Document ID: EPA-HQ-OAR-2003-0053-1960
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2005-03-10T05:00Z

1
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
4.
Part
51
is
amended
by
adding
§
51.123
to
Subpart
G
to
read
as
follows:

§
51.123
Findings
and
requirements
for
submission
of
State
implementation
plan
revisions
relating
to
emissions
of
oxides
of
nitrogen
pursuant
to
the
Clean
Air
Interstate
Rule.

(
a)(
1)
Under
section
110(
a)(
1)
of
the
CAA,
42
U.
S.
C.

7410(
a)(
1),
the
Administrator
determines
that
each
State
identified
in
paragraph
(
c)(
1)
and
(
2)
of
this
section
must
submit
a
SIP
revision
to
comply
with
the
requirements
of
section
110(
a)(
2)(
D)(
i)(
I)
of
the
CAA,
42
U.
S.
C.
7410(
a)(
2)(
D)(
i)(
I),

through
the
adoption
of
adequate
provisions
prohibiting
sources
and
other
activities
from
emitting
NOX
in
amounts
that
will
contribute
significantly
to
nonattainment
in,
or
interfere
with
maintenance
by,
one
or
more
other
States
with
respect
to
the
fine
particles
(
PM2.5)
NAAQS.

(
2)(
a)
Under
section
110(
a)(
1)
of
the
CAA,
42
U.
S.
C.

7410(
a)(
1),
the
Administrator
determines
that
each
State
identified
in
paragraph
(
c)(
1)
and
(
3)
of
this
section
must
submit
a
SIP
revision
to
comply
with
the
requirements
of
section
110(
a)(
2)(
D)(
i)(
I)
of
the
CAA,
42
U.
S.
C.
7410(
a)(
2)(
D)(
i)(
I),

through
the
adoption
of
adequate
provisions
prohibiting
sources
and
other
activities
from
emitting
NOX
in
amounts
that
will
contribute
significantly
to
nonattainment
in,
or
interfere
with
2
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
maintenance
by,
one
or
more
other
States
with
respect
to
the
8­

hour
ozone
NAAQS.

(
b)
For
each
State
identified
in
paragraph
(
c)
of
this
section,
the
SIP
revision
required
under
paragraph
(
a)
will
contain
adequate
provisions,
for
purposes
of
complying
with
section
110(
a)(
2)(
D)(
i)(
I)
of
the
CAA,
42
U.
S.
C.

7410(
a)(
2)(
D)(
i)(
I),
only
if
the
SIP
revision
contains
control
measures
that
assure
compliance
with
the
applicable
requirements
of
this
section.

(
c)
In
addition
to
being
subject
to
the
requirements
in
paragraphs
(
b)
and
(
d)
of
this
section:

(
1)
Alabama,
Florida,
Illinois,
Indiana,
Iowa,
Kentucky,

Louisiana,
Maryland,
Michigan,
Mississippi,
Missouri,
New
York,

North
Carolina,
Ohio,
Pennsylvania,
South
Carolina,
Tennessee,

Virginia,
West
Virginia,
Wisconsin,
and
the
District
of
Columbia
shall
be
subject
to
the
requirements
contained
in
paragraphs
(
e)

through
(
cc)
of
this
section;

(
2)
Georgia,
Minnesota,
and
Texas
shall
be
subject
to
the
requirements
in
paragraphs
(
e)
through
(
o)
and
(
cc)
of
this
section;
and
(
3)
Arkansas,
Connecticut,
Delaware,
Massachusetts,
and
New
Jersey
shall
be
subject
to
the
requirements
contained
in
paragraphs
(
q)
through
(
cc)
of
this
section.

(
d)(
1)
The
State's
SIP
revision
under
paragraph
(
a)
of
this
3
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
section
must
be
submitted
to
EPA
by
no
later
than
[
Insert
the
date
18
months
(
540
days)
from
the
date
on
which
the
Administrator
signs
the
final
Clean
Air
Interstate
Rule].

(
2)
The
requirements
of
appendix
V
to
this
part
shall
apply
to
the
SIP
revision
under
paragraph
(
a)
of
this
section.

(
3)
The
State
shall
deliver
5
copies
of
the
SIP
revision
under
paragraph
(
a)
of
this
section
to
the
appropriate
Regional
Office,
with
a
letter
giving
notice
of
such
action.

(
e)
The
State's
SIP
revision
shall
contain
control
measures
and
demonstrate
that
they
will
result
in
compliance
with
the
State's
Annual
EGU
NOX
budget,
if
applicable,
and
achieve
the
State's
Annual
Non­
EGU
NOX
Reduction
Requirement,
if
applicable,

for
the
appropriate
periods.
The
amounts
of
the
State's
Annual
EGU
NOX
budget
and
Annual
Non­
EGU
NOX
Reduction
Requirement
shall
be
determined
as
follows:

(
1)(
i)
The
Annual
EGU
NOX
budget
for
the
State
is
defined
as
the
total
amount
of
NOX
emissions
from
all
EGUs
in
that
State
for
a
year,
if
the
State
meets
the
requirements
of
paragraph
(
a)(
1)

of
this
section
by
imposing
control
measures,
at
least
in
part,

on
EGUs.
If
the
State
imposes
control
measures
under
this
section
on
only
EGUs,
the
Annual
EGU
NOX
budget
for
the
State
shall
not
exceed
the
amount,
during
the
indicated
periods,

specified
in
paragraph
(
e)(
2)
of
this
section.

(
ii)
The
Annual
Non­
EGU
NOX
Reduction
Requirement,
if
4
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
applicable,
is
defined
as
the
total
amount
of
NOX
emission
reductions
that
the
State
demonstrates,
in
accordance
with
paragraph
(
g)
of
this
section,
it
will
achieve
from
non­
EGUs
during
the
appropriate
period.
If
the
State
meets
the
requirements
of
paragraph
(
a)(
1)
of
this
section
by
imposing
control
measures
on
only
non­
EGUs,
then
the
State's
Annual
Non­

EGU
NOX
Reduction
Requirement
shall
equal
or
exceed,
during
the
appropriate
periods,
the
amount
determined
in
accordance
with
paragraph
(
e)(
3)
of
this
section.

(
iii)
If
a
State
meets
the
requirements
of
paragraph
(
a)(
1)

of
this
section
by
imposing
control
measures
on
both
EGUs
and
non­
EGUs,
then:

(
A)
The
Annual
Non­
EGU
NOX
Reduction
Requirement
shall
equal
or
exceed
the
difference
between
the
amount
specified
in
paragraph
(
e)(
2)
of
this
section
for
the
appropriate
period
and
the
amount
of
the
State's
Annual
EGU
NOX
budget
specified
in
the
SIP
revision
for
the
appropriate
period;
and
(
B)
The
Annual
EGU
NOX
budget
shall
not
exceed,
during
the
indicated
periods,
the
amount
specified
in
paragraph
(
e)(
2)
of
this
section
plus
the
amount
of
the
Annual
Non­
EGU
NOX
Reduction
Requirement
under
paragraph
(
e)(
1)(
iii)(
A)
of
this
section
for
the
appropriate
period.

(
2)
For
a
State
that
complies
with
the
requirements
of
paragraph
(
a)(
1)
of
this
section
by
imposing
control
measures
on
5
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
only
EGUs,
the
amount
of
the
Annual
EGU
NOX
budget,
in
tons
of
NOX
per
year,
shall
be
as
follows,
for
the
indicated
State
for
the
indicated
period:

State
Annual
EGU
NOX
Budget
for
2009­
2014
(
tons)
Annual
EGU
NOX
Budget
for
2015
and
thereafter
(
tons)
Alabama
69,020
57,517
District
of
Columbia
144
120
Florida
99,445
82,871
Georgia
66,321
55,268
Illinois
76,230
63,525
Indiana
108,935
90,779
Iowa
32,692
27,243
Kentucky
83,205
69,337
Louisiana
35,512
29,593
Maryland
27,724
23,104
Michigan
65,304
54,420
Minnesota
31,443
26,203
Mississippi
17,807
14,839
Missouri
59,871
49,892
New
York
45,617
38,014
North
Carolina
62,183
51,819
Ohio
108,667
90,556
Pennsylvania
99,049
82,541
South
Carolina
32,662
27,219
Tennessee
50,973
42,478
Texas
181,014
150,845
Virginia
36,074
30,062
West
Virginia
74,220
61,850
Wisconsin
40,759
33,966
(
3)
For
a
State
that
complies
with
the
requirements
of
paragraph
(
a)(
1)
of
this
section
by
imposing
control
measures
on
only
non­
EGUs,
the
amount
of
the
Annual
Non­
EGU
NOX
Reduction
Requirement,
in
tons
of
NOX
per
year,
shall
be
determined,
for
the
State
for
2009
and
thereafter,
by
subtracting
the
amount
of
the
State's
NOX
baseline
EGU
emissions
inventory
projected
for
the
appropriate
year,
specified
in
XXXXXXXXXXXXXX,
from
the
6
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
amount
of
the
State's
Annual
EGU
NOX
budget
for
the
appropriate
year,
specified
in
paragraph
(
e)(
2)
of
this
section.

(
4)(
i)
Notwithstanding
the
State's
obligation
to
comply
with
paragraph
(
e)(
2)
or
(
3)
of
this
section,
the
State's
SIP
revision
may
allow
sources
required
by
the
revision
to
implement
control
measures
to
demonstrate
compliance
using
credit
issued
from
the
State's
compliance
supplement
pool,
as
set
forth
in
paragraph
(
e)(
4)(
ii)
of
this
section.

(
ii)
The
State­
by­
State
amounts
of
the
compliance
supplement
pool
are
as
follows:

State
Compliance
Supplement
Pool
(
tons)
Alabama
10,179
District
Of
Columbia
0
Florida
8,345
Georgia
12,412
Illinois
11,313
Indiana
20,180
Iowa
6,987
Kentucky
14,953
Louisiana
2,254
Maryland
4,676
Michigan
8,358
Minnesota
6,536
Mississippi
3,070
Missouri
9,055
New
York
0
North
Carolina
0
Ohio
25,068
Pennsylvania
16,029
7
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
South
Carolina
2,604
Tennessee
8,955
Texas
773
Virginia
5,141
West
Virginia
16,950
Wisconsin
4,904
(
iii)
The
SIP
revision
may
provide
for
the
distribution
of
credits
from
the
compliance
supplement
pool
to
sources
that
are
required
to
implement
control
measures
using
one
or
both
of
the
following
two
mechanisms:

(
A)
The
State
may
issue
credit
from
compliance
supplement
pool
to
sources
that
are
required
by
the
SIP
revision
to
implement
NOX
emission
control
measures
and
that
implement
NOX
emission
reductions
in
2007
and
2008
that
are
not
necessary
to
comply
with
any
State
or
federal
emissions
limitation
applicable
at
any
time
during
such
years.
Such
a
source
may
be
issued
one
credit
from
the
compliance
supplement
pool
for
each
ton
of
such
emission
reductions
in
2007
and
2008.

(
1)
The
State
shall
complete
the
issuance
process
by
January
1,
2010.

(
2)
The
emissions
reductions
for
which
credits
are
issued
must
have
been
demonstrated
by
the
owners
and
operators
of
the
source
to
have
occurred
during
2007
and
2008
and
not
to
be
necessary
to
comply
with
any
applicable
State
or
federal
emissions
limitation.

(
3)
The
emissions
reductions
for
which
credits
are
issued
8
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
must
have
been
quantified
by
the
owners
and
operators
of
the
source:

(
i)
For
EGUs
and
for
fossil­
fuel­
fired
non­
EGUs
that
are
boilers
or
combustion
turbines
with
a
maximum
design
heat
input
greater
than
250
mmBut/
hr,
using
emissions
data
determined
in
accordance
with
subpart
H
of
part
75
of
this
chapter;
and
(
ii)
For
non­
EGUs
not
described
in
paragraph
(
e)(
4)(
iii)(
A)(
3)(
i)
of
this
section,
using
emissions
data
determined
in
accordance
with
subpart
H
of
part
75
of
this
chapter
or,
if
the
State
demonstrates
that
compliance
with
subpart
H
of
part
75
of
this
chapter
is
not
practicable,

determined,
to
the
extent
practicable,
with
the
same
degree
of
assurance
with
which
emissions
data
are
determined
for
sources
subject
to
subpart
H
of
part
75.

(
4)
If
the
SIP
revision
contains
approved
provisions
for
an
emissions
trading
program,
the
owners
and
operators
of
sources
that
receive
credit
according
to
the
requirements
of
this
paragraph
may
trade
the
credit
to
other
sources
or
persons
according
to
the
provisions
in
the
emissions
trading
program.

(
B)
The
State
may
issue
credit
from
the
compliance
supplement
pool
to
sources
that
are
required
by
the
SIP
revision
to
implement
NOX
emission
control
measures
and
whose
owners
and
operators
demonstrate
a
need
for
an
extension,
beyond
2009,
of
the
deadline
for
the
source
for
implementing
such
emission
controls.
9
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
(
1)
The
State
shall
complete
the
issuance
process
by
January
1,
2010.

(
2)
The
State
shall
issue
credit
to
a
source
only
if
the
owners
and
operators
of
the
source
demonstrate
that:

(
i)
For
a
source
used
to
generate
electricity,

implementation
of
the
SIP
revision's
applicable
control
measures
by
2009
would
create
undue
risk
for
the
reliability
of
the
electricity
supply.
This
demonstration
must
include
a
showing
that
it
would
not
be
feasible
for
the
owners
and
operators
of
the
source
to
obtain
a
sufficient
amount
of
electricity,
to
prevent
such
undue
risk,
from
other
electricity
generation
facilities
during
the
installation
of
control
technology
at
the
source
necessary
to
comply
with
the
SIP
revision.

(
ii)
For
a
source
not
used
to
generate
electricity,

compliance
with
the
SIP
revision's
applicable
control
measures
by
2009
would
create
undue
risk
for
the
source
or
its
associated
industry
to
a
degree
that
is
comparable
to
the
risk
described
in
paragraph
(
e)(
4)(
iii)(
B)(
2)(
i)
of
this
section
(
f)
Each
SIP
revision
must
set
forth
control
measures
to
10
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
meet
the
amounts
specified
in
paragraph
(
e)
of
this
section,
as
applicable,
including
the
following:

(
1)
A
description
of
enforcement
methods
including,
but
not
limited
to:

(
i)
Procedures
for
monitoring
compliance
with
each
of
the
selected
control
measures;

(
ii)
Procedures
for
handling
violations;
and
(
iii)
A
designation
of
agency
responsibility
for
enforcement
of
implementation.

(
2)(
i)
If
a
State
elects
to
impose
control
measures
on
EGUs,

then
those
measures
must
impose
an
annual
NOX
mass
emissions
cap
on
all
such
sources
in
the
State.

(
ii)
If
a
State
elects
to
impose
control
measures
on
fossil
fuel­
fired
non­
EGUs
that
are
boilers
or
combustion
turbines
with
a
maximum
design
heat
input
greater
than
250
mmBtu/
hr,
then
those
measures
must
impose
an
annual
NOX
mass
emissions
cap
on
all
such
sources
in
the
State.

(
iii)
If
a
State
elects
to
impose
control
measures
on
non­

EGUs
other
than
those
described
in
paragraph
(
f)(
2)(
ii)
of
this
section,
then
those
measures
must
impose
an
annual
NOX
mass
emissions
cap
on
all
such
sources
in
the
State
or
the
State
must
demonstrate
why
such
emissions
cap
is
not
practicable
and
adopt
alternative
requirements
that
ensure
that
the
State
will
comply
with
its
requirements
under
paragraph
(
e)
of
this
section,
as
11
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
applicable,
in
2009
and
subsequent
years.

(
g)(
1)
Each
SIP
revision
that
contains
control
measures
covering
non­
EGUs
as
part
or
all
of
a
State's
obligation
in
meeting
its
requirement
under
paragraph
(
a)(
1)
of
this
section
must
demonstrate
that
such
control
measures
are
adequate
to
provide
for
the
timely
compliance
with
the
State's
Annual
Non­
EGU
NOX
Reduction
Requirement
under
paragraph
(
e)
of
this
section
and
are
not
adopted
or
implemented
by
the
State,
as
of
[
Insert
the
date
of
publication
of
the
final
Clean
Air
Interstate
Rule],
and
are
not
adopted
or
implemented
by
the
federal
government,
as
of
the
date
of
submission
of
the
SIP
revision
by
the
State
to
EPA.

(
2)
The
demonstration
under
paragraph
(
g)(
1)
of
this
section
must
include
the
following,
with
respect
to
each
source
category
of
non­
EGUs
for
which
the
SIP
revision
requires
control
measures:

(
i)
A
detailed
historical
baseline
inventory
of
NOX
mass
emissions
from
the
source
category
in
a
representative
year
consisting,
at
the
State's
election,
of
2002,
2003,
2004,
or
2005,
or
an
average
of
2
or
more
of
those
years,
absent
the
control
measures
specified
in
the
SIP
revision.

(
A)
This
inventory
must
represent
estimates
of
actual
emissions
based
on
monitoring
data
in
accordance
with
subpart
H
of
part
75
of
this
chapter,
if
the
source
category
is
subject
to
monitoring
requirements
in
accordance
with
subpart
H
of
part
75
of
this
chapter.
12
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
(
B)
In
the
absence
of
monitoring
data
in
accordance
with
subpart
H
of
part
75
of
this
chapter,
actual
emissions
must
be
quantified,
to
the
maximum
extent
practicable,
with
the
same
degree
of
assurance
with
which
emissions
are
quantified
for
sources
subject
to
subpart
H
of
part
75
of
this
chapter
and
using
source­
specific
or
source­
category­
specific
assumptions
that
ensure
a
source's
or
source
category's
actual
emissions
are
not
overestimated.
If
a
State
uses
factors
to
estimate
emissions,

production
or
utilization,
or
effectiveness
of
controls
or
rules
for
a
source
category,
such
factors
must
be
chosen
to
ensure
that
emissions
are
not
overestimated.

(
C)
For
measures
to
reduce
emissions
from
motor
vehicles,

emission
estimates
must
be
based
on
an
emissions
model
that
has
been
approved
by
EPA
for
use
in
SIP
development
and
must
be
consistent
with
the
planning
assumptions
regarding
vehicle
miles
traveled
and
other
factors
current
at
the
time
of
the
SIP
development.

(
D)
For
measures
to
reduce
emissions
from
nonroad
engines
or
vehicles,
emission
estimates
methodologies
must
be
approved
by
EPA.

(
ii)
A
detailed
baseline
inventory
of
NOX
mass
emissions
from
the
source
category
in
the
years
2009
and
2015,
absent
the
control
measures
specified
in
the
SIP
revision
and
reflecting
changes
in
these
emissions
from
the
historical
baseline
year
to
13
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
the
years
2009
and
2015,
based
on
projected
changes
in
the
production
input
or
output,
population,
vehicle
miles
traveled,

economic
activity,
or
other
factors
as
applicable
to
this
source
category.

(
A)
These
inventories
must
account
for
implementation
of
any
control
measures
that
are
otherwise
required
by
final
rules
already
promulgated,
as
of
[
Insert
the
date
of
publication
of
the
final
Clean
Air
Interstate
Rule],
or
adopted
or
implemented
by
any
federal
agency,
as
of
the
date
of
submission
of
the
SIP
revision
by
the
State
to
EPA,
and
must
exclude
any
control
measures
specified
in
the
SIP
revision
to
meet
the
NOX
emissions
reduction
requirements
of
this
section.

(
B)
Economic
and
population
forecasts
must
be
as
specific
as
possible
to
the
applicable
industry,
State,
and
county
of
the
source
or
source
category
and
must
be
consistent
with
both
national
projections
and
relevant
official
planning
assumptions,

including
estimates
of
population
and
vehicle
miles
traveled
developed
through
consultation
between
State
and
local
transportation
and
air
quality
agencies.
However,
if
these
official
planning
assumptions
are
inconsistent
with
official
U.
S.

Census
projections
of
population
or
with
energy
consumption
projections
contained
in
the
U.
S.
Department
of
Energy's
most
recent
Annual
Energy
Outlook,
then
the
SIP
revision
must
make
adjustments
to
correct
the
inconsistency
or
must
demonstrate
how
14
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
the
official
planning
assumptions
are
more
accurate.

(
C)
These
inventories
must
account
for
any
changes
in
production
method,
materials,
fuels,
or
efficiency
that
are
expected
to
occur
between
the
historical
baseline
year
and
2009
or
2015,
as
appropriate.

(
iii)
A
projection
of
NOX
mass
emissions
in
2009
and
2015
from
the
source
category
assuming
the
same
projected
changes
as
under
paragraph
(
g)(
2)(
ii)
of
this
section
and
resulting
from
implementation
of
each
of
the
control
measures
specified
in
the
SIP
revision.

(
A)
These
inventories
must
address
the
possibility
that
the
State's
new
control
measures
may
cause
production
or
utilization,

and
emissions,
to
shift
to
unregulated
or
less
stringently
regulated
sources
in
the
source
category
in
the
same
or
another
State,
and
these
inventories
must
include
any
such
amounts
of
emissions
that
may
shift
to
such
other
sources.

(
B)
The
State
must
provide
EPA
with
a
summary
of
the
computations,
assumptions,
and
judgments
used
to
determine
the
degree
of
reduction
in
projected
2009
and
2015
NOX
emissions
that
will
be
achieved
from
the
implementation
of
the
new
control
measures
compared
to
the
relevant
baseline
emissions
inventory.

(
iv)
The
result
of
subtracting
the
amounts
in
paragraph
(
g)(
2)(
iii)
of
this
section
for
2009
and
2015,
respectively,
from
the
lower
of
the
amounts
in
paragraph
(
g)(
2)(
i)
or
(
g)(
2)(
ii)
of
15
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
this
section
for
2009
and
2015,
respectively,
may
be
credited
towards
the
State's
Annual
Non­
EGU
NOX
Reduction
Requirement
in
paragraph
(
e)(
3)
of
this
section
for
the
appropriate
period.

(
v)
Each
SIP
revision
must
identify
the
sources
of
the
data
used
in
each
estimate
and
each
projection
of
emissions.

(
h)
Each
SIP
revision
must
comply
with
§
51.116
(
regarding
data
availability).

(
i)
Each
SIP
revision
must
provide
for
monitoring
the
status
of
compliance
with
any
control
measures
adopted
to
meet
the
State's
requirements
under
paragraph
(
e)
of
this
section
as
follows:

(
1)
The
SIP
revision
must
provide
for
legally
enforceable
procedures
for
requiring
owners
or
operators
of
stationary
sources
to
maintain
records
of,
and
periodically
report
to
the
State:

(
i)
Information
on
the
amount
of
NOX
emissions
from
the
stationary
sources;
and
(
ii)
Other
information
as
may
be
necessary
to
enable
the
State
to
determine
whether
the
sources
are
in
compliance
with
applicable
portions
of
the
control
measures;

(
2)
The
SIP
revision
must
comply
with
§
51.212
(
regarding
testing,
inspection,
enforcement,
and
complaints);

(
3)
If
the
SIP
revision
contains
any
transportation
control
measures,
then
the
SIP
revision
must
comply
with
§
51.213
16
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
(
regarding
transportation
control
measures);

(
4)(
i)
If
the
SIP
revision
contains
measures
to
control
EGUs,
then
the
SIP
revision
must
require
such
sources
to
comply
with
the
monitoring,
recordkeeping,
and
reporting
provisions
of
subpart
H
of
part
75
of
this
chapter.

(
ii)
If
the
SIP
revision
contains
measures
to
control
fossil
fuel­
fired
non­
EGUs
that
are
boilers
or
combustion
turbines
with
a
maximum
design
heat
input
greater
than
250
mmBtu/
hr,
then
the
SIP
revision
must
require
such
sources
to
comply
with
the
monitoring,
recordkeeping,
and
reporting
provisions
of
subpart
H
of
part
75
of
this
chapter.

(
iii)
If
the
SIP
revision
contains
measures
to
control
any
other
non­
EGUs
that
are
not
described
in
paragraph
(
i)(
4)(
ii)
of
this
section,
then
the
SIP
revision
must
require
such
sources
to
comply
with
the
monitoring,
recordkeeping,
and
reporting
provisions
of
subpart
H
of
part
75
of
this
chapter,
or
the
State
must
demonstrate
why
such
requirements
are
not
practicable
and
adopt
alternative
requirements
that
ensure
that
the
required
emissions
reductions
will
be
quantified,
to
the
maximum
extent
practicable,
with
the
same
degree
of
assurance
with
which
emissions
are
quantified
for
sources
subject
to
subpart
H
of
part
75
of
this
chapter.

(
j)
Each
SIP
revision
must
show
that
the
State
has
legal
authority
to
carry
out
the
SIP
revision,
including
authority
to:
17
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
(
1)
Adopt
emissions
standards
and
limitations
and
any
other
measures
necessary
for
attainment
and
maintenance
of
the
State's
relevant
Annual
EGU
NOX
budget
or
the
Annual
Non­
EGU
NOX
Reduction
Requirement,
as
applicable,
under
paragraph
(
e);

(
2)
Enforce
applicable
laws,
regulations,
and
standards
and
seek
injunctive
relief;

(
3)
Obtain
information
necessary
to
determine
whether
air
pollution
sources
are
in
compliance
with
applicable
laws,

regulations,
and
standards,
including
authority
to
require
recordkeeping
and
to
make
inspections
and
conduct
tests
of
air
pollution
sources;
and
(
4)(
i)
Require
owners
or
operators
of
stationary
sources
to
install,
maintain,
and
use
emissions
monitoring
devices
and
to
make
periodic
reports
to
the
State
on
the
nature
and
amounts
of
emissions
from
such
stationary
sources;
and
(
ii)
Make
the
data
described
in
paragraph
(
j)(
4)(
i)
of
this
section
available
to
the
public
within
a
reasonable
time
after
being
reported
and
as
correlated
with
any
applicable
emissions
standards
or
limitations.

(
k)(
1)
The
provisions
of
law
or
regulation
that
the
State
determines
provide
the
authorities
required
under
this
section
must
be
specifically
identified,
and
copies
of
such
laws
or
regulations
must
be
submitted
with
the
SIP
revision.

(
2)
Legal
authority
adequate
to
fulfill
the
requirements
of
18
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
paragraphs
(
j)(
3)
and
(
4)
of
this
section
may
be
delegated
to
the
State
under
section
114
of
the
CAA.

(
l)(
1)
A
SIP
revision
may
assign
legal
authority
to
local
agencies
in
accordance
with
§
51.232.

(
2)
Each
SIP
revision
must
comply
with
§
51.240
(
regarding
general
plan
requirements).

(
m)
Each
SIP
revision
must
comply
with
§
51.280
(
regarding
resources).

(
n)
Each
SIP
revision
must
provide
for
State
compliance
with
the
reporting
requirements
in
§
51.125.

(
o)(
1)
Notwithstanding
any
other
provision
of
this
section,

if
a
State
adopts
regulations
substantively
identical
to
subparts
AA
through
II
of
part
96
of
this
chapter
(
CAIR
NOX
Annual
Trading
Program),
incorporates
such
subparts
by
reference
into
its
regulations,
or
adopts
regulations
that
differ
substantively
from
such
subparts
only
as
set
forth
in
paragraph
(
o)(
2)
of
this
section,
then
such
emissions
trading
program
in
the
State's
SIP
revision
is
automatically
approved
as
meeting
the
requirements
of
paragraph
(
e)
of
this
section,
provided
that
the
State
has
the
legal
authority
to
take
such
action
and
to
implement
its
responsibilities
under
such
regulations.

(
2)
If
a
State
adopts
an
emissions
trading
program
that
differs
substantively
from
subparts
AA
through
II
of
part
96
of
this
chapter
only
as
follows,
then
the
emissions
trading
program
19
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
is
approved
as
set
forth
in
paragraph
(
o)(
1)
of
this
section.

(
i)
The
State
may
decline
to
adopt
the
CAIR
NOX
opt­
in
provisions
of:

(
A)
Subpart
II
of
this
part
and
the
provisions
applicable
only
to
CAIR
NOX
opt­
in
units
in
subparts
AA
through
HH
of
this
part;

(
B)
§
96.188(
b)
and
the
provisions
of
subpart
II
of
this
part
applicable
only
to
CAIR
NOX
opt­
in
units
under
§
96.188(
b);
or
(
C)
§
96.188(
c)
and
the
provisions
of
subpart
II
of
this
part
applicable
only
to
CAIR
NOX
opt­
in
units
under
§
96.188(
c).

(
ii)
The
State
may
decline
to
adopt
the
allocation
provisions
set
forth
in
subpart
EE
of
part
96
of
this
chapter
and
may
instead
adopt
any
methodology
for
allocating
NOX
allowances
to
individual
sources,
as
follows:

(
A)
The
State's
methodology
must
not
allow
the
State
to
allocate
CAIR
NOX
allowances
for
a
year
in
excess
of
the
amount
in
the
State's
Annual
EGU
NOX
Budget
for
such
year;

(
B)
The
State's
methodology
must
require
that,
for
EGUs
commencing
operation
before
January
1,
2000,
the
State
will
determine,
and
notify
the
Administrator
of,
each
unit's
allocation
of
CAIR
NOX
allowances
by
October
31,
2006
for
2009,

2010,
and
2011
and
by
October
31,
2008
and
October
31
of
each
year
thereafter
for
the
year
4
years
after
the
notification
deadline;
and
20
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
(
C)
The
State's
methodology
must
require
that,
for
EGUs
commencing
operation
on
or
after
January
1,
2000,
the
State
will
determine,
and
notify
the
Administrator
of,
each
unit's
allocation
of
CAIR
NOX
allowances
by
October
31
of
the
year
immediately
after
the
year
for
which
the
CAIR
NOX
allowances
are
allocated.

(
3)
A
State
that
adopts
an
emissions
trading
program
in
accordance
with
paragraph
(
o)(
1)
or
(
2)
of
this
section
is
not
required
to
adopt
an
emissions
trading
program
in
accordance
with
paragraph
(
aa)(
1)
or
(
2)
of
this
section
or
§
96.124(
o)(
1)
or
(
2).

(
4)
If
a
State
adopts
an
emissions
trading
program
that
differs
substantively
from
subparts
AA
through
HH
of
part
96
of
this
chapter,
other
than
as
set
forth
in
paragraph
(
o)(
2)
of
this
section,
then
such
emissions
trading
program
is
not
automatically
approved
as
set
forth
in
paragraph
(
o)(
1)
or
(
2)
of
this
section
and
will
be
reviewed
by
the
Administrator
for
approvability
in
accordance
with
the
other
provisions
of
this
section,
provided
that
the
NOX
allowances
issued
under
such
emissions
trading
program
shall
not,
and
the
SIP
revision
shall
state
that
such
NOX
allowances
shall
not,
qualify
as
CAIR
NOX
allowances
or
CAIR
NOX
Ozone
Season
allowances
under
any
emissions
trading
program
approved
under
paragraphs
(
o)(
1)
or
(
2)
or
(
aa)(
1)
or
(
2)
of
this
section.
21
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
(
q)
The
State's
SIP
revision
shall
contain
control
measures
and
demonstrate
that
they
will
result
in
compliance
with
the
State's
Ozone
Season
EGU
NOX
budget,
if
applicable,
and
achieve
the
State's
Ozone
Season
Non­
EGU
NOX
Reduction
Requirement,
if
applicable,
for
the
appropriate
periods.
The
amounts
of
the
State's
Ozone
Season
EGU
NOX
budget
and
Ozone
Season
Non­
EGU
NOX
Reduction
Requirement
shall
be
determined
as
follows:

(
1)(
i)
The
Ozone
Season
EGU
NOX
budget
for
the
State
is
defined
as
the
total
amount
of
NOX
emissions
from
all
EGUs
in
that
State
for
an
ozone
season,
if
the
State
meets
the
requirements
of
paragraph
(
a)(
2)
of
this
section
by
imposing
control
measures,
at
least
in
part,
on
EGUs.
If
the
State
imposes
control
measures
under
this
section
on
only
EGUs,
the
Ozone
Season
EGU
NOX
budget
for
the
State
shall
not
exceed
the
amount,
during
the
indicated
periods,
specified
in
paragraph
(
q)(
2)
of
this
section.

(
ii)
The
Ozone
Season
Non­
EGU
NOX
Reduction
Requirement,
if
applicable,
is
defined
as
the
total
amount
of
NOX
emission
reductions
that
the
State
demonstrates,
in
accordance
with
paragraph
(
s)
of
this
section,
it
will
achieve
from
non­
EGUs
during
the
appropriate
period.
If
the
State
meets
the
requirements
of
paragraph
(
a)(
2)
of
this
section
by
imposing
control
measures
on
only
non­
EGUs,
then
the
State's
Ozone
Season
22
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
Non­
EGU
NOX
Reduction
Requirement
shall
equal
or
exceed,
during
the
appropriate
periods,
the
amount
determined
in
accordance
with
paragraph
(
q)(
3)
of
this
section.

(
iii)
If
a
State
meets
the
requirements
of
paragraph
(
a)(
2)

of
this
section
by
imposing
control
measures
on
both
EGUs
and
non­
EGUs,
then:

(
A)
The
Ozone
Season
Non­
EGU
NOX
Reduction
Requirement
shall
equal
or
exceed
the
difference
between
the
amount
specified
in
paragraph
(
q)(
2)
of
this
section
for
the
appropriate
period
and
the
amount
of
the
State's
Ozone
Season
EGU
NOX
budget
specified
in
the
SIP
revision
for
the
appropriate
period;
and
(
B)
The
Ozone
Season
EGU
NOX
budget
shall
not
exceed,
during
the
indicated
periods,
the
amount
specified
in
paragraph
(
e)(
2)

of
this
section
plus
the
amount
of
the
Ozone
Season
Non­
EGU
NOX
Reduction
Requirement
under
paragraph
(
q)(
1)(
iii)(
A)
of
this
section
for
the
appropriate
period.

(
2)
For
a
State
that
complies
with
the
requirements
of
paragraph
(
a)(
2)
of
this
section
by
imposing
control
measures
on
only
EGUs,
the
amount
of
the
Ozone
Season
EGU
NOX
budget,
in
tons
of
NOX
per
ozone
season,
shall
be
as
follows,
for
the
indicated
State
for
the
indicated
period:

State
Ozone
Season
EGU
NOX
Budget
for
2009­

2014
(
tons)
Ozone
Season
EGU
NOX
Budget
for
2015
and
thereafter
(
tons)
23
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
Alabama
32,182
26,818
Arkansas
11,515
9,596
Connecticut
2,559
2,559
Delaware
2,226
1,855
District
of
Columbia
112
94
Florida
47,912
39,926
Illinois
30,701
28,981
Indiana
45,952
39,273
Iowa
14,263
11,886
Kentucky
36,045
30,587
Louisiana
17,085
14,238
Maryland
12,834
10,695
Massachusetts
7,551
6,293
Michigan
28,971
24,142
Mississippi
8,714
7,262
Missouri
26,678
22,231
New
Jersey
6,654
5,545
New
York
20,632
17,193
North
Carolina
28,392
23,660
Ohio
45,664
39,945
Pennsylvania
42,171
35,143
South
Carolina
15,249
12,707
Tennessee
22,842
19,035
Virginia
15,994
13,328
West
Virginia
26,859
26,525
Wisconsin
17,987
14,989
(
3)
For
a
State
that
complies
with
the
requirements
of
paragraph
(
a)(
2)
of
this
section
by
imposing
control
measures
on
only
non­
EGUs,
the
amount
of
the
Ozone
Season
Non­
EGU
NOX
Reduction
Requirement,
in
tons
of
NOX
per
ozone
season,
shall
be
determined,
for
the
State
for
2009
and
thereafter,
by
subtracting
the
amount
of
the
State's
NOX
baseline
EGU
emissions
inventory
projected
for
the
ozone
season
in
the
appropriate
year,
specified
in
XXXXXXXXXXXXXX,
from
the
amount
of
the
State's
Ozone
Season
EGU
NOX
budget
for
the
appropriate
year,
specified
in
paragraph
(
e)(
2)
of
this
section.

(
4)
Notwithstanding
the
State's
obligation
to
comply
with
paragraph
(
q)(
2)
or
(
3)
of
this
section,
the
State's
SIP
revision
24
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
may
allow
sources
required
by
the
revision
to
implement
NOX
emission
control
measures
to
demonstrate
compliance
using
NOx
SIP
Call
allowances
allocated
under
the
NOX
Budget
Trading
Program
for
any
ozone
season
during
2003
through
2008
that
have
not
been
deducted
by
the
Administrator
under
the
NOX
Budget
Trading
Program,
if
the
SIP
revision
ensures
that
such
allowances
will
not
be
available
for
such
deduction
under
the
NOX
Budget
Trading
Program.

(
r)
Each
SIP
revision
must
set
forth
control
measures
to
meet
the
amounts
specified
in
paragraph
(
q)
of
this
section,
as
applicable,
including
the
following:

(
1)
A
description
of
enforcement
methods
including,
but
not
limited
to:

(
i)
Procedures
for
monitoring
compliance
with
each
of
the
selected
control
measures;

(
ii)
Procedures
for
handling
violations;
and
(
iii)
A
designation
of
agency
responsibility
for
enforcement
of
implementation.

(
2)(
i)
If
a
State
elects
to
impose
control
measures
on
EGUs,

then
those
measures
must
impose
an
ozone
season
NOX
mass
emissions
cap
on
all
such
sources
in
the
State.

(
ii)
If
a
State
elects
to
impose
control
measures
on
fossil
fuel­
fired
non­
EGUs
that
are
boilers
or
combustion
turbines
with
a
maximum
design
heat
input
greater
than
250
mmBtu/
hr,
then
those
25
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
measures
must
impose
an
ozone
season
NOX
mass
emissions
cap
on
all
such
sources
in
the
State.

(
iii)
If
a
State
elects
to
impose
control
measures
on
non­

EGUs
other
than
those
described
in
paragraph
(
r)(
2)(
ii)
of
this
section,
then
those
measures
must
impose
an
ozone
season
NOX
mass
emissions
cap
on
all
such
sources
in
the
State
or
the
State
must
demonstrate
why
such
emissions
cap
is
not
practicable
and
adopt
alternative
requirements
that
ensure
that
the
State
will
comply
with
its
requirements
under
paragraph
(
q)
of
this
section,
as
applicable,
in
2009
and
subsequent
years.

(
s)(
1)
Each
SIP
revision
that
contains
control
measures
covering
non­
EGUs
as
part
or
all
of
a
State's
obligation
in
meeting
its
requirement
under
paragraph
(
a)(
2)
of
this
section
must
demonstrate
that
such
control
measures
are
adequate
to
provide
for
the
timely
compliance
with
the
State's
Ozone
Season
Non­
EGU
NOX
Reduction
Requirement
under
paragraph
(
q)
of
this
section
and
are
not
adopted
or
implemented
by
the
State,
as
of
[
Insert
the
date
of
publication
of
the
final
Clean
Air
Interstate
Rule],
and
are
not
adopted
or
implemented
by
the
federal
government,
as
of
the
date
of
submission
of
the
SIP
revision
by
the
State
to
EPA.

(
2)
The
demonstration
under
paragraph
(
s)(
1)
of
this
section
must
include
the
following,
with
respect
to
each
source
category
of
non­
EGUs
for
which
the
SIP
revision
requires
control
measures:
26
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
(
i)
A
detailed
historical
baseline
inventory
of
NOX
mass
emissions
from
the
source
category
in
a
representative
ozone
season
consisting,
at
the
State's
election,
of
the
ozone
season
in
2002,
2003,
2004,
or
2005,
or
an
average
of
2
or
more
of
those
ozone
seasons,
absent
the
control
measures
specified
in
the
SIP
revision.

(
A)
This
inventory
must
represent
estimates
of
actual
emissions
based
on
monitoring
data
in
accordance
with
subpart
H
of
part
75
of
this
chapter,
if
the
source
category
is
subject
to
monitoring
requirements
in
accordance
with
subpart
H
of
part
75
of
this
chapter.

(
B)
In
the
absence
of
monitoring
data
in
accordance
with
subpart
H
of
part
75
of
this
chapter,
actual
emissions
must
be
quantified,
to
the
maximum
extent
practicable,
with
the
same
degree
of
assurance
with
which
emissions
are
quantified
for
sources
subject
to
subpart
H
of
part
75
of
this
chapter
and
using
source­
specific
or
source­
category­
specific
assumptions
that
ensure
a
source's
or
source
category's
actual
emissions
are
not
overestimated.
If
a
State
uses
factors
to
estimate
emissions,

production
or
utilization,
or
effectiveness
of
controls
or
rules
for
a
source
category,
such
factors
must
be
chosen
to
ensure
that
emissions
are
not
overestimated.

(
C)
For
measures
to
reduce
emissions
from
motor
vehicles,

emission
estimates
must
be
based
on
an
emissions
model
that
has
27
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
been
approved
by
EPA
for
use
in
SIP
development
and
must
be
consistent
with
the
planning
assumptions
regarding
vehicle
miles
traveled
and
other
factors
current
at
the
time
of
the
SIP
development.

(
D)
For
measures
to
reduce
emissions
from
nonroad
engines
or
vehicles,
emission
estimates
methodologies
must
be
approved
by
EPA.

(
ii)
A
detailed
baseline
inventory
of
NOX
mass
emissions
from
the
source
category
in
ozone
seasons
2009
and
2015,
absent
the
control
measures
specified
in
the
SIP
revision
and
reflecting
changes
in
these
emissions
from
the
historical
baseline
ozone
season
to
the
ozone
seasons
2009
and
2015,
based
on
projected
changes
in
the
production
input
or
output,
population,
vehicle
miles
traveled,
economic
activity,
or
other
factors
as
applicable
to
this
source
category.

(
A)
These
inventories
must
account
for
implementation
of
any
control
measures
that
are
adopted
or
implemented
by
the
State,
as
of
[
Insert
the
date
of
publication
of
the
final
Clean
Air
Interstate
Rule],
or
adopted
or
implemented
by
the
federal
government,
as
of
the
date
of
submission
of
the
SIP
revision
by
the
State
to
EPA,
and
must
exclude
any
control
measures
specified
in
the
SIP
revision
to
meet
the
NOX
emissions
reduction
requirements
of
this
section.

(
B)
Economic
and
population
forecasts
must
be
as
specific
as
28
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
possible
to
the
applicable
industry,
State,
and
county
of
the
source
or
source
category
and
must
be
consistent
with
both
national
projections
and
relevant
official
planning
assumptions,

including
estimates
of
population
and
vehicle
miles
traveled
developed
through
consultation
between
State
and
local
transportation
and
air
quality
agencies.
However,
if
these
official
planning
assumptions
are
inconsistent
with
official
U.
S.

Census
projections
of
population
or
with
energy
consumption
projections
contained
in
the
U.
S.
Department
of
Energy's
most
recent
Annual
Energy
Outlook,
then
the
SIP
revision
must
make
adjustments
to
correct
the
inconsistency
or
must
demonstrate
how
the
official
planning
assumptions
are
more
accurate.

(
C)
These
inventories
must
account
for
any
changes
in
production
method,
materials,
fuels,
or
efficiency
that
are
expected
to
occur
between
the
historical
baseline
ozone
season
and
ozone
season
2009
or
ozone
season
2015,
as
appropriate.

(
iii)
A
projection
of
NOX
mass
emissions
in
ozone
season
2009
and
ozone
season
2015
from
the
source
category
assuming
the
same
projected
changes
as
under
paragraph
(
s)(
2)(
ii)
of
this
section
and
resulting
from
implementation
of
each
of
the
control
measures
specified
in
the
SIP
revision.

(
A)
These
inventories
must
address
the
possibility
that
the
State's
new
control
measures
may
cause
production
or
utilization,

and
emissions,
to
shift
to
unregulated
or
less
stringently
29
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
regulated
sources
in
the
source
category
in
the
same
or
another
State,
and
these
inventories
must
include
any
such
amounts
of
emissions
that
may
shift
to
such
other
sources.

(
B)
The
State
must
provide
EPA
with
a
summary
of
the
computations,
assumptions,
and
judgments
used
to
determine
the
degree
of
reduction
in
projected
ozone
season
2009
and
ozone
season
2015
NOX
emissions
that
will
be
achieved
from
the
implementation
of
the
new
control
measures
compared
to
the
relevant
baseline
emissions
inventory.

(
iv)
The
result
of
subtracting
the
amounts
in
paragraph
(
s)(
2)(
iii)
of
this
section
for
ozone
season
2009
and
ozone
season
2015,
respectively,
from
the
lower
of
the
amounts
in
paragraph
(
s)(
2)(
i)
or
(
s)(
2)(
ii)
of
this
section
for
ozone
season
2009
and
ozone
season
2015,
respectively,
may
be
credited
towards
the
State's
Ozone
Season
Non­
EGU
NOX
Reduction
Requirement
in
paragraph
(
q)(
3)
of
this
section
for
the
appropriate
period.

(
v)
Each
SIP
revision
must
identify
the
sources
of
the
data
used
in
each
estimate
and
each
projection
of
emissions.

(
t)
Each
SIP
revision
must
comply
with
§
51.116
(
regarding
data
availability).

(
u)
Each
SIP
revision
must
provide
for
monitoring
the
status
of
compliance
with
any
control
measures
adopted
to
meet
the
State's
requirements
under
paragraph
(
q)
of
this
section
as
30
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
follows:

(
1)
The
SIP
revision
must
provide
for
legally
enforceable
procedures
for
requiring
owners
or
operators
of
stationary
sources
to
maintain
records
of,
and
periodically
report
to
the
State:

(
i)
Information
on
the
amount
of
NOX
emissions
from
the
stationary
sources;
and
(
ii)
Other
information
as
may
be
necessary
to
enable
the
State
to
determine
whether
the
sources
are
in
compliance
with
applicable
portions
of
the
control
measures;

(
2)
The
SIP
revision
must
comply
with
§
51.212
(
regarding
testing,
inspection,
enforcement,
and
complaints);

(
3)
If
the
SIP
revision
contains
any
transportation
control
measures,
then
the
SIP
revision
must
comply
with
§
51.213
(
regarding
transportation
control
measures);

(
4)(
i)
If
the
SIP
revision
contains
measures
to
control
EGUs,
then
the
SIP
revision
must
require
such
sources
to
comply
with
the
monitoring,
recordkeeping,
and
reporting
provisions
of
subpart
H
of
part
75
of
this
chapter.

(
ii)
If
the
SIP
revision
contains
measures
to
control
fossil
fuel­
fired
non­
EGUs
that
are
boilers
or
combustion
turbines
with
a
maximum
design
heat
input
greater
than
250
mmBtu/
hr,
then
the
SIP
revision
must
require
such
sources
to
comply
with
the
monitoring,
recordkeeping,
and
reporting
provisions
of
subpart
H
31
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
of
part
75
of
this
chapter.

(
iii)
If
the
SIP
revision
contains
measures
to
control
any
other
non­
EGUs
that
are
not
described
in
paragraph
(
u)(
4)(
ii)
of
this
section,
then
the
SIP
revision
must
require
such
sources
to
comply
with
the
monitoring,
recordkeeping,
and
reporting
provisions
of
subpart
H
of
part
75
of
this
chapter,
or
the
State
must
demonstrate
why
such
requirements
are
not
practicable
and
adopt
alternative
requirements
that
ensure
that
the
required
emissions
reductions
will
be
quantified,
to
the
maximum
extent
practicable,
with
the
same
degree
of
assurance
with
which
emissions
are
quantified
for
sources
subject
to
subpart
H
of
part
75
of
this
chapter.

(
v)
Each
SIP
revision
must
show
that
the
State
has
legal
authority
to
carry
out
the
SIP
revision,
including
authority
to:

(
1)
Adopt
emissions
standards
and
limitations
and
any
other
measures
necessary
for
attainment
and
maintenance
of
the
State's
relevant
Ozone
Season
EGU
NOX
budget
or
the
Ozone
Season
Non­
EGU
NOX
Reduction
Requirement,
as
applicable,
under
paragraph
(
q);

(
2)
Enforce
applicable
laws,
regulations,
and
standards
and
seek
injunctive
relief;

(
3)
Obtain
information
necessary
to
determine
whether
air
pollution
sources
are
in
compliance
with
applicable
laws,

regulations,
and
standards,
including
authority
to
require
recordkeeping
and
to
make
inspections
and
conduct
tests
of
air
32
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
pollution
sources;
and
(
4)(
i)
Require
owners
or
operators
of
stationary
sources
to
install,
maintain,
and
use
emissions
monitoring
devices
and
to
make
periodic
reports
to
the
State
on
the
nature
and
amounts
of
emissions
from
such
stationary
sources;
and
(
ii)
Make
the
data
described
in
paragraph
(
v)(
4)(
i)
of
this
section
available
to
the
public
within
a
reasonable
time
after
being
reported
and
as
correlated
with
any
applicable
emissions
standards
or
limitations.

(
w)(
1)
The
provisions
of
law
or
regulation
that
the
State
determines
provide
the
authorities
required
under
this
section
must
be
specifically
identified,
and
copies
of
such
laws
or
regulations
must
be
submitted
with
the
SIP
revision.

(
2)
Legal
authority
adequate
to
fulfill
the
requirements
of
paragraphs
(
v)(
3)
and
(
4)
of
this
section
may
be
delegated
to
the
State
under
section
114
of
the
CAA.

(
x)(
1)
A
SIP
revision
may
assign
legal
authority
to
local
agencies
in
accordance
with
§
51.232.

(
2)
Each
SIP
revision
must
comply
with
§
51.240
(
regarding
general
plan
requirements).

(
y)
Each
SIP
revision
must
comply
with
§
51.280
(
regarding
resources).

(
z)
Each
SIP
revision
must
provide
for
State
compliance
with
the
reporting
requirements
in
§
51.125.
33
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
(
aa)(
1)
Notwithstanding
any
other
provision
of
this
section,

if
a
State
adopts
regulations
substantively
identical
to
subparts
AAAA
through
IIII
of
part
96
of
this
chapter
(
CAIR
Ozone
Season
NOX
Trading
Program),
incorporates
such
subparts
by
reference
into
its
regulations,
or
adopts
regulations
that
differ
substantively
from
such
subparts
only
as
set
forth
in
paragraph
(
aa)(
2)
of
this
section,
then
such
emissions
trading
program
in
the
State's
SIP
revision
is
automatically
approved
as
meeting
the
requirements
of
paragraph
(
q)
of
this
section,
provided
that
the
State
has
the
legal
authority
to
take
such
action
and
to
implement
its
responsibilities
under
such
regulations.

(
2)
If
a
State
adopts
an
emissions
trading
program
that
differs
substantively
from
subparts
AAAA
through
IIII
of
part
96
of
this
chapter
only
as
follows,
then
the
emissions
trading
program
is
approved
as
set
forth
in
paragraph
(
aa)(
1)
of
this
section.

(
i)
The
State
may
expand
the
applicability
provisions
in
§
96.104
to
include
all
non­
EGUs
subject
to
the
requirements
of
the
State's
SIP
meeting
the
requirements
of
§
51.121.

(
ii)
The
State
may
decline
to
adopt
the
CAIR
NOX
Ozone
Season
opt­
in
provisions
of:

(
A)
Subpart
IIII
of
this
part
and
the
provisions
applicable
only
to
CAIR
NOX
Ozone
Season
opt­
in
units
in
subparts
AAAA
through
HHHH
of
this
part;

(
B)
§
96.388(
b)
and
the
provisions
of
subpart
IIII
of
this
34
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
part
applicable
only
to
CAIR
NOX
Ozone
Season
opt­
in
units
under
§
96.388(
b);
or
(
C)
§
96.388(
c)
and
the
provisions
of
subpart
IIII
of
this
part
applicable
only
to
CAIR
NOX
Ozone
Season
opt­
in
units
under
§
96.388(
c).

(
iii)
The
State
may
decline
to
adopt
the
allocation
provisions
set
forth
in
subpart
EEEE
of
part
96
of
this
chapter
and
may
instead
adopt
any
methodology
for
allocating
NOX
allowances
to
individual
sources,
as
follows:

(
A)
The
State
may
provide
for
issuance
of
an
amount
of
CAIR
Ozone
Season
NOX
allowances
for
an
ozone
season,
in
addition
to
the
amount
in
the
State's
Ozone
Season
EGU
NOX
Budget
for
such
ozone
season,
not
exceeding
the
amount
of
NOX
SIP
Call
allowances
allocated
for
the
ozone
season
under
the
NOX
Budget
Trading
Program
to
non­
EGUs
that
the
applicability
provisions
in
§
96.104
are
expanded
to
include
under
paragraph
(
aa)(
2)(
i)
of
this
section;

(
B)
The
State's
methodology
must
not
allow
the
State
to
allocate
CAIR
Ozone
Season
NOX
allowances
for
an
ozone
season
in
excess
of
the
amount
in
the
State's
Ozone
Season
EGU
NOX
budget
for
such
ozone
season
plus
any
additional
amount
of
CAIR
Ozone
Season
NOX
allowances
issued
under
paragraph
(
aa)(
2)(
iii)(
A)
of
this
section
for
such
ozone
season;

(
C)
The
State's
methodology
must
require
that,
for
EGUs
commencing
operation
before
January
1,
2000,
the
State
will
35
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
determine,
and
notify
the
Administrator
of,
each
unit's
allocation
of
CAIR
NOX
allowances
by
October
31,
2006
for
the
ozone
seasons
2009,
2010,
and
2011
and
by
October
31,
2008
and
October
31
of
each
year
thereafter
for
the
ozone
season
4
years
after
the
notification
deadline;
and
(
D)
The
State's
methodology
must
require
that,
for
EGUs
commencing
operation
on
or
after
January
1,
2000,
the
State
will
determine,
and
notify
the
Administrator
of,
each
unit's
allocation
of
CAIR
Ozone
Season
NOX
allowances
by
October
31
of
the
calendar
year
immediately
after
the
ozone
season
for
which
the
CAIR
Ozone
Season
NOX
allowances
are
allocated.

(
3)
A
State
that
adopts
an
emissions
trading
program
in
accordance
with
paragraph
(
aa)(
1)
or
(
2)
of
this
section
is
not
required
to
adopt
an
emissions
trading
program
in
accordance
with
paragraph
(
o)(
1)
or
(
2)
of
this
section
or
§
51.153(
o)(
1)
or
(
2).

(
4)
If
a
State
adopts
an
emissions
trading
program
that
differs
substantively
from
subparts
AAAA
through
IIII
of
part
96
of
this
chapter,
other
than
as
set
forth
in
paragraph
(
aa)(
2)
of
this
section,
then
such
emissions
trading
program
is
not
automatically
approved
as
set
forth
in
paragraph
(
aa)(
1)
or
(
2)

of
this
section
and
will
be
reviewed
by
the
Administrator
for
approvability
in
accordance
with
the
other
provisions
of
this
section,
provided
that
the
NOX
allowances
issued
under
such
emissions
trading
program
shall
not,
and
the
SIP
revision
shall
state
that
such
NOX
allowances
shall
not,
qualify
as
CAIR
NOX
36
Section
I
3/
4/
2005
DRAFT
Do
Not
Quote
or
Cite
allowances
or
CAIR
Ozone
Season
NOX
allowances
under
any
emissions
trading
program
approved
under
paragraphs
(
o)(
1)
or
(
2)

or
(
aa)(
1)
or
(
2)
of
this
section.

(
bb)(
1)
The
State
may
revise
its
SIP
to
provide
that,
for
each
ozone
season
during
which
a
State
implements
control
measures
on
EGUs
or
non­
EGUs
under
paragraph
(
aa)(
1)
or
(
2)
of
this
section,
such
EGUs
and
non­
EGUs
shall
not
be
subject
to
the
requirements
of
the
State's
SIP
meeting
the
requirements
of
§
51.121,
if
the
SIP
revision
also
provides
that:

(
i)
For
a
State
whose
amount
of
tons
specified
in
paragraph
(
q)(
2)
of
this
section
exceeds
the
amount
of
NOX
SIP
Call
allowances
allocated
for
the
ozone
season
in
2009
or
in
any
year
thereafter
for
the
same
types
and
sizes
of
units
as
those
covered
by
the
amount
of
tons
specified
in
paragraph
(
q)(
2)
of
this
section,
the
State
will
replace
the
former
amount
for
such
ozone
season
by
the
latter
amount
for
such
ozone
season
in
applying
paragraph
(
q)
of
this
section.

(
ii)
An
amount
of
NOX
SIP
Call
allowances
equal
to,
and
allocated
for
the
same
or
a
previous
ozone
season,
as
the
NOX
SIP
Call
allowances
allocated
to
such
EGUs
and
non­
EGUs
for
each
ozone
season
for
which
the
State
revises
its
SIP
under
paragraph
(
bb)(
1)
of
this
section
and
not
deducted
by
the
Administrator
under
the
NOX
Budget
Trading
Program
shall
be
permanently
retired
and
shall
not
be
available
for
deduction
by
the
Administrator
under
the
NOX
Budget
Trading
Program.
DRAFT
­
12/
2/
04
37
(
2)
Notwithstanding
a
SIP
revision
by
a
State
authorized
under
paragraph
(
bb)(
1)
of
this
section,
if
the
State's
SIP
that,

without
such
SIP
revision,
imposes
control
measures
on
EGUs
or
non­
EGUs
under
§
51.121
is
determined
by
the
Administrator
to
meet
the
requirements
of
§
51.121,
such
SIP
shall
be
deemed
to
continue
to
meet
the
requirements
of
§
51.121.

(
cc)
The
terms
used
in
this
section
shall
have
the
following
meanings:

Administrator
means
the
Administrator
of
the
United
States
Environmental
Protection
Agency
or
the
Administrator's
duly
authorized
representative.

Allocate
or
allocation
means,
with
regard
to
allowances,
the
determination
of
the
amount
of
allowances
to
be
initially
credited
to
a
source.

Boiler
means
an
enclosed
fossil­
or
other­
fuel­
fired
combustion
device
used
to
produce
heat
and
to
transfer
heat
to
recirculating
water,
steam,
or
other
medium.

Bottoming­
cycle
cogeneration
unit
means
a
cogeneration
unit
in
which
the
energy
input
to
the
unit
is
first
used
to
produce
useful
thermal
energy
and
at
least
some
of
the
reject
heat
from
the
useful
thermal
energy
application
or
process
is
then
used
for
electricity
production.

Clean
Air
Act
or
CAA
means
the
Clean
Air
Act,
42
U.
S.
C.

7401,
et
seq.

Cogeneration
unit
means
a
stationary,
fossil­
fuel­
fired
DRAFT
­
12/
2/
04
38
boiler
or
stationary,
fossil­
fuel­
fired
combustion
turbine:

(
1)
Having
equipment
used
to
produce
electricity
and
useful
thermal
energy
for
industrial,
commercial,
heating,
or
cooling
purposes
through
the
sequential
use
of
energy;
and
(
2)
Producing
during
the
12­
month
period
starting
on
the
date
the
unit
first
produces
electricity
and
during
any
calendar
year
after
which
the
unit
first
produces
electricity
 
(
i)
For
a
topping­
cycle
cogeneration
unit,

(
A)
Useful
thermal
energy
not
less
than
5
percent
of
total
energy
output;
and
(
B)
Useful
power
that,
when
added
to
one­
half
of
useful
thermal
energy
produced,
is
not
less
then
42.5
percent
of
total
energy
input
or,
if
useful
thermal
energy
produced
is
less
than
15
percent
of
total
energy
output,
not
less
than
45
percent
of
total
energy
input.

(
ii)
For
a
bottoming­
cycle
cogeneration
unit,
useful
power
not
less
than
45
percent
of
total
energy
input.

Combustion
turbine
means:

(
1)
An
enclosed
device
comprising
a
compressor,
a
combustor,

and
a
turbine
and
in
which
the
flue
gas
resulting
from
the
combustion
of
fuel
in
the
combustor
passes
through
the
turbine,

rotating
the
turbine;
and
(
2)
If
the
enclosed
device
under
paragraph
(
1)
of
this
definition
is
combined
cycle,
any
associated
heat
recovery
steam
generator
and
steam
turbine.
DRAFT
­
12/
2/
04
39
Commence
operation
means
to
have
begun
any
mechanical,

chemical,
or
electronic
process,
including,
with
regard
to
a
unit,
start­
up
of
a
unit's
combustion
chamber.

Electric
generating
unit
or
EGU
means:

(
1)
Except
as
provided
in
paragraph
(
2)
of
this
definition,

a
stationary,
fossil­
fuel­
fired
boiler
or
stationary,

fossilfuel
fired
combustion
turbine
serving
at
any
time,
since
the
start­
up
of
a
unit's
combustion
chamber,
a
generator
with
nameplate
capacity
of
more
than
25
MWe
producing
electricity
for
sale.

(
2)
For
a
unit
that
qualifies
as
a
cogeneration
unit
during
the
12­
month
period
starting
on
the
date
the
unit
first
produces
electricity
and
continues
to
qualify
as
a
cogeneration
unit,
a
cogeneration
unit
serving
at
any
time
a
generator
with
nameplate
capacity
of
more
than
25
MWe
and
supplying
in
any
calendar
year
more
than
one­
third
of
the
unit's
potential
electric
output
capacity
or
219,000
MWh,
whichever
is
greater,
to
any
utility
power
distribution
system
for
sale.
If
a
unit
that
qualifies
as
a
cogeneration
unit
during
the
12­
month
period
starting
on
the
date
the
unit
first
produces
electricity
but
subsequently
no
longer
qualifies
as
a
cogeneration
unit,
the
unit
shall
be
subject
to
paragraph
(
1)
of
this
definition
starting
on
the
day
on
which
the
unit
first
no
longer
qualifies
as
a
cogeneration
unit.

Fossil
fuel
means
natural
gas,
petroleum,
coal,
or
any
form
DRAFT
­
12/
2/
04
40
of
solid,
liquid,
or
gaseous
fuel
derived
from
such
material.

Fossil­
fuel­
fired
means,
with
regard
to
a
unit,
combusting
any
amount
of
fossil
fuel
in
any
calendar
year.

Generator
means
a
device
that
produces
electricity.

Maximum
design
heat
input
means
the
maximum
amount
of
fuel
per
hour
(
in
Btu/
hr)
that
a
unit
is
capable
of
combusting
on
a
steady
state
basis:

(
A)
As
specified
by
the
manufacturer
of
the
unit
as
of
the
initial
installation
of
the
unit;

(
B)
If
the
unit
subsequently
undergoes
a
physical
change
resulting
in
an
increase
in
such
maximum
design
heat
input,
as
specified
by
the
person
conducting
the
physical
change;
or
(
C)
For
purposes
of
applying
the
definition
of
the
term
"
potential
electrical
output
capacity"
and
if
the
unit
subsequently
undergoes
a
physical
change
resulting
in
a
decrease
in
such
maximum
design
heat
input,
as
specified
by
the
person
conducting
the
physical
change.

NAAQS
means
National
Ambient
Qir
Quality
Standard.

Nameplate
capacity
means
the
maximum
electrical
generating
output
(
in
MWe)
that
a
generator
is
capable
of
producing
on
a
steady
state
basis
and
during
continuous
operation
(
when
not
restricted
by
seasonal
or
other
deratings),
as
specified
by
the
manufacturer
of
the
generator
as
of
the
initial
installation
of
the
generator
or,
if
the
generator
subsequently
undergoes
a
physical
change
resulting
in
an
increase
in
such
maximum
DRAFT
­
12/
2/
04
41
electrical
generating
output,
as
specified
by
the
person
conducting
the
physical
change.

Non­
EGU
means
a
source
of
NOX
emissions
that
is
not
an
EGU.

NOX
Budget
Trading
Program
means
a
multi­
state
nitrogen
oxide
air
pollution
control
and
emission
reduction
program
approved
and
administered
by
the
Administrator
in
accordance
with
subparts
A
through
I
of
this
part
and
§
51.121
of
this
chapter,

as
a
means
of
mitigating
interstate
transport
of
ozone
and
nitrogen
oxides.

NOX
SIP
Call
allowance
means
a
limited
authorization
issued
by
the
Administrator
under
the
NOX
Budget
Trading
Program
to
emit
up
to
one
ton
of
nitrogen
oxides
during
the
ozone
season
of
the
specified
year
or
any
year
thereafter,
provided
that
the
provision
in
§
51.121(
b)(
2)(
ii)(
E)
of
this
chapter
shall
not
be
used
in
applying
this
definition.

Ozone
season
means
the
period,
which
begins
May
1
and
ends
September
30
of
any
year.

Potential
electrical
output
capacity
means
33
percent
of
a
unit's
maximum
design
heat
input,
divided
by
3,413
mmBtu/
kWh,

divided
by
1,000
kWh/
MWh,
and
multiplied
by
8,760
hr/
yr.

Sequential
use
of
energy
means:

(
1)
For
a
topping­
cycle
cogeneration
unit,
the
use
of
reject
heat
from
electricity
production
in
a
useful
thermal
energy
application
or
process;
or
(
2)
For
a
bottoming­
cycle
cogeneration
unit,
the
use
of
DRAFT
­
12/
2/
04
42
reject
heat
from
useful
thermal
energy
application
or
process
in
electricity
production.

Topping­
cycle
cogeneration
unit
means
a
cogeneration
unit
in
which
the
energy
input
to
the
unit
is
first
used
to
produce
useful
power,
including
electricity,
and
at
least
some
of
the
reject
heat
from
the
electricity
production
is
then
used
to
provide
useful
thermal
energy.

Total
energy
input
means,
with
regard
to
a
cogeneration
unit,
total
energy
of
all
forms
supplied
to
the
cogeneration
unit,
excluding
energy
produced
by
the
cogeneration
unit
itself.

Total
energy
output
means,
with
regard
to
a
cogeneration
unit,
the
sum
of
useful
power
and
useful
thermal
energy
produced
by
the
cogeneration
unit.

Unit
means
a
stationary,
fossil­
fuel­
fired
boiler
or
a
stationary,
fossil­
fuel­
fired
combustion
turbine.

Useful
power
means,
with
regard
to
a
cogeneration
unit,

electricity
or
mechanical
energy
made
available
for
use,

excluding
any
such
energy
used
in
the
power
production
process
(
which
process
includes,
but
is
not
limited
to,
any
on­
site
processing
or
treatment
of
fuel
combusted
at
the
unit
and
any
onsite
emission
controls).

Useful
thermal
energy
means,
with
regard
to
a
cogeneration
unit,
thermal
energy
that
is:

(
1)
Made
available
to
an
industrial
or
commercial
process,

excluding
any
heat
contained
in
condensate
return
or
makeup
DRAFT
­
12/
2/
04
43
water;

(
2)
Used
in
a
heat
application
(
e.
g.,
space
heating
or
domestic
hot
water
heating);
or
(
3)
Used
in
a
space
cooling
application
(
i.
e.,
thermal
energy
used
by
an
absorption
chiller).

Utility
power
distribution
system
means
the
portion
of
an
electricity
grid
owned
or
operated
by
a
utility
and
dedicated
to
delivering
electricity
to
customers.

5.
Part
51
is
amended
by
adding
§
51.124
to
Subpart
G
to
read
as
follows:

§
51.124
Findings
and
requirements
for
submission
of
State
implementation
plan
revisions
relating
to
emissions
of
sulfur
dioxide
pursuant
to
the
Clean
Air
Interstate
Rule.

(
a)
Under
section
110(
a)(
1)
of
the
CAA,
42
U.
S.
C.

7410(
a)(
1),
the
Administrator
determines
that
each
State
identified
in
paragraph
(
c)
of
this
section
must
submit
a
SIP
revision
to
comply
with
the
requirements
of
section
110(
a)(
2)(
D)(
i)(
I)
of
the
CAA,
42
U.
S.
C.
7410(
a)(
2)(
D)(
i)(
I),

through
the
adoption
of
adequate
provisions
prohibiting
sources
and
other
activities
from
emitting
SO2
in
amounts
that
will
contribute
significantly
to
nonattainment
in,
or
interfere
with
maintenance
by,
one
or
more
other
States
with
respect
to
the
fine
particles
(
PM2.5)
NAAQS.

(
b)
For
each
State
identified
in
paragraph
(
c)
of
this
section,
the
SIP
revision
required
under
paragraph
(
a)
will
DRAFT
­
12/
2/
04
44
contain
adequate
provisions,
for
purposes
of
complying
with
section
110(
a)(
2)(
D)(
i)(
I)
of
the
CAA,
42
U.
S.
C.

7410(
a)(
2)(
D)(
i)(
I),
only
if
the
SIP
revision
contains
control
measures
that
assure
compliance
with
the
applicable
requirements
of
this
section.

(
c)
The
following
States
are
subject
to
the
requirements
of
this
section:
Alabama,
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,
and
the
District
of
Columbia.

(
d)(
1)
The
SIP
revision
under
paragraph
(
a)
of
this
section
must
be
submitted
to
EPA
by
no
later
than
[
Insert
the
date
18
months
(
540
days)
from
the
date
on
which
the
Administrator
signs
the
final
Clean
Air
Interstate
Rule].

(
2)
The
requirements
of
appendix
V
to
this
part
shall
apply
to
the
SIP
revision
under
paragraph
(
a)
of
this
section.

(
3)
The
State
shall
deliver
5
copies
of
the
SIP
revision
under
paragraph
(
a)
of
this
section
to
the
appropriate
Regional
Office,
with
a
letter
giving
notice
of
such
action.

(
e)
The
State's
SIP
revision
shall
contain
control
measures
and
demonstrate
that
they
will
result
in
compliance
with
the
State's
Annual
EGU
SO2
budget,
if
applicable,
and
achieve
the
State's
Annual
Non­
EGU
SO2
Reduction
Requirement,
if
applicable,

for
the
appropriate
periods.
The
amounts
of
the
State's
Annual
DRAFT
­
12/
2/
04
45
EGU
SO2
budget
and
Annual
Non­
EGU
SO2
Reduction
Requirement
shall
be
determined
as
follows:

(
1)(
i)
The
Annual
EGU
SO2
budget
for
the
State
is
defined
as
the
total
amount
of
SO2
emissions
from
all
EGUs
in
that
State
for
a
year,
if
the
State
meets
the
requirements
of
paragraph
(
a)
of
this
section
by
imposing
control
measures,
at
least
in
part,
on
EGUs.
If
the
State
imposes
control
measures
under
this
section
on
only
EGUs,
the
Annual
EGU
SO2
budget
for
the
State
shall
not
exceed
the
amount,
during
the
indicated
periods,
specified
in
paragraph
(
e)(
2)
of
this
section.

(
ii)
The
Annual
Non­
EGU
SO2
Reduction
Requirement,
if
applicable,
is
defined
as
the
total
amount
of
SO2
emission
reductions
that
the
State
demonstrates,
in
accordance
with
paragraph
(
g)
of
this
section,
it
will
achieve
from
non­
EGUs
during
the
appropriate
period.
If
the
State
meets
the
requirements
of
paragraph
(
a)
of
this
section
by
imposing
control
measures
on
only
non­
EGUs,
then
the
State's
Annual
Non­
EGU
SO2
Reduction
Requirement
shall
equal
or
exceed,
during
the
appropriate
periods,
the
amount
determined
in
accordance
with
paragraph
(
e)(
3)
of
this
section.

(
iii)
If
a
State
meets
the
requirements
of
paragraph
(
a)
of
this
section
by
imposing
control
measures
on
both
EGUs
and
non­

EGUs,
then:

(
A)
The
Annual
Non­
EGU
SO2
Reduction
Requirement
shall
equal
or
exceed
the
difference
between
the
amount
specified
in
DRAFT
­
12/
2/
04
46
paragraph
(
e)(
2)
of
this
section
for
the
appropriate
period
and
the
amount
of
the
State's
Annual
EGU
SO2
budget
specified
in
the
SIP
revision
for
the
appropriate
period;
and
(
B)
The
Annual
EGU
SO2
budget
shall
not
exceed,
during
the
indicated
periods,
the
amount
specified
in
paragraph
(
e)(
2)
of
this
section
plus
the
amount
of
the
Annual
Non­
EGU
SO2
Reduction
Requirement
under
paragraph
(
e)(
1)(
iii)(
A)
of
this
section
for
the
appropriate
period.

(
2)
For
a
State
that
complies
with
the
requirements
of
paragraph
(
a)
of
this
section
by
imposing
control
measures
on
only
EGUs,
the
amount
of
the
Annual
EGU
SO2
budget,
in
tons
of
SO2
per
year,
shall
be
as
follows,
for
the
indicated
State
for
the
indicated
period:

State
Annual
EGU
SO2
Budget
for
2010­
2014
(
tons)
Annual
EGU
SO2
Budget
for
2015
and
thereafter
(
tons)
Alabama
157,582
110,307
District
of
Columbia
708
495
Florida
253,450
177,415
Georgia
213,057
149,140
Illinois
192,671
134,869
Indiana
254,599
178,219
Iowa
64,095
44,866
Kentucky
188,773
132,141
Louisiana
59,948
41,963
Maryland
70,697
49,488
Michigan
178,605
125,024
Minnesota
49,987
34,991
Mississippi
33,763
23,634
Missouri
137,214
96,050
New
York
135,139
94,597
North
Carolina
137,342
96,139
Ohio
333,520
233,464
Pennsylvania
275,990
193,193
South
Carolina
57,271
40,089
DRAFT
­
12/
2/
04
47
Tennessee
137,216
96,051
Texas
320,946
224,662
Virginia
63,478
44,435
West
Virginia
215,881
151,117
Wisconsin
87,264
61,085
(
3)
For
a
State
that
complies
with
the
requirements
of
paragraph
(
a)
of
this
section
by
imposing
control
measures
on
only
non­
EGUs,
the
amount
of
the
Annual
Non­
EGU
SO2
Reduction
Requirement,
in
tons
of
SO2
per
year,
shall
be
determined,
for
the
State
for
2010
and
thereafter,
by
subtracting
the
amount
of
the
State's
SO2
baseline
EGU
emissions
inventory
projected
for
the
ozone
season
in
the
appropriate
year,
specified
in
XXXXXXXXXXXXXX,
from
the
amount
of
the
State's
Annual
EGU
SO2
budget
for
the
appropriate
year,
specified
in
paragraph
(
e)(
2)
of
this
section.

(
f)
Each
SIP
revision
must
set
forth
control
measures
to
meet
the
amounts
specified
in
paragraph
(
e)
of
this
section,
as
applicable,
including
the
following:

(
1)
A
description
of
enforcement
methods
including,
but
not
limited
to:

(
i)
Procedures
for
monitoring
compliance
with
each
of
the
selected
control
measures;

(
ii)
Procedures
for
handling
violations;
and
(
iii)
A
designation
of
agency
responsibility
for
enforcement
of
implementation.

(
2)(
i)
If
a
State
elects
to
impose
control
measures
on
EGUs,

then
those
measures
must
impose
an
annual
SO2
mass
emissions
cap
on
all
such
sources
in
the
State.
DRAFT
­
12/
2/
04
48
(
ii)
If
a
State
elects
to
impose
control
measures
on
fossil
fuel­
fired
non­
EGUs
that
are
boilers
or
combustion
turbines
with
a
maximum
design
heat
input
greater
than
250
mmBtu/
hr,
then
those
measures
must
impose
an
annual
SO2
mass
emissions
cap
on
all
such
sources
in
the
State.

(
iii)
If
a
State
elects
to
impose
control
measures
on
non­

EGUs
other
than
those
described
in
paragraph
(
f)(
2)(
ii)
of
this
section,
then
those
measures
must
impose
an
annual
SO2
mass
emissions
cap
on
all
such
sources
in
the
State,
or
the
State
must
demonstrate
why
such
emissions
cap
is
not
practicable,
and
adopt
alternative
requirements
that
ensure
that
the
State
will
comply
with
its
requirements
under
paragraph
(
e)
of
this
section,
as
applicable,
in
2010
and
subsequent
years.

(
g)(
1)
Each
SIP
revision
that
contains
control
measures
covering
non­
EGUs
as
part
or
all
of
a
State's
obligation
in
meeting
its
requirement
under
paragraph
(
a)
of
this
section
must
demonstrate
that
such
control
measures
are
adequate
to
provide
for
the
timely
compliance
with
the
State's
Annual
Non­
EGU
SO2
Reduction
Requirement
under
paragraph
(
e)
of
this
section
and
are
not
adopted
or
implemented
by
the
State,
as
of
[
Insert
the
date
of
publication
of
the
final
Clean
Air
Interstate
Rule],
and
are
not
adopted
or
implemented
by
the
federal
government,
as
of
the
date
of
submission
of
the
SIP
revision
by
the
State
to
EPA.

(
2)
The
demonstration
under
paragraph
(
g)(
1)
of
this
section
must
include
the
following,
with
respect
to
each
source
category
DRAFT
­
12/
2/
04
49
of
non­
EGUs
for
which
the
SIP
revision
requires
control
measures:

(
i)
A
detailed
historical
baseline
inventory
of
SO2
mass
emissions
from
the
source
category
in
a
representative
year
consisting,
at
the
State's
election,
of
2002,
2003,
2004,
or
2005,
or
an
average
of
2
or
more
of
those
years,
absent
the
control
measures
specified
in
the
SIP
revision.

(
A)
This
inventory
must
represent
estimates
of
actual
emissions
based
on
monitoring
data
in
accordance
with
part
75
of
this
chapter,
if
the
source
category
is
subject
to
part
75
monitoring
requirements
in
accordance
with
part
75
of
this
chapter.

(
B)
In
the
absence
of
monitoring
data
in
accordance
with
part
75
of
this
chapter,
actual
emissions
must
be
quantified,
to
the
maximum
extent
practicable,
with
the
same
degree
of
assurance
with
which
emissions
are
quantified
for
sources
subject
to
part
75
of
this
chapter
and
using
source­
specific
or
source­

categoryspecific
assumptions
that
ensure
a
source's
or
source
category's
actual
emissions
are
not
overestimated.
If
a
State
uses
factors
to
estimate
emissions,
production
or
utilization,
or
effectiveness
of
controls
or
rules
for
a
source
category,
such
factors
must
be
chosen
to
ensure
that
emissions
are
not
overestimated.

(
C)
For
measures
to
reduce
emissions
from
motor
vehicles,

emission
estimates
must
be
based
on
an
emissions
model
that
has
been
approved
by
EPA
for
use
in
SIP
development
and
must
be
DRAFT
­
12/
2/
04
50
consistent
with
the
planning
assumptions
regarding
vehicle
miles
traveled
and
other
factors
current
at
the
time
of
the
SIP
development.

(
D)
For
measures
to
reduce
emissions
from
nonroad
engines
or
vehicles,
emission
estimates
methodologies
must
be
approved
by
EPA.

(
ii)
A
detailed
baseline
inventory
of
SO2
mass
emissions
from
the
source
category
in
the
years
2010
and
2015,
absent
the
control
measures
specified
in
the
SIP
revision
and
reflecting
changes
in
these
emissions
from
the
historical
baseline
year
to
the
years
2010
and
2015,
based
on
projected
changes
in
the
production
input
or
output,
population,
vehicle
miles
traveled,

economic
activity,
or
other
factors
as
applicable
to
this
source
category.

(
A)
These
inventories
must
account
for
implementation
of
any
control
measures
that
are
adopted
or
implemented
by
the
State,
as
of
[
Insert
the
date
of
publication
of
the
final
Clean
Air
Interstate
Rule],
or
adopted
or
implemented
by
the
federal
government,
as
of
the
date
of
submission
of
the
SIP
revision
by
the
State
to
EPA,
and
must
exclude
any
control
measures
specified
in
the
SIP
revision
to
meet
the
SO2
emissions
reduction
requirements
of
this
section.

(
B)
Economic
and
population
forecasts
must
be
as
specific
as
possible
to
the
applicable
industry,
State,
and
county
of
the
source
or
source
category
and
must
be
consistent
with
both
DRAFT
­
12/
2/
04
51
national
projections
and
relevant
official
planning
assumptions,

including
estimates
of
population
and
vehicle
miles
traveled
developed
through
consultation
between
State
and
local
transportation
and
air
quality
agencies.
However,
if
these
official
planning
assumptions
are
inconsistent
with
official
U.
S.

Census
projections
of
population
or
with
energy
consumption
projections
contained
in
the
U.
S.
Department
of
Energy's
most
recent
Annual
Energy
Outlook,
then
the
SIP
revision
must
make
adjustments
to
correct
the
inconsistency
or
must
demonstrate
how
the
official
planning
assumptions
are
more
accurate.

(
C)
These
inventories
must
account
for
any
changes
in
production
method,
materials,
fuels,
or
efficiency
that
are
expected
to
occur
between
the
historical
baseline
year
and
2010
or
2015,
as
appropriate.

(
iii)
A
projection
of
SO2
mass
emissions
in
2010
and
2015
from
the
source
category
assuming
the
same
projected
changes
as
under
paragraph
(
g)(
2)(
ii)
of
this
section
and
resulting
from
implementation
of
each
of
the
control
measures
specified
in
the
SIP
revision.

(
A)
These
inventories
must
address
the
possibility
that
the
State's
new
control
measures
may
cause
production
or
utilization,

and
emissions,
to
shift
to
unregulated
or
less
stringently
regulated
sources
in
the
source
category
in
the
same
or
another
State,
and
these
inventories
must
include
any
such
amounts
of
emissions
that
may
shift
to
such
other
sources.
DRAFT
­
12/
2/
04
52
(
B)
The
State
must
provide
EPA
with
a
summary
of
the
computations,
assumptions,
and
judgments
used
to
determine
the
degree
of
reduction
in
projected
2010
and
2015
SO2
emissions
that
will
be
achieved
from
the
implementation
of
the
new
control
measures
compared
to
the
relevant
baseline
emissions
inventory.

(
iv)
The
result
of
subtracting
the
amounts
in
paragraph
(
g)(
2)(
iii)
of
this
section
for
2010
and
2015,
respectively,
from
the
lower
of
the
amounts
in
paragraph
(
g)(
2)(
i)
or
(
g)(
2)(
ii)
of
this
section
for
2010
and
2015,
respectively,
may
be
credited
towards
the
State's
Annual
Non­
EGU
SO2
Reduction
Requirement
in
paragraph
(
e)(
3)
of
this
section
for
the
appropriate
period.

(
v)
Each
SIP
revision
must
identify
the
sources
of
the
data
used
in
each
estimate
and
each
projection
of
emissions.

(
h)
Each
SIP
revision
must
comply
with
§
51.116
(
regarding
data
availability).

(
i)
Each
SIP
revision
must
provide
for
monitoring
the
status
of
compliance
with
any
control
measures
adopted
to
meet
the
State's
requirements
under
paragraph
(
e)
of
this
section,
as
follows:

(
1)
The
SIP
revision
must
provide
for
legally
enforceable
procedures
for
requiring
owners
or
operators
of
stationary
sources
to
maintain
records
of,
and
periodically
report
to
the
State:

(
i)
Information
on
the
amount
of
SO2
emissions
from
the
stationary
sources;
and
DRAFT
­
12/
2/
04
53
(
ii)
Other
information
as
may
be
necessary
to
enable
the
State
to
determine
whether
the
sources
are
in
compliance
with
applicable
portions
of
the
control
measures;

(
2)
The
SIP
revision
must
comply
with
§
51.212
(
regarding
testing,
inspection,
enforcement,
and
complaints);

(
3)
If
the
SIP
revision
contains
any
transportation
control
measures,
then
the
SIP
revision
must
comply
with
§
51.213
(
regarding
transportation
control
measures);

(
4)(
i)
If
the
SIP
revision
contains
measures
to
control
EGUs,
then
the
SIP
revision
must
require
such
sources
to
comply
with
the
monitoring,
recordkeeping,
and
reporting
provisions
of
part
75
of
this
chapter.

(
ii)
If
the
SIP
revision
contains
measures
to
control
fossil
fuel­
fired
non­
EGUs
that
are
boilers
or
combustion
turbines
with
a
maximum
design
heat
input
greater
than
250
mmBtu/
hr,
then
the
SIP
revision
must
require
such
sources
to
comply
with
the
monitoring,
recordkeeping,
and
reporting
provisions
of
part
75
of
this
chapter.

(
iii)
If
the
SIP
revision
contains
measures
to
control
any
other
non­
EGUs
that
are
not
described
in
paragraph
(
i)(
4)(
ii)
of
this
section,
then
the
SIP
revision
must
require
such
sources
to
comply
with
the
monitoring,
recordkeeping,
and
reporting
provisions
of
part
75
of
this
chapter,
or
the
State
must
demonstrate
why
such
requirements
are
not
practicable
and
adopt
alternative
requirements
that
ensure
that
the
required
emissions
DRAFT
­
12/
2/
04
54
reductions
will
be
quantified,
to
the
maximum
extent
practicable,

with
the
same
degree
of
assurance
with
which
emissions
are
quantified
for
sources
subject
to
part
75
of
this
chapter.

(
j)
Each
SIP
revision
must
show
that
the
State
has
legal
authority
to
carry
out
the
SIP
revision,
including
authority
to:

(
1)
Adopt
emissions
standards
and
limitations
and
any
other
measures
necessary
for
attainment
and
maintenance
of
the
State's
relevant
Annual
EGU
SO2
budget
or
the
Annual
Non­
EGU
SO2
Reduction
Requirement,
as
applicable,
under
paragraph
(
e);

(
2)
Enforce
applicable
laws,
regulations,
and
standards
and
seek
injunctive
relief;

(
3)
Obtain
information
necessary
to
determine
whether
air
pollution
sources
are
in
compliance
with
applicable
laws,

regulations,
and
standards,
including
authority
to
require
recordkeeping
and
to
make
inspections
and
conduct
tests
of
air
pollution
sources;
and
(
4)(
i)
Require
owners
or
operators
of
stationary
sources
to
install,
maintain,
and
use
emissions
monitoring
devices
and
to
make
periodic
reports
to
the
State
on
the
nature
and
amounts
of
emissions
from
such
stationary
sources;
and
(
ii)
Make
the
data
described
in
paragraph
(
j)(
4)(
i)
of
this
section
available
to
the
public
within
a
reasonable
time
after
being
reported
and
as
correlated
with
any
applicable
emissions
standards
or
limitations.

(
k)(
1)
The
provisions
of
law
or
regulation
that
the
State
DRAFT
­
12/
2/
04
55
determines
provide
the
authorities
required
under
this
section
must
be
specifically
identified,
and
copies
of
such
laws
or
regulations
must
be
submitted
with
the
SIP
revision.

(
2)
Legal
authority
adequate
to
fulfill
the
requirements
of
paragraphs
(
j)(
3)
and
(
4)
of
this
section
may
be
delegated
to
the
State
under
section
114
of
the
CAA.

(
l)(
1)
A
SIP
revision
may
assign
legal
authority
to
local
agencies
in
accordance
with
§
51.232.

(
2)
Each
SIP
revision
must
comply
with
§
51.240
(
regarding
general
plan
requirements).

(
m)
Each
SIP
revision
must
comply
with
§
51.280
(
regarding
resources).

(
n)
Each
SIP
revision
must
provide
for
State
compliance
with
the
reporting
requirements
in
§
51.125.

(
o)(
1)
Notwithstanding
any
other
provision
of
this
section,

if
a
State
adopts
regulations
substantively
identical
to
subparts
AAA
through
III
of
part
96
of
this
chapter
(
CAIR
SO2
Trading
Program),
incorporates
such
subparts
by
reference
into
its
regulations,
or
adopts
regulations
that
differ
substantively
from
such
subparts
only
as
set
forth
in
paragraph
(
o)(
2)
of
this
section,
then
such
emissions
trading
program
in
the
State's
SIP
revision
is
automatically
approved
as
meeting
the
requirements
of
paragraph
(
e)
of
this
section,
provided
that
the
State
has
the
legal
authority
to
take
such
action
and
to
implement
its
responsibilities
under
such
regulations.
DRAFT
­
12/
2/
04
56
(
2)
If
a
State
adopts
an
emissions
trading
program
that
differs
substantively
from
subparts
AAA
through
III
of
part
96
of
this
chapter
only
as
follows,
then
the
emissions
trading
program
is
approved
as
set
forth
in
paragraph
(
o)(
1)
of
this
section.

(
i)
The
State
may
decline
to
adopt
the
CAIR
SO2
opt­
in
provisions
of
subpart
III
of
this
part
and
the
provisions
applicable
only
to
CAIR
SO2
opt­
in
units
in
subparts
AAA
through
HHH
of
this
part.

(
ii)
The
State
may
decline
to
adopt
the
CAIR
SO2
opt­
in
provisions
of
§
96.288(
b)
and
the
provisions
of
subpart
III
of
this
part
applicable
only
to
CAIR
SO2
opt­
in
units
under
§
96.288(
b).

(
iii)
The
State
may
decline
to
adopt
the
CAIR
SO2
opt­
in
provisions
of
§
96.288(
c)
and
the
provisions
of
subpart
II
of
this
part
applicable
only
to
CAIR
SO2
opt­
in
units
under
§
96.288(
c).

(
3)
A
State
that
adopts
an
emissions
trading
program
in
accordance
with
paragraph
(
o)(
1)
or
(
2)
of
this
section
is
not
required
to
adopt
an
emissions
trading
program
in
accordance
with
§
96.123
(
o)(
1)
or
(
2)
or
(
aa)(
1)
or
(
2).

(
4)
If
a
State
adopts
an
emissions
trading
program
that
differs
substantively
from
subparts
AAA
through
III
of
part
96
of
this
chapter,
other
than
as
set
forth
in
paragraph
(
o)(
2)(
ii)
of
this
section,
then
such
emissions
trading
program
is
not
automatically
approved
as
set
forth
in
paragraph
(
o)(
1)
or
(
2)
of
DRAFT
­
12/
2/
04
57
this
section
and
will
be
reviewed
by
the
Administrator
for
approvability
in
accordance
with
the
other
provisions
of
this
section,
provided
that
the
SO2
allowances
issued
under
such
emissions
trading
program
shall
not,
and
the
SIP
revision
shall
state
that
such
SO2
allowances
shall
not,
qualify
as
CAIR
SO2
allowances
under
any
emissions
trading
program
approved
under
paragraph
(
o)(
1)
or
(
2)
of
this
section.

(
p)
If
a
State's
SIP
revision
does
not
contain
an
emissions
trading
program
approved
under
paragraph
(
o)(
1)
or
(
2)
of
this
section
but
contains
control
measures
on
EGUs
as
part
or
all
of
a
State's
obligation
in
meeting
its
requirement
under
paragraph
(
a)

of
this
section:

(
1)
The
SIP
revision
shall
provide,
for
each
year
that
the
State
has
such
obligation,
for
the
permanent
retirement
of
an
amount
of
Acid
Rain
allowances
allocated
to
sources
in
the
State
for
that
year
and
not
deducted
by
the
Administrator
under
the
Acid
Rain
Program
and
any
emissions
trading
program
approved
under
paragraph
(
o)(
1)
or
(
2)
of
this
section,
equal
to
the
difference
between­

(
A)
The
total
amount
of
Acid
Rain
allowances
allocated
under
the
Acid
Rain
Program
to
the
sources
in
the
State
for
that
year;

and
(
B)
If
the
State's
SIP
revision
contains
only
control
measures
on
EGUs,
the
State's
Annual
EGU
SO2
Budget
for
the
appropriate
period
as
specified
in
paragraph
(
e)(
2)
of
this
DRAFT
­
12/
2/
04
58
section
or,
if
the
State's
SIP
revision
contains
control
measures
on
EGUs
and
non­
EGUs,
the
State's
Annual
EGU
SO2
Budget
for
the
appropriate
period
as
specified
in
the
SIP
revision.

(
2)
The
SIP
revision
providing
for
permanent
retirement
of
Acid
Rain
allowances
under
paragraph
(
p)(
1)
of
this
section
must
ensure
that
such
allowances
are
not
available
for
deduction
by
the
Administrator
under
the
Acid
Rain
Program
and
any
emissions
trading
program
approved
under
paragraph
(
o)(
1)
or
(
2)
of
this
section.

(
q)
The
terms
used
in
this
section
shall
have
the
following
meanings:

Acid
Rain
Program
means
a
multi­
State
sulfur
dioxide
and
nitrogen
oxides
air
pollution
control
and
emissions
reduction
program
established
by
the
Administrator
under
title
IV
of
the
CAA
and
parts
72
through
78
of
this
chapter.

Acid
Rain
allowance
means
a
limited
authorization
issued
by
the
Administrator
under
the
Acid
Rain
Program
to
emit
up
to
one
ton
of
sulfur
dioxide
during
the
specified
year
or
any
year
thereafter,
except
as
otherwise
provided
by
the
Administrator.

Administrator
means
the
Administrator
of
the
United
States
Environmental
Protection
Agency
or
the
Administrator's
duly
authorized
representative.

Allocate
or
allocation
means,
with
regard
to
allowances,
the
determination
of
the
amount
of
allowances
to
be
initially
credited
to
a
source.
DRAFT
­
12/
2/
04
59
Boiler
means
an
enclosed
fossil­
or
other­
fuel­
fired
combustion
device
used
to
produce
heat
and
to
transfer
heat
to
recirculating
water,
steam,
or
other
medium.

Bottoming­
cycle
cogeneration
unit
means
a
cogeneration
unit
in
which
the
energy
input
to
the
unit
is
first
used
to
produce
useful
thermal
energy
and
at
least
some
of
the
reject
heat
from
the
useful
thermal
energy
application
or
process
is
then
used
for
electricity
production.

Clean
Air
Act
or
CAA
means
the
Clean
Air
Act,
42
U.
S.
C.

7401,
et
seq.

Cogeneration
unit
means
a
stationary,
fossil­
fuel­
fired
boiler
or
stationary,
fossil­
fuel­
fired
combustion
turbine:

(
1)
Having
equipment
used
to
produce
electricity
and
useful
thermal
energy
for
industrial,
commercial,
heating,
or
cooling
purposes
through
the
sequential
use
of
energy;
and
(
2)
Producing
during
the
12­
month
period
starting
on
the
date
the
unit
first
produces
electricity
and
during
any
calendar
year
after
which
the
unit
first
produces
electricity
 
(
i)
For
a
topping­
cycle
cogeneration
unit,

(
A)
Useful
thermal
energy
not
less
than
5
percent
of
total
energy
output;
and
(
B)
Useful
power
that,
when
added
to
one­
half
of
useful
thermal
energy
produced,
is
not
less
then
42.5
percent
of
total
energy
input
or,
if
useful
thermal
energy
produced
is
less
than
15
percent
of
total
energy
output,
not
less
than
45
percent
of
DRAFT
­
12/
2/
04
60
total
energy
input.

(
ii)
For
a
bottoming­
cycle
cogeneration
unit,
useful
power
not
less
than
45
percent
of
total
energy
input.

Combustion
turbine
means:

(
1)
An
enclosed
device
comprising
a
compressor,
a
combustor,

and
a
turbine
and
in
which
the
flue
gas
resulting
from
the
combustion
of
fuel
in
the
combustor
passes
through
the
turbine,

rotating
the
turbine;
and
(
2)
If
the
enclosed
device
under
paragraph
(
1)
of
this
definition
is
combined
cycle,
any
associated
heat
recovery
steam
generator
and
steam
turbine.

Commence
operation
means
to
have
begun
any
mechanical,

chemical,
or
electronic
process,
including,
with
regard
to
a
unit,
start­
up
of
a
unit's
combustion
chamber.

Electric
generating
unit
or
EGU
means:

(
1)
Except
as
provided
in
paragraph
(
2)
of
this
definition,

a
stationary,
fossil­
fuel­
fired
boiler
or
stationary,

fossilfuel
fired
combustion
turbine
serving
at
any
time,
since
the
start­
up
of
a
unit's
combustion
chamber,
a
generator
with
nameplate
capacity
of
more
than
25
MWe
producing
electricity
for
sale.

(
2)
For
a
unit
that
qualifies
as
a
cogeneration
unit
during
the
12­
month
period
starting
on
the
date
the
unit
first
produces
electricity
and
continues
to
qualify
as
a
cogeneration
unit,
a
cogeneration
unit
serving
at
any
time
a
generator
with
nameplate
DRAFT
­
12/
2/
04
61
capacity
of
more
than
25
MWe
and
supplying
in
any
calendar
year
more
than
one­
third
of
the
unit's
potential
electric
output
capacity
or
219,000
MWh,
whichever
is
greater,
to
any
utility
power
distribution
system
for
sale.
If
a
unit
that
qualifies
as
a
cogeneration
unit
during
the
12­
month
period
starting
on
the
date
the
unit
first
produces
electricity
but
subsequently
no
longer
qualifies
as
a
cogeneration
unit,
the
unit
shall
be
subject
to
paragraph
(
1)
of
this
definition
starting
on
the
day
on
which
the
unit
first
no
longer
qualifies
as
a
cogeneration
unit.

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

Fossil­
fuel­
fired
means,
with
regard
to
a
unit,
combusting
any
amount
of
fossil
fuel
in
any
calendar
year.

Generator
means
a
device
that
produces
electricity.

Maximum
design
heat
input
means
the
maximum
amount
of
fuel
per
hour
(
in
Btu/
hr)
that
a
unit
is
capable
of
combusting
on
a
steady
state
basis:

(
A)
As
specified
by
the
manufacturer
of
the
unit
as
of
the
initial
installation
of
the
unit;

(
B)
If
the
unit
subsequently
undergoes
a
physical
change
resulting
in
an
increase
in
such
maximum
design
heat
input,
as
specified
by
the
person
conducting
the
physical
change;
or
(
C)
For
purposes
of
applying
the
definition
of
the
term
"
potential
electrical
output
capacity"
and
if
the
unit
DRAFT
­
12/
2/
04
62
subsequently
undergoes
a
physical
change
resulting
in
a
decrease
in
such
maximum
design
heat
input,
as
specified
by
the
person
conducting
the
physical
change.

NAAQS
means
National
Ambient
Qir
Quality
Standard.

Nameplate
capacity
means
the
maximum
electrical
generating
output
(
in
MWe)
that
a
generator
is
capable
of
producing
on
a
steady
state
basis
and
during
continuous
operation
(
when
not
restricted
by
seasonal
or
other
deratings),
as
specified
by
the
manufacturer
of
the
generator
as
of
the
initial
installation
of
the
generator
or,
if
the
generator
subsequently
undergoes
a
physical
change
resulting
in
an
increase
in
such
maximum
electrical
generating
output,
as
specified
by
the
person
conducting
the
physical
change.

Non­
EGU
means
a
source
of
SO2
emissions
that
is
not
an
EGU.

Potential
electrical
output
capacity
means
33
percent
of
a
unit's
maximum
design
heat
input,
divided
by
3,413
mmBtu/
kWh,

divided
by
1,000
kWh/
MWh,
and
multiplied
by
8,760
hr/
yr.

Sequential
use
of
energy
means:

(
1)
For
a
topping­
cycle
cogeneration
unit,
the
use
of
reject
heat
from
electricity
production
in
a
useful
thermal
energy
application
or
process;
or
(
2)
For
a
bottoming­
cycle
cogeneration
unit,
the
use
of
reject
heat
from
useful
thermal
energy
application
or
process
in
electricity
production.

Topping­
cycle
cogeneration
unit
means
a
cogeneration
unit
in
DRAFT
­
12/
2/
04
63
which
the
energy
input
to
the
unit
is
first
used
to
produce
useful
power,
including
electricity,
and
at
least
some
of
the
reject
heat
from
the
electricity
production
is
then
used
to
provide
useful
thermal
energy.

Total
energy
input
means,
with
regard
to
a
cogeneration
unit,
total
energy
of
all
forms
supplied
to
the
cogeneration
unit,
excluding
energy
produced
by
the
cogeneration
unit
itself.

Total
energy
output
means,
with
regard
to
a
cogeneration
unit,
the
sum
of
useful
power
and
useful
thermal
energy
produced
by
the
cogeneration
unit.

Unit
means
a
stationary,
fossil­
fuel­
fired
boiler
or
a
stationary,
fossil­
fuel
fired
combustion
turbine
.

Useful
power
means,
with
regard
to
a
cogeneration
unit,

electricity
or
mechanical
energy
made
available
for
use,

excluding
any
such
energy
used
in
the
power
production
process
(
which
process
includes,
but
is
not
limited
to,
any
on­
site
processing
or
treatment
of
fuel
combusted
at
the
unit
and
any
onsite
emission
controls).

Useful
thermal
energy
means,
with
regard
to
a
cogeneration
unit,
thermal
energy
that
is:

(
1)
Made
available
to
an
industrial
or
commercial
process,

excluding
any
heat
contained
in
condensate
return
or
makeup
water;

(
2)
Used
in
a
heat
application
(
e.
g.,
space
heating
or
domestic
hot
water
heating);
or
DRAFT
­
12/
2/
04
64
(
3)
Used
in
a
space
cooling
application
(
i.
e.,
thermal
energy
used
by
an
absorption
chiller).

Utility
power
distribution
system
means
the
portion
of
an
electricity
grid
owned
or
operated
by
a
utility
and
dedicated
to
delivering
electricity
to
customers.