VII.
SIP
Criteria
and
Emissions
Reporting
Requirements
This
section
describes:
(
1)
the
criteria
we
will
use
in
determining
approvability
of
SIPs
submitted
to
meet
the
requirements
of
today's
rulemaking;
(
2)
the
dates
for
submittal
of
the
SIPs
that
are
required
under
the
CAIR;
(
3)

the
consequences
of
either
failing
to
submit
such
a
SIP
or
submitting
a
SIP
which
is
disapproved;
and
(
4)
the
emissions
inventory
reporting
requirements
for
States.

A.
What
Criteria
Will
EPA
Use
to
Evaluate
the
Approvability
of
a
Transport
SIP?

1.
Introduction
The
approvability
criteria
for
CAIR
SIP
submissions
are
finalized
today
in
40
CFR
51.123
(
NOx
emissions
reductions)

and
in
40
CFR
51.124
(
SO2
emissions
reductions).
Most
of
the
criteria
are
substantially
similar
to
those
that
currently
apply
to
SIP
submissions
under
CAA
section
110
or
part
D
(
nonattainment).
For
example,
each
submission
must
describe
the
control
measures
that
the
State
intends
to
employ,
identify
the
enforcement
methods
for
monitoring
compliance
and
managing
violations,
and
demonstrate
that
the
State
has
legal
authority
to
carry
out
its
plan.

This
part
of
the
preamble
explains
additional
approvability
criteria
specific
to
the
CAIR
that
were
proposed
and
discussed
in
the
CAIR
NPR
or
in
the
CAIR
SNPR,

and
are
being
promulgated
today.
As
explained
in
both
the
CAIR
NPR
and
the
CAIR
SNPR,
EPA
proposed
that
each
affected
State
must
submit
SIP
revisions
containing
control
measures
that
assure
that
a
specified
amount
of
NOx
and
SO2
emissions
reductions
are
achieved
by
specified
dates.

Although
EPA
determined
the
amount
of
emissions
reductions
required
by
identifying
specific,
highly
costeffective
control
levels
for
EGUs,
EPA
explained
in
the
CAIR
NPR
and
the
CAIR
SNPR
that
States
have
flexibility
in
choosing
which
sources
to
control
to
achieve
the
required
emissions
reductions.
As
long
as
a
State's
emissions
reductions
requirements
are
met,
a
State
may
impose
controls
on
EGUs
only,
on
non­
EGUs
only,
or
on
a
combination
of
EGUs
and
non­
EGUs.
The
SIP
approvability
criteria
are
intended
to
provide
as
much
certainty
as
possible
that,
whichever
sources
a
State
chooses
to
control,
the
controls
will
result
in
the
required
amount
of
emissions
reductions.

In
the
CAIR
NPR,
EPA
proposed
a
"
hybrid"
approach
for
the
mechanisms
used
to
ensure
emissions
reductions
are
achieved.
This
approach
incorporates
elements
of
an
emissions
"
budget"
approach
(
requiring
an
emissions
cap
on
affected
sources)
and
an
"
emissions
reduction"
approach
(
not
requiring
an
emissions
cap).
In
this
hybrid
approach,
if
States
impose
control
measures
on
EGUs,
they
would
be
required
to
impose
an
emissions
cap
on
all
EGUs,
which
would
effectively
be
an
emissions
budget.
And,
as
stated
in
the
CAIR
NPR,
if
States
impose
control
measures
on
non­
EGUs,

they
would
be
encouraged
but
not
required
to
impose
an
emissions
cap
on
non­
EGUs.
In
the
CAIR
NPR,
we
requested
comment
on
the
issue
of
requiring
States
to
impose
caps
on
any
source
categories
that
the
State
chooses
to
regulate.

In
the
CAIR
SNPR,
we
proposed
to
modify
the
hybrid
approach
and
require
States
that
choose
to
control
large
industrial
boilers
or
turbines
(
greater
than
250
MMBTu/
hr)

to
impose
an
emissions
cap
on
all
such
sources
within
their
State.
This
is
similar
to
EPA's
approach
in
the
NOx
SIP
Call
which
required
States
to
include
an
emissions
cap
on
such
sources
as
well
as
on
EGUs
if
the
SIP
submittals
included
controls
on
such
sources.
(
See
40
CFR
51.121(
f)(
2)(
ii).)

A
few
commenters
supported
the
use
of
emissions
caps
on
any
source
category
subject
to
CAIR
controls,
including
non­

EGUs,
because
it
would
be
the
most
effective
way
to
demonstrate
compliance
with
the
budget.
A
few
other
commenters
opposed
the
use
of
an
emissions
cap
on
non­
EGUs,

saying
either
that
States
should
have
the
flexibility
to
determine
whether
to
impose
a
cap,
or
that
such
a
requirement
would
result
in
increased
costs
for
non­
EGUs
including
cogeneration
units
that
are
non­
EGUs.
No
commenter
opposing
such
a
requirement
provided
any
information
indicating
that
such
a
requirement
would
be
ineffective
or
impracticable.
Today
EPA
is
adopting
the
modified
approach,
as
described
in
the
CAIR
SNPR,
that
States
choosing
to
control
EGUs
or
large
industrial
boilers
or
turbines
must
do
so
by
imposing
an
emissions
cap
on
such
sources,
similar
to
what
was
required
in
the
NOx
SIP
Call.

Extensive
comments
were
received
regarding
the
need
for
an
ozone
season
NOx
cap
in
States
identified
to
be
contributing
significantly
to
the
region's
ozone
nonattainment
problems.
In
proposal,
EPA
stated
that
the
annual
NOx
cap
under
CAIR
reduced
NOx
emissions
sufficiently
enough
to
not
warrant
a
regional
ozone
season
NOx
cap.

Commenters
remained
very
concerned
that
the
annual
NOx
cap
would
not
aid
ozone
attainment.
While
EPA
feels
that
the
annual
NOx
limit
will
most
likely
be
protective
in
the
ozone
season,
a
seasonal
cap
will
provide
certainty,
which
EPA
agrees
is
very
important
in
the
effort
to
help
areas
achieve
ozone
attainment.
Today,
EPA
is
finalizing
an
ozone
season
NOx
cap
for
States
shown
to
contribute
significantly
for
ozone.
As
is
further
explained
in
section
VIII,
EPA
is
also
finalizing
an
ozone
season
trading
program
that
States
may
use
to
achieve
the
required
emissions
reductions.
This
program
will
subsume
the
existing
NOx
SIP
Call
trading
program.
Therefore,
any
State
that
wishes
to
continue
including
its
sources
in
an
interstate
trading
program
run
by
EPA
to
achieve
the
emissions
reductions
required
by
EPA
must
modify
its
SIP
to
conform
with
this
new
trading
program.

The
EPA
will
automatically
find
that
a
State
is
continuing
to
meet
its
NOx
SIP
Call
obligation
if
it
achieves
all
of
its
required
CAIR
emissions
reductions
by
capping
EGUs,
it
modifies
its
existing
NOx
SIP
Call
to
require
its
non­
EGUs
currently
participating
in
the
NOx
SIP
Call
budget
trading
program
to
conform
to
the
requirements
of
the
CAIR
ozone
season
NOx
trading
program
with
a
trading
budget
that
is
the
same
or
tighter
than
the
budget
in
the
currently
approved
SIP,
and
it
does
not
modify
any
of
its
other
existing
NOx
SIP
Call
rules.
If
a
State
chooses
to
achieve
the
ozone
season
NOx
emissions
reduction
requirements
of
CAIR
in
another
way,
it
will
also
be
required
to
demonstrate
that
it
continues
to
meet
the
requirements
of
the
NOx
SIP
Call.

Specific
criteria
for
approval
of
CAIR
SIP
submissions
as
promulgated
by
today's
action
are
described
below.
The
criteria
are
dependent
on
the
types
of
sources
a
State
chooses
to
control.

2.
Requirements
for
States
Choosing
to
Control
EGUs
a.
Emissions
Caps
and
Monitoring
As
explained
in
the
CAIR
NPR
(
69
FR
4626),
and
in
the
CAIR
SNPR
(
69
FR
32691),
EPA
proposed
requiring
States
to
apply
the
"
budget"
approach
if
they
choose
to
control
EGUs;
that
is,
each
State
must
cap
total
EGU
emissions
at
the
level
that
assures
the
appropriate
amount
of
reductions
for
that
State.
The
requirement
to
cap
all
EGUs
is
important
because
it
prevents
shifting
of
utilization
(
and
resulting
emissions)
to
uncapped
EGUs.
The
EGUs
are
part
of
a
highly
interconnected
electricity
grid
that
makes
utilization
shifting
likely
and
even
common.
The
units
are
large
and
offer
the
same
market
product
(
i.
e.,
electricity),
and
therefore
the
units
that
are
least
expensive
to
operate
are
likely
to
be
operated
as
much
as
possible.
If
capped
and
uncapped
units
are
interconnected,
the
uncapped
units'
costs
would
tend
to
decrease
relative
to
the
capped
units,
which
must
either
reduce
emissions
or
use
or
buy
allowances,
and
the
uncapped
units'
utilization
would
likely
increase.
The
cap
ensures
that
emissions
reductions
from
these
interconnected
sources
are
actually
achieved
rather
than
emissions
simply
shifting
among
sources.
The
caps
constitute
the
State
EGU
Budgets
for
SO2
and
NOx.

Additionally,
EPA
proposed
that,
if
States
choose
to
control
EGUs,
they
must
require
EGUs
to
follow
part
75
monitoring,

recordkeeping,
and
reporting
requirements.
Part
75
monitoring
and
reporting
requirements
have
been
used
effectively
for
determining
NOx
and
SO2
emissions
from
EGUs
under
the
title
IV
Acid
Rain
program
and
the
NOx
SIP
Call
program
and
in
combination
with
emissions
caps
are
an
integral
part
of
those
programs.
(
Additional
explanation
for
the
need
for
Part
75
monitoring
is
given
in
the
NPR
and
SNPR
and
is
incorporated
here.)
Therefore,
today,
EPA
adopts
the
requirements
for
emission
caps
and
Part
75
monitoring
for
EGUs
in
these
States.

b.
Using
the
Model
Trading
Rules
As
proposed,
if
a
State
chooses
to
allow
its
EGUs
to
participate
in
EPA­
administered
interstate
NOx
and
SO2
emissions
trading
programs,
the
State
must
adopt
EPA's
model
trading
rules,
as
described
elsewhere
in
today's
preamble
and
in
§
§
96.101­­
96.176
(
for
NOx)
and
§
§
96.201­­
96.276
(
for
SO2),
set
forth
below.
Additionally,
EPA
proposed
that
for
the
States
for
which
EPA
made
a
finding
of
significant
contribution
for
both
ozone
and
PM2.5,
participation
in
both
the
NOx
and
SO2
trading
programs
would
be
required
in
order
to
be
included
in
the
EPA­
administered
program.
States
for
which
the
finding
was
for
ozone
only
could
choose
to
participate
in
only
the
EPA­
administered
NOx
trading
program
through
adoption
of
the
NOx
model
trading
rule.
The
EPA
stated
that
States
adopting
EPA's
model
trading
rules,

modified
only
as
specifically
allowed
by
EPA,
will
meet
the
requirement
for
applying
an
emissions
cap
and
requirement
to
use
part
75
monitoring,
recordkeeping,
and
reporting
for
EGUs.

Some
commenters
opposed
EPA's
proposal
to
require
participation
in
both
the
NOx
and
SO2
trading
programs
because
some
States
may
want
to
participate
in
the
EPAadministered
trading
programs
for
only
NOx
or
only
SO2.
A
few
commenters
claimed
that
the
requirement
to
participate
in
both
programs
would
limit
State
flexibility
or
is
an
"
all
or
nothing"
approach;
other
commenters
objected
that
there
was
no
environmental
basis
for
such
a
requirement;
and
one
commenter
suggested
that
States
not
affected
by
CAIR
but
that
volunteer
to
control
emissions
should
be
permitted
to
join
the
program
for
one
or
both
pollutants.
Additionally,

commenters
cited
a
need
for
an
ozone
season
NOx
program.

The
EPA
has
taken
the
comments
into
account
and
in
today's
action
agrees
to
allow
a
State
identified
to
contribute
significantly
for
PM2.5
(
and
therefore
required
to
make
annual
SO2
and
NOx
reductions)
to
participate
in
the
EPA­
administered
CAIR
trading
program
for
either
SO2
or
NOx,

not
necessarily
both,
so
long
as
the
State
adopts
the
model
rule
for
the
applicable
trading
program.

In
response
to
extensive
comments
relating
to
EPA's
proposal
to
forego
a
seasonal
NOx
cap
because
EPA
demonstrated
that
the
annual
NOx
cap
was
sufficiently
stringent,
EPA
is
finalizing
an
ozone
season
NOx
trading
program
for
States
identified
as
contributing
significantly
for
ozone.
These
States
will
be
subject
to
an
ozone
season
NOx
cap
and
an
annual
NOx
cap
if
the
State
is
also
identified
as
contributing
significantly
for
PM
2.5.

Therefore,
today's
action
includes
an
additional
model
rule
for
an
ozone
season
NOx
trading
program
(
40
CFR
96,
subparts
AAAA
through
IIII).
The
States
that
may
use
the
ozone
season
NOx
trading
program
but
not
the
annual
NOx
trading
program
are
those
States
in
the
CAIR
region
identified
as
contributing
significantly
for
ozone
only
(
Arkansas,

Connecticut,
Delaware,
Massachusetts,
and
New
Jersey).

As
discussed
in
the
proposal,
EPA
is
finalizing
the
option
for
New
Hampshire
and
Rhode
Island
to
participate
in
the
regional
trading
program
through
use
of
the
CAIR
ozone
season
NOx
model
rule
because
sources
in
these
States
have
made
investments
in
NOx
controls
in
the
past
based
on
the
existence
of
a
regional
ozone
season
NOx
trading
program.

Additionally,
the
States'
combined
projected
2010
and
2015
NOx
emissions
are
less
than
one­
half
of
one
percent
of
the
total
CAIR
regional
NOx
cap
and
therefore
would
not
create
a
significant
increase
in
the
CAIR
cap.
All
comments
received
were
supportive
of
this
approach
and
EPA
is
finalizing
it
today.

None
of
these
States
(
Arkansas,
Connecticut,
Delaware,

Massachusetts,
New
Hampshire,
New
Jersey,
or
Rhode
Island)

has
the
option
to
participate
in
the
EPA­
administered
CAIR
SO2
trading
program
nor
the
annual
CAIR
NOx
trading
program
because
there
are
no
PM2.5­
related
emissions
reductions
1
Title
IV
allowances
can
however
be
traded
freely
across
the
boundary
of
the
CAIR
region
without
any
significant,
negative
environmental
consequence.
The
potential
negative
consequences
have
been
addressed
through
other
requirements
discussed
below,
like
the
retirement
of
excess
title
IV
allowances.
required
under
today's
action
in
those
States.
(
Of
course,

sources
in
these
States
will
still
be
subject
to
the
Acid
Rain
SO2
cap­
and­
trade
program.)
Likewise,
Texas,
Minnesota
and
Georgia
may
not
participate
in
the
ozone
season
NOx
program,
because
they
have
not
been
shown
to
contribute
significantly
to
the
regional
ozone
problem.
They
are,

however,
required
to
make
annual
NOx
and
SO2
reductions
and
may
choose
to
participate
in
the
annual
NOx
and
annual
SO2
trading
program
to
meet
their
CAIR
obligations.

Except
for
the
special
cases
of
Rhode
Island
and
New
Hampshire,
other
States
outside
of
the
CAIR
region
may
not
participate
in
the
CAIR
trading
programs
for
either
pollutant,
because
they
were
not
shown
to
contribute
significantly
to
PM2.5
or
ozone
nonattainment
in
the
CAIR
region.
Allowing
States
outside
of
the
CAIR
region
to
participate
would
generally
create
an
opportunity
 
­
through
net
sales
of
allowances
from
the
non­
CAIR
States
to
CAIR
States­­
for
emission
increases
in
States
that
have
been
shown
to
contribute
significantly
to
nonattainment
in
the
CAIR
region.
1
A
State
may
not
participate
in
the
EPA­
administered
trading
programs
if
they
choose
to
get
a
portion
of
CAIR
reductions
from
non­
EGUs.
(
This
is
also
discussed
in
Section
VIII.)
EPA
maintains
that
requiring
certain
consistencies
among
States
in
the
regionwide
trading
programs
that
EPA
has
offered
to
run
does
not
unfairly
limit
States'
flexibility
to
choose
an
approach
for
achieving
CAIR
mandated
reductions
that
is
best
suited
for
a
particular
State's
unique
circumstances.
States
are
free
to
achieve
the
reductions
through
whatever
alternative
mechanisms
the
States
wish
to
design;
for
example,
a
group
of
States
could
cooperatively
implement
their
own
multi­
State
trading
programs
that
EPA
would
not
administer.

c.
Using
a
Mechanism
Other
than
the
Model
Trading
Rules
If
States
choose
to
control
EGUs
through
a
mechanism
other
than
the
EPA­
administered
NOx
and
SO2
emissions
trading
programs,
then
the
States
(
i)
must
still
impose
an
emissions
cap
on
total
EGU
emissions
and
require
part
75
monitoring,
recordkeeping,
and
reporting
requirements
on
all
EGUs,
and
(
ii)
must
use
the
same
definition
of
EGU
as
EPA
uses
in
its
model
trading
rules,
i.
e.,
the
sources
described
as
"
CAIR
units"
in
§
96.102,
§
96.202,
and
§
96.302.
A
few
commenters
expressed
concern
that
these
requirements
limit
States'
discretion
in
designing
control
measures
to
meet
the
CAIR
requirements,
but
failed
to
offer
any
reason
why
the
requirements
would
be
impracticable
or
ineffective.
The
EPA
believes
that
the
requirements
are
necessary
for
a
number
of
reasons.
The
requirements
to
cap
all
EGUs
and
to
use
the
same
definition
of
EGU
are
important
because
they
prevent
shifting
of
utilization
(
and
resulting
emissions)
from
capped
to
uncapped
sources.
In
this
case,
not
requiring
a
cap
on
total
EGU
emissions
in
these
States
is
likely
to
result
in
increased
utilization
and
consequently
increased
emissions
in
these
States.
The
requirement
to
use
part
75
monitoring
ensures
the
accuracy
of
monitored
data
and
consistency
of
reporting
among
sources
(
and
thus
the
certainty
that
emissions
reductions
actually
occurred)

across
all
States.
Furthermore,
most
EGUs
are
currently
monitoring
and
reporting
using
part
75
so
it
does
not
impose
an
additional
requirement.
Therefore,
EPA
is
finalizing
the
proposed
approach.

If
a
State
chooses
to
design
its
own
intrastate
or
interstate
NOx
or
SO2
emissions
trading
programs,
the
State
must,
in
addition
to
meeting
the
requirements
of
the
rules
finalized
in
today's
action,
consider
EPA's
guidance,

"
Improving
Air
Quality
with
Economic
Incentive
Programs,"

January,
2001
(
EPA­
452/
R­
01­
001)
(
available
on
EPA's
website
at:
http://
www.
epa.
gov/
ttn/
ecas/
incentiv.
html).
The
State's
programs
are
subject
to
EPA
approval.
The
EPA
will
not
administer
a
State­
designed
trading
program.
Additionally,

it
should
be
noted
that
allowances
from
any
alternate
trading
program
may
not
be
used
in
the
EPA­
administered
trading
programs.

d.
Retirement
of
Excess
Title
IV
Allowances
The
CAIR
NPR
proposed
requirements
on
SIPs
relating
to
the
effects
of
title
IV
SO2
allowance
allocations
for
2010
and
beyond
that
are
in
excess
of
the
State's
CAIR
EGU
SO2
emissions
budget.
The
requirements
were
intended
to
ensure
that
the
excess
is
not
used
in
a
manner
that
would
lead
to
a
significant
increase
in
supply
of
title
IV
allowances,
the
collapse
of
the
price
of
title
IV
allowances,
the
disruption
of
operation
of
the
title
IV
allowance
market
and
the
title
IV
SO2
cap­
and­
trade
system,
and
the
potential
for
increased
emissions
in
all
States
prior
to
2010
and
in
non­
CAIR
States
in
2010
and
later.
These
negative
impacts
on
the
title
IV
allowance
market
and
on
air
quality,
which
are
discussed
in
detail
in
section
IX.
B.
below,
would
undermine
the
efficacy
of
the
title
IV
program
and
could
erode
confidence
in
capand
trade
programs
in
general.
To
avoid
these
impacts,
EPA
proposed
to
require
retirement
of
the
excess
title
IV
allowances
through
a
retirement
ratio
mechanism.

The
EPA
proposed,
as
a
mechanism
for
removing
these
additional
allowances
and
meeting
the
50
percent
reduction
required
under
phase
I
(
2010­
2014),
that
each
affected
EGU
had
to
hold,
and
EPA
would
retire,
two
vintage
2010­
2014
allowances
for
every
ton
of
SO2
that
the
unit
emits.

Further,
EPA
proposed
that,
for
phase
II
(
which
begins
in
2015)
when
a
65
percent
reduction
is
required,
each
affected
EGU
had
to
hold,
and
EPA
would
retire,
three
vintage
2015
and
beyond
allowances
for
every
ton
of
SO2
that
the
unit
emits.
This
3­
to­
1
ratio
would
result
in
slightly
more
reductions
than
EPA
has
determined
were
necessary
to
eliminate
the
significant
contribution
by
an
upwind
State.

In
the
CAIR
SNPR,
EPA
proposed
two
alternatives
for
addressing
the
issue
of
the
additional
allowances.
Under
the
first
alternative,
affected
EGUs
had
to
hold,
and
EPA
would
retire,
vintage
2015
and
beyond
allowances
at
a
rate
of
2.86­
to­
1
rather
than
3­
to­
1,
which
would
result
in
exactly
the
amount
of
reductions
EPA
has
determined
are
necessary
to
eliminate
a
State's
significant
contribution.

Alternatively,
also
in
the
CAIR
SNPR,
EPA
proposed
requiring
the
retirement
of
2015
and
beyond
vintage
allowances
at
a
3­
to­
1
ratio
and
permitting
States
to
convert
the
additional
reductions
into
allowances
in
their
rules.
The
EPA
also
suggested
that
some
States
may
want
to
use
these
reserved
allowances
to
create
an
incentive
for
additional
local
emissions
reductions
that
will
be
needed
to
bring
all
areas
into
attainment
with
the
PM2.5
NAAQS.

As
part
of
today's
final
CAIR
rulemaking,
EPA
is
finalizing
a
ratio
of
2.86­
to­
one.
The
ratio
ultimately
represents
a
reduction
of
65
percent
from
the
final
title
IV
cap
level,
which
has
been
found
to
be
highly
cost­
effective.
For
a
detailed
discussion
regarding
EPA's
determination
of
highly
cost­
effective,
please
refer
to
Section
IV
of
the
final
CAIR
preamble.
As
discussed
earlier,
EPA
must
employ
a
uniform
ratio
across
sources
to
ensure
consistency
and
the
same
cost­
effectiveness
level
across
sources.
The
use
of
a
3­
to­
1
ratio
is
above
the
threshold
that
EPA
has
found
to
be
cost­
effective,
and
the
use
of
this
ratio
in
conjunction
with
granting
States
flexibility
to
redistribute
the
additional
allowances
represented
by
the
difference
between
the
2.86­
to­
1
and
the
3­
to­
1
ratios
creates
potential
problems
since
some
States
may
choose
not
to
redistribute
the
additional
allowances.
EPA
is
unable
to
ensure
that
all
States
redistribute
the
additional
allowances
back
to
sources,
which
would
lead
to
different
ratios
for
various
sources.
In
light
of
this,
EPA
will
use
a
Phase
II
ratio
of
2.86­
to­
1
for
all
States
affected
by
CAIR
who
choose
to
participate
in
the
trading
program.

Today,
EPA
is
finalizing
the
general
requirement
that
all
SIPs
must
include
a
mechanism
to
ensure
that
excess
SO2
allowances
are
retired.
Furthermore,
for
States
that
participate
in
the
EPA­
administered
cap­
and­
trade
program,

EPA
is
finalizing
a
specific
mechanism
that
States
must
use.

i.
States
Participating
in
the
EPA­
Administered
SO2
Trading
Program
If
a
State
chooses
to
participate
in
the
EPA­
administered
trading
program,
the
State's
excess
title
IV
allowance
retirement
mechanism
must
follow
the
provisions
of
the
SO2
model
trading
rule
that
requires
that
vintage
2010
through
2014
title
IV
allowances
be
retired
at
a
ratio
of
two
allowances
for
every
ton
of
emissions
and
that
vintage
2015
and
beyond
title
IV
allowances
be
retired
at
a
ratio
of
2.86
allowances
for
every
ton
of
emissions.
Pre­
2010
vintage
allowances
would
be
retired
at
a
ratio
of
one
allowance
for
every
ton
of
emissions.
(
See
discussion
of
the
model
SO2
cap
and
trade
rule
in
section
VIII
of
today's
preamble.)
States
using
the
model
SO2
cap­
and­
trade
rule
satisfy
the
requirement
for
retirement
of
excess
title
IV
allowances.

ii.
States
not
Participating
in
the
EPA­
Administered
SO2
Trading
Program
In
the
CAIR
NPR,
EPA
stated
that
if
a
State
does
not
choose
to
participate
in
the
EPA­
administered
trading
programs
but
controls
only
EGUs,
the
State
may
choose
the
specific
method
to
retire
allowances
in
excess
of
its
budget.
The
EPA
considered
alternative
ways
for
retiring
these
excess
allowances
and,
as
stated
in
the
CAIR
SNPR,

believed
that
the
use
by
different
States
of
different
means
to
address
this
concern
could
undermine
the
regionwide
emissions
reduction
goals
of
the
CAIR
rulemaking.
The
EPA
further
described
its
concerns
in
section
II
of
the
preamble
to
the
CAIR
SNPR.
(
See
69
FR
32686­
32688.)
Because
of
these
concerns,
in
the
CAIR
SNPR,
EPA
withdrew
the
CAIR
NPR
proposal
on
this
point
and
re­
proposed
that
all
States
use
a
2­
for­
1
retirement
ratio
for
vintage
2010
through
2014
allowances
and
a
2.86­
for­
1
or
a
3­
for­
1
retirement
ratio
for
vintage
2015
and
beyond
allowances
to
address
concerns
about
title
IV
allowances
that
exceed
State
budgets.
The
EGUs
would
have
a
total
emissions
cap
enforced
by
the
State.

The
SNPR
described
that
for
sources
affected
by
both
title
IV
and
CAIR,
allowance
deductions
and
associated
compliance
determinations
would
be
sequential.
That
is,

title
IV
compliance
would
be
determined
and
then
CAIR
compliance
would
be
determined.
So,
in
2010­
2014,
after
surrendering
one
vintage
2010
through
2014
allowance
for
each
ton
of
emissions
for
title
IV
compliance,
the
source
would
then
surrender
one
additional
allowance
(
for
a
total
of
two
allowances
for
each
ton
which
meets
the
CAIR
requirement).
Similarly,
in
2015
and
beyond,
after
surrendering
one
vintage
2015
and
beyond
allowance
for
each
ton
of
emissions
for
title
IV
compliance,
the
source
would
surrender
1.86
or
2
additional
allowances
and
therefore
meet
the
CAIR
requirement.
Commenters
argued
that
in
States
where
EGUs
are
not
trading
under
CAIR
that
the
excess
title
IV
allowances
could
be
removed
in
a
variety
of
ways
and
that
EPA
did
not
need
to
require
each
State
do
this
the
same
way,
only
that
each
State
ensure
that
they
are
removed.

Today,
EPA
adopts
the
following
requirement:
if
a
State
does
not
choose
to
participate
in
the
EPA­
administered
trading
programs
but
controls
only
EGUs,
the
State
must
include
in
its
SIP
a
mechanism
for
retiring
the
excess
title
IV
allowances
(
i.
e.,
the
difference
between
total
allowance
allocations
in
the
State
and
the
State
EGU
SO2
budget).
To
meet
this
requirement,
the
State
may
use
the
above­
described
retirement
mechanism
or
may
develop
a
different
mechanism
that
will
achieve
the
required
retirement
of
excess
allowances.

3.
Requirements
for
States
Choosing
to
Control
Sources
Other
than
EGUs
a.
Overview
of
Requirements
As
noted
in
both
the
CAIR
NPR
and
the
CAIR
SNPR,
if
a
State
chooses
to
require
emissions
reductions
from
non­
EGUs,

the
State
must
adopt
and
submit
SIP
revisions
and
supporting
documentation
designed
to
quantify
the
amount
of
reductions
from
the
non­
EGU
sources
and
to
assure
that
the
controls
will
achieve
that
amount.
Although
EPA
did
not
propose
in
the
CAIR
NPR
that
States
be
required
to
impose
an
emissions
cap
on
those
sources,
but
instead
solicited
comment
on
the
issue,
EPA
proposed
in
the
CAIR
SNPR
that
States
be
required
to
impose
an
emissions
cap
in
certain
cases
on
non­
EGU
sources.
(
See
discussion
in
VII.
A.
1
of
today's
preamble.)
2
In
the
CAIR
SNPR,
EPA
mistakenly
cited
the
EGU
budget
numbers
from
Tables
VI­
9
and
VI­
10
in
the
CAIR
NPR
(
69
FR
4619­
20)
when
it
should
have
cited
Tables
II­
1
and
II­
2
in
the
CAIR
SNPR.
The
EPA
used
the
correct
numbers,
however,
in
the
proposed
regulatory
text
in
the
CAIR
SNPR
(
69
FR
32729­
30
and
69
FR
32733­
34
(
§
§
51.123(
e)(
2)
and
51.124(
e)(
2)).
If
a
State
chooses
to
obtain
some,
but
not
all,
of
its
required
reductions
for
SO2
or
NOx
emissions
from
non­
EGUs,

it
would
still
be
required
to
set
an
EGU
budget
for
SO2
or
NOx
respectively,
but
it
would
set
such
a
budget
at
some
level
higher
than
shown
in
Tables
V­
1,
V­
2,
or
V­
4
in
today's
preamble,
thus
allowing
more
emissions
from
EGUs.

The
difference
between
the
amount
of
a
State's
SO2
budget
in
Table
V­
1
and
a
State's
selected
higher
EGU
SO2
budget
would
be
the
amount
of
SO2
emissions
reductions
the
State
demonstrates
it
will
achieve
from
non­
EGU
sources.
By
the
same
token,
the
difference
between
the
amount
of
a
State's
annual
NOx
budget
in
Table
V­
2
and
a
State's
selected
higher
annual
EGU
NOx
budget
would
be
the
amount
of
annual
NOx
emissions
reductions
the
State
demonstrates
it
will
achieve
from
non­
EGU
sources.
2
Further,
the
difference
between
the
amount
of
a
State's
seasonal
NOx
budget
in
Table
V­
4
and
a
State's
selected
higher
ozone
season
EGU
NOx
budget
would
be
the
amount
of
ozone
season
NOx
emissions
reductions
the
State
demonstrates
it
will
achieve
from
non­
EGU
sources.

Special
concerns
about
SO2
allowances
In
the
case
where
a
State
requires
a
portion
of
its
SO2
emissions
reductions
from
non­
EGU
sources
and
a
portion
from
EGUs,
there
remains
a
concern
about
the
impact
of
excess
title
IV
allowances
above
a
State's
EGU
cap,

particularly
on
the
operation
of
the
title
IV
SO2
cap­

andtrade
program.
Consequently,
today,
we
are
adopting
the
requirement
that
these
States
include
a
mechanism
for
retirement
of
the
allowances
in
excess
of
the
State's
SO2
budget.

Like
a
State
choosing
to
control
only
EGUs
but
not
to
participate
in
the
trading
program,
a
State
that
chooses
to
control
non­
EGUs
and
EGUs
must
adopt
a
mechanism
for
retiring
surplus
title
IV
allowances.
The
number
of
title
IV
allowances
that
must
be
retired
is
equal
to
the
difference
between
the
number
of
title
IV
allowances
allocated
to
EGUs
in
that
State
and
the
SO2
budget
the
State
sets
for
EGUs
under
this
rule.
If
the
State
uses
a
retirement
mechanism
(
as
discussed
in
VII.
A.
2.
d.)
in
which
a
source
surrendering
allowances
under
the
title
IV
SO2
capand
trade
program
surrenders
more
allowances
than
otherwise
required
under
title
IV,
the
total
number
of
allowances
surrendered
per
ton
of
emissions
in
this
case
will
be
less
than
2
to
1
in
Phase
1
and
less
than
2.86
to
1
in
Phase
2.

This
is
because
the
non­
EGUs
will
control
to
achieve
a
portion
of
the
CAIR
SO2
reduction
required,
and
so
there
will
be
a
smaller
surplus
of
title
IV
allowances
than
if
all
the
required
reductions
were
achieved
by
EGUs.
The
appropriate
retirement
factor
will
equal
two
times
the
State's
SO2
budget
in
Phase
I
or
2.86
times
the
State's
SO2
budget
in
Phase
II
as
noted
in
Table
V­
1
of
the
budget
section,
divided
by
the
State's
selected
higher
EGU
SO2
budget
(
taking
into
account
non­
EGU
reductions).
The
factor
could
then
be
used
as
the
EGU
retirement
ratio
for
compliance
purposes
in
a
scenario
where
a
State
has
decided
to
control
SO2
emissions
from
EGUs
through
a
mechanism
other
than
the
EPA­
administered
trading
program.

A
simplified
example
can
help
illustrate
this.
Let
us
assume
a
State's
sources
were
allocated
a
total
of
200
allowances
under
title
IV.
Under
CAIR,
in
Phase
I,
the
State's
reduction
requirement
would
thus
be
100
tons.

Suppose
this
State
decided
that
25
tons
would
be
reduced
by
non­
EGUs
and
the
remaining
75
tons
would
be
reduced
by
the
EGUs.
(
The
State's
budget
for
EGUS
would
increase
to
125
tons.)
The
State
would
also
need
to
retire
75
excess
title
IV
allowances.
This
could
be
accomplished
by
requiring
each
Acid
Rain
source
to
surrender
a
total
of
1.6
vintage
2010
through
2014
allowances
(
200
allowances
allocated
in
the
State
/
125
tons
in
State
EGU
budget)
per
ton
of
SO2
emissions.
The
allowances
surrendered
would
satisfy
the
Acid
Rain
Program
requirement
of
surrendering
one
allowance
per
ton
of
emissions,
as
well
as
achieving
the
additional
retirement
requirement
under
CAIR
since
200
allowances
would
be
used
for
EGUs
to
emit
the
EGU
budget
of
125
tons
of
SO2.

(
Pre­
2010
allowances
continue
to
be
available
for
use
on
a
one­
allowance­
per­
ton­
of­
emissions
basis
here
as
in
other
situations.)

This
is
consistent
with
EPA's
overall
approach.
If
this
same
State
decided
to
get
all
reductions
(
i.
e.,
100
tons)
from
EGUs,
the
State
would
require
EGUs
to
retire
100
additional
allowances
by
surrendering
a
total
of
2
vintage
2010
through
2014
allowances
(
200
allowances
allocated
in
the
State
/
100
tons
in
State
EGU
budget)
per
ton
of
SO2
emissions.

The
demonstration
of
emissions
reductions
from
non­
EGUs
is
a
critical
requirement
of
the
SIP
revision
due
from
a
State
that
chooses
to
control
non­
EGUs.
The
State
must
take
into
account
the
amount
of
emissions
attributable
to
the
source
category
in
both
(
i)
the
base
case,
in
the
implementation
years
2010
and
2015,
i.
e.,
without
assuming
any
SIP­
required
reductions
under
the
CAIR
from
non­
EGUs;

and
(
ii)
in
the
control
case,
in
the
implementation
years
2010
and
2015,
i.
e.,
assuming
SIP­
required
reductions
under
the
CAIR
from
non­
EGUs.
We
proposed
an
alternative
methodology
for
calculating
the
base
case
for
certain
large
non­
EGU
sources,
as
described
below,
but
generally
the
difference
between
emissions
in
the
base
case
and
emissions
in
the
control
case
equals
the
amount
of
emissions
reductions
that
can
be
claimed
from
application
of
the
controls
on
non­
EGUs.
(
See
discussion
later
in
this
section
for
criteria
applicable
to
development
of
the
baseline
and
projected
control
emissions
inventories.)

States
that
meet
the
lesser
of
their
CAIR
ozone
season
NOx
budget
or
NOx
SIP
Call
EGU
trading
budget
using
the
CAIR
ozone
season
NOx
trading
program
also
satisfy
their
NOx
SIP
Call
requirements
for
EGUs.
States
may
also
choose
to
include
all
of
their
NOx
SIP
Call
non­
EGUs
in
the
CAIR
ozone
season
NOx
program
at
their
NOx
SIP
Call
levels
(
i.
e.,
the
non­
EGU
trading
budget
remains
the
same).

To
the
extent
EPA
allows
through
the
Regional
Haze
Rule
and
a
State
then
chooses
to
use
EPA
analysis
to
show
that
CAIR
reductions
from
EGUs
meet
BART
requirements,
States
that
achieve
a
portion
of
their
CAIR
reductions
from
sources
other
than
EGUs
and
wanting
to
show
that
even
with
those
reductions
the
EGUs
will
meet
BART
requirements
must
make
a
supplemental
demonstration
that
BART
requirements
are
satisfied.

b.
Eligibility
of
Non­
EGU
Reductions
In
the
CAIR
SNPR,
EPA
proposed
that,
in
evaluating
whether
emissions
reductions
from
non­
EGUs
would
count
towards
the
emissions
reductions
required
under
the
CAIR,

States
may
only
include
reductions
attributable
to
measures
that
are
not
otherwise
required
under
the
CAA.

Specifically,
EPA
proposed
that
States
must
exclude
non­
EGU
reductions
attributable
to
measures
otherwise
required
by
the
CAA,
including:
(
1)
measures
required
by
rules
already
in
place
at
the
date
of
promulgation
of
today's
final
rule,

such
as
adopted
State
rules,
SIP
revisions
approved
by
EPA,

and
settlement
agreements;
(
2)
measures
adopted
and
implemented
by
EPA
(
or
other
Federal
agencies)
such
as
emissions
reductions
required
pursuant
to
the
Federal
Motor
Vehicle
Control
Program
for
mobile
sources
(
vehicles
or
engines)
or
mobile
source
fuels,
or
pursuant
to
the
requirements
for
National
Emissions
Standards
for
Hazardous
Air
Pollutants;
and
(
3)
specific
measures
which
are
mandated
under
the
CAA
(
which
may
have
been
further
defined
by
EPA
rulemaking)
based
on
the
classification
of
an
area
which
has
been
designated
nonattainment
for
a
NAAQS,
such
as
vehicle
inspection
and
maintenance
programs.

In
discussing
this
proposal,
EPA
noted
that
States
required
to
make
CAIR
SIP
submittals
may
also
be
required
to
make
separate
SIP
submittals
to
meet
other
requirements
applicable
to
non­
EGUs,
e.
g.,
nonattainment
SIPs
required
for
areas
designated
nonattainment
under
the
PM2.5
or
8­
hour
ozone
NAAQS
or
regional
haze
SIPs.
The
EPA
noted
it
is
likely
that
CAIR
SIP
submittals
will
be
due
before
or
at
the
same
time
as
some
of
these
other
SIP
submittals.
We
therefore
proposed
that
States
relying
on
reductions
from
controls
on
non­
EGUs
must
commit
in
the
CAIR
SIP
revisions
to
replace
the
emissions
reductions
attributable
to
any
CAIR
SIP
measure
if
that
measure
is
subsequently
determined
to
be
required
to
meet
any
other
SIP
requirement.

Some
commenters
objected
to
the
proposed
exclusion
of
credit
for
measures
which
are
mandated
under
the
CAA
based
on
the
classification
of
an
area
which
has
been
designated
nonattainment
for
a
NAAQS,
as
well
as
to
the
proposed
requirement
that
such
measures
must
be
replaced
if
they
are
later
determined
to
be
required
in
meeting
separate
SIP
requirements.
These
commenters
reasoned
that
such
a
requirement
would
not
be
applied
to
EGUs
and
would
impose
unnecessary
and
costly
burdens
on
non­
EGUs,
thus
creating
an
incentive
for
States
to
avoid
controlling
non­
EGUs
and
to
impose
all
CAIR
reduction
requirements
on
EGUs.
One
commenter
further
objected
that,
as
long
as
a
measure
was
not
included
in
the
base
case
EPA
used
to
determine
a
State's
contribution
to
other
States'
nonattainment
under
CAA
section
110(
a)(
2)(
D),
there
is
no
justification
for
excluding
CAIR
credit
for
such
measure,
and
that
EPA's
proposed
exclusion
of
credit
for
any
measure
"
otherwise
required
by
the
CAA"
is
inconsistent
with
the
NOx
SIP
Call.

In
response
to
these
comments,
EPA
agrees
that
it
is
not
appropriate
to
apply
this
proposed
restriction
inconsistently
to
EGUs
and
non­
EGUs.
Thus,
EPA
is
adopting
a
modified
form
of
the
proposed
criteria
for
the
eligibility
of
non­
EGU
emissions
reductions,
eliminating
the
requirement
that
States
must
exclude
non­
EGU
reductions
attributable
to
measures
otherwise
required
by
the
CAA
based
on
the
classification
of
an
area
which
has
been
designated
nonattainment
for
a
NAAQS.
Consequently,
the
final
rule
allows
credit
for
measures
that
a
State
later
adopts
in
response
to
requirements
which
result
from
an
area's
nonattainment
classification,
such
as
reasonably
available
control
technology
(
RACT).
With
this
change,
all
emissions
reductions
are
eligible
for
credit
in
meeting
CAIR
except:

(
1)
measures
adopted
or
implemented
by
the
State
as
of
the
date
of
promulgation
of
today's
final
rule,
such
as
adopted
State
rules,
SIP
revisions
approved
by
EPA,
and
settlement
agreements;
and
(
2)
measures
adopted
or
implemented
by
the
Federal
government
(
e.
g.,
EPA
or
other
Federal
agencies)
as
of
the
date
of
submission
of
the
SIP
revision
by
the
State
to
EPA,
such
as
emissions
reductions
required
pursuant
to
the
Federal
Motor
Vehicle
Control
Program
for
mobile
sources
(
vehicles
or
engines)
or
mobile
source
fuels,
or
pursuant
to
the
requirements
for
National
Emissions
Standards
for
Hazardous
Air
Pollutants.

This
exclusion
of
credit
is
consistent
with
EPA's
approach
in
the
NOx
SIP
Call,
although
a
direct
comparison
of
the
creditability
requirements
in
the
CAIR
and
in
the
NOx
SIP
Call
is
not
possible
due
to
the
timing
and
context
in
which
both
rules
were
developed.
The
NOx
SIP
Call
used
statewide
budgets
for
all
sources
as
an
accounting
tool
to
determine
the
adequacy
of
a
strategy,
while
the
CAIR
takes
a
different
approach
in
which
baseline
emission
inventories
for
non­
EGU
sectors
will,
if
needed,
be
developed
later.

The
NOx
SIP
Call
did,
as
does
the
CAIR,
restrict
States
from
taking
credit
for
any
Federal
measures
adopted
after
promulgation
of
the
rule
(
63
FR
57427­
28).
It
also
did
not
allow
credit
for
already
adopted
measures,
but
the
timing
of
the
NOx
SIP
Call
was
such
that
nonattainment
planning
measures
would
have
already
likely
been
adopted
as
the
SIP
deadlines
for
adoption
of
such
measures
had
passed.
In
today's
action,
nonattainment
planning
measures
adopted
after
the
promulgation
of
today's
rule
will
be
allowed
credit
under
CAIR.

In
order
to
take
credit
for
CAIR
reductions
from
non­

EGUs,
the
reductions
must
be
beyond
what
is
required
under
the
NOx
SIP
Call.
That
is,
a
reduction
must
be
in
the
nonozone
season
or
it
must
be
beyond
what
is
expected
in
the
ozone
season.
Non­
ozone
season
reductions
must
also
be
beyond
what
is
in
the
base
case,
particularly
for
units
that
have
low
NOx
burners
and
certain
SCRs
(
e.
g.,
ones
required
to
be
run
annually).
The
reductions
must
be
in
addition
to
those
already
expected.
If
ozone
season
reductions
are
considered,
the
non­
EGU
NOx
SIP
Call
trading
budget
must
be
adjusted
by
the
increment
of
CAIR
reductions
beyond
the
levels
in
the
NOx
SIP
Call.
This
removes
the
corresponding
allowances
from
the
market
and
ensures
that
the
emissions
do
not
shift
to
other
sources.

After
evaluating
the
eligibility
of
non­
EGU
reductions
in
accordance
with
the
requirements
discussed
here,
States
must
exclude
credit
for
ineligible
measures
by
(
i)
including
such
measures
in
both
the
baseline
and
controlled
emissions
inventory
cases,
if
they
have
already
been
adopted;
or
(
ii)

excluding
them
from
both
the
base
and
control
emissions
inventory
cases
if
they
have
not
yet
been
adopted.
(
See
discussion
later
in
this
section
regarding
development
of
emissions
inventories
and
demonstration
of
non­
EGU
reductions.)

c.
Emissions
Controls
and
Monitoring
As
noted
in
section
VII.
A.
1.,
we
modified
the
"
hybrid"

approach
described
in
the
CAIR
NPR
as
it
applies
to
certain
non­
EGUs,
and
adopt
today
the
approach
described
in
the
CAIR
SNPR.
Specifically,
for
States
that
choose
to
impose
controls
on
large
industrial
boilers
and
turbines,
i.
e.,

those
whose
maximum
design
heat
input
is
greater
than
250
mmBtu/
hr,
to
meet
part
or
all
of
their
emissions
reductions
requirements
under
the
CAIR,
State
rules
must
include
an
emissions
cap
on
all
such
sources
in
their
State.

Additionally,
in
this
situation,
States
must
require
those
large
industrial
boilers
and
turbines
to
meet
part
75
requirements
for
monitoring
and
reporting
emissions
as
well
as
recordkeeping.
This
ensures
consistency
in
measurement
and
certainty
of
reductions
and
has
been
proven
technologically
and
economically
feasible
in
other
programs.

If
a
State
chooses
to
control
non­
EGUs
other
than
large
industrial
boilers
and
turbines
to
obtain
the
required
emissions
reductions,
the
State
must
either
(
i)
impose
the
same
requirements,
i.
e.,
an
emissions
cap
on
total
emissions
from
non­
EGUs
in
the
source
category
in
the
State
and
part
75
monitoring,
reporting
and
recordkeeping
requirements;
or
(
ii)
demonstrate
why
such
requirements
are
not
practicable.

In
the
latter
case,
the
State
must
adopt
appropriate
alternative
requirements
to
ensure
that
emissions
reductions
are
being
achieved
using
methods
that
quantify
those
emissions
reductions,
to
the
extent
practicable,
with
the
same
degree
of
assurance
that
reductions
are
being
quantified
for
EGUs
and
non­
EGU
boilers
and
turbines
using
part
75
monitoring.
This
is
to
ensure
that,
regardless
of
how
a
State
chooses
to
meet
the
CAIR
emissions
reduction
requirements,
all
reductions
made
by
States
to
comply
with
the
CAIR
have
the
same,
high
level
of
certainty
as
that
achieved
through
the
cap­
and­
trade
approach.
Further,
if
a
3
The
many
EPA
guidance
documents
and
tools
for
preparing
emission
inventory
estimates
for
SO2
and
NOx
are
available
at
the
following
websites:
http://
www.
epa.
gov/
ttn/
chief/
net/
general.
html,
http://
www.
epa.
gov/
ttn/
chief/
eiip/
techreport/,
http://
www.
epa.
gov/
ttn/
chief/
publications.
html#
general,
http://
www.
epa.
gov/
ttn/
chief/
software/
index.
html,
and
http://
www.
epa.
gov/
ttn/
chief/
efinformation.
html.
State
adopts
alternative
requirements
that
do
not
apply
to
all
non­
EGUs
in
a
particular
source
category
(
defined
to
include
all
sources
where
any
aspect
of
production
of
one
or
more
such
sources
is
reasonably
interchangeable
with
that
of
one
or
more
other
such
sources),
the
State
must
demonstrate
that
it
has
analyzed
the
potential
for
shifts
in
production
from
the
regulated
sources
to
unregulated
or
less
stringently
regulated
sources
in
the
same
State
as
well
as
in
other
States
and
that
the
State
is
not
including
reductions
attributable
to
sources
that
may
shift
emissions
to
such
unregulated
or
less
regulated
sources.

d.
Emissions
Inventories
and
Demonstrating
Reductions
To
quantify
emissions
reductions
attributable
to
controls
on
non­
EGUs,
the
States
must
submit
both
baseline
and
projected
control
emissions
inventories
for
the
applicable
implementation
years.
We
have
issued
many
guidance
documents
and
tools
for
preparing
such
emissions
inventories,
some
of
which
apply
to
specific
sectors
States
may
choose
to
control.
3
While
much
of
that
guidance
is
applicable
to
today's
rulemaking,
there
are
some
key
4
The
2010
modeling
date
is
relevant
for
both
SO2
and
NOx
even
though
NOx
requirements
begin
in
2009.
See
Section
IV
for
discussion.
differences
between
quantification
of
emissions
reduction
requirements
under
a
SIP
designed
to
help
achieve
attainment
with
a
NAAQS
and
emissions
reduction
requirements
under
a
SIP
designed
to
reduce
emissions
that
contribute
significantly
to
a
downwind
State's
nonattainment
problem
or
interfere
with
maintenance
in
a
downwind
State.
Because
States
are
taking
actions
as
a
result
of
their
impact
on
other
States,
and
because
the
impacted
States
have
no
authority
to
reduce
emissions
from
other
States,
the
emissions
reduction
estimates
become
even
more
important.

(
For
a
complete
discussion,
see
69
FR
32693;
June
10,
2004.)

Specifically,
when
we
review
CAIR
SIPs
for
approvability,
we
intend
to
review
closely
the
emissions
inventory
projections
for
non­
EGUs
to
evaluate
whether
emissions
reduction
estimates
are
correct.
We
intend
to
review
the
accuracy
of
baseline
historical
emissions
for
the
subject
sources,
assumptions
regarding
activity
and
emissions
growth
between
the
baseline
year
and
20104
and
2015,
and
assumptions
about
the
effectiveness
of
control
measures.

Before
describing
the
specific
steps
involved
in
this
quantification
process,
EPA
notes
that
a
few
commenters
objected
to
the
proposed
requirements
as
arbitrary
restrictions
intended
to
discourage
States'
discretion
in
imposing
control
measures
on
non­
EGUs
since
these
requirements
would
use
what
the
commenters
describe
as
extremely
conservative
emissions
baseline
and
emissions
reduction
estimates.
No
commenter
refuted
EPA's
explanation,
noted
above,
of
the
need
for
stringent
requirements
to
ensure
greater
accuracy
of
emission
inventories
and
greater
certainty
of
reduction
estimates
used
in
SIPs
addressing
transported
pollutants.
The
EPA
maintains
that
the
need
for
more
accurate
inventories
and
more
certain
reduction
estimates
justifies
the
requirements
discussed
below.
Further,
no
commenter
provided
an
alternate
method
of
addressing
EPA's
concerns
about
the
development
of
such
inventories
and
reduction
estimates.

Thus,
EPA
is
finalizing
its
proposed
approach.

i.
Historical
Baseline
To
quantify
non­
EGU
reductions,
as
the
first
step,
a
historical
baseline
must
be
established
for
emissions
of
SO2
or
NOx
from
the
non­
EGU
source(
s)
in
a
recent
year.
The
historical
baseline
inventory
should
represent
actual
emissions
from
the
sources
prior
to
the
application
of
the
controls.
We
expect
that
States
will
choose
a
representative
year
(
or
average
of
several
years)
during
2002­
2005
for
this
purpose.

The
requirements
for
estimating
the
historical
baseline
inventory
that
follow
reflect
EPA's
view
that,
when
States
assign
emissions
reductions
to
non­
EGU
sources,
achievement
of
those
reductions
should
carry
a
high
degree
of
certainty,

just
as
EGU
reductions
can
be
quantified
with
a
high
degree
of
certainty
in
accordance
with
the
applicable
part
75
monitoring
requirements.
Because
the
non­
EGU
emissions
reductions
are
estimated
by
subtracting
controlled
emissions
from
a
projected
baseline,
if
the
historical
baseline
overestimates
actual
emissions,
the
estimated
reductions
could
be
higher
than
the
actual
reductions
achieved.

For
non­
EGU
sources
that
are
subject
to
part
75
monitoring
requirements,
historical
baselines
must
be
derived
from
actual
emissions
obtained
from
part
75
monitored
data.
For
non­
EGU
sources
that
do
not
have
part
75
monitoring
data,
historical
baselines
must
be
established
that
estimate
actual
emissions
in
a
way
that
matches
or
approaches
as
closely
as
possible
the
certainty
provided
by
the
part
75
measured
data
for
EGUs.
For
these
sources,

States
must
estimate
historical
baseline
emissions
using
source­
specific
or
category­
specific
data
and
assumptions
that
ensure
a
source's
or
source
category's
actual
emissions
are
not
overestimated.

To
determine
the
baseline
for
sources
that
do
not
have
part
75
measured
data,
States
must
use
emission
factors
that
ensure
that
emissions
are
not
overestimated
(
e.
g.,
emission
factors
at
the
low
end
of
a
range
when
EPA
guidance
presents
a
range)
or
the
State
must
provide
additional
information
that
shows
with
reasonable
confidence
that
another
value
is
more
appropriate
for
estimating
actual
emissions.
Other
monitoring
or
stack
testing
data
can
be
considered,
but
care
must
be
taken
not
to
overestimate
baselines.
If
a
production
or
utilization
factor
is
part
of
the
historical
baseline
emissions
calculation,
a
factor
that
ensures
that
emissions
are
not
overestimated
must
be
used,
or
additional
data
must
be
provided.
Similarly,
if
a
control
or
rule
effectiveness
factor
enters
into
the
estimate
of
historical
baseline
emissions,
such
a
factor
must
be
realistic
and
supported
by
facts
or
analysis.
For
these
factors,
a
high
value
(
closer
to
100
percent
control
and
effectiveness)

ensures
that
emissions
are
not
overestimated.

ii.
Projections
of
2010
and
2015
Baselines
The
second
step
in
quantifying
SO2
or
NOx
emissions
reductions
for
non­
EGUs
is
to
use
the
historical
baseline
emissions
and
project
emissions
that
would
be
expected
in
2010
and
2015
without
the
CAIR.
This
step
results
in
the
2010
and
2015
baseline
emissions
estimates.

The
EPA
proposed
and
requested
comment
on
two
procedures
for
estimating
the
future
baselines:
one
relies
on
projections
based
on
a
number
of
estimated
parameters;

the
second
uses
the
lower
of
this
projection
and
actual
historical
emissions.
Today,
EPA
finalizes
the
second
approach
for
determining
2010
and
2015
emissions
baselines.

To
estimate
future
emissions,
States
must
use
state­

ofthe
art
methods
for
projecting
the
source
or
source
category's
economic
output.
Economic
and
population
forecasts
must
be
as
specific
as
possible
to
the
applicable
industry,
State,
and
county
of
the
source
and
must
be
consistent
with
both
national
projections
and
relevant
official
planning
assumptions,
including
estimates
of
population
and
vehicle
miles
traveled
developed
through
consultation
between
State
and
local
transportation
and
air
quality
agencies.
However,
if
these
official
planning
assumptions
are
themselves
inconsistent
with
official
U.
S.

Census
projections
of
population
or
with
energy
consumption
projections
contained
in
the
most
recent
Annual
Energy
Outlook
published
by
the
U.
S.
Department
of
Energy,
then
adjustments
must
be
made
to
correct
the
inconsistency,
or
the
SIP
must
demonstrate
how
the
official
planning
assumptions
are
more
accurate.
If
the
State
expects
changes
in
production
method,
materials,
fuels,
or
efficiency
to
occur
between
the
baseline
year
and
2010
or
2015,
the
State
must
account
for
these
changes
in
the
projected
2010
and
2015
baseline
emissions.
For
example,
if
a
source
has
publicly
announced
a
change
or
applied
for
a
permit
for
a
change,
it
should
be
reflected
in
the
projections.
The
projection
must
also
reflect
any
adopted
regulations
that
are
ineligible
control
measures
and
that
will
affect
source
emissions.

As
stated
above,
EPA
is
requiring
States
to
use
the
lower
of
historical
baseline
emissions
or
projected
2010
or
2015
emissions,
as
applicable,
for
a
source
category.
This
is
because
changes
in
production
method,
materials,
fuels,

or
efficiency
often
play
a
key
role
in
changes
in
emissions.

Because
of
factors
such
as
these,
emissions
can
often
stay
the
same
or
even
decrease
as
productivity
within
a
sector
increases.
These
factors
that
contribute
to
emission
decreases
can
be
very
difficult
to
quantify.

Underestimating
the
impact
of
these
types
of
factors
can
very
easily
result
in
a
projection
for
increased
emissions
within
a
sector,
when
a
correct
estimate
will
result
in
a
projection
for
decreased
emissions
within
the
sector.
A
few
commenters
opposed
this
methodology
as
arbitrary
but
failed
to
explain
why
EPA's
concerns,
as
described
above,
are
not
valid.
Commenters
also
failed
to
propose
other
methodologies
for
addressing
these
concerns.
Thus,
EPA
is
finalizing
the
use
of
this
second
methodology.

iii.
Controlled
Emissions
Estimates
for
2010
and
2015
The
third
step
is
to
develop
the
2010
and
2015
controlled
emissions
estimates
by
assuming
the
same
changes
in
economic
output
and
other
factors
listed
above
but
adding
the
effects
of
the
new
controls
adopted
for
the
purpose
of
meeting
the
CAIR.
The
controls
may
take
the
form
of
regulatory
requirements,
e.
g.,
emissions
caps,
emission
rate
limits,
technology
requirements,
or
work
practice
requirements.
The
State's
estimate
of
the
effect
of
the
control
regulations
must
be
realistic
in
light
of
the
specific
provisions
for
monitoring,
reporting,
and
enforcement
and
experience
with
similar
regulatory
approaches.

In
addition,
the
State's
analysis
must
examine
the
possibility
that
the
controls
may
cause
production
and
emissions
to
shift
to
unregulated
or
less
stringently
regulated
sources
in
the
same
State
or
another
State.
If
all
sources
of
a
source
category
(
defined
to
include
all
sources
where
any
aspect
of
production
is
reasonably
interchangeable)
within
the
State
are
regulated
with
the
same
stringency
and
compliance
assurance
provisions,
the
analysis
of
production
and
emissions
shifts
need
only
consider
the
possibility
of
shifts
to
other
States.
If
only
a
portion
of
a
source
category
within
a
State
is
regulated,

the
analysis
must
also
include
any
in­
State
shifting.
In
estimating
controlled
emissions
in
2010
and
2015,

assumptions
regarding
control
measures
that
are
not
eligible
for
CAIR
reduction
credit
must
be
the
same
as
in
the
2010
and
2015
baseline
estimates.
For
example,
a
State
may
not
take
credit
for
reductions
in
the
sulfur
content
of
nonroad
diesel
fuel
that
are
required
under
the
recent
Federal
nonroad
fuel
rule
(
69
FR
38958;
June
29,
2004).
By
including
the
effect
of
this
Federal
rule
in
both
the
baseline
and
controlled
emissions
estimates
for
2010
and
2015,
the
State
will
appropriately
exclude
this
ineligible
reduction
when
it
subtracts
the
controlled
emissions
estimates
from
the
baseline
emissions
estimates.

The
method
that
we
are
adopting
today
specifies
the
2010
and
2015
emissions
reductions
which
can
be
counted
toward
satisfying
the
CAIR.
The
method
requires
the
use
of
the
historical
baseline
or
the
baseline
emission
estimates,

whichever
is
lower.
That
is,
the
reduction
is
calculated
as
follows:
(
i)
for
2010,
the
difference
between
the
lower
of
historical
baseline
or
2010
baseline
emissions
estimates
and
the
2010
controlled
emissions
estimates,
minus
any
emissions
that
may
shift
to
other
sources
rather
than
be
eliminated;

and
(
ii)
for
2015,
the
difference
between
the
lower
of
historical
baseline
or
2015
baseline
emissions
estimates
and
the
2015
controlled
emissions
estimates,
minus
any
emissions
that
may
shift
to
other
sources
rather
than
be
eliminated.

4.
Controls
on
Non­
EGUs
Only
Although
we
stated
that
we
believe
it
is
unlikely
States
may
choose
to
control
only
non­
EGUs,
we
proposed
in
the
CAIR
SNPR
provisions
for
determining
the
specified
5
See
"
Technical
Support
Document
for
the
Clean
Air
Interstate
Rule
Notice
of
Final
Rulemaking:
Regional
and
State
SO2
and
NOx
Emissions
Budgets"
for
tables
containing
information
to
calculate
these
amounts
for
both
SO2
and
NOx.
emissions
reductions
that
must
be
obtained
if
States
pursue
this
alternative,
and
we
adopt
those
provisions
today.
The
reason
we
think
it
is
unlikely
is
based
on
States'
emissions
profiles.
Most
SO2
emissions
are
from
EGUs
and
therefore
it
is
unlikely
that
a
State
can
achieve
the
required
emissions
reductions
without
regulating
EGUs
to
some
degree.
In
addition,
SO2
emissions
reductions
from
EGUs
are
highly
cost
effective.
States
that
choose
this
path
must
ensure
that
the
amount
of
non­
EGU
reductions
is
equivalent
to
all
of
the
emissions
reductions
that
would
have
been
required
from
EGUs
had
the
State
chosen
to
assign
all
the
emissions
reductions
to
EGUs.
For
SO2
emissions,
this
amount
in
2010
would
be
50
percent
of
a
State's
title
IV
SO2
allocations
for
all
units
in
the
State
and,
for
2015,
65
percent
of
such
allocations.

For
NOx
emissions,
this
amount
would
be
the
difference
between
a
State's
EGU
budget
for
NOx
under
the
CAIR
and
its
NOx
baseline
EGU
emissions
inventory
as
projected
in
the
Integrated
Planning
Model
(
IPM)
for
2010
and
2015,

respectively.
5
In
addition,
the
same
requirements
described
elsewhere
in
this
part
of
today's
preamble
regarding
the
eligibility
of
non­
EGU
reductions,
emissions
control
and
monitoring,

emissions
inventories
and
demonstration
of
reductions,
will
apply
to
the
situation
where
a
State
chooses
to
control
only
non­
EGUs.

5.
Use
of
Banked
Allowances
and
the
Compliance
Supplement
Pool
In
the
CAIR
NPR,
EPA
stated
that
States
may
allow
EGUs
to
demonstrate
compliance
with
the
State
EGU
SO2
budget
by
using
title
IV
allowances
(
i)
that
were
banked,
or
(
ii)
that
were
obtained
in
the
current
year
from
sources
in
other
States
(
69
FR
4627).
The
EPA
adopts
this
provision
in
today's
action.
The
EPA
adopts
a
similar
provision
for
the
use
of
banked
NOx
SIP
Call
allowances
(
pre­
2009)
to
demonstrate
compliance
with
the
State
EGU
ozone
season
NOx
budget.
See
also
the
CAIR
NPR
(
69
FR
4633).
Therefore,

State
rules
may
allow
the
use
of
pre­
2010
title
IV
and
pre­

2009
NOx
SIP
Call
allowances
banked
in
the
title
IV
and
NOx
SIP
Call
trading
programs
for
compliance
in
the
CAIR.

States
participating
in
the
EPA­
administered
CAIR
trading
programs
must
allow
the
use
of
these
pre­
2010
title
IV
allowances
or
pre­
2009
NOx
SIP
Call
allowances
in
accordance
with
EPA's
model
trading
rules.

Additionally,
States
with
annual
NOx
reduction
requirements
may
use
compliance
supplement
pool
(
CSP)

allowances
as
described
in
sections
V
and
VIII.

Distribution
of
the
CSP
is
essentially
the
same
as
the
process
used
in
the
NOx
SIP
Call,
through
one
or
both
of
two
mechanisms.
States
may
distribute
CSP
allowances
on
a
tonfor
ton
basis
to
sources
that
implement
NOx
control
measures
resulting
in
reductions
in
2007
or
2008
that
are
beyond
what
is
required
by
any
applicable
State
or
Federal
emissions
limitation
(
early
reductions).
The
second
CSP
distribution
mechanism
that
a
State
can
use
is
to
issue
CSP
allowances
based
on
the
demonstration
of
a
need
for
an
extension
of
the
2009
deadline
for
implementing
emission
controls.
The
demonstration
must
show
unacceptable
risk
either
to
a
source's
own
operation
or
its
associated
industry­­
for
EGUs,

power
supply
reliability,
for
non­
EGUs
risk
comparable
to
that
described
for
the
electricity
industry.
See
also
63
FR
57356
for
further
discussion
of
these
points.

Pre­
2010
title
IV
SO2
allowances,
pre­
2009
NOx
SIP
Call
allowances
and
CAIR
annual
NOx
CSP
allowances
can
all
be
counted
toward
a
States
efforts
to
achieve
its
CAIR
reduction
obligations
regardless
of
whether
the
CAIR
trading
programs
are
used
or
not.
