Draft
 
Do
not
cite,
quote
or
distribute
6560­
50­
P
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Parts
51,
52,
78,
96,
and
97
[
FRL­
]
RIN
2060­
AJ16
Interstate
Ozone
Transport:
Response
to
Court
Decisions
on
the
NOx
SIP
Call,
NOx
SIP
Call
Technical
Amendments,
and
Section
126
Rules
AGENCY:
Environmental
Protection
Agency
(
EPA).

ACTION:
Final
rule.

SUMMARY:
In
today's
action,
EPA
is
establishing
the
final
full
nitrogen
oxides
(
NOx)
budgets
for
States
subject
to
the
NOx
State
implementation
plan
(
SIP)
Call.
This
final
rule
requires
States
that
submitted
SIPs
to
meet
the
Phase
I
NOx
SIP
Call
budgets
to
submit
Phase
II
SIP
revisions
as
needed
to
achieve
the
necessary
incremental
reductions
of
NOx.
It
also
requires
Georgia
and
Missouri
to
submit
SIP
revisions
meeting
the
full
NOx
SIP
Call
budgets
since
they
were
not
required
to
submit
Phase
I
SIPs.
These
SIPS
are
necessary
to
prohibit
specified
amounts
of
emissions
of
NOx
 
one
of
the
precursors
to
ozone
(
smog)
pollution
 
for
the
purposes
of
reducing
NOx
and
ozone
transport
across
State
boundaries
in
the
eastern
half
of
the
United
States.

In
today's
action,
we
are
amending
two
related
final
Draft
 
Do
not
cite,
quote
or
distribute
2
rules
we
issued
under
sections
110
and
126
of
the
Clean
Air
Act
(
CAA)
related
to
interstate
transport
of
NOx.
We
are
responding
to
the
March
3,
2000
decision
of
the
United
States
Court
of
Appeals
for
the
District
of
Columbia
Circuit
(
D.
C.
Circuit)
in
which
the
Court
largely
upheld
the
NOx
SIP
Call,
but
remanded
four
narrow
issues
to
us
for
further
rulemaking
action;
the
related
decision
by
the
D.
C.
Circuit
on
June
8,
2001,
concerning
the
rulemakings
providing
technical
amendments
to
the
NOx
SIP
Call
in
which
the
Court,

among
other
things,
vacated
and
remanded
an
issue
for
further
rulemaking;
and
the
decision
by
the
D.
C.
Circuit
on
May
15,
2001,
concerning
the
related
Section
126
rulemaking
in
which
the
Court,
among
other
things,
vacated
and
remanded
an
issue
for
further
rulemaking;
and
the
related
decision
by
the
D.
C.
Circuit
on
August
24,
2001,
concerning
the
Section
126
Rule,
in
which
the
Court
remanded
an
issue.

We
are
also
taking
final
action
on
modifications
that
were
proposed
on
June
13,
2001
to
the
Appeal
Procedures
and
to
the
Federal
NOx
Budget
Trading
Program.
Today's
final
rule
completes
action
on
the
June
13,
2001
proposed
rule
revisions
for
sources
subject
to
the
Federal
NOx
Budget
Trading
Program
under
the
section
126
final
rule.

The
specific
issues
addressed
in
this
action
are
described
below
under
SUPPLEMENTARY
INFORMATION.
Draft
 
Do
not
cite,
quote
or
distribute
3
DATES:
This
rule
is
effective
[
insert
60
days
after
publication].

FOR
FURTHER
INFORMATION
CONTACT:
General
questions
concerning
today's
action
should
be
addressed
to
Jan
King,

Office
of
Air
Quality
Planning
and
Standards,
Air
Quality
Strategies
and
Standards
Division,
C539­
02,
Research
Triangle
Park,
NC,
27711,
telephone
(
919)
541­
5665,
e­
mail
king.
jan@
epa.
gov.
Technical
questions
concerning
electric
generating
units
(
EGUs)
should
be
directed
to
Kevin
Culligan,
Office
of
Atmospheric
Programs,
Clean
Air
Markets
Division,
(
6204M),
1200
Pennsylvania
Ave.,
NW,
Washington,

DC
20460,
telephone
(
202)
564­
9172,
e­
mail
culligan.
kevin@
epa.
gov;
technical
questions
concerning
stationary
internal
combustion
(
IC)
engines
should
be
directed
to
Doug
Grano,
Office
of
Air
Quality
Planning
and
Standards,
C539­
02,
Research
Triangle
Park,
North
Carolina
27711,
telephone
(
919)
541­
3292,
e­
mail
grano.
doug@
epa.
gov;

legal
questions
should
be
directed
to
Winifred
Okoye,
Office
of
General
Counsel,
(
2344A),
1200
Pennsylvania
Ave.,
NW,

Washington,
DC
20460,
telephone
(
202)
564­
5446,
e­
mail
okoye.
winifred@
epa.
gov.

SUPPLEMENTARY
INFORMATION:

Today's
action
addresses
the
issues
remanded
or
vacated
Draft
 
Do
not
cite,
quote
or
distribute
4
by
the
D.
C.
Circuit
in
Michigan
v.
EPA,
213
F.
3d
663
(
D.
C.

Cir.
2000),
cert.
denied,
121
S.
Ct.
1225,
149
L.
ED.
135
(
2001),
which
concerned
the
NOx
SIP
Call
(
the
"
SIP
Call
case");
Appalachian
Power
v.
EPA,
251
F.
3d
1026
(
D.
C.
Cir.

2001),
which
concerned
the
technical
amendments
rulemakings
for
the
NOx
SIP
Call
(
the
"
Technical
Amendments
case");
and
Appalachian
Power
v.
EPA,
249
F.
3d
1042
(
D.
C.
Cir.
2001).

Today's
action
establishes
the
second
phase
or
Phase
II
of
the
NOx
SIP
Call
by:

(
1)
finalizing
the
definition
of
EGU
as
applied
to
certain
small
cogeneration
units,

(
2)
setting
the
control
levels
for
stationary
internal
combustion
engines,

(
3)
excluding
portions
of
Georgia,
Missouri,
Alabama
and
Michigan
from
the
NOx
SIP
Call,

(
4)
revising
statewide
emissions
budgets
in
the
NOx
SIP
Call
to
reflect
the
disposition
of
the
first
three
issues
above,

(
5)
setting
a
SIP
submittal
date,

(
6)
setting
the
compliance
date
for
implementation
of
control
measures,
and
(
7)
excluding
Wisconsin
from
NOx
SIP
Call
requirements.

For
more
detailed
discussions
of
the
issues
addressed
in
this
action,
see
section
II
below.
Draft
 
Do
not
cite,
quote
or
distribute
5
Ground­
level
ozone
has
long
been
recognized
to
affect
public
health.
Ozone
induces
health
effects,
including
decreased
lung
function
(
primarily
in
children
active
outdoors),
increased
respiratory
symptoms
(
particularly
in
highly
sensitive
individuals),
increased
hospital
admissions
and
emergency
room
visits
for
respiratory
causes
(
among
children
and
adults
with
pre­
existing
respiratory
disease
such
as
asthma),
increased
inflammation
of
the
lungs,
and
possible
long­
term
damage
to
the
lungs.
Each
year,

groundlevel
ozone
is
also
responsible
for
crop
yield
losses.

Ozone
also
causes
noticeable
foliar
damage
in
many
crops,

trees,
and
ornamental
plants
(
i.
e.,
grass,
flowers,
shrubs,

and
trees)
and
causes
reduced
growth
in
plants.
Studies
indicate
that
current
ambient
levels
of
ozone
are
responsible
for
damage
to
forests
and
ecosystems
(
including
habitat
for
native
animal
species).

Availability
of
Related
Information
We
have
established
an
official
public
docket
for
this
action
under
Docket
ID
No.
OAR­
2001­
0008;
it
has
also
been
incorporated
by
reference
in
the
docket
for
the
Section
126
Rule
under
Docket
ID
No.
OAR­
2001­
2009.
The
official
public
docket
consists
of
the
documents
specifically
referenced
in
this
action,
any
public
comments
received,
and
other
information
related
to
this
action.
Although
a
part
of
the
Draft
 
Do
not
cite,
quote
or
distribute
6
official
docket,
the
public
docket
does
not
include
Confidential
Business
Information
(
CBI)
or
other
information
whose
disclosure
is
restricted
by
statute.
The
official
public
docket
is
the
collection
of
materials
that
is
available
for
public
viewing
at
the
Air
Docket
in
the
EPA
Docket
Center,
EPA
West
Building,
Room
B102,
1301
Constitution
Ave.,
NW,
Washington,
DC.
The
Docket
telephone
number
is
(
202)
566­
1742;
fax
(
202)
566­
1741.
The
EPA
Docket
Center
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.

The
telephone
number
for
the
Reading
Room
is
(
202)
566­
1744.

A
reasonable
fee
may
be
charged
for
copying.

You
may
access
this
Federal
Register
document
electronically
through
the
EPA
Internet
under
the
"
Federal
Register"
listings
at
http://
www.
epa.
gov/
fedrgstr/.

Public
Hearing
We
held
a
public
hearing
in
Washington
D.
C.
on
March
15,
2002.
Four
people
presented
comments
at
the
hearing.

The
public
also
had
an
opportunity
to
submit
written
testimony
within
approximately
45
days
after
the
hearing
date.

Outline
I.
Background
A.
What
Was
Contained
in
the
NOx
SIP
Call?
Draft
 
Do
not
cite,
quote
or
distribute
7
B.
What
Were
the
Court
Decisions
on
the
NOx
SIP
Call?
1.
What
Was
the
Decision
of
the
Court
on
the
8­
Hour
NAAQS?
2.
What
Effect
Did
The
Court
Decision
Have
on
the
8­
Hour
Portion
of
the
NOx
SIP
Call?
3.
What
Was
the
D.
C.
Circuit
Decision
on
the
Stay
of
the
SIP
Submittal
Schedule
for
the
NOx
SIP
Call?
4.
What
Was
the
Court's
Decision
on
the
NOx
SIP
Call?
5.
How
Did
the
Court
Respond
to
Our
Request
to
Lift
the
Stay
of
the
1­
Hour
SIP
Submission
Schedule?
6.
What
Was
the
Court's
Order
for
the
Compliance
Date?
C.
What
Was
Contained
in
the
Section
126
Rule?
1.
What
Was
the
D.
C.
Circuit
Decision
on
the
Section
126
Rule?
D.
What
Were
the
Technical
Amendments
Rulemakings?
1.
What
Was
the
D.
C.
Circuit
Decision
on
the
Technical
Amendments?
E.
What
is
the
Overview
of
D.
C.
Circuit
Remands/
Vacaturs?
F.
What
is
Our
Process
for
Addressing
the
Remands/
Vacaturs?

II.
What
is
the
Scope
of
this
Action?
A.
How
Do
We
Treat
Cogeneration
Units
and
Non­
Acid
Rain
Units?
3.
What
is
the
Historical
Definition
of
Utility
Unit?
4.
What
Was
the
NOx
SIP
Call
Definition
of
EGU?
5.
What
is
the
Rationale
for
the
Final
Rule's
Treatment
of
Cogeneration
Units?
6.
What
Revisions
Are
Being
Made
to
the
Definition
of
EGU
in
the
NOx
SIP
Call
and
the
Section
126
Rule?
7.
What
is
the
Effect
on
Cogeneration
Unit
Classification
of
Applying
"
One­
Third
Potential
Electrical
Output
Capacity/
25
MWe
Sales"
Criteria,
Rather
Than
the
Same
Methodology
as
Used
for
Other
Units?
B.
What
Are
the
Control
Level
and
Budget
Calculations
for
Stationary
Reciprocating
Internal
Combustion
Engines
(
IC
Engines)?
1.
Determination
of
Highly
Cost­
Effective
Reductions
and
Budgets
2.
What
Are
the
Key
Comments
We
Received
Regarding
IC
Engines?
C.
What
is
Our
Response
to
the
Court
Decision
on
Georgia
and
Missouri?
D.
What
Are
We
Finalizing
for
Alabama
and
Michigan
in
Light
of
the
Court
Decision
on
Georgia
and
Missouri?
E.
What
Modifications
Are
Being
Made
to
the
NOx
Emissions
Budgets?
F.
How
Will
the
Compliance
Supplement
Pools
Be
Handled?
Draft
 
Do
not
cite,
quote
or
distribute
8
G.
Will
the
EGU
Budget
Changes
Affect
the
States
Included
in
the
Three­
State
Memorandum
of
Understanding?
H.
How
Does
the
Term
"
Budget"
Relate
to
Conformity
Budgets?
I.
How
Will
Partial­
State
Trading
Be
Administered?
1.
How
Will
Flow
Control
Be
Handled
for
Georgia
and
Missouri?
J.
What
Is
the
Phase
II
SIP
Submittal
Date?
K.
What
Are
the
Phase
II
Compliance
Dates?
1.
How
Are
We
Handling
Non­
Acid
Rain
EGUs
and
Any
Cogeneration
Units
That
Were
Previously
Classified
as
EGUs,
and
Whose
Classification
Changed
to
Non­
EGUs
Under
Today's
Rule?
2.
What
Complinace
Date
Are
We
Finalizing
for
IC
Engines
and
What
is
the
Technical
Feasibility
of
This
Date?
3.
What
Compliance
Date
Are
We
Finalizing
for
Georgia
and
Missouri?
L.
What
Action
Are
We
Taking
on
Wisconsin?
M.
How
Are
the
8­
Hour
NAAQS
Rules
Affected
by
This
Action?
N.
What
Modifications
Are
Being
Made
to
Parts
78
and
97?

III.
Statutory
and
Executive
Order
Reviews
O.
Executive
Order
12866:
Regulatory
Planning
and
Review
B.
Paperwork
Reduction
Act
C.
Regulatory
Flexibility
Act
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
and
Safety
Risks
H.
Executive
Order
13211:
Actions
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
I.
National
Technology
Transfer
Advancement
Act
J.
Executive
Order
12898:
Federal
Actions
to
Address
Environmental
Justice
in
Minority
Populations
and
Low­
Income
Populations
K.
Congressional
Review
Act
I.
BACKGROUND
A.
What
Was
Contained
in
the
NOx
SIP
Call?

By
notice
dated
October
27,
1998
(
63
FR
57356),
we
took
final
action
to
prohibit
specified
amounts
of
emissions
Draft
 
Do
not
cite,
quote
or
distribute
9
of
one
of
the
main
precursors
of
ground­
level
ozone,
NOx,
in
order
to
reduce
ozone
transport
across
State
boundaries
in
the
eastern
half
of
the
United
States.
Based
on
extensive
air
quality
modeling
and
analyses,
we
found
that
sources
in
22
States
and
the
District
of
Columbia
(
D.
C.)
(
23
States)

emit
NOx
in
amounts
that
significantly
contribute
to
nonattainment
of
the
1­
hour
ozone
national
ambient
air
quality
standards
(
NAAQS)
in
downwind
States.
We
set
forth
requirements
for
each
of
the
affected
upwind
States
to
submit
SIP
revisions
prohibiting
those
amounts
of
NOx
emissions
which
significantly
contribute
to
downwind
air
quality
problems.
We
established
statewide
NOx
emissions
budgets
for
the
affected
States.
The
budgets
were
calculated
by
assuming
the
emissions
reductions
that
would
be
achieved
by
applying
available,
highly
cost­
effective
controls
to
source
categories
of
NOx.
States
have
the
flexibility
to
adopt
the
appropriate
mix
of
controls
for
their
State
to
meet
the
NOx
emissions
reductions
requirements
of
the
NOx
SIP
Call.
A
number
of
parties,

including
certain
States
as
well
as
industry
and
labor
groups,
challenged
our
NOx
SIP
Call
Rule.

Independently,
we
also
found
that
sources
and
emitting
activities
in
22
States
and
the
District
of
Columbia
emit
NOx
in
amounts
that
significantly
contribute
to
Draft
 
Do
not
cite,
quote
or
distribute
10
nonattainment
of
the
8­
hour
ozone
NAAQS.
In
response
to
the
court
decisions,
on
September
18,
2000
(
65
FR
56245),
we
stayed
the
findings
in
the
NOx
SIP
Call
based
on
the
8­
hour
NAAQS.
However,
we
are
evaluating
the
process
for
lifting
the
stay
in
light
of
recent
EPA
actions
on
the
8­
hour
ozone
standard.

B.
What
Were
the
Court
Decisions
on
the
NOx
SIP
Call?

1.
What
Was
the
Decision
of
the
Court
on
the
8­
Hour
NAAQS?

On
May
14,
1999,
the
D.
C.
Circuit
issued
an
opinion
which,
in
relevant
parts,
questioned
the
constitutionality
of
the
CAA
as
applied
by
EPA
in
its
1997
revision
of
the
ozone
NAAQS.
See
American
Trucking
Ass'n
v.
EPA,
175
F.
3d
1027
(
D.
C.
Cir.,
1999).
The
Court's
ruling
curtailed
our
ability
to
require
States
to
comply
with
a
more
stringent
ozone
NAAQS.

On
October
29,
1999,
the
D.
C.
Circuit
granted
in
part
and
denied
in
part
our
rehearing
request.
American
Trucking
Ass'n
v.
EPA,
194
F.
3d
4
(
D.
C.
Cir.
1999).
In
May
2000,
the
Supreme
Court
granted
our
petition
and
certain
petitioners'

cross­
petitions
of
certiorari.
On
February
27,
2001,
the
Supreme
Court
handed
down
its
decision
in
Whitman
v.

American
Trucking
Association,
531
U.
S.
457
(
2001).
In
vacating
the
D.
C.
Circuit's
holding
on
the
point,
the
Supreme
Court
held
that
the
CAA
was
not
unconstitutional
in
Draft
 
Do
not
cite,
quote
or
distribute
11
its
delegation
of
authority
for
us
to
promulgate
a
revised
ozone
NAAQS.
The
case
was
remanded
to
the
D.
C.
Circuit
to
consider
challenges
to
the
revised
ozone
NAAQS
on
other
grounds.

2.
What
Effect
Did
the
Court
Decision
Have
on
the
8­
hour
Portion
of
the
NOx
SIP
Call?

The
litigation
created
uncertainty
with
respect
to
our
ability
to
rely
upon
the
8­
hour
ozone
standards
as
an
alternative
basis
for
the
NOx
SIP
Call.
As
a
result,
we
stayed
indefinitely
the
findings
of
significant
contribution
based
on
the
8­
hour
standard,
pending
further
developments
in
the
NAAQS
litigation
(
65
FR
56245,
September
18,
2000).

Because
the
NOx
SIP
Call
Rule
was
based
independently
on
the
1­
hour
standards,
a
stay
of
the
findings
based
on
the
8­
hour
standards
had
no
effect
on
the
remedy
required
by
the
1998
NOx
SIP
Call.
That
is,
the
stay
does
not
affect
our
findings
based
on
the
1­
hour
standards.

3.
What
Was
the
D.
C.
Circuit
Decision
on
the
Stay
of
the
SIP
Submittal
Schedule
for
the
NOx
SIP
Call?

The
NOx
SIP
Call
Rule
required
States
to
submit
SIP
revisions
by
September
30,
1999.
State
petitioners
challenging
the
NOx
SIP
Call
filed
a
motion
requesting
the
Court
to
stay
the
submission
schedule
until
April
27,
2000.

In
response,
the
D.
C.
Circuit
issued
a
stay
of
the
SIP
Draft
 
Do
not
cite,
quote
or
distribute
12
submission
deadline
pending
further
order
of
the
Court.

Michigan
v.
EPA,
213
F.
3d
663
(
D.
C.
Cir.
2000)
(
May
25,
1999
order
granting
stay
in
part).

4.
What
Was
the
Court's
Decision
on
the
NOx
SIP
Call?

On
March
3,
2000,
the
D.
C.
Circuit
issued
its
decision
on
the
NOx
SIP
Call,
ruling
in
our
favor
on
the
issues
that
affected
the
rulemaking
as
a
whole,
but
ruling
against
us
on
several
issues.
Michigan
v.
EPA,
213
F.
3d
663
(
D.
C.
Cir.

2000).
The
Court's
decision
in
Michigan
v.
EPA,
213
F.
3d
663
(
D.
C.
Cir.
2000)
concerns
only
the
1­
hour
basis
for
the
NOx
SIP
Call,
and
not
the
8­
hour
basis.
The
requirements
of
the
NOx
SIP
Call,
including
the
findings
of
significant
contribution
by
the
23
States,
the
emissions
reductions
that
must
be
achieved,
and
the
requirement
for
States
to
submit
SIPs
meeting
statewide
NOx
emissions
reductions
requirements,
are
fully
and
independently
supported
by
our
findings
under
the
1­
hour
NAAQS
alone.
The
Court
denied
petitioners'
requests
for
rehearing
or
rehearing
en
banc
on
July
22,
2000.
Specifically,
the
Court
found
in
our
favor
on
the
following
claims:

(
1)
we
could
call
for
the
SIP
revisions
without
convening
a
transport
commission;

(
2)
we
undertook
a
sufficiently
State­
specific
determination
of
ozone
contribution;
Draft
 
Do
not
cite,
quote
or
distribute
13
(
3)
we
did
not
unlawfully
override
past
precedent
regarding
"
significant"
contribution;

(
4)
our
consideration
of
the
cost
of
NOx
emissions
reductions
as
part
of
the
determination
of
significant
contribution
is
consistent
with
the
statute
and
judicial
precedent;

(
5)
our
scheme
of
uniform
emissions
reductions
requirements
is
reasonable;

(
6)
our
interpretation
of
CAA
section
110(
a)(
2)(
D)(
i)(
I)
does
not
violate
the
nondelegation
doctrine;

(
7)
we
did
not
intrude
on
the
statutory
rights
of
States
to
fashion
their
SIPs;

(
8)
we
properly
included
South
Carolina
in
the
NOx
SIP
Call;
and
(
9)
we
did
not
violate
the
Regulatory
Flexibility
Act
(
RFA).

However,
the
Court
ruled
against
us
on
four
specific
issues.
Specifically,
the
Court:

(
1)
remanded
and
vacated
the
inclusion
of
Wisconsin
because
emissions
from
Wisconsin
did
not
show
a
significant
contribution
to
downwind
nonattainment
of
the
NAAQS;

(
2)
remanded
and
vacated
the
inclusion
of
Georgia
and
Draft
 
Do
not
cite,
quote
or
distribute
14
Missouri
in
light
of
the
Ozone
Transport
Assessment
Group
(
OTAG)
conclusions
that
emissions
from
coarse
grid
portions
did
not
merit
controls;

(
3)
held
that
we
failed
to
provide
adequate
notice
of
the
change
in
the
definition
of
EGU
as
applied
to
cogeneration
units
that
supply
electricity
to
a
utility
power
distribution
system
for
sale
in
amounts
of
either
one­
third
or
less
of
their
potential
electrical
output
capacity
or
25
megawatts
or
less
per
year
(
small
cogeneration
units);
and
(
4)
held
that
we
failed
to
provide
adequate
notice
of
the
change
in
control
level
assumed
for
large
stationary
IC
engines.

The
Court
remanded
the
last
two
matters
for
further
rulemaking.

5.
How
Did
the
Court
Respond
to
Our
Request
to
Lift
the
Stay
of
the
1­
Hour
SIP
Submission
Schedule?

On
April
11,
2000,
we
filed
a
motion
with
the
Court
to
lift
the
stay
of
the
SIP
submission
date.
We
requested
that
the
Court
lift
the
stay
as
of
April
27,
2000.
We
recognized,
however,
that
at
the
time
the
stay
was
issued,

States
had
approximately
4
months
(
128
days)
remaining
to
submit
SIPs.
Therefore,
our
motion
to
lift
the
stay
Draft
 
Do
not
cite,
quote
or
distribute
1
October
30,
2000
was
the
first
business
day
following
the
expiration
of
the
128­
day
period.

15
indicated
that
we
would
allow
States
until
September
1,
2000
to
submit
SIPs
addressing
the
NOx
SIP
Call
and
provided
that
States
could
submit
only
those
portions
of
the
NOx
SIP
Call
upheld
by
the
Court
(
Phase
I
SIPs).
The
existing
record
in
the
NOx
SIP
Call
rulemaking
provides
a
breakdown
of
the
data
on
which
the
original
budgets
were
developed
sufficient
to
allow
States
to
develop
Phase
I
SIPs.
However,
we
reviewed
the
record
and
for
the
convenience
of
the
States
and
in
letters
to
the
State
Governors
and
State
Air
Directors,

dated
April
11,
2000,
we
identified
an
adjusted
Phase
I
NOx
budget
for
each
State
for
which
the
NOx
SIP
Call
applies.

On
June
22,
2000,
the
Court
granted
our
request
in
part.
The
Court
ordered
that
we
allow
the
States
128
days
from
the
June
22,
2000
date
of
the
order
to
submit
their
SIPs.
Therefore,
SIPs
in
response
to
the
NOx
SIP
Call
were
due
October
30,
2000.1
In
our
motion
to
lift
the
stay,
we
informed
the
Court
that
the
Agency
asked
19
States
and
the
District
of
Columbia,
in
letters
to
the
Governors
dated
April
11,
2000,

to
submit
SIPs
subject
to
the
Court's
response
to
our
motion
to
lift
the
stay.
The
19
States
are:
Alabama,
Connecticut,

Delaware,
Illinois,
Indiana,
Kentucky,
Massachusetts,
Draft
 
Do
not
cite,
quote
or
distribute
2
The
Phase
I
emissions
reductions
should
achieve
approximately
90
percent
of
the
total
emissions
reductions
called
for
by
the
NOx
SIP
Call.

16
Maryland,
Michigan,
North
Carolina,
New
Jersey,
New
York,

Ohio,
Pennsylvania,
Rhode
Island,
South
Carolina,
Tennessee,

Virginia
and
West
Virginia.
Rather
than
submit
a
SIP
that
fully
met
the
NOx
SIP
Call,
we
allowed
these
19
States
and
the
District
of
Columbia
to
submit
SIPs
that
cover
all
of
the
NOx
SIP
Call
requirements
except
for
a
small
part
of
the
EGU
portion
and
large
IC
engine
portions
of
the
budget.
We
refer
to
these
partial
plans
that
addressed
the
portion
of
the
rule
unaffected
by
the
Court's
remand
as
the
"
Phase
I"

SIPs.
2
Because
the
NOx
SIP
Call
was
vacated
with
respect
to
Georgia,
Missouri,
and
Wisconsin,
those
States
were
not
obligated
to
submit
any
SIPs
by
October
30,
2000.
The
SIPs
that
cover
the
portion
of
the
rule
affected
by
the
Court
decision
 
and
the
subject
of
today's
action
 
are
termed,

the
"
Phase
II"
SIPs.

6.
What
Was
the
Court's
Order
for
the
Compliance
Date?

In
response
to
a
motion
filed
by
the
industry/
labor
petitioners,
on
August
30,
2000,
the
D.
C.
Circuit
ordered
that
the
court
order
filed
on
June
22,
2000
be
amended
to
extend
the
deadline
for
full
implementation
of
the
NOx
SIP
Call
from
May
1,
2003
to
May
31,
2004.
This
extension
was
Draft
 
Do
not
cite,
quote
or
distribute
3
For
Indiana,
Kentucky,
Michigan,
and
New
York,
only
sources
in
portions
of
the
State
are
affected
by
that
rule.

4
The
Section
126
Rule
uses
the
same
definition
of
EGUs
that
we
are
finalizing
for
the
NOx
SIP
Call
in
today's
action.

17
calculated
in
the
same
manner
used
by
the
Court
in
extending
the
deadline
for
SIP
submissions,
so
that
sources
in
States
subject
to
the
NOx
SIP
Call
would
have
1,309
days
for
implementing
the
SIP
as
provided
in
the
original
NOx
SIP
Call.

C.
What
Was
Contained
in
the
Section
126
Rule?

We
have
also
addressed
interstate
NOx
transport
in
a
final
rule
(
Section
126
Rule)
that
responds
to
petitions
submitted
by
eight
Northeast
States
under
section
126
of
the
CAA
(
65
FR
2674,
January
18,
2000)(
the
Section
126
Rule).

In
this
rule,
we
made
findings
that
392
sources
in
12
States
and
the
District
of
Columbia
are
significantly
contributing
to
1­
hour
ozone
nonattainment
problems
in
the
petitioning
States
of
Connecticut,
Massachusetts,
New
York,
and
Pennsylvania.
The
upwind
States
with
sources
affected
by
the
Section
126
Rule
are:
Delaware,
Indiana,
Kentucky,

Maryland,
Michigan,
North
Carolina,
New
Jersey,
New
York,

Ohio,
Pennsylvania,
Virginia,
West
Virginia,
and
the
District
of
Columbia.
3
The
types
of
sources
affected
are
large
EGUs4
and
large
industrial
boilers
and
turbines
(
non­
Draft
 
Do
not
cite,
quote
or
distribute
5
As
discussed
in
the
next
section,
on
August
24,
2001,
the
D.
C.
Circuit
suspended
the
compliance
date
for
EGUs
while
we
resolved
a
remanded
issue
related
to
EGU
growth
factors.
We
published
our
response
to
the
growth
factor
issue
on
May
1,
2002
(
67
FR
21868).

18
EGUs).
The
rule
established
Federal
NOx
emissions
limits
for
the
affected
sources
and
set
a
May
1,
2003
compliance
date.
5
We
promulgated
a
NOx
cap­
and­
trade
program
as
the
control
remedy.
All
of
the
sources
affected
by
this
Section
126
Rule
are
located
in
States
that
are
subject
to
the
NOx
SIP
Call.

The
Section
126
Rule
includes
a
provision
to
coordinate
the
Section
126
Rule
with
State
actions
under
the
NOx
SIP
Call.
This
provision
automatically
withdraws
the
Section
126
findings
and
control
requirements
for
sources
in
a
State
if
the
State
submits,
and
we
give
final
approval
to,
a
SIP
revision
meeting
the
full
NOx
SIP
Call
requirements,

including
the
originally
promulgated
May
1,
2003
compliance
deadline
[
40
CFR
52.34(
i)].
The
Court
changed
the
NOx
SIP
Call
compliance
deadline
to
May
31,
2004
after
we
had
promulgated
and
justified
the
automatic
withdrawal
provision
based
on
approval
of
a
SIP
with
a
May
1,
2003
compliance
date
(
64
FR
28274­
76,
May
25,
1999;
65
FR
2679­
2684,
January
18,
2000).
As
described
below,
as
the
result
of
a
court
decision,
the
Section
126
Rule
was
delayed.
On
April
30,
Draft
 
Do
not
cite,
quote
or
distribute
19
2002,
we
published,
"
Section
126
Rule:
Revised
Deadlines;

Final
Rule,"
(
67
FR
21522)
which
reset
the
compliance
date
and
other
related
dates,
such
as
the
monitoring
certification
date.
The
new
compliance
date
is
May
31,

2004.
This
action
harmonized
the
dates
in
the
Section
126
Rule
with
those
in
the
NOx
SIP
Call.

On
April
30,
2002,
we
published
a
proposal
to
revise
the
Section
126
Rule
withdrawal
provision
so
that
it
would
continue
to
function
based
on
the
new
compliance
dates
and
on
a
Phase
I
SIP
(
67
FR
21522).

1.
What
Was
the
D.
C.
Circuit
Decision
on
the
Section
126
Rule?

On
May
15,
2001,
a
panel
of
the
D.
C.
Circuit
largely
upheld
the
Section
126
Rule
in
Appalachian
Power
v.
EPA,
249
F.
3d
1032
(
2001).
(
Appalachian
Power
 
Section
126).

However,
the
Court
remanded
the
method
for
determining
growth
to
the
year
2007
in
heat
input
utilization
by
EGUs.

This
calculation
is
important
for
determining
the
requirements
for
EGUs.
In
addition,
the
Court
vacated
and
remanded
to
us
the
portion
of
the
rule
classifying
as
EGUs
small
cogeneration
units.
Although
in
the
Michigan
decision
(
concerning
the
NOx
SIP
Call
rulemaking),
the
D.
C.
Circuit
remanded
this
issue
on
the
procedural
ground
of
inadequate
Draft
 
Do
not
cite,
quote
or
distribute
20
notice,
in
the
Appalachian
Power
 
Section
126
decision,
the
Court
vacated
and
remanded
on
grounds
that
we
did
not
justify
our
classification
of
small
cogeneration
units
as
EGUs.
In
an
order
dated
August
24,
2001,
the
D.
C.
Circuit,

in
Appalachian
Power
 
Section
126
Case,
remanded
the
Section
126
Rule
with
regard
to
the
classification
of
any
cogeneration
units
as
EGUs
and
tolled
(
suspended)
the
date
for
EGUs
to
implement
controls
pending
our
resolution
of
the
EGU
growth
factor
remand.

During
the
course
of
the
litigation
on
the
Section
126
Rule,
individual
sources
or
groups
of
sources
challenged
the
rule
on
grounds
that
our
allocations
of
allowances
were
improper.
We
resolved
these
cases
with
several
of
those
sources
with
our
agreement
to
propose
a
rulemaking
revising
the
allocations.

D.
What
Were
the
Technical
Amendments
Rulemakings?

When
we
promulgated
the
NOx
SIP
Call
Rule,
we
decided
to
reopen
public
comment
on
the
source­
specific
data
used
to
establish
each
State's
2007
EGU
budget
(
63
FR
57427,
October
28,
1998).
We
extended
this
comment
period
by
notice
dated
December
24,
1998
(
63
FR
71220).
We
indicated
that
we
would
entertain
requests
to
correct
the
2007
EGU
budgets
to
take
into
account
errors
or
updates
in
some
of
the
underlying
Draft
 
Do
not
cite,
quote
or
distribute
21
emissions
inventory
and
certain
other
specified
data.

Following
our
review
of
the
comments
received,
we
published
a
rulemaking
providing
Technical
Amendments
to,

among
other
things,
the
2007
EGU
budgets
(
64
FR
26298,
May
14,
1999).
In
response
to
additional
comments
received,
we
published
a
second
rulemaking,
making
additional
Technical
Amendments
to
the
2007
EGU
budgets
(
65
FR
11222,
March
2,

2000).
(
These
two
rulemakings
may
be
referred
to,
together,

as
the
Technical
Amendments
Rule.)
In
promulgating
the
Technical
Amendments
Rule,
we
kept
intact
our
method
for
determining
the
budgets,
including
the
methods
for
determining
growth
to
2007.
We
simply
made
adjustments
for
particular
sources
concerning
whether
they
were
large
EGUs
or
non­
EGUs,
and
adjustments
in
the
appropriate
baselines
for
those
sources.

1.
What
Was
the
D.
C.
Circuit
Decision
on
the
Technical
Amendments?

On
June
8,
2001,
the
D.
C.
Circuit
issued
its
opinion
in
a
case
involving
the
Technical
Amendments.
Appalachian
Power
v.
EPA,
251
F.
3d
1026
(
D.
C.
Cir.
2001).
(
Appalachian
Power
 
Technical
Amendments).
Although
largely
upholding
the
Technical
Amendments,
the
court,
as
in
the
Appalachian
Power
 
Section
126
case,
remanded
the
EGU
growth
factors
and
Draft
 
Do
not
cite,
quote
or
distribute
22
vacated
and
remanded
the
portion
of
the
rule
classifying
small
cogeneration
units
as
EGUs.
In
addition,
in
the
Appalachian
Power­
Technical
Amendments
decision,
the
Court
remanded
and
vacated
the
budget
under
the
Technical
Amendments
Rule
for
Missouri
under
both
the
1­
hour
and
8­

hour
ozone
NAAQS.

E.
What
is
the
Overview
of
D.
C.
Circuit
Remands/
Vacaturs?

In
summary,
the
D.
C.
Circuit
decisions
described
above
revised
or
remanded/
vacated
portions
of
the
NOx
SIP
Call,

Section
126,
and
Technical
Amendments
rulemakings
as
follows:

(
1)
remanded
the
portion
of
the
NOx
SIP
Call
requirements
based
on
the
assumed
control
level
for
stationary
IC
engines;

(
2)
delayed
the
NOx
SIP
Call
SIP
submittal
date
to
October
30,
2000.
Michigan;

(
3)
delayed
the
date
for
implementation
of
the
NOx
SIP
Call
reductions
to
May
31,
2004.
Michigan;

(
4)
remanded
and
vacated
the
inclusion
of
Wisconsin.

Michigan;

(
5)
remanded
and
vacated
the
NOx
SIP
Call
budgets
for
Georgia
and
Missouri
under
the
1­
hour
ozone
NAAQS.
Draft
 
Do
not
cite,
quote
or
distribute
23
Michigan;

(
6)
remanded
and
vacated
the
NOx
SIP
Call
budget,
as
revised
by
the
Technical
Amendments,
for
Missouri,

under
the
1­
hour
and
8­
hour
ozone
NAAQS.
Appalachian
Power
 
Technical
Amendments;

(
7)
remanded
the
EGU
growth
formula.
Appalachian
Power
 
Section
126,
Appalachian
Power
 
Technical
Amendments;

(
8)
remanded,
or
remanded
and
vacated,
the
classification
of
small
cogeneration
units
as
EGUS.
Michigan,

Appalachian
Power­
Section
126,
Appalachian
Power
 
Technical
Amendments;
and
(
9)
remanded
the
classification
of
any
cogeneration
units
as
EGUs.
Appalachian
Power­
Section
126.

F.
What
is
Our
Process
for
Addressing
the
Remands/

Vacaturs?

To
date,
we
have
responded
to
these
decisions
as
follows:

In
letters
dated
April
11,
2000,
to
the
Governors
of
the
affected
States,
we
advised
that
the
States
may
submit
by
October
30,
2000
Phase
I
SIPs
that
include
a
budget
allowing
more
emissions
than
under
the
NOx
SIP
Call
Rule.

This
budget
need
not
include
any
reductions
from
a
set
of
Draft
 
Do
not
cite,
quote
or
distribute
6
All
required
States
have
submitted
final
SIPs.
We
have
published
final
approval
for
15
States
and
the
District
of
Columbia.
We
have
published
final
conditional
approvals
for
two
States.

24
EGUs
that
we
believe
includes
all
of
the
small
cogeneration
units
or
reductions
from
stationary
IC
engines.
In
addition,
we
advised
Wisconsin
that
it
need
not
submit
a
NOx
SIP
Call
SIP
revision.
Further,
we
advised
Georgia
and
Missouri
that
they
did
not
have
to
submit
NOx
SIP
Call
SIPs
at
this
time.
We
advised
Alabama
and
Michigan
that
although
the
Court
upheld
the
NOx
SIP
Call
for
their
entire
States,

the
reasoning
of
the
Court's
opinion
concerning
Georgia
and
Missouri
supported
excluding
emissions
from
the
coarse­
grid
portion
of
their
States.
We
also
stated
that
if
they
wanted
the
coarse­
grid
portion
of
their
States
excluded,
they
could
submit
a
Phase
I
budget
addressing
sources
in
only
the
finegrid
portion
of
the
State.
All
States
were
further
advised
that
the
remanded
issues
would
be
addressed
in
a
future
rulemaking.

Many
States
did
not
officially
submit
complete
SIPs
as
required
by
October
30,
2000.
By
notice
dated
December
26,

2000
(
65
FR
81366),
we
issued
findings
of
failure
to
submit.
6
All
required
States
have
now
submitted
complete
Phase
I
SIPs
and
the
sanctions
clocks
have
effectively
been
Draft
 
Do
not
cite,
quote
or
distribute
25
turned
off.

On
February
22,
2002,
we
proposed
our
response
to
the
court
decisions
described
above,
except
for
the
EGU
growth
remand.
Today's
action
finalizes
the
second
phase
or
Phase
II
of
the
NOx
SIP
Call
by
addressing
the
remanded
and
vacated
issues
as
described
above.
In
addition,
we
are
modifying
the
budgets
for
Alabama
and
Michigan
based
on
inclusion
of
only
the
fine
grid
portion
of
those
States.

Further,
we
are
excluding
Wisconsin
from
the
NOx
SIP
Call.

Any
additional
emissions
reductions
required
as
a
result
of
this
rulemaking
are
reflected
in
the
Phase
II
portion
of
the
State's
emissions
budget.
The
emissions
reductions
required
in
Phase
II
are
relatively
small,

representing
less
than
10
percent
of
total
reductions
required
by
the
SIP
Call.
Partial
State
budgets
for
Georgia
and
Missouri
and
the
due
date
for
the
SIPs
meeting
the
resulting
State
emissions
budgets
("
Phase
II"
SIPs)
are
discussed
below
in
sections
II.
E
and
II.
J,
respectively.

Today's
rulemaking
does
not
address
the
EGU
growth
remand.
We
responded
to
that
issue
in
an
action
entitled,

"
Response
to
Court
Remand
on
NOx
SIP
Call
and
Section
126
Rule,"
which
was
published
in
the
Federal
Register
on
May
1,

2002
(
67
FR
21868).
Our
response
to
the
growth
remand
was
Draft
 
Do
not
cite,
quote
or
distribute
26
challenged
in
the
D.
C.
Circuit.
All
parties
filed
briefs
in
May
2003
and
oral
argument
is
scheduled
for
September
15,

2003.
The
Agency
expects
a
decision
by
the
Court
in
the
January
to
March
2004
timeframe.

Today's
rulemaking
does
not
address
NOx
SIP
Call
or
Section
126
Rule
issues
related
to
the
8­
hour
NAAQS.
While
we
had
stayed
the
findings
in
the
NOx
SIP
Call
based
on
the
8­
hour
NAAQS
(
65
FR
56245,
September
18,
2000),
we
are
evaluating
lifting
the
stay
in
light
of
our
recent
findings
on
the
8­
hour
ozone
standard
itself
to
address
a
prior
remand
of
the
standard
by
the
D.
C.
Circuit
concerning
the
potential
for
beneficial
effects
of
ozone
related
to
its
effect
on
ultraviolet
radiation
exposure.
In
the
meantime,

on
June
2,
2003
we
published
a
proposed
rulemaking
for
implementation
of
the
8­
hour
NAAQS
(
68
FR
32801).

II.
WHAT
IS
THE
SCOPE
OF
THIS
ACTION?

In
this
action,
we
are
finalizing
specific
changes
in
response
to
the
Court's
rulings
on
the
NOx
SIP
Call,
Section
126,
and
Technical
Amendments
rulemakings.
Specifically,
we
are
finalizing
the
following:

(
1)
Certain
aspects
of
the
definitions
of
EGU
and
non­
EGU.

We
are
addressing
the
definition
of
EGU
as
applied
to
cogeneration
units
by
finalizing
an
EGU
definition
that
excludes
certain
small
cogeneration
units
for
purposes
Draft
 
Do
not
cite,
quote
or
distribute
27
of
the
NOx
SIP
Call
and
Section
126
rulemakings.
We
are
also
finalizing
a
non­
EGU
definition
that
includes
such
cogeneration
units.
[
Note
that
a
cogeneration
unit
may
be
owned
by
a
utility
or
a
non­
utility
and
is
a
unit
that
uses
energy
sequentially
to
produce
both
useful
thermal
energy
(
heat
or
steam)
used
for
industrial,
commercial,
or
heating
or
cooling
purposes;

and
electricity.]

(
2)
The
control
level
assumed
for
large
stationary
IC
engines
in
the
NOx
SIP
Call.
We
proposed
a
range
of
possible
control
levels
(
82
percent
to
91
percent)
to
the
IC
engine
portion
of
the
budget.
We
are
setting
the
control
limit
for
large
natural
gas­
fired
stationary
IC
engines
in
the
NOx
SIP
Call
at
82
percent,
and
for
diesel
and
dual
fuel
stationary
IC
engines
at
90
percent.

(
3)
Partial
State
budgets
for
Georgia,
Missouri,
Alabama,

and
Michigan
in
the
NOx
SIP
Call.

(
4)
Changes
to
the
statewide
NOx
budgets
in
the
NOx
SIP
Call
to
reflect
the
appropriate
increments
of
emissions
reductions
that
States
should
be
required
to
achieve
with
respect
to
the
three
remanded
issues
(
discussed
above
in
numbers
1,
2,
3).

(
5)
The
SIP
submittal
dates
for
the
required
States
to
Draft
 
Do
not
cite,
quote
or
distribute
28
address
the
Phase
II
portion
of
the
budget,
and
for
Georgia
and
Missouri
to
submit
full
SIPs
meeting
the
NOx
SIP
Call.
We
proposed
a
range
of
dates
6
months
through
1
year
from
promulgation
of
this
rule,
but
no
later
than
April
1,
2003.
Based
on
comments
and
the
delay
in
finalizing
this
rule,
we
are
setting
a
SIP
submittal
date
1
year
from
signature
of
this
rule.

(
6)
The
compliance
date
for
all
covered
sources
to
meet
Phase
II
of
the
NOx
SIP
Call.
We
proposed
a
compliance
date
of
May
31,
2004
(
or,
if
later,
the
date
on
which
the
source
commences
operation)
for
all
sources
except
those
in
Georgia
and
Missouri.
We
proposed
May
1,
2005
for
sources
in
those
States.
We
are
setting
the
compliance
date
as
May
1,
2007
(
or,
if
later,
the
date
on
which
the
source
commences
operation)
for
sources
States
choose
to
control
under
Phase
II,
including
IC
engines
and
sources
in
Georgia
and
Missouri.
Sources
already
controlled
in
an
approved
Phase
I
SIP
are
required
to
meet
the
compliance
date
stipulated
in
that
SIP,
including
non­
Acid
Rain
EGUs
and
any
cogeneration
units
that
were
previously
classified
as
EGUs
and,

whose
classification
changed
to
non­
EGUs
under
today's
rule.

(
7)
The
exclusion
of
Wisconsin
from
the
NOx
SIP
Call.
Draft
 
Do
not
cite,
quote
or
distribute
29
A.
How
Do
We
Treat
Cogeneration
Units
and
Non­
Acid
Rain
Units?

By
way
of
background,
in
light
of
the
Michigan
decision
concerning
the
NOx
SIP
Call,
we
adopted
the
view
that
the
States
should
proceed
with
developing
and
submitting
SIPs
(
termed
"
Phase
I"
SIPs)
reflecting
the
level
of
required
reductions
that
was
not
affected
by
the
Court's
ruling.

Accordingly,
we
determined
that
the
Phase
I
SIPs,
under
the
Court's
ruling,
by
October
30,
2000,
should
reflect
all
reductions
required
under
the
NOx
SIP
Call,
except
those
reductions
attributable
to
parts
of
the
rule
that
the
Court
remanded
or
vacated,
such
as
reductions
by
small
cogeneration
units.

At
the
time,
we
were
uncertain
as
to
which
specific
units
were
small
cogeneration
units
and
what
total
emissions
were
attributable
to
small
cogeneration
units.
Even
so,
we
were
aware
that,
although
most
of
the
EGUs
that
were
subject
to
the
NOx
SIP
Call
were
also
subject
to
the
Acid
Rain
Program,
none
of
the
small
cogeneration
units
were
subject
to
the
Acid
Rain
Program.
Accordingly,
we
erred
on
the
side
of
caution
by
authorizing
States,
in
their
Phase
I
SIPs,
to
exclude
the
required
reductions
from
all
non­
Acid
Rain
units.

In
the
February
22,
2002
proposal,
as
applied
to
small
Draft
 
Do
not
cite,
quote
or
distribute
7
This
is
based
on
both
a
review
of
the
applicability
provisions
in
the
NOx
SIP
Call
SIPs
and
the
budget
demonstrations
for
those
SIPs.
For
more
detailed
discussion,
see
section
K.
1
of
today's
preamble.

30
cogeneration
units,
we
proposed
to
retain
the
EGU
definition
in
the
Section
126
Rule
and
to
retain
the
basic
EGU
definition
used
in
the
NOx
SIP
Call
Rule
with
minor,

technical
revisions
to
make
it
consistent
with
the
definition
in
the
Section
126
Rule.
In
today's
action,
we
are
finalizing
an
EGU
definition
that
excludes
certain
small
cogeneration
units.
All
other
cogeneration
units
and
other
non­
Acid
Rain
units
are
EGUs
if
the
other
criteria
in
the
EGU
definition
are
met.
Further,
we
are
finalizing
a
non­

EGU
definition
that
includes
certain
small
cogeneration
units.
As
a
result,
we
are
setting
Phase
II
budgets
that
include
reductions
from
small
cogeneration
units
and
non­

Acid
Rain
EGUs.

However,
our
review
of
the
SIPs
submitted
in
response
to
the
NOx
SIP
Call
indicates
that
the
States
already
included
the
non­
Acid
Rain
units
in
their
Phase
I
SIPs
as
EGUs
or
non­
EGUs.
7
In
addition,
for
today's
final
rule,

with
the
possible
exception
of
one
source,
we
have
not
identified
any
specific
small
cogeneration
units
that
were
originally
treated
by
EPA,
and
by
States
in
their
Phase
I
SIPs,
as
EGUs
and
which
now
are
defined
as
non­
EGUs
because,
Draft
 
Do
not
cite,
quote
or
distribute
31
in
general,
commenters
did
not
provide
specific
information
identifying
any
such
units.
The
only
exception
involves
one
commenter
that
claimed
that
its
units
(
located
at
the
Tobaccoville
facility)
classified
as
EGUs
should
be
classified
as
non­
EGUs.
However,
the
commenter
did
not
provide
sufficient
information
(
e.
g.,
information
supporting
the
maximum
design
heat
input
asserted
by
the
commenter)
for
us
to
make
a
final
determination
regarding
the
proper
classification
of
the
units.
Therefore,
today's
change
does
not
result
in
any
change
to
the
originally
finalized
SIP
Call
budgets
(
which
included
reductions
from
both
Phase
I
and
Phase
II
units).

Nevertheless,
it
is
still
possible
that
some
cogeneration
units
that
we
classified
as
EGUs
are
small
cogeneration
units
that
should
actually
be
treated
as
non­

EGUs.
To
the
extent
any
such
units
are
subsequently
identified
to
EPA,
we
will
make
any
further
revisions
to
the
budgets
of
particular
States
during
the
SIP
approval
process.
Similarly,
we
will
consider,
during
the
SIP
approval
process,
the
proper
classification
of
the
four
units
at
the
Tobaccoville
facility
identified
by
the
commenter
discussed
above.
Because
we
anticipate
that
few,

if
any,
existing
units
treated
as
EGUs
qualify
as
small
cogeneration
units,
we
expect
few,
if
any,
such
revisions
to
Draft
 
Do
not
cite,
quote
or
distribute
32
the
budgets
will
be
necessary
and
that
any
such
revisions
that
are
necessary
will
be
relatively
small
and
will
not
affect
most
States.

We
are
also
finalizing
certain
technical
changes
to
the
EGU
definition
in
the
NOx
SIP
Call
to
make
it
consistent
with
aspects
of
the
definition
of
EGU
used
in
the
Section
126
Rule.
In
addition,
since
the
EGU
definition
establishes
the
dividing
line
between
the
EGU
and
non­
EGU
categories,

the
changes
to
the
EGU
definition
result
in
corresponding
changes
to
the
non­
EGU
definition
in
the
NOx
SIP
Call.
In
the
process
of
correcting
the
EGU
and
non­
EGU
definitions,

we
are
also
finalizing
some
minor
changes
to
the
terminology,
and
minor
corrections
of
awkward
or
inconsistent
wording
and
grammatical
errors
in
the
applicability
provisions.

To
begin,
we
provide
a
discussion
of
what
preceded
today's
final
decision
on
the
treatment
of
cogeneration
units.
Under
the
NOx
SIP
Call,
the
amount
of
a
State's
significant
contribution
to
nonattainment
in
another
State
included
the
amount
of
highly
cost­
effective
reductions
that
could
be
achieved
for
large
EGUs
(
i.
e.,
EGUs
serving
generators
with
nameplate
capacity
exceeding
25
MWe)
and
large
non­
EGUs
(
non­
EGUs
with
maximum
design
heat
input
capacity
exceeding
250
mmBtu/
hr)
in
the
State.
No
Draft
 
Do
not
cite,
quote
or
distribute
33
reductions
for
small
EGUs
or
small
non­
EGUs
were
included.

We
determined
that
reductions
by
large
EGUs
to
0.15
lb
NOx/
mmBtu
and
by
large
non­
EGUs
to
60
percent
of
uncontrolled
emissions
are
highly
cost
effective.
In
developing
the
States'
budgets,
we
applied
definitions
of
EGU
and
non­
EGU
and
determined
which
sources
were
large
EGUs
or
large
non­
EGUs.

In
its
Michigan
decision,
the
D.
C.
Circuit
upheld
this
approach,
but
determined
that
we
did
not
provide
sufficient
notice
and
opportunity
to
comment
for
one
aspect
of
our
definition
of
EGU
and
remanded
the
rule
to
us
for
further
consideration.
Specifically,
a
petitioner
claimed,
and
the
Court
agreed,
that
"
EPA
did
not
provide
sufficient
notice
and
opportunity
for
comment
on
[
the]
revision"
of
the
EGU
definition
to
remove
the
exclusion,
from
the
EGU
category,

of
cogeneration
units
that
supply
one­
third
or
less
of
their
potential
electrical
output
capacity,
or
25
megawatts
(
MWe)

or
less,
to
any
utility
power
distribution
system
for
sale.

Michigan
v.
EPA,
213
F.
3d
at
691­
92.
(
These
thresholds
are
herein
referred
to
as
the
"
one­
third
potential
electrical
output
capacity/
25
MWe
criteria;"
cogeneration
units
that
meet
such
criteria
are
herein
referred
to
as
"
small
cogeneration
units.")
According
to
the
Court,
"
two
months
after
the
promulgation
of
the
[
NOx
SIP
Call]
rule,
EPA
Draft
 
Do
not
cite,
quote
or
distribute
34
redefined
an
EGU
as
a
unit
that
serves
a
`
large'
generator
(
greater
than
25
MWe)
that
sells
electricity."
Id.

Application
of
the
exclusion
for
cogeneration
units
from
the
definition
of
EGU
would
result
in
treating
as
non­
EGUs
those
cogeneration
units
meeting
the
"
one­
third
potential
electrical
output
capacity/
25
MWe"
criteria
and
treating
as
EGUs
those
cogeneration
units
not
meeting
these
criteria.

See
Brief
of
Petitioner
Council
of
Industrial
Boiler
Owners
(
CIBO)
at
4
(
submitted
in
Michigan).

The
petitioner
argued
that,
under
the
NOx
SIP
Call,
we
should
apply
these
criteria
for
excluding
cogeneration
units
from
treatment
as
EGUs.
According
to
the
petitioner,
the
criteria
had
been
established
under
the
regulations
implementing
new
source
performance
standards
(
NSPS)
and
under
title
IV
of
the
CAA
and
the
regulations
implementing
the
Acid
Rain
Program
under
title
IV.
The
petitioner
also
stated
that
section
112
of
the
CAA
defines
"
electricity
steam
generating
unit"
to
exclude
cogeneration
units
meeting
the
same
thresholds.

The
Court
found
that,
in
failing
to
apply
the
"

onethird
potential
electrical
output
capacity/
25
MWe"
criteria
for
cogeneration
units,
EPA
"
was
departing
from
the
definition
of
EGUs
as
used
in
prior
regulatory
contexts"
and
"
was
not
explicit
about
the
departure
from
the
prior
Draft
 
Do
not
cite,
quote
or
distribute
35
practice
until
two
months
after
the
rule
was
promulgated."

Michigan,
213
F.
3d
at
692.
Further,
the
Court
found
that:

it
is
an
exaggeration
to
state
that
some
general
"
theme"
of
the
regulatory
consequences
of
deregulation
of
the
utility
industry
throughout
rulemaking
meant
that
EPA's
last­
minute
revision
of
the
definition
of
EGU
should
have
been
anticipated
by
industrial
boilers
as
a
"
logical
outgrowth"
of
EPA's
earlier
statements.

Id.
The
Court
therefore
remanded
the
rulemaking
to
us
for
further
consideration
of
this
issue.

In
its
decisions
on
the
Section
126
Rule
and
the
Technical
Amendments
Rulemakings,
the
D.
C.
Circuit,
after
considering
the
merits
of
the
issue,
vacated
and
remanded
our
classification
of
small
cogeneration
units
as
EGUs.

Appalachian
Power­
Section
126
and
Appalachian
Power­

Technical
Amendments.
The
Court
held
that
we
had
failed
to
justify
this
classification
and
to
base
it
on
adequate
record
support
comparing
the
NOx
reduction
costs
of
cogeneration
units
to
those
of
other
EGUs
or
demonstrating
that
there
is
no
relevant
physical
or
technological
difference
between
small
cogeneration
units
and
other
units
treated
as
EGUs.
The
Court
also
remanded
our
classification
of
any
cogeneration
units
as
EGUs.

In
response
to
the
Court's
decisions,
we
addressed
the
cogeneration
unit
issue
in
the
February
22,
2002
proposed
rule.
In
the
proposed
rule,
we
noted
that,
in
prior
Draft
 
Do
not
cite,
quote
or
distribute
36
regulatory
programs,
we
sought
to
distinguish
between
utilities
(
regulated
monopolies
in
the
business
of
producing
and
selling
electricity)
and
non­
utilities
(
e.
g.,

independent
power
producers
and
industrial
companies).
In
order
to
make
this
distinction,
we
applied
the
"
one
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria.

These
criteria
were
not
always
applied
only
to
cogeneration
units
and
did
not
uniformly
result
in
less
stringent
regulation
for
units
meeting
the
criteria.
In
the
proposed
rule,
we
stated
that,
with
the
development
of
competitive
markets
for
electricity
generation
and
sale,
we
believed
that
these
criteria
no
longer
distinguish
between
units
in
the
business
of
producing
and
selling
electricity
(
i.
e.,

EGUs)
and
non­
EGUs.
In
addition,
we
explained
that
there
are
no
relevant
differences
between
the
way
cogenerating
units
and
non­
cogenerating
units
are
built
and
operated
that
justify
continuing
to
use
these
criteria
or
that
affect
the
general
ability
of
cogenerating
units
to
control
NOx.

In
response
to
the
February
22,
2002
proposed
rule,

most
commenters
again
argued
that,
under
the
NOx
SIP
Call,

we
should
apply
the
"
one
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria
to
exclude
cogeneration
units
from
treatment
as
EGUs.
The
comments
included
arguments
that:
classification
of
small
cogeneration
units
Draft
 
Do
not
cite,
quote
or
distribute
37
reverses
EPA
precedent,
contradicts
Congressional
intent,

and
will
discourage
new
industrial
cogeneration;
and
it
is
technically
and
economically
more
difficult
to
control
NOx
emissions
from
non­
utility
units.
A
few
commenters
supported
treatment
of
small
cogeneration
units
as
EGUs.

Under
today's
final
rulemaking,
we
are
finalizing
an
EGU
definition
that
excludes
certain
small
cogeneration
units
and
a
corresponding
non­
EGU
definition
that
includes
these
units.
We
still
maintain
that,
with
the
development
of
competitive
markets
for
electricity
generation
and
sale,

the
"
one
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria
no
longer
distinguishes
between
units
in
the
business
of
producing
and
selling
electricity
(
i.
e.,
EGUs)

and
non­
EGUs.
We
also
continue
to
believe
that
there
are
no
relevant
differences
between
the
way
cogenerating
units
and
non­
cogenerating
units
are
built
and
operated
that
justify
continuing
to
use
these
criteria
or
that
affect
the
general
ability
of
cogenerating
units
to
control
NOx.
However,
at
this
time,
we
do
not
believe
we
have
adequate
record
information
comparing
the
NOx
reduction
costs
of
all
types
of
industrial
cogeneration
units
to
those
of
other
units
that
are
treated
as
EGUs.

Our
discussion
below
begins
with
some
background
on
the
historical
definition
of
utility
unit
and
the
definition
of
Draft
 
Do
not
cite,
quote
or
distribute
38
EGU
in
the
NOx
SIP
Call
and
the
Section
126
rulemaking.
We
then
discuss
today's
final
rule,
including
our
final
decision
on
the
treatment
of
cogeneration
units
and
the
specific
revisions
to
the
definition
of
EGU
and
corresponding
revisions
to
the
definition
of
non­
EGU.

1.
What
is
the
Historical
Definition
of
Utility
Unit?

As
discussed
in
the
February
22,
2002
proposed
rule
(
67
FR
8402­
3),
in
prior
regulatory
programs,
we
have
used
variations
of
the
"
one­
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria
to
distinguish
between
utilities
and
non­
utilities.
The
Agency
began
using
these
criteria
in
1978,
in
40
CFR
part
60,
subpart
Da.
Subpart
Da
established
NSPS
for
"
electric
utility
steam
generating
units"
capable
of
combusting
more
than
250
mmBtu/
hr
of
fossil
fuel.
"
Electric
utility
steam
generating
unit"
was
defined
as
a
unit
"
constructed
for
the
purpose
of
supplying
more
than
one­
third
of
its
potential
electric
output
capacity
and
more
than
25
MWe
electrical
output
to
any
utility
power
distribution
system
for
sale"
(
40
CFR
60.41a).

In
that
case,
the
criteria
were
not
used
to
exempt
units
entirely
from
NSPS.
Rather,
the
criteria
were
used
to
classify
units
capable
of
combusting
more
than
250
mmBtu/
hr
of
fossil
fuel
as
either
"
electric
utility
steam
generating
units"
subject
to
the
requirements
under
subpart
Da
or
to
Draft
 
Do
not
cite,
quote
or
distribute
39
classify
them
as
non­
utility
"
steam
generating
units"
that,

depending
on
the
date
of
construction,
continued
to
be
subject
to
the
requirements
for
"
Fossil­
Fuel­
Fired
Steam
Generators"
under
subpart
D
or
subsequently
became
subject
to
the
requirements
for
"
Industrial­
Commercial­
Institutional
Steam
Generating
Units"
under
subpart
Db.
See
40
CFR
60.41a
(
definitions
of
"
steam
generating
unit"
and
"
electric
utility
steam
generating
unit"),
§
60.40b(
a)
(
stating
that
subpart
Db
applies
to
"
steam
generating
units"
with
heat
input
capacity
of
more
than
100
mmBtu/
hr),
and
§
60.40b(
e)

(
stating
that
"
electric
steam
generating
units"
subject
to
subpart
Da
are
not
subject
to
subpart
Db).
Depending
on
the
specific
circumstances
(
e.
g.,
type
of
equipment
and
fuel)
of
the
unit
involved,
some
of
the
emission
limits
in
subpart
Db
may
be
the
same
as
or
more
stringent
than
those
in
subpart
D
or
Da.

We
explained
that
we
were
distinguishing,
in
subpart
Da,
between
"
electric
utility
steam
generating
units"
and
"
industrial
boilers"
because
"
there
are
significant
differences
between
the
economic
structure
of
utilities
and
the
industrial
sector"
(
44
FR
33580,
33589,
June
11,
1979).

The
"
one­
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria
were
used
as
a
proxy
for
utility
vs.

industrial/
commercial/
institutional
(
i.
e.,
non­
utility)
Draft
 
Do
not
cite,
quote
or
distribute
40
ownership
of
the
units;
utility­
owned
units
were
covered
by
subpart
Da,
while
non­
utility­
owned
units
were
covered
by
subpart
D
or
Db.

A
similar
type
of
distinction
between
utility
and
nonutility
units
(
using
the
"
one­
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria)
continued
under
the
CAA
Amendments
of
1990,
in
both
title
IV
and
section
112
of
title
I,
but
was
applied
only
to
cogeneration
units.
Title
IV
established
the
Acid
Rain
Program
whose
requirements
apply
to
"
utility
units."
Section
402(
17)(
C)
excludes
a
cogeneration
unit
from
the
definition
of
"
utility
unit"

unless
the
unit
"
is
constructed
for
the
purpose
of
supplying,
or
commences
construction
after
the
date
of
enactment
of
[
title
IV]
and
supplies,
more
than
one­
third
of
its
potential
electric
output
capacity
and
more
than
25
MWe
electrical
output
to
any
utility
power
distribution
system
for
sale."
42
U.
S.
C.
7651a(
17)(
C).
See
also
40
CFR
72.6(
b)(
4).
Section
112
of
the
CAA,
which
addresses
hazardous
air
pollutants,
excludes
from
the
definition
of
"
electric
utility
steam
generating
unit"
cogeneration
units
(
but
not
non­
cogeneration
units)
that
meet
the
"
one­
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria
[
42
U.
S.
C.
7412(
a)(
8)].
Under
section
112,
emission
limits
established
by
the
Administrator
for
the
pollutants
listed
Draft
 
Do
not
cite,
quote
or
distribute
41
in
section
112(
b)
apply
generally
to
stationary
sources
but
apply
to
"
electric
utility
steam
generating
units"
only
if
the
Administrator
makes
a
specific
finding.
The
Administrator
must
conduct
a
study
of
the
"
hazards
to
public
health
reasonably
anticipated
to
occur"
from
emissions
from
such
units
and
determine
if
regulation
of
"
electric
utility
steam
generating
units"
is
"
appropriate
and
necessary."
42
U.
S.
C.
7412(
n)(
1)(
A).
In
summary,
the
above­
described
provisions
vary
as
to
both:
(
1)
the
application
of
the
"

onethird
potential
electrical
output
capacity/
25
MWe
sales"

criteria,
which
apply
to
all
units
in
some
provisions
and
only
to
cogeneration
units
in
other
provisions;
and
(
2)
the
consequences
of
a
unit
meeting
the
criteria,
which
results
in
the
unit
being
subject
to
more
stringent
regulation
under
some
provisions
and
less
stringent
or
later
regulation
under
other
provisions.

2.
What
Was
the
NOx
SIP
Call
Definition
of
EGU?

In
the
NOx
SIP
Call
rulemaking,
we
continued
the
general
approach,
described
above,
of
distinguishing
between
units
in
the
electric
generation
business
(
here,
EGUs)
and
units
in
the
industrial
sector
(
here,
non­
EGUs).
However,

we
adopted
a
different
method
of
defining
which
units
are
in
the
electric
generation
business
by
changing
the
definition
of
EGU.
We
defined
EGU
by
applying
to
all
fossil
fuel­
fired
Draft
 
Do
not
cite,
quote
or
distribute
42
units
the
methodology
described
in
detail
below
and
did
not
apply
to
cogeneration
units
the
"
one­
third
potential
electrical
output/
25
MWe
sales"
criteria.
Under
the
methodology
applied
to
all
units,
after
determining
the
date
on
which
a
unit
commenced
operation
(
i.
e.,
commenced
combusting
fuel),
we
determined
whether
the
unit
should
be
classified
as
an
EGU
or
a
non­
EGU
by
applying
the
appropriate
criteria
depending
on
the
commencement
of
operation
date.
Then
we
classified
the
unit
as
a
large
or
small
EGU
or
a
large
or
small
non­
EGU.

Specifically,
we
noted
in
a
December
24,
1998
supplemental
action
that
the
NOx
SIP
Call
used
the
following
methodology
for
classifying
all
units
(
including
cogeneration
units)
in
the
States
subject
to
the
NOx
SIP
Call
as
EGUs
or
non­
EGUs
(
63
FR
71220,
71223).
We
applied
this
methodology
to
cogeneration
units
and
not
the
"

onethird
potential
electrical
output
capacity/
25MWe
sales"

criteria.
See
id.

(
a)(
i)
For
units
commencing
operation
before
January
1,
1996,
we
classified
as
an
EGU
any
unit
serving
a
generator
producing
any
electricity
for
sale
under
firm
contract
to
the
electric
grid.
In
the
December
24,

1998
supplemental
action,
we
did
not
define
the
term
"
electricity
for
sale
under
firm
contract
to
the
Draft
 
Do
not
cite,
quote
or
distribute
8
For
purposes
of
the
January
18,
2000
Section
126
final
rule,
we
defined
"
electricity
for
sale
under
firm
contract
to
the
electric
grid"
as
where
"
the
capacity
involved
is
intended
to
be
available
at
all
times
during
the
period
covered
by
the
guaranteed
commitment
to
deliver,
even
under
adverse
conditions"
(
65
FR
2694
and
2731).
In
the
February
22,
2002
proposed
rule,
we
proposed
to
adopt
the
definition
for
the
term
provided
in
the
January
18,
2000
Section
126
final
rule.
This
definition
was
based
on
language
from
the
Glossary
of
Electric
Utility
Terms,
Edison
Electric
Institute,
Publication
No.
70­
40
(
definition
of
"
firm"
power).
Generally,
capacity
"
under
firm
contract
to
the
electricity
grid"
is
included
on
Energy
Information
Administration
(
EIA)
form
860A
(
called
EIA
form
860
before
1998)
or
is
reported
as
capacity
projected
for
summer
or
winter
peak
periods
on
EIA
form
411
(
Item
2.1
or
2.2,
line
10).

43
electric
grid."
8
(
ii)
For
units
commencing
operation
before
January
1,

1996,
we
classified
as
a
non­
EGU
any
unit
not
serving
a
generator
producing
electricity
for
sale
under
firm
contract
to
the
grid.

(
iii)
For
units
commencing
operation
on
or
after
January
1,
1996,
we
classified
as
an
EGU
any
unit
serving
a
generator
producing
any
amount
of
electricity
for
sale,
except
as
provided
in
paragraph
(
a)(
iv)

below.

(
iv)
For
units
commencing
operation
on
or
after
January
1,
1996,
we
classified
as
non­
EGUs
the
following:
any
unit
not
serving
a
generator
producing
electricity
for
sale;
or
any
unit
serving
a
generator
Draft
 
Do
not
cite,
quote
or
distribute
9
For
purposes
of
the
January
18,
2000
Section
126
final
rule,
we
used
the
more
familiar
term
"
potential
electrical
output
capacity,"
rather
than
the
term
"
usable
energy."
We
defined
"
potential
electrical
output"
using
the
longstanding
definition
of
the
latter
term
as
"
33
percent
of
a
unit's
maximum
design
heat
input"
(
65
FR
2694
and
2731).
In
the
February
22,
2002
proposed
rule,
we
proposed
to
adopt
the
same
term
and
definition
used
in
the
January
18,
2000
Section
126
final
rule.
"
Potential
electrical
output
capacity"
is
used,
and
defined
in
this
way,
in
part
72
of
the
Acid
Rain
Program
regulations
(
40
CFR
72.2
and
40
CFR
part
72,
appendix
D)
and
in
the
new
source
performance
standards
(
40
CFR
60.41a).

10
In
the
part
96
model
rule
in
the
NOx
SIP
Call
(
63
FR
57356,
57514­
38,
October
27,
1998),
and
subsequently
for
purposes
of
the
January
18,
2000
Section
126
final
rule
(
65
FR
2729
and
2731),
we
adopted
the
long­
standing
definition
of
"
nameplate
capacity"
as
"
the
maximum
electrical
generating
output
(
in
MWe)
that
a
generator
can
sustain
over
44
with
a
nameplate
capacity
equal
to
or
less
than
25
MWe,

producing
electricity
for
sale,
and
with
the
potential
to
use
50
percent
or
less
of
the
usable
energy
of
the
unit.
In
the
December
24,
1998
supplemental
action,
we
did
not
define
the
term
"
usable
energy."
9
(
b)(
i)
For
a
unit
classified
as
an
EGU
under
paragraph
(
a)(
i)
or
(
a)(
iii)
above,
we
then
classified
it
as
a
small
or
large
EGU.
An
EGU
serving
a
generator
with
a
nameplate
capacity
greater
than
25
MWe
is
a
large
EGU.

An
EGU
serving
a
generator
with
a
nameplate
capacity
equal
to
or
less
than
25
MWe
is
a
small
EGU.
In
the
December
24,
1998
supplemental
action,
we
did
not
expressly
define
the
term
"
nameplate
capacity."
10
Draft
 
Do
not
cite,
quote
or
distribute
a
specified
period
of
time
when
not
restricted
by
seasonal
or
other
deratings
as
measured
in
accordance
with
the
United
States
Department
of
Energy
standards."
In
the
February
22,
2002
proposed
rule,
we
proposed
to
adopt
the
same
definition
used
in
the
January
18,
2000
Section
126
final
rule.
The
term
is
defined
in
this
way
in
part
72
of
the
Acid
Rain
Program
regulations
(
40
CFR
72.2).

11
In
the
part
96
model
rule
in
the
NOx
SIP
Call
(
63
FR
57516)
and
subsequently
for
purposes
of
the
January
18,
2000
Section
126
final
rule
(
65
FR
2729),
we
defined
"
maximum
design
heat
input"
as
"
the
ability
of
a
unit
to
combust
a
stated
maximum
amount
of
fuel
per
hour
(
in
mmBtu/
hr)
on
a
steady
state
basis,
as
determined
by
the
physical
design
and
physical
characteristics
of
the
unit."
In
the
February
22,
2002
proposed
rule,
we
proposed
to
adopt
the
same
definition
used
in
the
January
18,
2000
Section
126
final
rule.

45
(
ii)
For
a
unit
classified
as
a
non­
EGU
under
paragraph
(
a)(
ii)
or
(
a)(
iv)
above,
we
then
classified
it
as
a
small
or
large
non­
EGU.
A
non­
EGU
with
a
maximum
design
heat
input
greater
than
250
mmBtu/
hour
is
a
large
non­
EGU.
A
non­
EGU
with
a
maximum
design
heat
input
equal
to
or
less
than
250
mmBtu/
hour
is
a
small
non­
EGU.
But
see
63
FR
71224
(
explaining
procedures
used
if
data
on
boiler
heat
input
capacity
were
not
available).
In
the
December
24,
1998
supplemental
action,
we
did
not
expressly
define
the
term
"
maximum
design
heat
input."
11
The
term
is
analogous
to
the
term
"
nameplate
capacity"
in
that
it
uses
the
manufacturer's
specifications
to
categorize
the
size
of
the
equipment
(
the
generator,
in
the
case
Draft
 
Do
not
cite,
quote
or
distribute
12
For
example,
in
establishing
the
State
budgets
for
large
EGUs
and
large
non­
EGUs,
we
identified
existing
units
as
being
large
or
small
based
on
nameplate
capacity
(
for
EGUs)
or
maximum
design
heat
input
(
for
non­
EGUs),
determined
each
unit's
baseline
heat
input
(
using
1995
or
1996)
and,
after
calculating
total
heat
input
for
large
EGUs
and
for
large
non­
EGUs,
grew
the
total
amounts
out
to
2007
using
heat
input
growth
rates
to
account
for
new
units
and
increased
utilization.
There
was
no
provision
for
modifying
the
budgets
to
remove
a
unit
initially
qualifying
as
a
large
EGU
or
large
non­
EGU
if
the
unit
changed
its
generating
or
heat
input
capacity.

46
of
an
EGU
or
the
boiler
or
turbine
or
combined­
cycle
system,
in
the
case
of
non­
EGU).
12
As
stated
previously,
we
defined
the
term
"
EGU"
by
applying
to
all
units,
including
cogeneration
units,
the
methodology
in
paragraphs
(
a)(
i)
and
(
a)(
iii)
above
and
used
the
methodology
in
paragraphs
(
a)(
ii)
and
(
a)(
iv)
above
to
define
units
as
non­
EGUs.
We
did
not
use,
for
cogeneration
units,
the
"
one­
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria
in
the
cogeneration
exclusion.
It
was
the
fact
that
we
did
not
apply
these
criteria
to
cogeneration
units
that
petitioners
challenged
in
Michigan.
As
discussed
further
below,
we
are
adopting
essentially
these
criteria
in
today's
final
rule.

3.
What
is
the
Rationale
for
the
Final
Rule's
Treatment
of
Cogeneration
Units?

a.
Distinction
between
units
in
the
electric
generation
business
and
units
in
the
industrial
sector.
Distinguishing
Draft
 
Do
not
cite,
quote
or
distribute
47
between
units
producing
electricity
for
sale
and
units
producing
electricity
for
internal
use
or
producing
steam
is
a
long­
standing
approach
in
setting
emission
limits.
In
the
NOx
SIP
Call,
the
Section
126
Rule,
and
today's
final
rule,

we
continue
to
take
this
general
approach
by
setting
different
emission
limits
for
units
producing
electricity
for
sale
(
EGUs)
and
units
that
do
not
produce
electricity
for
sale
(
non­
EGUs).

We
are
retaining
this
general
approach
for
several
reasons.
First,
this
is
a
long­
standing
approach,
and
few,

if
any,
commenters
in
the
NOx
SIP
Call
and
Section
126
rulemakings
supported
abandoning
the
distinction
between
units
in
the
electric
generation
business
and
units
in
the
industrial
sector.
Second,
after
organizing
the
units
into
these
two
categories,
we
found
that
there
was
some
difference
in
the
average
compliance
costs
of
the
two
groups.
See
65
FR
2677
(
estimating
average
large
EGU
control
costs
as
$
1,432
per
ton
in
1990
dollars
in
1997
and
average
large
non­
EGU
costs
as
$
1,589
per
ton).
Third,
this
approach
tends
to
result
in
units
that
directly
compete
in
the
electric
generation
business
having
to
meet
the
same
emission
limit,
and
that
result
seems
reasonable.

In
the
May
15,
2001
decision
in
the
Section
126
case,

the
D.
C.
Circuit
expressed
concern
that,
under
the
Section
Draft
 
Do
not
cite,
quote
or
distribute
13
In
fact,
use
of
the
"
one­
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria
for
cogeneration
units
distinguishes
between
EGU
cogeneration
units
and
non­
EGU
cogeneration
units
based
on
the
cogenerator's
amount
of
electricity
sales
and
raises
the
same
issue.
Under
these
criteria,
two
physically
identical
cogeneration
units
could
have
different
emission
limits
simply
because
one
produces
and
sells
the
requisite
amount
of
electricity
and
the
other
produces
more
electricity
for
internal
use
and
does
not
sell
the
requisite
amount.

48
126
Rule,
a
cogenerator
that
produces
electricity
for
sale
may
be
treated
as
an
EGU,
a
cogenerator
that
produces
electricity
for
internal
use
only
may
be
treated
as
a
non­

EGU,
and
thus
two
units
that
are
"
identical
physically"
may
be
subject
to
different
emission
reduction
requirements.

Appalachian
Power,
249
F.
3d
at
1062.
We
note
that
this
issue
is
not
unique
to
cogeneration
units
and
is
inherent
in
any
regulatory
program
that
distinguishes
between
units
in
the
electric
generation
business
and
units
that
are
in
the
industrial
sector
and
sets
different
emission
limits
for
the
two
groups.
13
As
previously
discussed,
we
are
continuing
to
use
the
general
approach
of
distinguishing
between
units
in
the
electric
generation
business
and
units
in
the
industrial
sector
in
the
NOx
SIP
Call
and
Section
126
Rule.
We
recognize
that
this
may
result
in
units
that
are
physically
identical
being
regulated
differently
based
on
whether
or
not
electricity
­­
particularly
electricity
for
sale
­­
is
produced
by
the
unit.
However,
before
abandoning
the
long­
Draft
 
Do
not
cite,
quote
or
distribute
49
standing
approach
of
distinguishing
between
units
on
this
basis
­­
an
action
that
few,
if
any,
commenters
in
the
NOx
SIP
Call
and
Section
126
rulemakings
have
advocated
­­
we
believe
that
it
is
prudent
to
gain
experience
in
operating
the
trading
program
under
the
NOx
SIP
Call
and
Section
126
Rule.
We
note
that
we
have
already
begun
the
process
of
treating
these
units
similarly
because
EGUs
and
non­
EGUs
will
participate
in
one
trading
program
and
will
trade
the
same
NOx
allowances.
After
we
have
gained
experience
with
the
NOx
SIP
Call
and
Section
126
trading
program,
we
intend
to
consider
whether
to
treat
as
the
same
all
large
boilers,

whether
they
produce
electricity
or
not.

b.
Effect
of
electricity
competition
and
electric
power
restructuring
on
distinction
between
utilities
and
nonutilities
As
discussed
in
the
February
22,
2002
proposed
rule
(
see
67
FR
8405­
06),
the
increasingly
competitive
nature
of
the
electric
power
industry
and
the
significant
and
increasing
participation
of
non­
utilities
(
e.
g.,
an
independent
power
producer
or
an
industrial
company)
in
competitive
electricity
markets
support
similar
treatment
of
utilities
and
non­
utilities.
In
the
proposed
rule,
we
stated
that,
with
these
changes
in
the
electric
power
industry
and
electricity
markets,
there
is
no
longer
a
factual
basis
for
excluding
cogeneration
units
from
Draft
 
Do
not
cite,
quote
or
distribute
50
treatment
as
EGUs
by
using
the
"
one­
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria.

Many
industry
commenters
argued
that
EGU
should
be
defined
to
exclude
a
cogeneration
unit
meeting
the
"

onethird
potential
electrical
output
capacity/
25
MWe
sales"

criteria.
They
raised
several
issues
in
support
of
their
argument
of
not
including
small
cogeneration
units
in
the
definition
of
EGU.
First,
commenters
argued
that
the
classification
of
cogeneration
units
as
EGUs
reversed
our
precedent
in
previous
regulations
and
contradicts
Congressional
intent
underlying
the
CAA.
They
also
argued
that
new
industrial
cogeneration,
and
the
potential
emissions
and
energy
efficiency
benefits
that
could
result,

would
be
discouraged.
In
addition,
commenters
maintained
that
the
costs
of
any
NOx
controls
for
these
units
would
be
reflected
in
the
market
for
the
products
produced
by
the
industrial
company
that
uses
energy
from
the
cogeneration
unit
and
not
in
the
electricity
market.
Commenters
maintained
that
a
manufacturing
company
can
engage
in
sales
of
electricity
without
being
in
the
business
of
selling
electricity.
Sometimes
such
a
company
exports
electricity
to
the
local
utility,
even
though
it
remains
a
net
importer
of
electricity
over
the
long­
term.
Furthermore,
commenters
argued
that
we
justified
our
definition
on
deregulation
and
Draft
 
Do
not
cite,
quote
or
distribute
51
have
failed
to
consider
the
halt
on
deregulation
efforts
that
California's
electricity
crisis
spurred
in
other
States.

Although
we
have
decided
for
the
final
rule
to
use
the
"
one­
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria,
we
are
not
persuaded
by
most
of
the
arguments
commenters
raised.
For
the
reasons
discussed
in
detail
in
the
proposed
rule
(
67
FR
8405­
06),
we
continue
to
believe
that
the
increasingly
competitive
nature
of
the
electric
power
industry
and
the
significant
and
increasing
participation
of
non­
utilities
in
competitive
electricity
markets
support
similar
treatment
of
utilities
and
nonutilities
We
also
note
that
deregulation
at
the
State
level
involves
sales
to
end­
users,
particularly
residential
and
commercial
customers,
and
a
slow­
down
(
or
halt)
in
State­
level
deregulation
would
not
change
this
conclusion
because
the
wholesale
electricity
market
­­
where
utilities
and
non­
utilities
can
compete
for
wholesale
sales
­­

continues
to
be
deregulated
at
the
Federal
level.

Commenters
claimed,
but
do
not
provide
any
documentation
of
the
magnitude,
that
failure
to
apply
the
"
one­
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria
will
discourage
new
industrial
cogeneration.
Further,
while
commenters
argued
that
industrial
companies
with
Draft
 
Do
not
cite,
quote
or
distribute
52
cogeneration
units
would
be
disadvantaged
because
the
units'

NOx
control
costs
would
be
reflected
in
the
costs
of
the
products
produced
using
energy
from
the
units,
they
ignore
the
fact
that
industrial
companies
that
instead
buy
electricity
from
utilities
would
presumably
have
utility
units'
NOx
control
costs
reflected
in
electricity
purchase
costs.

c.
Differences
between
the
design
and
operation
of
cogenerating
units
and
non­
cogenerating
units.
In
the
February
22,
2002
proposed
rule,
we
stated
that
there
appear
to
be
no
physical,
operational,
or
technological
differences
between
cogeneration
units
producing
electricity
for
sale
and
non­
cogeneration
units
producing
electricity
for
sale
that
would
prevent
cogeneration
units
classified
as
EGUs
from
achieving
average
NOx
reductions,
and
incurring
average
reduction
costs,
similar
to
those
achieved
by
noncogeneration
units.
We
concluded
in
the
proposed
rule
that
there
appear
to
be
no
such
differences
that
would
justify
using
the
"
one­
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria
for
classifying
cogeneration
units
as
EGUs
or
non­
EGUs,
rather
than
the
classification
methodology
used
for
all
other
units.
We
still
believe
that
there
are
no
relevant
differences
between
the
way
cogenerating
units
and
non­
cogenerating
units
are
built
and
operated
that
Draft
 
Do
not
cite,
quote
or
distribute
14
These
two
configurations
are
for
cogeneration
units
in
topping
cycle
cogeneration
facilities,
where
energy
is
used
sequentially,
first
to
produce
electricity
and
then
to
produce
thermal
energy
for
process
use
or
heating
and
cooling.
In
bottoming
cycle
cogeneration
facilities,
energy
is
used
sequentially
first
to
produce
thermal
energy
and
then
to
produce
electricity.
(
See
Cogeneration
Applications
Considerations,
R.
W.
Fisk
and
R.
L.
VanHousen,
GE
Power
Systems,
1996,
Docket
No.
OAR­
2001­
0008,
Item
No.
XII­
L­
04
at
1­
2.)
The
cogeneration
units
subject
to
the
NOx
SIP
Call
and
the
Section
126
Rule
are
boilers,
turbines,
or
combined
cycle
systems
and
so
are
likely
to
operate
in
topping
cycle
cogeneration
facilities.

53
affect
the
general
ability
of
cogenerating
units
to
control
NOx.
However,
at
this
time,
we
do
not
believe
we
have
adequate
record
support
comparing
the
NOx
reduction
costs
of
all
types
of
industrial
cogeneration
units
to
those
of
other
units
that
are
treated
as
EGUs.

As
discussed
in
the
February
22,
2002
proposed
rule,

cogeneration
units
under
the
NOx
SIP
Call
or
the
Section
126
Rule
operate
in
two
basic
configurations.
14
The
first
is
a
boiler
followed
by
a
steam
turbine­
generator.
In
this
configuration,
steam
is
generated
by
a
boiler.
The
steam
is
first
used
to
power
a
steam
turbine­
generator,
while
the
remaining
steam
is
used
for
an
industrial
application
or
for
heating
and
cooling.
The
boiler
that
generates
the
steam
used
in
this
manner
is
designed
and
operated
in
essentially
the
same
way
as
a
boiler
that
generates
steam
used
only
to
power
a
steam
turbine­
generator.
Therefore,
any
controls
Draft
 
Do
not
cite,
quote
or
distribute
54
that
could
be
used
on
a
boiler
used
to
produce
only
electricity
could
also
be
used
on
a
boiler
used
for
cogeneration.
In
each
case,
the
boiler
emits
the
same
amount
of
NOx.

The
second
typical
configuration
for
a
cogeneration
unit
is
a
gas­
fired
combined
cycle
system.
Combined
cycle
system
plant
refers
to
a
system
composed
of
a
gas
turbine,

heat
recovery
steam
generator,
and
a
steam
turbine.

Combined
cycle
units
that
cogenerate
is
designed
and
operated
in
essentially
the
same
way
as
combined
cycle
units
that
generate
only
electricity.
The
waste
heat
from
the
gas
turbine
serves
as
the
heat
input
(
possibly
supplemented
by
a
duct
burner)
to
the
heat
recovery
steam
generator
that
is
used
to
power
the
steam
turbine.
Both
the
gas
turbine
and
the
steam
turbine
are
connected
to
generators
to
produce
electricity.
The
gas
turbine
generator
and
the
heat
recovery
steam
generator
portions
can
be
adapted
to
supply
process
steam
as
well
as
electricity.
These
units
typically
emit
at
NOx
levels
well
below
0.15
lbs/
mmBtu
even
without
the
use
of
post­
combustion
controls.
Furthermore,
selective
catalytic
reduction
(
SCR)
has
been
used
extensively
on
combined
cycle
units
that
are
used
for
cogeneration
and
those
used
for
generation
of
electricity
only
and
results
in
NOx
emissions
at
levels
well
below
0.15
lb/
mmBtu.
(
See
GE
Draft
 
Do
not
cite,
quote
or
distribute
55
Combined­
Cycle
Product
Line
and
Performance,
GE
Power
Systems,
October
2000,
Docket
No.
OAR­
2001­
0008,
Item
No.

XII­
L­
04
at
10­
11.)

Both
cogeneration
configurations
identified
above
are
used
at
utility
and
non­
utility
facilities
that
produce
electricity
for
sale.
The
steam
generated
at
these
facilities
is
divided
between
powering
a
steam
turbine
and
serving
process
uses
or
heating
and
cooling.
The
cogeneration
units
with
the
same
configuration
at
these
facilities
are
almost
identical
in
design,
except
that
a
non­
utility
facility
may
use
more
of
the
steam
for
process
uses
or
heating
and
cooling
and
less
for
electricity
generation.

Further,
in
comparison
to
a
non­
cogeneration
system
that
generates
electricity
for
sale,
either
type
of
cogeneration
system
looks
essentially
the
same
as
such
a
non­
cogeneration
system
except
for
the
addition
of
valves
and
piping
to
send
the
steam
for
process
use
or
heating
and
cooling.
In
both
the
cogeneration
and
non­
cogeneration
systems
that
generate
electricity
for
sale,
all
the
flue
gas
(
containing
the
NOx
emissions)
exiting
the
combustion
process
can
be
directed
through
the
pollution
control
devices
and
then
through
a
stack.
Because
the
cogeneration
and
non­
cogeneration
systems
are
of
essentially
the
same
Draft
 
Do
not
cite,
quote
or
distribute
15
For
examples
and
discussion
of
how
post­
combustion
controls
apply
to
cogeneration
units,
see
Docket
No.
OAR­
2001­
0008
(
Legacy
Docket
No.
A­
96­
56),
Item
Nos.
XII­
L­
02;
XII­
L­
03;
and
XII­
L­
05
at
10­
11
and
13
(
Figure
15).
In
fact,
this
is
also
true
for
boilers
that
do
not
serve
any
generator.
Boilers
with
or
without
a
generator
and
with
or
without
the
capability
to
cogenerate
are
of
essentially
the
same
design,
and
the
flue
gas
exits
the
systems
in
the
same
manner.
Any
post­
combustion
pollution
control
device
used
for
NOx
control
in
either
system
is
located
in
the
same
place
and
operated
in
the
same
manner.

16
"
Lack
of
Relevant
Physical
or
Technological
Differences
Between
Cogeneration
Units
and
Utility
Electricity
Generating
Units,"
September
25,
2000,
Docket
No.
OAR­
2001­
0008
(
Legacy
Docket
No.
A­
96­
56),
Item
No.
XII­
K­
47.

56
design
and
the
flue
gas
exits
the
systems
in
the
same
manner,
the
control
of
NOx
emissions
can
be
achieved
in
the
same
manner.
Any
post­
combustion
pollution
control
device
used
for
NOx
control
in
either
system
is
located
in
the
same
place
and
operated
in
the
same
manner.
15
As
discussed
in
the
February
22,
2002
proposed
rule
and
the
technical
support
document16,
post­
combustion
NOx
control
technologies,
i.
e.,
selective
non­
catalytic
reduction
(
SNCR)

and
SCR,
are
available
for
use
on
both
non­
cogeneration
and
cogeneration
units
producing
electricity
for
sale.
The
technical
support
document
and
the
other
documents
cited
in
the
proposed
rule
support
the
following
conclusions:

(
8)
Selective
non­
catalytic
reduction
is
a
fully
commercial
technology
that
uses
reagent
injected
into
the
boiler
above
the
combustion
zone
to
reduce
NOx
to
elemental
Draft
 
Do
not
cite,
quote
or
distribute
57
nitrogen
and
water.
Because
the
NOx
reduction
takes
place
above
the
combustion
zone,
boiler
type
has
an
insignificant
impact
on
the
ability
to
use
SNCR.

Selective
non­
catalytic
reduction
has
been
demonstrated
on
a
wide
range
of
boiler
types
and
sizes
(
including
cogeneration
units)
and
on
a
wide
range
of
fuels
(
including
bio­
mass,
wood,
or
combinations
of
fuels
such
as
bark,
paper
sludge,
and
fiber
waste).

Selective
non­
catalytic
reduction
has
been
used
at
a
wide
range
of
temperatures
(
e.
g.,
from
1250
degrees
F
to
2600
degrees
F)
and
has
been
designed
to
handle
a
wide
range
of
load
variation
(
e.
g.,
33
percent
to
100
percent
of
a
unit's
maximum
continuous
rating).

(
9)
Selective
catalytic
reduction
is
a
fully
commercial
technology
that
uses
both
ammonia
injected
after
the
flue
gases
exit
the
boiler
or
the
combustion
turbine
and
catalyst
in
a
reactor
to
reduce
NOx
to
elemental
nitrogen
and
water.
Because
the
NOx
reduction
takes
place
in
a
reactor
outside
the
combustion
and
heat
transfer
zones,
boiler
type
has
an
insignificant
impact
on
the
ability
to
use
SCR.
The
SCR
has
been
demonstrated
on
a
wide
range
of
boiler
types
and
sizes
and
on
combined
cycle
systems.
The
SCR
has
been
used
at
a
wide
range
of
temperatures
(
e.
g.,
450
degrees
F
to
Draft
 
Do
not
cite,
quote
or
distribute
58
1100
degrees
F)
and
has
been
designed
to
handle
a
wide
range
of
load
variation.

In
the
February
22,
2002
proposed
rulemaking,
we
requested
comment
on,
and
specific
information
supporting
or
contradicting,
our
conclusions
that
there
are
no
relevant
physical,
operational,
or
technological
differences
and
no
significant
difference
in
average
control
retrofit
cost
for
cogeneration
versus
non­
cogeneration
units
producing
electricity
for
sale.
In
response
to
the
proposed
rule,

commenters
raised
concerns
that
it
is
technically
and
economically
more
difficult
to
control
NOx
in
industrial
cogeneration
units
than
in
non­
utility
units
because
they
are
smaller
sized
than
utility
boilers,
fire
multiple
fuels
and
often
co­
fire
two
or
more
fuels,
operate
in
a
loadfollowing
mode,
have
lower
annual
operating
load
or
capacity
factor,
and
have
boiler
temperature
profiles
and
other
factors
that
affect
pollution
control
devices.
A
few
commenters
supplied
data
or
indicated
the
cost
of
control
for
certain
units.
One
commenter
stated
that
reasonably
available
control
technology
(
RACT)
analysis
for
an
unidentified,
350
mmBtu/
hr
coal­
fired
stoker
boiler
indicated
that
the
only
technically
feasible
NOx
control
identified
by
boiler
and
NOx
control
experts
was
conversion
to
fluidized
bed
combustion
at
a
cost
of
over
$
11,000/
ton
Draft
 
Do
not
cite,
quote
or
distribute
59
based
on
year­
round
operation
and
over
$
26,000/
ton
considering
only
the
ozone
season.
Another
commenter
cited
EPA's
"
Alternative
Control
Techniques
Document:
NOx
Emissions
from
Industrial/
Commercial/
Institutional
Boilers"

(
March
1994)(
1994
ACT),
indicating
cost
effectiveness
of
SCR
for
a
400
mmBtu/
hr
pulverized
coal
boiler
of
$
3,400­

$
4,200/
ton
and
cost
effectiveness
of
SNCR
for
a
470
mmBtu
pulverized
coal
boiler
(
with
low
NOx
burners
and
a
50
percent
load
factor)
of
more
than
$
1,800/
ton.
An
additional
commenter
indicated
costs
in
excess
of
$
2,500
per
seasonal
ton
at
the
Tobaccoville
facility
(
in
1990
dollars).

In
light
of
the
limited
control
cost
data
provided
by
commenters,
we
conclude
that
at
this
time
we
lack
sufficient
cost
data
to
show
whether
there
is
a
significant
difference
in
the
average
cost
of
controlling
NOx
emissions
from
cogeneration
units,
as
compared
to
non­
cogeneration
units.

The
1994
ACT
costs
cited
by
one
commenter
are
not
relevant
because
the
boilers
involved
were
not
cogeneration
units.

In
addition,
the
cited
costs
were
early
estimates
by
the
Agency
on
the
cost
of
SCR
and
SNCR
and
have
been
superceded
by
later
data
and
documents.
Further,
the
commenters'

indicated
that
costs
at
the
coal­
fired
stoker
and
at
the
Tobaccoville
facility
do
not
necessarily
support
the
claim
that
average
costs
of
controlling
NOx
at
cogeneration
units
Draft
 
Do
not
cite,
quote
or
distribute
60
are
higher
than
such
costs
at
non­
cogeneration
units.
Due
to
economies
of
scale,
smaller
units,
like
some
industrial
cogeneration
units
and
smaller
utility
units,
may
have
costs
that
are
higher
than
the
average
costs.
We
acknowledge
that
the
actual
cost
impacts
will
vary
from
unit
to
unit,
with
the
costs
being
lower
for
some
and
higher
for
others.
In
our
analysis,
we
presented
average
costs
of
control
and
understood
that
some
units
may
have
higher
costs
than
the
average.
We
note
that
units
may
participate
in
a
trading
program
that
allows
for
the
buying
of
allowances
for
units
that
have
more
difficulty
controlling
NOx
emissions.

Furthermore,
we
note
that
we
have
cost
information
on
one
other
cogeneration
unit.
In
our
cost
analysis
of
EGUs,

we
used
an
average
capital
cost
of
$
69.70
to
$
71.80
per
kilowatt
for
SCR
on
a
200
MWe
coal­
fired
EGU.
See
"
Analyzing
Electric
Power
Generation
Under
the
CAAA,"
U.
S.

EPA,
March
1998,
Docket
No.
OAR­
2001­
0008,
Item
No.
V­
C­
03
at
A5­
7
(
Table
A5­
5).
The
record
shows
a
capital
cost
of
$
58
per
kilowatt
for
SCR
on
a
new
coal­
fired
cogeneration
unit.
See
"
Status
Report
on
NOx
Control
Technologies
and
Cost
Effectiveness
for
Utility
Boilers,"
Northeast
States
for
Coordinated
Air
Use
Management
and
Mid­
Atlantic
Regional
Air
Management
Association,
June
1998,
Docket
No.
OAR­
2001­

0008,
Item
No.
VI­
B­
05
at
151­
53.
We
maintain
that
this
Draft
 
Do
not
cite,
quote
or
distribute
17
We
also
note
that
the
dollar
per
ton
cost
for
this
installation
is
$
2,800
to
$
3,000
per
ton
of
NOx
removed.
This
is
higher
than
the
average
cost
for
EGUs
because
the
unit
started
at
a
low
NOx
rate
(
0.16
lb/
mmBtu)
and
controls
down
to
0.07­
0.08
lb/
mmBtu,
not
because
the
unit
is
a
cogenerator.
If
the
unit
only
generated
electricity
and
had
the
same
starting
NOx
rate,
the
cost
would
be
the
same.

61
cost
is
reasonably
consistent
with
the
average
cost
that
we
determined
for
all
EGUs.
17
However,
as
commenters
noted,

industrial
cogeneration
units
cover
a
wide
range
of
firing
types
and
fire
a
wide
range
of
fuels.
Since
the
cogeneration
unit
used
as
part
of
the
basis
for
the
control
costs
for
EGUs
was
a
medium­
size,
pulverized
coal
plant,

very
similar
to
many
coal­
fired
utility
boilers,
it
is
not
necessarily
representative
of
other
types
of
boilers
used
for
industrial
cogeneration
units
such
as
stoker
boilers
firing
a
combination
of
fuels.
Since
we
have
limited
control
cost
data
for
such
other
types
of
industrial
cogeneration
units,
we
believe
that
we
do
not
have
a
sufficient
record
at
this
time
to
show
whether
there
is
a
significant
difference
in
the
average
cost
of
controlling
NOx
emissions
from
these
units.

4.
What
Revisions
Are
Being
Made
to
the
Definition
of
EGU
in
the
NOx
SIP
Call
and
the
Section
126
Rule?

In
today's
final
rule,
we
are
addressing
three
aspects
of
the
EGU
definition.
First,
for
purposes
of
the
NOx
SIP
Draft
 
Do
not
cite,
quote
or
distribute
62
Call
and
the
Section
126
Rule
and
in
a
change
from
the
February
22,
2002
proposed
rule
(
see
67
FR
8401­
8410),
we
are
finalizing
an
EGU
definition
that
applies
to
cogeneration
units
the
"
one­
third
potential
electrical
output/
25
MWe
sales"
criteria
in
classifying
the
units
as
EGUs
or
non­
EGUs.
For
all
other
units,
we
are
continuing
to
apply
the
basic
approach
used
in
the
NOx
SIP
Call
Rule,

described
in
the
December
24,
1998
supplemental
action
(
63
FR
71233),
and
the
approach
in
the
Section
126
Rule
for
such
classification.
Second,
we
are
finalizing
some
minor
changes
to
the
categorization
(
based
on
dates
of
commencement
of
operation)
of
units
under
the
NOx
SIP
Call
definition
of
EGU
(
set
forth
in
section
II.
A.
2
above)
for
purposes
of
applying
the
firm­
contract
criterion
used
to
classify
units
as
EGUs.
While
the
NOx
SIP
Call
categorizes
units
as
those
commencing
operation
before
January
1,
1996
and
those
commencing
operation
on
or
after
January
1,
1996,

today's
final
rule
categorizes
units
as
those
commencing
operation
before
January
1,
1997,
those
commencing
operation
in
1997
or
1998,
and
those
commencing
operation
on
or
after
January
1,
1999.
These
new
categories
based
on
commencement
of
unit
operation
are
the
same
as
the
categories
adopted
in
the
January
18,
2000
Section
126
final
rule,
under
which
units
commencing
operation
before
1999
and
generating
Draft
 
Do
not
cite,
quote
or
distribute
63
electricity
for
sale,
but
not
for
sale
under
a
firm
contract
to
the
grid
(
i.
e.,
not
under
a
guaranteed
commitment
to
provide
the
electricity),
were
classified
as
non­
EGUs
and
units
commencing
operation
in
1999
or
thereafter
and
generating
any
electricity
for
sale
were
generally
classified
as
EGUs.
Today's
final
rule
uses
this
same
approach
to
classify
units
as
EGUs
or
non­
EGUs,
except
for
the
application
to
cogeneration
units
of
the
"
one­
third
potential
electrical
output/
25
MWe
sales"
criteria.
Third,

we
are
also
finalizing
some
minor
changes
to
the
terminology,
and
minor
corrections
of
awkward
or
inconsistent
wording
and
grammatical
errors
in
the
applicability
provisions.
For
example,
we
are
adopting
the
term
"
potential
electrical
output
capacity"
and
the
definitions
of
the
terms
"
electricity
for
sale
under
firm
contract
to
the
electric
grid,"
"
potential
electrical
output
capacity,"
"
nameplate
capacity,"
and
"
maximum
design
heat
input"
used
in
the
January
18,
2000
Section
126
Rule.

a.
Application
of
the
"
one­
third
potential
electrical
output/
25MWe
sales"
criteria,
in
lieu
of
the
firm­
contract
criterion,
to
cogeneration
units.
As
explained
in
the
NOx
SIP
Call
Rule,
described
in
the
December
24,
1998
supplemental
action
(
63
FR
71233),
and
the
Section
126
Rule,

we
adopted
the
approach
of
using
the
firm­
contract
criterion
Draft
 
Do
not
cite,
quote
or
distribute
64
for
units
(
non­
cogeneration
and
cogeneration
units)
that
commenced
operation
before
1999.
We
stated
that
the
criterion
provides
a
reasonable
transitional
means
of
making
the
EGU/
non­
EGU
classification
since,
for
units
commencing
operation
in
1999
or
thereafter,
a
unit
that
generates
any
electricity
for
sale
is
classified
as
an
EGU.
We
explained
that
the
firm­
contract
criterion
provides
a
reasonable
way
of
identifying
which
cogeneration
units
have
been
significantly
enough
involved
in
the
business
of
generating
electricity
for
sale
that
their
owners
have
provided
guaranteed
commitments
to
provide
electricity
from
the
units
to
one
or
more
customers.
We
also
stated
that
the
historical
information
necessary
to
apply
the
firm­
contract
criterion
to
cogeneration
units
(
and
other
units)
is
already
available
to
us.
Capacity
involved
in
sales
of
electricity
"
under
firm
contract
to
the
electricity
grid"
has
been
generally
included
on
EIA
form
860A
(
called
EIA
form
860
before
1998)
or
reported
to
EIA
as
capacity
projected
for
summer
or
winter
peak
periods
on
EIA
form
411
(
Item
2.1
or
2.2,
line
10).
The
historical
information
from
these
forms
is
publicly
available.

Nevertheless,
in
today's
final
rule,
we
are
adopting
the
"
one­
third
potential
electrical
output/
25MWe
sales"

criteria
for
classifying
cogenerations
units
as
EGUs
or
non­
Draft
 
Do
not
cite,
quote
or
distribute
65
EGUs.
The
reasons
for
this
approach
are
discussed
below
in
II.
A.
4.
Regardless
of
when
a
cogeneration
unit
commenced
or
commences
operation,
a
cogeneration
unit
supplying
more
than
one­
third
of
its
potential
electrical
output
and
more
than
25
MWe
to
a
utility
power
distribution
system
for
sale
during
any
year
in
the
relevant
period
is
classified
as
an
EGU,
and
a
cogeneration
unit
that
does
not
meet
these
criteria
is
classified
as
a
non­
EGU.
As
stated
above,

criteria
are
used
in
order
to
determine
whether
a
cogeneration
unit
is
exempt
from
the
Acid
Rain
Program
under
section
402(
17)(
C)
of
the
CAA,
as
implemented
under
§
72.4(
b)(
4)
of
the
Acid
Rain
regulations.
See
40
CFR
72.4(
b)(
4);
and
58
FR
15634,
15636­
38
(
1993).
Consequently,

in
implementing
the
use
of
the
"
one­
third"
potential
electrical
output/
25
MWe
sales"
criteria
for
classifying
cogeneration
units
in
the
NOx
SIP
Call
and
in
the
Section
126
Rule,
today's
final
rule
references
§
72.4
(
b)(
4).
Thus,

in
general,
a
cogeneration
unit
that
meets
the
criteria
for
an
unaffected
unit
in
the
Acid
Rain
Program
under
§
72.4(
b)(
4)
for
the
relevant
time
period
is
defined
as
a
non­
EGU,
while
a
cogeneration
unit
that
fails
to
meet
the
criteria
for
such
exemption
for
the
relevant
time
period
is
defined
as
an
EGU.
Moreover,
for
cogeneration
units
commencing
operation
before
January
1,
1997,
the
relevant
Draft
 
Do
not
cite,
quote
or
distribute
18
While
we
wish
to
be
as
consistent
as
possible
in
the
definitions
used
in
the
SIP
Call
and
the
definitions
used
in
the
Section
126
Rule,
there
is
an
important
difference
in
the
reason
for
categorizing
units
in
the
two
rulemakings.
In
the
NOx
SIP
Call,
the
definitions
are
used
to
set
the
State
budgets
and
therefore
need
to
focus
on
1995
and
1996,
the
base
years
used
for
developing
budgets.
State­
specific
growth
rates
were
used
to
take
into
account
units
commencing
operation
after
the
base
years.
The
NOx
SIP
Call
model
rule
(
in
part
96)
did
not
use
these
definitions
in
the
applicability
and
allowance
allocation
provisions,
and
States
adopted
their
own
applicability
and
allowance
allocation
provisions
in
their
SIPs.
Thus,
the
portion
of
the
definitions
that
affects
the
NOx
SIP
Call
is
the
portion
pertaining
to
units
in
operation
before
January
1,
1997.
In
the
Section
126
Rule,
the
definitions
are
used
for
purposes
of
determining
applicability
and
allocating
allowances.
Thus,
in
the
Section
126
Rule,
the
definitions
must
address
units
commencing
operation
after
1996,
as
well
as
those
operating
in
1995
and
1996.

66
period
is
1995­
1996;
for
cogeneration
units
commencing
operation
during
1997­
1998
the
relevant
period
is
1997­
1998;

and
for
units
commencing
operation
on
or
after
January
1,

1999,
the
relevant
period
is
1999
and
thereafter.
These
same
periods
or
categories
are
used
in
classifying
noncogeneration
units
as
EGUs
or
non
EGUs.
We
are
adopting
the
categories
so
that
a
consistent
set
of
categories
applies
to
all
units
(
either
cogeneration
or
non­
cogeneration
units),

which
will
simplify
and
facilitate
the
categorization
of
units
by
EPA,
States,
and
others.
18
As
discussed
below,
we
are
continuing
to
apply
the
firm­
contract
criterion
(
for
units
commencing
operation
before
1999)
or
the
electricity
sales
criterion
(
for
units
commencing
operation
in
or
after
Draft
 
Do
not
cite,
quote
or
distribute
67
1999)
for
classifying
non­
cogeneration
units
as
EGUs
or
non­

EGUs.

b.
Application
of
the
firm­
contract
criterion
to
noncogeneration
units.
As
noted
above,
in
the
NOx
SIP
Call
Rule
[
as
described
in
the
December
24,
1998
supplemental
action
(
63
FR
71233)]
and
the
Section
126
Rule,
we
adopted
the
approach
of
using
the
firm­
contract
criterion
for
noncogeneration
units
(
as
well
as
for
cogeneration
units)
that
commenced
operation
before
1999.
In
the
February
22,
2002
proposed
rule,
we
did
not
reconsider
that
general
approach
for
non­
cogeneration
units,
but
only
for
cogeneration
units.

However,
we
did
propose
minor
changes
in
the
categorization
of
non­
cogeneration
units
based
on
their
date
of
commencement
of
operation.
We
proposed
to
adopt
commencement
of
operation
before
1999
or
on
or
after
January
1,
1999
as
the
dividing
line
between
units
to
which
the
firm­
contract
criterion
are
applied
and
those
to
which
the
electricity
sales
criterion
are
applied.
Further,
for
application
of
the
firm­
contract
criterion,
we
proposed
to
distinguish
between
units
commencing
operation
before
1997
and
those
commencing
operation
in
1997
or
1998.
Some
commenters
on
the
proposed
rule
argued
for
the
keeping
of
the
"
firm
contract"
language
for
units
commencing
operation
in
1999
or
later,
especially
if
we
would
continue
with
our
Draft
 
Do
not
cite,
quote
or
distribute
68
proposed
definition
of
EGUs
with
regard
to
cogeneration
units.

In
today's
final
rule,
we
are
finalizing,
for
noncogeneration
units,
the
categorization
of
units
under
the
NOx
SIP
Call
as
those
units
commencing
operation
before
January
1,
1997,
those
commencing
operation
in
1997
or
1998,

and
those
commencing
operation
on
or
after
January
1,
1999.

The
firm­
contract
criterion
is
not
applied
to
noncogeneration
units
commencing
operation
on
or
after
January
1,
1999.
The
classification
of
units
commencing
operation
on
or
after
January
1,
1999
will
be
based
on
whether
the
unit
produces
any
electricity
for
sale.
In
general,
any
non­
cogeneration
unit
that
produces
electricity
for
sale
will
be
an
EGU,
except
that
the
non­
EGU
classification
will
apply
to
a
unit
serving
a
generator
that
has
a
nameplate
capacity
equal
to
or
less
than
25
MWe,
from
which
any
electricity
is
sold,
and
that
has
the
potential
(
determined
based
on
nameplate
capacity)
to
use
50
percent
or
less
of
the
potential
electrical
output
capacity
of
the
unit.

As
discussed
in
the
February
22,
2002
proposed
rule,

for
several
reasons,
we
are
establishing
January
1,
1999
as
the
cutoff
date
for
applying
EGU
and
non­
EGU
definitions
based
on
electricity
sales
under
firm
contract
to
the
grid
and
the
start
date
for
applying
EGU
and
non­
EGU
definitions
Draft
 
Do
not
cite,
quote
or
distribute
69
based
on
electricity
sales.
First,
information
is
available
to
us
on
electricity
sales
on
a
calendar
year
basis
only.

Consequently,
the
classification
of
units
based
on
whether
the
generators
that
they
serve
are
involved
in
firm­
contract
electricity
sales
must
be
made
on
a
calendar
year
basis,
and
any
cutoff
must
start
on
January
1.
Second,
use
of
the
January
1,
1999
cutoff
date
for
the
NOx
SIP
Call
is
consistent
with
the
use
of
that
same
cutoff
date
in
the
Section
126
Rule.
Third,
the
January
1,
1999
cutoff
date
will
limit
the
ability
of
owners
or
operators
of
new
units
that
might
otherwise
qualify
as
large
non­
EGUs
from
obtaining
small
EGU
classification
for
the
units
and
thereby
avoiding
all
emission
reduction
requirements.
For
example,

since
the
cutoff
date
and
the
relevant
period
for
determining
electricity
sales
are
past,
the
owner
of
a
large
new
unit
that
would
otherwise
not
serve
a
generator
will
not
be
able
to
obtain
small
EGU
classification
simply
by
adding
a
very
small
generator
(
e.
g.,
1
MWe)
to
the
unit
and
selling
a
small
amount
of
electricity
under
firm
contract
to
the
grid.

c.
Application
of
Section
126
terms
and
definitions
and
correction
of
awkward
or
inconsistent
wording
and
grammatical
errors.
We
also
are
finalizing
for
use
in
the
NOx
SIP
Call
the
same
term
"
potential
electrical
output
Draft
 
Do
not
cite,
quote
or
distribute
70
capacity,"
and
the
same
definitions
of
the
terms
"
electricity
for
sale
under
firm
contract
to
the
electric
grid,"
"
potential
electrical
output
capacity,"
"
nameplate
capacity,"
and
"
maximum
design
heat
input,"
adopted
in
the
January
18,
2000
Section
126
final
rule
and
used
in
the
EGU
definition
in
the
regulations
(
i.
e.,
part
97)
implementing
the
Section
126
program.
The
basis
for
these
terms
and
definitions
is
set
forth
above.

In
addition,
we
are
correcting
some
awkward
or
inconsistent
wording
and
grammatical
errors
without
making
any
substantive
change
in
the
EGU
and
non­
EGU
definitions.

For
example,
instead
of
referring
to
units
commencing
operation
"
on
or
after
January
1,
1997
and
before
January
1,

1999"
as
in
the
February
22,
2002
proposed
rule,
the
final
regulations
refer
to
units
commencing
operation
"
in
1997
or
1998."

By
further
example,
with
regard
to
units
classified
as
EGUs,
the
proposed
rule
refers
to
a
unit
commencing
operation
before
January
1,
1997
or
in
1997
or
1998
that
"
had"
a
nameplate
capacity
greater
than
25
MWe
and
refers
to
a
unit
commencing
operation
on
or
after
January
1,
1999
"
with"
the
requisite
nameplate
capacity.
With
regard
to
units
classified
as
non­
EGUs,
the
proposed
rule
refers
to
a
unit
commencing
operation
before
January
1,
1997
or
in
1997
Draft
 
Do
not
cite,
quote
or
distribute
71
or
1998
that
"
has"
a
maximum
design
heat
input
greater
than
250
mmBtu/
hr
and
refers
to
a
unit
commencing
operation
on
or
after
January
1,
1999
"
with"
the
requisite
maximum
design
heat
input.
This
inconsistent
wording
concerning
nameplate
capacity
and
maximum
design
heat
input,
where
sometimes
the
past
tense,
sometimes
the
present
tense,
and
sometimes
no
tense
are
used
for
units
that
had
already
commenced
commercial
operation
in
the
past,
is
confusing.
The
final
regulations
consistently
reference
nameplate
capacity
and
maximum
design
heat
without
using
past
or
present
tense.

The
regulations
refer
to
generators
"
with"
the
requisite
nameplate
capacity
and
units
"
with"
the
requisite
maximum
design
heat
input.

By
further
example,
the
proposed
rule
refers
to
EGUs
that
"
commenced
operation"
before
January
1,
1997
or
in
1997
or
1998
serving
a
generator
that
"
produced
electricity
for
sale"
and
to
EGUs
that
"
commence
operation"
on
or
after
January
1,
1999
that
serve
a
generator
that
"
produces
electricity
for
sale."
The
proposed
rule
also
refers
to
non­
EGUs
that
"
commenced
operation"
before
January
1,
1997
or
in
1997
or
1998
that
"
did
not
serve"
a
generator
"
producing
electricity
for
sale"
and
to
non­
EGUs
that
"
commence
operation"
on
or
after
January
1,
1999
that
"
at
no
time
serves"
or
"
at
any
time
serves"
a
generator
"
producing
Draft
 
Do
not
cite,
quote
or
distribute
72
electricity
for
sale."
This
inconsistent
wording
and
use
of
past
and
present
tenses
is
also
confusing.
For
example,

some
units
in
the
category
of
1999
or
later
commencement
of
operation
have
already
commenced
operation
while
others
will
commence
operation
in
the
future.
Yet,
the
present
tense
is
used
in
reference
to
all
such
units.
The
final
regulations
consistently
reference
commencement
of
operation
and
production
of
electricity
without
using
past
or
present
tense.

d.
Final
EGU
and
non­
EGU
definitions.
For
the
reasons
discussed
above,
we
are
adopting
the
following
definitions
of
EGU
and
non­
EGU
for
the
NOx
SIP
Call
and
the
proposed
definitions
discussed
above
(
in
footnotes
9,
10,
11,
and
12)

for
the
terms
"
electricity
for
sale
under
firm
contract
to
the
electric
grid,"
"
potential
electrical
output
capacity,"

"
nameplate
capacity,"
and
"
maximum
design
heat
input"
used
in
the
EGU
and
non­
EGU
definitions.
(
The
EGU
and
non­
EGU
definitions,
and
definitions
for
related
terms,
adopted
today
for
the
Section
126
Rule
are
set
forth
below
in
the
revised
rule
language
accompanying
this
preamble.)

(
a)
The
following
units
are
classified
as
EGUs:

(
1)
For
non­
cogeneration
units­­

(
A)
For
units
commencing
operation
before
January
1,
1997,
a
unit
serving
during
1995
Draft
 
Do
not
cite,
quote
or
distribute
73
or
1996,
a
generator
producing
electricity
for
sale
under
a
firm
contract
to
the
electric
grid.

(
B)
For
units
commencing
operation
in
1997
or
1998,
a
unit
serving,
during
1997
or
1998
a
generator
producing
electricity
for
sale
under
a
firm
contract
to
the
electric
grid.

(
C)
For
units
commencing
operation
on
or
after
January
1,
1999,
a
unit
serving,
at
any
time,
a
generator
producing
electricity
for
sale.

(
2)
For
cogeneration
units­­

(
A)
For
units
commencing
operation
before
January
1,
1997,
a
unit
that
fails
to
qualify
as
an
unaffected
unit
under
40
CFR
72.6(
b)(
4)

for
1995
or
1996
under
the
Acid
Rain
Program.

(
B)
For
units
commencing
operation
in
1997
or
1998,
a
unit
that
fails
to
qualify
as
an
unaffected
unit
under
40
CFR
72.6(
b)(
4)
for
1997
or
1998
under
the
Acid
Rain
Program.

(
C)
For
units
commencing
operation
on
or
after
January
1,
1999,
a
unit
that
fails
to
qualify
as
an
unaffected
unit
under
40
CFR
72.6(
b)(
4)
for
any
year
under
the
Acid
Rain
Draft
 
Do
not
cite,
quote
or
distribute
74
Program.

(
b)
The
following
units
are
classified
as
non­
EGUs:

(
1)
For
non­
cogeneration
units­­

(
A)
For
units
commencing
operation
before
January
1,
1997,
a
unit
not
serving
during
1995
or
1996
a
generator
producing
electricity
for
sale
under
a
firm
contract
to
the
electric
grid.

(
B)
For
units
commencing
operation
in
1997
or
1998,
a
unit
not
serving
during
1997
or
1998
a
generator
producing
electricity
for
sale
under
a
firm
contract
to
the
electric
grid.

(
C)
For
units
commencing
operation
on
or
after
January
1,
1999,
a
unit:

(
i)
At
no
time
serving
a
generator
producing
electricity
for
sale;
or
(
ii)
At
any
time
serving
a
generator
with
a
nameplate
capacity
of
25
MWe
or
less
producing
electricity
for
sale,
if
any
such
generator
has
the
potential
to
use
not
more
than
50
percent
of
the
potential
electrical
output
capacity
of
the
unit.

(
2)
For
cogeneration
units­­
Draft
 
Do
not
cite,
quote
or
distribute
75
(
A)
For
units
commencing
operation
before
January
1,
1997,
a
unit
that
qualifies
as
an
unaffected
unit
under
40
CFR
72.6(
b)(
4)
for
1995
and
1996
under
the
Acid
Rain
Program.

(
B)
For
units
commencing
operation
in
1997
or
1998,
a
unit
that
qualifies
as
an
unaffected
unit
under
40
CFR
72.6(
b)(
4)
for
1997
and
1998
under
the
Acid
Rain
Program.

(
C)
For
units
commencing
on
or
after
January
1,
1999,
a
unit
that
qualifies
as
an
unaffected
unit
under
40
CFR
72.6(
b)(
4)
for
each
year
under
the
Acid
Rain
Program.

(
c)
Units
classified
as
EGUs
or
non­
EGUs
under
paragraphs
(
a)
and
(
b)
are
classified
as
large
or
small
as
follows:

(
1)
A
unit
under
paragraph
(
a)
serving
a
generator
with
a
nameplate
capacity
greater
than
25
MWe
is
a
large
EGU.

(
2)
A
unit
under
paragraph
(
a)
serving
a
generator
with
a
nameplate
capacity
equal
to
or
less
than
25
MWe
is
a
small
EGU.

(
3)
A
unit
under
paragraph
(
b)
with
a
maximum
design
heat
input
greater
than
250
mmBtu/
hour
is
a
large
non­
EGU.
Draft
 
Do
not
cite,
quote
or
distribute
76
(
4)
A
unit
under
paragraph
(
b)
with
a
maximum
design
heat
input
equal
to
or
less
than
250
mmBtu/
hour
is
a
small
non­
EGU.

5.
What
is
the
Effect
on
Cogeneration
Unit
Classification
of
Applying
"
One­
Third
Potential
Electrical
Output
Capacity/
25
MWe
Sales"
Criteria,
Rather
Than
the
Same
Methodology
as
Used
for
Other
Units?

The
petitioner
in
Michigan
who
successfully
challenged
the
lack
of
application
of
the
"
one­
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria
to
cogeneration
units
claimed
that
the
failure
to
apply
such
criteria
would
result
in
"
sweeping
previously
unaffected
non­
EGUs
into
the
EGU
category."
Brief
of
Petitioner
CIBO
at
4
(
submitted
in
Michigan).
The
petitioner
further
suggested
that,
without
the
application
of
these
criteria,

"
any
sale
of
electricity
will
make
a
non­
EGU
a
more
stringently
regulated
EGU."
Reply
Brief
of
Petitioner
CIBO
at
1
(
submitted
in
Michigan).

As
discussed
above,
large
EGUs
and
large
non­
EGUs
are
included
in
the
determination
of
the
amount
of
a
State's
significant
contribution
to
nonattainment
in
another
State.

No
reductions
by
small
EGUs
or
small
non­
EGUs
are
included
in
that
determination.

Neither
the
petitioner
nor
any
party
that
commented
in
Draft
 
Do
not
cite,
quote
or
distribute
77
the
NOx
SIP
Call
or
the
Section
126
rulemakings
identified
any
specific,
existing
cogeneration
units
that,
without
the
application
of
the
"
one­
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria,
would
be
classified
as
large
EGUs
but
that,
with
the
application
of
such
criteria,

would
be
classified
as
either
large
or
small
non­
EGUs.
In
fact,
one
commenter
supporting
the
"
one­
third
potential
electrical
output
capacity/
25
MWe"
sales
criteria
stated
that
applying
the
criteria
to
the
NOx
SIP
Call
"
would
not
alter
the
Agency's
baseline
emissions
inventory,
since
cogeneration
units
were,
for
the
most
part,
classified
correctly
as
non­
EGUs
in
EPA's
current
data
base."
See
Responses
to
the
2007
Baseline
Sub­
Inventory
Information
and
Significant
Comments
for
the
Final
NOx
SIP
Call
(
63
FR
57356,
October
27,
1998),
May
1999
at
9.
In
our
proposed
rule
in
response
to
the
Court's
decision,
we
again
asked
commenters
to
identify
any
specific,
existing
cogeneration
units
that,
without
the
application
of
the
"
one­
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria,

would
be
classified
as
large
EGUs
but
that,
with
the
application
of
such
criteria,
would
be
classified
as
either
large
or
small
non­
EGUs.
One
commenter
stated
that
up
to
16
cogeneration
units
in
the
paper
and
pulp
industry
units
would
be
affected
by
the
change
in
EGU
definition.
However,
Draft
 
Do
not
cite,
quote
or
distribute
78
the
commenter
not
only
failed
to
provide
the
names
of
any
specific
units
but
also
stated
that
it
lacked
sufficient
information
to
determine
whether
any
of
the
units
were
selling
electricity
under
firm
contract
to
the
grid.
In
short,
the
commenter
did
not
really
know
whether
the
16
units
would
actually
be
treated
as
EGUs
if
the
"
one­
third
potential
electrical
output
capacity/
25
MWe
sales"
criteria
were
not
applied.

For
today's
final
rule,
in
light
of
the
lack
of
such
specific
information
in
the
comments,
we
were
unable
to
identify
any
small
cogeneration
units
whose
classification
as
EGUs
or
non­
EGUs
will
change
in
light
of
the
changes
in
the
EGU
and
non­
EGU
definitions
adopted
in
the
final
rule.

The
only
exception
may
be
for
units
at
the
Tobaccoville
facility,
which
are
addressed
above.
However,
for
the
reasons
discussed
above,
we
will
consider
reclassification
of
these
units
during
the
SIP
revision
approval
process.

Further,
it
is
conceivable
that
there
are
other
small
cogeneration
units
that
need
to
be
reclassified
from
EGUs
to
non­
EGUs
and
that,
therefore,
further
adjustments
to
the
budgets
of
particular
States
may
be
necessary.
We
will
also
make
such
further
adjustments
during
the
SIP
approval
process
when
we
receive
the
information
necessary
to
support
such
reclassifications
of
small
cogeneration
units.
Because
Draft
 
Do
not
cite,
quote
or
distribute
79
we
anticipate
that
few,
if
any,
units
currently
treated
in
the
budgets
as
EGUs
qualify
as
small
cogeneration
units,
we
expect
few,
if
any,
revisions
to
the
budgets
resulting
from
today's
final
rule,
and
if
any
revisions
do
result,
we
anticipate
that
they
will
be
very
small
and
will
not
affect
most
States.

In
order
to
facilitate
the
SIP
approval
process,
we
request
participants
in
the
process
of
developing
SIP
revisions
in
response
to
today's
final
rule
to
identify
by
name,
location,
and
plant
and
point
identification
any
cogeneration
unit
that
they
believe
should
be
classified
as
a
large
or
small
non­
EGU
under
the
methodology
in
today's
final
rule
and
that
would
have
been
classified
differently
as
a
large
or
small
EGU
under
the
methodology
in
the
proposed
rule.
We
also
request
identification
by
name,

location,
and
plant
and
point
identification
of
any
cogeneration
unit
that
should
be
classified
as
a
large
or
small
EGU
under
today's
final
rule
methodology
and
that
would
have
been
classified
as
a
large
or
small
non­
EGU
under
the
proposed
methodology.
In
addition,
we
request
information
supporting
any
claimed
EGU,
non­
EGU,
large,
or
small
classification
of
each
identified
unit.

Persons
that
identify
units
as
cogeneration
units
or
small
cogeneration
units
(
under
the
"
one­
third
potential
Draft
 
Do
not
cite,
quote
or
distribute
80
electrical
output
capacity/
25
MWe
sales"
criteria)
should
submit
the
following
information
to
confirm
their
identification:

(
1)
A
description
of
the
facility
to
demonstrate
that
the
facility
meets
the
definition
of
a
"
cogeneration
unit"

under
40
CFR
72.2.

(
2)
Data
describing
the
annual
electricity
sales
from
the
unit
for
every
year
from
the
unit's
commencement
of
operation
through
the
present.
To
provide
this
information,

persons
should
submit
the
same
form
as
they
used
to
report
the
information
to
the
EIA,
or
if
they
have
not
reported
the
information
to
EIA,
provide
the
same
information
on
annual
electricity
sales
as
was
or
would
have
been
required
to
be
reported
to
EIA.

(
3)
Information
stating
and
supporting
the
value
of
the
unit's
maximum
design
heat
input.

B.
What
Are
the
Control
Levels
and
Budget
Calculations
for
Stationary
Reciprocating
Internal
Combustion
Engines
(
IC
Engines)?

In
the
February
22,
2002
action,
we
proposed
that
highly
cost­
effective
controls
are
available
for
stationary
IC
engines.
We
proposed
to
assign
a
90
percent
emissions
decrease
on
average
for
large
natural
gas­
fired
rich­
burn,

diesel,
and
dual
fuel
IC
engines.
For
large
natural
gas­
Draft
 
Do
not
cite,
quote
or
distribute
81
fired
lean­
burn
IC
engines,
we
proposed
to
assign
a
percent
reduction
from
within
the
range
of
82
to
91
percent.
Based
on
available
data
regarding
demonstrated
costs,

effectiveness,
availability,
and
feasibility
of
low
emission
combustion
(
LEC)
technology,
and
consideration
of
comments
received
in
response
to
the
proposal,
we
stated
that
we
would
determine
a
percent
reduction
number
to
use
in
calculating
this
portion
of
the
NOx
SIP
Call
budget
decrease.

Today,
we
are
recalculating
the
budgets
to
reflect
a
control
level
of
82
percent
for
the
natural
gas­
fired
leanburn
IC
engines.
Because
the
vast
majority
of
large
natural
gas­
fired
IC
engines
are
lean
burn,
we
are
applying
the
82
percent
reduction
to
all
large
natural
gas­
fired
IC
engines
for
the
purpose
of
setting
this
portion
of
the
budget.
For
the
other
IC
engine
subcategories
(
diesel
and
dual
fuel)
we
are
using
90
percent
control,
as
proposed.

1.
Determination
of
Highly
Cost­
effective
Reductions
and
Budgets.

As
described
in
the
NOx
SIP
Call
final
rule,
after
determining
the
degree
to
which
NOx
emissions,
as
a
whole
from
the
particular
upwind
States,
contribute
to
downwind
nonattainment
or
maintenance
problems,
we
determined
whether
any
amounts
of
the
NOx
emissions
may
be
eliminated
through
Draft
 
Do
not
cite,
quote
or
distribute
82
controls
that,
on
a
cost­
per­
ton
basis,
may
be
considered
to
be
highly
cost
effective.
By
examining
the
cost
effectiveness
of
NOx
controls,
we
determined
that
an
average
of
approximately
$
2,000
per
ton
removed
is
highly
cost
effective.
We
first
projected
the
total
amount
of
NOx
emissions
that
sources
in
each
covered
State
would
emit,

accounting
for
their
projected
growth
and
measures
required
under
the
CAA,
in
2007.
We
then
projected
the
total
amount
of
NOx
emissions
that
each
of
those
States
would
emit
in
2007
if
each
State
applied
the
highly­
cost
effective
measures
(
the
State's
budget).
The
difference
between
the
2007
base
inventory
and
the
budget
for
each
State
is
that
State's
"
significant
contribution"
to
downwind
nonattainment.
For
a
more
detailed
discussion
of
the
determination
of
cost­
effective
reductions
and
budgets,
see
the
October
27,
1998
NOx
SIP
Call
(
63
FR
57399­
57403
and
57405,
respectively).

2.
What
Are
the
Key
Comments
We
Received
Regarding
IC
Engines?

The
following
describes
key
comments
regarding
IC
engines
and
provides
our
responses.
Additional
comments
and
responses
are
contained
in
the
Response
to
Comments
(
RTC)

document
associated
with
this
rulemaking.
Related
information
is
also
contained
in
the
Technical
Support
Draft
 
Do
not
cite,
quote
or
distribute
19
Note:
Use
of
a
higher
uncontrolled
value
would
result
in
a
higher
overall
percentage
control
value.
For
example,
assuming
a
control
level
of
3.0
g/
bhp­
hr
the
percentage
control
value
would
be
82
percent
using
16.8
g/
bhp­
hr
as
the
uncontrolled
level
and
75
percent
using
12.0
as
the
uncontrolled
level.

83
Document
(
TSD)
(
revised
version)
associated
with
this
rulemaking.

a.
Level
of
NOx
control.

(
1)
NOx
uncontrolled
emission
rate.

Comment:
Several
commenters
suggested
that
we
should
rely
on
the
July
2000
AP­
42
emission
factor
documents
(
Docket
No.

OAR­
2001­
0008,
Item
Nos.
XII­
D­
09
and
XII­
D­
10)
for
the
average
uncontrolled
emission
rates
[
11.7
g/
bhp­
hr
(
grams
per
brake
horsepower­
hour)
for
2­
stroke
engines
and
15.1
g/
bhp­
hr
for
4­
stroke
engines].
The
commenters
object
to
our
use
of
a
higher
value
(
16.8
g/
bhp­
hr)
as
the
uncontrolled
level.
19
The
commenters
state
that
the
July
2000
AP­
42
factors
are
best
because:

°
they
are
based
on
actual
engine
emission
tests;

°
the
engines
tested
are
similar
to
"
large"
SIP
call
engines;

°
they
are
not
based
on
horsepower
categories;

°
they
tested
both
2­
and
4­
stroke
engines;
and
°
they
have
documented
quality
control.

Response:
We
reviewed
the
data
used
to
update
AP­
42.
In
Draft
 
Do
not
cite,
quote
or
distribute
20
See
footnotes
"(
a)"
to
Tables
3.2­
1
and
3.2­
2
in
the
July
2000
AP­
42
document.

84
order
to
focus
on
the
large
engines
addressed
in
the
NOx
SIP
Call,
as
suggested
by
commenters,
we
examined
test
data
from
those
engines
greater
than
2,000
horsepower
(
hp)
operating
at
greater
than
90
percent
load.
The
large
engines
in
this
data
base
cover
only
2
engine
models
and
8
tests;
both
models
are
4­
stroke
engines.
According
to
comments
from
the
Interstate
Natural
Gas
Association
of
America
(
INGAA),
about
85
percent
of
the
large
engines
in
the
SIP
Call
area
are
2­

stroke.
Furthermore,
as
described
in
the
July
2000
AP­
42
document,
the
data
presented
do
not
differentiate
between
uncontrolled
lean­
burn
engines
and
engines
that
may
be
turbocharged.
20
Thus,
the
average
"
uncontrolled"
emissions
reported
may
include
some
engines
with
lower
NOx
emissions
due
to
the
turbocharging.
We
conclude
that
this
data
base
is
helpful
but
too
limited
to
stand
by
itself
considering
the
large
amount
of
data
available
from
other
sources.

Instead,
the
AP­
42
data
must
be
reviewed
along
with
other
data
as
described
below.

Comment:
Commenters
state
that
our
16.8
g/
bhp­
hr
average
is
derived
from
"
mostly"
new
engine
models
in
1991,
not
the
entire,
current
population
of
existing
engines.
According
to
commenters,
the
1994
ACT
document
numbers
are
not
Draft
 
Do
not
cite,
quote
or
distribute
21
The
letter
addressed
concerns
regarding
the
OTC's
development
of
a
set
of
model
NOx
rules,
including
rules
for
stationary
IC
engines.

85
representative
of
older
SIP
Call
type
engines,
the
details
of
the
data
are
unavailable,
and
the
16.8
value
cannot
be
replicated.
The
commenters
indicate
that
our
weighted
average
approach
does
not
correspond
to
engine
models
in
the
SIP
Call
population,
that
the
NOx
1994
ACT
reflects
1991
manufacturer's
letters
for
new,
4­
stroke
engines,
and
that
we
need
to
make
these
letters
available.

Response:
We
have
examined
data
from
the
pipeline
industry,

data
recently
collected
by
the
Agency,
and
data
from
the
1994
ACT
document
(
see
RTC
or
TSD
for
details).
These
include
data
from
large
engines
covered
by
the
SIP
Call
as
suggested
by
some
commenters.
We
believe
the
data
support
the
16.8
value
proposed,
as
described
below.

Emissions
data
compiled
by
three
pipeline
industry
companies
provide
support
to
the
16.8
g/
bhp­
hr
value
proposed
by
us
or
a
slightly
higher
value.
Test
data
are
contained
in
two
letters
to
the
Ozone
Transport
Commission
(
OTC)
in
November
2000.
Based
on
a
survey
of
LEC
retrofit
installation
in
SIP
Call
States,
two
pipeline
companies
in
a
November
20,
2000
letter
to
the
OTC,
21
presented
data
on
pre­
LEC
and
post­
LEC
emissions
for
86
engines
in
SIP
Call
States.
Most
of
the
engines
are
relatively
large,
at
2000
Draft
 
Do
not
cite,
quote
or
distribute
22
The
weighted
average
was
calculated
as
follows:
(
66
x
18.2
+
14
x
14.1
+
62
x
17.6)
divide
sum
by
142
=
17.5.

86
hp
or
greater.
Table
1
of
the
letter
summarizes
the
data
and
states
that
the
average
uncontrolled
NOx
emissions
level
for
these
86
engines
is
16.8
g/
bhp­
hr,
identical
to
the
level
we
proposed.
Considering
only
those
engines
greater
than
or
equal
to
2,000
hp,
there
are
66
engines
with
an
average
uncontrolled
emissions
rate
of
18.2
g/
hp­
hr
(
see
RTC
or
TSD
for
details).
Additional
data
in
the
same
letter
provide
pre­
LEC
and
post­
LEC
data
for
20
engines.
The
letter
states
that
the
average
uncontrolled
NOx
emissions
for
the
20
engines
is
14.1
g/
bhp­
hr.
Another
major
pipeline
company
also
sent
a
letter
(
November
22,
2000)
to
the
OTC
presenting
uncontrolled
and
RACT
emission
rates
for
62
engines
retrofit
with
LEC
(
see
RTC
or
TSD
for
details).
The
average
uncontrolled
emission
rate,
considering
all
62
engines
from
this
data
set,
is
17.6
g/
bhp­
hr.
The
weighted
average
of
these
three
data
sets
is
17.5
g/
bhp­
hr.
22
In
response
to
comments,
we
collected
additional
test
data
to
better
determine
controlled
and
uncontrolled
emission
levels
from
the
current
population
of
large
engines
in
the
NOx
SIP
Call
area.
Forty­
two
data
points
were
collected
(
see
RTC
or
TSD
for
details).
The
average
uncontrolled
NOx
level
from
this
data
is
16.7
g/
bhp­
hr,
Draft
 
Do
not
cite,
quote
or
distribute
23
For
large
lean­
burn
IC
engines
in
the
NOx
SIP
Call
States,
2­
stroke
engines
represent
83
percent
of
the
total
large
engines
and
85
percent
of
the
total
large
engine
horsepower.
(
From
INGAA's
April
22,
2002
comments,
pages
2
and
10.)(
Docket
No.
OAR­
2001­
0008,
Item
No.
XII­
D­
09).

87
nearly
identical
to
the
proposed
level
of
16.8
g/
bhp­
hr.

As
suggested
by
commenters,
we
also
examined
the
available
data
separately
for
2­
and
4­
stroke
engines.
The
test
data
for
the
large
IC
engines
in
the
SIP
Call
area
indicate
uncontrolled
levels
of
16.4
and
18.9,
respectively,

for
the
2­
and
4­
stroke
engines.
Using
information
from
the
pipeline
industry
that
about
85
percent
of
the
engines
in
the
SIP
Call
area
are
2­
stroke,
the
weighted
average
of
the
16.4
and
18.9
values
is
16.8,
identical
to
our
proposed
value.
23
As
described
in
the
1994
ACT
document
for
stationary
IC
engines,
uncontrolled
emission
levels
were
provided
to
us
by
several
engine
manufacturers.
Most
manufacturers
provided
emission
data
only
for
current
production
engines,
but
some
included
older
engine
lines
as
well.
The
manufacturers'

letters
were
placed
in
the
docket.
These
emission
levels
were
tabulated
and
averaged
for
engines
with
similar
power
ratings.
For
engines
greater
than
2000
hp,
the
average
uncontrolled
emission
rate
from
55
engines
is
approximately
16.8
g/
bhp­
hr.
As
noted
in
the
TSD,
there
are
several
Draft
 
Do
not
cite,
quote
or
distribute
88
reasons
to
use
the
1994
ACT
document
data.
Using
the
applicable
1994
ACT
document
is
consistent
with
how
we
treated
other
non­
EGU
source
categories
in
the
NOx
SIP
Call
rulemaking.
The
1994
ACT
document
provides
a
comprehensive
look
at
the
IC
engine
class
and
has
the
advantage
of
using
a
consistent
data
set
for
uncontrolled
emissions,
costs,
and
controls.
The
1994
ACT
document
uses
a
large
data
set
from
which
to
draw
conclusions.
The
1994
ACT
document
test
data
are
available
in
several
horsepower
size
categories
which
is
important
since
we
chose
not
to
calculate
emission
reductions
from
the
smaller
IC
engines.

In
summary,
based
on
the
1994
ACT
document
data,
the
data
contained
in
the
industry
letters
to
OTC
and
data
we
recently
collected,
there
is
considerable
agreement
with
the
16.8
g/
bhp­
hr
uncontrolled
emission
rate
value
that
we
proposed.
The
data
do
not
support
commenters
suggestion
for
a
lower
value,
namely
11.7
g/
bhp­
hr
for
2­
stroke
engines
and
15.1
g/
bhp­
hr
for
4­
stroke
engines.
Therefore,
we
conclude
that
use
of
the
16.8
g/
bhp­
hr
level
is
appropriate
to
represent
average,
uncontrolled
emissions.

(
2)
NOx
controlled
emission
rate
with
LEC
technology.

Comment:
Appendix
B
to
INGAA's
April
22,
2002
comment
letter
lists
226
lean­
burn
large
and
small
IC
engines
in
SIP
Draft
 
Do
not
cite,
quote
or
distribute
89
Call
States
that
are
retrofit
with
LEC
technology
and
for
which
they
could
obtain
State
NOx
permit
limits.
The
average
post­
control
NOx
permit
levels
for
2­
stroke
and
4­

stroke
engines
are
reported
to
be
5.0
and
3.7,
respectively.

The
INGAA
states
that
NOx
permit
limits
are
appropriate
for
use
in
calculating
the
average
post­
control
emission
rate
for
lean­
burn
engines
in
the
NOx
SIP
Call
area
for
the
following
reasons:

°
these
engines
are
located
in
the
NOx
SIP
Call
States,
and
represent
the
same
makes
and
models
as
the
large
NOx
SIP
Call
engines,

°
these
engines
operate
under
State
permit
limits
that
reflect
the
emission
control
achieved
by
LEC
on
actual
and
identified
individual
engines,

°
the
emission
control
limits
were
established
as
the
result
of
a
formal
regulatory
process
conducted
by
the
State
permitting
agencies,
and
°
the
LEC
retrofits
are
consistent
with
the
technology
and
costs
identified
by
our
NOx
SIP
Call
TSDs.

Response:
We
disagree
that
permit
limits
are
appropriate
for
determining
the
post­
control
emission
rate.
Permit
limits
generally
do
not
reflect
the
actual
emission
rate
and,
thus,
are
not
appropriate
to
determine
the
emission
Draft
 
Do
not
cite,
quote
or
distribute
24
See
docket
for
e­
mail
from
John
Patton
dated
May
30,
2002
and
attachments.
(
Docket
No.
OAR­
2001­
0008,
Item
No.
0917).

25
See
Docket
No.
OAR­
2001­
0008
(
Legacy
No.
A­
96­
56),
Item
No.
XII­
M­
01
for
November
20,
2000
letter,
appendices
A
&
B.

26
See
Docket
No.
OAR­
2001­
0008,
Item
No.
0921
for
June
5,
2002
fax
from
Randy
Hamilton.

27
Ventura
County
Rule
74.9
(
in
effect
September
1989
to
December
1993)
applied
to
engines
greater
than
or
equal
to
100
hp
and
required
125
ppm
(
1.7
g/
bhp­
hr)
or
80
percent
control.
Current
Ventura
County
Rule
74.9
requires
45
ppmv
(
0.6
g/
bhp­
hr)
or
94
percent
control.
For
best
available
retrofit
control
technology,
California
Air
Resources
Board
selected
for
engines
greater
than
or
equal
to
100
hp
65
ppm
(
0.9
g/
bhp­
hr)
or
90
percent
control,
based
on
Sacramento
90
rates
to
be
expected
from
installation
of
LEC
technology.

For
example,
State
records
indicate
permit
limits
of
18
and
8
even
though
LEC
technology
is
in
place
and
the
target
emission
rate
in
the
State
RACT
plan
is
3
for
both
engines.
24
In
another
case,
the
permit
level
is
3.0,
but
the
actual
rate
is
reported
as
1.7.25
The
permit
limits
for
six
engines
at
a
station
in
one
State
are
3.0
g/
bhp­
hr
while
the
test
data
show
emissions
at
less
than
1.1
g/
bhp­
hr
for
each
engine.
26
We
agree
with
the
comment
that
LEC
retrofits
are
consistent
with
the
costs
identified
by
our
NOx
SIP
Call
TSDs.

Further,
if
we
were
to
use
permit
rates,
it
makes
no
sense
to
ignore
permit
limits
set
in
areas
outside
the
SIP
Call
region.
California
and
Texas
permits,
for
example,

have
very
low
emission
rates
for
IC
engines.
27
The
permit
Draft
 
Do
not
cite,
quote
or
distribute
Air
Quality
Management
Division
Rule
412.
In
Texas,
requirements
applicable
in
Houston
are
0.5­
0.6
g/
bhp­
hr
for
lean­
burn
engines.

28
We
proposed
to
select
a
value
within
the
range
of
82
to
91
percent
control
(
1.5­
3.0
g/
bhp­
hr
controlled
level
assuming
16.8
uncontrolled
level)
based
primarily
on
information
in
the
1994
ACT
document.

29
This
equates
to
a
5.0
g/
bhp­
hr
limit,
assuming
an
uncontrolled
level
of
16.8
g/
bhp­
hr.

91
levels
suggested
by
commenters
are
limited
because
the
permits
generally
reflect
RACT
requirements.
However,

highly
cost­
effective
controls
under
the
NOx
SIP
Call
are
not
limited
to
RACT­
level
stringency
and
should
take
into
account
improvements
in
control
efficiency
and
cost
effectiveness
that
have
occurred
over
the
last
several
years
since
the
RACT
generation
of
controls.

Comment:
Commenters
state
that
data
we
used
to
support
the
proposed
controlled
levels28
are
for
new
or
rebuilt
engines­

­
not
retrofits­­
and
therefore
cannot
be
relied
upon.
They
suggest
we
should
use
NOx
limits
for
engines
retrofit
with
LEC
in
State
permits
and
that
the
permits
suggest
no
more
than
a
70
percent
reduction.
29
Several
commenters
indicate
it
is
important
to
examine
the
specific
engines
in
the
SIP
Call
States
to
determine
whether
the
reductions
we
assumed
are
achievable.
Comments
suggest
that
industry
experience
through
RACT
retrofits,
has
demonstrated
that
the
stringent
emission
rates
of
1.5
to
3.0
g/
bhp­
hr
are
not
achievable
on
Draft
 
Do
not
cite,
quote
or
distribute
30
For
example,
November
30,
1998
letter
from
INGAA
to
EPA
Docket
No.
OAR­
2001­
0008,
Item
No.
0919),
February
16,
1999
memo
from
INGAA
to
Tom
Helms,
EPA
(
Docket
No.
OAR­
2001­
0008,
Item
No.
XII­
K­
38),
and
April
26,
2002
comment
letter
from
Kinder
Morgan
(
Natural
Gas
Pipeline
Company
of
America)(
Docket
No.
OAR­
2001­
0008,
Item
No.
XII­
D­
24).

92
many
engines
and
the
average
emission
reduction
to
be
expected
for
LEC
retrofits
is
70
percent.
Comments
from
the
New
Hampshire
Department
of
Environmental
Services
expressed
support
for
a
90
percent
control
level.

Response:
The
commenters
and
EPA
agree
that
LEC
technology
is
a
proven
technology
for
natural
gas­
fired
lean­
burn
engines.
30
There
is
not
agreement,
however,
on
the
appropriate
level
of
control
to
assume
from
installation
of
the
LEC
technology.
In
response
to
comments,
we
collected
additional
test
data,
including
data
representative
of
emissions
from
large
engines
in
the
SIP
Call
area.
To
determine
the
appropriate
level
of
control,
we
examined
all
available
data,
including
data
from
State
permits
and
test
data
on
new,
rebuilt,
and
retrofit
engines
with
LEC
technology.
These
data
were
placed
in
the
docket.
A
summary
of
the
data
is
provided
below.
As
suggested
by
commenters,
the
data
have
been
organized
to
show
LEC
retrofit
test
data
for
large
engine
models
found
in
the
NOx
SIP
Call
area.

The
INGAA
in
their
April
22,
2002
comments,
identified
Draft
 
Do
not
cite,
quote
or
distribute
93
the
most
common
models
of
large
natural
gas
transmission
engines
in
the
SIP
Call
area.
In
addition,
INGAA
identified
engines
that
had
been
retrofit
with
LEC
in
the
SIP
Call
area.
In
response
to
these
comments,
we
contacted
the
various
EPA
Regional
Offices
to
obtain
information
on
specific
large
lean
burn
engines
used
by
the
gas
pipeline
industry
that
have
been
retrofit
with
LEC
in
the
SIP
Call
area.
Data
from
the
EPA
Regional
Offices
and
other
emission
test
results
were
obtained.
The
results
for
large
engines
in
the
SIP
Call
area
show
that
43
of
the
58
tests
have
NOx
emission
levels
at
or
below
3.0
g/
bhp­
hr
(
see
RTC
or
TSD
for
details).
The
LEC
technology
retrofit
on
these
large
engines
achieved,
on
average,
an
emission
rate
of
2.3
g/

bhphr

As
suggested
by
commenters,
we
also
examined
the
available
data
separately
for
2­
and
4­
stroke
engines
(
see
TSD
for
details).
Test
data
for
the
large
IC
engines
in
the
SIP
Call
area
indicate
controlled
levels
of
2.3
and
2.5,

respectively,
for
the
2­
and
4­
stroke
engines.
Assuming
85
percent
of
the
engines
in
the
SIP
Call
area
are
2­
stroke,

the
weighted
average
of
the
2.3
and
2.5
values
is
2.3.

As
described
in
the
TSD,
looking
at
a
broader
set
of
data
yields
similar
results.
That
is,
considering
data
from
large
engines
both
inside
and
outside
the
SIP
Call
area
Draft
 
Do
not
cite,
quote
or
distribute
31
"
Stationary
Reciprocating
Internal
Combustion
Engines:
Updated
Information
on
NOx
Emissions
and
Control
Techniques,"
EC/
R
Incorporated,
September
1,
2000,
page
4­
5
(
Docket
No.
OAR­
2001­
0008
(
Legacy
Docket
No.
A­
96­
56),
Item
No.
XII­
K­
43).

94
shows
that
60
of
the
79
tests
have
NOx
emission
levels
at
or
below
3.0
g/
bhp­
hr
(
see
TSD
for
details).
The
LEC
technology
retrofit
on
these
large
engines
achieved,
on
average,
an
emission
rate
of
2.2
g/
bhp­
hr.
Considering
the
similarity
of
the
resulting
average
controlled
emission
rates
and
the
ample
set
of
data
for
large
engines
in
the
SIP
Call
area,
we
agree
with
commenters
that
it
is
reasonable
to
focus
on
the
set
of
data
for
large
engines
in
the
SIP
Call
area.

The
set
of
data
for
large
engines
in
the
SIP
Call
area
cover
80
percent
of
the
engine
models
in
the
NOx
SIP
Call
area.
However,
emission
rates
for
some
of
the
engine
models
for
which
test
data
are
not
available
are
likely
to
be
higher
than
the
2.3
average
value.
For
example,
Worthington
and
Nordberg
engines
are
known
to
be
difficult
to
retrofit.

One
vendor
reported
achieving
a
level
of
6
g/
bhp­
hr
for
certain
Worthington
engines.
31
As
noted
in
the
TSD,
a
Worthington
UTC
165
in
New
York
reduced
NOx
emissions
to
4.4
g/
hp­
hr.
A
pipeline
company
commented
that
they
operate
six
Worthington
engines
and
that
4.0
g/
bhp­
hr
is
their
targeted
Draft
 
Do
not
cite,
quote
or
distribute
32
Docket
No.
OAR­
2001­
0008
(
Legacy
Docket
No.
A­
96­
56),
Item
No.
XII­
D­
24.

95
emission
reduction
level,
based
on
vendor
projections.
32
Thus,
it
appears
that
a
4.0
to
6.0
g/
bhp­
hr
level
is
achievable
on
these
difficult
to
retrofit
Worthington
engines.
At
this
time,
we
believe
that
5.0
g/
bhp­
hr
is
a
reasonable
emission
rate,
on
average,
for
engines
known
to
be
difficult
to
retrofit.
Although
not
all
of
the
20
percent
of
engine
models
for
which
test
data
are
not
available
are
likely
to
be
difficult
to
retrofit,
we
believe
it
is
reasonable
to
treat
these
engines
as
one
group
and
to
conservatively
assume
that
this
group
of
engines
would
achieve
a
5.0
level,
on
average.

In
summary,
based
on
the
available
test
data,
we
believe
it
is
reasonable
to
assume
about
80
percent
of
the
large
engines
in
the
SIP
Call
area
are
able
to
meet
a
2.3
level,
on
average,
and
that
20
percent
are
able
to
meet
a
5.0
level,
on
average
with
LEC
technology.
Thus,

calculating
the
weighted
average
for
installation
of
LEC
technology
retrofit
on
all
of
these
large
IC
engines
results
in
a
2.8
g/
bhp­
hr
limit.

Comment:
In
their
letter
of
October
25,
2002,
INGAA
commented
that
the
additional
data
we
collected
includes
data
on
27
lean­
burn
engines
and
the
data
indicate
that
the
Draft
 
Do
not
cite,
quote
or
distribute
96
average
retrofit
LEC
technology
level
is
2.7
g/
bhp­
hr
for
2­

stroke
engines,
which
represent
the
bulk
of
the
engine
horsepower
in
the
SIP
Call
area.
In
addition,
INGAA
commented
that
the
data
reported
on
the
IC
engines
retrofit
with
LEC
have
a
number
of
problems,
including
scarcity
of
before­
and­
after
tests
on
the
same
engine,
and
the
absence
of
data
on
load
or
other
operating
conditions
of
the
tested
engines.
The
INGAA
also
commented
that
the
vendor
references
we
cited
indicate
that
the
retrofit
LEC
technology
is
intended
to
result
in
emissions
to
meet
a
3
g/
bhp­
hr
limit.

Response:
We
agree
that
test
data
cited
by
INGAA
and
the
vendor
estimates
indicate
that
the
average
retrofit
LEC
technology
level
is
in
the
2.7
to
3.0
g/
bhp­
hr
range.
We
also
note
that
these
comments
are
fairly
consistent
with
a
November
20,
2000
letter
to
the
OTC
from
two
pipeline
companies
which
recommended
a
limit
of
no
less
than
3.0
g/
bhp­
hr,
with
an
alternative
standard
of
no
more
than
80
percent
reduction.
This
range
is
also
consistent
with
the
available
test
data
for
large
engines
in
the
SIP
Call
area
which
indicates
an
average
value
of
2.8
g/
bhp­
hr.

As
INGAA
points
out,
there
is
some
uncertainty
in
the
test
data
due,
for
example,
to
lack
of
data
on
operating
load
in
some
cases.
In
addition,
there
is
some
uncertainty
Draft
 
Do
not
cite,
quote
or
distribute
97
because
of
the
lack
of
data
for
all
engine
models.
Due
to
this
uncertainty,
we
believe
it
is
appropriate
to
consider
a
minor
adjustment
to
the
control
level
suggested
by
the
test
data.
The
difference
between
selecting
a
2.8
value
(
suggested
primarily
by
the
test
data)
or
a
3.0
value
(
suggested
by
some
pipeline
companies
and
vendor
comments)

for
the
controlled
emission
rate
is
very
small,
only
a
1
percent
difference.
That
is,
the
two
values
result
in
either
an
82
percent
or
83
percent
control
level,
assuming
a
16.8
g/
bhp­
hr
uncontrolled
value.
Thus,
while
our
analysis
of
the
test
data
indicates
a
2.8
value
is
reasonable,
in
view
of
the
recommended
3.0
level
from
some
industry
and
vendor
comments,
and
considering
the
uncertainties
in
the
data
and
the
small
difference
in
the
resultant
control
level,
we
believe
it
is
appropriate
to
select
the
upper
range
of
the
control
levels
proposed,
namely
3.0
g/
bhp­
hr.

(
3)
Level
of
NOx
control
to
assume
for
budget
calculation.

Comment:
In
the
proposed
rule
we
invited
comment
on
how
many
of
the
large
natural
gas­
fired
IC
engines
are
from
lean­
burn
operation
and
how
many
are
from
rich­
burn.
The
INGAA
commented
that
156
of
the
168
large
engines
listed
in
the
NOx
SIP
Call
Inventory
that
have
Standard
Industrial
Classification
codes
associated
with
the
natural
gas
Draft
 
Do
not
cite,
quote
or
distribute
98
transmission
industry
are
lean­
burn
models,
with
one
exception.
For
the
purposes
of
calculating
the
IC
engine
portion
of
the
NOx
SIP
Call
State
budgets,
INGAA
recommended
that
we
should
assume
that
all
the
large
natural
gas­
fired
stationary
engines
in
the
inventory
are
lean
burn.
Comments
from
the
State
of
Indiana
indicated
there
are
no
large,

rich­
burn
engines
in
the
State.

Response:
As
pointed
out
by
the
commenters,
the
vast
majority
of
large
IC
engines
in
the
NOx
SIP
Call
inventory
are
natural
gas­
fired
lean­
burn
engines.
Furthermore,
the
emission
inventory
does
not
contain
sufficient
detail
to
determine
exactly
which
engines
are
lean
burn
and
which
are
not.
For
these
reasons,
we
agree
with
the
comment
that
it
is
reasonable
to
assume
that
all
the
large
natural
gas
stationary
engines
in
the
inventory
are
lean
burn
for
the
purposes
of
calculating
the
IC
engine
portion
of
the
NOx
SIP
Call
State
budgets.

Comment:
As
discussed
above,
we
received
comments
on
the
uncontrolled
and
controlled
levels
for
natural
gas­
fired
engines.
Several
commenters
recommended
no
more
than
70
percent
reduction,
based
primarily
on
permit
data.
One
State
recommended
90
percent
reduction.

Response:
The
percent
reduction
determination
is
based
primarily
on
two
factors
 
the
uncontrolled
and
controlled
Draft
 
Do
not
cite,
quote
or
distribute
99
levels
 
which
are
discussed
above.
We
reviewed
information
submitted
by
commenters
and
collected
additional
data
in
response
to
concerns
raised
by
commenters.
Considering
all
of
the
available
data,
we
have
determined
that
the
appropriate
uncontrolled
and
controlled
values
are
16.8
and
3.0,
respectively.
As
a
result,
we
believe
that
application
of
highly
cost­
effective
controls
on
large
natural
gas­
fired
IC
engines
will
achieve,
on
average,
an
82
percent
reduction.
Therefore,
82
percent
is
used
for
purposes
of
calculating
this
portion
of
the
NOx
SIP
Call
budget.

b.
Flexibility/
Averaging.

Comment:
Several
commenters
noted
that
the
response
of
IC
engines
to
retrofit
NOx
controls
is
highly
variable
and
that
the
average
NOx
reduction
used
to
calculate
the
NOx
SIP
Call
budgets
is
not
necessarily
the
level
that
all
large
engines
can
achieve.
Because
of
this
variability,
these
commenters
suggest
that
State
air
agencies
should
assign
NOx
reductions
to
the
owners
or
operators
of
IC
engines,
but
not
attempt
a
uniform
definition
of
the
required
control
technology,
or
specification
of
a
single
compliance
limit.
The
commenters
suggest
that
we
include
language
in
the
final
rule
stating
that
we
recommend,
and
will
approve,
SIPs
which
provide
that
owners
or
operators
of
large
engines
in
the
NOx
SIP
Call
inventory
develop
company­
specific
compliance
plans
to
Draft
 
Do
not
cite,
quote
or
distribute
100
demonstrate
achievement
of
NOx
reductions.
In
addition
to
describing
the
standards
for
emissions
reduction
averaging
in
the
final
rule,
commenters
suggested
that
we
issue
a
guidance
letter
to
the
States
urging
them
to
provide
flexibility
for
IC
engines
and
explaining
how
to
do
that.

The
industry
lists
a
number
of
advantages
to
the
company
compliance
plan
approach
to
meeting
the
engine
NOx
reductions
in
the
NOx
SIP
Call
Rule:

°
Engine
owners
and
operators
would
accept
enforceable
and
verifiable
measures
to
control
engines
to
meet
assigned
NOx
SIP
Call
reductions.

°
Based
on
the
company
compliance
plans,
States
would
be
able
to
clearly
demonstrate
to
us
their
compliance
with
Phase
II
of
the
NOx
SIP
Call.

°
The
EPA,
States,
and
regulated
companies
would
not
have
to
work
through
the
technical
confusion
of
definitions
of
lean­
burn
and
rich­
burn
engines,

and
whether
individual
engines
could
in
fact
achieve
certain
control
levels
with
a
prescribed
control
technology.

°
Compliance
with
NOx
SIP
Call
requirements
could
be
achieved
with
minimum
impacts
on
cost,
natural
gas
capacity,
and
operational
reliability.

One
pipeline
company
stated
that
we
should
encourage
Draft
 
Do
not
cite,
quote
or
distribute
33
August
22,
2002
memo
from
Lydia
Wegman
to
EPA
Regional
Air
Directors
providing
guidance
on
issues
related
to
stationary
IC
engines
and
the
NOx
SIP
Call
(
Docket
No.
OAR­
2001­
0008
(
Legacy
Docket
No.
A­
96­
56),
Item
No.
XII­
C­
115).

101
States
implementing
the
engine
portion
of
the
NOx
SIP
Call
to
focus
primarily
on
the
population
of
large
engines
which
emitted
more
than
1
ton
per
day
during
the
1995
ozone
season
and
which
formed
the
basis
for
our
calculation
of
the
desired
emissions
reductions.
Retrofitting
this
population
of
engines
is
more
feasible
and
is
the
most
cost­
effective
method
for
achieving
reductions
due
to
economies
achieved
by
controlling
larger
sources.

Response:
We
addressed
this
issue
in
a
guidance
memorandum
dated
August
22,
2002.
As
discussed
in
the
reference
memorandum,
33
where
States
choose
to
regulate
large
IC
engines,
we
encourage
the
States
to
allow
owners
and
operators
of
large
IC
engines
the
flexibility
to
achieve
the
NOx
tons/
season
reductions
by
selecting
from
among
a
variety
of
technologies
or
a
combination
of
technologies
applied
to
various
sizes
and
types
of
IC
engines.
Flexibility
would
be
helpful
as
companies
take
into
account
that
individual
engines
or
engine
models
may
respond
differently
to
control
equipment.
That
is,
while
certain
controls
are
known
to
have
a
specific
average
control
effectiveness
for
an
engine
population,
some
individual
engines
that
install
the
Draft
 
Do
not
cite,
quote
or
distribute
102
controls
would
be
expected
to
be
above
and
some
below
that
average
control
level,
simply
because
it
is
an
average.

Although
the
issue
of
flexibility
does
not
affect
the
setting
of
the
NOx
SIP
Call
budget,
it
is
an
important
issue
as
States
take
steps
to
meet
their
NOx
SIP
Call
requirements.

During
the
SIP
development
process,
the
States
may
establish
a
NOx
tons/
season
emissions
decrease
target
for
individual
companies
and
then
provide
the
companies
with
the
opportunity
to
develop
a
plan
that
would
achieve
the
needed
emissions
reductions.
The
companies
may
select
from
a
variety
of
control
measures
to
apply
at
their
various
emission
units
in
the
State
or
portion
of
the
State
affected
under
the
NOx
SIP
Call.
These
control
measures
would
be
adopted
as
part
of
the
SIP
and
must
yield
enforceable
and
demonstrable
reductions
equal
to
the
NOx
tons/
season
reductions
required
by
the
State.
What
is
important
from
our
perspective
is
that
the
State,
through
a
SIP
revision,

demonstrate
that
all
the
control
measures
contained
in
the
SIP
are
collectively
adequate
to
provide
for
compliance
with
the
State's
NOx
budget
during
the
2007
ozone
season.

c.
New
Source
Review
(
NSR)
Exclusion.

Comment:
Some
commenters
stated
that
the
final
rule
should
provide
an
exemption
from
NSR
regulations
for
IC
engines
Draft
 
Do
not
cite,
quote
or
distribute
34
August
22,
2002
memo
from
Lydia
Wegman
to
EPA
Regional
Air
Directors
providing
guidance
on
issues
related
to
stationary
IC
engines
and
the
NOx
SIP
Call
(
Docket
No.
OAR­
2001­
0008
(
Legacy
Docket
No.
A­
96­
56),
Item
No.
XII­
C­
115).

103
that
install
NOx
controls
for
compliance
with
the
NOx
SIP
Call.
According
to
the
commenters,
installation
of
the
required
emission
controls
will
likely
result
in
increases
in
emissions
of
carbon
monoxide
(
CO)
and/
or
volatile
organic
compounds
(
VOC);
the
resulting
emission
increases
could
exceed
the
"
significant"
levels
for
carbon
monoxide
or
VOC,

thereby
subjecting
those
facilities
to
either
prevention
of
significant
deterioration
(
PSD)
or
nonattainment
NSR
permit
requirements;
and,
this
would
increase
the
compliance
costs.

Pipeline
industry
comments
request
that
we
expressly
state
in
our
final
remand
response
that
installing
controls
on
IC
engines
to
meet
NOx
SIP
Call
requirements
will
not
trigger
NSR
for
NOx
under
the
"
actual­
to­
potential"
test.

Commenters
also
request
that
we
state
that
installing
retrofit
controls
is
an
"
environmentally
beneficial"
action
that
qualifies
for
a
NSR
exclusion
for
any
collateral
increases
of
other
criteria
pollutants.

Response:
As
discussed
in
the
earlier
referenced
memorandum34,
where
sources
choose
to
install
combustion
modification
technology
to
reduce
emissions
of
NOx
at
natural
gas­
fired
lean­
burn
IC
engines,
we
believe
this
Draft
 
Do
not
cite,
quote
or
distribute
35
In
the
Federal
Register
on
December
31,
2002,
EPA
codified/
finalized
the
Pollution
Prevention
Project
exclusion.
In
Table
2,
Environmentally
Beneficial
Pollution
Control
Projects,
LEC
for
IC
engines
is
mentioned.
However,
for
the
present
time,
the
regulatory
changes
generally
only
affect
States
with
delegation
authority
to
implement
the
Federal
PSD
program
which
became
effective
on
March
3,
2003.
For
States
continuing
to
implement
their
existing
programs
for
another
2
to
3
years,
the
August
22,
2002
guidance
memo
mentioned
above,
is
appropriate.

104
action
should
be
considered
by
permitting
authorities
for
exclusion
from
major
NSR
as
a
pollution
control
project.

Further,
the
memo
indicates
that,
unless
information
regarding
a
specific
case
indicates
otherwise,
installation
of
combustion
modification
technology
for
the
purpose
of
reducing
NOx
emissions
at
natural
gas­
fired
lean­
burn
IC
engines
can
be
presumed,
by
its
nature,
to
be
environmentally
beneficial.
We
recently
stated
our
intent
to
modify
the
"
actual
to
potential"
test.
35
In
most
cases,

we
believe
that
LEC
retrofit
technology
will
not
increase
emissions
of
CO
or
VOC
to
the
extent
that
NSR
is
triggered;

in
many
cases,
emissions
of
CO
and
VOC
will
decrease
with
the
installation
of
LEC
technology
(
see
RTC
document
for
details).
Thus,
we
believe
that
the
permit
process
will
not
hamper
efforts
to
install
controls.

d.
Early
Reductions.

Comments:
Industry
comments
recommend
that
we
provide
specific
guidance
in
the
final
rule
that
directs
States
to
Draft
 
Do
not
cite,
quote
or
distribute
105
recognize
emissions
reductions
that
companies
have
made
since
1995
and
that
companies
should
be
allowed
credit
for
emissions
reductions
achieved
since
1995
for
determining
compliance
with
their
portion
of
the
States'
emissions
reductions
required
to
meet
the
emissions
budgets.

Response:
We
addressed
this
issue
in
the
above
mentioned
guidance
memorandum.
As
discussed
in
the
memo,
we
agree
that
creditable
reductions
with
respect
to
the
NOx
SIP
Call
may
include
emission
controls
in
place
during
or
prior
to
1995,
as
well
as
after
1995
for
the
large
engines.
In
addition,
States
generally
may
use
emission
reductions
achieved
after
1995
at
the
smaller
engines
as
part
of
their
NOx
SIP
Call
budget
demonstration.

e.
Presumptive
Technology.

Comment:
Because
of
the
variability
of
gas
pipeline
engines
in
the
NOx
SIP
Call
area,
industry
commenters
suggest
that
State
air
agencies
should
assign
NOx
reductions
to
the
owners
or
operators
of
IC
engines,
but
not
attempt
a
uniform
definition
of
the
required
control
technology,
or
specification
of
a
single
compliance
limit.
There
is
significant
variability
both
in
the
pre­
controlled
emission
levels
of
lean­
burn
engines
and
in
the
response
of
any
particular
engine
to
the
retrofit
installation
of
LEC
technology.
Draft
 
Do
not
cite,
quote
or
distribute
106
Response:
As
suggested,
we
have
dropped
from
the
final
rulemaking
the
definition
of
LEC
retrofit
technology
and
the
presumption
of
NOx
reduction
effectiveness.
The
definition
and
presumption
are
not
necessary
to
establish
the
NOx
budget.
Nevertheless,
we
believe
that,
on
average,
LEC
technology
achieves
an
82
percent
reduction
from
uncontrolled
emissions.

f.
Monitoring.

Comment:
Industry
comments
recommended
that
we
should
specify
in
the
final
rule
the
types
of
monitoring
that
will
be
acceptable.

Response:
We
addressed
this
issue
in
the
August
22,
2002
guidance
memorandum.
As
discussed
in
the
memo,
acceptable
monitoring
is
not
limited
to
those
monitoring
methods
such
as
continuous
or
predictive
emissions
measurement
systems
that
rely
on
automated
data
collection
from
instruments.

Non­
automated
monitoring
may
provide
a
reasonable
assurance
of
compliance
for
IC
engines
provided
such
periodic
monitoring
is
sufficient
to
yield
reliable
data
for
the
relevant
time
periods
determined
by
the
emission
standard.

g.
Emission
Factors
for
2­
and
4­
Stroke
Engines.

Comment:
Some
commenters
asked
us
to
use
separate
emission
factors
for
2­
and
4­
stroke
engines.

Response:
As
described
above,
we
examined
"
uncontrolled"
Draft
 
Do
not
cite,
quote
or
distribute
107
emissions
from
2­
and
4­
stroke
engines
separately
and
concluded
that
the
data
support
the
16.8
value
we
proposed.

We
also
examined
the
available
"
controlled"
data
separately
for
2­
and
4­
stroke
engines.
Test
data
for
the
large
IC
engines
in
the
SIP
Call
area
indicate
controlled
levels
of
2.3
and
2.5,
respectively,
for
the
2­
and
4­
stroke
engines.

Assuming
85
percent
of
the
engines
in
the
SIP
Call
area
are
2­
stroke,
the
weighted
average
of
the
2.3
and
2.5
values
is
2.3.
Thus,
because
the
2­
stroke
engines
dominate
the
SIP
Call
inventory
and
the
controlled
value
for
the
4­
stroke
engines
is
nearly
identical,
there
is
no
benefit
from
using
separate
emission
factors.
Furthermore,
our
emission
inventory
is
not
detailed
enough
to
identify
which
engines
are
2­
or
4­
stroke
engines;
thus,
we
need
to
use
an
average
value
to
represent
the
combined
population
of
large,

leanburn
engines.
We
believe
the
difference
between
the
two
values
is
relatively
small,
there
is
a
great
deal
of
overlap,
some
key
industry
reports
also
use
a
single
value,

the
available
data
for
2­
and
4­
stroke
engines
support
the
value
we
proposed,
control
techniques
are
the
same,
and
we
have
already
subdivided
the
category
of
IC
engines.
For
these
reasons
we
have
chosen
not
to
further
subdivide
the
IC
engines
category.

C.
What
is
Our
Response
to
the
Court
Decision
on
Georgia
Draft
 
Do
not
cite,
quote
or
distribute
36
OTAG
Policy
Paper
approved
by
the
Policy
Group
on
December
4,
1995.

108
and
Missouri?

In
today's
final
action,
we
are
finalizing
our
inclusion
of
only
certain
portions
of
Georgia
and
Missouri
in
the
NOx
SIP
Call
and
revising
their
statewide
budgets
to
reflect
our
inclusion
of
only
sources
in
the
fine
grid
parts
of
both
States.

As
stated
in
the
final
NOx
SIP
Call
Rule,
air
pollution
travels
across
county
and
State
lines
and
it
is
essential
for
State
governments
and
air
pollution
control
agencies
to
cooperate
to
solve
the
problem.
Ozone
transport
is
a
regional
problem
and
we
believe
that
NOx
emissions
reductions
across
the
region
in
amounts
achievable
by
costeffective
controls
is
a
reasonable
step
to
take
to
mitigate
ozone
nonattainment
in
downwind
States
(
63
FR
57362).
These
emissions
reductions,
in
combination
with
other
measures,

will
enable
attainment
and
maintenance
of
the
1­
hour
ozone
NAAQs
in
the
OTAG
region.
36
Since
the
problem
is
a
regional
one,
we
believe
that
all
States
in
the
NOx
SIP
Call
area
must
cooperate
to
solve
the
problem.

By
way
of
background,
we
took
final
action
on
October
27,
1998,
in
the
NOx
SIP
Call
Rule,
to
prohibit
those
amounts
of
NOx
emissions
which
significantly
contribute
to
Draft
 
Do
not
cite,
quote
or
distribute
109
downwind
nonattainment.
See,
NOx
SIP
Call
Rule,
63
FR
57356.
We
determined
the
amount
of
emissions
that
significantly
contribute
to
downwind
nonattainment
by
evaluating:

(
1)
the
overall
nature
of
the
ozone
problem
(
i.
e.

"
collective
contribution");
(
2)
the
extent
of
the
downwind
nonattainment
problems
to
which
the
upwind
State's
emissions
are
linked,
including
the
ambient
impact
of
controls
required
under
the
CAA
or
otherwise
implemented
in
the
downwind
areas;
(
3)
the
ambient
impact
of
the
emissions
from
the
upwind
State's
sources
on
the
downwind
nonattainment
problems;
and
(
4)
the
availability
of
highly
cost
effective
control
measures
for
upwind
emissions.
[
63
FR
57376
(
October
27,
1998)].

As
part
of
our
analyses
of
the
air
quality
factors
we
considered
the
OTAG
modeling
and
our
State­
specific
modeling.
Id.
at
57384.

In
its
modeling,
OTAG
used
grids
drawn
across
most
of
the
eastern
half
of
the
United
States.
The
"
fine
grid"
has
grid
cells
of
approximately
12
kilometers
on
each
side
(
144
square
kilometers).
The
"
coarse
grid"
extends
beyond
the
perimeter
of
the
fine
grid
and
has
cells
with
36
kilometer
resolution.
The
fine
grid
includes
the
area
encompassed
by
a
box
with
the
following
geographic
coordinates
as
shown
in
Draft
 
Do
not
cite,
quote
or
distribute
37
In
addition
to
these
three
factors,
OTAG
considered
three
other
factors
in
establishing
the
geographic
resolution,
overall
size,
and
the
extent
of
the
fine
grid.
These
other
factors
dealt
with
the
computer
limitations
and
the
resolution
of
available
model
inputs.

110
Figure
1,
below:
Southwest
Corner:
92
degrees
West
longitude,
32
degrees
North
latitude;
Northeast
Corner:

69.5
degrees
West
longitude,
44
degrees
North
latitude
(
OTAG
Final
Report,
chapter
2).
The
OTAG
could
not
include
the
entire
Eastern
U.
S.
within
the
fine
grid
because
of
computer
hardware
constraints.

It
is
important
to
note
that
there
were
three
key
factors
directly
related
to
air
quality
which
OTAG
considered
in
determining
the
location
of
the
fine
gridcoarse
grid
line.
37
(
OTAG
Technical
Supporting
Document,

chapter
2,
pg.
6;

www.
epa.
gov/
ttn/
naaqs/
ozone/
rto/
otag/
finalrpt/).

Specifically,
the
fine
grid­
coarse
grid
line
was
drawn
to:

(
1)
include
within
the
fine
grid
as
many
of
the
1­
hour
ozone
nonattainment
problem
areas
as
possible
and
still
stay
within
the
computer
and
model
run
time
constraints,
(
2)

avoid
dividing
any
individual
major
urban
area
between
the
fine
grid
and
coarse
grid,
and
(
3)
be
located
along
an
area
of
relatively
low
emissions
density.
As
a
result,
the
fine
grid­
coarse
grid
line
did
not
track
State
boundaries,
and
Missouri
and
Georgia
were
among
several
States
that
were
Draft
 
Do
not
cite,
quote
or
distribute
38
The
OTAG
recommendation
on
Major
Modeling/
Air
Quality
Conclusions
approved
by
the
Policy
Group,
June
3,
1997
(
62
FR
60318,
appendix
B,
November
7,
1997).

39
The
2007
Base
Case
includes
all
control
measures
required
by
the
CAA.

111
split
between
the
fine
and
coarse
grids.
Eastern
Missouri
and
northern
Georgia
were
in
the
fine
grid
while
western
Missouri
and
southern
Georgia
were
in
the
coarse
grid.

The
analysis
OTAG
conducted
found
that
the
emission
controls
they
examined,
when
modeled
in
the
entire
coarse
grid
(
i.
e.,
all
States
and
portions
of
States
in
the
OTAG
region
that
are
in
the
coarse
grid)
had
little
impact
on
high
1­
hour
ozone
levels
in
the
downwind
ozone
problem
areas
of
the
fine
grid.
38
Examining
the
2007
Base
Case39
NOx
emissions
for
Georgia
indicates
that
the
amount
of
NOx
emissions
per
square
mile
in
the
fine
grid
portion
of
the
State
is
over
60
percent
greater
than
in
the
coarse
grid
part.
In
Missouri,

the
amount
of
NOx
emissions
per
square
mile
in
the
fine
grid
portion
of
the
State
is
more
than
100
percent
greater
(
i.
e.,

more
than
double)
than
in
the
coarse
grid
part.
The
OTAG
concluded
from
its
modeling
that
the
closer
an
upwind
area
is
to
the
downwind
area,
the
greater
the
benefits
in
the
downwind
area
from
controls
in
the
upwind
area.

A
number
of
parties,
including
certain
States
as
well
Draft
 
Do
not
cite,
quote
or
distribute
112
as
industry
and
labor
groups
challenged
the
NOx
SIP
Call
Rule.
Specifically,
Georgia
and
Missouri
industry
petitioners
claimed
that
our
record
supported
inclusion
of
only
eastern
Missouri
and
northern
Georgia
as
contributing
significantly
to
downwind
nonattainment.
The
D.
C.
Circuit
Court
upheld
our
finding
of
significant
contribution
but
vacated
and
remanded
our
inclusion
of
Georgia
and
Missouri.

Michigan
v.
EPA,
213
F.
3d
663
(
D.
C.
Cir.
2000),
cert.

denied,
121
S.
Ct.
1225
(
2001)(
Michigan).
The
Court
found
that
the
NOx
budgets
for
these
States
"
not
only
encompass
the
whole
state
but
are
calculated
on
the
basis
of
hypothesized
cutbacks
from
areas
that
have
not
been
shown
to
have
made
significant
contributions."
Id.
at
684
(
emphasis
in
original).
The
Court
also
found
that
"
EPA
must
first
establish
that
there
is
a
measurable
contribution"
from
the
coarse
grid
portion
of
the
State
before
holding
the
coarse
grid
portion
of
the
State
responsible
for
the
significant
contribution
of
downwind
ozone
nonattainment
in
another
state.
Id.
at
683­
84
(
emphasis
in
original).

Subsequently,
we
made
revisions
to
the
NOx
SIP
Call
Rule
emissions
budgets
in
the
Technical
Amendments
Rulemakings
[
64
FR
26298
(
May
14,
1999);
65
FR
11222
(
March
2,
2000)].
A
group
of
Missouri
Utilities
and
the
City
of
Independence,
Missouri
challenged
our
budget
for
the
State
Draft
 
Do
not
cite,
quote
or
distribute
113
of
Missouri
and
requested
the
Court
to
vacate
the
entire
budget
under
both
the
1­
hour
and
8­
hour
ozone
standards.
In
its
decision,
the
Court
found
"
it
prudent
to
vacate
and
remand
the
TAs
[
technical
amendments]
insofar
as
they
include[
d]
a
budget
for
Missouri
under
any
ozone
standard."

Appalachian
Power
Company
v.
EPA,
251
F.
3d
1026,
1041
(
2001).
The
Court
also
found
that
"[
w]
here
the
agency's
own
data
inculpate
part
of
a
state
and
not
another,
EPA
should
honor
the
resulting
findings."
Id.
at
1040.

In
response
to
the
Court's
decisions,
we
issued
the
February
22,
2002
rule
proposing
to
include
only
fine
grid
parts
of
Georgia
and
Missouri
in
the
NOx
SIP
Call.
We
explained
that
the
Court
in
Michigan
did
not
call
into
question
our
"
proposition
that
the
fine
grid
portion
of
each
State
should
be
considered
to
make
a
significant
contribution
downwind."
(
67
FR
8413).

We
stated
that
based
on
OTAG's
modeling
and
recommendations,
the
technical
support
documents
for
the
NOx
SIP
Call
rulemaking,
and
emissions
data,
we
believed
that
emissions
in
the
fine
grid
parts
of
Georgia
and
Missouri
comprise
a
measurable
or
material
portion
of
the
entire
State's
significant
contribution
to
downwind
nonattainment.

In
addition,
we
explained
that
we
had
performed
State­
by­

State
modeling
for
Georgia
and
Missouri
as
part
of
the
final
Draft
 
Do
not
cite,
quote
or
distribute
114
NOx
SIP
Call
rulemaking.
The
results
of
this
modeling
showed
that
emissions
in
both
Georgia
and
Missouri
make
a
significant
contribution
to
nonattainment
in
other
States.

Moreover,
we
explained
that
the
Court
pointed
out
that
the
fine
grid
portion
of
each
State
lies
closer
to
downwind
nonattainment
areas.
Michigan
v.
EPA,
213
F.
3d
at
683.

We
further
explained
that
for
purposes
of
determining
budgets
for
the
fine
grid
portion,
we
believed
that
OTAG
modeling
should
be
used
with
an
adjustment
for
counties
that
straddle
the
line
separating
the
fine
grid
and
coarse
grid.

We
also
explained
that
we
would
base
our
overall
NOx
emissions
budgets
on
all
counties
which
lie
wholly
contained
in
the
fine
grid,
as
a
result
of
the
difficulties
and
uncertainties
associated
with
accurately
dividing
the
fine
and
coarse
grid
for
individual
counties.
Counties
that
straddle
the
fine
grid­
coarse
grid
line
or
which
are
completely
within
the
coarse
grid
would
be
excluded
from
the
budget
calculations
for
Georgia
and
Missouri.
As
a
result,

we
proposed
to
revise
the
NOx
budgets
for
Georgia
and
Missouri
to
include
only
the
fine
grid
portions
of
these
States.

In
response
to
our
proposal,
several
commenters
asserted
that
our
inclusion
of
the
fine
grid
portions
of
the
States
of
Georgia
and
Missouri
was
not
supported
by
reliable
Draft
 
Do
not
cite,
quote
or
distribute
115
data
in
light
of
the
Court's
ruling
in
Michigan
and
requested
additional
air
quality
modeling
for
these
portions.
A
couple
of
commenters
submitted
air
quality
modeling
and
one
commenter
requested
reconsideration
of
our
inclusion
of
sources
that
lie
"
just
inside
the
fine
grid."

Other
commenters
argued
that
no
SIP
Call
exists
for
the
States
of
Georgia
and
Missouri
in
light
of
the
Court's
holdings
in
Michigan
and
Appalachian
Power
(
Technical
Amendments
Case).
They
further
argued
that
the
Agency
must
make
independent
findings
of
significant
contribution
for
both
eastern
Missouri
and
northern
Georgia,
respectively.

One
commenter
also
contended
that
we
could
not
base
our
findings
on
existing
data
but
must
consider
new
circumstances
and
any
changes
in
air
quality
since
promulgation
of
the
NOx
SIP
Call
Rule.
Another
commenter
requested
that
we
not
exclude
sources
in
any
county
that
partially
lies
within
the
coarse
grid
area
in
the
affected
States.

Under
today's
final
rulemaking,
we
are
finalizing
our
proposal
to
include
the
fine
grid
portions
of
Georgia
and
Missouri
as
contributing
significantly
to
downwind
nonattainment.
We
believe
this
is
consistent
with
the
Court's
pronouncements
in
Michigan.
Specifically,
the
Court
found
that
"[
t]
he
fine
grid
modeling
of
parts
of
Missouri
Draft
 
Do
not
cite,
quote
or
distribute
116
and
Georgia
showed
emissions
in
the
aggregate
meeting
the
EPA's
threshold
contribution
criteria."
Michigan,
213
F.
3d
at
683
(
emphasis
in
original).
The
Court
also
found
that
it
was
"
no
mere
techno­
fortuity
that
the
fine
grid
included
enough
of
Missouri
to
include
the
city
of
St.
Louis
and
enough
of
Georgia
to
include
Atlanta:
[
because]
the
fine
grid
portions
of
both
states
are
closest
to
other
nonattainment
areas,
such
as
Chicago
and
Birmingham,
and
generally
higher
ozone
density."
Id.

We
see
no
reason
to
revise
the
existing
determination
that
sources
in
the
fine
grid
parts
of
Georgia
and
Missouri
contribute
significantly
to
downwind
nonattainment.
As
explained
in
our
proposal,
the
basis
for
our
determination
continues
to
be:
(
1)
the
results
of
our
State­
by­
State
modeling;
(
2)
the
relatively
high
amount
of
NOx
emissions
per
square
mile
in
the
fine
grid
portions
of
each
State;
and
(
3)
the
close
locations
of
the
fine
grid
portions
of
each
State
to
downwind
nonattainment
areas
compared
to
the
coarse
grid
(
67
FR
8414).

Additionally,
we
note
that
Georgia
and
Missouri
industry
petitioners
maintained
that
there
was
only
record
support
for
inclusion
of
emissions
from
the
eastern
half
of
Missouri
and
the
northern­
two
thirds
of
Georgia
as
contributing
to
downwind
ozone
problems.
Michigan
213
F.
3d
Draft
 
Do
not
cite,
quote
or
distribute
117
at
684.

We
have
also
evaluated
the
modeling
submitted
by
commenters
and
we
find
that
this
modeling
does
not
refute
our
conclusion
that
sources
in
the
fine
grid
portions
of
Georgia
and
Missouri
contribute
significantly
to
downwind
nonattainment.

Accordingly,
consistent
with
the
Court's
finding
in
Michigan,
we
have
revised
the
NOx
emissions
budgets
for
Georgia
and
Missouri
to
include
only
the
fine
grid
portions
of
these
States.
The
counties
that
are
included
in
the
calculation
of
NOx
budgets
for
each
of
these
States
are
listed
in
Table
1.

Table
1.
Fine
Grid
Counties
in
Georgia
and
Missouri
Georgia
Baldwin
Co
Effingham
Co
Jefferson
Co
Putnam
Co
Banks
Co
Elbert
Co
Jenkins
Co
Rabun
Co
Barrow
Co
Emanuel
Co
Johnson
Co
Richmond
Co
Bartow
Co
Evans
Co
Jones
Co
Rockdale
Co
Bibb
Co
Fannin
Co
Lamar
Co
Schley
Co
Bleckley
Co
Fayette
Co
Laurens
Co
Screven
Co
Bulloch
Co
Floyd
Co
Lincoln
Co
Spalding
Co
Burke
Co
Forsyth
Co
Lumpkin
Co
Stephens
Co
Butts
Co
Franklin
Co
McDuffie
Co
Talbot
Co
Candler
Co
Fulton
Co
Macon
Co
Taliaferro
Co
Carroll
Co
Gilmer
Co
Madison
Co
Taylor
Co
Catoosa
Co
Glascock
Co
Marion
Co
Towns
Co
Chattahoochee
Co
Gordon
Co
Meriwether
Co
Treutlen
Co
Chattooga
Co
Greene
Co
Monroe
Co
Troup
Co
Cherokee
Co
Gwinnett
Co
Morgan
Co
Twiggs
Co
Clarke
Co
Habersham
Co
Murray
Co
Union
Co
Clayton
Co
Hall
Co
Muscogee
Co
Upson
Co
Cobb
Co
Hancock
Co
Newton
Co
Walker
Co
Draft
 
Do
not
cite,
quote
or
distribute
118
Columbia
Co
Haralson
Co
Oconee
Co
Walton
Co
Coweta
Co
Harris
Co
Oglethorpe
Co
Warren
Co
Crawford
Co
Hart
Co
Paulding
Co
Washington
Co
Dade
Co
Heard
Co
Peach
Co
White
Co
Dawson
Co
Henry
Co
Pickens
Co
Whitfield
Co
De
Kalb
Co
Houston
Co
Pike
Co
Wilkes
Co
Dooly
Co
Jackson
Co
Polk
Co
Wilkinson
Co
Douglas
Co
Jasper
Co
Pulaski
Co
Missouri
Bollinger
Co
Iron
Co
Oregon
Co
St.
Francois
Co
Butler
Co
Jefferson
Co
Pemiscot
Co
St.
Louis
Co
Cape
Girardeau
Co
Lewis
Co
Perry
Co
St.
Louis
City
Carter
Co
Lincoln
Co
Pike
Co
Scott
Co
Clark
Co
Madison
Co
Ralls
Co
Shannon
Co
Crawford
Co
Marion
Co
Reynolds
Co
Stoddard
Co
Dent
Co
Mississippi
Co
Ripley
Co
Warren
Co
Dunklin
Co
Montgomery
Co
St.
Charles
Co
Washington
Co
Franklin
Co
New
Madrid
Co
St.
Genevieve
Co
Wayne
Co
Gasconade
Co
We
are
not
making
a
finding
today
as
to
whether
sources
in
the
coarse
grid
portions
of
Georgia
and/
or
Missouri
make
a
measurable
or
material
part
of
the
significant
contribution
of
each
of
these
States,

respectively.
In
addition,
apart
from
our
findings
relating
to
the
SIP
Call,
a
State
may,
of
course,
assess
the
in­
State
impacts
of
NOx
emissions
from
its
coarse
grid
area,
and
impose
additional
NOx
reductions,
beyond
the
NOx
SIP
Call
requirements
in
the
fine
grid,
as
necessary
to
demonstrate
attainment
or
maintenance
of
the
ozone
NAAQS
in
the
State.

Comment:
Several
commenters
supported
our
inclusion
of
the
fine
grid
portions
of
Missouri
and
Georgia.
One
commenter
requested
that
we
not
exclude
sources
within
any
county
that
partially
lies
within
the
coarse
grid
area
in
the
affected
Draft
 
Do
not
cite,
quote
or
distribute
119
States.

Response:
Today's
action
is
in
response
to
the
court's
decision
that
vacated
our
inclusion
of
the
entire
States
of
Georgia
and
Missouri.
Michigan
v.
EPA,
213
F.
3d
663.
(
D.
C.

Cir.
2000),
cert.
denied,
121
S.
Ct.
1225
(
2001)(
Michigan).

"
EPA
must
first
establish
that
there
is
a
measurable
contribution"
from
the
coarse
grid
portion
of
the
State
before
holding
the
coarse
grid
portion
responsible
for
the
significant
contribution
of
downwind
ozone
nonattainment
in
another
state."
Id.
At
683­
84
(
emphasis
in
original).

As
explained
in
our
February
22,
2002
proposal,

"
because
of
difficulties
and
uncertainties
with
accurately
dividing
emissions
between
the
fine
and
coarse
grid
of
individual
counties
for
the
purpose
of
setting
overall
NOx
emissions
budgets,
we
believe
that
the
calculation
of
the
emissions
budgets
should
be
based
on
all
counties
which
are
wholly
contained
within
the
fine
grid."
67
FR
8415.

In
today's
action
we
are
finalizing
our
proposal
because
at
this
time
we
have
not
accurately
determined
the
emissions
attributed
to
either
the
fine
grid
or
coarse
grid
portions
of
such
counties.
We
believe
this
is
also
consistent
with
the
Court's
ruling.
Thus,
we
have
now
recalculated
the
budgets
for
Georgia
and
Missouri
to
include
only
those
counties
that
lie
wholly
within
the
fine
grid
Draft
 
Do
not
cite,
quote
or
distribute
120
portions
of
both
States
as
described
above.

Comment:
One
commenter
requested
the
reconsideration
of
our
inclusion
of
sources
that
are
"
just
inside
the
fine
grid."

This
commenter
based
its
request
on
modeling
showing
that
sources
in
Georgia
south
of
32.67
degrees
latitude
do
not
significantly
contribute
to
nonattainment
ozone
areas
in
downwind
States.

Response:
We
have
evaluated
the
modeling
submitted
by
this
commenter
and
found
that
the
modeling
does
not
refute
the
overall
conclusions
we
have
drawn
concerning
the
impacts
of
NOx
emissions
in
the
relevant
geographic
areas.
The
commenter
quantified
the
contribution
from
those
emissions
in
Georgia
south
of
32.67
degrees
latitude
(
i.
e.,
southern
Georgia)
by
modeling
the
four
OTAG
episodes
with
emissions
in
southern
Georgia
removed
(
i.
e.,
zero­
out).
The
results
of
this
modeling,
as
presented
by
the
commenter,
suggest
that
emissions
in
southern
Georgia
contribute
less
than
2
parts
per
billion
(
ppb)
to
the
peak
daily
1­
hour
ozone
in
1­

hour
nonattainment
areas
outside
of
Georgia
in
each
of
the
four
episodes.
In
view
of
these
results,
the
commenter
contends
that
the
contribution
from
southern
Georgia
to
all
downwind
nonattainment
areas
is
not
significant
since
the
contribution
is
less
than
the
2
ppb
screening
criteria
used
Draft
 
Do
not
cite,
quote
or
distribute
121
by
EPA
in
the
NOx
SIP
Call
to
identify
those
upwind
Stateto
downwind
nonattainment
area
linkages
that
were
clearly
not
significant.
However,
the
commenter
misinterpreted
the
definition
of
EPA's
2
ppb
screening
criteria
by
limiting
the
analysis
of
contribution
to
just
the
episode
peak
concentration
in
the
downwind
areas.
By
doing
so,
the
contractor
did
not
consider
or
present
any
data
to
evaluate
the
contribution
from
southern
Georgia
to
other
ozone
exceedances
(
i.
e.,
less
than
the
peak
by
exceeding
the
NAAQS)
predicted
in
each
downwind
area.
For
example,

southern
Georgia
may
not
impact
the
predicted
episode
peak
1­
hour
ozone
in
Birmingham
by
2
ppb,
but
southern
Georgia
could
have
contributed
at
least
2
ppb
to
one
or
more
of
the
other
88
exceedances
in
Birmingham.
Unfortunately,
the
commenter
did
not
provide
any
data
to
permit
an
examination
of
the
contribution
from
emissions
from
southern
Georgia
to
all
exceedances
in
downwind
nonattainment
areas.
Thus,
the
comment
that
southern
Georgia
does
not
significantly
contribute
to
downwind
nonattainment
because
the
contributions
are
less
than
2
ppb
is
not
fully
supported
by
the
data
presented
by
the
commenter.

Thus,
to
the
extent
that
this
source
is
in
a
county
that
falls
within
the
fine
grid
part
of
Georgia,
we
do
not
believe
we
should
reconsider
its
inclusion
in
the
NOx
SIP
Draft
 
Do
not
cite,
quote
or
distribute
122
Call.

Comment:
Several
commenters
stated
that
our
inclusion
of
portions
of
the
State
of
Georgia
was
not
supported
by
reliable
data
and
sound
science
especially
in
light
of
Michigan,
"
that
remanded
and
vacated
in
its
entirety
[
the
inclusion
of
whole
states
of
Georgia
and
Missouri],"
due
to
"
EPA's
unsupportable
determination
of
significant
contribution."
Several
commenters
also
stated
that
we
had
failed
to
provide
data
to
support
the
inclusion
of
portions
of
the
State
of
Georgia
that
are
within
the
fine
grid.

Another
commenter
argued
that
we
had
failed
to
provide
information
to
support
inclusion
of
affected
sources
in
Georgia.

Response:
In
Michigan,
the
D.
C.
Circuit
Court
held
"[
t]
he
fine
grid
modeling
of
parts
of
Missouri
and
Georgia
showed
emissions
in
the
aggregate
meeting
the
EPA's
threshold
contribution
criteria."
Michigan,
213
F.
3d
at
683
(
emphasis
in
original).
The
Court
noted
that
"
EPA's
explanation
and
technique
make
clear
that
emissions
from
the
fine
grid
areas
may
have
been
the
sole
source
of
the
finding.
Id.
The
Court
also
found
that
it
was
"
no
mere
techno­
fortuity
that
the
fine
grid
included
enough
of
Missouri
to
include
the
city
of
St.
Louis
and
enough
of
Georgia
to
include
Atlanta:
[
because]
the[
se]
fine
grid
Draft
 
Do
not
cite,
quote
or
distribute
123
portions
of
both
states
are
closest
to
other
nonattainment
areas,
such
as
Chicago
and
Birmingham,
and
generally
higher
ozone
density."
Id.
However,
the
Court
vacated
and
remanded
the
NOx
SIP
Call
budgets
for
the
States
of
Georgia
and
Missouri
finding
that
the
budgets
"
not
only
encompass
the
whole
state
but
are
calculated
on
the
basis
of
hypothesized
cutbacks
from
areas
that
have
not
been
show
to
have
made
significant
contributions."
Id
at
684.
(
emphasis
in
original).
The
Court
further
held
that
"
EPA
must
first
establish
that
there
is
a
measurable
contribution"
from
the
coarse
grid
portion
of
the
State
before
holding
the
coarse
grid
portion
of
the
State
responsible
for
the
significant
contribution
of
downwind
ozone
nonattainment
in
another
state.
Id.
In
Appalachian
Power
Company
v.
EPA,
251
F.
3d
1026,
1040­
1
(
2001),
the
Court
found
that
"
insofar
as
the
TAs
[
technical
amendments]
include
a
statewide
Missouri
emission
budget
they
are
unlawful
under
Michigan.

Thus,
the
Court
did
not
call
into
question
the
proposition
that
the
fine
grid
portions
of
Georgia
and
Missouri
should
be
considered
as
making
a
significant
contribution
to
downwind
nonattainment.
We
also
note
that
Georgia
and
Missouri
industry
petitioners
maintained
that
there
was
only
record
support
for
inclusion
of
emissions
from
the
eastern
half
of
Missouri
and
the
northern­
two
Draft
 
Do
not
cite,
quote
or
distribute
124
thirds
of
Georgia
as
contributing
to
downwind
ozone
problems.
Michigan,
213
F.
3d
at
681.

In
addition,
in
the
NOx
SIP
Call
Rule,
we
found
that
"[
s]
ources
that
are
closer
to
the
nonattainment
area
tend
to
have
much
larger
effects
on
the
air
quality
than
sources
that
are
far
away."
(
63
FR
25919.)
Further,
OTAG's
technical
findings
and
recommendations
concluded
that
areas
located
in
the
fine
grid
should
receive
additional
controls
because
they
contribute
to
ozone
in
other
areas
within
the
fine
grid.

Today's
rulemaking
finalizes
our
revision
of
the
budgets
for
Georgia
and
Missouri
to
reflect
the
Court's
pronouncements
in
Michigan.
This
is
also
consistent
with
OTAG's
recommendations
and
findings.
We
have
revised
neither
our
existing
determination
nor
our
bases
for
the
determination
that
sources
in
the
fine
grid
portion
of
Georgia
and
Missouri
are
contributing
significantly
to
downwind
nonattainment.
We
are
revising
the
NOx
budgets
for
Georgia
and
Missouri
to
reflect
the
inclusion
of
only
the
sources
that
are
within
the
fine
grid
portions
of
both
States.
Accordingly,
we
also
continue
to
rely
on
the
Technical
Support
Document
and
Notice
of
Data
Availability
which
are
the
underlying
documents
for
the
NOx
SIP
Call
Rule.
Draft
 
Do
not
cite,
quote
or
distribute
125
Comment:
One
commenter
argued
that
the
Court
vacated
our
determination
of
significant
contribution
for
all
of
Missouri
in
Michigan,
and
therefore,
we
no
longer
have
a
basis
for
including
any
portion
of
Missouri
in
the
SIP
Call.

The
commenter
also
argued
that
we
made
no
significant
contribution
finding
for
eastern
Missouri
but
rather
based
our
findings
on
emissions
from
the
whole
State.

Response:
We
disagree
with
the
comment.
As
stated
elsewhere
in
this
rule,
the
Court
did
not
question
our
findings
of
significant
contribution
for
the
fine
grid
parts
of
Georgia
and
Missouri.
"[
T]
he
fine
grid
modeling
of
parts
of
Missouri
and
Georgia
showed
emissions
in
the
aggregate
meeting
the
EPA's
threshold
contribution
criteria."

Michigan,
213
F.
3d.
at
683.
We
also
note
that
Georgia
and
Missouri
industry
petitioners
maintained
that
there
was
only
record
support
for
inclusion
of
emissions
from
the
eastern
half
of
Missouri
and
the
northern­
two
thirds
of
Georgia
as
contributing
to
downwind
ozone
problems.
Id.,
at
681.

OTAG's
recommendations
and
findings
concluded
that
areas
located
in
the
fine
grid
should
receive
additional
controls
because
they
contribute
to
ozone
in
other
areas
within
the
fine
grid.
In
addition,
our
modeling
showed
that
emissions
in
both
Georgia
and
Missouri
make
a
significant
contribution
to
nonattainment
in
other
areas.
Therefore,
we
believe
Draft
 
Do
not
cite,
quote
or
distribute
126
there
is
record
support
for
inclusion
of
eastern
Missouri.

Comment:
One
commenter
argued
that
as
a
result
of
the
vacatur
in
Michigan,
we
have
to
justify
the
inclusion
of
eastern
Missouri
in
the
NOx
SIP
Call
taking
into
consideration
facts
in
existence
at
the
time
of
our
proposal
(
February
22,
2002,
67
FR
8395).

Response:
We
disagree.
As
stated
earlier,
the
Court
did
not
question
our
findings
of
significant
contribution
for
the
fine
grid
portions
of
the
States
of
Georgia
and
Missouri.

The
Court
also
let
stand
OTAG's
modeling
analyses
(
except
with
respect
to
Wisconsin).
Thus,
the
inclusion
of
eastern
Missouri
accords
with
the
Court
pronouncements
on
the
fine
grid/
coarse
grid.

In
today's
rulemaking,
we
see
no
reason
to
revise
the
existing
determination
that
sources
in
the
fine
grid
parts
of
Missouri
contribute
significantly
to
nonattainment
downwind.
The
basis
for
this
determination
continues
to
be:

(
1)
the
results
of
our
State­
by­
State
modeling;
(
2)
the
relatively
high
amount
of
NOx
emissions
per
square
mile
in
the
fine
grid
portions
of
the
State;
and
(
3)
the
close
locations
of
the
fine
grid
portions
of
the
State
to
downwind
nonattainment
areas
compared
to
the
coarse
grid
part.

Comment:
One
commenter
stated
that
it
was
erroneous
to
continue
using
data
that
was
4
years
old
as
basis
for
Draft
 
Do
not
cite,
quote
or
distribute
127
inclusion
of
eastern
Missouri
in
the
NOx
SIP
Call
in
light
of
data
showing
that
areas
receiving
measurable
contributions
from
Missouri
sources
are
now
in
attainment
of
the
1­
hour
ozone
standards.

Response:
We
disagree
with
the
comment
that
downwind
ozone
nonattainment
areas
have
achieved
attainment
of
the
1­
hour
ozone
standards.
More
specifically,
Chicago
has
not
yet
attained
the
1­
hour
ozone
standard.
Chicago's
attainment
demonstration
relies,
in
part,
on
implementation
of
Missouri's
statewide
NOx
rule,
approved
by
EPA
into
the
SIP.

The
NOX
SIP
Call
reductions
in
Missouri
are
needed
for
Chicago
to
attain/
maintain
the
1­
hour
standard.
The
reductions
will
also
help
Chicago
and
other
areas
attain
the
8­
hour
ozone
standard.

Although
the
attainment
plan
was
approved,
we
believe
it
is
important
to
point
out
that
there
are
inherent
uncertainties
in
the
plan,
including
hourly
emission
estimates
and
emissions
growth
projections.
Further,

without
the
NOx
SIP
Call,
Missouri
may
come
under
increased
pressure
to
relax
the
existing
State
rule,
which
could
jeopardize
attainment
in
Chicago.
Additionally,
the
SIP
approved
State
rule
has
not
yet
been
implemented
and
was,
in
fact,
recently
revised
by
the
State.

Additional
emissions
reductions
due
to
the
NOx
SIP
Call
Draft
 
Do
not
cite,
quote
or
distribute
128
would
help
attain
and
maintain
the
8­
hr
ozone
and
PM
fine
standards,
improve
visibility
and
reduce
deposition
of
nitrogen.
Missouri
was
found
to
significantly
contribute
to
nonattainment
of
the
8­
hour
ozone
standard
in
eight
downwind
States
(
IL,
IN,
KY,
MI,
OH,
PA,
TN
&
WI).
The
reductions
are
highly
cost­
effective
and
would
also
help
offset
emissions
from
a
number
of
large
sources
locating
upwind
of
St.
Louis
and
avoid
very
costly
local
controls
in
the
future.

In
general,
we
believe
an
agency
should
not
revisit
an
otherwise
sound
rulemaking
just
due
to
the
passage
of
time
leading
to
changed
circumstances,
because
circumstances
always
change.
Specifically,
we
disagree
that
a
new
emissions
inventory
is
necessary
that
takes
into
account
Missouri's
statewide
NOx
rule
and
other
post­
1998
CAA
rules.

Because
SIPs
are
constantly
changing
it
is
impractical
to
revise
emission
inventories
and
modeling
analyses
each
time
changes
are
made.
For
example,
the
NOx
limits
the
commenter
cites
have
since
been
revised
by
the
State
and
are
yet
to
be
approved
by
EPA.

Further,
completing
the
NOx
SIP
Call
in
Missouri
is
an
equitable
approach.
It
would
be
inequitable
to
use
2003
air
quality
analysis
for
Missouri
but
to
hold
other
NOx
SIP
Call
States
to
the
1998
analysis.
It
should
also
be
noted
that
Draft
 
Do
not
cite,
quote
or
distribute
129
we
intend
to
review
the
NOx
SIP
Call
Rule
and
will
make
adjustments
if
necessary
(
63
FR
57428).

This
program
is
the
single
most
important
measure
to
reduce
interstate
pollution
in
the
short
term.
Reductions
of
NOx
emissions
from
the
program
will
enhance
the
protection
of
public
health
for
over
100
million
people
in
the
eastern
half
of
the
United
States
­­
including
people
in
Missouri.
It
is
a
centerpiece
of
the
clean
air
plans
for
many
cities,
including
the
Chicago
area.

Comments:
Another
commenter
stated
that
the
current
state
of
Missouri
control
regulations
would
achieve
greater
NOx
emissions
and
greater
improvements
than
the
NOx
SIP
Call.

Response:
We
disagree.
Missouri
adopted
and,
in
December
2000,
we
approved
a
statewide
NOx
rule
which
requires
emission
reductions
in
the
eastern
third
of
the
State
and
lesser
reductions
in
the
remainder
of
the
State
for
large
EGUs.
While
we
approved
this
rule
because
it
helped
address
the
ozone
nonattainment
issue
in
St
Louis,
we
did
not
find
that
this
rule
addressed
the
significant
transport
of
NOx
to
other
areas
that
we
had
identified
in
the
NOx
SIP
Call.

Revisions
to
the
statewide
NOx
rule
were
adopted
on
April
24,
2003
and
may
be
submitted
as
a
SIP
revision
sometime
after
their
effective
date
of
August
30,
2003.

Both
the
SIP­
approved
statewide
NOx
rule
and
the
recent
Draft
 
Do
not
cite,
quote
or
distribute
130
revisions
to
the
rule
adopted
by
the
State
would
achieve
less
NOx
emissions
reductions
than
implementation
of
the
NOx
SIP
Call.
Missouri's
current
and
proposed
NOx
rules
are
less
stringent
than
the
NOx
SIP
Call
requirements.
There
are
greater
emissions
reductions
under
the
NOx
SIP
Call
(
about
20
percent
statewide
and
40
percent
in
the
fine
grid
compared
to
the
SIP­
approved
Missouri
rule).
The
NOx
SIP
Call
offers
the
advantages
of
a
cap
and
trade
program,

including
certainty
of
emissions
reductions;
the
State
rules
have
no
emissions
cap.
Reductions
are
more
effective
in
preventing
interstate
transport
to
key
downwind
areas
under
the
NOx
SIP
Call
as
they
must
occur
in
the
eastern
part
of
Missouri
and
trading
is
not
allowed
between
eastern
and
western
Missouri
EGUs.
The
NOx
SIP
Call
budget
also
includes
reductions
in
emissions
from
large
cement
kilns,

industrial
boilers,
and
stationary
IC
engines.
The
NOx
SIP
Call
would
allow
fewer
emissions
statewide,
as
shown
in
the
table
below.

EGU
Emissions
(
tons
per
ozone
season)
Fine
Grid
Statewide
Actual
2001
Emissions
30,872
60,102
NOx
SIP
Call
13,400
cap
37,600a
in
2001b,
c
MO
current
rule
23,100
in
2001c
46,900
in
2001c
Draft
 
Do
not
cite,
quote
or
distribute
131
MO
rule,
potential
revision
19,100
in
2001dc
49,600
in
2001c
a.
Assuming
MO
current
rule
remains
effective
in
the
coarse
grid
(
reductions
from
rule
are
included
in
the
attainment
demonstrations
for
St.
Louis
and
Chicago).

b.
The
table
only
compares
EGU
emissions;
the
NOx
SIP
Call
requires
2,900
tons
additional
NOx
reductions
due
to
controls
on
cement,
industrial
boilers
and
engines
in
the
fine
grid
c.
Estimated
emissions
based
on
actual
2001
heat
input;
emissions
after
2001
would
be
higher
as
the
State
rule
has
no
cap.

Further,
we
recently
informed
the
State
of
some
problem
areas
in
their
recent
rule
revisions.
At
least
one
of
the
proposed
revisions
appears
to
relax
existing
requirements;

that
is,
the
delay
of
the
compliance
date
from
2003
to
2004.

If
this
provision
is
adopted
and
submitted
as
a
SIP
revision,
the
State
must
provide
an
adequate
demonstration
pursuant
to
section
110(
l)
of
the
CAA
that
this
revision
"
would
not
interfere
with
any
applicable
requirement
concerning
attainment
and
reasonable
further
progress...."

As
a
practical
matter,
utilities
have
been
on
notice
since
original
rule
adoption
that
compliance
would
be
expected
in
ozone
season
2003,
so
an
extension
of
the
compliance
date
does
not
appear
justified.
A
second
area
of
serious
concern
in
the
proposed
rule
is
the
generation
and
use
of
"
paper"

credits
by
allowing
utilities
to
demonstrate
compliance
at
the
0.18
lb/
mmBtu
emission
level
but
then
receive
credit
at
Draft
 
Do
not
cite,
quote
or
distribute
40
Both
Georgia
and
Missouri
submitted
Phase
I
SIPs
which
included
only
the
fine
grid
portion
of
the
States.

132
a
0.25
lbmm/
Btu
emission
level.
This
provision
is
inconsistent
with
our
policy
that
credit
for
emission
reductions
must
be
real,
quantifiable,
surplus,
enforceable,

and
permanent.

D.
What
Are
We
Finalizing
for
Alabama
and
Michigan
in
Light
of
the
Court
Decision
on
Georgia
and
Missouri?

We
calculated
Alabama's
and
Michigan's
budgets
in
the
same
manner
as
we
did
for
Georgia
and
Missouri,
as
described
above.
While
no
petitioners
raised
any
issues
concerning
the
inclusion
of
only
parts
of
Alabama
and
Michigan
in
the
NOx
SIP
Call,
the
Court's
reasoning
regarding
Georgia
and
Missouri
applies
equally
to
Alabama
and
Michigan.
Based
on
the
information
in
the
record,
we
revised
the
NOx
budgets
for
Alabama
and
Michigan
to
reflect
reductions
only
in
the
fine
grid
portions
of
these
States.
40
Again,
like
Georgia
and
Missouri,
we
see
no
reason
to
disturb
the
determination
that
sources
in
the
fine
grid
contribute
significantly
to
nonattainment
downwind;
the
fine
grid
portions
of
both
Alabama
and
Michigan
are
closer
to
downwind
1­
hour
ozone
nonattainment
areas
than
the
coarse
grid
parts
of
these
States.
Also,
the
amount
of
NOx
emissions
per
square
mile
in
the
fine
grid
portion
of
Alabama
is
nearly
60
percent
Draft
 
Do
not
cite,
quote
or
distribute
41
Pursuant
to
the
court's
order
lifting
the
stay
of
the
SIP
submission
obligation,
the
19
States,
including
Alabama,
Michigan,
and
the
District
of
Columbia,
were
required
to
submit
SIPs
in
response
to
the
NOx
SIP
Call
by
October
30,
2000.
As
discussed
above,
in
letters
dated
April
11,
2000
to
State
Governors,
we
informed
the
States
that
remained
subject
to
the
NOx
SIP
Call
that
they
could
choose
to
submit
SIPs
meeting
only
the
Phase
I
emissions
budget
for
each
State.
With
respect
to
Alabama
and
Michigan,
we
also
provided
that
they
could
choose
to
submit
SIPs
that
address
emissions
only
in
the
fine
grid
portion
of
the
State.
Alabama
and
Michigan
submitted
Phase
I
SIPs
which
included
only
the
fine
grid
portion
of
the
States.

133
greater
than
in
the
coarse
grid
part;
and
in
Michigan
the
fine
grid
NOx
emissions
per
square
mile
are
more
than
500
percent
greater
than
emissions
per
square
mile
in
the
coarse
grid
portion
of
the
State.
Counties
in
Michigan
and
Alabama
which
straddle
the
fine
grid­
coarse
grid
are
excluded
from
the
budget
calculations
as
described
above
for
Georgia
and
Missouri.
We
believe
this
approach
is
consistent
with
the
reasoning
of
the
Court's
March
3,
2000
opinion
concerning
Georgia
and
Missouri
and
is
justified
as
provided
above.
41
The
counties
in
Alabama
and
Michigan
that
are
included
in
the
calculation
of
NOx
budgets
for
each
of
these
States
are
listed
in
Table
2.

Table
2.
Fine
Grid
Counties
in
Alabama
and
Michigan
Alabama
Autauga
Co
Colbert
Co
Greene
Co
Macon
Co
St.
Clair
Co
Bibb
Co
Coosa
Co
Hale
Co
Madison
Co
Shelby
Co
Blount
Co
Cullman
Co
Jackson
Co
Marion
Co
Sumter
Co
Calhoun
Co
Dallas
Co
Jefferson
Co
Marshall
Co
Talladega
Co
Chambers
Co
De
Kalb
Co
Lamar
Co
Morgan
Co
Tallapoosa
Co
Cherokee
Co
Elmore
Co
Lauderdale
Co
Perry
Co
Tuscaloosa
Co
Draft
 
Do
not
cite,
quote
or
distribute
134
Chilton
Co
Etowah
Co
Lawrence
Co
Pickens
Co
Walker
Co
Clay
Co
Fayette
Co
Lee
Co
Randolph
Co
Winston
Co
Cleburne
Co
Franklin
Co
Limestone
Co
Russell
Co
Michigan
Allegan
Co
Eaton
Co
Kalamazoo
Co
Monroe
Co
St.
Clair
Co
Barry
Co
Genesee
Co
Kent
Co
Montcalm
Co
St.
Joseph
Co
Bay
Co
Gratiot
Co
Lapeer
Co
Muskegon
Co
Sanilac
Co
Berrien
Co
Hillsdale
Co
Lenawee
Co
Newaygo
Co
Shiawassee
Co
Branch
Co
Ingham
Co
Livingston
Co
Oakland
Co
Tuscola
Co
Calhoun
Co
Ionia
Co
Macomb
Co
Oceana
Co
Van
Buren
Co
Cass
Co
Isabella
Co
Mecosta
Co
Ottawa
Co
Washtenaw
Co
Clinton
Co
Jackson
Co
Midland
Co
Saginaw
Co
Wayne
Co
E.
What
Modifications
Are
Being
Made
to
the
NOx
Emissions
Budgets?

In
today's
final
action,
in
a
change
from
the
proposed
rule,
we
are
excluding
certain
small
cogeneration
units
from
the
definition
of
EGU.
All
other
cogeneration
units
and
other
non­
acid
rain
units
will
remain
as
EGUs.
As
a
result,

it
makes
sense
to
require
States
to
include
in
their
Phase
II
SIPs
the
anticipated
emissions
reductions
from
non­
Acid
Rain
units.
However,
since,
as
discussed
below,
States
seem
to
have
already
included
non­
Acid
rain
units
in
the
Phase
I
SIPs,
today's
action
concerning
the
EGU
definition
will
have
little
or
no
effect
on
State
budgets
and
required
reductions.

We
are
also
finalizing
technical
changes
to
the
EGU
definition
in
the
NOx
SIP
Call
to
make
it
consistent
with
the
definition
of
EGU
used
in
the
Section
126
Rule.
Since
the
EGU
definition
establishes
the
dividing
line
between
the
EGU
and
non­
EGU
categories,
the
changes
to
the
EGU
Draft
 
Do
not
cite,
quote
or
distribute
135
definition
result
in
corresponding
changes
to
the
non­
EGU
definition
in
the
NOx
SIP
Call,
which
make
it
consistent
with
the
non­
EGU
definition
in
the
Section
126
Rule.

Today's
action
concerning
these
definitions
does
not
result
in
any
specific
revisions
to
the
budgets
established
under
the
final
NOx
SIP
Call
and
the
Technical
Amendments.

We
are
recalculating
the
budgets
to
reflect
a
control
level
of
82
percent
for
the
natural
gas­
fired
lean­
burn
IC
engines.
For
the
other
IC
engine
subcategories
(
diesel
and
dual
fuel)
we
are
using
90
percent
control,
as
proposed.

We
are
calculating
the
budgets
for
Georgia,
Missouri,

Alabama,
and
Michigan
assuming
controls
in
all
counties
that
are
fully
located
in
the
fine
grid,
as
discussed
in
sections
II.
C.
and
II.
D.
The
partial
State
budgets
for
Georgia,

Missouri,
Alabama,
and
Michigan
in
today's
action
are
calculated
using
IC
engine
control,
as
well
as
the
definition
of
EGUs
as
described
above.

Our
budgets
are
shown
in
Tables
3
and
4.
For
States
that
are
required
to
submit
Phase
I
SIPs,
Table
5
shows
the
Phase
I
and
Phase
II
budgets
and
the
incremental
difference
between
the
two
budgets.
We
are
requiring
States
that
have
submitted
SIPs
that
meet
only
the
Phase
I
budget
to
supplement
their
control
plans
with
rules
that
will
meet
the
Phase
II
increment.
Draft
 
Do
not
cite,
quote
or
distribute
136
Table
3.
State
Emissions
Budgets
and
Percent
Reduction
(
tons/
season)

State
Final
Base
Phase
II
Budget
Tons
Reduced
Percent
Reduction
Connecticut
46,015
42,850
3,165
7%
Delaware
23,797
22,862
935
4%
District
of
Columbia
6,471
6,657
­
186
­
3%

Illinois
368,870
271,091
97,779
27%
Indiana
340,654
230,381
110,273
32%
Kentucky
237,413
162,519
74,894
32%
Maryland
103,476
81,947
21,529
21%
Massachusetts
87,095
84,848
2,247
3%
New
Jersey
105,489
96,876
8,613
8%
New
York
255,658
240,322
15,336
6%
North
Carolina
224,696
165,306
59,390
26%
Ohio
373,222
249,541
123,681
33%
Pennsylvania
345,203
257,928
87,275
25%
Rhode
Island
9,463
9,378
85
1%
South
Carolina
152,805
123,496
29,309
19%
Tennessee
256,765
198,286
58,479
23%
Virginia
210,786
180,521
30,265
14%
West
Virginia
176,699
83,921
92,778
53%

Table
4.
Partial
State
Emissions
Budgets
and
Percent
Reduction
(
tons/
season)

State
Final
Base
Final
Budget
Tons
Reduced
Percent
Reduction
Georgia
209,914
150,656
59,258
28%
Missouri
92,697
61,406
31,291
34%
Alabama
169,156
119,827
49,329
29%
Michigan
245,929
190,908
55,021
22%

Table
5.
Comparison
of
Phase
I
and
Phase
II
Draft
 
Do
not
cite,
quote
or
distribute
137
State
NOx
Budgets
Comparison
(
tons/
season)

State
Phase
I
Budget
Phase
II
Budget
Phase
II
Incremental
Difference
Alabama
124,795
119,827
4,968
Connecticut
42,891
42,850
41
Delaware
23,522
22,862
660
District
of
Columbia
6,658
6,657
1
Illinois
278,146
271,091
7,055
Indiana
234,625
230,381
4,244
Kentucky
165,075
162,519
2,556
Maryland
82,727
81,947
780
Massachusetts
85,871
84,848
1,023
Michigan
191,941
190,908
1,033
New
Jersey
95,882
96,876
­
994
New
York
241,981
240,322
1,659
North
Carolina
171,332
165,306
6,026
Ohio
252,282
249,541
2,741
Pennsylvania
268,158
257,928
10,230
Rhode
Island
9,570
9,378
192
South
Carolina
127,756
123,496
4,260
Tennessee
201,163
198,286
2,877
Virginia
186,689
180,521
6,168
West
Virginia
85,045
83,921
1,124
F.
How
Will
the
Compliance
Supplement
Pools
be
Handled?

The
compliance
supplement
pool
(
CSP)
is
a
pool
of
allowances
that
can
be
used
in
the
beginning
of
the
program
to
provide
affected
sources
additional
compliance
flexibility.
The
CSP
was
created
to
address
concerns
raised
by
commenters
on
the
NOx
SIP
Call
proposal
regarding
electric
reliability
during
the
initial
years
of
the
program.
In
the
NOx
SIP
Call
Rule,
the
CSP
may
be
used
in
Draft
 
Do
not
cite,
quote
or
distribute
138
the
years
2003
and
2004
(
see
63
FR
57428­
57430,
October
27,

1998,
for
further
discussion
of
the
CSP).
In
Michigan,
the
D.
C.
Circuit
Court
ruled
that
May
31,
2004,
rather
than
May
1,
2003
is
the
date
by
which
sources
must
install
controls
to
comply
with
the
NOx
SIP
Call.
Consequently,
to
be
consistent
with
the
original
2­
year
window
specified
in
the
NOx
SIP
Call
in
which
we
allowed
the
CSP
allowances
to
be
used,
we
are
finalizing
an
extension
of
the
time
that
allowances
from
the
CSP
can
be
used
from
September
30,
2004
to
September
30,
2005
for
sources
with
a
May
31,
2004
compliance
date,
and
to
September
30,
2008
for
sources
with
a
May
1,
2007
compliance
date.
We
are
also
including
CSPs
for
Georgia
and
Missouri.
As
under
the
original
NOx
SIP
Call,
Georgia
and
Missouri
may
distribute
the
allowances
in
their
respective
pools
either
based
on
early
reductions,

directly
to
sources
based
on
a
demonstrated
need,
or
by
some
combination
of
the
two
methods.
(
For
a
more
complete
discussion
of
how
CSP
allowances
may
be
distributed
under
the
NOx
SIP
Call
see
63
FR
57429.)
The
allowances
from
Georgia's
and
Missouri's
CSPs
may
be
used
to
account
for
emissions
during
the
2007
and
2008
ozone
seasons,
the
first
2
years'
ozone
seasons
that
sources
in
those
States
are
required
to
comply.
Draft
 
Do
not
cite,
quote
or
distribute
139
We
are
not
changing
the
individual
State
CSP
values
that
were
finalized
in
the
March
2,
2000
technical
corrections
to
the
emission
budgets
(
65
FR
11222)
with
the
exception
of
Alabama,
Georgia,
Michigan,
Missouri,
and
Wisconsin.
Changing
the
State
CSPs
to
reflect
the
State
budget
changes
made
in
this
action
would
result
in
minimal
impacts
on
the
size
of
any
State's
CSP.
Therefore,
we
have
decided
to
maintain
the
CSPs
at
the
levels
determined
in
the
March
2,
2000
technical
amendment
(
with
the
exception
of
Alabama,
Georgia,
Michigan,
Missouri,
and
Wisconsin).

Since
required
reductions
in
Georgia,
Missouri,

Alabama,
and
Michigan
finalized
under
today's
final
rule
are
less
than
the
required
reductions
of
the
October
27,
1998
NOx
SIP
Call
reflecting
full
State
emissions
budgets,
we
are
making
corresponding
decreases
to
the
CSPs
for
the
portion
of
each
State
that
is
still
subject
to
the
NOx
SIP
Call.
We
have
calculated
the
partial­
State
CSPs
by
prorating
the
size
of
the
full­
State
CSP
by
the
ratio
of
the
reductions
that
we
are
finalizing
for
the
partial
State
to
the
reductions
that
we
required
in
the
March
2,
2000
Technical
Amendment
(
65
FR
11222).
However,
even
though
we
are
finalizing
an
82
percent
reduction
requirement
from
large
natural
gas­
fired
IC
engines,
to
be
consistent
with
the
way
the
CSP
was
calculated
in
the
other
States,
we
assumed
a
90
percent
Draft
 
Do
not
cite,
quote
or
distribute
140
reduction
from
all
large
IC
engines
for
purposes
of
calculating
the
CSP.
In
addition,
since
Wisconsin
is
not
being
required
to
make
reductions
at
this
time,
Wisconsin
is
no
longer
receiving
a
share
of
the
CSP.
(
Wisconsin's
original
CSP
was
6,920
tons.)
For
these
reasons,
the
total
CSP
is
now
less
than
200,000
tons.
The
revised
CSPs
for
Georgia,
Missouri,
Alabama,
and
Michigan
are
shown
in
Table
6.

Table
6.
Compliance
Supplement
Pools
(
CSP)

Full
State
Tons
Reduced
(
from
March
2,
2000
FR)
Partial
State
Tons
Reduced
With
90%
IC
Engine
Control
Full
State
CSP
Partial
State
CSP
With
90%
IC
Engine
Control
GA
63,582
57,623
11,440
10,728
MO
62,242
31,291
11,199
5,630
AL
64,954
49,806
11,687
8,962
MI
63,118
55,064
11,356
9,907
One
commenter
(
EL
Paso
Corporation,
OAR­
2001­
0008,

XIID
10)
commented
that
IC
engines
should
be
allowed
to
receive
reductions
from
the
CSP.
The
commenter
asserts
that
we
have
failed
to
recognize
that
the
CSP
contains
NOx
allocations
generated
by
IC
engines.
The
commenter
also
claims
that
because
IC
engines
will
also
have
to
be
retrofitted
to
comply
with
the
NOx
SIP
Call
they
could
also
have
Draft
 
Do
not
cite,
quote
or
distribute
141
reliability
problems
and,
therefore,
should
be
able
to
receive
allowances
from
the
CSP.

Under
the
NOx
SIP
Call,
the
CSP
is
limited
to
use
by
the
large
boilers
and
turbines
that
are
in
the
NOx
Budget
Trading
Program.
Because
IC
engines
are
not
in
the
NOx
Budget
Trading
Program,
they
are
not
eligible
to
receive
allowances
from
the
CSP.
States
have
two
options
for
making
the
pool
available
to
sources
in
the
trading
program.
One
option
is
to
distribute
some
or
all
of
the
pool
to
sources
that
generate
early
reductions
during
ozone
seasons
prior
to
May
1,
2003.
The
second
option
is
to
run
a
public
process
to
provide
tons
to
sources
that
demonstrate
a
need
for
a
compliance
extension.
The
pool
was
created
to
help
that
group
of
sources
meet
compliance
deadlines
without
jeopardizing
electric
reliability.
It
was
not
created
to
address
reliability
problems
in
other
sectors.

G.
Will
the
EGU
Budget
Changes
Affect
the
States
Included
in
the
Three­
State
Memorandum
of
Understanding?
In
February
1999,
Connecticut,
Massachusetts,
Rhode
Island,
and
EPA
signed
a
Memorandum
of
Understanding
(
the
three­
State
MOU).
The
three­
State
MOU
redistributed
Connecticut,

Massachusetts,
and
Rhode
Island's
EGU
emissions
budgets
to
minimize
the
size
differential
between
their
EGU
budgets
Draft
 
Do
not
cite,
quote
or
distribute
142
under
the
NOx
SIP
Call
and
Phase
III
of
the
OTC
NOx
Budget
program.
It
also
reallocated
the
three
States'
CSPs.

Under
the
three­
State
MOU,
Connecticut,
Massachusetts,

and
Rhode
Island
would
collectively
be
meeting
their
NOx
SIP
Call
reduction
responsibilities
because
the
budget
redistribution
did
not
result
in
a
higher
combined
overall
EGU
budget
for
the
three
States.
We
took
action
to
implement
the
three­
State
MOU
and
concurrently
published
proposed
and
direct
final
rules
on
September
15,
1999
(
64
FR
50036
and
49987).
We
subsequently
withdrew
the
direct
final
rule
on
November
1,
1999
due
to
the
receipt
of
adverse
comment
(
64
FR
58792).
The
EGU
budgets
in
today's
action
will
not
affect
the
EGU
budgets
for
Connecticut,

Massachusetts,
and
Rhode
Island
that
we
proposed
in
response
to
the
three­
State
MOU.
We
did
not
finalize
the
proposal
to
act
on
the
three
State
MOU.
Instead,
we
proposed
to
approve
the
three
States'
NOx
SIP
Call
SIP
submittals,
with
budgets
that
reflected
the
three­
State
MOU,
as
collectively
meeting
their
NOx
SIP
Call
budgets.
We
did
not
receive
any
comments
on
the
proposed
approval
of
these
three
State's
SIPs
and
finalized
approval
of
them
on
December
27,
2000.

H.
How
Does
the
Term
"
Budget"
Relate
to
Conformity
Budgets?
Draft
 
Do
not
cite,
quote
or
distribute
143
We
wish
to
clarify
that
the
use
of
the
term
"
budget"
in
this
action
does
not
refer
to
the
transportation
conformity
rule's
use
of
the
term
"
motor
vehicle
emissions
budget,"

defined
at
40
CFR
93.101.
The
budgets
finalized
today
do
not
set
budgets
for
specific
ozone
nonattainment
areas
for
the
purposes
of
transportation
conformity.
Transportation
conformity
budgets
cannot
be
tied
directly
to
the
NOx
SIP
Call
budgets
because
the
latter
are
for
all
or
a
large
part
of
the
State
and
the
former
are
nonattainment­
area­
specific.

For
nonattainment
or
maintenance
areas
in
a
State
covered
by
the
NOx
SIP
Call,
transportation
conformity
budgets
must
reflect
the
mobile
source
controls
assumed
in
the
NOx
SIP
Call
budgets
to
the
extent
that
the
attainment
SIP
ultimately
relies
upon
those
controls.

I.
How
Will
Partial­
State
Trading
be
Administered?

In
the
final
NOx
SIP
Call,
we
offered
to
administer
a
multi­
State
NOx
Budget
Trading
Program
for
States
affected
by
the
NOx
SIP
Call.
In
today's
action,
we
are
including
only
partial
State
budgets
for
Alabama,
Georgia,
Michigan,

and
Missouri.
Therefore,
we
will
administer
a
trading
program
for
the
NOx
SIP
Call
region
that,
for
these
four
States,
includes
only
the
portion
of
the
States
we
are
including
in
the
NOx
SIP
Call.
In
the
final
NOx
SIP
Call,

as
well
as
the
January
18,
2000
final
rulemaking
on
the
Draft
 
Do
not
cite,
quote
or
distribute
42
Banked
allowances
are
those
allowances
that
are
not
used
in
the
ozone
season
for
which
they
are
allocated
and
that
are
therefore
carried
into
the
next
ozone
season.

144
original
eight
Section
126
petitions,
we
authorized
sources
in
States
affected
by
either
the
NOx
SIP
Call
or
the
Section
126
rulemaking
to
trade
with
each
other
through
the
mechanisms
of
the
NOx
Budget
Trading
Program
provided
certain
criteria
were
met.
These
criteria
included
that
States
must
be
subject
to
the
NOx
SIP
Call
and
that
States
must
meet
the
emission
control
level
under
the
final
rule
for
the
NOx
SIP
Call.
The
justification
for
allowing
trading
across
States
is
the
test
of
significant
contribution
which
underlies
both
the
Section
126
rulemaking
and
the
NOx
SIP
Call.
Therefore,
at
this
time,
only
sources
in
the
portions
of
the
States
for
which
a
finding
of
significant
contribution
has
been
made
and
budgets
have
been
established
are
allowed
to
participate
in
trading
with
sources
in
States
which
are
subject
to
either
the
NOx
SIP
Call
or
the
Section
126
rulemaking.

1.
How
Will
Flow
Control
Be
Handled
for
Georgia
and
Missouri?

The
NOx
SIP
Call
(
63
FR
57356)
includes
a
limitation
(
referred
to
as
"
flow
control")
on
the
use
of
banked
allowances
for
compliance
with
the
requirement
to
hold
allowances
covering
emissions
from
affected
units.
42
In
the
Draft
 
Do
not
cite,
quote
or
distribute
Allowances
from
the
CSP
are
considered
banked
at
the
start
of
the
second
year
of
the
program.
See
40
CFR
51.121(
b)(
2)(
ii)(
D).

145
NOx
SIP
Call,
we
noted
that
banking
of
allowances
may
inhibit
or
prohibit
achievement
of
the
desired
emissions
budget
in
a
given
[
ozone]
season
since
the
use
of
banked
allowances
for
compliance
for
a
specific
ozone
season
may
result
in
total
emissions
for
affected
units
exceeding
the
trading
budget
for
that
ozone
season
(
63
FR
25902,
25935;

May
11,
1998).
The
trading
budget
reflects
the
emissions
reductions
mandated,
and
found
to
be
highly
cost
effective,

under
the
NOx
SIP
Call
in
order
to
prevent
significant
contribution
to
nonattainment
in
downwind
States.
Flow
control
addresses
the
potential
problem
caused
by
banking
by
continuing
to
allow
unlimited
banking
of
unused
allowances
but
discouraging
the
"
excessive
use"
of
banked
allowances
for
compliance.
Id.;
see
also
63
FR
57473.

Flow
control
discourages
the
excessive
use
of
banked
allowances
by
discounting
the
use
of
banked
allowances
for
compliance
over
a
specified
threshold.
This
threshold
was
set
at
10
percent
in
the
NOx
SIP
Call
and
applies
to
the
entire
NOx
SIP
Call
region.
The
number
of
banked
allowances
held
in
all
allowance
tracking
system
(
ATS)
accounts
under
the
trading
program
is
tabulated
when
each
ozone
season
is
completed
to
determine
what
percentage
banked
allowances
Draft
 
Do
not
cite,
quote
or
distribute
146
comprise
of
the
total
multi­
State
trading
budget
for
the
next
ozone
season.
If
this
percentage
is
greater
than
10
percent,
flow
control
is
triggered,
and
a
withdrawal
ratio
is
established
for
that
next
ozone
season.
The
withdrawal
ratio
is
calculated
by
dividing
10
percent
of
the
total
multi­
state
trading
program
budget
for
that
next
ozone
season
by
the
total
number
of
banked
allowances
at
the
end
of
the
completed
ozone
season.
The
ratio
is
then
applied
to
each
ATS
compliance
account
that
holds
banked
allowances
at
the
end
of
that
next
ozone
season.
A
unit
can
use
banked
allowances
for
compliance
without
restriction
(
i.
e.,
on
a
one­
allowance­
to­
one
ton
basis)
in
an
amount
not
exceeding
the
amount
in
the
unit's
compliance
account
times
the
withdrawal
ratio.
Banked
allowances
used
for
compliance
in
an
amount
exceeding
that
determined
using
the
withdrawal
ratio
must
be
used
on
a
two­
allowances­
for­
one
ton
basis.

The
NOx
SIP
Call
provided
that
flow
control
provisions
apply
starting
in
the
second
year
of
the
NOx
SIP
Call
program.
(
The
first
ozone
season
in
which
flow
control
applies
and
can
be
triggered
is
referred
to
as
the
"
flow
control
date.")
Specifically,
the
NOx
SIP
Call
established
May
1,
2003
as
the
commencement
date
for
the
NOx
SIP
Call
program
and
required
the
flow
control
provisions
to
apply
starting
in
the
second
year
(
i.
e.,
2004).
See
40
CFR
Draft
 
Do
not
cite,
quote
or
distribute
43
In
approving
trading
program
rules
for
Connecticut,
Delaware,
District
of
Columbia,
Maryland,
Massachusetts,
New
Jersey,
New
York,
and
Rhode
Island,
we
approved
flow
control
dates
of
2004
based
on
the
initial
NOx
SIP
Call
Rule,
under
which
the
program
started
May
1,
2003.
(
We
note
that
we
erroneously
approved
2005
as
the
flow
control
date
for
Pennsylvania,
whose
program
also
begins
in
2003.)
After
the
Court
established
May
31,
2004
as
the
commencement
date
for
the
NOx
SIP
Call
program,
we
approved
2005
as
the
flow
control
date
for
States
(
i.
e.,
Alabama,
Illinois,
Indiana,
Kentucky,
North
Carolina,
South
Carolina,
Tennessee,
and
West
Virginia)
whose
programs
begin
in
2004.
We
also
approved
NOx
SIP
Call
rules
for
two
States
(
Ohio
and
Virginia)
on
the
condition
that
a
2005
flow
control
date
be
adopted.

44
Although
we
approved
several
State
programs
with
a
2004
flow
control
date
(
see
n.
43),
2005
is
the
earliest
year
that
flow
control
is
likely
to
be
triggered
for
those
147
51.121(
b)(
1)(
ii)
and
(
b)(
2)(
ii)(
E).
Subsequent
to
the
initial
NOx
SIP
Call
rulemaking,
the
D.
C.
Circuit
delayed
the
commencement
date
for
the
NOx
SIP
Call
program
to
May
31,
2004,
and
so
the
second
year
of
the
program
­­
and
the
required
flow
control
date
­­
for
State
programs
beginning
in
2004
became
2005.
While
the
regulations
(
§
51.121
and
part
96)
were
not
revised,
we
have
implemented
the
new
flow
control
date
through
the
notice
and
comment
rulemakings
for
approval
of
the
SIPs.
We
have
approved
rules
under
the
NOx
SIP
Call
for
17
states
and
the
District
of
Columbia.
The
approved
rules
provide
for
a
flow
control
date
of
2004
or
2005,43
and,
as
a
practical
matter
the
earliest
date
that
flow
control
can
be
triggered
in
any
of
these
States
and
the
District
of
Columbia
is
2005.44
Draft
 
Do
not
cite,
quote
or
distribute
States.
For
2004,
the
calculation
for
triggering
flow
control
is
the
total
number
of
banked
allowances
in
accounts
as
of
December
1,
2003
(
i.
e.,
only
the
unused
allowances
allocated
for
2003
plus
the
CSP
allowances
for
those
States
with
programs
beginning
in
2003)
divided
by
the
total
trading
budgets
for
the
States
with
programs
in
effect
in
2004
(
i.
e.,
virtually
all
States
in
the
NOx
SIP
Call
region).
Because,
for
this
calculation
for
2004,
the
number
of
States
reflected
in
the
numerator
is
so
much
smaller
than
the
number
of
States
reflected
in
the
denominator,
2005
is
effectively
the
flow
control
date
for
all
States
whose
programs
begin
in
2003.

148
It
is
our
general
intent
to
treat
affected
units
in
Georgia
and
Missouri
in
essentially
the
same
manner
as
affected
units
under
Phase
I
of
the
NOx
SIP
Call.
Once
Georgia
and
Missouri
submit
SIPs
in
accordance
with
today's
rule,
we
will
review
these
SIPs
in
light
of
our
general
intent.
As
we
did
in
the
case
of
the
SIPs
submitted
by
States
under
Phase
I
of
the
NOx
SIP
Call,
we
will
address,

in
the
context
of
reviewing
Georgia's
and
Missouri's
SIPs,

such
issues
as
the
flow
control
provisions
and
the
flow
control
date
and
are
not
revising
the
flow
control
date
in
§
51.121
and
part
96.

However,
we
note
that
if
the
flow
control
provisions
in
the
initial
NOx
SIP
Call
Rule
were
applied
to
Georgia
and
Missouri,
potential
problems
could
arise
because
the
units
in
those
States
would
have
a
flow
control
date,
i.
e.,
the
second
year
(
2008)
of
those
States'
programs,
that
is
3
years
later
than
the
effective
2005
flow
control
date
for
units
in
States
in
Phase
I
of
the
NOx
SIP
Call.
We
will
Draft
 
Do
not
cite,
quote
or
distribute
149
consider
and
resolve
these
potential
problems
when
we
review
Georgia's
and
Missouri's
SIPs
rather
than
in
today's
rule.

In
order
to
provide
guidance
to
Georgia
and
Missouri
in
the
development
of
their
SIPs,
we
are
discussing
below
these
potential
problems.

The
potential
problems
in
applying
the
flow
control
provision
in
§
51.121
and
part
96
to
Georgia
and
Missouri
are
as
follows.
Allowing
2008
to
be
the
flow
control
date
in
Georgia
(
or
Missouri)
could
result
in
an
unfair
advantage
for
units
in
that
State
over
units
in
other
States
with
an
effective
2005
flow
control
date.
Specifically,
for
the
2007
ozone
season
when
the
Georgia
(
or
Missouri)
programs
begin,
banked
allowances
held
for
Georgia
(
or
Missouri)

units
or
by
Georgia
(
or
Missouri)
companies
as
of
November
30,
2006
could
be
a
contributing
factor
for
triggering
flow
control
in
2007
for
all
other
States
with
programs
that
are
in
effect.
If
Georgia
(
or
Missouri)
units
were
to
help
trigger
flow
control
in
2007
but
would
not
be
subject
to
the
flow
control
limitation
on
use
of
banked
allowances
in
2007,

this
would
give
Georgia
(
or
Missouri)
units
an
unfair
advantage
over
units
in
the
other
States.

Further,
should
a
2008
flow
control
date
be
approved
for
Georgia
(
or
Missouri),
this
would
allow
some
companies
to
circumvent
the
earlier
flow
control
dates
established
by
Draft
 
Do
not
cite,
quote
or
distribute
150
other
States.
A
company
with
affected
units
in
both
Georgia
(
or
Missouri)
and
a
State
with
an
effective
2005
flow
control
date
would
be
particularly
advantaged
in
this
regard.
Such
a
company
could
circumvent
the
earlier
flow
control
date
by
exchanging
banked
allowances
held
for
its
units
in
the
State
with
the
2005
flow
control
date
for
2007
allowances
held
for
its
units
in
Georgia
(
or
Missouri).
All
of
these
banked
allowances
could
be
used
in
Georgia
(
or
Missouri)
in
2007
without
application
of
flow
control.

Moreover,
a
company
with
only
units
in
States
with
earlier
flow
control
dates
could
also
circumvent,
to
some
extent,

the
flow
control
provisions
of
those
States.
To
the
extent
that
the
latter
company
could
purchase
2007
allowances
and
sell
banked
allowances,
it
could
also
avoid
the
application
of
the
flow
control
limitation
in
2007.
In
short,
allowing
a
2008
flow
control
date
for
Georgia
(
or
Missouri)
would
allow
erosion
of
the
effectiveness
of
flow
control
for
States
with
an
effective
2005
flow
control
date
and
would
give
an
unfair
advantage
to
some
companies.

We
believe
these
potential
problems
might
be
avoided
if,
under
Georgia's
and
Missouri's
SIPs,
flow
control
is
effective
starting
in
the
first
year
(
2007)
of
their
programs
while
CSP
allowances
for
those
States
continue
to
be
treated
as
banked
allowances
starting
in
the
second
year
Draft
 
Do
not
cite,
quote
or
distribute
151
(
2008)
of
their
programs.
This
approach
would
appear
to
prevent
companies
from
being
able
to
circumvent
the
effective
2005
flow
control
dates
in
other
States'
programs
since
banked
allowances
­­
whether
held
by
units
or
companies
in
Georgia
or
Missouri
or
in
other
States
­­
would
be
subject
to
flow
control
in
2007.
Transferring
banked
allowances
to
Georgia
or
Missouri
units
or
companies
would
not
avoid
flow
control
if
it
is
triggered.

It
also
appears
that
applying
flow
control
in
the
first
year
of
the
program
in
Georgia
and
Missouri
would
not
disadvantage
units
and
companies
in
Georgia
and
Missouri
with
regard
to
their
CSP
allowances.
The
NOx
SIP
Call
established
that
the
CSP
could
be
used
in
the
first
2
years
of
a
State's
trading
program
without
the
application
of
flow
control
to
the
CSP
allowances
in
the
first
year.
Under
the
approach
discussed
above,
the
allowances
from
Georgia's
and
Missouri's
CSPs
(
like
the
CSPs
for
other
States)
would
be
available
for
use
in
the
first
and
second
years
(
2007
and
2008
for
Georgia
and
Missouri).
Because
the
CSP
allowances
would
not
be
considered
banked
until
2008,
these
allowances
could
be
used
in
the
first
year
of
the
program
(
2007)

without
being
affected
by
flow
control.
Thus,
the
Georgia
and
Missouri
CSP
allowances
could
be
used
in
2007
without
limit
regardless
of
whether
flow
control
is
triggered
at
the
Draft
 
Do
not
cite,
quote
or
distribute
152
end
of
the
2006
ozone
season
and
could
not
trigger
flow
control
at
the
end
of
2007.

As
noted
above,
today's
rule
does
not
establish
a
flow
control
date
for
Georgia
and
Missouri.
Instead,
we
are
indicating
how
we
intend
to
address
this
issue
when
we
review
the
Georgia
and
Missouri
SIPs,
and
we
will
consider,

in
conducting
those
reviews,
the
approach
discussed
above
and
any
other
approach
that
is
proposed
for
addressing
the
issue.

J.
What
Is
the
Phase
II
SIP
Submittal
Date?

In
today's
action,
we
are
setting
a
date
for
States
to
submit
SIPs
meeting
the
Phase
II
NOx
budgets
and
the
partial
State
budgets
for
Georgia
and
Missouri.
We
believe
that
an
adequate
timeframe
for
SIP
submittal
is
12
months
from
signature
date
of
this
rulemaking.
We
believe
that
this
schedule
will
allow
adequate
time
for
States
to
promulgate
rules,
and
for
sources
affected
by
a
State's
Phase
II
NOx
strategy
and
by
Georgia
and
Missouri's
NOx
strategy
to
comply
with
the
regulations
by
the
dates
in
this
action.

Please
see
section
K,
below,
for
a
discussion
of
the
compliance
dates.

Comment:
Several
commenters
contend
that
the
range
of
proposed
SIP
submittal
dates
(
i.
e.,
6
months
to
a
year
from
final
promulgation
of
this
rulemaking,
but
no
later
than
Draft
 
Do
not
cite,
quote
or
distribute
153
April
1,
2003)
does
not
allow
enough
time
for
States
to
develop
a
SIP.
They
noted
that
this
is
due
to
the
fact
that
the
proposal
was
published
on
February
22,
2002
and
the
comment
period
was
scheduled
to
end
on
April
15,
2002,
and
that
the
final
rule
would
not
be
promulgated
in
time
to
allow
adequate
time
for
States
to
complete
their
rulemaking
processes.
These
commenters
fell
into
several
categories
based
on
their
recommendation
for
a
SIP
submittal
date:
(
1)

EPA
is
not
allowing
enough
time
for
SIP
submittal;
(
2)
EPA
should
set
a
SIP
submittal
date
12
months
from
the
date
of
final
promulgation
of
this
rule;
(
3)
EPA
should
allow
more
than
12
months
for
States
to
submit
SIPs;
and
(
4)
EPA
should
allow
18
months
for
SIP
submittal
as
authorized
in
section
110(
k)(
5).

Response:
After
considering
these
comments,
we
are
requiring
that
SIP
revisions
be
submitted
within
12
months
after
the
date
of
signature
of
this
final
rule.
We
believe
this
is
adequate
time
for
States
to
submit
SIP
revisions
reflecting
the
reductions
required
by
this
phase
of
the
NOx
SIP
Call.
In
response
to
the
court
decision
in
Michigan
v.

EPA,
213
F.
3d
663
(
D.
C.
Cir.
2000),
cert.
denied,
121
S.
Ct.

1225
(
2001),
we
divided
the
NOx
SIP
Call
into
two
phases
 
Phase
I
which
accounted
for
90
percent
of
the
total
reductions
required
by
the
NOx
SIP
Call,
and
Phase
II
which
Draft
 
Do
not
cite,
quote
or
distribute
154
will
achieve
approximately
10
percent
of
the
total
reductions
required
by
the
NOx
SIP
call.
Thus,
because
Phase
II
of
the
NOx
SIP
Call
requires
relatively
smaller
NOx
emissions
reductions
and
because
it
applies
to
a
much
smaller
subset
of
sources,
we
believe
that
12
months
is
adequate
time
for
States
to
develop
and
submit
the
required
SIP
revisions.
In
addition,
as
earlier
stated,
this
action
is
being
taken
under
section
110(
k)(
5)
which
requires
SIP
revisions
within
a
specified
period
but
"
not
to
exceed
18
months"
after
a
finding
of
inadequacy
by
the
Agency.

Initially
we
had
allowed
States
12
months
for
submittal
of
SIPs
meeting
the
full
NOx
SIP
Call,
with
September
30,

1999
as
the
submission
date.
On
May
25,
1999,
in
response
to
a
request
by
States
challenging
the
NOx
SIP
Call,
the
D.
C.
Circuit
issued
a
stay
of
the
SIP
submission
deadline
pending
further
order
of
the
Court.
Michigan,
213
F.
3d
663
(
D.
C.
Cir.
2000),
cert.
denied,
121
S.
Ct.
1225
(
2001)
(
May
25,
1999
order
granting
stay
in
part).
Subsequently,
we
filed
a
motion
on
April
11,
2000,
requesting
the
court
to
lift
the
stay
of
the
SIP
submission
date
and
on
June
22,

2000,
the
court
lifted
the
stay
and
established
October
30,

2000,
as
the
new
SIP
submission
date.
Thus,
by
setting
this
submission
date,
the
Court
recognized
the
12­
month
submission
schedule
required
in
the
NOx
SIP
Call.
Draft
 
Do
not
cite,
quote
or
distribute
155
In
setting
this
time
frame,
we
also
recognize
that
the
proposed
NOx
SIP
submittal
date
of
6
months
to
1
year
from
final
promulgation
of
this
rulemaking,
but
no
later
than
April
1,
2003,
is
no
longer
appropriate
due
to
the
February
22,
2002
publication
date
of
the
proposed
rule.
We
are
also
aware
that
some
States
have
lengthy
rulemaking
processes
that
may
require
longer
than
12
months
for
full
adoption
of
regulations.
However,
States
have
the
ability
to
set
their
rulemaking
procedures
and
can
provide
adequate
mechanisms
to
adopt
regulations
to
address
interstate
transport.
Many
States
already
have
emergency
or
other
shortened
procedures
in
place
in
order
to
bypass
regular
rulemaking
procedures
in
certain
circumstances.
We
also
note
that
some
States
have
already
adopted
SIPs
that
comply
fully
with
the
NOx
SIP
Call.

Moreover,
we
note
that
States
that
fail
to
submit
SIPs
within
12
months
are
not
precluded
from
submitting
plans
after
that
date.
Areas
will
not
be
subject
to
mandatory
sanctions
under
section
179
of
the
CAA
until
18
months
after
we
find
that
the
State
failed
to
submit
a
plan
in
response
to
the
NOx
SIP
Call.
Furthermore,
if
the
State
makes
a
late
submission,
our
approval
of
that
program
would
serve
to
replace
any
Federal
plan
that
may
have
taken
effect
in
the
interim.
We
note
that
States
can
submit
draft
plans
(
i.
e.,
Draft
 
Do
not
cite,
quote
or
distribute
45
Technical
Support
Document,
"
Responses
to
Significant
Comments
on
the
Proposed
Finding
of
Significant
Contribution
and
Rulemaking
for
CertainStates
in
the
OTAG
Region
for
Purposes
of
Reducing
Regional
Transport
of
Ozone,"
Docket
No.
A­
96­
56,
Item
No.
VI­
C­
01,
September
1998.

156
plans
that
have
not
completed
the
final
steps
in
the
State
administrative
process)
for
parallel
processing.
See
47
FR
2703
(
June
23,
1982).
While
this
type
of
submission
may
not
preclude
a
finding
of
failure
to
submit,
it
can
help
ensure
that
the
State
program
is
approved
as
a
SIP
revision
and
as
a
replacement
for
any
promulgated
Federal
implementation
plan)
in
the
most
expeditious
manner.
Also,
as
we
did
for
the
Phase
I
NOx
SIP
submittals,
the
EPA
Regional
Offices
and
Headquarters
will
work
closely
with
the
States
to
ensure
that
approvability
issues
are
quickly
resolved
in
order
to
allow
SIPs
to
be
submitted
as
expeditiously
as
possible.
45
[
Section
II.
J,
OAR­
2001­
0008,
comments
XII­
D­
28,
XII­
D­
29
K.
What
Are
the
Phase
II
Compliance
Dates?

We
are
setting
a
Phase
II
compliance
date
of
May
1,

2007.
This
date
is
24
months
after
the
SIP
submittal
date
plus
the
days
until
the
next
ozone
season
begins.
However,

sources
already
controlled
in
an
approved
Phase
I
SIP
are
required
to
meet
the
compliance
date
stipulated
in
that
SIP,

including
non­
Acid
Rain
EGUs
and
any
cogeneration
units
that
were
previously
classified
as
EGUs
and
whose
classification
changed
to
non­
EGUs
under
today's
rule.
Draft
 
Do
not
cite,
quote
or
distribute
157
In
this
section,
it
is
important
to
note
that
although
compliance
dates
are
discussed
for
certain
EGUs
and
non­
EGUs
and
IC
engines,
States
may
choose
to
control
other
sources.

As
stated
in
the
original
NOx
SIP
Call:

"
States
are
not
constrained
to
adopt
measures
that
mirror
the
measures
EPA
used
in
calculating
the
budgets.
In
fact,
EPA
believes
that
many
control
measures
not
on
the
list
relied
upon
to
develop
EPA's
proposed
budgets
are
reasonable
 
especially
those,
like
enhanced
vehicle
inspection
and
maintenance
programs,
that
yield
both
NOx
and
VOC
emissions
reductions.
Thus,
one
State
may
choose
to
primarily
achieve
emissions
reductions
from
stationary
sources
while
another
State
may
focus
emission
reductions
from
the
mobile
source
sector
(
63
FR
57378,
October
27,
1998).

1.
How
Are
We
Handling
Non­
Acid
Rain
EGUs
and
Any
Cogeneration
Units
That
Were
Previously
Classified
as
EGUs
and
Whose
Classification
Changed
to
Non­
EGUs
Under
Today's
Rule?

We
proposed
a
compliance
date
of
May
31,
2004
(
or,
if
later,
the
date
on
which
the
source
commences
operation)
for
all
Phase
II
EGUs
and
non­
EGUs
in
Alabama,
Connecticut,

District
of
Columbia,
Delaware,
Illinois,
Indiana,
Kentucky,

Massachusetts,
Maryland,
Michigan,
North
Carolina,
New
Jersey,
New
York,
Ohio,
Pennsylvania,
Rhode
Island,
South
Carolina,
Tennessee,
Virginia,
and
West
Virginia.
We
also
proposed
a
compliance
date
of
May
1,
2005
(
or,
if
later,
the
date
on
which
the
source
commences
operation)
for
all
Draft
 
Do
not
cite,
quote
or
distribute
46
We
note
that
the
non­
EGU
classification
of
those
cogeneration
units
that
have
been
consistently
treated
as
non­
EGUs
in
the
NOx
SIP
Call
and
the
Section
126
Rule
was
not
remanded
and
vacated
by
the
Court,
and
we
maintain
that
the
May
31,
2004
compliance
date
for
such
units
is
not
at
issue
in
today's
rulemaking.
However,
even
assuming
arguendo
that
their
compliance
date
were
at
issue,
there
would
be
no
basis
for
establishing
a
later
compliance
date
since
these
units
(
like,
e.
g.,
the
non­
Acid
Rain
EGUs)
are
already
subject
to
the
May
31,
2004
date
under
the
Phase
I
SIPs.

158
sources
in
Georgia
and
Missouri.
The
compliance
dates
mark
the
beginning
of
the
periods
during
which
units
in
the
trading
program
must
hold
at
least
enough
NOx
allowances
to
cover
their
ozone
season
NOx
emissions.

The
proposed
compliance
date
of
May
31,
2004
(
or,
if
later,
the
date
on
which
the
source
commences
operation)
was
designed
to
provide
Phase
II
EGUs
and
non­
EGUs
a
little
over
12
months
after
the
deadline
for
State
submission
of
Phase
II
SIPs
covering
such
units
to
install
any
necessary
emission
controls.
In
today's
rule,
we
are
finalizing
a
deadline
of
[
insert
12
months
after
signature]
for
submission
of
Phase
II
SIPs.
However,
we
believe
that
for
all
of
the
States
(
except
Georgia
and
Missouri,
which
are
addressed
separately
below),
non­
Acid
Rain
EGUs
and
any
cogeneration
units
that
were
previously
classified
as
EGUs
and
whose
classification
changed
to
non­
EGUs
under
today's
rule
were
included
in
the
Phase
I
SIPs
that
were
already
submitted.
46
Several
States
(
i.
e.,
Connecticut,
District
of
Draft
 
Do
not
cite,
quote
or
distribute
159
Columbia,
Delaware,
Massachusetts,
Maryland,
New
Jersey,
New
York,
Pennsylvania,
and
Rhode
Island)
have
submitted
SIPs
that
cover
non­
Acid
Rain
EGUs
and
any
cogeneration
units
whose
classification
changed
from
EGUs
to
non­
EGUs
under
today's
rule,
as
well
as
Phase
I
EGUs
and
non­
EGUs,
and
require
compliance
with
the
allowance
holding
requirement
starting
May
1,
2003
(
or,
if
later,
the
date
on
which
the
source
commences
operation).
The
remaining
States
other
than
Georgia
and
Missouri
(
i.
e.,
Alabama,
Illinois,
Indiana,

Kentucky,
Michigan,
North
Carolina,
Ohio,
South
Carolina,

Tennessee,
Virginia,
and
West
Virginia)
have
submitted
SIPs
that
cover
non­
Acid
Rain
EGUs
and
any
cogeneration
units
whose
classification
changed
from
EGUs
to
non­
EGUs
under
today's
rule,
as
well
as
Phase
I
EGUs
and
non­
EGUs
and
require
compliance
starting
May
31,
2004
(
or,
if
later,
the
date
on
which
the
source
commences
operation).
The
coverage
of
non­
Acid
Rain
EGUs
and
any
cogeneration
units
whose
classification
changed
from
EGUs
to
non­
EGUs
under
today's
rule
is
reflected
both
in
the
applicability
provisions
in
the
various
SIPs
 
which
provisions
cover
EGUs
and
non­
EGUs
without
assuming
any
non­
Acid
Rain
units
or
any
cogeneration
units
 
and
in
the
State
budget
demonstrations
and
allowance
allocations
 
which
list
the
affected
units
including
the
non­
Acid
Rain
EGUs
and
any
cogeneration
units
whose
Draft
 
Do
not
cite,
quote
or
distribute
47
To
the
extent
that
the
revisions
of
the
EGU
and
non­
EGU
definitions
have
such
an
impact
on
any
specific
units,
we
will
address
the
matter
in
connection
with
our
review
of
the
relevant
State
Phase
II
SIP
provisions.

160
classification
changed
from
EGUs
to
non­
EGUs
under
today's
rule.
(
See
docket
Item
No.___).
Although,
elsewhere
in
today's
final
rule,
we
are
revising
the
definition
of
EGU
and
non­
EGU,
we
believe
that
these
revisions
will
require
the
reclassification
of
few,
if
any,
units
as
EGUs
and
non­

EGUs
and
will
not
make
any
additional
units
subject
to
the
NOx
SIP
Call.
See
section
II.
A.
4
of
this
preamble.
47
Since
all
Phase
II
non­
Acid
Rain
EGUs
and
any
cogeneration
units
whose
classification
changed
from
EGUs
to
non­
EGUs
under
today's
rule
in
these
States
are
already
subject
to
a
compliance
date
of
May
1,
2003
or
May
31,
2004
(
or,
if
later,
the
date
on
which
the
source
commences
operation),
we
see
no
basis
for
extending
the
NOx
SIP
Call
compliance
deadline
beyond
the
date
stipulated
in
the
Phase
I
SIPs
under
which
these
units
are
covered.
The
CAA
rests
on
an
"
overarching"
principle
that
the
NAAQS
be
achieved
as
expeditiously
as
possible
(
63
FR
57356,
57449,
October
27,

1998).
For
example,
under
section
181
of
the
CAA,
the
"
primary
standard
attainment
date
for
ozone
shall
be
as
expeditiously
as
practicable
but
not
later
than
[
certain
statutorily
prescribed
attainment
dates]."
42
U.
S.
C.
7511;

see
also
42
U.
S.
C.
7502(
a)(
2)(
A).
The
State
trading
budgets
Draft
 
Do
not
cite,
quote
or
distribute
161
under
the
NOx
SIP
Call
reflect
the
emissions
reductions
mandated
under
the
NOx
SIP
Call
in
order
to
prevent
significant
contribution
to
nonattainment
in
downwind
States.
Under
these
circumstances,
we
believe
that
the
CAA's
overarching
objective
of
expeditious
as
practicable
attainment
applies
to
these
units.

A
number
of
commenters
(
including
several
States
that
have
adopted
SIPs
with
May
31,
2004
compliance
dates
for
non­
Acid
Rain
EGUs
and
any
cogeneration
units
whose
classification
changed
from
EGUs
to
non­
EGUs
under
today's
rule)
suggested
that
a
compliance
date
of
May
31,
2004
did
not
provide
sources
enough
time
to
install
emission
controls.
Some
commenters
suggested
that
units
should
be
given
2
years
after
submittal
of
SIPs
to
comply.
Several
other
commenters
suggested
that
a
compliance
deadline
should
be
set
1,309
days
after
the
required
SIP
submittal
date
to
be
consistent
with
the
D.
C.
Circuit's
August
30,
2000
order
related
to
compliance
dates
under
the
NOx
SIP
Call.
As
explained
above,
we
do
not
believe
it
is
necessary
or
appropriate
to
extend
the
compliance
date
beyond
May
31,

2004
because
the
States
involved
have
already
adopted
rules
requiring
non­
Acid
Rain
EGUs
and
any
cogeneration
units
whose
classification
changed
from
EGUs
to
non­
EGUs
under
today's
rule
to
comply
by
that
date
or
earlier.
It
should
Draft
 
Do
not
cite,
quote
or
distribute
162
also
be
noted
that,
even
if
the
units
had
not
already
been
included
in
the
State's
Phase
I
SIPs,
the
1,309­
day
period
used
for
setting
the
May
31,
2004
compliance
date
for
Phase
I
SIPs
would
not
be
appropriate
for
those
units.
The
Court's
decision
to
provide
units
1,309
days
after
submittal
of
SIPs
was
based
on
the
amount
of
time
that
we
provided
units
to
comply
with
the
original
NOx
SIP
Call,
which
had
a
compliance
deadline
of
May
1,
2003.
The
original
NOx
SIP
Call
required
States
to
make
significantly
more
emissions
reductions
(
i.
e.,
all
the
reductions
that
were
subsequently
designated
as
either
Phase
I
or
Phase
II
reductions
in
response
to
the
Court's
decision)
than
the
reductions
(
i.
e.,

only
the
Phase
II
reductions
for
non­
Acid
Rain
EGUs
and
any
cogeneration
units
whose
classification
changed
from
EGUs
to
non­
EGUs
under
today's
rule)
addressed
here.
Greater
emissions
reductions
require
the
installation
of
more
emission
controls,
which
in
turn
requires
more
resources
such
as
boiler­
makers
and
cranes.
The
analysis
that
we
performed
for
the
proposed
Phase
II
rule
shows
that
less
time
is
required
to
install
emission
controls
for
the
smaller
number
of
Phase
II
units
than
the
significantly
larger
number
of
Phase
I
units
in
the
trading
program.

2.
What
Compliance
Date
Are
We
Finalizing
for
IC
Engines
and
What
is
the
Technical
Feasibility
of
this
Date?
Draft
 
Do
not
cite,
quote
or
distribute
163
We
are
setting
a
compliance
date
for
IC
engines
of
May
1,
2007
(
or,
if
later,
the
date
on
which
the
source
commences
operation).
This
date
is
24
months
after
the
SIP
submittal
date
plus
the
days
until
the
next
ozone
season
begins.

Comment:
Several
commenters
from
the
pipeline
industry
suggest
the
need
to
stagger
or
phase­
in
the
compliance
activities
over
several
years.
Additional
comments
from
the
pipeline
industry
state
that
we
ignore
time
needed
to
get
permits;
that
we
assume
160
engines
would
be
off­
line
in
the
same
winter
heating
season;
and
that
we
failed
to
consider
the
problem
of
having
multiple
engines
at
one
facility
subject
to
retrofit
requirements
during
the
same
short
compliance
timeframe.

Comments
from
22
citizen
groups
recommend
the
May
2004
and
May
2005
dates
(
or,
if
later,
the
date
on
which
the
source
commences
operation),
as
proposed.
One
State
supports
the
May
2005
compliance
deadline
proposed.
All
other
commenters
request
that
we
provide
more
time
than
was
proposed.
Another
State
believes
that
a
minimum
of
24
months
from
the
date
final
SIP
submittals
is
needed
for
sources
to
complete
the
necessary
construction
and
installation
of
controls
to
comply
with
the
Phase
II
provisions.
A
third
State
recommends
the
compliance
date
be
Draft
 
Do
not
cite,
quote
or
distribute
164
1,309
days
after
the
SIP
submittal
date.
Pipeline
industry
comments
generally
recommend
May
2007
or
36
to
43
months
from
SIP
submittal.
These
commenters
refer
to
the
1998
NOx
SIP
Call
Rule
which
gave
43
months
from
SIP
submittal.

Utility
group
comments
also
recommend
we
should
apply
the
same
1,309­
day
compliance
period
for
the
Phase
II
NOx
SIP
Call
requirements
that
applies
to
sources
for
the
Phase
I
compliance
pursuant
to
the
original
NOx
SIP
Call
Rule
schedule.

Response:
The
pipeline
industry
has
considerable
experience
with
the
installation
of
LEC
technology.
While
there
is
some
evidence
that
installation
of
controls
on
a
few
engines
within
1
year
is
reasonable,
installing
controls
on
many
engines
in
a
narrow
timeframe
is
more
problematic.
As
discussed
below,
we
believe
that
the
proposed
timeframe
of
about
13
months
should
be
extended
to
a
minimum
of
24
months
from
the
SIP
submittal
date
and
the
initial
compliance
date
should
occur
within
the
ozone
season.

We
obtained
additional
information
regarding
this
issue.
One
manufacturer
estimated
the
time
between
request
for
cost
proposal
and
contract
to
be
2
to
5
months
and
typically
3
to
4
months.
It
then
takes
4
to
5
months
for
delivery
and
an
additional
1
month
to
install
and
commence
Draft
 
Do
not
cite,
quote
or
distribute
48
See
Docket
No.
OAR­
2001­
0009,
Item
#
XII­
E­
01.
49
See
Docket
No.
OAR­
2001­
0008
(
Legacy
Docket
No.
A­
96­
56),
Item
No.
XII­
E­
02.
50
See
http://
www.
dieselsupply.
com/
dscartic.
htm
for
reprint
of
article
from
May
1998
of
"
American
Oil
&
Gas
Reporter."

165
operation.
This
adds
up
to
a
total
of
7
to
11
months.
48
Another
manufacturer
estimated
the
time
between
cost
proposal
and
contract
is
2
to
4
weeks
to
obtain
bids;
2
to
3
months
for
selection
of
bids;
12
to
20
weeks
for
parts
delivery
to
site;
and
2
weeks
to
1
½
months
for
field
installation.
49
Another
manufacturer
estimated
from
request
for
cost
bids
to
shipping
of
parts
takes
6
to
8
months
for
delivery
and
an
additional
2
to
4
weeks
to
install
and
commence
operation.
This
adds
up
to
a
total
of
6
to
9
months.
17
Information
from
the
Ventura
County
Air
Pollution
Control
District
in
California
estimated
2
weeks
to
1
month
to
install
LEC
and
the
total
time
estimated
from
request
for
cost
proposal
and
commencing
operation
of
LEC
was
6
to
9
months.
A
gas
pipeline
company,
CMS
Energy,
stated
that
a
compliance
schedule
of
11
months
was
easy
to
meet
for
one
to
two
engines
but
would
put
a
stress
on
the
system
for
200
engines.
Columbia
Gas
Transmission
Corporation
installed
controls
on
two
engines
in
Bedford
County,
Pennsylvania
in
3
days,
meeting
the
3.0
g/
bhp­
hr
standard
set
by
the
State.
50
Thus,
there
is
some
agreement
that
the
necessary
compliance
period
for
installation
of
controls
on
a
small
number
of
Draft
 
Do
not
cite,
quote
or
distribute
166
engines
is
less
than
1
year.

We
disagree
with
the
comment
that
160
engines
would
be
off­
line
at
the
same
time.
We
expect
some
companies
to
choose
to
phase­
in
installation
of
the
control
equipment
over
a
2­
year
period
(
or
longer
if
the
companies
begin
retrofit
activities
sooner)
and
that
installation
activities
would
occur
primarily
in
the
summer
along
with
normally
scheduled
maintenance
activities.
Further,
as
noted
below,

not
all
of
the
potentially
affected
IC
engines
should
be
expected
to
need
LEC
retrofits
and
not
in
the
same
timeframe.

In
response
to
Phase
II
of
the
NOx
SIP
Call,
some
States
may
seek
emissions
reductions
from
source
categories
other
than
IC
engines.
Other
States
have
already
met
their
NOx
budgets
and
do
not
need
to
further
control
IC
engines
for
purposes
of
the
NOx
SIP
Call.
Still
other
States
have
met
at
least
a
portion
of
the
Phase
II
NOx
SIP
Call
reductions
due
to
emissions
reductions
affecting
other
source
categories
contained
in
their
1­
hour
ozone
nonattainment
area
plans.
This
reduces
the
need
to
retrofit
IC
engines
in
those
States.

In
many
cases,
companies
may
use
"
early
reductions"

achieved
at
IC
engines
due
to
other
requirements,
such
as
Draft
 
Do
not
cite,
quote
or
distribute
51
Memo
from
Lydia
Wegman,
Director,
Air
Quality
Strategies
and
Standards
Division,
U.
S.
EPA
to
Air
Division
Directors,
U.
S.
EPA
Regions
I­
V,
VII
(
August
22,
2002),
providing
guidance
on
issues
related
to
stationary
IC
engines
and
the
NOx
SIP
Call.

52
"
IC
Engine
OTAG
Questions"
document
prepared
by
INGAA,
February
17,
2000.
Many
of
these
engines
are
smaller
than
the
"
large"
engines
identified
in
the
NOx
SIP
Call.

53
Alpha
Gamma
memo
of
June
19,
2002
(
Docket
No.
OAR­
2001­
0008,
Item
No.
0917).

54
See
proposed
rule
at
67
FR
77845.

167
RACT.
51
For
example,
many
IC
engines
were
previously
controlled
to
meet
RACT
requirements
in
many
of
the
NOx
SIP
Call
States.
These
emissions
reductions
help
States
meet
their
NOx
budgets
and,
thus,
decrease
the
amount
of
additional
reductions
needed.
According
to
information
submitted
by
INGAA,
a
1996­
97
survey
determined
that
245
lean
burn
engines
in
the
NOx
SIP
Call
area
have
LEC.
52
Many
engines
in
the
NOx
SIP
Call
area
already
have
decreased
NOx
emissions
at
rich­
burn
engines
through
NSCR.
53
States
may
choose
to
credit
these
reductions
instead
of
requiring
new
reductions
at
other
engines
in
order
to
meet
the
SIP
budget.

Many
more
NOx
reductions
are
likely
to
result
from
future
maximum
achievable
control
technology
(
MACT)
controls
at
IC
engines.
54
These
factors
also
reduce
the
need
to
retrofit
IC
engines
in
some
States.

We
agree
with
industry
comments
that
pipeline
companies
Draft
 
Do
not
cite,
quote
or
distribute
55
INGAA
letter
of
July
16,
2002
[
Docket
No.
OAR­
2001­
0008,
Item
No.
0918].

56
A
top­
end
overhaul
is
generally
recommended
between
8,000
and
30,000
hours
of
operation
that
entails
a
cylinder
head
and
turbocharger
rebuild
(
see
Table
4
from
"
Technology
Characterization:
Reciprocating
Engines"
prepared
by
Energy
Nexus
Group
for
EPA,
2­
02).

57
GRI
12­
98
report
"
NOx
Control
for
Two­
Cycle
Pipeline
Reciprocating
Engines,"
page
4­
11.
(
Docket
No.
OAR­
2001­
0008,
Item
No.
XII­
K­
24.)

168
will
phase­
in
the
control
equipment
over
a
multi­
year
timeframe.
55
Some
companies
may
choose
to
stagger
installation
of
the
controls,
beginning
even
before
completion
of
our
rulemaking.
22
Stretching
out
the
installation
timeframe
in
this
manner
would
help
the
companies
achieve
the
results
on
time.
Further,
companies
might
choose
to
install
controls
early
in
some
of
their
engines
in
a
timeframe
that
coincides
with
the
engine
rebuild
cycle.
56
In
another
case,
installation
of
the
LEC
retrofit
kit
was
estimated
to
span
3
to
4
weeks
and
the
installation
was
not
expected
to
impact
the
normal
maintenance
interval.
57
These
approaches
will
help
reduce
the
time
needed
to
install
the
controls.

We
believe
the
industry
has
demonstrated
that
multiple
engines
at
compressor
stations
can
be
successfully
retrofitted
over
a
24­
month
timeframe.
For
example,
the
Jefferson
Town
Compressor
Station's
RACT
compliance
plan
of
April
2000
describes
the
installation
of
LEC
using
a
phased
Draft
 
Do
not
cite,
quote
or
distribute
58
See
http://
www.
enginuityinc.
com
169
approach
over
a
2­
year
period.
Four
engines
were
retrofitted
during
summer
2001
and
the
remaining
five
engines
were
retrofitted
in
summer
2002.
Each
engine
was
expected
to
be
out
of
service
for
approximately
6
weeks
and,

due
to
heavy
demand
during
winter
heating
season,
all
engines
were
expected
to
be
operable
from
October
to
April.

Two
additional
cases
show
installation
on
multiple
engines
in
short
time
periods.
Southern
California
Gas
Company
completed
testing
of
one
engine
in
1995
and
installed
precombustion
chambers
on
six
engines
in
its
Mojave
Desert
operating
area.
The
conversion
of
the
first
unit
was
completed
in
October
1995
and
the
conversion
of
the
sixth
unit
was
completed
in
November
1996.
The
engines
met
the
2.0
g/
bhp­
hr
standard
set
by
the
Mojave
Air
District.

Furthermore,
as
cited
in
a
case
study
in
Vidor,
Texas,
six
engines
in
the
Beaumont/
Port
Arthur
area
were
retrofitted
in
the
summer
of
1999.58
As
shown
below,
we
also
examined
historic
timeframes
allowed
by
the
Congress
and
various
regulatory
agencies
to
achieve
compliance
with
NOx
requirements
following
State/
local
rule
adoption.
These
timeframes
generally
illustrate
the
successful
implementation
of
past
regulatory
programs
involving
the
installation
of
NOx
controls.
Draft
 
Do
not
cite,
quote
or
distribute
59
"
Determination
of
RACT
and
BARCT
for
Stationary
Spark­
Ignited
Internal
Combustion
Engines,
"
California
Air
170
In
the
1990
Amendments
to
the
CAA,
Congress
added
RACT
requirements
for
major
sources
of
NOx.
All
categories
of
major
NOx
sources
in
certain
areas
of
the
nation
were
required
to
install
RACT
as
expeditiously
as
practicable
or
no
later
than
May
31,
1995.
Thus,
Congress
allowed
a
maximum
of
30
months
from
the
SIP
submittal
deadline
of
November
15,
1992
for
a
much
larger
number
of
sources
than
affected
by
this
rulemaking.

Subsequent
to
the
initial
set
of
NOx
RACT
SIP
revisions,
we
approved
NOx
RACT
SIP
submittals
in
some
areas
which
had
been
exempt
from
the
requirements.
For
example,

in
Dallas,
SIP
rules
required
RACT
as
expeditiously
as
practicable
or
24
months
from
the
State
adoption
date
(
rule
adopted
March
21,
1999).
The
State
of
Texas,
on
December
31,
1997,
implemented
a
requirement
for
all
major
NOx
sources
in
the
Houston
area
to
implement
RACT;
the
State
adopted
a
compliance
date
of
November
15,
1999
for
this
program
(
22.5
months).
In
a
recent
case,
the
State
of
Louisiana
allowed
up
to
a
3­
year
period
in
Baton
Rouge,

coinciding
with
their
attainment
deadline.

For
engines
subject
to
RACT
limits,
the
California
Air
Resources
Board
guidance
document
on
IC
engines
recommends
final
compliance
within
2
years
of
district
rule
adoption.
59
Draft
 
Do
not
cite,
quote
or
distribute
Resources
Board,
November
2001,
pg.
IV­
15.
(
Docket
No.
OAR­
2001­
0008,
Item
No.
XII­
K­
71.)

171
The
guidance
states
that
this
time
period
should
be
sufficient
to
evaluate
control
options,
place
purchase
orders,
install
equipment,
and
perform
compliance
verification
testing.
The
Sacramento
Air
District
in
California
required
compliance
within
2
years
of
rule
adoption
(
June
1995).

Regarding
the
need
to
obtain
permits,
we
believe
that
States
will
process
permits
expeditiously,
especially
those
permits
associated
with
pollution
control
projects.
We
have
specifically
encouraged
States
in
a
recent
memo
(
see
NSR
exclusion
discussion
in
section
II.
B.
2.
c
of
this
final
rule)

to
consider
exempting
pollution
control
projects
from
certain
permitting
requirements.
Further,
by
moving
the
compliance
date
to
at
least
24
months
after
the
SIP
submittal
date,
we
believe
that
the
time
needed
to
revise
permits
will
not
adversely
affect
the
compliance
schedule.

Further,
the
CAA
contains
an
overarching
principle
that
downwind
areas
attain
the
ozone
NAAQS
"
as
expeditiously
as
practicable."
[
Sections
191(
a),
172(
a)].
The
emissions
reductions
from
today's
rulemaking
reflect
the
emissions
reductions
mandated
under
the
NOx
SIP
Call
in
order
to
prevent
significant
contribution
to
nonattainment
in
downwind
States.
Thus,
we
are
setting
an
implementation
Draft
 
Do
not
cite,
quote
or
distribute
172
date
that
will
assure
that
the
downwind
States
realize
the
air
quality
benefits
of
NOx
reductions
in
order
to
achieve
attainment
or
reasonable
further
progress
toward
attainment
(
63
FR
57449­
50).

Although
we
provided
a
compliance
date
of
1,309
days
for
Phase
I
sources
from
the
SIP
submittal
date,
we
do
not
believe
that
a
similar
compliance
period
is
needed
for
the
sources
affected
by
today's
rulemaking.
This
is
because
today's
rulemaking
affects
a
smaller
subset
of
sources
than
Phase
I
sources,
and
which
sources
have
been
aware
of
the
applicability
of
the
NOx
SIP
Call
since
1998.
In
addition,

as
discussed
earlier,
States
are
free
to
choose
which
sources
to
regulate
in
compliance
with
the
NOx
SIP
Call
requirements.
Also,
some
States
have
already
adopted
SIPs
that
meet
the
full
NOx
SIP
Call
requirements.

In
summary,
several
factors
described
above
will
serve
to
minimize
the
number
of
large
IC
engines
that
would
need
to
be
scheduled
for
LEC
retrofit.
Further,
companies
that
phase­
in
compliance
activities
over
several
years
would
also
reduce
the
number
of
IC
engines
needing
LEC
retrofit
per
year.
It
is
important
to
note
that
RACT
experience
shows
that
companies
can
install
LEC
retrofit
over
a
2­
year
timeframe,
even
where
multiple
engines
are
located
at
the
same
compressor
station.
In
recent
RACT
compliance
time
Draft
 
Do
not
cite,
quote
or
distribute
173
decisions,
State/
local
regulatory
agencies
generally
specified
24­
month
periods
to
install
controls.
The
Congress
in
its
1990
CAA
Amendments
allowed
a
maximum
of
30
months
for
all
major
NOx
sources
across
the
nation
to
install
RACT;
this
was
a
much
larger
task
than
installation
of
controls
at
IC
engines
in
certain
States.
As
a
result,

we
believe
that
a
2­
year
period
after
the
SIP
submittal
due
date
is
adequate
for
the
installation
of
controls.

Further,
because
the
NOx
SIP
Call
is
directed
at
emissions
during
the
ozone
season,
we
believe
that
the
initial
month
where
compliance
is
required
should
occur
during
the
ozone
season.
Therefore,
the
compliance
date
is
May
1,
2007
(
or,
if
later,
the
date
on
which
the
source
commences
operation).

3.
What
Compliance
Date
Are
We
Finalizing
for
Georgia
and
Missouri?

For
all
sources
in
Georgia
and
Missouri,
we
proposed
a
compliance
date
of
May
1,
2005
(
or,
if
later,
the
date
on
which
the
source
commences
operation).
This
compliance
date
was
based
on
a
proposed
SIP
submittal
deadline
of
April
1,

2003
and
would
have
provided
sources
25
months
after
SIP
submittal
to
install
controls.
Based
on
the
[
Insert
12
months
from
signature
date]
SIP
submittal
deadline
being
finalized
in
today's
final
rule,
providing
sources
with
25
Draft
 
Do
not
cite,
quote
or
distribute
174
months
to
install
controls
would
result
in
a
compliance
deadline
of
September
30,
2006.
Because
this
would
be
after
the
2006
ozone
season,
we
are
finalizing
a
compliance
deadline
of
May
1,
2007
(
or,
if
later,
the
date
on
which
the
source
commences
operation).
As
we
explained
in
the
NOx
SIP
Call,
we
believe
a
25­
month
compliance
time
frame
is
reasonable
given
the
amount
of
controls
that
need
to
be
installed.
If
Missouri
and/
or
Georgia
elect
to
control
large
EGUs
under
a
trading
program,
we
project
that
the
most
time
consuming
control
installation
will
require
installation
of
two
SCRs
and
one
SNCR.
We
also
project
that
this
can
be
done
in
25
months
(
67
FR
8395).

Several
commenters
suggested
that
a
May
1,
2005
compliance
date
was
reasonable
for
Georgia
and
Missouri
if
the
rule
were
finalized
in
time
to
give
States
1
year
to
develop
a
regulation
and
SIPs
were
due
by
April
1,
2003.

One
commenter
added
that
many
EGUs
will
be
installing
controls
before
2005
in
order
to
comply
with
a
State
ozone
attainment
plan.
We
agree
that
the
proposed
compliance
deadline
was
reasonable
when
it
was
proposed.
However,
we
are
adopting
a
May
1,
2007
compliance
deadline
to
take
into
account
the
delay
in
finalizing
today's
rule.

One
commenter
suggested
that
providing
units
in
Georgia
and
Missouri
25
months
to
comply
was
not
enough
time.
This
Draft
 
Do
not
cite,
quote
or
distribute
175
commenter
provided
documentation
from
an
engineering
firm
suggesting
that
it
would
take
at
least
36
months
to
install
SCR
on
one
unit.
The
commenter
further
asserted
that
it
would
take
even
longer
to
install
SCR
on
two
units
at
a
single
plant
and
suggested
that
Missouri
sources
be
given
at
least
43
months
to
install
controls.
We
disagree
with
this
commenter.
Many
SCR
projects
have
been
completed
in
significantly
less
time.
For
instance,
an
SCR
was
installed
on
the
AES
Somerset
Plant
in
New
York
in
9
months
from
contract
award
to
completion.
Reliant
Energy
completed
construction
of
two
SCRs
on
two
900
MW
units
at
their
Keystone
Plant
in
Pennsylvania
in
46
weeks.
Even
assuming
that
the
engineering
and
permitting
took
a
year,
this
job
was
completed
in
less
than
24
months.
It
should
also
be
noted
that
this
job
was
completed
in
2003.
This
was
part
of
the
peak
construction
period
for
SCRs
under
Phase
I
of
the
NOx
SIP
Call.
Projects
in
Georgia
and
Missouri,
being
constructed
after
the
bulk
of
the
SCRs
for
the
NOx
SIP
Call
have
been
installed,
should
have
much
less
competition
for
resources.
The
commenter
provided
no
explanation
of
why
this
project
should
take
so
long
when
so
many
other
projects
have
been
completed
in
less
time.
Furthermore,
the
NOx
SIP
Call
provides
Missouri
with
CSP
allowances
that
Missouri
may
use
to
address
situations
when
installation
cannot
be
Draft
 
Do
not
cite,
quote
or
distribute
176
completely
finished
by
the
compliance
date.
It
should
also
be
noted
that
while
we
believe
that
the
SCRs
can
be
installed
within
25
months,
if
Missouri
completes
its
SIP
by
December
31,
2005,
they
will
actually
have
29
months
to
install
the
SCRs.
This
assumes
that
the
company
does
not
begin
any
work
on
the
SCRs
until
after
the
SIP
is
finalized.

Since
the
company
should
have
a
strong
indication
as
to
whether
they
will
need
to
install
the
SCRs
before
the
SIP
is
completed,
they
will
actually
have
more
than
29
months
to
install
the
SCRs.

L.
What
Action
Are
We
Taking
on
Wisconsin?

In
Michigan,
the
Wisconsin
industry
petitioners
argued
that
the
emissions
from
Wisconsin
do
not
contribute
significantly
to
nonattainment
in
any
other
State.
Section
110(
a)(
2)(
D)(
i)(
I)
requires
that
a
State
"
contribute
significantly
to
nonattainment
in
...
any
other
State"
in
order
to
be
included
in
the
challenged
NOx
SIP
Call.
42
U.
S.
C.
7410(
a)(
2)(
D)(
i)(
I).
The
Court
held
that
"
EPA
erroneously
included
Wisconsin
in
the
NOx
SIP
Call
because
EPA
failed
to
explain
how
Wisconsin
contributes
to
nonattainment
in
any
other
State,"
Michigan,
213
F.
3d
at
681
(
emphasis
in
original).
The
Court
noted
that
the
record
showed
only
that
emissions
from
Wisconsin
contribute
to
violations
of
the
standard
over
Lake
Michigan.
Draft
 
Do
not
cite,
quote
or
distribute
177
Our
"
zero­
out"
modeling
of
Wisconsin
emissions
using
UAM­
V
shows
that
emissions
from
Wisconsin
impact
ozone
levels
in
neighboring
States,
but
not
during
exceedances
of
the
1­
hour
NAAQS
(
i.
e.,
these
impacts
occur
when
ozone
levels
are
below
the
NAAQS).
For
the
OTAG
episodes
we
modeled,
the
ozone
impacts
of
Wisconsin
on
1­
hour
nonattainment
are
predicted
in
the
northwestern
part
of
Lake
Michigan
near
the
shore
line
of
Wisconsin.
In
the
NOx
SIP
Call
rulemaking,
we
concluded
that
impacts
over
the
lake
should
be
considered
as
contributions
to
States
bordering
the
lake
(
i.
e.,
Michigan,
Indiana,
and
Illinois)
because
of
lake
breeze
effects
(
63
FR
57386,
October
27,
1998).
The
Court
found
that
we
had
not
provided
adequate
support
for
this
determination
and
vacated
the
rule's
application
to
Wisconsin
for
the
1­
hour
standard
Michigan,
213
F.
3d
at
681.

We
agree
that
additional
modeling
would
be
necessary
in
order
to
find
that
Wisconsin
significantly
contributes
to
downwind
1­
hour
nonattainment
in
any
other
State
and
to
include
Wisconsin
in
the
NOx
SIP
Call
at
this
time.
We
do
not
currently
have
the
modeling
necessary
to
take
such
action,
therefore,
we
are
excluding
the
entire
State
of
Wisconsin
from
the
requirements
of
the
1­
hour
basis
of
the
NOx
SIP
Call
to
conform
to
the
Court's
decision.
In
Draft
 
Do
not
cite,
quote
or
distribute
178
addition,
we
received
only
one
comment
on
excluding
Wisconsin
from
the
NOx
SIP
Call
and
it
supported
our
proposal
to
do
so.

We
are
not,
however,
determining
that
Wisconsin's
emissions
do
not
contribute
significantly
to
nonattainment
downwind.
We
have
not
completed
the
additional
modeling
analysis
for
the
States
that
are
part
of
the
OTAG
region
but
were
not
included
in
the
final
NOx
SIP
Call.
Although
we
stayed
the
8­
hour
basis
of
the
NOx
SIP
Call
Rule
on
September
18,
2000
(
65
FR
56245),
we
are
in
the
process
of
evaluating
lifting
the
stay.
Today's
action
to
exclude
Wisconsin
from
the
1­
hour
basis
of
the
NOx
SIP
Call
does
not
address
whether
Wisconsin
should
remain
subject
to
the
8­

hour
basis
of
the
NOx
SIP
Call.
We
will
address
that
issue
at
the
time
we
lift
the
stay
as
it
applies
to
Wisconsin.

M.
How
Are
the
8­
hour
NAAQS
Rules
Affected
by
this
Action?

As
noted
above,
the
revisions
to
the
NOx
SIP
Call
in
today's
action
respond
to
the
Court's
decision
in
Michigan.

The
Court's
decision
and
today's
action
concern
issues
arising
under
only
the
1­
hour
ozone
NAAQS,
and
not
the
8­

hour
NAAQS.
Accordingly,
none
of
the
actions
finalized
today
 
the
definitions
of
EGU
and
non­
EGU
and
the
control
requirements
for
IC
engines,
and
implications
for
the
State
budgets;
the
SIP
submission
dates;
compliance
dates;
the
Draft
 
Do
not
cite,
quote
or
distribute
179
revised
emissions
budgets
for
Alabama,
Georgia,
Michigan,

and
Missouri;
and
the
exclusion
of
Wisconsin
 
have
any
effect
on
any
requirements
of
the
NOx
SIP
Call
on
States
under
the
8­
hour
NAAQS.
Because
of
the
litigation
concerning
the
8­
hour
ozone
NAAQS,
we
stayed
all
of
the
requirements
of
the
NOx
SIP
Call
under
the
8­
hour
NAAQS,

ranging
from
the
SIP
submission
dates
to
the
control
requirements
(
65
FR
56245,
September
18,
2000).
Since
then,

the
Supreme
Court
has
held
that
the
CAA
authorizes
EPA
to
revise
the
ozone
NAAQS.
Whitman
v.
American
Trucking
Ass'ns.,
121
S.
Ct.
903
(
2001).
At
this
time,
we
are
evaluating
the
process
for
lifting
the
8­
hour
stay.

N.
What
Modifications
Are
Being
Made
to
Parts
78
and
97?

Today's
action
finalizes
modifications
to
40
CFR
parts
78
and
97
that
were
proposed
on
June
13,
2001.
The
modifications
to
part
78
were
proposed
so
that
affected
sources
under
the
Federal
NOx
Budget
Trading
Program
would
have
the
same
right
of
administrative
appeal
as
affected
sources
under
the
Acid
Rain
Program.
We
received
no
comments
on
the
revisions
to
part
78.
The
proposed
revisions
to
part
97
were
made
in
order
to
align
monitoring
and
reporting
requirements
with
modification
to
part
75
made
after
the
promulgation
of
part
97
and
to
correct
certain
grammatical
and
technical
errors.
We
received
two
comments,
Draft
 
Do
not
cite,
quote
or
distribute
60
In
addition,
the
final
revisions
correct,
without
any
substantive
changes,
a
few
minor,
technical
errors
in
the
proposed
revisions
or
that
were
inadvertently
left
out
of
the
proposed
revisions.

180
one
supporting
a
proposed
revision
to
part
97
and
the
other
suggesting
a
change
that
was
addressed
in
the
June
12,
2002
final
revisions
to
part
75
(
in
§
75.19).

We
are
finalizing
the
proposed
modifications
to
parts
78
and
97
as
proposed,
with
only
three
exceptions
of
any
significance.
60
The
final
revisions
to
§
97.61(
b)
differ
from
the
proposed
revisions
in
that
the
final
revisions
use
language
consistent
with
language
in
the
analogous
provision
in
§
96.61(
b)
of
the
model
rule
for
the
NOx
Budget
Trading
Program
under
the
NOx
SIP
Call.
In
particular,
the
final
revisions
refer
to
"
the
control
period
to
which
the
NOx
allowance
transfer
deadline
applies,"
rather
than
referencing
"
the
control
period
in
the
same
year
as
the
NOx
allowance
transfer
deadline."
We
believe
that
the
language
in
the
final
revisions
to
§
97.61(
b)
is
clearer
and
more
accurate
than
the
language
in
the
proposed
revisions,
as
well
as
being
analogous
to
the
language
in
§
96.61(
b).

Further,
the
final
revisions
to
§
97.70(
b)(
5)
and
(
6)

differ
from
the
proposed
revisions
in
that
the
final
revisions
use
language
consistent
with
language
in
the
analogous
provision
in
§
75.4(
e)
of
the
Acid
Rain
Program
emission
monitoring
regulations.
In
particular,
the
final
Draft
 
Do
not
cite,
quote
or
distribute
181
revisions
add,
to
the
language
"
a
new
stack
or
flue,"
a
reference
to
new
"
add­
on
NOx
emission
controls."
As
a
result,
§
97.70(
b)(
5)
and
(
6)
contain
the
same
references
to
new
stacks,
flues,
or
add­
on
NOx
emission
controls
as
§
75.4(
e).

Similarly,
the
final
revisions
to
§
97.71(
c)
differ
from
the
proposed
revisions
in
that
the
final
revisions
use
language
consistent
with
language
in
the
analogous
provision
in
§
75.20(
h)(
3)
of
the
Acid
Rain
Program
emission
monitoring
regulations.
In
particular,
the
final
revisions
[
similar
to
§
75.20(
h)(
3)]
provide
that
provisional
certification
status
for
the
low
mass
emission
excepted
methodology
is
tied
to
receipt
of
a
"
complete"
certification
application.

III.
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
Draft
 
Do
not
cite,
quote
or
distribute
182
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.

This
action,
which
responds
to
the
court
decisions
in
Michigan
v.
EPA,
213
F.
3d
663
(
D.
C.
Cir.
2000)(
NOx
SIP
Call);
Appalachian
Power
v.
EPA,
249
F.
3d
1032
(
D.
C.
Cir.

2001)(
Section
126
Rule),
and
Appalachian
Power
v.
EPA,
251
F.
3d
1026
(
D.
C.
Cir.
2001)
(
NOx
SIP
Call
Technical
Amendments),
is
a
"
significant
regulatory
action"
under
Executive
Order
12866
because
it
raises
novel
legal
or
policy
issues
and
is,
therefore,
subject
to
review
by
OMB.

Because
this
is
a
"
significant
regulatory
action,"
a
Regulatory
Impact
Analysis
(
RIA)
is
required.
We
are
using
the
original
RIAs
prepared
for
the
three
actions
at
issue
in
the
cases
listed
above
["
Regulatory
Impact
Analysis
for
the
Draft
 
Do
not
cite,
quote
or
distribute
183
NOx
SIP
Call,
FIP,
and
Section
126
Petitions"
(
Docket
OAR­

2001­
0008)]
and
["
Regulatory
Impact
Analysis
for
the
Final
Section
126
Rule"
(
Docket
A­
97­
43)],
which
contain
cost
and
benefit
analyses
and
economic
impact
analyses
reflecting
requirements
of
those
rules.
In
addition,
we
are
using
an
update
to
some
of
the
information
in
the
final
NOx
SIP
Call
RIA
entitled,
"
NOx
Emissions
Control
Costs
for
Stationary
Reciprocating
Internal
Combustion
Engines
in
the
NOx
SIP
Call
States"
(
August
11,
2000),
an
analysis
prepared
for
the
IC
engine
portion
of
this
action.
This
analysis
indicates
that
there
is
less
cost
incurred
per
engine
than
shown
in
the
original
RIA
which
was
prepared
for
the
final
NOx
SIP
Call.
This
document
is
available
for
public
inspection
in
Docket
OAR­
2001­
0008
which
is
listed
in
the
ADDRESSES
section
of
this
preamble.

B.
Paperwork
Reduction
Act
Today's
action
does
not
add
any
information
collection
requirements
or
increase
burden
under
the
provisions
of
the
Paperwork
Reduction
Act
(
44
U.
S.
C.
3501
et
seq.),
and
therefore
is
not
subject
to
these
requirements.

C.
Regulatory
Flexibility
Act
(
RFA)

The
EPA
has
determined
that
it
is
not
necessary
to
prepare
a
regulatory
flexibility
analysis
in
connection
with
this
final
rule.
Draft
 
Do
not
cite,
quote
or
distribute
184
For
purposes
of
assessing
the
impacts
of
today's
rule
on
small
entities,
small
entity
is
defined
as:
(
1)
a
small
business
as
defined
in
the
Small
Business
Administration's
(
SBA)
regulations
at
13
CFR
12.201;
(
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;
and
(
3)
a
small
organization
that
is
any
not­
for­
profit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.

After
considering
the
economic
impacts
of
today's
final
rule
on
small
entities,
EPA
has
concluded
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
This
final
rule
will
not
impose
any
requirements
on
small
entities.
This
final
rule
responds
to
the
court
decisions
in
Michigan
v.
EPA,
213
F.
3d
663,
Appalachian
Power
v.
EPA,
249
F.
3d
1032
(
D.
C.
Cir.

2001),
and
Appalachian
Power
v.
EPA,
251
F.
3d
1026
(
D.
C.

Cir.
2001)
(
decisions
on
the
NOx
SIP
Call,
Section
126
Rule,

and
NOx
SIP
Call
Technical
Amendments,
respectively).
The
RIA
for
the
original
final
NOx
SIP
Call
included
impacts
to
small
entities
presuming
the
application
of
the
control
strategies
we
modeled
as
surrogates
for
what
the
States
would
actually
employ
in
their
NOx
SIPs.
We
also
prepared
an
analysis
of
impacts
to
small
entities
affected
by
the
Draft
 
Do
not
cite,
quote
or
distribute
185
Section
126
Rule.
This
analysis
is
summarized
in
the
RIA
for
the
final
Section
126
Rule
and
included
in
the
docket
for
that
rule.
This
action
does
not
impose
any
requirements
on
small
entities
nor
will
there
be
impacts
on
small
entities
beyond
those,
if
any,
required
by
or
resulting
from
the
NOx
SIP
Call
and
the
Section
126
Rules.

D.
Unfunded
Mandates
Reform
Act
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Public
Law
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,
2
U.
S.
C.

1532,
EPA
generally
must
prepare
a
written
statement,

including
a
cost­
benefit
analysis,
for
any
proposed
or
final
rules
with
"
Federal
mandates"
that
may
result
in
the
expenditure
by
State,
local,
and
tribal
governments,
in
the
aggregate,
or
by
the
private
sector,
of
$
100
million
or
more
in
any
1
year.
A
"
Federal
mandate"
is
defined
to
include
a
"
Federal
intergovernmental
mandate"
and
a
"
Federal
private
sector
mandate"
[
2
U.
S.
C.
658(
6)].
A
"
Federal
intergovernmental
mandate,"
in
turn,
is
defined
to
include
a
regulation
that
"
would
impose
an
enforceable
duty
upon
State,
local,
or
tribal
governments,"
[
2
U.
S.
C.

658(
5)(
A)(
i)],
except
for,
among
other
things,
a
duty
that
Draft
 
Do
not
cite,
quote
or
distribute
186
is
"
a
condition
of
Federal
assistance"
[
2
U.
S.
C.

658(
5)(
A)(
I)].
A
"
Federal
private
sector
mandate"
includes
a
regulation
that
"
would
impose
an
enforceable
duty
upon
the
private
sector,"
with
certain
exceptions
[
2
U.
S.
C.

658(
7)(
A)].

The
EPA
prepared
a
statement
for
the
final
NOx
SIP
Call
that
would
be
required
by
UMRA
if
its
statutory
provisions
applied.
Today's
action
does
not
create
any
additional
requirements
beyond
those
of
the
final
NOx
SIP
Call,

therefore,
no
further
UMRA
analysis
is
needed.

An
Unfunded
Mandates
Analysis
was
prepared
for
the
proposed
Section
126
Rule
which
was
published
on
May
25,

1999.
The
EPA
updated
this
analysis
for
the
final
Section
126
Rule
(
January
18,
2000).
This
"
Government
Entity
Analysis
for
the
Final
Section
126
Petitions
Under
the
Clean
Air
Act
Amendments
Title
I,"
is
available
for
public
inspection
in
Docket
A­
97­
43
which
is
listed
in
the
ADDRESSES
section
of
this
preamble.
This
analysis
determined
that
the
final
Section
126
rulemaking
contained
no
regulatory
requirements
that
might
significantly
or
uniquely
affect
small
governments.
Today's
action
imposes
no
new
additional
requirements
above
those
established
in
the
final
Section
126
Rule.

E.
Executive
Order
13132:
Federalism
Draft
 
Do
not
cite,
quote
or
distribute
187
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."
Under
section
6
of
Executive
Order
13132,
EPA
may
not
issue
a
regulation
that
has
federalism
implications,
that
imposes
substantial
direct
compliance
costs,
and
that
is
not
required
by
statute,

unless
the
Federal
government
provides
the
funds
necessary
to
pay
the
direct
compliance
costs
incurred
by
State
and
local
governments,
or
EPA
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
The
EPA
also
may
not
issue
a
regulation
that
has
federalism
implications
and
that
preempts
State
law,

unless
the
Agency
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.

This
action
addressing
the
NOx
SIP
Call
and
Section
126
Rules
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
Draft
 
Do
not
cite,
quote
or
distribute
188
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.

In
issuing
the
NOx
SIP
Call,
EPA
acted
under
section
110(
k)(
5),
which
requires
the
Agency
to
require
a
State
to
correct
a
deficiency
that
EPA
has
found
in
the
SIP.
In
October
1998,
EPA
issued
its
final
NOx
SIP
Call
Rule
finding
that
the
SIPs
for
22
States
and
the
District
of
Columbia
were
substantially
inadequate
because
they
did
not
regulate
emissions
that
significantly
contribute
to
downwind
nonattainment
in
other
States.
On
March
3,
2000,
the
D.
C.

Circuit
largely
upheld
that
rule
but
remanded
certain
minor
issues
and
vacated
and
remanded
other
minor
issues
to
the
Agency
for
further
consideration.
Michigan
v.
EPA,
213
F.
3d
663
(
D.
C.
Cir.
2000)(
NOx
SIP
Call).
Today,
EPA
is
finalizing
action
on
these
remanded
and
remanded
and
vacated
portions
of
the
rule.
This
action
also
responds
to
an
issue
that
the
court
remanded
and
vacated
in
the
challenge
to
the
NOx
SIP
Call
Technical
Amendments.
Appalachian
Power
v.

EPA,
251
F.
3d
1026
(
D.
C.
Cir.
2001)(
NOx
SIP
Call
Technical
Amendments).

With
respect
to
the
action
concerning
the
definition
of
EGU
and
the
level
of
control
for
IC
engines,
action
revising
the
emission
budgets
for
Georgia,
Missouri,
Alabama,
and
Draft
 
Do
not
cite,
quote
or
distribute
189
Michigan,
and
the
SIP
submission
and
source
compliance
dates,
EPA's
action
does
not
impose
any
additional
burdens
beyond
those
imposed
by
the
final
NOx
SIP
Call.
Thus,

today's
action
does
not
alter
the
relationship
established
by
the
final
NOx
SIP
Call
Rule,
which
remains
in
place
for
19
States
(
including
Alabama
and
Michigan)
and
the
District
of
Columbia.
Moreover,
no
aspect
of
this
rule
changes
the
established
relationship
between
the
States
and
EPA
under
title
I
of
the
CAA.
Under
title
I
of
the
CAA,
States
have
the
primary
responsibility
to
develop
plans
to
attain
and
maintain
the
NAAQS.
As
found
by
the
court,
the
States
have
full
discretion
under
the
NOx
SIP
Call
Rule
to
choose
the
control
requirements
necessary
to
address
the
transported
emissions
identified
by
EPA
in
the
NOx
SIP
Call
Rule.

As
provided
in
the
final
action
promulgating
the
NOx
SIP
Call
Rule
and
the
Technical
Amendments,
the
NOx
SIP
Call
Rule
will
not
impose
substantial
direct
compliance
costs.

While
the
States
will
incur
some
costs
to
develop
the
plan,

those
costs
are
not
expected
to
be
substantial.
Moreover,

under
section
105
of
the
CAA,
the
Federal
government
supports
the
States'
SIP
development
activities
by
providing
partial
funding
of
State
programs
for
the
prevention
and
control
of
air
pollution.
Thus,
the
requirements
of
section
6
of
the
Executive
Order
do
not
apply
to
this
rule.

Today's
rule
also
responds
to
the
Court's
decision
in
Draft
 
Do
not
cite,
quote
or
distribute
190
Appalachian
Power
v.
EPA,
249
F.
3d
1032
(
D.
C.
Cir.

2001)(
Section
126
Rule).
This
action
imposes
no
new
requirements
that
impose
compliance
burdens
beyond
those
that
EPA
established
under
the
final
Section
126
Rule
(
January
18,
2000).

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
6,
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."
"
Policies
that
have
tribal
implications"
is
defined
in
the
Executive
Order
to
include
regulations
that
have
"
substantial
direct
effects
on
one
or
more
Indian
tribes,
on
the
relationship
between
the
Federal
government
and
the
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes."

This
rule
does
not
have
tribal
implications.
It
will
not
have
substantial
direct
effects
on
tribal
governments,

on
the
relationship
between
the
Federal
government
and
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes,
as
specified
in
Executive
Order
13175.
Today's
Draft
 
Do
not
cite,
quote
or
distribute
191
action
does
not
significantly
or
uniquely
affect
the
communities
of
Indian
tribal
governments.
The
EPA
stated
in
the
final
NOx
SIP
Call
Rule,
the
Technical
Amendments
Rule,

and
the
Section
126
Rule
that
Executive
Order
13084
did
not
apply
because
those
final
rules
do
not
significantly
or
uniquely
affect
the
communities
of
Indian
tribal
governments
or
call
on
States
to
regulate
NOx
sources
located
on
tribal
lands.
The
same
is
true
of
today's
action.
Thus,
Executive
Order
13175
does
not
apply
to
this
rule.

G.
Executive
Order
13045:
Protection
of
Children
from
Environmental
Health
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.

The
EPA
interprets
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
Draft
 
Do
not
cite,
quote
or
distribute
192
safety
risks,
such
that
the
analysis
required
under
section
5­
501
of
the
Order
has
the
potential
to
influence
the
regulation.
This
action
is
not
subject
to
Executive
Order
13045
because
it
does
not
concern
an
environmental
health
or
safety
risk
that
we
have
reason
to
believe
may
have
a
disproportionate
effect
on
children
and
it
is
not
economically
significant
under
Executive
Order
12866.

H.
Executive
Order
13211:
Actions
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
This
summary
of
the
energy
impact
analysis
report
[
add
cite]
estimates
the
energy
impacts
associated
with
the
Phase
II
portion
of
the
NOx
SIP
Call,
in
accordance
with
Executive
Order
13211.
It
covers
all
large
EGUs
that
do
not
participate
in
the
Acid
Rain
Trading
Program
and
large
IC
engines
in
the
District
of
Columbia
and
the
21
States
of
the
NOx
SIP
Call
region,
as
well
as
all
NOx
SIP
Call
sources
(
cement
kilns,
utility
boilers,
industrial
boilers,

combustion
turbines,
and
IC
engines)
in
the
fine
grid
portions
of
Georgia
and
Missouri.
This
analysis
also
considered
impacts
on
sources
in
only
the
fine
grid
portions
of
Michigan
and
Alabama.
We
identified
applications
of
control
devices
appropriate
for
this
analysis
that
provide
high
levels
of
NOx
reduction
at
relatively
low
cost,
with
an
average
cost
of
less
than
$
2,000
(
1990
dollars)
per
ozone
season
ton
of
NOx
removed,
among
them:
SCR
and
NSCR,
fluid
Draft
 
Do
not
cite,
quote
or
distribute
61
National
Energy
Foundation
web
page:
http://
www.
nef1.
org/
ea/
eastats.
html
193
injection
(
steam
or
ammonia
­
termed
SNCR),
and
LEC.

Through
the
analysis,
we
identified
three
relevant
energy
effects
that
occur
during
normal
operation
of
these
devices:

increased
energy
demands
required
by
certain
control
devices
and
equipment,
increased
energy
use
due
to
pressure
drop
and
changes
in
the
stoichiometry
of
the
combustion
process,
and
energy
credits
from
improved
combustion.
Each
of
these
NOx
controls
has
at
least
one
of
these
energy
effects
as
part
of
their
normal
operation.

The
United
States
consumed
over
22
quads
(
quadrillion
Btus)
of
natural
gas
in
1999.61
With
respect
to
energy
sources,
the
application
of
LEC
technology
to
natural
gasdriven
IC
engines
amounts
to
a
savings
of
about
4,000
million
British
thermal
units
(
mmBtus)
per
unit,
or
about
70
billion
Btus
for
all
affected
IC
engines
(
about
70
million
cubic
feet
of
gas).
This
amounts
to
about
three
tenths
of
one
percent
of
the
nation's
annual
consumption.

Consequently,
the
application
of
LEC
technology
leads
to
a
small
savings
in
natural
gas
use
nationwide
by
affected
sources
and
their
firms,
but
not
a
large
enough
savings
to
affect
the
price
or
distribution
of
gas
in
the
United
States.

The
additional
coal
necessary
to
compensate
for
the
loss
of
efficiency
from
SCR
and
SNCR
controls
amounts
to
Draft
 
Do
not
cite,
quote
or
distribute
194
about
11
MMBtus
per
affected
coal­
fired
boiler,
or
89
MMBtus
per
year
per
source.
For
all
affected
utility
and
industrial
coal­
fired
boilers,
this
translates
to
slightly
more
than
70
billion
Btus.
The
United
States
also
consumed
over
22
quads
of
coal
in
1999.
Therefore,
the
net
increase
in
coal
consumption
necessary
for
affected
boilers
to
compensate
for
their
efficiency
loss
amounts
to
about
three
ten­
thousandths
of
one
percent
of
the
nation's
annual
demand
for
coal.
The
change
in
demand
for
coal
caused
by
NOx
control
efficiency
loss
will
not
be
of
sufficient
magnitude
to
affect
coal
prices.
In
addition,
the
reduction
in
electricity
output
in
response
to
the
requirements
of
the
Phase
II
NOx
SIP
all
rulemaking
is
less
than
one­
half
of
1
percent
of
predicted
nationwide
output
between
2005
and
2010
(
to
approximate
a
2007
projection).
Because
utilities
constantly
adjust
their
output
to
match
demand,
and
because
demand
fluctuates
more
widely
than
the
predicted
reduction
in
electricity
output
from
the
Phase
II
rulemaking,
this
report
indicates
there
will
be
no
significant
effect
on
production
or
the
factors
of
production
imposed
by
the
NOx
SIP
Call
for
affected
boilers.

Therefore,
we
conclude
that
the
rule
when
implemented
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy.
For
more
information
on
the
results
of
this
analysis,
please
consult
Draft
 
Do
not
cite,
quote
or
distribute
195
the
energy
impact
analysis
report
in
the
public
docket
for
this
rule.

We
received
four
comments
on
this
administrative
requirement
as
summarized
below
[
XII­
D­
07,
TX
Gas
Transmission
Corp.;
XII­
D­
09,
INGAA;
XII­
D­
10,
El
Paso
Corp.;
XII­
F­
12,
NiSource,
Inc.].

Comment:
Executive
Order
13211
requires
us
to
analyze
the
effect
of
its
regulations
on
the
Nation's
energy
supply,

distribution
and
use.
Commenters
state
that
(
1)
we
failed
to
analyze,
or
even
recognize,
its
deadline's
potential
effect
on
the
United
States'
natural
gas
transmission
system(
XII­
F­
12),(
2)
the
proposal's
impractical
compliance
deadline
could
compromise
much
of
the
Nation's
gas
transmission
and
storage
system,
yet
there
has
been
no
analysis
of
this
issue,
(
3)
EPA
must
provide
a
compliance
period
that
is
adequate
to
avoid
these
problems,
and
(
4)
the
Agency
must
conduct
a
study
that
demonstrates
(
after
notice
and
opportunity
for
comment)
that
it
has
fully
considered
all
of
the
impacts
on
energy
supply
and
distribution.
(
p.
12
of
comment
XII­
D­
09
and
p.
13
of
comment
XII­
D­
10.)

Response:
We
disagree
with
the
comment
that
we
failed
to
analyze
the
effect
of
this
rule
on
the
Nation's
energy
supply,
distribution
and
use.
In
accordance
with
Executive
Order
13211,
we
completed
an
energy
impact
analysis
of
this
rule,
on
October
2,
2001.
The
analysis
indicated
minimal
Draft
 
Do
not
cite,
quote
or
distribute
62
Stationary
Reciprocating
Internal
Combustion
Engines
Updated
Information
on
Nox
Emissions
and
Control
Techniques,
Revised
Final
Report,
prepared
by
Ec/
R,
Inc.
for
EPA,
p.
4­
2,
September
1,
2000,
available
on
the
Internet
at
http://
www.
epa.
gov/
ttn/
naaqs/
ozone/
rto/
fip/
data/
rfic_
engine.
pdf.

63
Found
in
reprint
of
article
in
"
American
Gas
&
Oil
Reporter",
May
1998,
available
on
the
Internet
at
http://
www.
dieselsupply.
com/
dscartic.
htm.

196
effects,
less
than
0.5
percent
nationally,
on
both
energy
supply,
distribution
and
demand,
including
natural
gas.

We
note
that
the
more
prevalent
LEC
retrofit,
which
has
been
in
use
for
almost
20
years,
is
the
screw­
in
precombustion
chamber.
62
This
kind
of
retrofit
is
both
less
costly
and
time­
consuming
than
other
kinds
of
LEC
retrofit.

For
example,
Columbia
Gas
Transmission
Corporation,
using
screw­
in
precombustion
chambers,
retrofit
two
IC
engines
at
its
Bedford
County,
Pennsylvania,
facility
within
3
days.
63
We
have
also
found
that
most,
if
not
all,
natural
gas
pipeline
stations
are
equipped
with
multiple
IC
engines
and
that
not
all
engines
are
operated
at
the
same
time.

Therefore,
we
believe
that
LEC
retrofits
can
be
phased­
in
making
it
less
likely
for
an
entire
station
to
go
offline
for
a
LEC
retrofit.
Thus,
because
a
phased­
in
approach
is
feasible,
we
believe
that
engine
stations
can
continue
operating
close
to
their
standard
level
thereby
avoiding
service
interruptions.
We
also
note
that
the
December
1998
Gas
Research
Institute
report
concluded
that
"
installation
Draft
 
Do
not
cite,
quote
or
distribute
64
NOx
Control
for
Two­
Cycle
Pipeline
Reciprocating
Engines,"
p.
4­
11,
December
1998.

197
of
the
[
LEC]
retrofit
kit
is
not
expected
to
impact
the
normal
maintenance
interval."
64
The
energy
impact
analysis
also
indicated
that
IC
engines
retrofit
with
LEC
will
experience,
on
average,
an
energy
savings
of
half
a
million
BTUs
per
hour
per
engine,
and
therefore
savings
in
operating
costs.

The
comment
that
the
11­
month
compliance
deadline
could
compromise
the
nation's
gas
transmission
and
storage
system
is
no
longer
an
because
we
are
allowing
more
than
24
months
from
SIP
submittal
date
for
implementation
of
controls.

Our
response
to
this
comment
is
fully
discussed
in
section
II.
K.
2
of
this
rule,
"
What
Compliance
Date
Are
We
Finalizing
for
IC
Engines
and
What
is
the
Technical
Feasibility
of
This
Date?"

With
the
improvements
in
ease
of
LEC
retrofits
that
include
scheduling
retrofits
during
maintenance
cycles,
the
adequate
time
we
believe
exists
for
implementation,
and
the
flexibility
granted
to
States
to
meet
their
NOx
budgets,
we
do
not
believe
the
concerns
expressed
about
effects
on
natural
gas
transmission
from
compliance
with
the
Phase
II
NOx
SIP
Call
rule
are
warranted.

I.
National
Technology
Transfer
Advancement
Act
The
National
Technology
Transfer
Advancement
Act
of
Draft
 
Do
not
cite,
quote
or
distribute
198
1997
does
not
apply
because
today's
action
does
not
require
the
public
to
perform
activities
conducive
to
the
use
of
voluntary
consensus
standards
under
that
Act
in
the
NOx
SIP
Call,
and
NOx
SIP
Call
Technical
Amendments.
Today's
final
action
also
does
not
impose
additional
requirements
over
those
in
the
final
Section
126
Rule.
The
EPA's
compliance
with
these
statutes
and
Executive
Orders
for
the
underlying
rules,
the
final
NOx
SIP
Call
(
63
FR
57477,
October
27,

1998),
the
NOx
SIP
Call
Technical
Amendments
(
64
FR
26298,

May
14,
1999;
65
FR
11222,
March
2,
2000),
and
the
final
Section
126
Rule
(
65
FR
2674,
January
18,
2000)
is
discussed
in
more
detail
in
the
citations
shown
above.

J.
Executive
Order
12898:
Federal
Actions
to
Address
Environmental
Justice
in
Minority
Populations
and
Low­
Income
Populations
This
action
does
not
involve
special
consideration
of
environmental
justice
related
issues
as
required
by
Executive
Order
12898
(
59
FR
7629,
February
16,
1994).
For
the
final
NOx
SIP
Call
and
Section
126
Rules,
the
Agency
conducted
general
analyses
of
the
potential
changes
in
ozone
and
particulate
matter
levels
that
may
be
experienced
by
minority
and
low­
income
populations
as
a
result
of
the
requirements
of
these
rules.
These
findings
were
presented
in
the
RIA
for
each
of
these
rules.
Today's
action
does
not
affect
these
analyses.
Draft
 
Do
not
cite,
quote
or
distribute
199
J.
Congressional
Review
Act
The
Congressional
Review
Act,
5
U.
S.
C.
801
et
seq.,
as
added
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996,
generally
provides
that
before
a
rule
may
take
effect,
the
agency
promulgating
the
rule
must
submit
a
rule
report,
which
includes
a
copy
of
the
rule,
to
each
House
of
the
Congress
and
to
the
Comptroller
General
of
the
United
States.
The
EPA
will
submit
a
report
containing
this
rule
and
other
required
information
to
the
U.
S.
Senate,
the
U.
S.

House
of
Representatives,
and
the
Comptroller
General
of
the
United
States
prior
to
publication
of
the
rule
in
the
Federal
Register.
A
"
major
rule"
cannot
take
effect
until
60
days
after
it
is
published
in
the
Federal
Register.
This
action
is
a
"
major
rule"
as
defined
by
5
U.
S.
C.
§
804(
2).

This
rule
will
be
effective
[
Insert
60
days
after
publication].

List
of
Subjects
40
CFR
Part
51
Administrative
practice
and
procedure,
Air
pollution
control,
Environmental
protection,
Intergovernmental
relations,
Ozone,
Reporting
and
recordkeeping
requirements.

40
CFR
Part
52
Air
pollution
control,
Ozone,
Reporting
and
recordkeeping
requirements.
Interstate
Ozone
Transport:
Response
to
Court
Decisions
on
the
NOx
SIP
Call,
NOx
SIP
Call
Technical
Amendments,
and
Section
126
Rules­
Page
202
of
______

200
40
CFR
Part
96
Administrative
practice
and
procedure,
Air
pollution
control,
Nitrogen
oxides,
Ozone,
Reporting
and
recordkeeping
requirements.

40
CFR
Part
97
Administrative
practice
and
procedure,
Air
pollution
control,
Intergovernmental
relations,
Nitrogen
oxides,

Ozone,
Reporting
and
recordkeeping
requirements.

Dated:

______________________________

Marianne
Lamont
Horinko
Acting
Administrator
For
the
reasons
set
out
in
the
preamble,
title
40
chapter
of
the
Code
of
Federal
Regulations
is
amended
as
follows:

Part
78
­­
Appeal
Procedures
for
Acid
Rain
Program
1.
The
authority
for
part
78
reads
as
follows:

Authority:
42
U.
S.
C.
7401,
7403,
7410,
7426,
7601,
and
7651,
et
seq.
201
2.
Section
78.1
is
amended
by
removing
from
paragraph
(
a)(
1)
the
words
"
parts
72,
73,
74,
75,
76,
and
77
of
this
chapter"
and
revising
them
to
read
"
parts
72,
73,
74,
75,

76,
or
77
of
this
chapter
or
part
97
of
this
chapter";
and
adding
a
new
paragraph
(
b)(
6)
to
read
as
follows:

§
78.1
Purpose
and
scope.

(
b)
*
*
*

(
6)
Under
part
97
of
this
chapter,

(
I)
The
adjustment
of
the
information
in
a
compliance
certification
or
other
submission
and
the
deduction
or
transfer
of
NOx
allowances
based
on
the
information,
as
adjusted,
under
§
97.31;

(
ii)
The
decision
on
the
allocation
of
NOx
allowances
to
a
NOx
Budget
unit
under
§
97.41(
b),
(
c),
(
d),
or
(
e);

(
iii)
The
decision
on
the
allocation
of
NOx
allowances
to
a
NOx
Budget
unit
from
the
compliance
supplement
pool
under
§
97.43;

(
iv)
The
decision
on
the
deduction
of
NOx
allowances
under
§
97.54;

(
v)
The
decision
on
the
transfer
of
NOx
allowances
under
§
97.61;

(
vi)
The
decision
on
a
petition
for
approval
of
an
alternative
monitoring
system;

(
vii)
The
approval
or
disapproval
of
a
monitoring
system
certification
or
recertification
under
§
97.71;

(
viii)
The
finalization
of
control
period
emissions
202
data,
including
retroactive
adjustment
based
on
audit;

(
ix)
The
approval
or
disapproval
of
a
petition
under
§
97.75;

(
x)
The
determination
of
the
sufficiency
of
the
monitoring
plan
for
a
NOX
Budget
opt­
in
unit;

(
xi)
The
decision
on
a
request
for
withdrawal
of
a
NOx
Budget
opt­
in
unit
from
the
NOx
Budget
Trading
Program
under
§
97.86;

(
xii)
The
decision
on
the
deduction
of
NOx
allowances
under
§
97.87;
and
(
xiii)
The
decision
on
the
allocation
of
NOx
allowances
to
a
NOx
Budget
opt­
in
unit
under
§
97.88.

§
78.2
[
Amended].

3.
Section
78.2
is
amended
by
removing
the
words
"
shall
apply
to
this
part"
and
revising
them
to
read
"
shall
apply
to
appeals
of
any
final
decision
of
the
Administrator
under
parts
72,
73,
74,
75,
76,
or
77
of
this
chapter."

4.
Section
78.3
is
amended
by:

a.
Revising
paragraph
(
b)(
3)(
i)
by
adding,
after
the
word
"
petitioner)",
the
words
"
or
the
NOx
authorized
account
representative
under
paragraph
(
a)(
3)
of
this
section
(
unless
the
NOx
authorized
account
representative
is
the
petitioner)";

b.
In
paragraph
(
c)(
7)
by
adding,
after
the
words
"
title
IV
of
the
Act",
the
words
"
or
part
97
of
this
chapter,
as
appropriate";
203
c.
In
paragraph
(
d)(
2)
by
adding,
after
the
words
"
Acid
Rain
Program"
the
words
"
or
on
an
account
certificate
of
representation
submitted
by
a
NOx
authorized
account
representative
or
an
application
for
a
general
account
submitted
by
a
NOx
authorized
account
representative
under
the
NOx
Budget
Trading
Program";

d..
Redesignating
paragraphs
(
d)(
2)
and
(
d)(
3)
as
paragraphs
(
d)(
3)
and
(
d)(
4)
respectively;
and
e.
Adding
new
paragraphs
(
a)(
3)
and
(
d)(
2).

The
additions
and
revisions
read
as
follows:

§
78.3
Petition
for
administrative
review
and
request
for
evidentiary
hearing.

(
a)
*
*
*

(
3)
The
following
persons
may
petition
for
administrative
review
of
a
decision
of
the
Administrator
that
is
made
under
part
97
and
that
is
appealable
under
§
78.1(
a)
of
this
part:

(
I)
The
NOx
authorized
account
representative
for
the
unit
or
any
NOx
Allowance
Tracking
System
account
covered
by
the
decision;
or
(
ii)
Any
interested
person.

*
*
*
*
*

(
d)
*
*
*

(
2)
Any
provision
or
requirement
of
part
97,
including
the
standard
requirements
under
§
97.6
of
this
chapter
and
any
emission
monitoring
or
reporting
requirements
under
part
204
97
of
this
chapter.

*
*
*
*
*

5.
Section
78.4
is
amended
by
adding
two
new
sentences
after
the
third
sentence
in
paragraph
(
a)
to
read
as
follows:

§
78.4
Filings.

(
a)
*
*
*
Any
filings
on
behalf
of
owners
and
operators
of
a
NOx
Budget
unit
or
source
shall
be
signed
by
the
NOx
authorized
account
representative.
Any
filings
on
behalf
of
persons
with
an
interest
in
NOx
allowances
in
a
general
account
shall
be
signed
by
the
NOx
authorized
account
representative.
*
*
*

*
*
*
*
*

§
78.12
[
Amended].

6.
Section
78.12
is
amended
by
adding,
after
the
words
"
was
properly
issued
or
should
be
issued"
in
paragraph
(
a)(
2),

the
words
"
or
that
a
NOx
Budget
permit
or
other
federally
enforceable
permit
was
properly
issued
or
should
be
issued".

Part
97
­­
Federal
NOx
Budget
Trading
Program
7.
The
authority
citation
for
part
97
continues
to
read
as
follows:

Authority:
42
U.
S.
C.
7401,
7403,
7426,
and
7601.

8.
Section
97.2
is
amended
by:

a.
Revising
the
definition
of
"
Continuous
emission
monitoring
system
or
CEMS";

b.
In
the
definition
of
"
Fossil
fuel
fired"
by
205
revising
the
first
occurrence
of
the
word
"
combination"
in
paragraphs
(
1),
(
2),
and
(
3)(
i)
to
read
"
combustion";

c.
In
the
definition
of
"
Most
stringent
State
or
Federal
NOx
emissions
limitation"
by
removing
the
words
",
with
regard
to
a
NOx
Budget
opt­
in
unit,";

d.
In
the
third
sentence
of
the
definition
of
"
NOx
allowance"
by
adding
the
reference
"
§
97.40,"
after
the
word
"
except";

e.
Correcting
the
alphabetical
order
of
the
definitions
so
that
"
NOx
allowances
held
or
hold
NOx
allowances"
appears
immediately
antecedent
to
"
NOx
Allowance
Tracking
System";

f.
In
the
definition
of
"
NOx
Budget
unit"
by
removing
the
words
"
Trading
Program";

g.
In
the
definition
of
"
owner"
by
adding
the
word
"
the"
before
the
final
occurrence
of
the
word
"
NOx"
in
paragraph
(
4)
of
the
definition;
and
h.
In
the
definition
of
"
Percent
monitor
data
availability"
by
revising
the
words
"
3,672
hours
per"
to
read
"
the
total
number
of
unit
operating
hours
in
the",
and
by
revising
the
symbol
"%"
to
read
"
percent".

The
revisions
and
additions
read
as
follows:

§
97.2
Definitions.

*
*
*
*
*

Continuous
emission
monitoring
system
or
CEMS
means
the
equipment
required
under
subpart
H
of
this
part
to
sample,
206
analyze,
measure,
and
provide,
by
means
of
readings
taken
at
least
once
every
15
minutes
(
using
an
automated
data
acquisition
and
handling
system
(
DAHS)),
a
permanent
record
of
nitrogen
oxides
(
NOx)
emissions,
stack
gas
volumetric
flow
rate
or
stack
gas
moisture
content
(
as
applicable),
in
a
manner
consistent
with
part
75
of
this
chapter.
The
following
are
the
principal
types
of
continuous
emission
monitoring
systems
required
under
subpart
H
of
this
part:

(
1)
A
flow
monitoring
system,
consisting
of
a
stack
flow
rate
monitor
and
an
automated
DAHS.
A
flow
monitoring
system
provides
a
permanent,
continuous
record
of
stack
gas
volumetric
flow
rate,
in
units
of
standard
cubic
feet
per
hour
(
scfh);

(
2)
A
nitrogen
oxides
concentration
monitoring
system,

consisting
of
a
NOx
pollutant
concentration
monitor
and
an
automated
DAHS.
A
NOx
concentration
monitoring
system
provides
a
permanent,
continuous
record
of
NOx
emissions
in
units
of
parts
per
million
(
ppm);

(
3)
A
nitrogen
oxides
emission
rate
(
or
NOx­
diluent)

monitoring
system,
consisting
of
a
NOx
pollutant
concentration
monitor,
a
diluent
gas
(
CO2
or
O2
)
monitor,

and
an
automated
DAHS.
A
NOx
concentration
monitoring
system
provides
a
permanent,
continuous
record
of:
NOx
concentration
in
units
of
parts
per
million
(
ppm),
diluent
gas
concentration
in
units
of
percent
O2
or
CO2
(%
O2
or
CO2
),
and
NOx
emission
rate
in
units
of
pounds
per
million
207
British
thermal
units
(
lb/
mmBtu);
and
(
4)
A
moisture
monitoring
system,
as
defined
in
§
75.11(
b)(
2)
of
this
chapter.
A
moisture
monitoring
system
provides
a
permanent,
continuous
record
of
the
stack
gas
moisture
content,
in
units
of
percent
H2O
(%
H2O).

*
*
*
*
*

§
97.4
[
Amended].

9.
Section
97.4(
a)
is
removed
and
replaced.

10.
Section
97.4(
b)
is
amended
by:

a.
Revising
the
first
sentence
of
paragraph
(
b)(
1)
by:

adding,
after
the
words
"
federally
enforceable
permit
that",

the
words
"
restricts
the
unit
to
combusting
only
natural
gas
or
fuel
oil
(
as
defined
in
§
75.2
of
this
chapter)
during
a
control
period";
and
replacing
the
words
"
and
that"
,
after
the
words
"
25
tons
or
less",
by
the
words
",
and";

b.
In
paragraph
(
b)(
4)(
i)
by
adding,
after
the
words
"
with
the
restriction
on",
the
words
"
fuel
use
and";
and
c.
In
paragraph
(
b)(
4)(
iv)
by
adding,
after
both
occurrences
of
the
words
"
restriction
on",
the
words
"
fuel
use
or";

d.
In
paragraph
(
b)(
4)(
vi)(
A)
by
adding,
after
the
words
"
restriction
on",
the
words
"
fuel
use
or";

e.
In
paragraph
(
b)(
4)(
vi)(
B)
by
adding,
after
the
words
"
the
restriction
on",
the
words
"
fuel
use
or".

The
revisions
and
additions
read
as
follows:

§
97.4
Applicability.
208
(
a)
The
following
units
in
a
State
shall
be
a
NOx
Budget
unit,
and
any
source
that
includes
one
or
more
such
units
shall
be
a
NOx
Budget
source,
subject
to
the
requirements
of
this
part:

(
1)(
A)
For
units
other
than
cogeneration
units­­

(
i)
For
units
commencing
operation
before
January
1,

1997,
a
unit
serving
during
1995
or
1996
a
generator­­

(
1)
with
a
nameplate
capacity
greater
than
25
MWe
and
(
2)
producing
electricity
for
sale
under
a
firm
contract
to
the
electric
grid.

(
ii)
For
units
commencing
operation
in
1997
or
1998,
a
unit
serving
during
1997
or
1998
a
generator­­

(
1)
with
a
nameplate
capacity
greater
than
25
MWe
and
(
2)
producing
electricity
for
sale
under
a
firm
contract
to
the
electric
grid.

(
iii)
For
units
commencing
operation
on
or
after
January
1,
1999,
a
unit
serving
at
any
time
a
generator­­

(
1)
with
a
nameplate
capacity
greater
than
25
MWe
and
(
2)
producing
electricity
for
sale.

(
B)
For
cogeneration
units­­

(
i)
For
units
commencing
operation
before
January
1,

1997,
a
unit
otherwise
under
item
(
A)(
i)(
1)
that
fails
to
qualify
as
an
unaffected
unit
under
§
72.6(
b)(
4)
for
1995
and
1996
under
the
Acid
Rain
Program.

(
ii)
For
units
commencing
operation
in
1997
or
1998,
a
unit
otherwise
under
item
(
A)(
ii)(
1)
that
fails
to
qualify
209
as
an
unaffected
unit
under
§
72.6(
b)(
4)
for
1997
or
1998
under
the
Acid
Rain
Program.

(
iii)
For
units
commencing
operation
on
or
after
January
1,
1999,
a
unit
otherwise
under
item
(
A)(
iii)
that
fails
to
qualify
as
an
unaffected
unit
under
§
72.6(
b)(
4)

under
the
Acid
Rain
Program
in
each
year.

(
2)(
A)
For
units
other
than
cogeneration
units­­

(
i)
For
units
commencing
operation
before
January
1,

1997,
a
unit­­

(
1)
with
a
maximum
design
heat
input
greater
than
250
mmBtu/
hr
and
(
2)
not
serving
during
1995
or
1996
a
generator
producing
electricity
for
sale
under
a
firm
contract
to
the
electric
grid.

(
ii)
For
units
commencing
operation
in
1997
or
1998,
a
unit­­

(
1)
with
a
maximum
design
heat
input
greater
than
250
mmBtu/
hr
and
(
2)
not
serving
during
1997
or
1998
a
generator
producing
electricity
for
sale
under
a
firm
contract
to
the
electric
grid.

(
iii)
For
units
commencing
on
or
after
January
1,

1999,
a
unit
with
a
maximum
design
heat
input
greater
than
250
mmBtu/
hr:

(
1)
At
no
time
serving
a
generator
producing
electricity
for
sale;
or
210
(
2)
At
any
time
serving
a
generator
with
a
nameplate
capacity
of
25
MWe
or
less
producing
electricity
for
sale,
if
any
such
generator
has
the
potential
to
use
not
more
than
50
percent
of
the
potential
electrical
output
capacity
of
the
unit.

(
B)
For
cogeneration
units­­

(
i)
For
units
commencing
operation
before
January
1,

1997,
a
unit
otherwise
under
item
(
A)(
i)(
1)
that
qualifies
as
an
unaffected
unit
under
§
72.6(
b)(
4)
under
the
Acid
Rain
Program
for
1995
and
1996.

(
ii)
For
units
commencing
operation
in
1997
or
1998,
a
unit
otherwise
under
item
(
A)(
ii)(
1)
that
qualifies
as
an
unaffected
unit
under
§
72.6(
b)(
4)
under
the
Acid
Rain
Program
for
1997
and
1998.

(
iii)
For
units
commencing
on
or
after
January
1,

1999,
a
unit
otherwise
under
item
(
A)(
iii)
that
qualifies
as
an
unaffected
unit
under
under
§
72.6(
b)(
4)
under
the
Acid
Rain
Program
for
each
year.

*
*
*
*
*

11.
Section
97.5
is
amended
by:

a.
In
paragraph
(
c)(
6)(
i)
by
removing
the
word
"
or"

b.
In
paragraph
(
c)(
6)(
ii)
by
removing
the
period
and
replacing
it
with
";
or";
and
c.
Adding
a
new
paragraph
(
c)(
6)(
iii).

The
revisions
and
additions
read
as
follows:

§
97.5
Retired
unit
exemption.
211
*
*
*
*
*

(
c)
*
*
*

(
6)
*
*
*

(
iii)
The
date
on
which
the
unit
resumes
operation,
if
the
unit
is
not
required
to
submit
a
NOx
permit
application.

*
*
*
*
*

§
97.40
[
Amended].

12.
Section
97.40
is
amended
by
removing
the
word
"
program".

§
97.42
[
Amended].

13.
Section
97.42
is
amended
by:

a.
In
paragraph
(
d)(
4)
by
revising
the
words
"
a
control
period"
to
read
"
the
control
period";

b.
In
paragraph
(
c)(
1)
by
adding,
before
the
words
0.15
lb/
mmBT&
U"
and
"
0.17
lb/
mmBTU"
in
the
formulas,
the
words
"
the
lesser
of"
and
by
adding,
after
the
words
"
0.15
lb/
mmBTU"
and
(
0.17
lb/
mmBTU"
in
the
formulas,
the
words
"
the
unit's
most
stringent
State
or
Federal
emission
limitation."

c.
In
paragraph
(
e)(
2)
by
revising
the
words
"
paragraph
(
c)(
1)"
to
read
"
paragraph
(
e)(
1)".

§
97.43
[
Amended].

14.
Section
97.43
is
amended
by
removing
paragraph
(
c)(
8).

§
97.51
[
Amended].

15.
Section
97.51
is
amended
by
revising
paragraph
(
b)(
1)(
i)(
D)
by
adding,
after
the
words
"
with
respect
to",

the
word
"
NOx".
212
16.
Section
97.54
is
amended
by
revising
paragraph
(
f)
by
removing
the
colon
after
the
words
"
as
follows"
and
replacing
it
with
a
period
and
by
adding
a
new
sentence
to
the
end
of
the
paragraph
to
read
as
follows:

§
97.54
Compliance.

*
*
*
*
*

(
f)
*
*
*
For
each
State
NOx
Budget
Trading
Program
that
is
established,
and
approved
and
administered
by
the
Administrator
pursuant
to
§
51.121
of
this
chapter,
the
terms
"
compliance
account"
or
"
compliance
accounts",

"
overdraft
account"
or
"
overdraft
accounts",
"
general
account"
or
"
general
accounts",
"
States",
and
"
trading
program
budgets
under
§
97.40"
in
paragraphs
(
f)(
1)
through
(
f)(
3)
of
this
section
shall
be
read
to
include
respectively:
a
compliance
account
or
compliance
accounts
established
under
such
State
NOx
Budget
Trading
Program;
an
overdraft
account
or
overdraft
accounts
established
under
such
State
NOx
Budget
Trading
Program;
a
general
account
or
general
accounts
established
under
such
State
NOx
Budget
Trading
Program;
the
State
or
portion
of
a
State
covered
by
such
State
NOx
Budget
Trading
Program;
and
the
trading
program
budget
of
the
State
or
portion
of
a
State
covered
by
such
State
NOx
Budget
Trading
Program.

*
*
*
*
*

§
97.61
[
Amended].

17.
Section
97.61
is
amended
in
paragraph
(
b)
by
revising
213
the
words
"
in
a
prior
year
or
the
same
year
as
the
NOx
allowance
transfer
deadline"
to
read
"
prior
to
or
the
same
as
the
control
period
to
which
the
NOs
allowance
transfer
deadline
applies"
and
by
revising
the
words
"
the
control
period
in
the
same
year
as
the
NOx
allowance
transfer
deadline"
to
read
"
the
control
period
in
the
fourth
year
after
the
control
period
to
which
the
NOx
allowance
transfer
deadline
applies."

18.
Section
97.70
is
amended
by:

a.
In
paragraph
(
a)(
1)
by
revising
the
words
"
§
§
75.72
and
§
§
75.76"
to
read
"
§
§
75.71
and
75.72";

b.
Revising
paragraphs
(
b)(
3),
(
b)(
3)(
i)
and
(
b)(
3)(
ii);

c.
Revising
paragraph
(
b)(
4)
and
adding
new
paragraphs
(
b)(
4)(
i)
and
(
ii);

d.
Removing
paragraphs
(
b)(
5)
and
(
b)(
6);

e.
Redesignating
paragraphs
(
b)(
7),
(
b)(
8)
and
(
b)(
9)

as
paragraphs
(
b)(
5),
(
b)(
6),
and
(
b)(
7),
respectively;

f.
Revising
newly
redesignated
paragraphs
(
b)(
5)
and
(
b)(
6),
and
adding
new
paragraphs
(
b)(
6)(
i)
and
(
ii);
and
g.
Revising
paragraph
(
c)
and
adding
new
paragraphs
(
c)(
1),
(
c)(
2),
and
(
c)(
3).

The
revisions
and
additions
read
as
follows:

§
97.70
General
Requirements.

*
*
*
*
*

(
b)
*
*
*
214
(
3)
For
the
owner
or
operator
of
a
NOx
Budget
unit
under
§
97.4(
a)
that
commences
operation
on
or
after
January
1,
2003
and
that
reports
on
an
annual
basis
under
§
97.74(
d)

by
the
following
dates:

(
I)
The
earlier
of
90
unit
operating
days
after
the
date
on
which
the
unit
commences
commercial
operation
or
180
calendar
days
after
the
date
on
which
the
unit
commences
commercial
operation;
or
(
ii)
May
1,
2003,
if
the
compliance
date
under
paragraph
(
b)(
3)(
i)
of
this
section
is
before
May
1,
2003.

(
4)
For
the
owner
or
operator
of
a
NOx
Budget
unit
under
§
97.4(
a)
that
commences
operation
on
or
after
January
1,
2003
and
that
reports
on
a
control
period
basis
under
§
97.74(
d)(
2)(
ii),
by
the
following
dates:

(
i)
The
earlier
of
90
unit
operating
days
or
180
calendar
days
after
the
date
on
which
the
unit
commences
commercial
operation,
if
this
compliance
date
is
during
a
control
period;
or
(
ii)
May
1
immediately
following
the
compliance
date
under
paragraph
(
b)(
4)(
i)
of
this
section,
if
such
compliance
date
is
not
during
a
control
period.

(
5)
For
the
owner
or
operator
of
a
NOx
Budget
unit
that
has
a
new
stack
or
flue
or
add­
on
NOx
emission
controls
for
which
construction
is
completed
after
the
applicable
deadline
under
paragraph
(
b)(
1),
(
b)(
2),
(
b)(
3),
or
(
b)(
4)

of
this
section
or
under
subpart
I
of
this
part
and
that
215
reports
on
an
annual
basis
under
§
97.74(
d),
by
the
earlier
of
90
unit
operating
days
or
180
calendar
days
after
the
date
on
which
emissions
first
exit
to
the
atmosphere
through
the
new
stack
or
flue
or
add­
on
NOx
emission
controls.

(
6)
For
the
owner
or
operator
of
a
NOx
Budget
unit
that
has
a
new
stack
or
flue
or
add­
on
NOx
emission
controls
for
which
construction
is
completed
after
the
applicable
deadline
under
paragraph
(
b)(
1),
(
b)(
2),
(
b)(
3),
or
(
b)(
4)

of
this
section
or
under
subpart
I
of
this
part
and
that
reports
on
a
control
period
basis
under
§
97.74(
d)(
2)(
ii),

by
the
following
dates:

(
i)
The
earlier
of
90
unit
operating
days
or
180
calendar
days
after
the
date
on
which
emissions
first
exit
to
the
atmosphere
through
the
new
stack
or
flue
or
add­
on
NOx
emission
controls,
if
this
compliance
date
is
during
a
control
period;
or
(
ii)
May
1
immediately
following
the
compliance
date
under
paragraph
(
b)(
6)(
i)
of
this
section,
if
such
compliance
date
is
not
during
a
control
period.

*
*
*
*
*

(
c)
Commencement
of
data
reporting.

(
1)
The
owner
or
operator
of
NOx
Budget
units
under
paragraph
(
b)(
1)
or
(
b)(
2)
of
this
section
shall
determine,

record
and
report
NOx
mass
emissions,
heat
input
rate,
and
any
other
values
required
to
determine
NOx
mass
emissions
(
e.
g.,
NOx
emission
rate
and
heat
input
rate,
or
NOx
216
concentration
and
stack
flow
rate)
in
accordance
with
§
75.70(
g)
of
this
chapter,
beginning
on
the
first
hour
of
the
applicable
compliance
deadline
in
paragraph
(
b)(
1)
or
(
b)(
2)
of
this
section.

(
2)
The
owner
or
operator
of
a
NOX
Budget
unit
under
paragraph
(
b)(
3)
or
(
b)(
4)
of
this
section
shall
determine,

record
and
report
NOx
mass
emissions,
heat
input
rate,
and
any
other
values
required
to
determine
NOx
mass
emissions
(
e.
g.,
NOx
emission
rate
and
heat
input
rate,
or
NOx
concentration
and
stack
flow
rate)
and
electric
and
thermal
output
in
accordance
with
§
75.70(
g)
of
this
chapter,

beginning
on:

(
i)
The
date
and
hour
on
which
the
unit
commences
operation,
if
the
date
and
hour
on
which
the
unit
commences
operation
is
during
a
control
period;
or
(
ii)
The
first
hour
on
May
1
of
the
first
control
period
after
the
date
and
hour
on
which
the
unit
commences
operation,
if
the
date
and
hour
on
which
the
unit
commences
operation
is
not
during
a
control
period.

(
3)
Notwithstanding
paragraphs
(
c)(
2)(
i)
and
(
c)(
2)(
ii)

of
this
section,
the
owner
or
operator
may
begin
reporting
NOx
mass
emission
data
and
heat
input
data
before
the
date
and
hour
under
paragraph
(
c)(
2)(
i)
or
(
c)(
2)(
ii)
of
this
section
if
the
unit
reports
on
an
annual
basis
and
if
the
required
monitoring
systems
are
certified
before
the
applicable
date
and
hour
under
paragraph
(
c)(
1)
or
(
c)(
2)
of
217
this
section.

*
*
*
*
*

19.
Section
97.71
is
amended
by:

a.
Revising
paragraph
(
a)
introductory
text;

b.
In
paragraphs
(
b)(
1),
(
b)(
2),
and
(
b)(
3)(
ii)
by
adding
the
word
"
emission"
before
the
words
"
monitoring
system"
in
each
occurrence
in
paragraph
(
b)(
1),
in
both
occurrences
in
the
first
sentence
of
paragraph
(
b)(
2),
and
in
the
one
occurrence
in
paragraph
(
b)(
3)(
ii);
and
by
revising
the
word
"
a"
to
read
"
an"
after
the
word
"
installs"

in
the
second
sentence
of
paragraph
(
b)(
1);

c.
In
paragraphs
(
b)(
3)(
iii)
and
(
b)(
3)(
iv)(
C)
by
removing
each
occurrence
of
the
words
"
or
component
thereof";
and
d.
Revising
the
second
sentence
of
paragraph
(
c),

adding
two
new
sentences
to
the
end
of
paragraph
(
c),
and
removing
paragraphs
(
c)(
i)
through
(
iii).

The
revisions
and
additions
read
as
follows:

§
97.71
Initial
certification
and
recertification
procedures.

(
a)
The
owner
or
operator
of
a
NOx
Budget
unit
that
is
subject
to
an
Acid
Rain
emissions
limitation
shall
comply
with
the
initial
certification
and
recertification
procedures
of
part
75
of
this
chapter
for
NOx­
diluent
CEMS,

flow
monitors,
NOx
concentration
CEMS,
or
excepted
monitoring
systems
under
Appendix
E
of
part
75
of
this
218
chapter
for
NOx,
under
Appendix
D
for
heat
input,
or
under
§
75.19
for
NOx
and
heat
input,
except
that:

*
*
*
*
*

(
c)
*
*
*
The
owner
or
operator
of
such
a
unit
shall
also
meet
the
applicable
certification
and
recertification
procedures
of
paragraph
(
b)
of
this
section,
except
that
the
excepted
methodology
shall
be
deemed
provisionally
certified
for
use
under
the
NOx
Budget
Trading
Program
as
of
the
date
on
which
a
complete
certification
application
is
received
by
the
Administrator.
The
methodology
shall
be
considered
to
be
certified
either
upon
receipt
of
a
written
notice
of
approval
from
the
Administrator
or,
if
such
notice
is
not
provided,
at
the
end
of
the
Administrator's
120
day
review
period.
However,
a
provisionally
certified
or
certified
low
mass
emissions
excepted
methodology
shall
not
be
used
to
report
data
under
the
NOx
Budget
Trading
Program
prior
to
the
applicable
commencement
date
specified
in
§
75.19(
a)(
1)(
ii)
of
this
chapter.

*
*
*
*
*

20.
Section
97.72
is
amended
by:

a.
In
paragraph
(
a)
by
adding
the
word
"
emission"

before
the
words
"
monitoring
system"
and
the
words
"
subpart
H,"
before
"
appendix
D";
and
b.
In
paragraph
(
b)
by
revising
the
words
"
a
monitoring
system"
in
the
first
sentence
to
read
"
an
emission
monitoring
system",
by
removing
each
occurrence
of
the
words
"
or
component"
in
the
219
paragraph,
and
by
adding
a
new
final
sentence.

The
revisions
and
additions
read
as
follows:

§
97.72
Out
of
control
periods.

*
*
*
*
*

(
b)
*
*
*
The
owner
or
operator
shall
follow
the
initial
certification
or
recertification
procedures
in
§
97.71
for
each
disapproved
system.

21.
Section
97.74
is
amended
by
revising
paragraphs
(
a)(
1),
(
d)(
1),
(
d)(
1)(
i)
through
(
d)(
1)(
iii),
and
(
d)(
2)(
ii);
and
by
adding
new
paragraphs
(
d)(
1)(
iii)(
A)
and
(
B),
and
(
d)(
1)(
iv)
to
read
as
follows:

§
97.74
Recordkeeping
and
reporting.

(
a)
*
*
*

(
1)
The
NO
x
authorized
account
representative
shall
comply
with
all
recordkeeping
and
reporting
requirements
in
this
section,
with
the
recordkeeping
and
reporting
requirements
under
§
75.73
of
this
chapter,
and
with
the
requirements
of
§
97.10(
e)(
1).

*
*
*
*
*

(
d)
*
*
*

(
1)
If
a
unit
is
subject
to
an
Acid
Rain
emission
limitation
or
if
the
owner
or
operator
of
the
NO
x
budget
unit
chooses
to
meet
the
annual
reporting
requirements
of
this
subpart
H,
the
NO
x
authorized
account
representative
shall
submit
a
quarterly
report
for
each
calendar
quarter
beginning
with:

(
i)
For
a
unit
for
which
the
owner
or
operator
intends
to
apply
or
applies
for
the
early
reduction
credits
under
§
97.43,
the
calendar
quarter
that
covers
May
1,
2000
through
June
30,
2000.
NO
x
mass
emission
data
shall
be
recorded
and
reported
from
the
first
hour
on
May
1,
2000;
or
220
(
ii)
For
a
unit
that
commences
operation
before
January
1,
2003
and
that
is
not
subject
to
paragraph
(
d)(
1)(
i)
of
this
section,
the
calendar
quarter
covering
May
1,
2003
through
June
30,
2003.
NO
x
mass
emission
data
shall
be
recorded
and
reported
from
the
first
hour
on
May
1,
2003;
or
(
iii)
For
a
unit
that
commences
operation
on
or
after
January
1,
2003:

(
A)
The
calendar
quarter
in
which
the
unit
commences
operation,
if
unit
operation
commences
during
a
control
period.
NO
x
mass
emission
data
shall
be
recorded
and
reported
from
the
date
and
hour
when
the
unit
commences
operation;
or
(
B)
The
calendar
quarter
which
includes
May
1
through
June
30
of
the
first
control
period
following
the
date
on
which
the
unit
commences
operation,
if
the
unit
does
not
commence
operation
during
a
control
period.
NO
x
mass
emission
data
shall
be
recorded
and
reported
from
the
first
hour
on
May
1
of
that
control
period;
or
(
iv)
A
calendar
quarter
before
the
quarter
specified
in
paragraph
(
d)(
1)(
i),

(
d)(
1)(
ii),
or
(
d)(
1)(
iii)(
B)
of
this
section,
if
the
owner
or
operator
elects
to
begin
reporting
early
under
§
97.70(
c)(
3).

(
2)
*
*
*

(
ii)
Submit
quarterly
reports,
documenting
NO
x
mass
emissions
from
the
unit,
only
for
the
period
from
May
1
through
September
30
of
each
year
and
including
the
data
described
in
§
75.74(
c)(
6)
of
this
chapter.
The
NO
x
authorized
account
representative
shall
submit
such
quarterly
reports,
beginning
with:

(
A)
For
a
unit
for
which
the
owner
or
operator
intends
to
apply
or
applies
for
the
early
reduction
credits
under
§
97.43,
the
calendar
quarter
that
covers
May
1,
2000
through
June
30,
2000.
NO
x
mass
emission
data
shall
be
recorded
and
reported
from
the
first
hour
on
May
1,
2000;
or
221
(
B)
For
a
unit
that
commences
operation
before
January
1,
2003
and
that
is
not
subject
to
paragraph
(
d)(
2)(
ii)(
A)
of
this
section,
the
calendar
quarter
covering
May
1,

2003
through
June
30,
2003.
NO
x
mass
emission
data
shall
be
recorded
and
reported
from
the
first
hour
on
May
1,
2003;
or
(
C)
For
a
unit
that
commences
operation
on
or
after
January
1,
2003
and
during
a
control
period,
the
calendar
quarter
in
which
the
unit
commences
operation.
NO
x
mass
emission
data
shall
be
recorded
and
reported
from
the
date
and
hour
when
the
unit
commences
operation;
or
(
D)
For
a
unit
that
commences
operation
on
or
after
January
1,
2003
and
not
during
a
control
period,
the
calendar
quarter
which
includes
May
1
through
June
30
of
the
first
control
period
following
the
date
on
which
the
unit
commences
operation.
NO
x
mass
emission
data
shall
be
recorded
and
reported
from
the
first
hour
on
May
1
of
that
control
period
*
*
*
*
*

§
97.87
[
Amended].

22.
Section
97.87
is
amended
by
revising
the
second
sentence
of
paragraph
(
b)(
1)(
iii)(
A)

by
adding
the
word
"
be"
after
the
words
"
shall
not".

23.
Subpart
J
and
§
97.90
are
added
to
read
as
follows:

Subpart
J
­­
Appeal
Procedures
§
97.90
Appeal
Procedures.

The
appeal
procedures
for
the
NO
x
Budget
Trading
Program
are
set
forth
in
part
78
of
this
chapter.
222
