language,
as
well
as
additional
data
and
information.

III.
Background
on
EGU
Requirements
and
Emissions
In
this
section
we
describe
the
regulatory
history
and
programs
applying
to
EGUs.

These
include
the
command­
and­
control
strategies
such
as
NSPS
and
major
NSR
that
went
into
effect
before
1990,
as
well
as
the
more
efficient
programs
since
1990
that
have
achieved
substantial
reductions
in
EGU
emissions.

A.
SO2
and
NOx
Requirements
Before
1990
Beginning
in
1970,
the
CAA
and
our
implementing
regulations
have
imposed
numerous
requirements
on
sulfur
dioxide
(
SO
2)
and
nitrous
oxide
(
NOx)
emissions
from
utilities.
In
the
early
regulatory
history
under
the
CAA,
these
requirements
were
limited
to
Internal
and
Deliberative­
Do
Not
Quote,
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Copy,
or
Distribute
September
30,
2005
15
the
NSPS
and
major
NSR
programs.
The
NSPS
program
applies
to
EGUs
and
other
stationary
sources
of
pollutants,
including
SO
2,
NOx,
particulate
matter
(
PM),
carbon
monoxide
(
CO),
ozone,
and
lead,
among
others.
The
Act
required
us
to
develop
NSPS
for
a
number
of
source
categories,
including
coal­
fired
power
plants.
The
first
NSPS
for
EGUs
(
40
CFR
Part
60,
subpart
D)
required
new
units
to
limit
SO2
emissions
either
by
using
scrubbers
or
by
using
low
sulfur
coal.
It
required
limits
on
NOx
emissions
through
the
use
of
low
NOx
burners.
A
new
NSPS
(
40
CFR
Part
60,
subpart
Da),
promulgated
in
1978,
tightened
the
standards
for
SO2,
requiring
scrubbers
on
all
new
units.

Preconstruction
permitting
for
EGUs
and
other
new
stationary
sources
was
considered
in
1970,
but
not
added
to
the
CAA
until
it
was
amended
again
in
1977.
The
preconstruction
program
for
major
stationary
sources
is
commonly
called
the
major
NSR
program.
As
we
discuss
in
further
detail
in
Section
V.
B.
of
this
preamble,
the
major
NSR
program
required
emission
limitations
based
on
Best
Available
Control
Technology
(
BACT)
and
Lowest
Achievable
Emission
Rate
(
LAER)
controls.

The
NSPS
and
major
NSR
programs
imposed
limitations
on
EGU
SO
2
and
NOx
emissions
at
individual
sources
based
on
control
technology
performance.
They
did
not
set
specific
limits
on
the
total
regional
or
national
emissions
from
EGUs.
Neither
of
these
programs
apply
to
EGUs
that
were
already
in
existence
before
the
regulations
were
effective,
unless
these
EGUs
choose
to
modify.
Thus,
neither
program
applies
to
all
EGUs.

Before
1990,
however,
the
major
NSR
program
did
provide
States
one
of
the
few
opportunities
to
mitigate
rising
levels
of
air
pollution
through
regulation
of
possible
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and
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30,
2005
4
The
Acid
Rain
Program
generally
applies
to
all
fossil­
fuel
fired
combustion
devices
that,
if
commencing
commercial
operation
before
November
15,
1990,
serve
on
or
after
November
15,
1990
a
generator
greater
than
25
MW
producing
electricity
for
sale
and
that,
if
commencing
commercial
operation
on
or
after
November
15,
1990,
serve
on
or
after
November
15,
1990
any
generator
producing
electricity
for
sale.
The
Acid
Rain
Program
does
not
apply
to
a
small
portion
of
the
national
EGU
inventory,
including
some
cogeneration
units
(
many
of
which
are
natural­
gas
fired),
certain
independent
power
producers,
and
solid
waste
incineration
units.

16
emissions
increases
from
existing
sources.
Therefore,
the
program
was
consistent
with
Congress'
directive
that
the
major
NSR
program
be
tailored
to
balance
the
"
need
for
environmental
protection
against
the
desires
to
encourage
economic
growth."

B.
SO
2
and
NOx
Requirements
After
1990
The
1990
Amendments
to
the
CAA
imposed
a
number
of
new
requirements
on
EGUs.
The
Acid
Rain
Program,
established
under
title
IV
of
the
1990
CAA
Amendments,

requires
major
reductions
of
SO2
and
NOx
emissions.
The
SO2
program,
which
covers
most
EGU
in
the
contiguous
United
States4,
sets
a
permanent
cap
on
the
total
amount
of
SO2
that
can
be
emitted
by
EGUs
at
about
one­
half
of
the
amount
of
SO2
these
sources
emitted
in
1980.
Using
a
market­
based
cap­
and­
trade
mechanism
allows
flexibility
for
individual
combustion
units
to
select
their
own
methods
of
compliance.
The
program
requires
NOx
emission
limitations
for
certain
coal­
fired
EGUs,
with
the
objective
of
achieving
a
2
million
ton
reduction
from
projected
NOx
emission
levels
that
would
have
been
emitted
in
the
year
2000
without
implementation
of
Title
IV.

The
Acid
Rain
Program
at
40
CFR
parts
72
through
78
comprises
two
phases
for
SO2
and
NOx.
Phase
I
applied
primarily
to
the
largest
coal­
fired
electric
generation
sources
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September
30,
2005
5
63
FR
57356,
October
27,
1998.

17
from
1995
through
1999
for
SO2
and
from
1996
through
1999
for
NOx.
Phase
II
for
both
pollutants
began
in
2000.
For
SO2,
it
applies
to
thousands
of
combustion
units
generating
electricity
nationwide;
for
NOx
it
generally
applies
to
affected
units
nationwide
that
burned
coal
during
the
period
between
1990
and
1995.
The
Acid
Rain
Program
has
led
to
the
installation
of
scrubbers
on
a
number
of
existing
coal­
fired
units,
as
well
as
significant
fuel
switching
to
lower
sulfur
coals.
Under
the
NOx
provisions
of
Title
IV,
most
existing
coalfired
units
were
required
to
install
low
NOx
burners.

The
1990
CAA
also
placed
much
greater
emphasis
on
interstate
transport
of
ozone
and
its
precursors,
and
on
control
of
NOx
to
reduce
ozone
nonattainment.
This
led
to
the
formation
of
several
regional
NOx
trading
programs.
In
1998,
EPA
promulgated
regulations,
known
as
the
NOx
SIP
Call5,
that
required
21
states
in
the
eastern
United
States
and
the
District
of
Columbia
to
reduce
NOx
emissions
that
contributed
to
nonattainment
in
downwind
States.
EPA
based
the
reduction
requirements
on,
and
States
implemented
those
requirements
through,
a
cap­
and­
trade
approach
targeted
to
EGUs.

This
program
has
resulted
in
the
installation
of
significant
amounts
of
selective
catalytic
reduction
(
SCR).
The
first
SCR
application
in
the
U.
S.
on
a
coal­
fired
boiler
started
operating
in
1993.
At
the
end
of
2002,
56
U.
S.
boilers
were
operating
with
SCR.

By
notice
dated
May
12,
2005
[
70
FR
25162],
we
promulgated
the
Clean
Air
Interstate
Rule
(
CAIR)
to
reduce
interstate
transport
of
SO
2
and
NOx
emissions.
This
rule
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and
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September
30,
2005
6
The
proposed
test
would
not
apply
to
all
cogeneration
units.
It
would
apply
only
to
those
EGU
that
§
§
96.104,
96.204,
and
96.304
identify.
On
August
24,
2005
[
70
FR
49708],
we
18
established
statewide
emission
reduction
requirements
for
SO
2
and
NOx
for
States
in
the
CAIR
region.
The
emission
reduction
requirements
are
based
on
controls
that
are
known
to
be
highly
cost
effective
for
EGUs.
This
program
was
based
on
extensive
experience
in
the
Acid
Rain
and
NOx
SIP
Call
cap­
and­
trade
programs
for
major
sources
of
SO
2
and
NOx.

In
the
CAIR,
we
took
final
action
requiring
28
States
and
the
District
of
Columbia
to
adopt
and
submit
revisions
to
their
State
Implementation
Plans
(
SIPs),
under
the
requirements
of
CAA
section
110(
a)(
2)(
D),
that
would
eliminate
specified
amounts
of
SO
2
and/
or
NOx
emissions.
In
developing
the
CAIR,
we
made
a
determination
that
EGUs
in
States
not
affected
by
CAIR
are
not
having
an
impact
on
downwind
areas.
Therefore,

there
was
no
air
quality
reason
to
regulate
those
EGUs
under
the
CAIR.

Each
State
covered
by
CAIR
may
independently
determine
which
emission
sources
to
control,
and
which
control
measures
to
adopt.
Our
analysis
indicates
that
emissions
reductions
from
EGUs
are
highly
cost
effective,
and
we
encourage
States
to
base
their
CAIR
SIP
programs
on
emissions
reductions
from
EGUs.
States
that
do
so
may
allow
their
EGUs
to
participate
in
an
EPA­
administered
cap­
and­
trade
program
as
a
way
to
reduce
the
cost
of
compliance,
and
to
provide
compliance
flexibility.
The
EPAadministered
cap­
and­
trade
program
includes
fossil­
fuel
fired
boilers,
combustion
turbines,

and
certain
cogeneration
units6
with
nameplate
capacity
of
more
than
25
MWe
producing
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Deliberative­
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September
30,
2005
proposed
changes
to
§
§
96.104
and
96.204
to
exclude
units
(
serving
a
greater­
than­
25
MW
generator)
that
stopped
operating
before
November
15,
1990
and
do
not
resume.
In
this
notice,
we
also
proposed
changes
to
the
definition
of
"
EGU"
to
exclude
certain
solid
waste
incineration
units.

7
For
allowances
of
vintage
years
2010­
2014,
each
allowance
authorizes
the
emission
of
half
a
ton
of
SO
2
for
a
calendar
year.
For
allowances
of
vintage
years
2015
and
beyond,
each
allowance
authorizes
the
emission
of
0.35
ton
of
SO
2
for
a
calendar
year.
See
70
FR
25258,
May
12,
2005.
See
also
40
CFR
96.202.

19
or
supplying
electricity
for
sale
as
defined
in
40
CFR
96.104
and
96.204.
Some
of
these
units
have
never
been
subject
to
major
NSR
because
they
commenced
construction
before
the
effective
date
of
the
major
NSR
regulations,
and
they
have
never
undertaken
modifications.
CAIR
Units
must
hold
annual
allowances.
Each
allowance
authorizes
the
emission
of
one
ton
of
NOx
for
a
specified
calendar
year.
For
SO
2
allowances
with
vintage
in
the
years
before
2010,
each
allowance
authorizes
the
emission
of
one
ton
of
SO
2
for
a
calendar
year.
For
2010
and
beyond,
each
allowance
authorizes
the
emission
of
less
than
one
ton
of
SO
2
per
year.
7
The
CAIR
emissions
reductions
will
be
implemented
in
two
phases,
one
beginning
in
2009
(
2010
for
SO
2)
and
a
second
beginning
in
2015.
CAIR
Units
are
subject
to
stringent
monitoring,
recordkeeping,
and
reporting
requirements.

Owner/
operators
must
monitor
and
report
CAIR
Unit
emissions
using
CEMS
or
other
monitoring
methodologies
that
are
as
precise,
reliable,
accurate,
and
timely
according
to
the
requirements
in
40
CFR
Part
75.
Source
information
management,
emissions
data
reporting,
and
allowance
trading
occur
through
EPA­
administered
online
systems.
Any
source
found
to
have
excess
emissions
must
surrender
allowances
sufficient
to
offset
excess
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September
30,
2005
8
For
a
complete
description
of
requirements
for
CAIR
Units
under
the
EPA­
administered
trading
program,
see
70
FR
25162.

9
See
our
Regulatory
Impact
Analysis
for
the
CAIR
at
6­
9.
The
RIA
is
available
at
http://
www.
epa.
gov/
air/
interstateairquality/
pdfs/
finaltech08.
pdf.

20
emissions
and
surrender
future
allowances
equal
to
three
times
the
excess
emissions.
8
The
CAIR
will
result
in
significant
reductions
in
SO
2
and
NOx
emissions
across
the
region
that
it
covers.
CAIR,
if
implemented
through
controls
on
EGUs,
would
result
in
EGU
emissions
reductions
in
the
CAIR
States
of
roughly
73
percent
for
SO
2
and
61
percent
for
NOx
from
2003
levels.
The
rule
would
affect
roughly
3,000
fossil­
fuel­
fired
units.
As
Table
1
Shows,
these
sources
accounted
for
roughly
89
percent
of
nationwide
SO
2
emissions
and
79
percent
of
nationwide
NOx
emissions
from
EGUs
in
2003.
9
Table
1.
EGU
SO2
and
NOx
Emissions
in
2003
and
Percentage
of
Emissions
in
the
CAIR
Affected
Region
(
tons)

SO2
NOx
CAIR
Region
9,407,406
3,222,636
Nationwide
10,595,069
4,165,026
CAIR
Emissions
as
%
Nationwide
89%
79%

Note:
Region
includes
States
covered
for
the
annual
SO2
and
NOx
trading
programs
(
Alabama,
District
of
Columbia,
Florida,
Georgia,
Illinois,
Indiana,
Iowa,
Kentucky,
Louisiana,
Maryland,
Michigan,
Minnesota,
Mississippi,
Missouri,
New
York
,
North
Carolina,
Ohio,
Pennsylvania,
South
Carolina,
Tennessee,
Texas,
Virginia,
West
Virginia,
and
Wisconsin).
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and
Deliberative­
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or
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September
30,
2005
10
These
data
are
from
EPA's
most
recent
Integrated
Planning
Model
(
IPM)
modeling
reflecting
the
final
CAIR
as
promulgated
at
70
FR
25162.
Please
see
the
final
CAIR
rule
at
70
FR
25162
for
a
complete
description
of
the
assumptions
related
to
these
data.

11
The
banking
provisions
of
the
cap­
and­
trade
program
encourage
sources
to
make
significant
reductions
before
2010.
Such
early
reductions
are
beneficial
because
they
encourage
greater
health
benefits
sooner.
However,
due
to
the
use
of
banked
allowances,
EPA
does
not
project
that
these
caps
will
be
met
in
2010
or
2015.

21
We
estimate
that
the
CAIR
will
reduce
SO
2
emissions
by
3.5
million
tons10
in
2010
and
by
3.8
million
tons
in
2015.
We
also
estimate
that
it
will
reduce
annual
NOx
emissions
by
1.2
million
tons
in
2009
and
by
1.5
million
tons
in
2015.
(
These
numbers
are
for
the
23
States
and
the
District
of
Columbia
that
are
affected
by
the
annual
SO
2
and
NOx
requirements
of
CAIR.)
If
all
the
affected
States
choose
to
achieve
these
reductions
through
EGU
controls,
then
EGU
SO
2
emissions
in
the
affected
States
would
be
capped
at
3.6
million
tons
in
2010
and
2.5
million
tons
in
201511,
and
EGU
annual
NOx
emissions
would
be
capped
at
1.5
million
tons
in
2009
and
1.3
million
tons
in
2015.

The
CAIR
will
also
improve
air
quality
in
all
areas
of
the
eastern
U.
S.
We
estimate
that
the
required
SO
2
and
NOx
emissions
reductions
will,
by
themselves,
bring
into
attainment
52
of
the
79
counties
that
are
otherwise
projected
to
be
in
nonattainment
for
PM
2.5
in
2010,
and
57
of
the
74
counties
that
are
otherwise
projected
to
be
in
nonattainment
for
PM
2.5
in
2015.
We
further
estimate
that
the
required
NOx
emissions
reductions
will,
by
themselves,
bring
into
attainment
three
of
the
40
counties
that
are
otherwise
projected
to
be
in
nonattainment
for
8­
hour
ozone
in
2010,
and
six
of
the
22
Internal
and
Deliberative­
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Quote,
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or
Distribute
September
30,
2005
12
70
FR
25165
13
U.
S.
EPA,
Regulatory
Impact
Analysis
for
the
CAIR
at
pg.
7­
5.
Available
at
http://
www.
epa.
gov/
air/
interstateairquality/
pdfs/
finaltech08.
pdf.
For
more
information
about
the
highly
cost
effective
controls
for
EGUs
that
were
used
to
establish
the
emissions
reductions
under
the
CAIR,
see
also
69
FR
4612.

22
counties
that
are
otherwise
projected
to
be
in
nonattainment
for
8­
hour
ozone
in
2015.12
In
addition,
the
CAIR
will
improve
PM
2.5
and
8­
hour
ozone
air
quality
in
the
areas
that
would
remain
nonattainment
for
those
two
NAAQS
after
implementation
of
the
rule.
The
CAIR
will
also
reduce
PM
2.5
and
8­
hour
ozone
levels
in
attainment
areas.

To
determine
the
statewide
emission
caps
under
the
CAIR,
we
assumed
the
application
of
highly
cost­
effective
control
measures
to
EGUs
and
determined
the
emissions
reductions
that
would
result.
Specifically,
we
modeled
emissions
reductions
using
the
Integrated
Planning
Model
(
IPM)
with
wet
and
dry
desulfurization
(
FGD,

commonly
known
as
scrubbers)
technologies
for
SO
2
control
and
SCR
technology
for
NOx
control
on
coal­
fired
boilers.
13
These
are
fully
demonstrated
and
available
pollution
control
technologies.
The
design
and
performance
levels
for
these
technologies
were
based
on
proven
industry
experience.

We
expect
many
EGUs
to
install
scrubbers
and
SCR
to
meet
the
emissions
reductions
required
under
the
CAIR.
As
a
result
of
the
CAIR,
we
project
installation
of
scrubbers
on
an
additional
64
GW
of
existing
coal­
fired
generation
capacity
for
SO
2
control
and
SCR
on
an
additional
34
GW
of
existing
coal­
fired
generation
capacity
for
NOx
control
by
2015.
By
2020,
we
expect
installation
of
scrubbers
on
an
additional
82
GW
of
Internal
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September
30,
2005
14
See
CAIR
RIA
at
7­
8
and
7­
9.
The
CAIR
RIA
is
available
at
http://
www.
epa.
gov/
air/
interstateairquality/
technical.
html.
In
1999,
total
electric
generating
capacity
was
781
GW,
of
which
utilities
accounted
for
approximately
85
percent.
U.
S.
EPA
NSR
90­
Day
Review
Background
Paper,
pg.
12.
Document
II­
A­
01,
available
in
Docket
A­
2001­
19.

23
existing
coal­
fired
generation
capacity
for
SO
2
control
and
SCR
on
an
additional
33
GW
of
existing
coal­
fired
generation
capacity
for
NOx
control.
14
In
the
western
half
of
the
U.
S.
and
other
States
where
CAIR
will
not
apply,
the
Best
Available
Retrofit
Technology
(
BART)
requirements
of
the
regional
haze
rule
will
also
apply
to
EGUs
that
may
not
be
subject
to
major
NSR.
The
regional
haze
rule
requires
all
States
to
take
steps
in
their
implementation
plans
to
improve
visibility
in
Class
I
areas.

[
64
FR
35714
(
July
1,
1999);
70
FR
39104
(
July
6,
2005)]
Under
the
regional
haze
program,
States
are
to
address
all
types
of
manmade
emissions
contributing
to
visibility
impairment
in
Class
I
areas,
including
those
from
mobile
sources,
stationary
sources
(
such
as
EGUs),
area
sources
such
as
residential
wood
combustion
and
gas
stations,
and
prescribed
fires.
[
See
CAA
section
169(
b)(
2)(
A)
and
(
g)(
7)]
specifically
require
installation
of
BART
for
emissions
of
visibility­
impairing
pollutants
(
for
example,
SO
2
and
NOx)
from
certain
existing
stationary
sources,
including
large
EGUs.
The
CAA
defines
a
BART­
eligible
source
as
a
stationary
source
of
air
pollutants
that
falls
within
one
of
26
listed
categories
and
that
was
put
into
operation
between
August
7,
1962
and
August
7,

1977,
with
the
potential
to
emit
250
tons
per
year
of
any
visibility­
impairing
pollutant.

[
CAA
Section
169(
b)(
2)(
A)
and
(
g)(
7);
40
CFR
51.301.]
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and
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September
30,
2005
15
70
FR
39104
(
July
6,
2005)

24
We
issued
guidelines
for
implementing
BART
requirements,
15
including
presumptive
BART
control
levels
for
emissions
of
SO
2
and
NOx
from
utility
boilers
located
at
power
plants
over
750
MW.
Those
presumptive
BART
control
levels
are
based
on
cost
effective
controls.
As
explained
in
the
guidelines,
as
a
general
matter
States
must
require
owners
and
operators
of
greater
than
750
MW
power
plants
to
meet
these
BART
emission
limits.
In
addition,
while
States
are
not
required
to
follow
these
guidelines
for
EGUs
located
at
power
plants
with
a
generating
capacity
of
less
than
750
MW,
based
on
our
analysis,
we
believe
that
States
will
find
these
same
presumptive
controls
to
be
highly
cost
effective,
and
to
result
in
a
significant
degree
of
visibility
improvement,
for
most
EGUs
greater
than
200
MW,
regardless
of
the
size
of
the
plant
at
which
they
are
located.

Regional
haze
is
the
result
of
air
pollutants
emitted
by
numerous
sources
over
a
wide
geographic
region.
As
a
result,
EPA
has
encouraged
States
to
work
together
in
developing
and
implementing
their
air
quality
plans
addressing
regional
haze.
In
fact,
the
States
have
been
working
together
in
regional
planning
organizations
to
develop
regional
plans.
Moreover,
we
have
proposed
a
process
by
which
States
may
use
an
emissions
trading
program
in
place
of
facility­
by­
facility
BART
requirements.
In
these
aspects,
the
requirements
for
BART
are
similar
to
those
under
the
CAIR.
We
expect
that
like
the
CAIR,
the
BART
requirements
will
reduce
regional
SO
2
and
NOx
emissions
from
EGUs
in
a
cost­
effective
manner.
Internal
and
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September
30,
2005
16
That
is,
these
are
the
reductions
that
are
estimated
to
occur
under
Scenario
2
in
addition
to
the
reductions
that
are
estimated
to
occur
under
CAIR.
See
BART
RIA
at
3­
6.
Regulatory
Impact
Analysis
for
the
Final
Clean
Air
Visibility
Rule
or
the
Guidelines
for
Best
Available
Retrofit
Technology
(
BART)
Determinations
Under
the
Regional
Haze
Regulations.
EPA­
452/
R­
05­
004.
U.
S.
Environmental
Protection
Agency,
June
2005.
Available
at:
http://
www.
epa.
gov/
oar/
visibility/
actions.
html.

25
We
developed
three
scenarios
to
project
the
nationwide
EGU
SO
2
and
NOx
emissions
reductions
under
BART.
Under
the
medium
stringency
scenario
(
Scenario
2),

we
estimate
that
BART
controls
will
result
in
annual
NOx
reductions
of
585,459
tons,

about
a
9.6
percent
reduction;
and
in
annual
SO
2
reductions
of
390,224
tons,
about
a
2.3
percent
reduction,
over
the
2015
base
case.
16
Under
Scenario
2,
BART
is
projected
to
result
in
the
installation
of
scrubbers
on
an
additional
6.2
GW
of
existing
coal­
fired
generation
capacity
for
SO2
control
in
2015
(
relative
to
CAIR).
For
NOx
control,
this
BART
scenario
is
also
projected
to
result
in
installation
of
combustion
control
equipment
on
an
additional
24
GW
of
on
cyclone­
boiler
coal­
fired
generation
capacity
by
2015,
as
well
as
installation
of
SCR
on
an
additional
2.4
GW
of
SCR
on
cyclone­
boiler
coal­
fired
generation
capacity
by
2015.

We
have
conducted
analyses
based
on
emission
projections
and
air
quality
modeling
showing
that
CAIR
will
achieve
greater
reasonable
progress
towards
the
national
visibility
goal
than
would
BART
for
affected
EGUs.
In
our
final
BART
rule
(
70
FR
39104),
we
thus
promulgated
regional
haze
rule
revisions
allowing
States
to
treat
CAIR
as
an
in­
lieu­
of
BART
program
for
SO
2
and
NOx
revisions
from
EGUs
in
CAIR­
affected
States.
The
criteria
for
making
"
better
than
BART"
determinations
have
now
been
codified
in
the
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30,
2005
17
Major
stationary
sources
of
regulated
NSR
pollutants
that
commenced
construction
on
or
after
August
7,
1977
are
subject
to
requirements
under
major
NSR,
including
meeting
emissions
limitations
based
on
BACT
or
LAER.
To
be
BART
eligible,
an
EGU
must
have
commenced
operation
between
August
7,
1962
and
August
7,
1977.
Thus,
due
to
their
construction
date,
BART­
eligible
EGUs
are
not
subject
to
major
NSR
unless
they
modify.

26
regional
haze
rule
at
40
CFR
51.308(
e)(
3).
We
thus
expect
EGUs
in
CAIR­
affected
States
to
be
subject
to
CAIR
SO
2
and
NOx
requirements
rather
than
to
BART.

We
are
aware
that
there
are
some
EGUs
that
would
not
be
subject
to
the
Acid
Rain
Program,
CAIR,
or
BART,
and
that
also
would
not
be
subject
to
major
NSR
unless
they
choose
to
modify.
17
The
first
set
of
these
EGUs
is
those
that
are
not
in
CAIR
affected
States,
and
that
are
BART
eligible
but
are
not
subject
to
BART.
Assuming
Scenario
2,

there
would
be
approximately
28
coal­
fired
EGUs
that
are
BART­
eligible,
not
in
the
CAIR
region,
and
have
a
capacity
less
than
200
MW.
The
total
capacity
for
these
28
units
is
approximately
4
GW,
less
than
one
half
of
a
percent
of
current
national
capacity.
Of
these
28
units,
approximately
3
GW
have
NOx
controls
and
approximately
2
GW
have
SO2
controls.
There
are
approximately
47
oil
or
gas­
fired
EGUs
that
are
BART­
eligible,
not
in
the
CAIR
region,
and
have
a
capacity
less
than
200
MW.
The
total
capacity
for
these
47
units
is
approximately
5
GW,
also
less
than
one
half
of
a
percent
of
national
capacity.
Of
these
47
units,
approximately
1
GW
have
NOx
controls.
Of
these
47
units,
41
are
gasfired
Gas­
fired
EGU
are
clean
burning
and
generally
emit
very
small
amounts
of
SO2.

The
main
control
strategy
for
SO2
emissions
from
oil­
fired
units
is
using
lower­
sulfur
fuel.

The
second
set
of
EGUs
that
may
not
be
subject
to
any
control
requirements
are
Internal
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or
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30,
2005
18
Information
received
from
Mikhail
Adamantiades,
U.
S.
EPA,
Clear
Air
Markets
Division
and
available
in
the
docket.

27
those
in
the
non­
CAIR
States
that
are
not
subject
to
major
NSR
and
are
not
BARTeligible
Some
EGUs
that
are
located
in
non­
CAIR
States
and
that
began
operation
on
or
before
August
7,
1962
would
not
be
BART­
eligible.
These
units
would
not
be
subject
to
either
BART
or
CAIR,
nor
would
they
be
subject
to
major
NSR.
Some
may
be
subject
to
the
Acid
Rain
Program.
Our
IPM
database
18
shows
that
there
is
a
total
of
about
2.1
GW
of
coal
capacity
(
less
than
one
half
of
a
percent
of
national
capacity)
outside
the
CAIR
region
that
was
constructed
or
began
operations
before
1962.
This
capacity
represents
about
37
units
at
about
20
plants,
ranging
in
capacity
from
5­
120
MW.
We
estimate
that
about
25
of
these
units
have
a
potential
to
emit
SO
2
and
NOx
that
is
high
enough
that
they
would
have
been
subject
to
major
NSR
if
they
had
been
constructed
later.
Of
these
25
units,
four
have
NOx
controls
and
two
have
SO
2
controls.
The
20
plants
are
geographically
dispersed.

Thus,
as
we
explain
above,
there
are
a
small
number
of
EGUs
that
may
not
be
required
to
control
emissions
under
any
program,
but
they
comprise
a
very
small
portion
of
the
national
capacity
and
will
have
a
minimal
impact
on
emissions.
As
we
note
in
Table
1,

approximately
90
percent
of
nationwide
EGU
SO
2
emissions
and
approximately
80
percent
of
nationwide
EGU
NOx
emissions
are
from
EGU
in
the
CAIR
affected
region.

Furthermore,
we
note
that
EGUs,
including
non­
CAIR
EGUs,
are
subject
to
national
caps
on
SO
2
emissions
through
the
Acid
Rain
Program
requirements.
We
therefore
believe
that
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September
30,
2005
19
Modeled
1990
baseline
emissions
from
John
Robbins.
Reductions
based
on
2015
projected
emissions
for
EGUs
greater
than
25
MW,
assuming
BART
Scenario
2
(
medium
stringency
scenario).
These
projected
reductions
assume
control
requirements
under
CAIR,
the
Acid
Rain
Program,
BART
(
Scenario
2),
and
State
rules.
Under
BART
Scenario,
our
IPM
modeling
assumes
control
of
all
EGU
at
least
200
MW,
regardless
of
the
size
of
the
plant
at
which
the
EGU
is
located.
See
BART
RIA
at
7­
7.

28
any
EGUs
that
might
remain
uncontrolled
would
have
a
negligible
impact
on
national
emissions
of
regulated
NSR
pollutants.

Finally,
as
Table
2
below
shows,
substantial
reductions
in
SO
2
and
NOx
emissions
are
projected
to
occurred
following
the
imposition
of
these
market­
based
strategies
after1990.

Table
2
Reduction
In
EGU
National
Annual
Emissions19
(
in
thousands
of
tons
per
year)

1990
2015
Emission
Reduction
Percent
Reduction
SO2
(
Annual)
15,700
4,770
10,930
70
NOx
(
Annual)
6,700
1,916
4,784
71
The
figure
below
shows
the
national
reductions
in
EGU
SO
2
and
NOx
emissions
that
have
occurred
to
date,
and
that
we
expect
to
occur,
due
to
these
programs.
In
addition,
we
expect
further
reductions
from
implementation
of
BART.
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and
Deliberative­
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September
30,
2005
20
Data
from
EPA
Office
of
Air
and
Radiation,
Clean
Air
Markets
Division,
available
in
EPA
Docket
OAR
2005­
0163.

29
0
5
10
15
20
1980
1985
1990
1995
2000
2005
2010
2015
2020
Million
Tons
Nationwide
SO2
and
NOx
Emissions
from
the
Power
Sector
SO
2
NOx
Source:
EPA
Projected,
w/
CAIR
These
reductions
in
national
emissions
for
the
utility
sector
are
especially
significant
considering
that
national
capacity
continues
to
increase.
In
1990,
national
nameplate
capacity
for
EGUs
was
692,935
MW,
in
2002
it
was
758,756
MW,
and
in
2015
we
anticipate
it
to
be
776,377
MW.
20
In
summary,
since
the
1990
CAA
Amendments,
additional
requirements
for
EGUs
have
applied
under
the
Acid
Rain
Program
and
the
NOx
SIP
Call,
and
will
apply
under
the
CAIR.
These
programs
apply
or
will
apply
to
all
EGUs,
regardless
of
when
the
EGUs
were
constructed
or
began
operating.
More
importantly,
these
national
or
regional
trading
programs
set
permanent
caps
on
SO
2
and
NOx
emissions
from
the
utility
sector
as
a
whole.
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30,
2005
30
Notably,
the
CAIR
will
permanently
cap
SO
2
and
NOx
emissions
from
EGU
in
the
CAIR
region,
which
covers
approximately
80
percent
of
national
electric
generating
capacity.

Despite
growth
in
the
sector,
these
programs
have
substantially
reduced
SO
2
and
NOx
emissions
from
EGUs
and
even
more
substantial
reductions
will
occur
as
a
result
of
the
CAIR.
The
BART
program
will
further
reduce
national
EGU
SO
2
and
NOx
emissions.

The
Acid
Rain,
NOx
SIP
Call
and
CAIR
programs
ensure
no
overall
growth
in
SO2
and
NOx
emissions
from
the
sector
as
a
whole.
As
a
result,
they
serve
a
function
similar
to
that
under
major
NSR
of
balancing
environmental
goals
and
encouraging
economic
growth.

As
we
discuss
in
more
detail
in
Section
V.
B.
of
this
preamble,
the
primary
purpose
of
the
major
NSR
program
is
not
to
reduce
emissions,
but
to
balance
the
need
for
environmental
protection
and
economic
growth.
That
is,
the
goal
of
major
NSR
is
to
minimize
emissions
increases
from
new
source
growth.
The
major
NSR
approach
we
have
been
taking
leads
to
outcomes
that
have
not
advanced
the
central
policy
of
the
major
NSR
program
as
applied
to
existing
sources.
This
is
because
the
program
is
not
designed
to
cut
back
on
emissions
from
existing
major
stationary
sources
through
limitations
on
their
productive
capacity,
but
rather
to
ensure
that
they
will
install
state­
of­
the­
art
pollution
controls
at
a
juncture
where
it
otherwise
makes
sense
to
do
so.
We
also
do
not
believe
the
outcomes
produced
by
the
approach
we
have
been
taking
have
significant
environmental
benefits
compared
with
the
approach
we
are
proposing
today.
We
do
not
believe
that
today's
revised
emissions
test
is
substantially
different
from
the
actual­
to­
projected­
actual
test.
This
is
particularly
true
in
light
of
the
substantial
EGU
emissions
reductions
that
other
Internal
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2005
21
In
our
projections
of
emissions
changes
under
the
Acid
Rain
Program,
the
NOx
SIP
Call,
the
CAIR,
and
BART,
increases
in
future
electric
generating
capacity
are
accounted
for.

22
Information
received
from
Gene­
Hua
Sun,
U.
S.
EPA
Clean
Air
Markets
Division,
available
in
docket
OAR­
2005­
0163.

31
programs
have
achieved.
We
therefore
believe
that,
to
any
extent
today's
revised
emissions
test
would
lead
to
more
growth
in
emissions
than
the
actual­
to­
projected­
actual
test
would,
the
emissions
increases
from
that
growth
would
be
substantially
less
than
the
emissions
reductions
we
expect
from
the
Acid
Rain,
NOx
SIP
Call,
CAIR,
and
BART
programs.
21
C.
Requirements
for
Pollutants
Other
Than
SO
2
and
NOx
Concerning
PM
and
lead,
the
application
of
the
major
NSR
program
to
EGU
emissions
increases
would
be
unlikely
to
result
in
the
implementation
of
any
additional
controls.
Current
BACT
and
LAER
limits
to
control
PM
(
both
PM
10
and
PM
2.5)
for
EGUs
are
achieved
through
the
application
of
baghouses
or
electrostatic
precipitators
(
ESPs)
to
individual
boilers.
Of
the
450
coal­
fired
plants,
the
following
controls
are
in
place
to
reduce
PM
emissions
from
EGU:
79
plants
have
bag
houses
(
fabric
filters),
354
plants
have
ESPs,
and
21
plants
have
both
ESPs
and
baghouses.
22
Therefore,
virtually
all
coal­
fired
EGUs
are
already
well­
controlled
for
PM.
The
minimal
lead
emissions
from
EGUs
are
in
particulate
form,
and
are
captured
by
PM
controls.

For
CO
and
VOC,
the
only
BACT/
LAER
requirements
that
exist
for
boilers
are
"
good
combustion"
practices.
EGUs
operate
under
enormous
economic
incentives
not
to
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32
waste
fuel,
and
good
combustion
practices
conserve
fuel.
Thus,
EGUs
have
strong
incentives
to
use
good
combustion
practices,
regardless
of
the
major
NSR
regulations.
We
believe
that
virtually
all
EGUs
are
already
implementing
such
practices
to
control
CO
and
VOC.
Accordingly,
we
do
not
believe
that
VOC
or
CO
emissions
increases
at
EGU
are
likely
or
that
the
application
of
the
major
NSR
program
to
changes
made
at
the
EGUs
would
be
likely
to
result
in
the
implementation
of
additional
controls
for
CO
and
VOC.

Furthermore,
even
if
EGU
did
not
have
built­
in
incentives
to
control
VOC
and
CO
emissions,
we
do
not
believe
that
today's
revised
emissions
test
would
result
in
emissions
increases
compared
to
the
actual­
to­
projected­
actual
test.
Therefore,
we
expect
no
air
quality
impacts
due
to
CO
or
VOC
emissions
as
a
result
of
this
proposed
rule.

IV.
Today's
Proposed
Rule
Today,
we
are
proposing
to
allow
existing
EGUs
to
use
the
same
maximum
achievable
hourly
emissions
test
we
apply
under
NSPS
to
determine
whether
a
physical
change
in
or
change
in
the
method
of
operation
(
physical
or
operation
change)
results
in
an
emissions
increase
under
the
major
NSR
program.
We
request
public
comments
on
all
aspects
of
the
proposed
changes.

This
section
also
provides
a
brief
background
on
the
emissions
increase
test
used
in
the
NSPS
and
major
NSR
programs,
and
summarizes
our
proposed
changes
to
the
NSR
program,
which
is
necessary
to
understand
the
proposed
regulations.
For
a
fuller
discussion
on
the
statutory
and
legislative
background
of
the
major
NSR
program,
please
see
Section
V.
B.
of
today's
preamble.
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23
We
described
the
relationship
between
the
provisions
contained
in
Sections
60.2
and
60.14
in
a
1974
Federal
Register
Notice,
in
which
we
stated
that
the
regulations
concerning
modifications
in
§
60.14
clarify
the
phrase
"
increases
the
amount
of
any
air
pollutant"
that
appears
in
the
definition
of
modification
in
§
60.2.
39
FR
36946,
October
15,
1974.

33
A.
Background
on
Existing
Regulations
Both
the
NSPS
and
major
NSR
programs
impose
requirements
on
modifications
of
stationary
sources.
Our
NSPS
regulations
contain
a
two­
part
definition
of
modification.

The
first
part
substantially
mirrors
the
statutory
text
found
in
Section
111(
a)(
4)
of
the
Act,

while
the
second
elaborates
upon
the
first.
In
simplistic
terms,
the
Act
establishes
a
twostep
test
for
determining
whether
an
activity
is
a
modification.
First
you
must
determine
whether
the
activity
qualifies
as
a
physical
change
or
operational
change
of
a
stationary
source,
then
you
must
determine
whether
that
activity
also
increases
the
amount
of
pollution
emitted
by
the
stationary
source.

You
can
find
the
regulatory
text
defining
"
modification"
within
the
NSPS
general
provision
regulations
at
40
CFR
Sections
60.2
and
60.14.
Substantially
mirroring
CAA
111(
a)(
4),
Section
60.2
contains
a
general
description
of
the
two
components
an
activity
must
satisfy
to
qualify
as
a
modification.
Section
60.14
elaborates
on
the
general
description
contained
in
Section
60.2
by
more
precisely
defining
how
you
measure
the
amount
of
pollution
that
results
from
an
activity,
and
listing
activities
that
do
not
qualify
as
physical
or
operational
changes.
23
Unlike
our
NSPS
regulations,
our
major
NSR
regulations
do
not
contain
a
specific
definition
of
the
term
"
modification."
Instead,
our
regulations
define
"
major
modification,"
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34
which
adds
provisions
for
determining
whether
an
activity
satisfies
the
second
component
(
whether
there
is
an
increase
in
the
amount
of
an
air
pollutant).
Specifically,
the
major
modification
definition
provides
a
two­
step
procedure
for
measuring
emissions
increases.

Under
this
process,
a
source
looks
at
whether
a
project
will
result
in
a
significant
emissions
increase
on
an
annual
basis
and
then
whether
contemporaneous
increases
and
decreases
will
result
in
a
significant
net
emissions
increase
(
netting)
on
an
annual
basis.

The
differences
between
the
definition
of
"
modification"
as
applied
in
the
NSPS
program
and
"
major
modification"
as
applied
in
the
major
NSR
program
illustrate
some
fundamental
differences
in
the
way
we
have
implemented
the
programs
to
date.
First,
the
NSPS
program
regulates
all
emissions
increases
(
that
is,
it
regulates
any
increase
in
the
hourly
emissions),
while
the
major
NSR
program
exempts
emissions
increases
that
are
less
than
significant
(
that
is,
it
exempts
emissions
increases
that
are
less
than
40
tpy).
Second,

the
NSPS
program
regulates
modifications
of
"
affected
facilities,"
which
are
typically
small
collections
of
equipment
within
a
larger
manufacturing
plant.
The
major
NSR
program
regulates
modifications
of
major
stationary
sources.
Accordingly,
all
the
equipment
within
a
larger
manufacturing
plant
is
looked
at
collectively.
Finally,
because
the
NSPS
regulates
small
collections
of
equipment
rather
than
the
entire
plant,
increases
in
one
part
of
the
plant
cannot
be
"
offset"
with
decreases
at
other
parts
of
the
plant.
[
See
Asarco,
Inc.
v.
EPA,
578
F.
2d
319
(
D.
C.
Cir.
1978).]
Conversely,
major
NSR
regulates
changes
in
emissions
at
the
major
stationary
source
as
a
whole
and
allows
decreases
in
emissions
from
one
part
of
the
plant
to
"
offset"
increases
in
emissions
that
occur
in
another
part
of
the
plant.
[
See
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September
30,
2005
35
Alabama
Power
v.
Costle,
636
F.
2d
323
(
D.
C.
Cir.
1979).
This
process
is
known
as
"
netting."

The
NSPS
modification
provisions
apply
an
hourly
emission
rate
test
to
measure
emissions
increases
resulting
from
a
physical
or
operational
change.
Specifically,
under
the
regulations,
whether
there
is
an
emissions
increase
is
determined
by
comparing
the
prechange
baseline
hourly
emission
rate
to
the
post­
change
hourly
emission
rate.
For
electric
utility
steam
generating
units
(
EUSGUs),
the
baseline
hourly
rate
is
"
the
maximum
hourly
emissions
achievable
at
that
unit
during
the
5
years
prior
to
the
change."
[
See
40
CFR
60.14(
h).]
EPA
has
described
this
rate
as
the
rate,
in
the
past
5
years,
that
the
source
could
achieve
at
its
physical
and
operational
capacity
(
57
FR
32330).
Thus,
this
hourly
rate
represents
the
highest
rate
at
which
the
source
could
actually
emit
during
the
relevant
period.

The
baseline
hourly
emissions
rate
for
non­
EGUs
is
likewise
based
on
current
maximum
capacity,
which
is
defined
as
the
production
rate
at
which
the
source
could
operate
without
making
a
capital
expenditure.
[
See
§
60.14(
e)(
2).]
As
provided
in
§
60.14
(
b)(
1),
we
measure
the
emissions
rate
in
kg/
hr
or
lbs/
hr.
Therefore,
the
baseline
hourly
emissions
for
non­
utilities
is
also
based
on
the
highest
rate
at
which
the
source
could
actually
emit.
As
we
stated
at
57
FR
32316
referring
to
the
rules
for
non­
utilities,
"
under
current
NSPS
regulations,
emissions
increases,
for
applicability
purposes,
are
calculated
by
comparing
the
hourly
emission
rate,
at
maximum
physical
capacity,
before
and
after
the
physical
or
operational
change.
That
is,
to
determine
whether
a
change
to
an
existing
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24
These
changes
were
adopted
on
December
16,
1975
(
see
40
FR
58416)
and
the
provisions
have
remained
unchanged,
except
to
clarify
that
it
applies
to
the
facility
rather
than
to
the
stationary
source
containing
that
facility.

36
facility
will
increase
the
emissions
rate,
the
existing
NSPS
regulations
authorize
the
use
of
an
`
emissions
factor
analysis',
or
materials
balance,
continuous
monitoring,
or
manual
emissions
test
to
evaluate
emissions
before
and
after
the
change."

This
characterization
of
the
emissions
rate
as
based
on
the
highest
rate
at
which
the
source
could
actually
emit
is
consistent
with
our
previous
statements
and
regulations.
In
the
preamble
to
the
December
23,
1971
NSPS
rules,
we
stated
that
"
procedures
have
been
modified
so
that
the
equipment
will
have
to
be
operated
at
maximum
expected
production
rate,
rather
than
rated
capacity,
during
compliance
tests."
(
See
36
FR
24876.)
The
December
1971
rules
specified
that
a
change
in
the
method
of
operation
did
not
include
"
an
increase
in
the
production
rate,
if
such
increase
does
not
exceed
the
operating
design
capacity
of
the
affected
facility."
(
See
36
FR
24877.)
On
October
15,
1974,
we
proposed
to
change
this
provision
to
"
an
increase
in
the
production
rate
of
an
existing
facility,
if
that
increase
can
be
accomplished
without
a
major
capital
expenditure"
and
to
move
it
to
§
60.14(
e)(
2).
24
[
See
39
FR
36946.]
In
describing
the
reason
for
this
change,

we
specifically
stated
that
hourly
emissions
must
be
determined
considering
what
the
source
could
actually
emit,
rather
than
"
design"
(
nameplate)
capacity.

The
exemption
of
increases
in
production
rate
is
no
longer
dependent
upon
the
`
operating
design
capacity.'
This
term
is
not
easily
defined
and
for
certain
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2005
25
The
legislative
history
is
clear
that
Congress
considered
"
potential
to
emit"
and
"
design
capacity"
to
be
equivalent
terms.
The
House
bill
defined
a
major
stationary
source
as
any
stationary
source
of
air
pollutant
which
directly
emits
or
has
the
design
capacity
to
emit
100
tons
annually
of
any
pollutant
for
which
an
ambient
air
quality
standard
is
promulgated.
[
H.
R.
Report
95­
564,
p.
172(
1977),
U.
S.
Code
Cong.
&
Admin.
News
1977,
p.
1552.]
The
House
bill
also
stated
that
"
major
emitting
facilities
proposing
to
construct
facilities
must
receive
State
permits.
All
sources
with
the
design
capacity
to
emit
100
tons
per
year
or
more
of
any
pollutant
must
receive
a
permit."
[
H.
R.
Report
95­
564,
p.
149(
1977),
U.
S.
Code
Cong.
&
Admin.
News
1977,
p.
1529.]
The
Senate
amendment
defined
major
emitting
facility
as
any
stationary
source
with
an
annual
potential
to
emit
100
tons
or
more
of
any
pollutant.
The
Senate
bill
also
required
permits
for
major
stationary
sources
with
potential
to
emit
over
250
tons
per
year.
The
conference
committee
agreed
on
the
provisions
on
major
emitting
facilities
and
major
stationary
sources
to
be
included
in
the
statute
at
302(
j)
and
169(
1)
as
follows.
The
State
plan
must
require
permits
for:
(
a)
All
28
categories
listed
in
the
Senate
bill
if
the
sources
has
the
potential
(
design
capacity)
to
emit
over
100
tons
per
year;
and
(
b)
any
other
source
with
the
design
capacity
to
emit
more
than
250
tons
per
year
of
any
air
pollutant.
[
H.
R.
Report
95­
564,
p.
149(
1977),
U.
S.
Code
Cong.
&
Admin.
News
1977,
p.
1153]

37
industries
the
`
design
capacity'
bears
little
relationship
to
the
actual
operating
capacity
of
the
facility.

Id.
at
39
FR
36948.

As
Congress
indicated
in
the
legislative
history
for
the
1977
CAA,
25
design
capacity
is
equivalent
to
potential
to
emit.
In
the
NSPS
regulations,
neither
the
EGU
nor
the
non­
EGU
hourly
emissions
are
based
on
design
capacity.
Thus,
to
describe
the
NSPS
test
as
a
potential­
to­
potential
test
is
inaccurate,
and
EPA
has
not
asserted
that
the
NSPS
test
is
a
potential­
to­
potential
test.
Instead,
the
Agency
has
at
times
referred
to
"
hourly
potential
emissions."
Where
we
have
referred
to
hourly
potential
emissions,
we
have
also
been
clear
that
we
are
referring
to
what
the
source
is
actually
able
to
emit
at
current
maximum
capacity.
For
example,
in
the
1988
WEPCO
memorandum,
we
stated:
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30,
2005
26
Memorandum
dated
September
9,
1988,
from
Don
R.
Clay,
Acting
Assistant
Administrator
for
Air
&
Radiation,
U.
S.
EPA,
to
David
A.
Kee,
Director,
Air
and
Radiation
Division,
U.
S.
EPA
Region
V.
Applicability
of
PSD
and
NSPS
Requirements
to
the
WEPCO
Port
Washington
Life
Extension
Project.
Available
at:
http://
www.
epa.
gov/
region7/
programs/
artd/
air/
nsr/
nsrmemos/
wpco2.
pdf
.
Pg.
9.

27
Correspondence
dated
February
15,
1989,
from
Don
R.
Clay,
Acting
Assistant
Administrator
for
Air
&
Radiation,
U.
S.
EPA,
to
John
W.
Boston,
Wisconsin
Electric
Power
Company.
Available
at:
http://
www.
epa.
gov/
region7/
programs/
artd/
air/
nsr/
nsrmemos/
lifextn.
pdf
.
Pg.
8.

38
"
Pursuant
to
longstanding
EPA
interpretations,
the
emission
rate
before
and
after
a
physical
or
operational
change
is
evaluated
at
each
unit
by
comparing
the
hourly
potential
emissions
under
current
maximum
capacity
to
emissions
at
maximum
capacity
after
the
change."
26
However,
in
the
following
WEPCO
memorandum,
we
clarified
that
"
Baseline
emissions
for
NSPS
purposes
are
determined
by
hourly
maximum
capacity
just
prior
to
the
renovations"
27
and
required
a
determination
of
the
current
actual
operating
capacity
of
the
units.

Our
current
major
NSR
regulations
measure
an
emissions
increase
at
an
existing
emissions
unit
using
the
"
actual­
to­
projected­
actual"
applicability
test.
Under
this
approach,
we
compare
an
emissions
unit's
"
baseline
actual
emissions"
to
the
emission
unit's
projected
actual
emissions
after
the
change.
Our
current
test
distinguishes
how
non­

EUSGUs
compute
an
emissions
unit's
baseline
actual
emissions
from
the
method
used
for
EUSGUs.
We
define
baseline
actual
emissions
for
non­
EUSGUs
as
the
average
annual
emission
rate
calculated
from
any
consecutive
24­
month
period
in
the
past
10
years.
For
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2005
39
EUSGUs
,
the
baseline
actual
emissions
equals
the
average
annual
emission
rate
achieved
over
any
consecutive
24­
month
period
in
the
past
5
years
unless
there
is
another
period
of
time
that
is
more
representative
of
normal
source
operations.
We
use
the
same
definition
of
projected
actual
emissions
for
both
EUSGUs
and
non­
EUSGUs.
The
rules
generally
define
projected
actual
emissions
as
the
maximum
annual
rate
of
emissions
at
which
the
emissions
unit
is
projected
to
operate
for
the
first
5
years
after
the
emissions
unit
begins
operation
following
the
change.
See
40
CFR
51.166
(
b)(
47)
and
(
b)(
40)
to
understand
all
aspects
of
the
baseline
actual
emissions
and
projected
actual
emissions
definitions.

B.
What
We
Are
Proposing
1.
Test
for
EGUs
Based
on
Maximum
Achievable
Hourly
Emissions
Today,
we
are
proposing
to
allow
existing
EGUs
to
use
the
same
maximum
achievable
hourly
emissions
test
applied
in
the
NSPS
to
determine
whether
a
physical
or
operation
change
results
in
an
emissions
increase
under
the
major
NSR
program.

Accordingly,
the
major
NSR
regulations
would
apply
at
an
EGU
if
a
physical
or
operational
change
results
in
any
increase
in
the
maximum
hourly
emissions
rate.
We
are
not
proposing
to
allow
EGUs
to
exclude
emissions
increases
that
fall
below
a
particular
significant
emissions
rate,
or
to
allow
EGUs
to
use
plantwide
netting
to
avoid
NSR
applicability.

We
are
proposing
to
define
EGUs
in
the
same
way
that
this
term
is
defined
by
the
CAIR
and
Acid
Rain
regulations.
Specifically,
we
would
define
EGU
as
fossil­
fuel
fired
boilers
and
turbines
serving
an
electric
generator
with
a
nameplate
capacity
greater
than
25
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30,
2005
28
CAIR
EGU
do
not
include
municipal
waste
combustors
(
MWC)
or
solid
waste
incinerators.
We
have
proposed
regulatory
language
to
clarify
this
on
August
24,
2005,
at
70
FR
49708.

29
In
the
near
future,
we
plan
to
publish
a
proposed
rule
addressing
NSR
requirements
in
tribal
lands.

40
megawatts
(
MW)
producing
electricity
for
sale.
28
Fossil
fuel
is
described
as
natural
gas,

petroleum,
coal,
or
any
form
of
solid,
liquid,
or
gaseous
fuel
derived
from
such
material.

The
term
"
fossil
fuel­
fired"
with
regard
to
an
emissions
unit
means
combusting
fossil
fuel,

alone
or
in
combination
with
any
amount
of
other
fuel
or
material.

This
definition
of
EGU
is
broader
than
the
definition
of
EUSGU
currently
found
in
the
NSPS
and
NSR
regulations.
The
EGU
definition
includes
cogeneration
facilities
and
simple
cycle
gas
turbines
that
would
not
qualify
under
EUSGU
definitions.
That
is,
the
revised
emissions
test
would
apply
to
EUSGUs,
cogeneration
facilities,
and
simple
cycle
gas
turbines.

To
incorporate
the
NSPS
maximum
achievable
hourly
emissions
test
into
the
major
NSR
regulations,
we
are
proposing
to
add
a
definition
of
modification
to
the
major
NSR
regulation
that
will
apply
to
changes
affecting
regulated
NSR
pollutant
emissions
in
lieu
of
the
current
definition
of
major
modification.
We
would
add
the
new
definition
to
all
versions
of
the
NSR
regulations
including
40
CFR
51.165,
51.166,
52.21,
52.24,
and
in
Appendix
S
of
40
CFR
part
51,
as
well
as
any
regulations
we
finalize
to
implement
major
NSR
in
Indian
Country.
29
We
propose
that
this
definition
would
substantially
mirror,
but
would
not
be
Internal
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30,
2005
30
The
major
NSR
regulations
define
NSR
regulated
pollutants
at
40
CFR
51.166(
b)(
49).

41
identical
to,
the
definition
of
modification
contained
in
Section
60.14
of
the
NSPS
regulations.
There
are
differences
between
the
two
programs
that
prevent
a
wholesale
adoption
of
the
NSPS
modification
definition
into
the
major
NSR
provisions.
For
example,

the
NSPS
program
applies
the
definition
of
modifications
only
to
stationary
sources
and
pollutants
for
which
a
particular
NSPS
standard
applies.
Specifically,
the
NSPS
program
regulates
modifications
of
"
affected
facilities,"
which
are
typically
small
collections
of
equipment
within
a
larger
manufacturing
plant.
The
NSPS
program
also
specifies
which
pollutants
from
the
affected
facility
are
regulated.
For
example,
Subpart
Da
of
40
CFR
part
60
regulates
emissions
increases
of
sulfur
dioxides,
nitrogen
oxides,
and
particulate
matter
from
EUSGUs.
The
major
NSR
program,
on
the
other
hand,
regulates
modifications
of
major
stationary
sources.
Accordingly,
all
the
equipment
within
a
larger
manufacturing
plant
is
looked
at
collectively.
Furthermore,
the
Act
mandates
that
major
NSR
requirements
apply
to
modifications
at
any
major
stationary
source
that
increases
emissions
of
any
regulated
NSR
pollutant.
30
The
proposed
definition
is
as
follows.

"
Modification,"
for
an
electric
generation
unit
(
EGU),
means
any
physical
change
in,
or
change
in
the
method
of
operation
of,
an
EGU
which
increases
the
amount
of
any
regulated
NSR
pollutant
emitted
into
the
atmosphere
by
that
source
or
which
results
in
the
emission
of
any
regulated
NSR
pollutant(
s)
into
the
atmosphere
that
the
source
did
not
previously
emit.
An
increase
in
the
amount
of
regulated
NSR
Internal
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30,
2005
31
The
Duke
Energy
Court
also
noted
that
in
Northern
Plains
Res.
Council
v.
EPA,
645
F.
2d
1349,
1356
(
9th
Cir.
1981),
the
Ninth
Circuit
allowed
EPA
to
interpret
the
statutory
term
"
commenced"
differently
in
the
NSPS
and
PSD
regulations.
Duke
Energy,
slip
op.
at
17.

42
pollutants
must
be
determined
according
to
the
provisions
in
paragraph
(
x)
of
this
section.

While
we
disagree
with
the
Fourth
Circuit's
holding
in
Duke
Energy,
and
thus
believe
we
are
able
to
make
reasonable
distinctions
between
the
NSPS
and
NSR
programs
where
appropriate,
we
believe
that
such
distinctions
are
appropriate
even
in
the
Fourth
Circuit.
Although
the
Fourth
Circuit
held
in
Duke
Energy
that
we
must
use
the
same
definition
of
modification
in
both
the
NSPS
and
NSR
programs
where
appropriate,
it
only
discussed
this
finding
in
the
context
of
the
component
term
of
the
definition
"
increases
in
the
amount
of
any
air
pollutant
emitted."
In
fact,
the
Court
noted
that
the
Fourth
Circuit
had
previously
held
that
the
term
"
stationary
source,"
a
component
term
within
the
definition
of
"
modification",
could
be
interpreted
differently
in
the
NSPS
and
PSD
programs
because
Congress
had
not
defined
the
term
in
both
programs.
[
Duke
Energy,
slip
op.
at
17,
citing
Potomac
Elec.
Power
Co.
v.
EPA,
650
F.
2d
509,
518
(
4th
Cir.
1981).
31
Accordingly,
we
believe
it
is
reasonable
to
interpret
the
Duke
Energy
decision
as
requiring,

within
the
Fourth
Circuit,
that
the
maximum
hourly
emission
test
be
used
within
the
major
NSR
provisions,
but
as
not
requiring
the
identical
treatment
of
the
term
"
physical
change
in
or
change
in
the
method
of
operation."
Based
on
our
interpretation,
we
propose
to
incorporate
the
part
of
the
major
modification
definition
that
addresses
regulation
of
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September
30,
2005
43
physical
and
operational
changes
into
the
modification
definition
for
EGUs.
We
request
comment
on
this
interpretation.

We
also
are
not
proposing
to
change
our
current
methodologies
for
computing
the
amount
or
availability
of
emissions
offsets,
or
for
computing
emissions
for
purposes
of
conducting
an
ambient
impact
analysis.
Accordingly,
EGUs
will
be
required
to
follow
the
existing
regulations
related
to
these
provisions.

In
proposing
this
NSR
test
for
EGUs
based
on
maximum
achievable
hourly
emissions,
we
are
aware
of
the
recent
opinion
by
the
United
States
Court
of
Appeals
for
the
District
of
Columbia
Circuit
in
New
York
v.
EPA,
413
F.
3d
3
(
D.
C.
Cir.
June
24,

2005).
In
that
case,
the
Court
rejected
challenges
to
substantial
portions
of
EPA's
2002
NSR
rules.
However,
the
Court
did
hold
that
EPA
lacked
authority
to
promulgate
the
"
Clean
Unit"
provision
of
the
2002
rules,
and
in
doing
so,
held
that
"
the
plain
language
of
the
CAA
indicates
that
Congress
intended
to
apply
NSR
to
changes
that
increase
actual
emissions
instead
of
potential
or
allowable
emissions."
Id.
,
slip
op.
at
40.

We
respectfully
disagree
with
the
Court's
holding
that
the
plain
language
of
the
CAA
requires
that
NSR
apply
to
changes
in
actual
emissions,
and
the
United
States
has
filed
a
petition
for
rehearing
and
rehearing
en
banc
as
to
this
holding.
We
believe
that
the
CAA
is
silent
on
whether
increases
in
emissions
for
purposes
of
determining
whether
a
physical
or
operational
change
constitutes
a
modification
must
be
measured
in
terms
of
actual
emissions,
potential
emissions,
or
some
other
currency.
Therefore,
we
believe
that
even
if
the
test
for
emissions
increases
that
we
propose
today
were
based
on
something
Internal
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Deliberative­
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September
30,
2005
32
See
the
EPA
memorandum,
Issuance
of
the
Clean
Air
Act
National
Stack
Testing
Guidance,
from
Michael
M.
Stahl,
Director,
Office
of
Compliance,
to
Regional
Compliance/
Enforcement
Division
Directors,
February
2,
2004,
pg.
10.
available
at
http://
www.
epa.
gov/
Compliance/
resources/
policies/
monitoring/
caa/
stacktesting.
pdf.

44
other
than
actual
emissions,
it
would
be
an
appropriate
interpretation
and
entitled
to
deference
under
step
2
of
the
analytical
process
set
forth
in
Chevron
U.
S.
A.,
Inc.
v.
Natural
Res.
Def.
Council,
467
U.
S.
837
(
1984).
Nonetheless,
we
recognize
that
we
must
promulgate
a
rule
that
is
consistent
with
the
D.
C.
Circuit's
resolution
of
this
issue.

However,
regardless
of
whether
our
petition
for
rehearing
in
New
York
v.
EPA
is
denied,
we
believe
that
a
test
based
on
maximum
achievable
hourly
emissions
is
a
test
based
on
actual
emissions.
The
maximum
achievable
hourly
emissions
test
measures
what
a
source
has
been
actually
able
to
emit
based
on
physical
and
operating
capacity
during
a
representative
period
prior
to
the
change.
For
most,
if
not
all
EGUs,
the
hourly
rate
at
which
the
unit
is
actually
able
to
emit
is
substantively
equivalent
to
that
unit's
historical
maximum
hourly
emissions.
States
require
most,
if
not
all
EGUs,
to
perform
periodic
performance
tests
under
applicable
SIPs
and
enhanced
monitoring
requirements.
The
NSPS
regulations
require
a
source
to
conduct
testing
based
on
representative
performance
of
the
affected
facility.
[
See
40
CFR
60.8(
c).]
In
the
National
Stack
Test
Guidance
that
we
issued
in
February
2004,
we
recommended
that
facilities
conduct
performance
tests
"
under
the
most
severe
conditions
that
create
the
highest
emissions."
32
Accordingly,
most
EGUs
actually
emit
at
maximum
physical
and
operational
capacity
within
a
5­
year
baseline
period.
Internal
and
Deliberative­
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September
30,
2005
45
We
solicit
comment
on
our
assumption
that
an
NSR
test
for
EGUs
based
on
maximum
achievable
hourly
emissions
is,
in
fact,
a
test
that
would
be
based
on
a
measure
of
actual
emissions
in
light
of
the
manner
in
which
EGUs
are
operated.

As
we
noted
earlier,
the
current
major
NSR
regulations
contain
a
definition
of
major
modification.
Specifically,
the
major
modification
definition
provides
a
two­
step
procedure
for
measuring
emissions
increases.
Under
this
process,
a
source
looks
at
whether
a
project
will
result
in
a
significant
emissions
increase
on
an
annual
basis
and
then
whether
contemporaneous
increases
and
decreases
will
result
in
a
significant
net
emissions
increase
(
netting)
on
an
annual
basis.
We
are
proposing
to
replace
this
definition
of
major
modification
with
a
definition
of
modification
based
on
the
maximum
hourly
achievable
emissions
increase
test
(
or
one
of
the
two
other
emissions
increase
tests
that
we
discuss
in
the
following
sections,
maximum
achieved
emissions
or
an
output­
based
measure
of
emissions).
However,
we
request
comment
on
whether
we
should
instead
add
the
definition
of
modification
based
on
an
hourly
emissions
test,
which
would
then
be
followed
by
the
current
major
modification
provisions
based
on
annual
emissions.
Specifically,
we
request
comment
on
whether
the
major
NSR
program
should
include
a
four­
step
process
as
follows:
(
1)
physical
change
or
change
in
the
method
of
operation;
(
2)
maximum
achievable
hourly
emissions
increase
(
or
another
alternative
emissions
increase
test
such
as
discussed
below);
(
3)
significant
emissions
increase
as
in
the
current
major
NSR
regulations;
(
4)

significant
net
emissions
increase
as
in
the
current
major
NSR
regulations.

2.
Test
for
EGUs
Based
on
Maximum
Achieved
Hourly
Emissions
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2005
46
We
are
also
proposing
in
the
alternative
a
slightly
different
emissions
test
from
the
maximum
achievable
hourly
emissions
test
applied
in
the
NSPS
program.
Specifically,
we
are
requesting
comment
on
whether
we
should
promulgate
an
emissions
test
based
on
assessing
an
emissions
unit's
historical
maximum
hourly
emissions.
That
is,
instead
of
calculating
what
a
source
could
actually
emit
at
current
maximum
capacity,
actual
emissions
would
be
determined
by
a
specific
measure
of
historical
emissions,
such
as
with
CEMS.
This
test
may
be
preferred
by
some
because
the
method
of
assessing
the
source's
actual
emissions
is
similar
to
the
current
major
NSR
approach
for
determining
baseline
actual
emissions.

We
would
call
this
test
the
maximum
achieved
hourly
emissions
test.
Under
this
approach,
an
EGU
would
determine
whether
an
emissions
increase
will
occur
by
comparing
the
pre­
change
maximum
actual
hourly
emission
rate
to
a
projection
of
the
post­
change
maximum
actual
hourly
emission
rate.
The
pre­
change
maximum
actual
hourly
emission
rate
would
be
the
highest
rate
at
which
the
EGU
actually
emitted
the
pollutant
within
the
5­

year
period
immediately
before
the
physical
or
operational
change.

Like
the
maximum
achievable
hourly
emissions
test,
the
maximum
achieved
emissions
test
is
a
measure
of
a
source's
actual
emissions.
The
maximum
achieved
hourly
emissions
test
is
based
on
a
specific
measure
of
historical
actual
emissions
during
a
representative
period.
Therefore,
even
if
our
petition
for
rehearing
in
New
York
v.
EPA
is
denied,
we
believe
that
a
test
based
on
maximum
achieved
hourly
emissions
satisfies
the
requirement
that
major
NSR
applicability
be
based
on
"
some
measure
of
actual
emissions."
Internal
and
Deliberative­
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2005
47
We
believe
that
adopting
this
alternative
approach
may
not
achieve
the
policy
objectives
supporting
this
proposal.
We
stated
that
two
of
our
goals
for
this
proposal
are
to
streamline
the
regulatory
requirements
applying
to
EGUs
by
allowing
EGUs
to
apply
the
same
test
for
measuring
emissions
increases
from
modifications
under
both
the
NSPS
program
and
NSR
program,
and
to
provide
some
nationwide
consistency
in
the
emissions
calculation
procedures
in
light
of
the
Fourth
Circuit's
decision
in
Duke.
We
believe
that
the
maximum
achievable
hourly
emissions
test
better
comports
with
our
policy
goals
than
the
maximum
achieved
hourly
emissions
test.
Therefore,
given
that
we
do
not
believe
that
there
is
substantive
difference
in
the
baseline
emissions
between
the
two
tests,
we
prefer
adoption
of
the
maximum
achievable
hourly
emissions
test
as
used
in
the
NSPS
program.

3.
Emissions
Test
Based
on
Energy
Output
We
also
request
comment
on
adopting
an
NSR
emissions
test
based
on
mass
of
emissions
per
unit
of
energy
output,
such
as
lb/
MW
hour
or
nanograms
per
Joule.

Applicability
under
the
major
NSR
program
has
historically
been
based
on
annual
limits
measured
in
tons
per
year.
As
we
discuss
in
Section
V.
of
this
preamble,
Congress
did
not
specify
how
to
calculate
"
increases"
in
emissions
and
left
EPA
with
the
task
of
filling
that
gap.
We
believe
establishing
an
NSR
emissions
increase
test
based
on
mass
emissions
per
unit
of
energy
output
would
be
a
reasonable
use
of
our
discretion.

We
also
believe
that
incorporating
an
output­
based
emissions
test
has
merit
for
several
reasons.
The
primary
benefit
of
output­
based
standards
is
that
they
recognize
energy
efficiency
as
a
form
of
pollution
prevention.
Using
more
efficient
technologies
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48
reduces
fossil
fuel
use
and
also
reduces
the
environmental
impacts
associated
with
the
production
and
use
of
fossil
fuels.
Another
benefit
is
that
output­
based
standards
allow
sources
to
use
energy
efficiency
as
a
part
of
their
emissions
control
strategy.
Energy
efficiency
as
an
additional
compliance
option
can
lead
to
reduced
compliance
costs,
as
well
as
lower
emissions.
We
want
to
encourage
use
of
efficient
units
that
displace
less
efficient,

more
polluting
units.
This
approach
is
especially
desirable
where
EGU
are
subject
to
market­
based
systems
such
as
the
Acid
Rain
Program,
NOx
SIP
Call,
and
CAIR,
as
those
programs
increase
incentives
for
using
efficient
units
Furthermore,
an
output­
based
emissions
test
would
comport
with
recent
State
efforts.
Several
States
have
initiated
regulations
or
permits­
by­
rule
for
distributed
generation
(
DG)
units,
including
combustion
turbines.
States
that
have
made
efforts
to
regulate
DG
sources
include
California,
Texas,
New
York,
New
Jersey,
Connecticut,

Delaware,
Maine,
and
Massachusetts.
Those
State
rules
include
emission
limits
that
are
output­
based,
and
many
allow
generators
that
use
combined
heat
and
power
(
CHP)
to
take
credit
for
heat
recovered.
For
example,
Texas
recently
passed
a
DG
permit­
by­
rule
regulation
that
gives
facilities
100
percent
credit
for
steam
generation
thermal
output,
and
incorporates
HRSG
and
duct
burners
under
the
same
limit.
The
California
Air
Resources
Board
(
CARB)
also
has
output­
based
emission
limits,
which
allow
DG
units
using
CHP
to
take
a
credit
to
meet
the
standards,
at
a
rate
of
1
MW
hr
for
each
3.4
million
British
thermal
units
(
MMBtu)
of
heat
recovered,
or
essentially,
100
percent.
The
draft
rules
for
New
York
and
Delaware
also
allow
DG
sources
using
CHP
to
receive
credit
toward
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49
compliance
with
the
emission
standards.

We
request
comment
on
the
desirability
and
feasibility
of
using
an
output­
based
test
for
measuring
emissions
increases
in
the
major
NSR
program.

C.
Pollutants
to
Which
the
Revised
Applicability
Test
Applies
We
request
comments
on
our
proposal
that
the
revised
emissions
test
(
either
our
preferred
maximum
achievable
test
or
the
alternative
maximum
achieved
test)
should
apply
to
all
regulated
NSR
pollutants.
In
light
of
our
policy
goal
to
provide
a
nationally
consistent
program
and
to
streamline
major
NSR
for
EGUs,
we
believe
it
is
desirable
to
provide
the
alternative
test
for
emissions
increases
of
all
regulated
NSR
pollutants.

However,
we
request
comment
on
whether
existing
controls
for
PM,
lead,
CO,
and
VOC
are
sufficient
to
warrant
the
exercise
of
EPA's
discretion
to
implement
a
revised
NSR
emissions
test
for
EGUs
with
respect
to
these
pollutants.
We
also
are
soliciting
comment
on
what
constitutes
good
combustion
practices
for
CO
and
VOC,
in
order
for
us
to
provide
a
more
precise
definition
of
these
practices.

D.
Significant
Emissions
Rates
As
we
stated,
we
are
not
proposing
to
allow
EGUs
to
exclude
emissions
increases
that
fall
below
a
particular
significant
emissions
rate.
Our
current
major
NSR
regulations
allow
sources
to
avoid
major
NSR
applicability
if
the
physical
or
operational
change
results
in
an
emissions
increase
that
is
below
a
significant
level.

We
codified
the
existing
significant
rates
based
on
a
de
minimis
legal
theory
that
balances
the
administrative
burden
of
running
the
program
with
the
environmental
benefit
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of
undergoing
major
NSR
review.
In
codifying
the
significant
rates,
we
relied
on
our
belief
that
Congress
did
not
intend
to
regulate
every
physical
or
operational
change
at
a
major
source.
Because
a
maximum
achievable
hourly
emissions
rate
test
is
based
on
computing
a
unit's
rate
of
emissions
in
kg/
hr,
whereas
the
existing
significant
rates
are
expressed
in
tons
per
year
(
tpy),
it
is
more
administratively
efficient
to
eliminate
the
need
to
compute
significant
emission
rates
from
the
proposed
emissions
test.

By
eliminating
the
use
of
a
significant
emission
rate
threshold
for
modifications,
we
balance
the
differences
in
these
tests,
and
focus
permitting
authority
resources
on
reviewing
all
changes
that
result
in
increases
in
existing
capacity.
We
believe
that
this
result
is
consistent
with
our
interpretation
of
Congressional
intent
in
that
it
assures
that,
at
a
minimum,
increases
in
existing
capacity
undergo
major
NSR
review.
See
a
fuller
discussion
of
the
legislative
history
in
Section
V.
of
this
preamble.

We
request
comment
on
our
conclusion
that
the
maximum
achievable
hourly
emission
test
should
regulate
all
emissions
increases
and
not
just
those
that
are
above
the
significant
rate.
Alternatively,
we
request
comment
on
including
a
significant
emissions
rate
as
a
component
of
the
maximum
achievable
hourly
emissions
test
for
major
NSR.
If
we
include
use
of
the
significant
rate
within
the
emissions
increase
test,
sources
would
have
to
extrapolate
their
maximum
hourly
emission
rate
to
a
maximum
annual
emission
rate.
We
request
comment
on
an
appropriate
approach
for
making
this
extrapolation.

E.
Eliminating
Netting
Netting
has
played
an
important
role
over
the
history
of
the
major
NSR
program
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by,
to
some
extent,
allowing
sources
to
manage
plantwide
changes
in
a
way
that
assures
that
the
major
stationary
source's
emissions
do
not
increase.
Nonetheless,
numerous
stakeholders,
including
individuals
among
State,
environmental,
and
industry
groups,

believe
that
our
netting
procedures
in
the
existing
program
are
too
complicated
and
allow
construction
of
brand
new
emissions
units
to
occur
without
requiring
emissions
controls.

These
stakeholders
suggested
removing
the
netting
provisions
or
revising
the
procedures
to
shorten
the
contemporaneous
period
to
allow
for
"
project
netting."
Project
netting
allows
the
emissions
increases
and
decreases
from
a
given
project
to
be
summed
together
without
the
need
to
review
all
changes
over
the
previous
5
years.

Because
the
maximum
achievable
hourly
emissions
test
is
based
on
increases
in
kg/
hr,
including
netting
within
the
emissions
test
would
further
complicate
administration
of
the
program
by
adding
additional
calculations
to
an
already
complicated
process.

Accordingly,
eliminating
the
ability
to
net
pollutant
increases
and
decreases
would
simplify
applicability
determinations
and
assure
that
increases
in
existing
capacity
could
not
occur
without
preconstruction
review
and
installation
of
appropriate
controls.
Also,
one
of
the
advantages
of
our
proposal
to
eliminate
netting
is
that
there
would
be
no
unreviewed
increases.

Nevertheless,
the
Court
in
Alabama
Power
held
that
the
Act
requires
EPA
to
allow
netting
within
our
regulations
(
the
"
bubble"
approach),
because
such
an
approach
is
consistent
with
the
purposes
of
the
Act.
The
Court
reasoned
that
Congress
intended
to
"
generate
technological
improvement
in
pollution
control,
but
this
approach
focused
upon
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`
rapid
adoption
of
improvements
in
technology
as
new
sources
are
built,'
not
as
old
ones
[
plants]
were
changed
without
pollution
increases."

It
is
important
to
place
this
ruling
in
the
context
of
the
rules
before
the
Court
at
that
time.
Our
1978
regulations
required
a
source­
wide
accumulation
of
emissions
increases
without
providing
for
an
ability
to
offset
these
accumulated
increases
with
any
source­
wide
decreases.
In
finding
that
we
must
apply
a
bubble
approach,
the
court
held
that
we
could
not
require
sources
to
accumulate
increases
without
also
accumulating
decreases.
It
is
unclear
whether
the
Court
would
have
reached
the
same
conclusion
if
the
emissions
test
before
the
court
only
considered
the
increases
from
the
project
under
review
and
not
source­
wide
increases
from
multiple
projects.
Moreover,
contrary
to
the
Alabama
Power
Court's
analysis,
some
have
argued
that
the
netting
approach
may
have
impeded
Congress'

objective
of
promoting
"
rapid
adoption
of
improvements
in
technology
as
new
sources
are
built."
This
is
because
it
allows
construction
of
new
units
at
existing
facilities
without
emissions
controls,
while
requiring
major
NSR
for
large
greenfield
sources.

We
request
comment
on
our
observations
related
to
the
Alabama
Power
Court's
decision
related
to
netting
and
whether
a
major
NSR
program
without
netting
can
be
supported
under
the
Act.
Specifically,
we
request
comment
on
whether,
in
adding
the
maximum
achievable
emissions
test
for
EGUs
within
the
major
NSR
program,
we
should
retain
the
requirement
to
compute
a
net
emissions
increase.
Under
this
approach,
a
source
would
first
determine
whether
an
activity
results
in
an
increase
in
maximum
hourly
emissions,
and
then
the
source
would
determine
whether
this
increase,
when
considered
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with
other
increases
and
decreases
at
the
major
stationary
source
over
the
past
5
years,

would
result
in
a
net
emissions
increase
at
the
major
stationary
source.
Alternatively,
we
request
comment
on
whether
we
should
retain
netting,
but
shorten
the
contemporaneous
period
to
the
time
of
construction
and
allow
EGUs
to
use
only
"
project"
netting
in
computing
whether
a
physical
or
operational
change
results
in
an
emissions
increase.

F.
Benefits
of
Maximum
Achievable
Hourly
Emissions
Test
We
believe
that
implementing
our
proposed
maximum
achievable
hourly
emissions
rate
test
for
EGUs
offers
significant
benefits
over
the
current
actual­
to­
projected­
actual
emissions
test.
The
proposed
regulations
(
and
our
alternate
proposal)
would
provide
nationwide
consistency
in
how
States
implement
the
major
NSR
program
for
EGUs.
They
would
also
establish
a
uniform
emissions
test
nationally
under
the
NSPS
and
NSR
programs
for
existing
EGUs.
We
believe
a
uniform
national
emissions
test
has
merit
considering
the
substantial
emissions
reductions
from
more
efficient
mechanisms
than
major
NSR,
which
we
describe
in
Section
III
of
this
preamble.

Furthermore,
the
proposed
regulations
allow
owner/
operators
to
make
changes
that,
without
increasing
existing
capacity,
promote
the
safety,
reliability,
and
efficiency
of
EGUs.
We
do
not
want
to
discourage
plant
owners
or
operators
from
engaging
in
activities
that
are
important
to
restoring,
maintaining,
and
improving
plant
safety,
reliability,

and
efficiency.
Uncertainties
inherent
in
the
current
major
NSR
permitting
approach
can
exacerbate
the
reluctance
to
engage
in
these
activities.
To
elaborate
on
the
uncertainty
issues:
Unless
an
owner
or
operator
seeks
an
applicability
determination
from
his
or
her
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reviewing
authority,
it
can
be
difficult
for
the
owner
or
operator
to
know
with
reasonable
certainty
whether
a
particular
activity
would
trigger
major
NSR.
This
gives
the
owner
or
operator
five
choices,
two
of
which
the
owner
or
operator
is
not
likely
to
select,
and
the
other
three
of
which
have
significant
drawbacks
for
the
productivity
of
the
plant.

First,
the
owner
or
operator
may
simply
seek
an
NSR
permit.
That
course,

however,
is
likely
to
be
time­
consuming
and
expensive,
since
it
will
likely
result
in
a
requirement
to
retrofit
an
existing
plant
with
state­
of­
the
art
pollution
controls,
which
often
is
very
costly
and
can
present
significant
technical
challenges.
Therefore,
an
owner
or
operator
is
not
likely
to
select
this
option
if
it
can
be
avoided.

Second,
the
owner
or
operator
may
proceed
at
risk
without
a
reviewing
authority
determination.
That
option,
however,
is
also
not
likely
to
be
attractive
where
a
significant
replacement
activity
is
involved,
because
if
the
owner
or
operator
proceeds
without
a
reviewing
authority
determination
and
if
we
later
find
that
he
or
she
made
an
incorrect
determination
on
their
own,
the
owner
or
operator
faces
potentially
serious
enforcement
consequences.
Those
consequences
could
well
include
substantial
fines
for
violation
of
the
CAA
(
along
with
the
further
consequences
of
violation
of
the
CAA)
and
penalties
and
a
requirement
to
install
the
state­
of­
the­
art
pollution
controls,
even
though
those
controls
present
technical
issues
or
represent
a
significant
enough
expenditure
that
they
likely
would
have
deterred
the
owner
or
operator
from
seeking
a
permit
in
the
first
place.
The
owner
or
operator
is
not
likely
to
take
this
risk
if
he
or
she
believes
there
is
a
high
probability
of
these
kinds
of
consequences
and
if
he
or
she
has
other
options.
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Third,
the
owner
or
operator
may
seek
an
applicability
determination.
That
process,
too,
is
time­
consuming
and
expensive,
albeit
typically
less
so
than
seeking
a
permit.
This
path
presents
a
potentially
significant
barrier
to
EGUs
and
other
industries.

This
approach
also
is
likely
to
delay
important
projects
that
would
enhance
the
safety,

reliability,
and
efficiency
of
the
plant
while
the
owner/
operator
waits
for
the
applicability
determination.

Fourth,
the
owner
or
operator
may
forego
or
curtail
activities
that
would
enhance
the
safe,
reliable,
or
efficient
operation
of
its
plant,
instead
opting
to
repair
existing
components,
even
though
they
are
inferior
to
current
day
components
because
they
are
probably
are
less
advanced
and
less
efficient
than
current
technology.
Foregoing
the
activities
altogether
will
reduce
plant
safety,
reliability
and
efficiency;
curtailing
or
postponing
them
does
as
well,
differing
only
in
the
degree
of
these
effects.

Finally,
the
owner
or
operator
may
curtail
the
plant's
productive
capacity
by
replacing
components
with
less
than
the
best
technology
to
be
more
certain
that
the
replacement
is
within
the
regulatory
bounds.
Or
he
or
she
may
agree
to
limit
the
source's
hours
of
operation
or
capacity
or
install
air
pollution
controls
that
are
less
than
state­
of­

theart
These
alternative
courses
of
action,
however,
will
also
result
in
loss
of
plant
productivity.

The
current
approach
to
major
NSR
is
also
problematic
for
State
and
local
reviewing
authorities.
They
require
the
regulatory
authorities
to
devote
scarce
resources
to
make
complex
determinations,
including
applicability
determinations,
and
consult
with
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2005
56
other
agencies
to
ensure
that
any
determinations
are
consistent
with
determinations
made
for
similar
circumstances
in
other
jurisdictions
and/
or
that
other
reviewing
authorities
would
concur
with
the
conclusion.
In
our
June
2002
report
to
the
President,
we
concluded
that
the
current
major
NSR
program
has
impeded
or
resulted
in
the
cancellation
of
projects
that
would
have
maintained
and
improved
the
reliability,
efficiency,
or
safety
of
existing
energy
capacity.

We
believe
it
is
desirable
to
change
the
approach
to
major
NSR.
The
current
approach
discourages
sources
from
replacing
components,
and
encourages
them
to
replace
components
with
inferior
components
or
to
artificially
constrain
production
in
other
ways.

This
behavior
does
not
advance
the
central
policy
goals
of
the
major
NSR
program
as
applied
to
existing
sources.
The
central
policy
goal
is
not
to
limit
productive
capacity
of
major
stationary
sources,
but
rather
to
ensure
that
they
will
install
state­
of­
the­
art
pollution
controls
at
a
juncture
where
it
otherwise
makes
sense
to
do
so.
We
also
do
not
believe
the
outcomes
produced
by
the
approach
we
have
been
taking
have
significant
environmental
benefits
compared
with
the
approach
we
are
proposing
today.

We
believe
that
these
problems
would
be
significantly
reduced
by
the
rule
we
are
proposing
today.
Our
new
approach
would
provide
more
certainty
both
to
source
owners
or
operators
who
will
be
able
better
to
plan
activities
at
their
facilities,
and
to
reviewing
authorities
who
will
be
able
better
to
focus
resources
on
other
areas
of
their
environmental
programs
rather
than
on
time­
consuming
determinations.
The
effect
should
be
to
remove
disincentives
to
undertaking
activities
that
improve
efficiency,
safety,
reliability,
and
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33
We
discuss
the
regulatory
history
related
to
the
CMA
Exhibit
B
Settlement
Agreement
in
Section
V.
of
today's
preamble.
See
also
67
FR
80205,
December
31,
2002.

57
environmental
performance.

We
also
note
that
today's
proposed
emissions
test
would
simplify
applicability
determinations
for
sources
by
using
the
same
test
for
both
the
NSPS
and
NSR
programs.

Moreover,
it
eliminates
the
burden
of
projecting
future
emissions
and
distinguishing
between
emissions
increases
caused
by
the
change
from
those
due
solely
to
demand
growth,
because
any
increase
in
the
emissions
under
the
maximum
achievable
emissions
test
would
logically
be
attributed
to
the
change.
It
reduces
recordkeeping
and
reporting
burdens
on
sources
because
compliance
will
no
longer
rely
on
synthesizing
emissions
data
into
rolling
average
emissions.
It
improves
compliance
by
making
the
rules
more
understandable,
which
correspondingly
reduces
the
reviewing
authorities'
compliance
and
enforcement
burden.

Nonetheless,
despite
identifying
many
of
these
benefits
in
our
analysis
of
the
Settlement
Agreement
that
EPA
had
entered
into
in
Chemical
Manufacturer's
Association
v.
EPA,
No.
79­
112,
we
rejected
the
use
of
that
approach
because
we
stated
that
such
an
approach
was
not
acceptable
for
major
NSR
applicability
as
a
general
matter.
33
We
based
our
conclusions
on
concerns
that
the
Settlement
Agreement
Approach
would
allow
facilities
to
generate
paper
credits
for
netting
and
offsets
because
the
facility
may
never
have
operated
at
its
full
potential
emissions.
Moreover,
we
raised
concerns
that
unreviewed
increases
could
lead
to
increment
violations.
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34
For
a
complete
discussion
of
the
emissions
reductions
and
air
quality
impacts
of
the
BART
rule,
see
Chapter
3
of
the
RIA
for
the
BART
final
rule,
available
at
http://
www.
epa.
gov/
oar/
visibility/
actions.
html.

58
Today's
proposal
differs
from
the
Settlement
Agreement
Approach
in
an
important
way.
We
retain
the
existing
procedures
for
calculating
offset
credits
to
avoid
any
possibility
of
generating
paper
reductions.
Moreover,
we
requested
comment
on
eliminating
or
limiting
the
availability
of
netting.
Either
approach
would
alleviate
the
possibility
of
generating
paper
reductions.
One
of
the
advantages
of
our
proposal
to
eliminate
netting
is
that
there
would
be
no
unreviewed
increases.
(
That
is,
all
emission
increases,
including
those
less
than
40
tpy,
would
be
reviewed.)
On
the
other
hand,
if
we
continue
to
include
netting
provisions
in
the
major
NSR
applicability
test,
those
provisions
will
continue
to
be
based
on
actual
emissions.

Importantly,
States'
implementation
of
the
Acid
Rain,
CAIR,
and
BART
programs
will
generate
significant
reductions
in
pollution
and
thereby
decrease
the
likelihood
that
an
unreviewed
source
could
cause
an
increment
violation.
We
conducted
modeling
to
estimate
the
impact
of
the
CAIR
program
on
nationwide
emissions
trends
and
ambient
concentrations.
The
modeling
shows
that
emissions
are
predicted
to
decline
in
all
parts
of
the
country.
We
also
conducted
modeling
to
estimate
the
impact
of
the
BART
rule
on
nationwide
emissions
trends
and
visibility.
The
modeling
shows
that
emissions
will
decline
beyond
those
reductions
under
CAIR,
particularly
in
Class
I
areas.
34
With
nationwide
emissions
declining,
there
is
a
decreased
likelihood
that
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59
unpermitted
emissions
increases
could
violate
a
PSD
increment
by
returning
a
given
geographical
area
to
levels
above
that
area's
historical
actual
levels.
Accordingly,
we
now
believe
that
it
is
appropriate
to
consider
the
acknowledged
benefits
of
implementing
the
maximum
achievable
hourly
emissions
increase
test.

G.
Would
States
be
required
to
adopt
the
revised
emissions
test?

Consistent
with
our
longstanding
practice,
we
are
proposing
that
the
revised
emissions
test
would
be
a
core,
mandatory,
minimum
program
element
for
SIPs
implementing
the
part
C
and
part
D
major
NSR
programs.
We
are
also
proposing
that
State
and
local
agencies
would
submit
NSR
SIP
revisions
incorporating
the
revised
emissions
test
within
12
months
after
promulgation
of
the
final
rules.
For
the
reasons
we
articulate
in
Section
V.
C.
of
this
preamble,
we
believe
the
maximum
achievable
hourly
emissions
test
implements
Congressional
intent
for
the
major
NSR
program
and
in
a
more
effective
manner
for
EGUs
than
the
current
major
NSR
program.

Consistent
with
our
longstanding
practice,
we
are
also
proposing
that
if
a
State
were
to
decide
it
does
not
want
to
implement
the
revised
emissions
test,
that
State
would
need
to
making
a
showing
that
its
program
is
at
least
as
effective
as
our
program.

V.
Statutory
and
Regulatory
History
and
Legal
Rationale
This
section
provides
our
legal
basis
and
rationale
for
the
proposed
changes.
In
support
of
our
legal
basis
and
rationale,
this
section
provides
a
more
detailed
background
than
that
in
Section
IV.
on
the
emissions
increase
test
used
in
the
NSPS
program
and
major
NSR
program.
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35
See
House
Report
91­
1146
at
5365:

The
purpose
of
this
authority
is
to
prevent
the
occurrence
of
significant
new
air
pollution
problems
arising
from
or
associated
with
such
new
sources.
As
explained
above,
such
new
sources
may
take
the
form
either
of
entirely
new
facilities
or
expanded
or
modified
facilities,
or
of
expanded
or
modified
operations
which
result
in
substantially
increased
pollution....
The
emission
standards
shall
provide
that
sources
of
such
emissions
shall
be
designed
and
equipped
to
prevent
and
control
such
emissions
to
the
fullest
extent
compatible
with
the
available
technology
and
economic
feasibility
as
determined
by
the
Secretary.

60
A.
The
NSPS
Program
In
the
1970
CAA
Amendments,
Congress
included,
for
the
first
time,
emission
standards
for
new
sources
of
air
pollution,
termed
"
new
source
performance
standards"

(
NSPS).
[
CAA
Section
111.]
The
purpose
of
the
NSPS
program
was
to
prevent
new
air
pollution
problems
by
requiring
that
new
sources
of
emissions,
including
those
from
expanded
or
modified
existing
facilities,
be
designed
and
equipped
to
incorporate
demonstrated
emissions
controls.
35
Specifically,
Congress
required
the
EPA
to
set
emission
limitations
for
categories
of
new
stationary
sources
of
air
pollution
based
on
the
best
system
of
emissions
reduction,

considering
costs,
that
has
been
adequately
demonstrated.
Congress
also
specifically
required
that
the
NSPS
apply
to
modifications
of
existing
facilities,
and
defined
"
modification"
in
CAA
Section
111(
a)(
4)
as
follows:

"
The
term
modification
means
any
physical
change
in,
or
change
in
the
method
of
operation
of,
a
stationary
source
which
increases
the
amount
of
any
air
pollutant
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36
CAA
Section111(
a)(
4).
This
Section
has
not
been
amended
since
it
was
inserted
into
the
statute
in
1970.

37
H.
R.
Rep
91­
1146,
p.
5361
(
1970).

61
emitted
by
such
source
or
which
results
in
the
emission
of
any
air
pollutant
not
previously
emitted."
36
The
statute
does
not
specify
how
increases
in
emissions
are
to
be
determined
and
the
1970
legislative
history
does
not
directly
speak
to
it.
Nonetheless,
the
legislative
history
shows
that,
at
a
minimum,
Congress
was
concerned
about
regulating
new
sources
of
emissions
caused
by
expanded
or
modified
capacity,
as
the
following
two
statements
indicate:

Therefore,
particular
attention
must
be
given
to
new
stationary
sources
which
are
known
to
be
either
particularly
large­
scale
polluters
or
where
the
pollutants
are
extra
hazardous.
The
legislation,
therefore,
grants
authority
to
the
Secretary
of
Health,
Education,
and
Welfare
to
establish
emission
standards
for
any
such
sources
which
either
in
the
form
of
entire
new
facilities
or
in
the
form
of
expanded
or
modified
facilities,
or
because
of
expanded
or
modified
operation
or
capacity,

constitute
new
sources
of
substantially
increased
pollution.
37
Therefore,
it
would
appear
to
me
that,
for
instance,
an
old
steel
plant
which
altered
its
production
of
a
particular
unit
or
operation,
even
though
that
unit
was
an
old
unit,
would
be
controlled
just
as
its
competitor,
a
new
steel
plant,
would
be
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38
Congressional
Record­
HR
17090,
June
10,
1970
at
19212.

39
This
language
concerning
modifications
was
never
included
in
the
NSR
regulations
at
§
§
51.165,
51.166,
52.21,
52.24,
and
Appendix
S
to
part
51.
On
January
23,
1980
(
45
FR
5616),
we
amended
this
language
to
delete
the
portions
of
§
60.14
that
implemented
the
bubble
concept,
which
the
United
States
Court
of
Appeals
for
the
District
of
Columbia
Circuit
rejected
in
a
62
controlled,
where
new
equipment
plus
new
sources
of
emissions
occur?

That
is
correct.
38
On
December
23,
1971
(
36
FR
24877),
we
promulgated
the
first
NSPS
regulations.

Consistent
with
Congressional
intent
to
regulate
new
sources
of
emissions,
these
regulations
included
a
definition
of
modification
applying
to
affected
facilities
as
follows.

Modification
means
any
physical
change
in,
or
change
in
the
method
of
operation
of,
an
affected
facility
which
increases
the
amount
of
any
air
pollutant
(
to
which
a
standard
applies)
emitted
by
such
facility
or
which
results
in
the
emission
of
any
air
pollutant
(
to
which
a
standard
applies)
not
previously
emitted,...

Id.

On
December
16,
1975,
we
revised
the
definition
of
modification
in
the
NSPS
program.
40
FR
58416.
Our
revisions
clarified
how
to
measure
emissions
increases
when
there
is
a
physical
change
or
change
in
the
method
of
operation
at
an
existing
facility.

Specifically,
we
added
the
phrase
"
emitted
into
the
atmosphere"
to
the
definition
of
modification
at
40
CFR
60.2
and
added
new
provisions
to
define
how
to
measure
emissions
increases
for
purposes
of
determining
whether
a
modification
occurs,
at
40
CFR
60.14.
39
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decision
rendered
January
27,
1978.
[
Asarco,
Inc.
v.
EPA,
578
F.
2d
319
(
D.
C.
Cir.
1978).]
Following
the
Asarco
decision,
§
60.14
was
amended
to
include
the
current
provisions.

63
Our
focus
in
adding
the
regulatory
phrase
"
emission
rate
to
the
atmosphere"
was
to
regulate
facilities
only
when
they
constitute
a
new
source
of
emissions.
We
do
not
believe
that
Congress
intended
to
draw
existing
facilities
into
NSPS
applicability
when
there
was
no
increase
in
the
amount
of
pollution
that
a
facility
could
actually
emit
to
the
environment,
either
because
the
new
equipment
did
not
emit
pollutants
or
because
the
addition
of
control
devices
means
that
the
total
emissions
rate
to
the
atmosphere
did
not
increase.
In
the
proposed
preamble,
we
described
the
addition
of
the
regulatory
term
"
emitted
into
the
atmosphere"
by
reference
to
"
actual
emissions,"
measured
as
post­
control
emissions
at
capacity
instead
of
potential
emissions
without
controls.

The
proposed
amended
definition
of
"
modification"
also
includes
a
new
phrase
"

emitted
into
the
atmosphere."
The
new
phrase
clarifies
that
for
an
existing
facility
to
undergo
a
modification
there
must
be
an
increase
in
actual
emissions.
If
any
increase
in
emissions
that
would
result
from
a
physical
or
operational
change
to
an
existing
facility
can
be
offset
by
improving
an
existing
control
system
or
installing
a
new
control
system
for
that
facility,
such
a
change
would
not
be
considered
a
modification
because
there
would
be
no
increase
in
emissions
to
the
atmosphere.

The
Administrator
considered
defining
"
modification"
so
that
increases
in
pre
controlled
(
potential)
emissions
would
be
considered
modifications.
However,
the
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64
proposed
definition
of
modification
is
limited
to
increases
in
actual
emissions
in
keeping
with
the
intent
of
section
111
of
controlling
facilities
only
when
they
constitute
a
new
source
of
emissions...
Section
60.14(
b)
provides
four
mechanisms
which
the
Administrator
may
use
(
but
to
which
he
is
not
limited)
in
determining
whether
an
increase
in
emissions
has
occurred....[
T]
hese
techniques
utilize
parameters
such
as
maximum
production
rate...."

39
FR
36946,
36946­
7.

As
we
stated
in
the
preamble
for
the
proposal,
we
added
the
regulations
in
§
60.14
to
clarify
the
phrase
"
increases
the
amount
of
any
air
pollutant"
in
the
definition
of
modification
in
§
60.2
.
[
See
39
FR
36946.]
We
did
not
create
a
new
definition
of
modification
in
codifying
§
60.14,
but
instead
used
Section
60.14
to
define
how
to
determine
an
actual
emissions
increase
based
on
the
facility's
maximum
hourly
emissions
rate
considering
controls.
Under
§
60.14(
b),
we
calculate
an
emissions
increase
by
comparing
the
hourly
emissions
rate
before
and
after
the
physical
or
operational
change
using
"
parameters
such
as
maximum
production
rate...."
39
FR
36946,
36947.
We
clarified
in
the
proposed
rule
that
maximum
production
rate
should
not
be
interpreted
to
mean
the
facility's
operating
design
capacity
(
some
times
referred
to
as
name
plate
capacity)
because
this
rate
"
bears
little
relationship
to
the
actual
operating
capacity
of
the
facility."
Id.
at
36948.
Instead,
the
maximum
production
rate
refers
to
"
that
production
rate
that
can
be
accomplished
without
making
major
capital
expenditures."
Id.

Thus,
the
final
regulations
calculate
changes
in
what
a
source
is
actually
able
to
emit
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65
at
its
capacity,
considering
controls.
(
We
may
refer
to
this
test
as
the
actually­
able­
to­
emit
test.)
Under
§
60.14(
b),
we
calculate
an
emissions
increase
by
comparing
the
hourly
emissions
rate
before
and
after
the
physical
or
operational
change
using
"
parameters
such
as
maximum
production
rate...."
39
FR
36946,
36947.
Some
refer
to
this
test
as
a
"
maximum
hourly
potential­
to­
potential"
emissions
test.
However,
since
the
NSPS
test
is
based
on
actual
operating
capacity
rather
than
design
capacity,
we
believe
that
this
potential­
to­
potential
terminology
can
be
misleading,
and
prefer
the
name
"
maximum
achievable
hourly
emission
rate"
which
is
similar
to
the
provision
we
promulgated
in
the
1992
WEPCO
rule,
described
below.
As
we
discuss
in
detail
in
Section
IV.
A
of
this
preamble,
NSPS
applicability
based
on
maximum
achievable
hourly
emissions
before
and
after
a
change
was
reiterated
in
various
policy
memoranda
and
applicability
determinations
over
the
history
of
the
program.

On
July
21,
1992,
we
further
revised
the
NSPS
regulations
to
clarify
how
we
calculate
emissions
increases
at
electric
utilities.
[
See
57
FR
32314
(
final
rule);
56
FR
27630
(
June
14,
1991)
(
proposed
rule).]
Among
other
things,
this
regulation
further
defined
"
capacity"
for
electric
utilities
subject
to
the
NSPS
program.
Specifically,
we
indicated
that
utilities
could
use
the
highest
hourly
emissions
rate
achievable
by
the
facility
at
any
time
during
the
5
years
before
the
change.

In
this
rulemaking,
prompted
by
litigation
involving
the
Wisconsin
Electric
Power
Company
and
commonly
called
the
WEPCO
rule,
we
noted
that
the
pre­
existing
NSPS
program
"
examines
maximum
hourly
emission
rates,
expressed
in
kilograms
per
hour,"
that
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40
By
comparison,
we
added,
"
NSR
regulations
examine
total
emissions
to
the
atmosphere,"
that
is,
"
emissions
increases
under
NSR
are
determined
by
changes
in
annual
emissions
as
expressed
in
tons
per
year
(
tpy)."
Id.
We
explained
how
to
determine
the
annual
emissions
as
follows:
Annual
emissions
may
be
calculated
as
the
product
of
the
hourly
emissions
rate
times
the
utilization
rate,
expressed
as
hours
of
operation
per
year,
or
as
the
product
of
an
emission
factor...
in
units
of
mass
emitted
per
unit
of
process
throughput
times
the
annual
throughput...
.

Thus,
we
said,
both
NSPS
and
NSR
calculations
include
the
hourly
emission
rate,
but
the
difference
between
the
two
is
that
the
NSR
calculation
then
adds
the
annual
utilization
rate,
expressed
as
hours
of
operation
per
year.

66
is,
"[
e]
missions
increases
for
NSPS
purposes
are
determined
by
changes
in
the
hourly
emissions
rates
at
maximum
physical
capacity."
57
FR
32316.
We
explained
how
to
determine
an
hourly
rate,
as
follows.

An
hourly
emissions
rate
may
be
determined
by
a
stack
test
or
calculated
from
the
product
of
the
instantaneous
emissions
rate,
i.
e.,
the
amount
of
pollution
emitted
by
a
source,
after
control,
per
unit
of
fuel
combusted
or
material
processed
(
such
as
pounds
of
sulfur
dioxide
emitted
per
ton
of
coal
burned)
times
the
production
rate
(
such
as
tons
of
coal
burned
per
hour)....

Id.
,
n.
5.40
One
of
the
purposes
of
the
WEPCO
rule
was
to
address
problems
that
resulted
from
the
pre­
existing
method
of
calculating
the
maximum
hourly
emissions
rate
for
NSPS
purposes.
We
stated
the
following.

Under
current
regulations,
the
emissions
rate
before
and
after
a
physical
or
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67
operational
change
is
evaluated
at
each
unit
by
comparing
the
current
hourly
potential
emissions
at
maximum
operating
capacity
to
hourly
emissions
at
maximum
capacity
after
the
change.
In
this
calculation,
the
reviewing
authority
disregards
the
unit's
maximum
design
capacity.
The
original
design
capacity
of
a
unit,
to
the
extent
it
differs
from
actual
maximum
capacity
at
the
time
that
the
baseline
is
established
due
to
physical
deterioration
of
the
facility,
is
immaterial
to
this
calculation.

57
FR
32,330.
We
stated
that
current
regulations
presented
the
problem
of
"
undue
emphasis
on
the
physical
condition
of
the
affected
facility
immediately
prior
to
the
change....
For
instance,
if
a
unit
has
broken
down
and
is
in
need
of
repairs,
the
utility's
baseline
will
be
artificially
low."
Id.

Accordingly,
we
revised
the
baseline
requirement
for
electric
utilities
to
include
the
following
constraint.

No
physical
change,
or
change
in
the
method
of
operation,
at
an
existing
electric
utility
steam
generating
unit
shall
be
treated
as
a
modification
for
the
purposes
of
this
section
provided
that
such
change
does
not
increase
the
maximum
hourly
emissions
of
any
pollutant
regulated
under
this
section
above
the
maximum
hourly
emissions
achievable
at
that
unit
during
the
5
years
prior
to
the
change.

40
CFR
60.14(
h).
In
characterizing
this
requirement
as
a
"
modest"
change
from
the
preexisting
regulation,
we
described
this
requirement
as
a
more
flexible
provision
[
that]
enables
units
to
establish
a
baseline
that
is
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68
representative
of
its
physical
and
operational
capacity
in
recent
years,
while
still
precluding
the
use
of
a
baseline
tied
to
original
design
capacity,
which...
may
bear
no
relationship
to
the
facility's
capacity
in
recent
years.

57
FR
32,330.
Therefore,
the
WEPCO
rule
makes
clear
that
the
NSPS
applicability
test
for
EGUs
is
the
same
test
(
that
is,
the
actually­
able­
to­
emit
test)
that
is
generally
applicable.
Thus,
the
only
difference
in
the
NSPS
applicability
test
for
EGUs
and
non­

EGUs
is
the
method
for
determining
the
actual
operating
capacity­
for
EGUs
it
is
the
actual
operating
capacity
at
any
time
in
the
previous
5
years
and
for
non­
EGUs
it
is
actual
operating
capacity
that
is
achievable
without
a
capital
expenditure.

B.
The
Major
NSR
Program
EPA
promulgated
the
first
set
of
PSD
regulations
in
1974
(
39
FR
42510),
and
the
first
nonattainment
Major
NSR
programs
in
1976
(
41
FR
55524).
At
that
time,
the
Act
did
not
contain
specific
provisions
for
these
programs.
Instead,
the
PSD
program
evolved
from
a
lawsuit
claiming
that
the
Act
required
EPA
to
ensure
that
air
quality
did
not
deteriorate
in
areas
where
air
quality
met
the
NAAQS.
Sierra
Club
v.
Ruckelshaus,
344
F.
Supp.
253
(
D.
D.
C
1972).
We
issued
the
first
nonattainment
NSR
regulations
(
known
as
the
Emission
Offset
Interpretative
ruling)
because
attainment
dates
had
passed
and
we
received
questions
as
to
whether,
and
to
what
extent,
new
stationary
sources
could
locate
in
areas
that
failed
to
meet
the
attainment
date.

Our
preamble
to
the
1974
PSD
rules
explained
that
we
intended
the
PSD
definition
of
"
modified
source"
to
be
consistent
with
the
definition
of
that
term
under
the
NSPS
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69
regulations.
39
FR
42510,
42513.
Accordingly,
the
1974
PSD
regulations
defined
"
modification"
in
essentially
the
same
way
for
both
programs.
[
See
40
CFR
52.01(
d);
39
FR
42514;
1975.]
Similar
to
the
NSPS
provisions,
EPA
also
included
an
exclusion
for
increases
in
production
rate
and
hours
of
operation
within
the
regulatory
definition
of
physical
change
in
or
change
in
the
method
of
operation.

Congress
expressly
added
an
expanded
preconstruction
permitting
program
for
new
and
modified
major
stationary
sources
to
the
CAA
in
1977.
The
1977
Amendments
contained
different
preconstruction
permitting
requirements
for
major
stationary
sources
in
attainment
and
nonattainment
areas.
In
areas
meeting
the
NAAQS
("
attainment"
areas)
or
for
which
there
is
insufficient
information
to
determine
whether
they
meet
the
NAAQS
("
unclassifiable"
areas),
Congress
added
requirements
for
the
PSD
program
in
part
C
of
title
I
of
the
Act.
Congress
required
States
to
amend
their
implementation
plans
to
include
requirements
to
prevent
the
significant
deterioration
of
air
quality
where
such
air
quality
is
presently
cleaner
than
existing
ambient
air
quality
standards.
The
main
focus
of
the
PSD
program
was
a
ceiling
on
incremental
pollution
growth.
The
statute
at
Sections
163(
b)
and
165
(
d)
included
specific
"
increments,"
or
maximum
allowable
increases
in
particulates
and
sulfur
dioxide.
In
Section
166,
the
1977
Amendments
also
required
EPA
to
propose
regulations
for
increments
or
other
means
for
preventing
significant
deterioration
that
would
result
from
the
other
criteria
pollutants.
To
ensure
protection
of
increments
and
other
means
of
preventing
significant
deterioration,
Congress
established
a
preconstruction
permitting
program
for
major
sources
that
required
installation
of
BACT
for
major
sources.
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41
Before
1990,
Congress
provided
States
with
two
options
for
managing
the
impact
of
economic
growth
on
emissions.
A
State
could
either
provide
a
case­
by­
case
review
of
each
new
or
modified
major
source
and
require
such
source
to
obtain
offsetting
emissions,
or
the
State
could
implement
a
waiver
provision
which
allowed
the
State
to
develop
an
alternative
to
the
caseby
case
emissions
offset
requirement.
This
alternative
program
became
known
as
the
"
growth
allowance"
approach.
In
1990,
Congress
invalidated
some
of
the
existing
growth
allowances
and
shifted
the
emphasis
for
managing
growth
from
using
growth
allowances
to
using
the
case­
bycase
offset
approach.

70
Thus
Congress
established
the
PSD
program
to
allow
for
economic
growth
in
attainment
areas,
to
be
accomplished
primarily
through
preservation
of
increment.
The
PSD
program
is
implemented
primarily
through
SIP­
approved
State
preconstruction
permitting
programs
meeting
the
requirements
of
our
regulations
at
40
CFR
51.166.
Where
we
have
not
approved
a
SIP
for
an
attainment
or
unclassifiable
area,
the
program
is
implemented
by
us
or
by
the
States
according
to
the
requirements
in
40
CFR
52.21.

Congress
in
1977
was
likewise
concerned
with
permitting
new
or
modified
facilities
in
nonattainment
areas.
The
House
proposed
a
new
CAA
Section
117
for
nonattainment
areas
"
as
a
means
of
assuring
realization
of
the
dual
goals
of
attainment
air
quality
standards
and
providing
for
new
economic
growth."
[
H.
R.
Report
95­
294,
p.
19(
1977),

U.
S.
Code
Cong.
&
Admin.
News
1977,
p.
1091.]
Thus,
Congress
added
the
preconstruction
permitting
program
for
major
stationary
sources
in
nonattainment
areas
in
part
D
of
Title
1
of
the
1977
CAA
at
Section
173.
The
basic
requirements
of
the
program
as
Congress
established
them
in
CAA
Section
173
are
still
in
place:
(
1)
each
major
stationary
source
must
go
through
preconstruction
review;
(
2)
the
total
allowable
emissions
from
new
and
modified
sources
must
be
offset;
41
(
3)
the
source
must
comply
with
the
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42
See
the
first
nonattainment
area
regulations
at
Appendix
S
to
part
51,
December
21,
1976,
at
41
FR
55528/
1.
Similarly,
a
"
major
modification"
shall
include
a
modification
to
any
structure,
building,
facility,
installation
or
operation
(
or
combination
thereof)
which
increases
the
allowable
emission
rate
by
the
amounts
set
forth
above.
See
also
our
1978
regulations
at
43
FR
26380.

71
lowest
achievable
emission
rate
(
LAER);
(
4)
there
must
be
a
demonstration
that
all
major
stationary
sources
in
the
State
that
have
the
same
owner
or
operator
are
in
compliance;
and
(
5)
an
alternative
sites
analysis
must
be
conducted.
The
preconstruction
permitting
program
for
major
stationary
sources
in
nonattainment
areas,
commonly
known
as
the
nonattainment
major
NSR
program,
is
generally
implemented
through
the
SIP
according
to
our
regulations
at
40
CFR
51.165.
In
transition
periods
before
SIP
approval,
permits
must
be
issued
meeting
the
conditions
of
40
CFR
Appendix
S,
which
reflects
substantially
the
same
requirements
as
those
in
§
51.165.

Following
the
enactment
of
the
major
NSR
program
in
the
1977
CAA,
in
1978
we
promulgated
comprehensive
changes
to
the
PSD
and
nonattainment
major
NSR
regulations
to
carry
out
the
statutory
changes.
43
FR
26380.
In
the
absence
of
statutory
language
on
how
to
determine
an
emissions
increase,
we
initially
defined
emissions
increases
in
terms
of
allowable
or
potential
emissions.
42
As
with
the
NSPS
regulations,
we
defined
potential
emissions
as
uncontrolled
emissions.
Nonetheless,
when
we
interpreted
111(
a)(
4)
for
the
major
NSR
program,
we
concluded
that
the
NSPS
and
NSR
program
have
different
purposes.
We
believed
that
the
NSPS­
based
definitions
and
interpretations
should
not
be
controlling
for
NSR
purposes.
Accordingly,
in
our
1978
final
rules,
we
defined
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43
The
Court
amended
the
December
14th
opinion
on
April
21,
1980.

72
"
modification"
for
NSR
differently
than
we
defined
it
in
the
NSPS
program
by
including
a
plantwide
approach
for
reviewing
emissions
increases
(
netting),
even
though
the
Court
held
this
approach
unlawful
as
applied
in
the
NSPS
program.
[
Asarco,
Inc.
v.
EPA,
578
F.
2d
319
(
D.
C.
Cir.
1978).]

Numerous
aspects
of
our
1978
final
rules
were
challenged
by
industry,
State
and
environmental
petitioners.
In
June
1979,
the
D.
C.
Circuit
Court
issued
a
per
curiam
(
preliminary)
opinion.
[
Alabama
Power
Co.
v.
Costle,
606
F.
2d
1068
(
D.
C.
Cir.
1979).]

In
response
to
that
opinion,
we
immediately
undertook
to
revise
our
regulations
consistent
with
that
opinion
and
proposed
significant
changes
to
the
method
for
determining
whether
a
change
constitutes
a
major
modification.
Under
the
proposal,
a
major
modification
would
occur
if
a
source
increased
its
potential
to
emit
a
pollutant.

On
December
14,
1979,
the
Court
in
Alabama
Power
issued
an
opinion
that
superseded
its
per
curiam
decision.
[
Alabama
Power
v.
Costle,
636
F.
2d
323
(
D.
C.
Cir.

1979).]
43
EPA
interpreted
the
Court's
opinion
as
focusing
on
"
actual
emissions"
rather
than
"
potential
to
emit."
[
45
FR
52676,
52700.]
This
led
EPA
to
amend
its
NSR
regulations
and
to
change
the
baseline
for
measuring
emissions
increases
from
using
a
source's
potential
to
emit
to
using
the
source's
"
actual
emissions."
The
final
rules
generally
defined
pre­
change
actual
emissions
based
on
historical
emissions
(
the
average
of
annual
emissions
for
the
2
years
preceding
the
change),
but
also
included
provisions
to
Internal
and
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30,
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44
The
regulations
define
"
electric
utility
steam
generating
units"
as
any
steam
electric
generating
unit
that
is
constructed
for
the
purpose
of
supplying
more
than
one­
third
of
its
potential
electric
output
capacity
and
more
than
25
megawatts
(
MW)
of
electrical
output
to
any
utility
power
distribution
system
for
sale.
See,
for
example,
§
51.166(
b)(
30).

73
allow
source­
specific
allowables
or
potential
to
emit
to
be
a
measure
of
pre­
change
actual
emissions
in
certain
circumstances.
[
See
40
CFR
52.21(
b)(
21).]

Our
1980
regulations
resulted
in
numerous
challenges,
including
challenges
to
our
methodology
for
calculating
emissions
increases.
These
challenges
were
consolidated
in
Chemical
Manufacturer's
Association
v.
EPA,
No.­
79­
112.
EPA
entered
into
a
Settlement
Agreement
which
required
us
to
propose
an
NSPS­
like,
hourly
potential
to
hourly
potential
emissions
increase
test
for
modifications
("
CMA
Exhibit
B").

In
1992,
before
implementing
the
Settlement
Agreement,
we
promulgated
revisions
to
our
applicability
regulations
creating
special
rules
for
physical
and
operational
changes
at
EUSGUs.
[
See
57
FR
32314
(
July
21,
1992).]
44
In
this
rule,
as
noted
above,
commonly
referred
to
as
the
"
WEPCO
rule,"
we
adopted
an
actual­
to­
future­
actual
methodology
for
all
changes
at
EUSGUs
except
the
construction
of
a
new
electric
generating
unit
or
the
replacement
of
an
existing
emissions
unit.
Under
this
methodology,
the
actual
annual
emissions
before
the
change
are
compared
with
the
projected
actual
emissions
after
the
change
to
determine
if
a
physical
or
operational
change
would
result
in
a
significant
increase
in
emissions.
To
ensure
that
the
projection
is
valid,
the
rule
requires
the
utility
to
track
its
emissions
for
the
next
5
years
and
provide
to
the
reviewing
authority
information
demonstrating
that
the
physical
or
operational
change
did
not
result
in
an
emissions
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74
increase.

In
promulgating
the
WEPCO
rule,
we
also
adopted
a
presumption
that
utilities
may
use
as
baseline
emissions
the
actual
annual
emissions
from
any
2
consecutive
years
within
the
5
years
immediately
preceding
the
change.

On
July
23,
1996,
we
proposed
CMA
Exhibit
B
as
one
alternative
as
part
of
a
comprehensive
proposal
to
reform
the
NSR
regulations.
[
61
FR
38250.]
Finally,
On
December
21,
2002,
we
took
final
action
on
certain
elements
of
our
1996
proposal
and
declined
to
promulgate
the
CMA
Exhibit
B
approach.
Instead,
we
revised
the
emissions
calculation
procedures
to
include
an
actual­
to­
projected­
actual
emissions
test
for
all
sources.
[
67
FR
80290.]

While
industry,
environmental
groups
and
States
filed
petitions
for
review
with
the
United
States
Court
of
Appeals
for
the
District
of
Columbia
Circuit
regarding
both
our
1980
and
1992
rules,
those
challenges
were
not
heard
and
decided
until
earlier
this
year
when
those
challenges
were
consolidated
with
challenges
to
our
2002
revisions
to
the
major
source
NSR
program.
[
See
New
York.
v.
E.
PA.,
No.
02­
1387
(
D.
C.
Cir.
June
24,

2005).]
The
Court
upheld
EPA's
regulations
concerning
the
actual­
to­
projected­
actual
test.
Id.,
slip
op.
at
26.
While
industry
argued
that
the
statute
requires
EPA
to
use
the
same
definition
of
"
modification"
for
the
NSPS
program
and
NSR
programs,
the
Court
concluded
that
industry
had
waived
the
argument
and
thus
declined
to
address
this
issue
in
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and
Deliberative­
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or
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30,
2005
45
The
Court
expressed
a
view
that
Congress'
failure
to
expressly
incorporate
the
NSPS
regulatory
definition
of
NSPS
argues
against
a
finding
that
Congress
intended
the
NSPS
definition
to
apply
in
implementing
the
NSR
program.
Id.
at
25.

46
EPA
has
filed
a
petition
for
rehearing
in
which
we
argue
that
this
holding
was
in
error,
and
that
the
term
"
increases"
is
ambiguous
for
NSR
purposes
and
therefore
EPA
has
discretion
to
promulgate
an
actuals,
allowables,
or
potentials
interpretation.

75
its
ruling.
45
In
a
separate
part
of
its
opinion,
the
Court
held
that
EPA
had
discretion
in
defining
the
period
of
time
over
which
to
calculate
emissions,
for
purposes
of
ascertaining
whether
a
physical
or
operational
change
increases
those
emissions.
Id.
at
39­
40.
The
Court
upheld
EPA
regulations
that
revised
that
period
as
a
2­
year
period
within
the
10
years
prior
the
change.
The
Court
stated:

In
enacting
the
NSR
program,
Congress
did
not
specify
how
to
calculate
"
increases"
in
emissions,
leaving
EPA
to
fill
in
that
gap
while
balancing
the
economic
and
environmental
goals
of
the
statute.
[
citation
omitted]
Based
on
its
experience
with
the
NSR
program
and
its
examination
of
the
relevant
data,
EPA
determined
that
a
ten­
year
lookback
period
would
alleviate
the
problems
experienced
under
the
1980
rule
and
advance
the
economic
and
environmental
goals
of
the
CAA.
...
[
W]
e
defer
to
EPA's
statutory
interpretation
under
Chevron
step
2....

Id.
at
39­
40.

In
another
part
of
the
Court's
opinion,
the
Court
held
that
the
NSR
modification
requirement,
which
incorporates
by
reference
CAA
Section
111(
a)(
4),
"
unambiguously
defines
`
increases'
in
terms
of
actual
emissions."
Id.
at
62.46
On
June
15,
2005,
the
United
States
Court
of
Appeals
for
the
Fourth
Circuit
handed
down
a
decision
concerning
an
enforcement
action
against
Duke
Energy
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and
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September
30,
2005
76
Corporation
concerning
major
NSR
applicability
at
eight
electric
utilities.
[
United
States
v.

Duke
Energy
Corp.,
No.
04­
1763.]
The
court
ruled
that
"
because
Congress
mandated
that
the
PSD
definition
of
`
modification'
be
identical
to
the
NSPS
definition
of
`
modification,'

the
EPA
cannot
interpret
`
modification'
under
the
PSD
inconsistently
with
the
way
it
interprets
that
term
under
the
NSPS."
Id.,
slip
op.
at
12­
14).
The
court
also
stated
that
"
No
one
disputes
that
prior
to
enactment
of
the
PSD
statute,
the
EPA
promulgated
NSPS
regulations
that
define
the
term
`
modification'
so
that
only
a
project
that
increases
a
plant's
hourly
rate
of
emissions
constitutes
a
`
modification'"
Id.,
slip
op.
at
18.
The
Court
thus
held
that
for
purposes
of
the
PSD
program,
emissions
increases
must
be
determined
by
comparing
the
pre­
and
post­
change
maximum
hourly
emissions.

C.
Legal
Rationale
1.
Maximum
Achievable
Hourly
Emission
Test
Sections
169(
2)(
C)
and
171(
4)
of
the
Act
specify
that
the
definition
of
"
modification"
set
forth
in
CAA
Section
111(
a)(
4)
applies
in
the
PSD
and
nonattainment
major
NSR
programs.
Pursuant
to
CAA
Section
111(
a)(
4),
the
term
modification
means
"
any
physical
change
or
change
in
the
method
of
operation
of
a
stationary
source
which
increases
the
amount
of
any
air
pollutant
emitted
by
such
source
or
which
results
in
the
emission
of
any
air
pollutant
not
previously
emitted."
The
statute,
however,
does
not
prescribe
the
methodology
for
determining
when
an
emissions
increase
has
occurred
following
a
physical
change
or
change
in
the
method
of
operation.
New
York
v.
EPA,
slip
op.
at
31,
39­
40,
No.
02­
1387
(
D.
C.
Cir.
June
24,
2005).
Since
Congress
did
not
specify
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2005
77
how
to
calculate
"
increases"
in
emissions,
it
left
EPA
with
the
task
of
filling
that
gap
while
balancing
the
economic
and
environmental
goals
of
the
CAA.
Id.
at
39­
40.

When
a
statute
is
silent
or
ambiguous
with
respect
to
specific
issues,
the
relevant
inquiry
for
a
reviewing
court
is
whether
the
Agency's
interpretation
of
the
statutory
provision
is
permissible.
Chevron
U.
S.
A.,
Inc.
v.
NRDC,
Inc.
467
U.
S.
837,
865
(
1984).

Accordingly,
EPA
has
the
discretion
to
propose
a
reasonable
method
by
which
to
calculate
emissions
increases
for
purposes
of
NSR
applicability.
Although
we
do
not
assert
that
the
NSPS
interpretation
is
the
only
one
we
can
adopt
for
NSR
purposes
(
we
followed
quite
a
different
interpretation
from
1980
until
today),
at
the
very
least
we
believe
that
the
statutory
silence
on
this
issue
delineates
a
zone
of
discretion
within
which
EPA
may
operate.

As
we
discuss
in
the
previous
Section
of
this
preamble,
we
modeled
our
early
major
NSR
method
for
calculating
an
emissions
increases
after
the
existing
NSPS
program.
In
the
NSPS
program,
we
define
major
modification
as
the
maximum
achievable
hourly
increase
in
emissions
at
actual
operating
capacity,
considering
controls.
That
is,
we
defined
actual
emissions
as
post­
controlled
emissions
at
current
capacity.
Our
early
NSR
regulations
defined
emissions
increases
in
terms
of
allowable
or
potential
emissions,

consistent
with
our
interpretation
that
Congress
intended
the
modification
definition
to
apply
to
expansions
in
capacity,
but
not
to
apply
to
the
use
of
existing
capacity.
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and
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or
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30,
2005
47
The
1980
rules
revised
the
pre­
change
(
baseline)
emissions
calculation
to
one
based
on
actual
emissions,
but
retained
potential­
to­
emit
for
measuring
post­
change
emissions.

78
As
we
previously
explained,
we
promulgated
the
actual­
to­
potential
emissions
test47
in
1980,
after
interpreting
the
Alabama
Power
final
decision
as
shifting
the
focus
from
regulating
increases
in
existing
capacity
to
regulating
possible
changes
in
actual
emissions.

Our
decision
to
change
to
a
historical
actual
emissions
baseline
must
be
viewed
in
light
of
the
progress
of
air
quality
programs
at
that
time.
The
air
quality
was
significantly
degraded
in
a
number
of
areas
and
air
emission
trends
showed
a
steady
decline
in
the
quality
of
our
nation's
air
in
some
jurisdictions.
State
and
local
air
pollution
control
programs
were
just
developing,
and
the
programs
mandated
in
1990
by
parts
2,
3,
and
4
of
title
I
of
the
Act
and
programs
such
as
the
Acid
Rain
Program,
the
NOx
SIP
Call,
CAIR,
and
BART
did
not
exist.
Accordingly,
the
major
NSR
program
provided
States
one
of
the
few
opportunities
to
mitigate
rising
levels
of
air
pollution
through
regulation
of
potential
emissions
increases
from
existing
sources.
Moving
to
an
actual­
to­
potential
applicability
test
was
a
sensible
approach
for
managing
air
quality
at
that
time,
and
interpreting
the
Alabama
Power
final
decision
to
support
this
goal
was
appropriate.

The
Alabama
Power
Court
recognized
EPA's
discretion
to
define
the
same
statutory
terms
differently
in
the
NSR
and
NSPS
regulations.
[
Alabama
Power
Co.
v.

Costle,
636
F.
2d
at
397­
98
(
EPA
has
latitude
to
adopt
definitions
of
the
component
terms
of
"
source"
that
are
different
in
scope
from
those
that
may
be
employed
for
NSPS
and
PSD,
due
to
differences
in
the
purpose
and
structure
of
the
two
programs).]
Moreover,
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2005
79
while
the
Court
held
that
potential
to
emit
must
be
determined
considering
controls,
and
that
NSR
major
modifications
must
be
determined
considering
total
or
net
emissions
from
the
source
over
a
contemporaneous
period,
the
court
otherwise
left
it
to
EPA's
discretion
to
determine
how
emissions
increases
following
a
physical
change
or
change
in
the
method
of
operation
were
to
be
determined,
including
the
currency
for
measuring
the
emissions
increases.
Id.
at
353­
54,
401­
03.

In
using
our
discretion
for
defining
the
component
term
"
increases
in
any
pollutant
emitted"
within
the
definition
of
"
modification,"
we
are
mindful
of
Congress'
directive
that
the
major
NSR
program
be
tailored
in
such
a
way
as
to
balance
the
need
for
environmental
protection
against
the
desires
to
encourage
economic
growth.
In
this
context,
the
appropriate
methodologies
for
measuring
emissions
increases
is
inherently
linked
to
our
responsibility
to
guide
the
States
in
their
efforts
to
achieve
and
maintain
an
effective,

comprehensive
air
quality
program,
of
which
the
major
NSR
program
is
only
one
component.
See
Section
101(
a)
of
the
Act.
Accordingly,
as
both
we
and
the
States
have
gained
experience
in
managing
air
quality,
we
have
amended
the
applicability
provisions
of
the
NSR
regulations
to
better
balance
the
need
for
environmental
protection
and
economic
growth,
and
the
administrative
burden
of
running
the
program.
(
See
for
example
57
FR
32314,
July
21,
1992;
67
FR
80186,
December
31,
2002;
68
FR
61248,
October
27,
2003
)

In
light
of
the
progress
of
air
quality
programs
under
the
1990
CAA
to
reduce
EGU
emissions
and
the
policy
goals
of
the
major
NSR
program,
we
considered
the
appropriate
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2005
80
scope
of
the
major
NSR
program
as
it
applies
to
existing
sources.
The
NSR
program's
scope
is
closely
related
to
the
scope
of
the
NSPS
program,
created
7
years
earlier
in
the
CAA
Amendments
of
1970.
In
section
111
of
the
CAA,
which
sets
forth
the
NSPS
provisions,
Congress
applied
the
NSPS
to
``
new
sources.''
[
CAA
Sections
111(
b)(
1)(
B),
111(
b)(
4).]
Congress
determined
that
as
a
general
matter
it
would
not
impose
the
NSPS
standards
on
existing
sources,
instead
leaving
to
the
State
and
local
permitting
authorities
the
decision
of
the
extent
to
which
to
regulate
those
sources
through
``
State
Implementation
Plans''
designed
to
implement
National
Ambient
Air
Quality
Standards
(
NAAQS).
[
See
CAA
Section
110.]
Congress
followed
a
similar
approach
in
determining
the
scope
of
the
major
NSR
program
established
by
the
1977Amendments
to
the
CAA.
As
amended,
the
CAA
specifies
that
State
Implementation
Plans
must
contain
provisions
that
require
sources
to
obtain
major
NSR
permits
prior
to
the
point
of
``
construction''
of
a
source.
[
CAA
Sections172(
c)(
5);
165
(
a).]
By
contrast,
the
CAA
generally
leaves
to
State
and
local
permitting
authorities
in
the
first
instance
the
question
of
the
extent,
means,
and
timetable
for
obtaining
reductions
from
existing
sources
that
are
needed
to
comply
with
NAAQS.
[
See
CAA
Sections
172(
c)(
1),
161.]
NSR's
applicability
to
existing
sources
that
undergo
a
``
modification''
is
an
exception
to
this
basic
concept.

This
exception
likewise
finds
its
roots
in
the
NSPS
program's
applicability
to
``
modifications''
of
existing
sources.
The
1970
CAA
made
the
NSPS
program
applicable
to
modifications
through
its
definition
of
a
``
new
source,''
which
it
defined
as
``
any
stationary
source,
the
construction
or
modification
of
which
is
commenced
after
the
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48
45
FR
52676,
August,
7,
1980;
57
FR
32314,
July
21,
1992;
67
FR
80186,
December
31,
2002
81
publication
of
regulations
*
*
*
prescribing
a[
n
applicable]
standard
of
performance*
*
*.''

[
CAA
Section
111(
a)(
2).]
CAA
Section
111(
a)(
4),
in
turn,
defined
a``
modification''
as
``
any
physical
change
in,
or
change
in
the
method
of
operation
of,
a
stationary
source
which
increases
the
amount
of
any
air
pollutant
emitted
from
such
source
or
which
results
in
the
emission
of
any
air
pollutant
not
previously
emitted.''

The
1980,
1992
and
2002
rules48
were
reasonable
interpretations
of
the
statutory
language
in
CAA
Section
111(
a)(
4)
for
purposes
of
the
major
NSR
program
and
the
air
quality
needs
of
the
country
at
those
times,
and
continue
to
be
reasonable
in
many
respects.

Nonetheless,
we
retain
discretion
to
adopt
other
constructs
for
determining
emissions
increases
following
a
physical
change
or
change
in
the
method
of
operation
when
they
make
sense
in
particular
circumstances.
The
proposed
regulations
would
establish
a
uniform
emissions
test
nationally
under
the
NSPS
and
NSR
programs
for
existing
EGUs.

They
would
also
streamline
requirements
for
EGUs.
Accordingly,
we
believe
that
it
is
appropriate
to
tailor
the
major
NSR
program
for
EGUs
to
regulate
modifications
that
result
in
increases
to
an
EGU's
existing
capacity.
The
maximum
achievable
hourly
emission
test
is
an
appropriate
tool
for
this
purpose.

The
Court
in
New
York
v.
EPA
held
that
the
language
of
the
CAA
indicates
that
Congress
intended
to
apply
NSR
to
changes
that
increase
actual
emissions,
instead
of
potential
or
allowable
emissions.
Slip
op.
at
64.
The
court
based
its
opinion,
in
part,
on
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49
As
previously
stated,
the
United
States
has
filed
a
petition
for
rehearing
on
this
aspect
of
the
Court's
decision
in
New
York
v.
EPA.

82
the
Alabama
Power
Court's
finding
that
the
term
"
emit"
in
the
phrase
"
emit,
or
have
the
potential
to
emit"
within
the
definition
of
major
emitting
facility,
is
"
some
measure
of
actual
emissions."
New
York
v.
EPA,
slip
op.
at
63,
citing
Alabama
Power
,
636
F.
2d
at
353
(
emphasis
added).
49
To
the
extent
that
the
Alabama
Power
Court's
holding
relating
to
the
definition
of
major
emitting
facility
in
CAA
Section
169(
1)
should
have
any
persuasive
value
in
interpreting
a
different
component
term
(
increases
the
amount
of
any
air
pollutant)
in
a
different
definition
[
definition
of
modification
in
CAA
111(
a)(
4)]
in
the
Act,
the
Court's
reference
to
"
some
measure
of
actual
emissions"
indicates
that
the
statute
allows
for
different
ways
of
measuring
actual
emissions.

We
believe
that
the
maximum
achievable
hourly
emissions
test
provides
"
some
measure
of
actual
emissions."
For
most,
if
not
all
EGUs,
the
amount
at
which
the
unit
is
actually
able
to
emit
 
its
maximum
achievable
hourly
rate
 
is
equivalent
to
that
unit's
maximum
actual
hourly
rate
during
the
relevant
period.
States
require
most,
if
not
all
EGUs,
to
perform
periodic
performance
tests
under
applicable
State
Implementation
Plans
and
enhanced
monitoring
requirements.
The
NSPS
regulations
require
a
source
to
conduct
testing
based
on
representative
performance
of
the
affected
facility.
[
40
CFR
60.8(
c).]
In
the
National
Stack
Test
Guidance
that
we
issued
in
February
2004,
we
recommended
that
facilities
conduct
performance
tests
"
under
the
most
severe
conditions
that
create
the
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See
the
EPA
memorandum,
Issuance
of
the
Clean
Air
Act
National
Stack
Testing
Guidance,
from
Michael
M.
Stahl,
Director,
Office
of
Compliance,
to
Regional
Compliance/
Enforcement
Division
Directors,
February
2,
2004,
pg.
10.
available
at
http://
www.
epa.
gov/
Compliance/
resources/
policies/
monitoring/
caa/
stacktesting.
pdf.

83
highest
emissions."
50
Accordingly,
most
EGUs
actually
emit
at
the
highest
level
at
which
they
are
capable
of
emitting
at
some
time
within
a
5
year
baseline
period.

One
way
in
which
the
maximum
achievable
hourly
emissions
test
differs
from
the
way
actual
emissions
are
measured
under
the
current
actual­
to­
projected­
actual
test
is
that
the
former
measures
actual
emissions
over
an
hourly
period
rather
than
over
an
annual
period.
When
Congress
enacted
the
1977
amendments
to
the
CAA
creating
the
NSR
program,
it
did
not
specify
how
increases
in
emissions
were
to
be
calculated,
or
over
what
increment
of
time
emissions
should
be
measured.
Nonetheless,
Congress
was
likely
aware,

before
it
enacted
the
1977
Amendments,
that
we
calculated
emissions
increases
in
terms
of
kg/
hr
to
determine
whether
a
project
resulted
in
a
"
modification."
Congress
did
not
indicate
anywhere
in
the
1977
Amendments
or
the
legislative
history
that
our
use
of
a
kg/
hr
measure
of
emissions
would
be
contrary
to
the
purposes
of
the
NSR
program.

Accordingly,
we
believe
that
we
have
discretion
to
determine
the
appropriate
increment
of
time
over
which
to
measure
actual
emissions
for
purposes
of
determining
whether
emissions
increases
have
occurred
in
the
major
NSR
program.

We
believe
that
it
is
reasonable
to
use
an
hourly
period
to
calculate
actual
emissions
for
purposes
of
measuring
emissions
increases
in
the
major
NSR
program.
Prior
to
Congress'
enactment
of
the
major
NSR
provisions
in
the
CAA
Amendments
of
1977,
the
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84
NSPS
regulations
calculated
emissions
increases
from
physical
and
operational
changes
in
terms
of
hourly
emissions.
Our
1975
NSPS
regulations
provided
that
"
any
physical
or
operational
change
to
an
existing
facility
which
results
in
an
increase
in
the
emission
rate
to
the
atmosphere
of
any
pollutant
to
which
a
standard
applies
shall
be
considered
a
modification
with
the
meaning...
of
the
Act,"
with
"
emission
rate...
expressed
as
kg/
hr
of
any
pollutant
discharged
to
the
atmosphere."
[
40
FR
58416,
58419
(
December
16,
1975)]

Even
before
the
1975
NSPS
rule,
we
put
forth
a
definition
of
"
modification"
in
a
1974
regulation
implementing
what
became
known
as
the
"
Prevention
of
Significant
Deterioration"
program.
[
39
FR
42510
(
December
5,
1974).]
The
regulation's
preamble
further
provided
that
we
intended
the
term
"
modified
source"
to
be
"
consistent
with
the
definition
used
in
the
[
NSPS]."
Id.
at
42513.

We
further
believe
that
today's
revised
emissions
test
does
not
result
in
a
substantially
different
outcome
from
the
actual­
to­
projected­
actual
test.
The
current
major
NSR
regulations
measure
actual
emissions
differently
from
the
emissions
test
we
are
proposing
by
assessing
changes
in
emissions
relative
to
historical
emissions
over
a
baseline
period
defined
in
terms
of
annual
emissions.
Nonetheless,
like
the
NSPS
test,
the
major
NSR
regulations
allow
for
consideration
of
an
emissions
unit's
operating
capacity
in
determining
whether
a
change
results
in
an
emissions
increase.
Under
the
actual­

toprojected
actual
test,
a
source
can
subtract
from
its
post
project
emissions
those
emissions
that
the
unit
could
have
accommodated
during
the
baseline
period
and
that
are
unrelated
to
the
change
(
sometimes
referred
to
as
the
"
demand
growth
exclusion").
That
is,
the
source
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85
can
emit
up
to
its
current
maximum
capacity
without
triggering
major
NSR
under
the
actual­
to­
projected­
actual
test,
as
long
as
the
increase
is
unrelated
to
the
physical
or
operational
change.
The
NSPS
approach
thus
differs
from
the
major
NSR
test
only
by
when
a
source
considers
operating
capacity
in
the
methodology,
and
by
assuming
that
a
source's
use
of
existing
operating
capacity
is
unrelated
to
the
change.

Although
the
approaches
differ,
applying
the
maximum
achievable
hourly
emissions
test
for
EGUs
in
the
major
NSR
program
has
merit
because
it
reduces
the
administrative
burden
of
the
NSR
program.
In
view
of
this,
allowing
use
of
the
maximum
achievable
hourly
rate
test
reasonably
balances
the
economic
need
of
sources
to
use
existing
operating
capacity
with
the
environmental
benefit
of
regulating
those
emissions
increases
related
to
a
change.
Moreover,
allowing
use
of
this
approach
for
EGUs
is
a
reasonable
use
of
our
discretion
to
define
how
we
measure
emissions
increases
for
purposes
of
the
major
NSR
program,
because
it
reduces
administrative
burden
associated
with
the
emissions
calculation
procedure,
and
considers
the
effectiveness
of
other
regulatory
programs
in
regulating
use
of
existing
EGU
capacity.

Finally,
the
test
allows
sources
to
undertake
projects
designed
to
improve
the
efficiency,
reliability,
and
safety
of
the
EGU
without
necessitating
a
finding
that
postchange
emissions
at
such
a
unit
are
unrelated
to
regulated
physical
or
operational
changes.

In
our
2003
final
rule
on
the
Equipment
Replacement
Provision
of
the
Routine
Maintenance,
Repair
and
Replacement
Exclusion
for
NSR
(
68
FR
61248,
October
27,

2003),
we
articulated
our
position
that
activities
designed
to
promote
safety,
reliability,
and
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86
efficiency
of
emissions
units
should
not
be
subject
to
major
NSR,
yet
it
is
often
these
types
of
projects
that
raise
questions
as
to
whether
post­
change
emissions
are
related
to
a
change.
The
maximum
achievable
hourly
emission
test
encourages
sources
to
undertake
such
projects
by
focusing
reviewing
authority
resources
on
changes
that
add
new
operating
capacity
rather
than
on
projects
that
restore
a
source
to
normal
operations.
Importantly,

short
term
emissions
are
a
good
indicator
for
operating
capacity.
That
is,
longer
averaging
periods,
such
as
an
annual
basis,
can
mask
spikes
in
production.

2.
Maximum
Achieved
Hourly
Emissions
Test
As
we
stated
in
Section
IV.
B.
of
this
preamble,
we
also
believe
that,
like
the
maximum
achievable
hourly
emissions
test,
the
maximum
achieved
emissions
test
is
a
measure
of
a
source's
actual
emissions.
The
maximum
achieved
hourly
emissions
test
is
based
on
a
specific
measure
of
historical
actual
emissions
during
a
representative
period.

Therefore,
even
though
it
is
not
our
preferred
option,
we
believe
that
a
test
based
on
maximum
achieved
hourly
emissions
satisfies
the
requirement
that
major
NSR
applicability
be
based
on
"
some
measure
of
actual
emissions."
For
the
reasons
that
we
state
in
Section
V.
C.
1
of
this
preamble,
we
believe
we
have
discretion
to
adopt
a
maximum
hourly
achieved
emissions
test
for
determining
whether
there
is
an
increase
in
emissions
following
a
physical
change
or
change
in
the
method
of
operation.
We
request
comment
on
this
option
and
on
whether
it
satisfies
the
requirement
that
major
NSR
applicability
be
based
on
a
measure
of
actual
emissions.

We
request
public
comment
on
all
aspects
of
the
legal
basis
in
today's
proposed
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87
action.

VI.
Statutory
and
Executive
Order
Reviews
A.
Executive
Order
12866
 
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,
1993),
the
Agency
must
determine
whether
the
regulatory
action
is
"
significant"
and
therefore
subject
to
Office
of
Management
and
Budget
(
OMB)
review
and
the
requirements
of
the
Executive
Order.
The
Order
defines
"
significant
regulatory
action"
as
one
that
is
likely
to
result
in
a
rule
that
may:

(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,
competition,

jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
tribal
governments
or
communities;

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

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

Pursuant
to
the
terms
of
Executive
Order
12866,
OMB
has
notified
EPA
that
it
considers
this
a
"
significant
regulatory
action"
within
the
meaning
of
the
Executive
Order.

EPA
has
submitted
this
action
to
OMB
for
review.
Changes
made
in
response
to
OMB
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suggestions
or
recommendations
will
be
documented
in
the
public
record.

B.
Paperwork
Reduction
Act
The
information
collection
requirements
in
this
proposed
rule
have
been
submitted
for
approval
to
the
Office
of
Management
and
Budget
(
OMB)
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
The
Information
Collection
Request
(
ICR)

document
prepared
by
EPA
has
been
assigned
EPA
ICR
number
1230.18.

Certain
records
and
reports
are
necessary
for
the
State
or
local
agency
(
or
the
EPA
Administrator
in
non­
delegated
areas),
for
example,
to:
(
1)
confirm
the
compliance
status
of
stationary
sources,
identify
any
stationary
sources
not
subject
to
the
standards,
and
identify
stationary
sources
subject
to
the
rules;
and
(
2)
ensure
that
the
stationary
source
control
requirements
are
being
achieved.
The
information
would
be
used
by
the
EPA
or
State
enforcement
personnel
to
(
1)
identify
stationary
sources
subject
to
the
rules,
(
2)

ensure
that
appropriate
control
technology
is
being
properly
applied,
and
(
3)
ensure
that
the
emission
control
devices
are
being
properly
operated
and
maintained
on
a
continuous
basis.
Based
on
the
reported
information,
the
delegate
tribes
can
decide
which
plants,

records,
or
processes
should
be
inspected.

The
proposed
rule
would
reduce
burden
for
owners
and
operators
of
major
stationary
sources.
While
we
do
not
expect
a
change
in
the
number
of
permit
actions
due
to
the
proposed
changes,
we
expect
the
proposed
rule
would
simplify
applicability
determinations,
eliminate
the
burden
of
projecting
future
emissions
and
distinguishing
between
emissions
increases
caused
by
the
change
from
those
due
solely
to
demand
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89
growth,
and
reduce
recordkeeping
and
reporting
burdens.
Over
the
3­
year
period
covered
by
the
ICR,
we
estimate
an
average
annual
reduction
in
burden
of
about
5,870
hours
and
$
462,000
for
all
industry
entities
that
would
be
affected
by
the
proposed
rule.
For
the
same
reasons,
we
also
expect
the
proposed
rule
to
reduce
burden
for
State
and
local
authorities
reviewing
permits
when
fully
implemented.
However,
there
would
be
a
one­
time,

additional
burden
for
State
and
local
agencies
to
revise
their
SIPs
to
incorporate
the
proposed
changes.
We
estimate
this
one­
time
burden
to
be
about
2,240
annual
hours
and
$
83,000
for
all
State
and
local
reviewing
authorities
that
would
be
affected
by
this
proposed
rule.

Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.

This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purpose
of
responding
to
the
information
collection;
adjust
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
respond
to
a
collection
of
information;
search
existing
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.

An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,

a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
We
will
continue
to
present
OMB
control
numbers
in
a
consolidated
table
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format
to
be
codified
in
40
CFR
part
9
of
the
Agency's
regulations,
and
in
each
CFR
volume
containing
EPA
regulations.
The
table
lists
the
section
numbers
with
reporting
and
recordkeeping
requirements,
and
the
current
OMB
control
numbers.
This
listing
of
the
OMB
control
numbers
and
their
subsequent
codification
in
the
CFR
satisfy
the
requirements
of
the
Paperwork
Reduction
Act
(
44
U.
S.
C.
3501
et
seq.)
and
OMB's
implementing
regulations
at
5
CFR
part
1320.

To
comment
on
the
Agency's
need
for
this
information,
the
accuracy
of
the
provided
burden
estimates,
and
any
suggested
methods
for
minimizine
respondent
burden,

including
use
of
automated
collection
techniques,
EPA
has
established
a
public
docket
for
this
rule,
which
includes
this
ICR,
under
Docket
ID
number
OAR­
2005­
1064.
Submit
any
comments
related
to
the
ICR
for
this
proposed
rule
to
EPA
and
OMB.
See
`
Addresses'

section
at
the
beginning
of
this
notice
for
where
to
submit
comments
to
EPA.
Send
comments
to
OMB
at
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
725
17th
Street,
Northwest,
Washington,
DC
20503,
Attention:

Desk
Officer
for
EPA.
Since
OMB
is
required
to
make
a
decision
concerning
the
ICR
between
30
and
60
days
after
[
Insert
date
of
publication
in
the
FEDERAL
REGISTER],
a
comment
to
OMB
is
best
assured
of
having
its
full
effect
if
OMB
receives
it
by
[
Insert
date
30
days
after
publication
in
the
FEDERAL
REGISTER].
The
final
rule
will
respond
to
any
OMB
or
public
comments
on
the
information
collection
requirements
contained
in
this
proposal.

C.
Regulatory
Flexibility
Act
(
RFA)
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The
RFA
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedure
Act
or
any
other
statute
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.

For
purposes
of
assessing
the
impacts
of
today's
notice
on
small
entities,
small
entity
is
defined
as:
(
1)
a
small
business
that
is
a
small
industrial
entity
as
defined
in
the
U.
S.
Small
Business
Administration
(
SBA)
size
standards.
(
See
13
CFR
121.201);
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district,

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

After
considering
the
economic
impacts
of
today's
notice
on
small
entities,
I
certify
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
In
determining
whether
a
rule
has
a
significant
economic
impact
on
a
substantial
number
of
small
entities,
the
impact
of
concern
is
any
significant
adverse
economic
impact
on
small
entities,
since
the
primary
purpose
of
the
regulatory
flexibility
analyses
is
to
identify
and
address
regulatory
alternatives
"
which
minimize
any
significant
economic
impact
of
the
proposed
rule
on
small
entities."
5
U.
S.
C.
sections
603
and
604.
Thus,
an
agency
may
certify
that
a
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities
if
the
rule
relieves
regulatory
burden,
or
otherwise
has
a
positive
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economic
effect,
on
all
of
the
small
entities
subject
to
the
rule.

We
believe
that
today's
proposed
rule
changes
will
relieve
the
regulatory
burden
associated
with
the
major
NSR
program
for
all
EGU,
including
any
EGU
that
are
small
businesses.
This
is
because
the
proposed
rule
would
simplify
applicability
determinations,

eliminate
the
burden
of
projecting
future
emissions
and
distinguishing
between
emissions
increases
caused
by
the
change
from
those
due
solely
to
demand
growth,
and
by
reducing
recordkeeping
and
reporting
burdens.
As
a
result,
the
program
changes
provided
in
the
proposed
rule
are
not
expected
to
result
in
any
increases
in
expenditure
by
any
small
entity.

We
have
therefore
concluded
that
today's
proposed
rule
would
relieve
regulatory
burden
for
all
small
entities.
We
continue
to
be
interested
in
the
potential
impacts
of
the
proposed
rule
on
small
entities
and
welcome
comments
on
issues
related
to
such
impacts.

D.
Unfunded
Mandates
Reform
Act
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
P.
L.
104­
4,

establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
EPA
generally
must
prepare
a
written
statement,
including
a
cost­
benefit
analysis,
for
proposed
and
final
rules
with
"
Federal
mandates"
that
may
result
in
expenditures
to
State,
local,
and
tribal
governments,
in
the
aggregate,
or
to
the
private
sector,
of
$
100
million
or
more
in
any
one
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
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costly,
most
cost­
effective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
EPA
to
adopt
an
alternative
other
than
the
least
costly,
most
cost­
effective
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
it
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
EPA
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.

We
have
determined
that
this
rule
would
not
contain
a
Federal
mandate
that
would
result
in
expenditures
of
$
100
million
or
more
by
State,
local,
and
tribal
governments,
in
the
aggregate,
or
the
private
sector
in
any
1
year.
Although
initially
these
changes
are
expected
to
result
in
a
small
increase
in
the
burden
imposed
upon
reviewing
authorities
in
order
for
them
to
be
included
in
the
State's
SIP,
these
revisions
would
ultimately
simplify
applicability
determinations,
eliminate
the
burden
of
reviewing
projected
future
emissions
and
distinguishing
between
emissions
increases
caused
by
the
change
from
those
due
solely
to
demand
growth,
and
reduce
the
burden
associated
with
making
compliance
determinations.
Thus,
today's
action
is
not
subject
to
the
requirements
of
sections
202
and
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94
205
of
the
UMRA.

For
the
same
reasons
stated
above,
we
have
determined
that
today's
notice
contains
no
regulatory
requirements
that
might
significantly
or
uniquely
affect
small
governments.

Thus,
today's
action
is
not
subject
to
the
requirements
of
section
203
of
the
UMRA.

E.
Executive
Order
13132
 
Federalism
Executive
Order
13132,
entitled
"
Federalism"
(
64
FR
43255,
August
10,
1999),

requires
EPA
to
develop
an
accountable
process
to
ensure
"
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications."
"
Policies
that
have
federalism
implications"
is
defined
in
the
Executive
Order
to
include
regulations
that
have
"
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government."

This
proposed
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
While
this
rule
will
result
in
some
expenditures
by
the
States,
we
expect
those
expenditures
to
be
limited
to
a
one­
time
burden
to
be
about
2,240
annual
hours
and
$
83,000
for
all
State
and
local
reviewing
authorities
that
would
be
affected
by
this
proposed
rule.
This
figure
includes
the
small
increase
in
the
burden
imposed
upon
reviewing
authorities
in
order
for
them
to
revise
the
State's
SIP.
However,
these
revisions
would
ultimately
simplify
applicability
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determinations,
eliminate
the
burden
of
reviewing
projected
future
emissions
and
distinguishing
between
emissions
increases
caused
by
the
change
from
those
due
solely
to
demand
growth,
and
reduce
the
burden
associated
with
making
compliance
determinations.

This
will
in
turn
reduce
the
overall
burden
of
the
program.
Thus,
Executive
Order
13132
does
not
apply
to
this
rule.

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

F.
Executive
Order
13175
 
Consultation
and
Coordination
with
Indian
Tribal
Governments
Executive
Order
13175,
entitled
"
Consultation
and
Coordination
with
Indian
Tribal
Governments"
(
65
FR
67249,
November
9,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
"
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications."
This
proposed
rule
does
not
have
tribal
implications,
as
specified
in
Executive
Order
13175.
There
are
no
Tribal
authorities
currently
issuing
major
NSR
permits.
To
the
extent
that
today's
proposed
rule
may
apply
in
the
future
to
any
EGU
that
may
locate
on
tribal
lands,
tribal
officials
are
afforded
the
opportunity
to
comment
on
tribal
implications
in
today's
notice.
Thus,
Executive
Order
13175
does
not
apply
to
this
rule.

Although
Executive
Order
13175
does
not
apply
to
this
proposed
rule,
EPA
specifically
solicits
comment
on
this
proposed
rule
from
tribal
officials.
We
will
also
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consult
with
tribal
officials,
including
officials
of
the
Navaho
Nation
lands
on
which
Navajo
Power
Plant
and
Four
Corners
Generating
Plant
are
located,
before
promulgating
the
final
regulations.

G.
Executive
Order
13045
 
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045:
"
Protection
of
Children
from
Environmental
health
Risks
and
Safety
Risks"
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that:
(
1)
is
determined
to
be
"
economically
significant"
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
the
Agency
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered
by
the
Agency.

EPA
interprets
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5­
501
of
the
Order
has
the
potential
to
influence
the
regulation.
This
proposed
rule
is
not
subject
to
Executive
Order
13045
because
it
does
not
establish
an
environmental
standard
intended
to
mitigate
health
or
safety
risks.

H.
Executive
Order
13211
 
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
This
rule
is
not
a
"
significant
energy
action"
as
defined
in
Executive
Order
13211,

"
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
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Use"
(
66
FR
28355
(
May
22,
2001))
because
it
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy.
In
fact,
this
rule
improves
owner/
operator
flexibility
concerning
the
supply,
distribution,
and
use
of
energy.

Specifically,
the
propose
rule
would
increase
owner/
operators'
ability
to
utilize
existing
capacity
at
EGUs.

I.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
of
1995
("
NTTAA"),
Public
Law
No.
104­
113,
12(
d)
(
15
U.
S.
C.
272
note)
directs
EPA
to
use
voluntary
consensus
standards
in
its
regulatory
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(
for
example,
materials
specifications,
test
methods,
sampling
procedures,
and
business
practices)
that
are
developed
or
adopted
by
voluntary
consensus
standards
bodies.
The
NTTAA
directs
EPA
to
provide
Congress,
through
OMB,

explanations
when
the
Agency
decides
not
to
use
available
and
applicable
voluntary
consensus
standards.

Today's
proposed
rule
does
not
involve
technical
standards.
Therefore,
EPA
is
not
considering
the
use
of
any
voluntary
consensus
standards.

List
of
Subjects
in
40
CFR
Parts
51
and
52
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Electric
Generating
Unit,
BACT,
LAER,
Nitrogen
Oxides,
Sulfur
Dioxide,
BART,
Clean
Air
Interstate
Rule
Internal
and
Deliberative­
Do
Not
Quote,
Cite,
Copy,
or
Distribute
September
30,
2005
98
____________________

Dated:

_____________________

Stephen
L.
Johnson,
Administrator
