Document ID: EPA-HQ-OAR-2003-0053-2359
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2006-03-17T05:00Z

RESPONSE
TO
SIGNIFICANT
PUBLIC
COMMENTS
ON
THE
PROPOSED
CLEAN
AIR
INTERSTATE
RULE
Received
in
response
to:

Rulemaking
to
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Clean
Air
Interstate
Rule):
Reconsideration
(
FR
)

Docket
Number:
EPA­
HQ­
OAR­
2003­
0053
MARCH
2006
INTRODUCTION
The
purpose
of
this
document
is
to
provide
EPA's
responses
to
public
comments
received
on
the
rule,
"
Rulemaking
to
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Clean
Air
Interstate
Rule):
Reconsideration
(
EPA­
HQ­
OAR­
2003­
0053).
A
summary
of
these
public
comments
and
EPA's
responses
follows.
TABLE
OF
CONTENTS
XVIII.
SO2
Allocations
XVIII.
A.
Independent
Power
Producers
XVIII.
B.
EPA
does
not
have
the
statutory
authority
to
base
SO2
allocations
on
title
IV
allowances
XVIII.
C.
EPA
did
not
properly
analyze
the
potential
impacts
of
its
SO2
allocation
system
on
parent/
holding
companies
XVIII.
D.
EPA
did
not
properly
analyze
the
potential
impacts
of
its
SO2
allocation
system
on
owner/
operating
companies
XVIII.
E.
EPA's
method
imposes
a
disproportionate
compliance
burden
on
"
clean"
scrubbed
units
and/
or
low­
emitting
states
as
compared
to
uncontrolled
units
and/
or
highemitting
states
XVIII.
F.
EPA
inappropriately
assumed
that
units
can
opt
into
the
Acid
Rain
Program
XVIII.
G.
Comments
on
late
notice
of
data
corrections
documents
XVIII.
H.
General
XVIII.
I.
Comments
incorporated
by
reference
XIX.
NOx
Fuel
Factors
XIX.
A.
EPA
did
not
provide
sufficient
notice
of
use
of
fuel
factor
methodology
and/
or
values
of
factors
XIX.
B.
Fuel
factor
approach
unfairly
penalizes
non­
coal
fired
units
(
gas
and
oil
units)
and/
or
benefits
coal­
fired
units
XIX.
C.
EPA
did
not
properly
analyze
regionwide
or
state­
bystate
impacts
of
using
fuel
factor
approach
(
both
preamble
and
TSD)
XIX.
D.
EPA
did
not
properly
analyze
the
potential
impacts
on
DE/
NJ
budgets
XIX.
E.
EPA
did
not
properly
analyze
the
potential
impacts
on
ozone­
season
NOx
budgets
XIX.
F.
EPA
did
not
properly
analyze
impacts
of
modeling
using
EIA
(
i.
e.,
high
gas
prices)
assumptions
XIX.
G.
General
XIX.
H.
Comments
incorporated
by
reference
XX.
PM2.5
Modeling
for
Minnesota
XX.
A.
Comments
incorporated
by
reference
XXI.
Inclusion
of
Florida
in
the
CAIR
Region
for
Ozone
XXI.
A.
Comments
incorporated
by
reference
XXII.
Impact
on
CAIR
Analyses
of
D.
C.
Circuit
Decision
in
New
York
v.
EPA
XXII.
A.
EPA
did
not
provide
sufficient
analysis
of
the
impacts
on
CAIR­
affected
sources
XXII.
B.
EPA
did
not
properly
analyze
the
potential
impacts
on
SO3/
H2SO4
emissions
XXII.
C.
EPA
did
not
properly
analyze
the
potential
impacts
on
PM
emissions
XXII.
D.
EPA
did
not
properly
analyze
the
potential
impacts
on
CO
emissions
XXII.
E.
EPA
did
not
properly
analyze
the
potential
impacts
on
boilermaker
labor
XXII.
F.
EPA
did
not
properly
analyze
the
potential
impacts
on
EPA's
highly
cost­
effective
determination
XXII.
G.
EPA
did
not
properly
estimate
costs
of
SO3/
H2SO4
mitigation
XXII.
H.
EPA
did
not
properly
analyze
the
potential
impacts
of
NSR
permitting
XXII.
I.
General
XXII.
J.
Comments
incorporated
by
reference
XXIII.
Comments
Outside
Scope
of
the
Proposal
 
CAIR
reconsideration
and
Supplemental
Reconsideration
XVIII.
A.
EPA's
allocation
system
based
on
title
IV
allowances
is
inequitable
to
new
units
and
Independent
Power
Producers
(
IPPs)

XVIII.
A.
1
Document
No.:
OAR­
2003­
0053­
2294.1
Commenter:
Doswell
Limited
Partnership
(
DLP)
Comment:
We
enumerated
our
concerns
with
the
proposed
integration
of
the
CAIR
SO2
cap
and
trade
program
with
the
title
IV
program.
Specifically,
the
two
programs
have
different
goals,
affect
different
(
though
overlapping)
geographical
areas
and
types
of
facilities,
and
require
different
levels
of
controls.
The
extensive
discussion
in
the
Supplemental
Proposal
regarding
the
approaches
to
integrating
title
IV
with
CAIR
SO2
cap
and
trade
program
demonstrates
the
(
sic)
how
convoluted
the
program
must
become
if
the
two
are
integrated.
Additionally,
for
the
reasons
expressed
in
our
comments
on
the
Supplemental
Proposal,
we
are
not
persuaded
that
the
CAIR
SO2
cap
and
trade
program
can
achieve
the
combined
goals
of
providing
a
remedy
for
EPA=
s
finding
that
>
28
States
and
the
District
of
Columbia
contribute
significantly
to
nonattainment
of
the
national
ambient
air
quality
standards
(
NAAQS)
for
fine
particles
(
PM2.5)
and/
or
8­
hour
ozone
in
downwind
States=
and
preserving
the
title
IV
program.
[[
(
2294.1,
pp.
1­
2)
]]
The
notice
for
reconsideration
re­
states
EPA=
s
belief
that
>
achieving
SO2
reductions
for
EGUs
using
the
title
IV
allowances
is
necessary
in
order
to
ensure
the
preservation
of
a
viable
title
IV
program=,
but
it
still
does
not
explain
why
it
is
important
that
the
CAIR
SO2
cap
and
trade
program
>
preserve
a
viable
title
IV
program.=
The
preamble
to
the
CAIR
supports
the
decision
to
use
the
title
IV
allocations
as
currency
in
the
CAIR
program
by
noting
that
the
unit
specific
allocations
were
established
by
Congress.
If
this
is
the
reason,
then,
it
should
also
be
noted
that,
in
the
same
title,
Congress
specified
exemptions
for
units
that
co­
generate
steam
and
electricity
as
well
as
independent
power
producers
(
IPPs)
that
had
a
power
purchase
agreement
in
place
prior
to
the
passage
of
the
Clean
Air
Act
of
1990.
[[
(
2294.1,
p.
2)
]]
The
inequity
in
the
CAIR
SO2
allowance
allocation
is
a
result
of
EPA=
s
inconsistent
adherence
to
the
specifications
set
forth
by
Congress
in
title
IV
of
the
Clean
Air
Act.
EPA
did
not
include
the
exemption
for
(
sic)
provided
for
IPPs
in
title
IV
and
modified
the
definition
of
cogenerator
in
such
a
way
as
to
include
some
units
in
CAIR
that
are
exempt
from
title
IV.[[
(
2294.1,
p.
2)
]]
We
recommend
that
EPA
decouple
the
CAIR
SO2
cap
and
trade
program
from
title
IV
and
modify
the
SO2
allowance
allocation
methodology
so
that
all
affected
units
are
considered
in
the
allocation
process.
Additionally,
the
SO2
model
rule
should
provide
the
states
with
the
same
flexibility
in
determining
unit
specific
allocations
within
their
state
that
is
provided
in
the
NOx
model
rules.
[[
(
2294.1,
p.
2)
]]

Response:
EPA
understands
that
independent
power
producing
(
IPP)
facilities
and
qualifying
facilities
(
QF),
such
as
waste
coal­
fired
units,
have
not
received
a
title
IV
SO2
allowance
allocation
because
they
have
been
exempt
from
title
IV
under
the
IPP
exemption.
Title
IV's
IPP
exemption
applies
to
units
that
had
power
purchase
agreements
with
fixed
prices
in
place
on
November
15,
1990
and
includes
units
other
than
waste
coal­
fired
facilities.
Congress
limited
this
exemption
to
only
those
units
with
power
purchase
commitments
in
effect,
thereby
acknowledging
that
once
the
unit
was
freed
from
its
power
purchase
commitment,
it
was
free
to
pass
through
compliance
costs
to
its
customers.
The
unit
may
lose
this
exemption
even
before
the
full­
term
of
the
contract
if
the
power
purchase
commitment
changes
after
November
15,
1990
in
a
way
that
allows
the
cost
of
compliance
with
the
Acid
Rain
Program
to
be
shifted
to
the
purchaser.
For
example,
expiration
or
termination
of
the
power
purchase
commitment
or
modification
so
that
the
price
is
increased
(
e.
g.,
changed
to
a
market
price)
results
in
loss
of
the
exemption.
The
purpose
of
the
exemption
is
to
protect
IPP
facilities
subject
to
contract
prices
that
were
set
before
passage
of
the
CAA
Amendments
of
1990
(
including
the
Acid
Rain
Program
in
title
IV)
and
that
did
not
allow
pass
through
of
the
costs
of
Acid
Rain
Program
compliance.
However,
EPA
believes
that
this
exemption
was
aimed
at
easing
the
transition
of
such
facilities
into
the
Acid
Rain
Program
and
that
there
is
no
basis
for
maintaining
this
exemption
for
every
subsequent
cap­
and­
trade
program.
Congress
has
further
limited
the
exemption
to
apply
to
the
Acid
Rain
Program
and
did
not
mandate
the
Agency
with
maintaining
the
exemption
in
future
programs.

Waste
coal­
fired
units
are
designed
and
operated
for
the
purpose
of
generating
electricity
for
sale.
As
a
result,
they
are
reasonably
treated
as
part
of
the
power
generation
sector,
which
comprises
the
category
of
sources
the
CAIR
and
CAIR
FIP
trading
programs
aimed
at
regulating.
For
this
reason,
EPA
modeling
for
CAIR
included
waste
coal­
fired
EGUs
as
part
of
the
power
sector,
which
was
shown
to
collectively
be
able
to
make
highly
cost­
effective
SO2
and
NOx
emission
reductions.
The
marginal
cost
of
control
and
the
average
cost
of
control,
shown
to
be
"
highly
cost­
effective,"
reflect
a
range
of
power
sector
control
costs
that
include
costs
from
sources
such
as
waste
coal­
fired
units.
Notably,
the
model
considers
where
control
will
be
least
expensive
and
that
some
units
that
will
purchase
allowances
in
the
determination
of
which
units
are
projected
to
dispatch.
EPA
modeling
shows
that
waste
coal­
fired
units
continue
to
be
dispatched
even
when
the
cost
of
complying
with
CAIR
is
part
of
the
unit's
production
costs.
Commenters
did
not
provide
any
basis
for
changing
EPA's
treatment
of
waste
coal­
fired
units
in
the
modeling
or
for
challenging
EPA's
modeling
results.

XVIII.
A.
2
Document
No.:
OAR­
2003­
0053­
2285
Commenter:
Virginia
Independent
Power
Producers
Comment:
EPA=
s
CAIR
SO2
regulations
essentially
take
away
an
exemption
that
Congress
specifically
afforded
to
IPPs
and
qualifying
facilities
(>
QFs=)
under
the
Acid
Rain
Program
in
the
1990
Clean
Air
Act
Amendments.
Since
these
plants
do
not
have
an
existing
allocation
of
Acid
Rain
Program
SO2
allowances,
they
will
unfairly
bear
the
full
brunt
of
CAIR
compliance
costs
(
i.
e.,
purchasing
allowances
to
cover
all
of
the
plant=
s
SO2
emissions
starting
in
2010)
because
they
have
no
way
of
passing
these
new
compliance
costs
onto
the
power
purchaser
under
the
fixed
price
formula
contracts
that
they
entered
prior
to
the
enactment
of
the
1990
Clean
Air
Act
Amendments.
The
statutory
exemption
from
the
SO2
reduction
requirements
of
the
Acid
Rain
Program
was
one
of
the
important
factors
that
investors
considered
when
financing
the
construction
of
these
plants.
[[
(
p.
1)
]]
.
.
.
We
request
that
EPA
grant
IPPs
and
QFs
an
exemption
from
the
CAIR
SO2
requirements
substantially
similar
to
the
IPP
and
QF
exemptions
provided
under
the
Acid
Rain
Program.
[[
(
p.
2)
]]
.
.
.
Since
EPA=
s
CAIR
model
SO2
rule
uses
the
Acid
Rain
Program
allocations
as
the
mechanism
for
achieving
further
reductions,
more
environmentally
friendly
IPPs
and
QFs
end
up
being
penalized
even
though
they
typically
emit
less
SO2
than
most
uncontrolled
older
electric
generating
stations.
[[
(
p.
2)
]]
EPA=
s
CAIR
SO2
Requirements
Are
Contrary
to
Congressional
Intent.
.
.
.
Further,
EPA
cites
the
NOx
SIP
Call
as
an
example
of
a
cap
and
trade
program
where
an
exemption
for
IPPs
and
QFs
was
not
provided.
However,
there
are
fundamental
differences
between
the
NOx
SIP
Call
and
the
Acid
Rain
Program
that
EPA
overlooks.
Under
the
NOx
SIP
Call,
the
states
determined
the
allowance
allocations
after
the
program
was
created,
and
IPPs
and
QFs
were
typically
allocated
a
fair
share
of
NOx
allowances.
Under
CAIR,
there
is
no
opportunity
for
states
to
allocate
SO2
allowances
if
they
adopt
EPA=
s
model
SO2
cap
and
trade
rule
because
EPA
has
already
allocated
all
of
the
available
Phase
I
and
Phase
II
SO2
allowances
under
the
Acid
Rain
Program.
Moreover,
many
utilities
that
received
allowance
allocations
have
been
able
to
build
up
significant
>
banks=
of
unused
SO2
allowances,
which
those
utilities
may
now
use
to
offset
CAIR
SO2
compliance
costs.
When
the
CAIR
SO2
reduction
requirements
take
effect
in
2010,
all
pre­
2010
Acid
Rain
Program
allowances
may
be
retired
on
a
one
to
one
basis
instead
of
the
CAIR
retirement
ratio
of
two
vintage
2010
to
2014
allowances
for
every
ton
of
SO2
emitted
and
a
retirement
ratio
of
2.86
vintage
2015
and
beyond
allowances
for
every
ton
on
SO2
emitted.
[[
(
p.
4)
]]
The
CAIR
SO2
Rule
Will
Impose
a
Financial
Hardship
on
IPPs
and
QFs.
.
.
.
We
believe
that
IPPs
and
QFs
will
unfairly
bear
a
disproportionate
share
of
the
costs
to
comply
with
CAIR
and
are
left
with
no
mechanism
to
recover
these
costs
through
the
existing
fixed
price
formula
PPAs.
Accordingly,
we
request
that
EPA
grant
IPPs
and
QFs
an
exemption
from
compliance
with
the
CAIR
SO2
requirements.
An
exemption
for
IPPs
and
QFs
under
CAIR
would
ensure
that
these
plants
are
not
unfairly
penalized
for
entering
into
fixed
price
power
contracts
prior
to
the
enactment
of
the
1990
Clean
Air
Act
Amendments.
[[
(
p.
6)
]]

Response:
See
response
to
comment
XVIII.
A.
1.
Inaccuracies
in
the
commenter's
assumptions
about
projected
cost
per
ton
resulted
in
an
overestimation
of
its
cost
of
compliance
estimates.
One
specific
assumption
made
by
the
commenter
is
that
the
projected
cost
per
ton
was
the
allowance
price.
As
a
result,
the
commenter
multiplied
the
projected
cost
per
ton
by
the
CAIR
SO2
programs
retirement
ratios
(
i.
e.,
2­
to­
1
in
2010
and
2.86­
to­
1
in
2015).
In
fact,
EPA
modeling
has
projected
the
cost
of
emitting
one
ton
of
SO2
under
the
CAIR
to
be
$
686/
ton
and
$
994/
ton
in
2010
and
2015,
respectively
(
2004$).
(
The
modeling,
and
resulting
cost
per
ton,
already
incorporates
the
CAIR
SO2
retirement
ratios.)

XVIII.
A.
3
Document
No.:
OAR­
2003­
0053­
2275.1
Commenter:
FPL
Group
Comment:
SO2
allowances
should
not
be
allocated
in
proportion
to
Title
IV
Acid
Rain
allowances.
(
Reconsideration
Issue
No.
1)
FPL
Group
believes
that
EPA
has
embarked
on
the
wrong
course
by
requiring
states,
as
a
condition
of
participating
in
EPA=
s
allowance
trading
program,
to
base
the
allocation
of
CAIR
SO2
allowances
on
the
allocation
of
allowances
under
the
Title
IV
Acid
Rain
program.
Title
IV
was
enacted
expressly
for
the
purpose
of
>
reduce[
ing]
(
sic)
the
adverse
effects
of
acid
depositions
through
reductions
in
annual
emissions
of
sulfur
dioxide...,
and,
in
combination
with
other
provisions
of
[
the
Clean
Air
Act],
of
nitrogen
oxides
emissions
>
42
U
S
C
'
7651(
b).
It
was
not
intended
to
address
the
localized
issues
of
NAAQS
attainment
generally
or
of
PM2.5
attainment
in
particular.
Other
than
the
happenstance
that
SO2
emissions
are
precursors
to
both
acid
rain
and
PM2.5,
there
is
no
connection
between
the
regulation
of
SO2
emissions
under
CAIR
and
under
Title
IV.
Because
EPA
is
neither
directed
nor
authorized
by
Title
IV
to
regulate
SO2
emissions
for
the
purposes
of
CAIR,
basing
the
allocation
of
SO2
allowances
on
the
allocation
under
Title
IV
would
be
justified
only
if
the
resulting
allocation
were
equitable
and
appropriate
to
the
purposes
of
CAIR.
As
discussed
below,
such
an
allocation
would
be
neither
equitable
nor
appropriate.
[[
(
2275.1,
p.
11)
]]

Basing
the
allocation
of
SO2
allowances
under
CAIR
on
the
Title
IV
allocation
is
unfair
because
it
perpetuates
a
very
stale
allocation.
For
the
most
part,
Title
IV
allowances
were
based
on
unit
data
from
1985­
87.
Those
data
are
now
20
years
old,
and
much
has
changed
in
the
interim.
Use
of
stale
allocation
data
unfairly
penalizes
fast­
growing
utilities
such
as
FPL
Group,
because
they
have
a
disproportionate
number
of
new
EGUs
that
will
not
be
allocated
allowances.
This
will
impose
substantial
costs
on
those
utilities
even
if
the
new
EGUs
are
very
efficient
and
use
advanced
pollution
controls.
[[
(
2275.1,
pp.
11­
12)
]]
Moreover,
the
use
of
stale
allocation
data
inappropriately
continues
to
reward
old,
uncontrolled
coal
units.
The
Acid
Rain
program
required
emission
reductions
both
from
EGUs
that
had
installed
SO2
controls
in
response
to
new
source
performance
requirements
and
from
older;
uncontrolled
EGUs.
Those
older
EGUs
have
been
able
for
the
past
several
years
to
reap
a
substantial
windfall
by
installing
relatively
inexpensive
pollution
controls,
creating
a
substantial
surplus
of
SO2
allowances
for
themselves
as
a
result,
and
then
selling
those
surplus
allowances
to
the
cleaner
EGUs
that
had
already
installed
pollution
controls
and
hence
have
no
inexpensive
alternatives
available
to
further
reduce
their
SO2
emissions.
While
this
windfall
perhaps
was
an
unavoidable
consequence
of
the
Congressional
mandate
in
Title
IV
to
address
acid
rain
via
across­
the­
board
SO2
reductions,
there
is
no
such
mandate
with
respect
to
the
goal
of
attaining
the
NAAQS
for
PM2.5,
which
motivates
CAIR.
Providing
that
same
windfall
under
CAIR
in
the
absence
of
any
mandate
to
do
so
would
send
entirely
the
wrong
signal:
old,
uncontrolled
EGUs
will
continue
to
be
rewarded
for
having
delayed
installation
of
their
pollution
controls
until
after
the
Title
IV
allowances
were
doled
out.
[[
(
2275.1,
pp.
12)
]]

Rather
than
tying
the
CAIR
SO2
allowances
to
the
Title
IV
allocation,
FPL
Group
recommends
that
they
be
allocated
on
the
basis
of
recent
historical
electrical
output
for
all
existing
EGUs,
with
frequent
re­
allocations
to
reflect
updated
data.
This
will
recognize
and
reward
the
construction
of
EGUs
with
more
energy­
efficient
designs,
as
well
as
operational
measures
taken
to
improve
energy
efficiency
regardless
of
design.
If
EPA
determines
instead
to
allocate
CAIR
SO2
allowances
on
the
basis
of
heat
input,
then
FPL
Group
recommends
that
it
be
done
without
using
FAFs,
for
the
reasons
discussed
above.
Finally
and
in
any
event,
there
should
not
be
a
separate
distinction
made
with
respect
to
the
type
of
coal
that
is
used.
Similar
to
the
point
made
above
about
lower
fuel
costs
for
coal
EGUs
offsetting
any
additional
CAIR
compliance
costs
for
that
type
of
unit,
high­
sulfur
coal
tends
to
be
less
expensive
than
lower
sulfur
coal
and
thus
offsets
higher
compliance
costs.
[[
(
2275.1,
p.
12)
]]

Response:
During
the
CAIR
rulemaking
process,
EPA
examined
several
allocation
methodologies
including
straight
heat
input
and
electric
output­
based
methods.
See
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A,
for
EPA's
justification
for
choosing
the
title
IV­
based
approach.
See
also
"
Corrected
Response
to
Significant
Public
Comments
on
the
Proposed
Clean
Air
Interstate
Rule"
responses
to
comments
X.
A.
12
and
X.
A.
26
and
final
CAIR
preamble,
Section
V.
In
addition,
see
Notice
of
Reconsideration
TSD
for
an
explanation
of
why
pure
heat
input
approach
is
not
advisable.
FPL's
argument
that
EGUs
that
have
installed
controls
now
reap
a
large
windfall
from
current
title
IV
SO2
allocations
dismisses
the
substantial
costs
to
these
EGUs
of
installing
those
controls.
EPA's
analysis
shows
that
old
previously
uncontrolled
EGUs
will
often
bear
greater
costs
for
CAIR
compliance
than
new
clean
EGUs
and
previously
controlled
EGUs
because
of
the
incremental
expenses
of
installing
and
operating
an
FGD.
(
See
response
to
comment
XVIII.
I.
1
and
Memo
from
Barry
Galef
and
Jason
Lee,
ICF
Consulting,
March
14,
2006
(
Docket:
EPA­
HQ­
OAR­
2003­
0053)
Finally,
it
should
be
noted
that
FPL
and
the
State
of
Florida
are
projected
to
have
windfall
allowances
under
the
CAIR
SO2
allowance
allocation
method
according
to
EPA's
analyses.
Arguments
that
FPL
or
the
State
of
Florida
are
unfairly
burdened
by
the
CAIR
SO2
allocation
methodology
are
completely
unfounded.
As
shown
in
Table
1
of
the
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A,
Florida
receives
among
the
largest
percentage
of
the
region­
wide
budget
of
allowances,
and
receives
more
allowances
with
EPA's
chosen
approach
than
with
the
two
other
approaches
most
frequently
suggested
by
commenters
in
this
Reconsideration
process,
namely
heat
input
with
fuel
factors,
and
heat
input
with
fuel
factors
and
coal
type.
As
shown
in
Appendix
B
of
the
"
CAIR
SO2
Allocation
Approach
Analysis"
Technical
Support
Document,
FPL
receives
more
allowances
with
EPA's
chosen
approach
than
with
the
two
other
approaches
most
frequently
suggested
by
commenters
in
this
Reconsideration
process,
namely
heat
input
with
fuel
factors,
and
heat
input
with
fuel
factors
and
coal
type.
FPL
is
projected
to
receive
allowances
in
excess
of
projected
emissions
under
the
CAIR
SO2
allocation
method.
It
appears
that
FPL
simply
wants
to
have
as
large
a
windfall
as
possible
and
equity
is
simply
a
pretext.

XVIII.
A.
4
Document
No.:
OAR­
2003­
0053­
2288.1
Commenter:
GE
Energy
Financial
Services
Comment:
EPA=
s
CAIR
SO2
regulations
essentially
take
away
an
exemption
that
Congress
specifically
afforded
to
IPPs
and
qualifying
facilities
(>
QFs=)
under
the
Acid
Rain
Program
in
the
1990
Clean
Air
Act
Amendments.
Since
these
plants
do
not
have
an
existing
allocation
of
Acid
Rain
Program
SO2
allowances,
they
will
unfairly
bear
the
full
brunt
of
CAIR
compliance
costs
(
i.
e.,
purchasing
allowances
to
cover
all
of
the
plant=
s
SO2
emissions
starting
in
2010)
because
they
have
no
way
of
passing
these
new
compliance
costs
onto
the
power
purchaser
under
the
fixed
price
formula
power
purchase
agreements
(>
PPAs=)
that
they
entered
into
prior
to
the
enactment
of
the
1990
Clean
Air
Act
Amendments.
The
statutory
exemption
from
the
SO2
reduction
requirements
of
the
Acid
Rain
Program
was
one
of
the
important
economic
factors
that
GE
Energy
Financial
Services
considered
when
we
provided
equity
or
term
financing
to
the
plants.
The
construction
of
these
facilities
was
financed
in
reliance
on
the
fixed
price
formula
of
the
power
contracts
and
a
key
component
of
that
analysis
was
the
understanding
that
the
Acid
Rain
Program
exemption
would
be
in
effect
for
the
life
of
the
PPA.
[[
(
2288.1,
p.
1)
]]
For
the
reasons
set
forth
below,
we
request
that
EPA
grant
IPPs
and
QFs
on
exemption
from
the
CAIR
SO2
requirements
substantially
similar
to
the
IPP
and
QF
exemptions
provided
under
the
Acid
Rain
Program.
[[
(
2288.1,
p.
2)
]].
.
.
Legislative
history
of
the
IPP
and
QF
exemptions
further
demonstrates
that
it
was
Congress=
intent
that
these
facilities
not
be
subject
to
the
Acid
Rain
Program
while
they
were
operating
under
fixed
price
formula
PPAs.
The
SO2
allocation
methodology
established
by
Congress
in
the
Acid
Rain
Program
specifically
incorporated
the
statutory
exemptions
for
IPPs
and
QFs,
and
to
choose
only
port
of
that
methodology
to
implement
further
steep
reductions
in
SO2
emissions
effectively
changes
the
scheme
crafted
by
the
Congress
for
IPPs
and
QFs
that
still
have
fixed
price
power
contracts
in
place.
[[
(
2288.1,
p.
3)
]].
.
.
GE
Energy
Financial
Services
believes
that
its
IPPs
ond
QFs
will
unfairly
bear
a
disproportionate
share
of
the
costs
to
comply
with
CAlR
and
are
left
with
no
mechanism
to
recover
these
costs
through
the
existing
fixed
price
formula
PPAs.
Accordingly,
we
request
that
EPA
grant
IPPs
and
QFs
an
exemption
from
compliance
with
the
CAIR
SO2
requirements.
An
exemption
for
IPPs
and
QFs
under
CAIR
would
ensure
that
these
plants
are
not
unfairly
penalized
for
entering
into
fixed
price
power
contracts
prior
to
the
enactment
of
the
1990
Clean
Air
Act
Amendments.
[[
(
2288.1,
p.
5)
]]

Response:
See
response
to
comment
XVIII.
A.
1
and
CAIR
FIP/
126
final
rule,
Section
VI.
E.
Inaccuracies
in
the
commenter's
assumptions
about
projected
cost
per
ton
resulted
in
an
overestimation
of
its
cost
of
compliance
estimates.
One
specific
assumption
made
by
the
commenter
is
that
the
projected
cost
per
ton
were
allowance
prices.
As
a
result,
the
commenter
multiplied
the
projected
cost
per
ton
by
the
CAIR
SO2
programs
retirement
ratios
(
i.
e.,
2­
to­
1
in
2010
and
2.86­
to­
1
in
2015).
In
fact,
EPA
modeling
has
projected
the
cost
of
emitting
one
ton
of
SO2
under
the
CAIR
to
be
$
686/
ton
and
$
994/
ton
in
2010
and
2015,
respectively
(
2004$).
(
The
modeling,
and
resulting
cost
per
ton,
already
incorporates
the
CAIR
SO2
retirement
ratios.)

XVIII.
A.
5
Document
No.:
OAR­
2003­
0053­
2287.1
Commenter:
Birchwood
Power
Partners,
L.
P.
Comment:
EPA=
s
CAIR
SO2
regulations
essentially
take
away
an
exemption
that
Congress
specifically
afforded
to
IPPs
and
qualifying
facilities
(>
QFs=)
under
the
Acid
Rain
Program
in
the
1990
Clean
Air
Act
Amendments.
Since
the
Birchwood
Power
facility
does
not
have
an
existing
allocation
of
Acid
Rain
Program
SO2
allowances,
it
will
unfairly
bear
the
full
brunt
of
CAIR
compliance
costs
(
i.
e.,
purchasing
allowances
to
cover
all
of
the
plant=
s
SO2
emissions
starting
in
2010)
because
our
PPA,
which
was
entered
into
prior
to
the
enactment
of
the
1990
Clean
Air
Act
Amendments,
does
not
generally
allow
these
types
of
environmental
compliance
costs
to
be
passed
onto
the
power
purchaser.
The
statutory
exemption
from
the
SO2
reduction
requirements
of
the
Acid
Rain
Program
was
one
of
the
important
economic
factors
that
our
investors
considered
when
they
agreed
to
finance
the
construction
of
our
plant,
and
a
key
consideration
that
subsequent
investors
have
relied
on
when
providing
financing
to
BPP.
[[
(
2287.1,
p.
1)
]]
.
We
request
that
EPA
grant
IPPs
and
QFs
an
exemption
from
the
CAIR
SO2
requirements
substantially
similar
to
the
IPP
and
QF
exemptions
provided
under
the
Acid
Rain
Program.
[[
(
2287.1,
p.
1)
]].
.
.
We
believe
that
IPPs
and
QFs
will
unfairly
hear
a
disproportionate
share
of
the
costs
to
comply
with
CAIR
and
are
left
with
no
mechanism
to
recover
these
costs
through
the
existing
fixed
price
formula
PPAs.
Accordingly,
we
request
that
EPA
grant
IPPs
and
QFs
an
exemption
from
compliance
with
the
CAIR
SO2
requirements.
An
exemption
for
IPPs
and
QFs
under
CAIR
would
ensure
that
plants
like
Birchwood
are
not
unfairly
penalized
for
entering
into
fixed
price
power
contracts
prior
to
the
enactment
of
the
1990
Clean
Air
Act
Amendments.
[[
(
2287.1,
p.
6)
]]

Response:
See
response
to
comment
XVIII.
A.
1.

XVIII.
A.
6
Document
No.:
OAR­
2003­
0053­
2273.1
Commenter:
Cogentrix
Energy,
Inc.
Comment:
Cogentrix
Energy
believes
that
EPA
should
allow
States
to
exempt
low
emitting,
highly­
efficient
coal­
fired
IPP/
QF
units
from
the
CAIR
model
SO2
trading
rules
as
long
as
they
maintain
their
Title
IV
Acid
Rain
exempt
status
or
in
the
alternative,
EPA
should
use
an
alternative
allowance
allocation
method
under
which
IPP/
QF
units
could
be
assured
of
a
fair
allocation
of
allowances.
[[
Docket
number
2273.1,
p.
1]]

Response:
See
response
to
comment
XVIII.
A.
1.

XVIII.
A.
7
Document
No.:
OAR­
2003­
0053­
2269.1
Commenter:
AES
Corporation
Comment:
In
the
preamble
to
the
CAIR
final
rule
(
May
12,
2005),
EPA
addressed
its
rationale
for
not
continuing
the
statutory
exemption
for
certain
Independent
Power
Producer
(
IPP)
facilities
that
had,
as
of
November
15,
1990,
and
still
have
a
qualifying
power
purchase
commitment.
EPA
notes,
>
The
purpose
of
the
exemption
is
to
protect
IPP
facilities
subject
to
contract
prices
that
were
set
before
passage
of
the
CAA
Amendments
of
1990
(
including
the
Acid
Rain
Program
in
title
IV)
and
that
did
not
allow
passthrough
of
the
costs
of
Acid
Rain
Program
compliance.'
However,
the
EPA
maintains
that
this
exemption
was
aimed
at
easing
the
transition
of
such
facilities
into
the
Acid
Rain
Program
and
that
there
is
no
basis
for
maintaining
this
exemption
for
every
subsequent
cap
and
trade
program.
In
addition,
this
exemption
was
not
used
in
the
NOx
SIP
Call.=
[[
Docket
number
2269.1,
pp.
1­
2]]
AES
respectfully
points
out
the
following
errors
in
EPA=
s
position:
Assuming
that
EPA
is
correct
in
its
assertion
>
that
this
exemption
was
aimed
at
easing
transition
of
such
facilities
into
the
Acid
Rain
program=,
it
is
clear
from
both
the
law
and
the
legislative
history
of
the
CAA
SO2
cap
and
trade
program
that
the
statutory
exemption
afforded
by
Congress
was
intended
to
ease
the
transition
of
exempt
facilities
into
an
SO2
cap
and
trade
program
only
after
the
existing
price
contracts
expired.
Plants
with
pre­
1990
fixed
price
contracts
that
remain
in
effect
do
not
have
the
opportunity
to
modify
their
contracts
­
prices
are
fixed
into
the
future,
until
the
date
of
expiration
of
the
contract.
Nothing
has
changed
for
those
plants
still
under
the
contracts
that
existed
before
passage
of
the
CAA
Amendments
of
1990.
AES
has
two
such
plants
within
the
CAIR
region.
AES
Beaver
Valley=
s
contract
doesn=
t
expire
until
2016,
and
AES
Warrior
Run=
s
contract
expires
in
2030.
Therefore,
for
the
duration
of
these
contracts
these
and
the
small
population
of
similar
plants
have
not
and
do
not
have
an
opportunity
to
>
transition=
into
a
new
costing
structure
which
allows
incorporation
of
new
compliance
costs.
[[
Docket
number
2269.1,
p.
2]]
At
70
Fed.
Reg.
72272
of
the
Notice
of
Reconsideration,
it
states,
>
EPA
believes
that,
for
purposes
of
evaluating
the
various
allocation
methodologies,
computing
allocations
on
a
company­
by­
company
basis
is
more
appropriate
than
comparing
allocations
on
a
unit­
by­
unit
basis.
This
is
because,
while
one
unit
could
be
allocated
fewer
allowances
under
one
methodology,
another
unit
owned
by
the
same
company
could
be
allocated
more
allowances,
which
may
offset
the
smaller
allocation
of
the
first
unit.=
[[
Docket
number
2269.1,
p.
4]]
While
this
method
of
evaluating
various
allocation
methodologies
by
comparing
company­
by­
company
allocations
may
be
appropriate
for
traditional
utilities,
it
is
grossly
inappropriate
in
evaluating
impacts
on
IPPs.
[[
Docket
number
2269.1,
p.
4]]
IPPs
finance
acquisitions
and
new
plant
development
on
an
individual,
project
by
project
basis.
Project
financing
rules
do
not
allow
for
cross­
subsidization
between
projects.
As
such,
should
one
plant
(
Plant
A)
be
allocated
more
allowances
than
it
emits,
it
cannot
transfer
its
excess
allowances
to
another
plant
(
Plant
B)
to
offset
Plant
B=
s
short
allowance
position.
The
plant
that
is
in
a
short
position
(
Plant
B)
could
purchase
needed
allowances
from
Plant
A
at
current
market
prices,
or
from
any
other
seller
of
allowances.
The
point
is
that
Plant
B
does
not
derive
any
benefit
by
another
plant
in
the
same
company
having
excess
allowances.
Each
project
has
to
financially
stand
on
its
own.
Plant
B=
s
short
allowance
position
could
place
that
plant
in
a
situation
where
it
is
no
longer
financially
viable,
regardless
of
Plant
A
having
excess
allowances.
Therefore,
the
company­
by­
company
method
used
by
EPA
to
evaluate
the
implications
of
different
allocation
methodologies
should
not
be
used
as
a
basis
for
drawing
conclusions
on
the
impact
of
alternative
allocation
mechanisms
on
the
IPP
segment
of
the
electric
power
generation
industry.
[[
Docket
number
2269.1,
p.
4]]
In
summary,
AES
respectfully
request
that
EPA
take
the
following
CAIRrelated
actions:
.
.
.1.
For
the
legal
and
equity
reason
identified
above,
revise
the
SO2
portion
of
CAIR
to
continue
the
Title
IV
SO2
exemption
that
Congress
enacted
for
IPPs
under
long­
term
contracts.
2.
Acknowledge
that
its
assumptions
used
to
evaluate
the
implication
of
alternative
allowance
allocation
methodologies
are
inappropriate
for
IPPs.
Any
conclusions
drawn
based
on
the
assumption
of
the
ability
to
transfer
allowance
between
units
within
a
company
are
erroneous
for
this
sector
of
the
electric
power
industry.
[[
Docket
number
2269.1,
p.
5]]

Response:
See
response
to
comment
XVII.
A.
1
for
explanation
of
EPA's
position
on
IPPs
and
other
units
that
without
title
IV
allocations,
and
see
the
Technical
Support
Document
"
SO2
Allocation
Approach
Analysis,"
for
explanation
of
the
appropriateness
of
company­
level
analysis.
In
addition,
contrary
the
commenter's
intimation,
EPA
modeling
shows
that
the
AES
Beaver
Valley
and
AES
Warrior
Run
plants
will
not
be
uneconomic
to
maintain
under
CAIR.

XVIII.
A.
8
Document
No.:
OAR­
2003­
0053­
2280.1
Commenter:
ARIPPA
Comment:
As
set
forth
in
more
detail
below,
ARIPPA=
s
primary
comments
under
the
Reconsideration
Notice
relate
to
this
issue
and
are
the
following:
1.
The
SO2
allowance
allocation
methodology
established
by
the
Agency
within
CAIR
for
implementation
by
states
choosing
to
participate
in
the
trading
program
(
the
>
CAIR
Allocation
Methodology=)
is
clearly
inequitable
in
its
application
to
waste
coal­
fired
EGUs
which
receive
no
allowance
allocation
under
the
Acid
Rain
Program,
and
therefore
would
receive
no
allowance
allocation
under
CAIR.
2.
Based
on
the
insignificant
aggregate
SO2
emissions
from
waste
coal­
fired
sources,
the
inability
of
such
sources
to
readily
achieve
further
SO2
emission
reductions
and
the
unique
benefits
and
circumstances
associated
with
these
sources,
the
inequities
associated
with
the
CAIR
Allocation
Methodology
could
be
remedied
by
exempting
these
waste
coal­
fired
independent
power
production
units
(>
IPPs=)
from
CAIR.
3.
In
the
alternative,
to
the
extent
that
waste
coal­
fired
EGUs
remain
subject
to
CAIR,
the
clear
inequities
in
the
CAIR
Allocation
Methodology
must
be
addressed
by
providing
an
allocation
of
SO2
allowances
to
such
sources
in
an
equitable
manner
relative
to
sources
receiving
allowances
under
the
Acid
Rain
Program.
[[
(
2280.1,
p.
4)
]]
It
is
also
significant
that,
in
enacting
the
Clean
Air
Act
Amendments
of
1990,
Congress
specifically
determined
to
exempt
certain
IPPs,
including
ARIPPA
facilities,
from
the
acid
rain
requirements
of
the
Clean
Air
Act.
The
justifications
for
the
decision
to
exempt
these
facilities
are
reflected
in
the
Congressional
Record.
First,
Congress
acknowledged
that
many
IPPs
face
unique
economic
constraints
due
to
the
effect
of
long­
term,
fixed
price
contracts.
In
light
of
these
contracts,
the
facilities
cannot
pass
on
the
cost
of
additional
environmental
compliance
measures
to
any
consumer.
In
addition,
Congress
expressly
recognized
that
these
IPPs
are
clean
and
reliable
sources
of
energy
that
should
be
encouraged
by
clean
air
legislation.
These
environmental
and
public
policy
justifications
lead
Congress
to
determine
that
these
IPP
facilities,
such
as
the
ARIPPA
facilities,
deserved
favorable
treatment
under
the
acid
rain
program
and
therefore
were
exempted
from
the
acid
rain
control
requirements.
[[
(
2280.1,
p.
7)
]]
The
CAIR
Allocation
Methodology
is
clearly
inequitable
in
its
application
to
waste
coal­
fired
EGUs,
which
receive
no
allowance
allocation
under
the
Acid
Rain
Program,
and
therefore
would
receive
no
allowance
allocation
under
CAIR.
[[
(
2280.1,
p.
7)
]]
In
publishing
its
Reconsideration
Notice,
the
Agency
expressly
requested
comment
regarding
>
the
alleged
inequities
resulting
from
the
application
of
the
SO2
allowance
allocation
methodology
that
States
choosing
to
participate
in
the
trading
program
would
use
to
allocate
SO2
allowances
to
sources.=
ARIPPA
submits
that
the
Agency=
s
CAIR
Allocation
Methodology
is
clearly
inequitable,
insofar
as
it
directly
penalizes
those
facilities
that
Congress
determined
to
exempt
from
the
acid
rain
program.
Specifically,
the
Agency
has
included
within
CAIR
waste
coal­
fired
CFB
units
operated
by
IPPs,
including
ARIPPA
members,
as
EGUs
affected
under
CAIR=
s
model
trading
rules,
notwithstanding
Congress=
exemption
of
those
sources
from
the
Acid
Rain
Program,
yet
effectively
prohibited
any
mechanism
for
allocating
allowances
to
these
sources
under
CAIR.
[[
(
2280.1,
pp.
7­
8)
]]
Congress=
decision
to
exempt
IPPs
from
the
Acid
Rain
Program
appropriately
acknowledged
the
technical
and
economic
constraints
affecting
the
ability
of
waste
coal­
fired
CFB
units
to
further
reduce
SO2
emissions.
Indeed,
the
Congressional
determination
reflected
in
Title
IV
of
the
Clean
Air
Act
Amendments
of
1990
­­
that
relevant
independent
power
production
facilities
deserve
favorable
treatment
in
the
context
of
enhanced
SO2
emission
control
standards
­­
is
equally
applicable
to
the
SO2
emission
control
program
identified
through
CAIR.
Subjecting
IPPs
to
additional
SO2
reduction
requirements
under
CAIR
is
inconsistent
with
this
determination.
[[
(
2280.1,
p.
8)
]]
Based
on
the
insignificant
aggregate
SO2
emissions
from
waste
coal­
fired
sources,
the
inability
of
such
sources
to
readily
achieve
further
SO2
emission
reductions
and
the
unique
benefits
and
circumstances
associated
with
these
sources,
the
inequities
associated
with
the
CAIR
Allocation
Methodology
could
be
remedied
by
exempting
these
waste
coal­
fired
IPPs
from
CAIR.
[[
(
2280.1,
p.
13)
]]
[[
(
See
pp.
13­
16
of
Docket
Number
2280.1
for
a
detailed
discussion
of
this
issue.)
]]
In
the
alternative,
to
the
extent
that
waste
mat­
fired
EGUs
remain
subject
to
CAIR,
the
clear
inequities
in
the
CAIR
Allocation
Methodology
must
be
addressed
by
providing
an
allocation
of
SO2
allowances
to
such
sources
in
an
equitable
manner
relative
to
sources
receiving
allowances
under
the
Acid
Rain
Program.
[[
(
2280.1,
p.
17)
]]
[[
(
See
pp.
17­
19
of
Docket
Number
2280.1
for
a
detailed
discussion
of
this
issue.)
]]
In
the
alternative,
and
at
a
minimum,
to
the
extent
that
the
Agency
nonetheless
continues
to
subject
these
clean
sources
to
CAIR,
the
Agency
must
revise
CAIR
to
ensure
that
these
sources
are
provided
an
allowance
allocation
in
a
manner
that
is
equitable
relative
to
other
sources.
[[
(
2280.1,
p.
20)
]]

Response:
See
response
to
comment
XVIII.
A.
1.

XVIII.
B.
EPA
does
not
have
the
statutory
authority
to
base
SO2
allocations
on
title
IV
allowances
XVIII.
B.
1
Document
No.:
OAR­
2003­
0053­
2281.1
Commenter:
Northern
Indiana
Public
Service
Company
(
NIPSCO)
Comment:
In
the
reconsideration
and
related
technical
support
documents,
USEPA
describes
its
additional
analysis
of
various
allocation
methodologies
that
it
performed
for
SO2
allowance
allocations.
However,
this
analysis
was
effectively
performed
within
the
scope
of
USEPA=
s
chosen
approach
to
the
CAIR
SO2
program
(
i.
e.,
staying
within
the
bounds
of
Title
IV
of
the
Clean
Air
Act
by
comparing
ratios
of
various
allocation
methodologies
to
the
Acid
Rain­
based
allocations,
as
discussed
above)
and
ignored
a
fundamental
flaw
in
USEPA=
s
approach
to
the
CAIR
SO2
trading
program.
Specifically,
USEPA
assumed
that
the
following
sentence
in
Section
403(
f)
of
the
Clean
Air
Act
(
42
U.
S.
C.
'
7651b(
f))
effectively
requires
USEPA
to
alter
the
emissions
value
of
SO2
allowances
allocated
under
Title
IV,
which
Congress
established
at
one
allowance
per
ton
of
SO2
emitted:
>
Nothing
in
this
section
relating
to
allowances
shall
be
construed
as
affecting
the
application
of,
or
compliance
with,
any
other
provision
of
this
chapter
to
an
affected
unit
or
source,
including
the
provisions
related
to
applicable
National
Ambient
Air
Quality
Standards
and
State
implementation
plans.=
USEPA
interprets
this
statement
to
mean
that
it
must,
at
all
costs,
preserve
the
Acid
Rain
Program=
s
allocation
methodology
without
regard
to
the
congressionally
determined
emissions
value
of
the
allowances.=
70
Fed.
Reg..
25161,
25295
(
May
12,
2005).
USEPA
appears
determined
to
take
an
approach
it
believes
would
preserve
the
economic
value
of
Acid
Rain
allowances
in
violation
of
the
congressionally­
mandated
emissions
value
of
the
allowances.
USEPA=
s
initial
analysis
of
the
impact
of
the
CAIR
SO2
program
indicate
that
CAIR
will
>
drive=
the
economic
value
of
SO2
allowances,
such
that
a
separate
program
would
deflate
the
economic
value
of
the
allowances.
70
Fed.
Reg..
25161,
25294.
That
is,
according
to
USEPA=
s
analysis,
allowances
issued
under
the
Acid
Rain
Program
would
effectively
lose
all
their
economic
value
because,
a
separate
CAIR
SO2
program,
rather
than
the
less
stringent
Acid
Rain
Program,
would
determine
the
economic
value
of
SO2
allowances.
[[
(
2281.1,
pp.
2­
3)
]]
While
USEPA=
s
analysis
of
the
economic
impact
of
the
CAIR
on
the
Acid
Rain
Program
may
be
correct,
it
is
irrelevant.
Congress
established
in
Title
IV
that
a
single
SO2
allowance
is
worth
one
ton
of
SO2
emissions.
By
changing
in
the
CAIR
the
emissions
value
of
an
SO2
allowance,
USEPA
is
tampering
with
a
fundamental,
statutory
provision
of
the
Acid
Rain
Program.
This
alone
should
militate
against
conflation
of
the
Acid
Rain
Program=
s
allowance
structure
with
the
reduction
requirements
of
the
CAIR,
thus
rendering
USEPA=
s
analyses
performed
during
the
reconsideration
meaningless.
[[
(
2281.1,
p.
3)
]]
USEPA=
s
analytical
approach
continues
to
ignore
the
Acid
Rain
bonus
allowance
program.
As
explained
in
our
petition
for
reconsideration,
USEPA
is
effectively
and
fundamentally
tampering
with
the
Acid
Rain
Program
when
it
ignores
the
fact
that
the
bonus
allowance
provisions
of
Title
IV
end
in
2009.
Sources
that
received
bonus
allowances
will
no
longer
receive
them
under
the
Acid
Rain
Program
commencing
in
2010,
the
same
year
in
which
the
reduced
emissions
value
of
Acid
Rain
allowances
takes
effect.
The
convergence
of
these
two
events
undermines
a
purpose
and
intent
of
the
bonus
allowance
provisions
of
the
Acid
Rain
Program.
That
purpose
and
intent
were
to
effectively
level
the
playing
field
for
sources
that
were
low
emitting
during
the
baseline
years
for
the
Acid
Rain
Program
(
thereby
reducing
the
number
of
allowances
they
would
be
allocated
because
of
their
low
baselines)
by
rewarding
such
sources
with
additional
allowances.
These
sources
were
expected
to
plan
for
the
loss
of
the
bonus
allowances.
They
were
not
expected
to
plan
for
the
loss
of
the
bonus
allowances
plus
another
50%
reduction
in
emissions
value.
Our
suggested
resolution
of
this
inequity,
which
inequity
would
not
have
resulted
had
USEPA
not
determined
that
the
Acid
Rain
Program
was
the
necessary
structure
for
the
CAIR
SO2
reductions,
was
to
issue
bonus
allowances
to
these
same
sources
in
some
form
over
a
future
period
of
time.
This
approach
would
ameliorate
the
immediate
inequities
to
lower
emitting
units.
USEPA
appears
not
to
have
addressed
this
issue
in
the
reconsideration.
[[
(
2281.1,
p.
3)
]]

Response:
EPA's
legal
authority
to
use
title
IV
allocations
under
CAIR
and
its
reasons
for
doing
so
are
discussed
in
the
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A.
See
also
70
FR
25292
for
discussion
of
confluence
of
title
IV
and
CAIR
compliance
mechanisms
and
see
response
to
comment
XVIII.
E.
5
for
discussion
of
the
bonus
allowance
program.

XVIII.
B.
2
Document
No.:
OAR­
2003­
0053­
2271.1
Commenter:
National
Mining
Association
Comment:
EPA=
s
methodology
for
allocating
SO2
allowances
as
part
of
the
CAIR
Model
Trading
Rules
is
claimed
to
be
unreasonable
and
inequitable.
However,
NMA
believes
that
methodology
is
completely
consistent
with
the
statute
and,
as
such,
should
remain
unchanged.
[[
(
2271.1,
p.
15)
]]
As
was
the
case
with
EPA=
s
need
to
set
State
NOx
budgets,
Section
110(
a)(
2)(
D)
of
the
Act
prohibits
a
state=
s
SO2
emissions
from
contributing
significantly
to
out­
of­
state
nonattainment.
The
CAIR
SO2
trading
program
achieves
the
requisite
SO2
reductions
from
each
state
by
requiring
CAIR
sources
to
retire
more
than
one
title
IV
allowance
for
each
ton
of
their
SO2
emissions
in
2010
and
thereafter.
[[
(
2271.1,
p.
15)
]]
Because
Congress
was
silent
on
what
constitutes
>
significant
contribution=
to
downwind
nonattainment,
the
Chevron
doctrine
of
statutory
construction
requires
that
EPA=
s
regulation
for
prohibiting
SO2
emissions
that
result
in
significant
contribution
must
be
a
permissible
interpretation
of
Section
110(
a)(
2)(
d).
As
noted
previously,
a
court
will
ask
whether
the
agency=
s
regulatory
provision
in
question
is
reasonable.
[[
(
2271.1,
p.
15)
]]
In
the
preamble
to
the
final
CAIR,
EPA
discussed
various
factors
which
it
had
considered
in
concluding
that
setting
state
SO2
budgets
according
to
title
IV
allowances
represents
a
reasonable
approach
to
the
mandate
of
Section
110(
a)(
2)(
D).
17
Moreover,
in
its
notice
of
reconsideration,
the
Agency
presented
results
of
additional
analyses
of
the
impacts
of
the
Model
Rule=
s
method
for
allocation
of
SO2
allowances
and
of
other,
alternative
methods
which
had
been
considered
during
the
rulemaking
process.
[[
(
2271.1,
pp.
15­
16)
]]
The
Clean
Air
Act
does
not
explain
what
>
significant
contribution=
means
in
the
context
of
Section
110(
a)(
2)(
D).
Under
such
conditions,
an
agency's
regulation
is
not
required
to
be
the
only
one
it
permissibly
could
have
adopted,
or
even
the
reading
the
court
would
have
reached.
Rather,
the
agency=
s
construction
is
acceptable
if
it
is
reasonable
in
the
context
of
the
particular
program.
[[
(
2271.1,
p.
16)
]]
NMA
believes
the
administrative
record
in
this
rulemaking
adequately
demonstrates
that
EPA=
s
chosen
methodology
for
allocating
SO2
allowances
is
a
reasonable
approach
to
eliminating
>
significant
contribution=
to
downwind
nonattainment
of
the
fine
particle
ambient
standard.
As
such,
that
method
is
fully
consistent
with
the
statutory
command
of
Section
110(
a)(
2)(
D)
and
should
not
be
changed.
[[
(
2271.1,
p.
16)
]]

Response:
EPA
appreciates
the
commenter's
support
for
CAIR
as
finalized.

XVIII.
B.
3
Document
No.:
OAR­
2003­
0053­
2282.1
Commenter:
South
Carolina
Public
Service
Authority
and
JEA
Comment:
Our
concern
relates
to
EPA=
s
use
of
the
title
IV
Acid
Rain
Program
for
implementing
title
I
reduction
obligations.
South
Carolina
Public
Service
Authority
and
JEA
believe
that
using
the
Acid
Rain
Program
as
a
basis
for
setting
the
CAIR
SO2
allowance
budgets
and
regulating
individual
EGUs
is
invalid
on
several
grounds.
First,
it
impermissibly
interferes
with
the
statutory
scheme
that
Congress
adopted
for
the
Acid
Rain
Program
under
title
IV
of
the
Clean
Air
Act,
42
U.
S.
C.
''
7561­
7561o
(
2000).
Second,
EPA=
s
approach
impermissibly
intrudes
on
the
rights
of
states
under
section
110
of
the
Clean
Air
Act
to
develop
emission
control
measures
in
their
State
Implementation
Plans.
Each
CAIR
state
has
no
real
choice
but
to
regulate
its
EGUs
to
meet
its
CAIR
budget,
and
CAIR
forces
each
state
to
use
the
Acid
Rain
Program­
based
methodology
as
a
basis
for
setting
the
emission
reduction
obligations
for
each
of
its
different
EGUs.
Furthermore,
the
Acid
Rain
Program­
based
approach
is
arbitrary
and
capricious,
contrary
to
law,
and
not
otherwise
supported
by
a
rational
basis.
While
the
Acid
Rain
Program=
s
allocation
methodology
may
have
been
acceptable
15­
20
years
ago
for
the
purposes
of
establishing
the
Acid
Rain
Program=
s
emission
reduction
requirements,
it
has
highly
inequitable
and
irrational
results
when
applied
to
the
far
more
stringent
CAIR
program.
For
example,
the
methodology:
(
1)
imposes
a
disproportionate
compliance
burden
on
coal­
fired
generators
that
installed
emission
controls
prior
to
the
Acid
Rain
Program=
s
baseline
period;
(
2)
severely
penalizes
new
units
and
independent
power
producers
(
IPPs);
and
(
3)
results
in
extremely
large
wealth
transfers
from
low­
emitting
to
high
emitting
states.
[[
docket
number
2282.1,
p.
2]]
B.
EPA
has
no
basis
for
its
assertion
that
a
non­
title
IV
allocation
approach
contravenes
Congressional
intentions
rather,
it
is
EPA=
s
own
allocation
approach
that
interferes
with
the
Clean
Air
Act.
[[
Docket
number
2282.1,
p.
19]][[
See
docket
number
2282.1,
pp19­
20
for
further
discussion
of
this
issue.]]
Response:
EPA's
legal
authority
to
use
title
IV
allocations
under
CAIR
and
its
reasons
for
doing
so
are
discussed
in
the
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A,
"
CAIR
SO2
Allocation
Approach
Analysis"
Technical
Support
Document,
and
the
original
CAIR
final
rule
preamble.

XVIII.
B.
4
Document
No.:
OAR­
2003­
0053­
2276.1
Commenter:
Duke
Energy
Comment:
In
the
reconsideration
notice,
EPA
asserted
in
effect
that
general
reasonableness
is
the
proper
test
of
the
validity
of
its
choice
of
allocation
method.
See
70
Fed.
Reg.
72272
col.
2.
It
then
listed
four
reasons
why
it
continues
to
think
its
choice
of
the
Title
IV­
based
method
is
reasonable.
EPA=
s
thinking
is
fundamentally
flawed.
It
has
failed
to
build
a
coherent
set
of
statutorilygrounded
principles
from
which
it
can
determine
what
is
and
what
is
not
>
reasonable.=
EPA
speaks
as
if
it
is
entirely
free
to
make
up
the
rules
for
allocating
state
SO2
budgets
according
to
what
it
thinks
makes
sense.
This
it
cannot
do.
EPA
itself
has
discerned
in
section
110(
a)(
2)(
D)
an
obligation
on
the
part
of
each
CAIR
state
to
be
a
>
good
neighbor=
by
controlling
its
current
sources
to
a
level
corresponding
to
the
application
of
highly
cost­
effective
controls
on
EGUs.
A
necessary
corollary
of
that
obligation
is
that
no
state
can
be
required
to
control
its
sources
to
a
more
stringent
level
that
is,
no
state
can
be
required
to
be
a
>
better=
neighbor
than
any
other
state.
The
choice
of
allocation
methodology,
therefore,
is
>
reasonable=
only
if
it
maximizes
parity
among
the
CAIR
states
in
relation
to
the
task
of
curing
the
PM2.5
nonattainment
problem.
Here,
it
is
clear
from
both
EPA=
s
and
Duke
Energy=
s
analyses
that
a
Title
IV­
based
method
fails
that
test.
In
effect
it
forces
different
states
to
control
to
different
emission
rates
(
lb/
mmBtu),
thereby
imposing
greater
costs
on
some
states,
whereas
a
properly
executed
method
based
on
more
recent
heat
input
(
with
appropriate
fuel
adjustments)
produces
a
uniform
effective
emission
rate.
[[
Docket
number
2276.1,
pp
7­
8]][[
See
docket
number
2276.1,
pp
8­
10
for
extensive
discussion
of
this
issue.]]

*
Footnote
Text:
10
Moreover,
Title
IV
was
designed
with
the
specific
intention
to
reduce
SO2
emissions
by
ten
million
tons
from
1980
levels
by
2000.
42
U.
S.
C.
§
7651(
b).
The
allowance
trading
program
is
merely
the
method
to
meet
the
goal
set
by
Congress.
Since
that
goal
has
already
been
achieved,
concerns
about
harming
the
Title
IV
market
are
unfounded.
EPA
has
elevated
the
means
above
the
end.
Nothing
in
the
CAIR
rule,
including
use
of
heat
input
to
develop
SO2
budgets,
will
cause
SO2
emissions
to
increase
above
2000
levels
 
the
actual
goal
of
Congress
in
Title
IV.
11
Also,
the
legal
fact
that
section
110
of
the
CAA
gives
states,
not
EPA,
the
job
of
allocating
SIP
control
burdens
among
in­
state
sources
highlights
the
fundamental
irrationality
of
attempting
to
commandeer
the
Title
IV
program.
If
states
have
the
ultimate
discretion
for
deciding
how
to
achieve
necessary
reductions,
there
is
no
point
in
the
attempt.
Similarly,
the
need
may
well
arise
again
someday
to
tighten
SIPs
further
at
a
regional
level.
Will
EPA
again
try
to
protect
the
Title
IV
system
when
that
happens?
EPA's
use
of
the
Title
IV
system
for
CAIR
purposes
is
quixotic.
[[
Docket
number
2276.1,
p.
9]]
12
Indeed,
although
EPA
relies
considerably
on
predictions
of
investor
behavior,
it
has
developed
not
a
shred
of
empirical
data
to
support
those
predictions.
[[
Docket
number
2276.1,
p.
10]]

Response:
EPA's
legal
authority
to
use
title
IV
allocations
under
CAIR
and
its
reasons
for
doing
so
are
discussed
in
the
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A.
In
addition,
EPA
believes
it
is
imperative
to
retain
the
national
constraints
on
SO2
emissions
that
Congress
put
in
place
in
1990.
As
EPA
discusses
in
the
preamble,
developing
new
CAIR
SO2
allowances
that
are
separate
from
title
IV
allowances
would
serve
could
jeopardize
some
of
the
environmental
and
air
quality
gains
that
have
been
made
under
title
IV.

EPA
disagrees
with
the
argument
presented
by
the
commenter
that
"
the
choice
of
allocation
methodology
.
.
.
is
>
reasonable=
only
if
it
maximizes
parity
among
the
CAIR
States
in
relation
to
the
task
of
curing
the
PM2.5
nonattainment
problem,"
and,
as
explained
in
the
preamble,
believes
that
the
commenter's
interpretation
of
section
102(
a)
of
the
Clean
Air
Act
in
support
of
this
argument
is
flawed.
Also
in
the
preamble,
EPA
discusses
its
key
considerations
in
determining
if
its
allocation
method
is
reasonable.

The
commenter
suggests
using
a
comparison
of
"
effective
emission
rates"
to
measure
an
allocation
method's
parity
among
States.
However,
while
Duke
claims
to
calculate
the
effective
emissions
rate
for
CAIR
States
under
an
allocation
approach
based
on
heat
input
adjusted
for
fuel
factors,
that
is
not
actually
what
it
calculates.
To
calculate
the
effective
emissions
rate
limit
under
CAIR,
Duke
should
have
done
so
using
pure,
unadjusted
heat
input,
rather
than
heat
input
adjusted
for
fuel
type.

The
following
calculation
illustrates
what
Duke
did,
resulting
in
what
we
refer
to
as
the
"
Duke
Rate"
below,
and
why
it
resulted
in
a
constant
across
all
States;

State
Budget
(
from
adjusted
heat
input)
=
(
Adjusted
State
Heat
Input
*
Total
Regional
Cap)
Adjusted
Regional
Heat
Input
This
value
is
then
divided
by
each
State's
Adjusted
State
Heat
Input,
to
calculate
the
"
Duke
Rate,"
as
follows.

Duke
Rate
=
(
Adjusted
State
Heat
Input
*
Total
Regional
Cap
)*
1________
Adjusted
Regional
Heat
Input
Adjusted
State
Heat
Input
As
is
shown
above,
the
"
Adjusted
State
Heat
Input"
values
in
the
numerator
and
denominator
cancel
each
other
out.
The
result
is
a
constant
value
that
is
obtained
for
every
State,
equal
to
the
Total
Regional
Cap
Divided
by
the
Adjusted
Regional
Heat
Input.

If
Duke
were
to
correct
this
mistake,
it
would
find
that
its
rate
value,
while
accurate
for
a
State
with
only
coal­
fired
generation,
would
actually
overstate
the
effective
emissions
rate
limit
for
a
State
with
only
gas­
or
oil­
fired
generation
(
or
any
combination
of
generation
other
than
exclusively
coal),
because
their
actual
heat
inputs
would
be
greater
than
the
adjusted
heat
input.
Adjusted
heat
input
for
a
State
with
only
gas
generation,
for
example,
would
be
multiplied
by
(
1/
0.009).

If
Duke
were
to
perform
the
calculation
correctly,
they
would
find
that
their
preferred
allocation
approach
would
actually
fail
their
own
test
of
equity.

XVIII.
B.
5
Document
No.:
OAR­
2003­
0053­
2269.1
Commenter:
AES
Corporation
Comment:
EPA
is
improperly
trying
to
pick
and
choose
among
the
various
provisions
of
the
Acid
Rain
Program.
First,
EPA
fails
to
provide
any
allowances
to
facilities
that
are
exempt
from
the
Acid
Rain
Program
and
justifies
using
the
Program=
s
SO2
allocation
system,
in
part,
by
noting
that
>
Congress
clearly
did
not
choose
a
policy
to
regularly
revisit
and
revise
these
allocations,
believing
that
its
allocation
methodology
for
title
IV
allowances
would
he
appropriate
for
future
time
periods.=
See
70
Fed.
Reg.
72272.
But
then,
EPA
fails
to
recognize
and
honor
the
Congressionally
enacted
exemption
from
the
requirement
to
hold
any
SO2
allowances
during
the
life
of
preexisting
fixed
price
contract.
[[
Docket
number
2269.1,
p.
2]]

Response:
EPA's
legal
authority
to
use
title
IV
allocations
under
CAIR
and
its
reasons
for
doing
so
are
discussed
in
the
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A,
"
CAIR
SO2
Allocation
Approach
Analysis"
Technical
Support
Document,
and
the
original
CAIR
final
rule
preamble.
See
also
response
to
comment
XVIII.
A.
1.

XVIII.
C.
EPA
did
not
properly
analyze
the
potential
impacts
of
its
SO2
allocation
system
on
parent
/
holding
companies
XVIII.
C.
1
Document
No.:
OAR­
2003­
0053­
2281.1
Commenter:
Northern
Indiana
Public
Service
Company
(
NIPSCO)
Comment:
USEPA=
s
conclusion
in
the
reconsideration
is
that
all
of
the
new
baselines
that
it
examined
have
effectively
the
same
result,
though
the
loci
of
the
inequities
may
change
somewhat
with
each
one.
We
believe,
for
the
reasons
discussed
below,
that
USEPA=
s
analysis
is
fundamentally
flawed
because,
although
it
examined
an
allocation
methodology
based
upon
more
recent
heat
inputs
used
for
the
CAIR
nitrogen
oxide
(>
NOx=)
programs,
the
analysis
does
not
perform
an
evaluation
based
upon
parameters
or
metrics
that
would
truly
reflect
the
equity
or
fairness
of
the
allowance
allocation.
The
analysis
focuses
on
the
reference
or
starting
point
with
the
thought
that
the
ratio
of
reduction
should
be
consistent
or
comparable
across
all
of
the
parent/
holding
companies.
This
analytical
approach
neglects
the
end
point
or
the
impact
of
the
stringency
of
the
required
reduction
and,
therefore,
does
not
address
inequity.
Rather,
this
analysis
focuses
upon
the
amount
or
ratio
of
reduction
from
a
base
level
of
emissions
achieved
to
comply
with
the
Acid
Rain
Program.
Should
the
initial
Acid
Rain
allocation
be
small
or
inequitable,
then,
in
order
to
be
equitable,
the
amount
of
further
reduction
should
not
be
as
great.
In
other
words,
if
a
source
or
company=
s
Acid
Rain
allocation
already
results
in
a
very
low
rate
of
emissions,
say
0.5
lb/
mmBtu,
then
in
every
instance
in
order
to
achieve
an
equitable
end
point,
the
resulting
ratio
should
necessarily
be
high.
For
example,
if
a
parent/
holding
company
projects
SO2
emissions,
which
are
in
compliance
with
their
SO2
allocation
for
Acid
Rain,
combined
with
a
heat
input
production
level
that
results
in
a
projected
SO2
rate
of
1.0
lb/
mmBtu
and
another
parent/
holding
company
projects
a
rate
of
0.5
lb/
mmBtu
and
both
have
their
allocations
reduced
by
CAIR
by
50%,
the
resultant
effective
emission
rates
for
each
company
would
be
0.5
lb/
mmBtu
and
0.25
lb/
mmBtu,
respectively.
The
analysis
provided
by
USEPA
in
the
reconsideration
would
consider
the
ratio
identical
and
deem
this
method
acceptable.
An
analysis
that
truly
looks
at
reasonableness
and
equity
would
compare
end
points
or
the
resultant
impact
of
the
allocation
in
terms
of
effective
emission
rate,
as
that
would
relate
better
to
the
marginal
cost
of
control
and
the
relative
financial
impact
of
the
allowance
allocation.
In
an
equitable
system,
the
end
point
of
a
fair
allowance
allocation
would
achieve
near
equivalent
levels
in
terms
of
an
effective
lb/
mmBtu
rate.
Therefore,
we
do
not
believe
that
USEPA
has
considered
or
analyzed
an
approach
that
would
prove
more
equitable
to
all
sources
affected
by
the
CAIR
SO2
program.
[[
(
2281.1,
pp.
1­
2)
]]

Response:
The
commenter
suggests
that
EPA
should
have
performed
an
analysis
looking
at
endpoints
rather
than
the
starting
point.
EPA
has
in
fact
performed
both
a
starting
point
analysis
and
an
endpoint
analysis
of
alternative
allocation
approaches.
See
response
to
comment
XVIII.
E.
5
and
Technical
Support
Document
"
SO2
Allocation
Approaches
Analysis,"
which
can
be
found
in
the
CAIR
docket
(
EPA­
OAR­
2003­
0053).

XVIII.
C.
2
Document
No.:
OAR­
2003­
0053­
2276.1
Commenter:
Duke
Energy
Comment:
In
the
recent
reconsideration
notice,
EPA
proposed
to
retain
the
current
state­
by­
state
SO2
budgets
for
two
sets
of
reasons
­
first,
the
core
rationalizations
it
asserted
previously
in
taking
final
action
and,
second,
certain
supplemental
analyses
it
performed
as
part
of
the
reconsideration
process.
According
to
EPA,
those
supplemental
analyses
show
that
the
choice
of
allocation
method
makes
no
significant
difference
and,
hence,
that
its
choice
of
the
Title
IVbased
method
is
reasonable,
>[
g]
iven
the
over­
riding
policy
decision
to
maintain
the
title
IV
SO2
trading
program=.
In
other
words,
EPA
concluded
that
its
decision
to
allocate
SO2
budgets
to
states
and
affected
sources
in
proportion
to
their
Title
IV
allowances
was
rational
because,
in
its
opinion,
it
does
not
harm
owners
of
electric
generating
units
(>
EGUs=)
significantly,
while
preserving
the
gains
of
the
Title
IV
cap­
and­
trade
program.
[[
Docket
number
2276.1,
pp.
1­
2]]
Duke
Energy
strongly
disagrees
­
at
several
levels.
First,
the
choice
of
allocation
method
in
fact
does
make
a
significant
difference,
as
revealed
by
an
examination
of
EPA=
s
supplemental
analyses
and
by
two
additional
analyses
that
Duke
Energy
has
performed
on
its
own.
Second,
given
that
the
choice
of
allocation
method
does
matter,
it
is
clear
that
EPA=
s
analysis
is
incomplete,
because
EPA
has
failed
to
take
the
critical
next
step
of
examining
which
method
is
the
better
one.
Duke
Energy=
s
two
additional
analyses
demonstrate
that
a
heat
input
method,
specifically
EPA
Method
4,
as
opposed
to
the
Title
IV­
based
method,
is
clearly
the
better
one.
Finally,
as
discussed
below,
EPA=
s
prior
rationalizations
lack
merit.
[[
Docket
number
2276.1,
p.
2]]
As
a
threshold
matter,
we
first
address
below
EPA=
s
erroneous
claim
that
the
choice
of
allocation
makes
no
significant
difference,
making
the
following
points:
First,
the
Agency=
s
supplemental
analyses
do
reveal,
contrary
to
the
Agency=
s
claims,
a
real
difference
for
companies
and
states
in
the
impact
of
the
different
allocation
methods.
Second,
and
more
importantly,
the
analyses
contain
a
serious
design
flaw.
When
that
flaw
is
corrected,
the
analyses
reveal
even
more
disparity
between
methods,
providing
strong
evidence
that
the
choice
of
method
indeed
does
make
a
significant
difference.
Third,
that
disparity
­
and
the
reality
of
substantial
cost
consequences
for
Duke
Energy
and
others
­
is
even
more
apparent
from
two
additional
analyses
performed
by
the
company
and
described
below.
[[
Docket
number
2276.1,
p.
2]]
Duke
Energy
urges
EPA
to
abandon
its
current
approach
and
instead
to
base
the
state­
bystate
SO2
budget
allocations
on
the
most
recently
available
heat
input
values
(
adjusted
by
fuel
type),
as
it
has
done
for
other
federal
cap­
and­
trade
programs,
most
particularly
the
NOx
portion
of
CAIR
and
the
Clean
Air
Mercury
Rule
(
CAMR)."
[[
Docket
number
2276.1,
p.
2]].
.
.
EPA=
s
supplemental
analyses
as
they
stand
and
as
corrected
do
not
support
EPA=
s
position
that
the
choice
of
methodology
is
inconsequential.
Actually,
they
show
that
the
choice
makes
a
significant
difference,
and
specifically
that
the
choice
of
the
Title
IV
method
is
inequitable.
EPA=
s
original
rationalizations
for
the
Title
IV
choice
are
similarly
inadequate.
EPA
should
abandon
the
current
approach,
and
re­
do
the
SO2
allocations
according
to
the
most
recently
available
heat
input
values
(
with
adjustments
for
fuel
type),
establishing
a
system
of
CAIR
(
not
Title
IV)
allowances.
In
that
system,
EPA
would
be
free
to
give
credit
for
early
reductions
by
permitting
the
trade­
in
of
pre­
2010
Title
IV
SO2
allowances
for
the
new
CAIR
SO2
allowances
at
a
one­
to­
one
ratio,
and
Duke
Energy
would
support
such
an
approach.
[[
Docket
number
2276.1,
p.
10]]

*
Footnote
text:
3
EPA
also
should
have
examined
which
of
the
methods
provide
greater
equity
among
CAIR
states,
focusing,
for
instance,
as
Duke
Energy
has
done
here,
on
the
state­
by­
state
effective
emission
rates
that
result
from
different
methods.
5
The
SO2
TSD
for
the
reconsideration
package
refers
to
a
state­
by­
state
analysis
of
several
alternative
methods
of
allocating
state
SO2
budgets
that
EPA
performed
and
presented
in
its
CAIR
Response­
to­
Comments
(
RTC,
Section
X.
A.
26).
All
that
was
presented
in
the
RTC
was
state­
by­
state
budget
percentages
under
each
method
analyzed.
Such
a
comparison
is
of
no
greater
value
in
identifying
the
best
allocation
method
than
the
analyses
EPA
performed
for
its
reconsideration.
What
the
RTC
analysis
and
now
the
supplemental
analyses
should
have
signaled
to
EPA
was
that
more
analysis
was
required.
Instead,
EPA
chose
not
to
examine
the
issue
more
deeply.
7
Another
reason
why
EPA
should
have
focused
only
on
states
is
that
section
110
of
the
CAA
places
exclusively
on
each
state
the
responsibility
for
allocating
control
burdens
among
in­
state
sources.
This
means
that
the
sort
of
analyses
EPA
performed
for
the
reconsideration
are
inherently
speculative,
because
they
presume
that
states
will
assign
control
burdens
to
sources
in
particular
ways,
when
in
fact
states
are
free
to
choose
to
assign
them
in
different
ways.
Moreover,
the
focus
on
parent
and
operating
companies
is
dubious.
First,
it
has
the
potential
to
mask
the
degree
of
state­
by­
state
variation,
because
many
companies
operate
across
many
CAIR
and
non­
CAIR
states.
Second,
in
this
deregulatory
environment,
the
shifts
of
corporate
structure
and
asset
ownership
are
so
fluid
and
frequent
as
to
undermine
quickly
the
reliability
of
any
database.
For
instance,
in
its
reconsideration
analyses,
EPA
attributed
to
Duke
Energy
Title
IV
SO2
allowances
which
it
does
not
have.
In
the
case
of
the
allowances
in
question,
Duke
Energy
did
purchase
certain
EGUs
but
the
seller
retained
most
or
all
of
the
allowances.
[[
Docket
number
2276.1,
pp
3­
5]]
13
In
thus
applying
the
heat­
input
approach,
EPA
should
consider
excluding
natural
gas­
fired
units,
given
their
trivial
SO2
emissions.
[[
Docket
number
2276.1,
p.
10]]

Response:
In
its
comment,
Duke
Energy
mischaracterizes
EPA's
position,
stating
that
EPA
argues
that
"
the
choice
of
allocation
method
makes
no
significant
difference."
The
Agency
acknowledges
that
there
are
differences
between
the
allocation
methods,
particularly
in
the
distribution
of
"
winners"
and
"
losers."
While
North
Carolina
and
South
Carolina
may
be
better
off
in
terms
of
equity
under
Duke
Energy's
suggested
allocation
method,
other
states,
Michigan
and
Georgia
for
example,
are
significantly
worse
off
under
the
same
method.
As
discussed
in
the
response
to
comment
XVIII.
B.
4,
Duke
Energy
did
not
correctly
perform
the
calculation
it
suggests
as
a
measure
of
equity.
EPA
has
subsequently
performed
several
analyses
of
equity,
both
on
a
company
level
and
a
state
level
(
see
"
SO2
Allowance
Allocation
Methodology
Comparative
Analysis
Data
Files"
and
"
SO2
State
Budget
Analysis,"
which
can
be
found
in
the
CAIR
docket
EPA­
OAR­
2003­
0053).
It
is
the
Agency's
view
that
these
analyses
show
the
final
CAIR
SO2
allocation
method
to
be
reasonable.
Finally,
Duke's
suggestion
that
EPA
allocate
new
CAIR
SO2
allowances
and
allow
sources
to
trade
in
pre­
2010
title
IV
allowances
for
CAIR
allowances
would
not
address
the
impact
of
excess
post­
2010
title
IV
allowances
and
the
significant
emissions
increases
that
would
result
in
non­
CAIR
States
from
these
allowances
being
unusable
in
the
CAIR
region.
Additionally,
EPA
will
not
exclude
natural
gas­
fired
units
chiefly
because
of
their
inclusion
in
the
title
IV
program.
In
addition,
many
natural
gas­
fired
units
fire
or
can
fire
oil,
which
results
in
SO2
emissions.

With
regard
to
Duke
Energy's
claim
of
"
substantial
cost
consequences"
of
different
allocations
approaches,
EPA
would
like
to
note
that
the
disparity
between
EPA's
chosen
approach
and
Duke
Energy's
preferred
approach
amounts
to
only
about
0.03
percent
of
the
company's
2005
revenue,
assuming
the
company
would
have
to
purchase
allowances
for
all
of
its
emissions
.

The
EPA
analysis
Duke
Energy
criticizes
in
its
comment
uses
the
best
available
information
on
ownership
issues,
and,
given
the
complex
multiple­
owner
issues
involved
with
performing
such
an
analysis,
serves
as
only
a
rough
approximation
of
that
relationship,
and
not
a
definitive
statement
of
exactly
how
many
allowances
are
related
to
specific
companies.
For
instance,
as
of
now,
Reliant
gets
listed
as
owning
all
25,000+
allowances
for
Conemaugh
even
though
multiple
companies
own
a
share
of
that
plant.
EPA
believes
its
assumptions
to
be
acceptable
because
the
purpose
of
this
analysis
is
to
see
if
any
other
allocation
methodology
seems
more
"
fair"
in
a
directional
sense,
not
as
applied
to
any
single
entity.
EPA
does
not
claim
to
know
what
allowance
arrangements
apply
for
any
unit
for
an
individual
company
where
there
have
been
ownership
changes
or
where
there
are
multiple
owners.
For
a
more
detailed
description
of
data
and
analytical
methods
used,
see
Memo
from
David
Sellers,
Perrin
Quarles
Associates,
March
2006
(
Docket:
EPA­
HQ­
OAR­
2003­
0053).
A
quick
review
of
Duke
plants
shows
that
the
historical
Duke
Energy
Corporation
plants
account
for
over
70,000
allowances
under
EPA
approach
and
the
pure
heat
input
approach;
the
units
owned
by
other
subsidiaries
outside
the
North
Carolina/
South
Carolina
region
account
for
only
about
3,500
allowances
(
or
5%
of
Duke's
total),
using
Option
3.
EPA
has
performed
further
state
analysis,
"
SO2
State
Budget
Analysis,"
which
can
be
found
in
the
CAIR
docket
EPA­
OAR­
2003­
0053.

XVIII.
C.
3
Document
No.:
OAR­
2003­
0053­
2282.1
Commenter:
South
Carolina
Public
Service
Authority
and
JEA
Comment:
South
Carolina
Public
Service
Authority
and
JEA
are
disappointed
to
find
that
EPA
proposes
in
the
Notice
of
Reconsideration
to
finalize
its
Acid
Rain
Program­
based
approach
­
and,
moreover,
that
the
Agency
proposes
to
finalize
it
on
the
basis
of
a
highly
inadequate
analysis.
Far
from
supplying
a
rational
basis
for
the
CAIR
SO2
allowance
allocation
methodology,
the
Notice
of
Reconsideration
underscores
its
arbitrariness
and,
if
anything,
raises
a
host
of
new
questions.
As
explained
below:­­
South
Carolina
Public
Service
Authority
and
JEA
believe
EPA
has
used
the
correct
criteria
and
analytical
approach
for
assessing
the
reasonableness
of
the
CAIR
NOx
allocation
method
relative
to
an
alternative
method.
These
criteria
are:
(
1)
whether
the
allocation
method
avoids
penalizing
coal­
fired
generation
units
that
already
have
installed
emission
controls;
and
(
2)
whether,
relative
to
alternatives,
it
better
minimizes
for
each
state
the
disparity
between
allowances
provided
and
projected
emissions.
Yet,
EPA
fails
to
apply
the
same
criteria
and
analytical
approach
to
its
comparative
assessment
of
SO2
allowance
allocation
methods.­­
If
EPA
were
to
apply
the
NOx
criteria
and
approach
noted
above
to
the
SO2
allocation
options,
this
analysis
­
as
highlighted
below
­
would
show
that
the
Acid
Rain
Program­
based
method
is
much
inferior
to
a
method
that
uses
recent
heat
input
data
adjusted
by
fuel
type.
This
is
reflected
by
the
fact
that
the
Acid
Rain
Program­
based
method
has
a
higher
allowances­
to
emissions
disparity
than
the
latter
method.­­
Moreover,
EPA=
s
presentation
of
its
findings
is
grossly
misleading.
The
Agency
maintains
that
its
analyses
show
that
the
Acid
Rain
Program
based
method
is
>
very
similar=
to
the
alternatives,
but
its
numbers
mask
potentially
enormous
differences.­­
Furthermore,
if
EPA=
s
SO2
results
show
anything,
it
is
that
the
Acid
Rain
Program­
based
allocation
method
consistently
scores
below
the
alternatives
on
even
the
Agency=
s
own
measures
of
reasonableness.
In
particular,
EPA's
results
consistently
show
that
the
disparity
between
allowances
provided
and
projected
emissions
is
greater
under
the
Acid
Rain
Program­
based
approach
than
under
alternatives.­­
In
addition,
a
critical
omission
from
EPA=
s
analysis
is
an
evaluation
of
whether
use
of
the
Acid
Rain
Program­
based
method
would
result
in
inflation
of
the
CAIR
SO2
emissions
cap.­­
Finally,
EPA=
s
case
for
the
Acid
Rain
Program
based
approach
appears
to
rest
primarily
on
arguments
that
statutory
constraints
and
other
policy
interests
compel
that
approach,
but
each
of
EPA=
s
arguments
is
fundamentally
flawed.
[
Docket
number
2282.1,
pp
3­
4]]
III.
Applying
the
criteria
and
method
of
analysis
EPA
used
for
the
state
NOx
budgets
to
the
SO2
allowance
allocation
methodologies
shows
that
the
Acid
Rain
Program­
based
method
is
inferior
to
the
an
approach
based
on
recent
heat
input
data
adjusted
for
fuel
type.
[[
Docket
number
2282.1,
p.
6]][[
See
docket
number
2282.1,
p.
7
for
Comparison
Table.
Also
see
pp.
6­
9
for
extensive
discussion
of
this
issue.]]
IV.
EPA=
s
Flawed
Analysis
in
the
Notice
of
Reconsideration.
.
.
EPA=
s
Notice
of
Reconsideration
omits
an
appropriate
state­
by­
state
analysis
of
the
relative
performance
of
the
SO2
allowance
allocation
methodologies
in
minimizing
the
disparity
between
allowances
provided
to
each
state
and
projected
state
emissions.
Instead,
it
includes
results
from
other
types
of
analyses,
but
these
analyses
fail
to
provide
evidence
to
support
the
reasonableness
of
the
Acid
Rain
Program­
based
method.
A.
EPA=
s
state­
by­
state
analysis
fails
to
provide
any
meaningful
information
to
establish
the
reasonableness
of
that
methodology.
[[
Docket
number
2282.1,
p.
9]]
See
docket
number
2282.1,
pp.
9­
10
for
discussion
of
this
issue.]]

B.
EPA=
s
company­
by­
company
analyses
fail
to
demonstrate
that
the
Acid
Rain
Program­
based
method
generates
an
allowances­
to­
emissions
ratio
that
is
comparable
to
that
generated
by
alternative
methods.
[[
Docket
number
2282.1,
p.
10]][[
See
docket
number
2282.1,
pp.
10­
14
for
extensive
discussion
of
this
issue.

These
analyses
have
certain
fundamental
flaws
that
prevent
them
from
establishing
the
reasonableness
of
EPA's
Acid
Rain
Program­
based
method
of
allowance
allocation.
First,
this
company­
by­
company
analysis
fails
to
provide
information
needed
about
how
states
fare
under
the
different
approaches.
It
is
states
 
not
companies
 
that
face
direct
compliance
obligations
of
achieving
their
applicable
emissions
budgets
established
under
the
CAIR.
Second,
a
state
does
not
have
the
authority
to
force
an
EGU
within
its
borders
to
acquire
and
surrender
Acid
Rain
allowances
from
an
EGU
in
another
state.
And
third,
the
economic
impacts
of
different
allocation
schemes
cannot
be
so
easily
shifted
even
in
the
case
of
a
parent
company
that
may
own
different
utility
systems
in
different
states.
A
state
public
utility
commission,
for
example,
will
not
allow
the
transfer
of
allowances
from
a
subsidiary
company
in
one
state
to
a
second
subsidiary
company
in
another
state
unless
the
second
company
pays
fair
market
value
price
for
the
transferred
allowances.
Thus,
the
averaging
of
the
economic
impacts
across
a
multi­
state
utility
system
is
not
an
accurate
or
realistic
way
to
measure
the
relative
allowances­
to
emissions
disparity
of
various
allocation
options.
Rather,
the
appropriate
frame
of
reference
is
individual
states,
not
large,
multi­
state
power
companies.

Even
so,
South
Carolina
Public
Service
Authority
and
JEA
urge
EPA
to
take
notice
of
the
fact
that
in
each
of
these
six
analyses,
EPA's
approach
has
the
lowest
ratio
of
allowances
allocated
to
projected
emissions
 
or,
in
other
words,
the
highest
disparity
between
allowances
and
emissions
 
of
the
four
methods
analyzed.
It
thus
fails
on
the
criterion
that
EPA
itself
said
was
a
matter
of
"
public
interest."
Moreover,
in
each
of
these
analyses,
the
"
heat
input
with
fuel
factors"
method
 
the
SO2
analogue
of
the
same
method
EPA
selected
and
defended
for
the
NOx
emission
budgets
 
has
the
highest
or
second
highest
ratio
of
allowances
allocated
to
projected
emissions
(
and
therefore
the
lowest
or
second
lowest
disparity
between
allowances
and
emissions).
In
this
regard,
EPA's
own
analysis
corresponds
to
the
findings
of
the
South
Carolina
Public
Service
Authority
and
JEA
analysis
 
namely,
that
the
"
heat
input
with
fuel
factors"
method
is
superior
to
the
Acid
Rain
Program­
based
method.

Nevertheless,
EPA
insists
that
its
approach
is
"
reasonable."
EPA's
basis
for
this
claim
is
that
the
median
ratio
of
allowances
allocated
to
projected
emissions
under
EPA's
preferred
method
is
"
very
similar"
to
that
for
the
alternate
methods26
 
by
which
EPA
apparently
means
that
the
Acid
Rain
Program­
based
method
is
only
a
little
worse
than
the
other
methods.
EPA
seems
to
base
this
claim
of
rough
equivalency
on
the
fact
that
the
median
ratios
in
the
various
analyses
are
generally
within
0.1
or
0.2
of
one
another.

However,
by
presenting
its
results
in
this
way,
it
is
difficult
to
say
whether
the
Acid
Rain
Program­
based
method
is
only
a
little
worse
than
the
other
alternative
methods
 
or
whether
it
is,
in
fact,
a
lot
worse.
The
problem
is
that
EPA's
chosen
metric
obscures
potentially
enormous
differences.
Take,
for
example,
the
analysis
under
which
the
Acid
Rain
Program­
based
method
results
in
an
allowances­
to­
emissions
ratio
`
most
similar'
to
that
of
the
other
three
methods.
This
is
Table
2,
which
shows
a
ratio
of
0.5
for
the
Acid
Rain
Program­
based
method
and
a
ratio
of
0.6
for
each
of
the
other
three
alternate
methods.
Assuming
this
simply
reflects
a
difference
0.1
in
the
ratio
values,
then
it
also
means
that
that
median
company
would
have
20%
more
allowances
at
its
disposal
under
any
of
the
alternate
methods.
Viewed
in
this
light,
EPA's
own
data
suggests
that
its
Acid
Rain­
based
method
is
much
worse
than
the
"
heat
input
with
fuel
factors"
approach.
Furthermore,
this
interpretation
of
EPA's
data
does
not
even
take
into
account
what
may
be
obscured
by
EPA's
rather
blunt
rounding
convention.
For
example,
it
could
be
that,
under
the
Table
2
analysis,
the
median
ratio
under
the
EPA
method
is
actually
0.46
(
rounded
to
0.5)
and
the
median
ratio
under
an
alternative
method
is
actually
0.64
(
rounded
0.6),
in
which
case
the
median
company
could
have
approximately
39%
more
allowances
under
any
of
the
alternate
methods.
Accordingly,
even
on
EPA's
own
terms,
its
Acid
Rain
Program­
based
allocation
method
substantially
underperforms
the
alternate
methods,
including
the
"
heat
input
with
fuel
factors"
method.

C.
The
>
select
high­
emitting
companies=
analysis
does
not
provide
evidence
to
support
EPA=
s
reasonableness
claims.
[[
Docket
number
2282.1,
p.
14]][[
See
docket
number
2282.1,
pp14­
16
for
discussion
of
this
issue.]]

In
addition
to
the
median
parent
company
analyses
and
median
owner/
operator
level
analyses,
the
Technical
Support
Document
includes
a
table
showing
allowance­
to
emissions
ratios
for
a
group
of
"
select
high­
emitting
companies."
27
This
Table
3
lists
15.
parent
companies.
For
each
company,
EPA
provides
the
resulting
ratio
of
allowances
allocated
to
projected
emissions
under
each
allocation
method
 
first
for
the
2015
CAIR
Control
Scenario
and
then
for
the
2015
Base
Case
Scenario.
EPA
asserts
that
results
show
that:
"
While
the
allocations
vary
from
company
to
company
under
the
four
methodologies,
overall,
the
distributions
of
allowances
that
companies
received
relative
to
their
project
emissions
for
the
CAIR
control
case
are
very
similar."
Again,
as
explained
above,
this
analysis
is
flawed
because
states
not
companies
are
the
appropriate
frame
of
analysis
on
this
issue.
Yet,
even
so,
what
stands
out
about
the
findings
in
Table
3
are
that
they
show
that
a
majority
of
the
companies
still
fare
better
with
the
"
heat
input
with
fuel
factors"
method
than
the
Acid
Rain
Program­
based
approach
 
even
though
the
latter
method
allows
for
substantial
importation
of
non­
CAIR
title
IV
allowances.
Thus,
even
this
analysis
shows
that
the
Acid
Rain
Program­
based
method
generally
under­
performs
the
"
heat
input
with
fuel
factors"
method.

Furthermore,
if
the
results
presented
for
South
Carolina
Public
Service
Authority
are
any
guide,
many
companies
fare
far
worse
under
EPA's
method
than
under
other
methods.
For
example,
under
the
2015
CAIR
Control
Scenario,
the
ratio
for
South
Carolina
Public
Service
Authority
under
the
Acid
Rain
Program­
based
method
is
0.44,
while
the
ratio
for
the
company
under
the
"
heat
input
with
fuel
factors"
method
is
0.58.
This
ratio
difference
represents
a
gain
of
4830
allowances
(+
32%)
over
the
EPA
method.
According
to
EPA's
data,
additional
allowances
of
this
amount
would
have
a
value
of
nearly
$
6
million
per
year
for
2015
and
every
year
thereafter.
To
say
the
least,
South
Carolina
Public
Service
Authority
does
not
view
the
results
generated
under
these
two
allocation
methods
as
"
very
similar."

V..
.
.
EPA=
s
own
analysis
not
only
fails
to
demonstrate
that
its
Acid
Rain
Program­
based
allocation
method
is
superior
to
the
alternatives,
it
suggests
that
its
allocation
method
is
significantly
inferior.
Apparently,
the
Agency=
s
fall­
back
argument
for
the
reasonableness
of
its
preferred
approach
is
its
>
over­
riding
policy
decision
to
maintain
the
title
IV
SO2
trading
program.=
In
particular,
EPA
makes
three
assertions:
(
1)
that
>
achieving
SO2
reductions
for
EGUs
using
the
title
IV
allowances
is
necessary
in
order
to
ensure
the
preservation
of
a
viable
title
IV
program;=
(
2)
that
>
Congress
clearly
did
not
choose
a
policy
to
regularly
revise
and
revisit
[
the
title
IV]
allocations,
believing
that
its
allocations
methodology
for
title
IV
allowances
would
be
appropriate
for
future
time
periods;=
and
(
3)
that
>
title
IV
allowance
allocations
provide
a
logical
and
well
understood
starting
point
from
which
additional
EGU
SO2
emissions.=
For
the
reasons
provided
below,
these
arguments
are
fundamentally
flawed
[[
Docket
number
2282.1,
p.
17]][[
See
docket
number
2282.1,
pp.
18­
22
for
>
reasons.=]]
A.
EPA
has
failed
to
demonstrate
that
using
an
alternate
allocation
method
jeopardizes
the
environmental
purpose
of
the
Acid
Rain
Program.
Notwithstanding
its
assertions,
EPA
has
failed
to
demonstrate
that
using
an
allocation
method
would
put
the
environmental
viability
and
environmental
purposes
of
the
Acid
Rain
Program
at
risk.
As
discussed
above,
EPA
explains
in
the
CAIR
that
its
analysis
shows
that
the
use
of
a
non­
title
IV
approach
would
result
in
an
increase
of
260,000
tons
of
SO2
in
the
non­
CAIR
region
in
2010.
[[
Docket
number
2282.1
p.
18]][[
See
docket
number
2282.1,
p.
18
for
further
discussion
of
this
issue.]]
C.
EPA=
s
analysis
for
the
Notice
of
Reconsideration
belies
the
argument
that
the
Acid
Rain
Program
provides
a
>
logical
starting
point=
for
the
CAIR
SO2
trading
program.
[[
Docket
number
2282.1,
p.
20]][[
See
docket
number
2282.1,
pp.
20­
21
for
further
discussion
of
this
issue.]]
VI..
.
.
South
Carolina
Public
Service
Authority
and
JEA
believe
EPA=
s
analysis
of
the
SO2
allowance
allocation
methods
for
the
Notice
of
Reconsideration
fails
to
establish
the
reasonableness
of
EPA=
s
Acid
Rain
Program­
based
method.
The
companies
urge
the
Agency
to
give
fuller
consideration
of
alternatives,
including
a
method
based
on
recent
heat
input
data
and
adjusted
for
fuel
type.
Our
companies
stand
ready
to
assist
the
Agency
in
developing
different
approaches
that
achieve
the
regional
emission
limits
established
in
the
CAIR
program
but
that
are
lawful
and
more
equitable.
[[
Docket
number
2282.1,
p.
21]]

Response:
EPA's
legal
authority
to
use
title
IV
allocations
under
CAIR
and
its
reasons
for
doing
so
are
discussed
in
the
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A.
See
also
response
to
comment
XVIII.
C.
2.
With
regard
to
the
commenter's
point
that
EPA
omitted
an
evaluation
of
whether
use
of
the
Acid
Rain
Program­
based
method
would
result
in
inflation
of
the
CAIR
SO2
emissions
cap,
see
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A.,
"
Potential
for
Regional
Emissions
Increases."

EPA
disagrees
with
a
number
of
points
made
by
the
commenter
regarding
the
environmental
impact
of
using
non­
title
IV
allocations
for
SO2.
First,
EPA
believes
that
the
nationwide
control
of
SO2
emissions
is
an
important
part
of
the
overall
environmental
goal
of
title
IV.
As
EPA
has
demonstrated,
the
use
of
non­
title
IV
allocations
would
result
in
260,000
tons
of
additional
SO2
emissions
in
annually,
starting
in
2010.
As
is
discussed
in
the
preamble,
this
represents
about
a
30%
increase
in
projected
non­
CAIR
region
emissions
in
2010.
Further,
the
commenter's
argument
that
EPA
could
use
title
I
provisions
to
address
negative
environmental
impacts
created
by
using
non­
title
IV
allowances
under
CAIR,
essentially
suggests
that
the
Agency
invest
substantial
time
and
resources
in
order
to
generate
rulemakings
to
address
environmental
impacts
that
could
be
avoided
through
the
use
of
title
IV
allowances
under
CAIR.
Such
an
approach
would
impose
huge
costs
to
society
in
order
to
provide
additional
allowances
to
a
few
companies.

EPA
disagrees
with
the
commenter's
reasoning
for
disregarding
company­
by­
company
analysis.
EPA
analyzed
company­
level
allocations
at
both
the
owner/
operating
company
and
parent/
holding
company
levels
because
each
is
instructive
in
its
own
way.
As
stated
in
the
Notice
of
Final
Action
on
Reconsideration,
performing
the
analysis
at
the
operating
company
level
recognizes
that
holding
companies
may
incur
costs
to
shift
allowances
between
operating
companies
(
which
typically
consist
of
units
within
a
single
State).
In
so
doing,
EPA
addressed
the
major
concern
of
the
commenter
and
found
that
regardless
of
the
level
of
analysis
(
owner­
or
parent­
company
level),
EPA's
method
provides
reasonable
results
(
see
"
CAIR
SO2
Allocation
Approach
Analysis"
Technical
Support
Document
and
"
SO2
State
Budget
Analysis,"
EPA­
HQOAR
2003­
0053).
Additionally,
EPA
has
addressed
issues
this
commenter
raises
in
support
of
their
characterization
of
the
Agency's
analysis
as
being
"
highly
inadequate"
in
the
"
CAIR
SO2
Allocation
Approach
Analysis"
Technical
Support
Document
and
final
CAIR
technical
support
document,
available
in
the
CAIR
docket
(
EPA­
HQ­
OAR­
2003­
0053).

Regarding
the
commenter's
assessment
of
EPA's
"
select
high­
emitters"
analysis
in
the
Notice
of
Reconsideration,
EPA
agrees
with
the
commenter,
as
well
as
other
commenters,
that
looking
at
differences
in
allowances
or
coverage
ratios
across
the
approaches
for
individual
companies
is
not
as
instructive
as
other
metrics.
Therefore
EPA
does
not
repeat
the
"
Select
High­
emitting
Companies"
analysis
for
the
purposes
of
the
Notice
of
Final
Action
on
Reconsideration.

However,
EPA
disagrees
with
the
commenter's
statement
that
EPA's
approach
allows
"
substantial
importation
of
non­
CAIR
title
IV
allowances."
The
number
of
allowances
that
could
be
transferred
into
the
CAIR
region
by
companies
who
own
plants
outside
of
the
CAIR
region,
according
to
EPA's
analyses,
make
up
only
2%
(
or
about
57,000
allowances)
of
the
overall
allocations
for
the
EPA
approach.
This
can
be
calculated
by
subtracting
the
region­
wide
totals
of
column
B
from
column
E
(
see
docket
spreadsheet
"
SO2
Analysis
Approach
Data,"
file
with
parent
&
owner
comparison
data).
EPA
does
not
view
this
as
a
"
substantial"
amount,
nor
does
the
commenter
sufficiently
describe
how
to
evaluate
whether
importation
is
substantial.

EPA
does
not
project
that
any
units
in
South
Carolina
will
shut
down
as
a
result
of
CAIR.

EPA
disagrees
with
the
commenter's
assessment
of
the
median
as
a
metric
to
evaluate
SO2
allowance
allocation
approaches.
In
the
Notice
of
Reconsideration,
EPA
examined
the
median
point
of
company
coverage
ratios
as
one
among
several
metrics
to
evaluate
the
reasonableness
of
EPA's
approach.
The
difference
between
two
medians
cannot
be
directly
equated
with
an
allowance
allocation
value,
in
the
way
the
commenter
has
described,
because
the
coverage
ratios
are
a
measure
of
the
relationship
between
allowances
and
emissions,
and
thus,
the
distribution
of
ratios
is
also
affected
by
emissions.
Also,
the
median
describes
a
tendency
for
a
system
as
a
whole
 
that
the
midpoint
of
the
entire
dataset
for
the
particular
allocation
approach
­­
and
not
for
individual
data
points
across
approaches,
the
way
the
commenter
suggests.

As
described
in
the
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A.,
EPA
has
analyzed
relevant
data
using
several
other
metrics
and
analytic
methods
to
establish
that
its
approach
is
a
rational
choice
among
the
alternatives.

XVIII.
D.
EPA
did
not
properly
analyze
the
potential
impacts
of
its
SO2
allocation
system
on
owner
/
operating
companies
[
There
are
no
comments
in
this
section.]

XVIII.
E.
EPA
=

s
method
imposes
a
disproportionate
compliance
burden
on
>

clean
=

scrubbed
units
and
/
or
low­
emitting
states
as
compared
to
uncontrolled
units
and
/
or
high­
emitting
states
XVIII.
E.
1
Document
No.:
OAR­
2003­
0053­
2284.2
Commenter:
Minnesota
Power
Comment:
Electric
utilities
that
had
relatively
low
emission
rates
compared
to
the
national
average
at
the
timing
of
the
Acid
Rain
Program
due
to
operation
with
low
sulfur
coal
and
wet
scrubbers
are
not
treated
fairly
under
the
CAIR
compliance
mechanism.
Such
units
are
required
to
provide
for
the
full
surrender
ratio
(
2:
1
or
2.86:
1)
under
the
CAIR
program
while
only
receiving
allowance
allocations
that
already
reflected
the
sort
of
emission
reductions
intended
by
the
CAIR
program.
[ ]
The
Minnesota
Power
average
emission
rate
reflects
operation
with
low
sulfur
coal
and
wet
scrubbers.
The
incremental
SO2
emission
improvement
achieved
by
replacing
existing
scrubbers
with
new
scrubbers
is
not
cost
effective
compared
to
the
cost
per
ton
SO2
removal
involved
with
installing
a
scrubber
on
a
unit
operating
without
SO2
control
equipment.
Consequently,
such
facilities
that
were
scrubbed
during
the
Acid
Rain
Program
1985
to
1987
baseline
allocation
period
and
received
a
relatively
lower
SO2
allowance
allocation
under
that
program
will
require
purchase
of
allowances.
These
purchased
allowances
will
likely
be
released
to
the
market
by
units
that
were
not
scrubbed
during
the
baseline
period
that
are
just
now
retrofitting
scrubbers.
In
effect,
low
emission
units
operating
with
good
environmental
performance
in
the
1980'
s
will
be
helping
pay
for
scrubbers
on
units
whose
owners
had
chosen
to
not
act
to
provide
for
emission
controls
at
that
time.
[ ]
Minnesota
Power
recommends
that
EPA
adopt
an
SO2
allowance
allocation
method
that
assigns
allowances
in
a
manner
similar
to
that
being
done
for
NOx
allowances:
e.
g.
the
recent
baseline
heat
input
is
used
to
prorate
the
pool
of
capped
allowances.
A
heat
input
allocation
basis
will
allow
units
with
good
environmental
performance
to
receive
more
equitable
treatment
under
the
CAIR
by
creating
a
market
where
allowances
are
exchanged
relative
to
actual
emission
performance.
The
pool
of
units
included
for
SO2
allowance
requirements
should
be
limited
to
coal
and
oil
fired
units
that
have
significant
annual
SO2
emissions.
Natural
gas
fired
units
that
burn
natural
gas
meeting
industry
standards
for
sulfur
content
should
be
exempt
from
SO2
allowance
requirements.
Under
a
heat
input
based
allocation,
SO2
allowances
can
continue
to
have
a
surrender
rate
of
1:
1
and
allowances
banked
from
the
Acid
Rain
Program
can
be
carried
over.

Response:
EPA
believes
that
Minnesota
Power's
arguments
that
the
continued
use
of
title
IV
allowances
penalizes
sources
that
installed
controls
prior
to
the
Acid
Rain
Program
is
unfounded.
First,
these
controls
were
installed
over
20
years
ago
and
are,
at
this
point,
a
sunk
cost.
Second,
these
control
installations
were
completed
within
a
regulated
electricity
sector,
such
that
in
most
cases
the
cost
of
installing
these
controls
should
have
been
recovered
through
an
electricity
price
rate
increase.
Third,
these
controls
were
installed
in
response
to
requirements
separate
from
both
CAIR
and
the
Acid
Rain
Program.
Fourth,
the
commenter
suggests
that
a
hypothetical
unscrubbed
coal­
fired
unit
would
be
receive
a
windfall
of
allowances
by
installing
a
scrubber
and
reducing
emissions
but
neglects
the
fact
that
this
unit
would
have
the
costs
of
installing
controls;
thus,
the
ostensible
windfall
would
be
significantly
smaller
than
was
suggested
by
the
commenter
(
or
nonexistent)
(
see
response
XVIII.
i.
1).
Finally,
EPA
would
like
to
note
that
equity
concerns
are
one
of
a
suite
of
considerations
in
the
determination
of
an
appropriate
SO2
allocation
approach.
As
discussed
in
the
CAIR
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A,
EPA
believes
its
chosen
method
is
reasonable.
Additionally,
EPA
is
not
excluding
natural
gas­
fired
units,
chiefly
because
of
their
inclusion
in
the
title
IV
program.
In
addition,
many
natural
gas­
fired
units
fire
or
can
fire
oil,
which
results
in
SO2
emissions.

The
Agency
would
also
like
to
note
that
Congress
did
not
see
a
problem
with
allocating
a
shortfall
of
allowances
to
units
that
already
were
"
clean."
Further,
this
commenter
reframes
its
history
out
of
context.
What
really
occurred
was
that
Minnesota
took
actions
to
reduce
SO2
in
the
1980s,
but
these
actions
were
not
sufficient
for
what
Congress
wanted
in
1990,
and
they
are
not
sufficient
for
what
we
want
under
CAIR.
To
achieve
further
reductions,
we
have
chosen
a
very
flexible
system
that
allows
trading
instead
of
direct
command­
and­
control
reductions,
which
would
result
in
significantly
higher
costs.
Additionally,
Minnesota
Power
can
also
reduce
emissions
through
improvement
of
existing
scrubber
efficiency.

XVIII.
E.
2
Document
No.:
OAR­
2003­
0053­
2280.1
Commenter:
ARIPPA
Comment:
The
Agency=
s
CAIR
program
fails
to
accord
waste
coal­
fired
IPPs
the
favorable
treatment
identified
by
Congress
in
the
context
of
the
Acid
Rain
Program.
More
importantly,
the
Agency
has
isolated
these
sources
for
inequitable,
more
onerous
requirements
compared
to
all
other
affected
units
under
CAIR.
In
particular,
without
any
thorough
explanation,
the
Agency
established
a
compliance
demonstration
program
for
CAIR
that
relies
upon
the
SO2
allowance
program
established
by
the
Agency
under
the
entirely
distinct
acid
rain
control
program.
Affected
sources
must
demonstrate
compliance
under
CAIR
by
holding
allowances
allocated
to
certain
sources,
for
completely
distinct
purposes,
under
the
acid
rain
control
program.
Having
received
no
acid
rain
allocation
because
Congress
determined
to
exempt
the
ARIPPA
plants
from
the
Acid
Rain
Program,
the
ARIPPA
facilities
are
left
in
the
incongruous
position
of
being
rendered
subject
to
the
compliance
requirements
under
CAIR
while,
unlike
most
other
affected
sources,
receiving
no
allocation
of
allowances
with
which
to
demonstrate
compliance.
[[
(
2280.1,
pp.
8­
9)
]]
Notwithstanding
their
relatively
low
SO2
emission
rates
and
the
Congressional
determination
that
these
sources
deserved
favorable
treatment
under
the
acid
rain
program,
ARIPPA
facilities
would
be
required
to
spend
significant
monies
to
acquire
SO2
allowances
from
other
sources,
to
the
extent
that
those
allowances
will
even
be
available
at
a
reasonable
price.
By
contrast,
sources
with
higher
SO2
emission
rates,
for
which
Congress
determined
SO2
emission
reductions
were
necessary
to
address
acid
rain
concerns,
would
receive
an
allocation
of
allowances
­­
through
the
acid
rain
program
­­
to
satisfy
or
significantly
reduce
their
compliance
obligations
under
CAIR.
[[
(
2280.1,
p.
9)
]]
The
Agency
appears
to
suggest
that
non­
acid
rain
sources,
such
as
the
ARIPPA
facilities,
can
simply
purchase
SO2
allowances
from
the
market
in
order
to
demonstrate
compliance
with
CAIR.
This
proposed
solution
obviously
assumes
that
sufficient
allowances
would
be
available
through
market
trading,
which
is
necessarily
an
unproven
assumption.
Further,
if
ARIPPA
facilities
merely
faced
an
increase
in
compliance
costs,
relative
to
other
CAIR­
affected
facilities,
because
of
EPA=
s
allocation
methodology,
this,
by
itself,
would
demonstrate
the
inequity
of
EPA=
s
approach.
However,
even
should
a
sufficient
number
of
allowances
be
available
for
purchase,
the
economic
consequences
of
such
purchase
would
be
devastating
to
the
ARIPPA
facilities.
Because
of
the
existence
of
fixed
price
contracts
and
the
limited
margin
under
which
these
waste
coal­
fired
plants
operate,
the
ARIPPA
facilities
cannot
remain
economically
viable
if
they
must
absorb
significant
additional
compliance
costs.
[[
(
2280.1,
p.
9)
]]
Contrary
to
EPA=
s
assertion
and
analysis,
the
projected
cost
to
ARIPPA
facilities
of
securing
allowances
to
comply
with
CAIR
constitutes
a
significant
portion
of
the
operating
margin
of
these
sources,
and
threatens
their
on­
going
financial
viability.
In
its
Regulatory
Impact
Analysis
(
RIA)
within
CAIR,
EPA
estimated
that
the
marginal
costs
of
control
for
affected
sources
would
be
$
700
per
ton
in
2010
and
$
1000
per
ton
in
2015.
In
a
sensitivity
analysis
conducted
by
the
Agency
and
also
summarized
in
the
preamble,
rising
natural
gas
costs
and
higher
energy
demand
were
predicted
to
raise
these
costs
to
$
800
per
ton
in
2010
and
$
1200
in
2015.
In
evaluating
these
predictions
in
terms
of
current
market
conditions,
Evolution
Markets
recently
identified
2010
vintage
allowances
being
offered
at
$
740,
and
the
spot
price
for
SO2
has
been
over
$
1500
in
recent
weeks.
Thus,
the
Agency=
s
estimates
of
control
costs
appear
to
be
quite
conservative,
and
likely
underpredict
the
actual
cost
of
allowances
to
be
incurred
during
CAIR
implementation.
[[
(
2280.1,
p.
10)
]]
Assuming
allowances
can
be
purchased
for
the
marginal
cost
of
control
in
the
EPA
sensitivity
analysis,
each
ARIPPA
facility
would,
on
average,
incur
costs
of
two
million
dollars
per
year
during
the
first
phase
of
CAIR,
and
over
four
million
dollars
per
year
during
the
second
phase
of
CAIR,
to
secure
necessary
allowances.
By
contrast,
CAIR
provides
allowances,
without
cost,
to
the
majority
of
affected
sources,
which
generally
emit
SO2
and
other
pollutants
at
higher
levels
than
the
ARIPPA
facilities,
in
terms
of
both
total
emissions
and
in
emission
rates.
[[
(
2280.1,
p.
10)
]]
The
Agency=
s
RIA
under
CAIR
also
reveals
the
Agency=
s
estimation
that
only
one
investor­
owned
utility
would
incur
compliance
costs
greater
than
1%
of
revenue
in
2010,
and
only
two
facilities
would
bear
such
costs
in
2015.
Clearly,
EPA
did
not
consider
the
ARIPPA
facilities
in
this
analysis.
Specifically,
if
the
analysis
is
performed
for
the
ARIPPA
plants
­­
accepting
both
the
Agency=
s
estimation
of
the
marginal
control
cost
for
affected
sources
and
the
assumption
that
allowance
costs
would
equal
the
marginal
cost
of
control
­­
every
ARIPPA
plant
would
expend
more
than
1%
of
its
revenue
to
comply
with
the
SO2
allowance
provisions
of
CAIR
in
every
year
that
it
remains
in
operation.
Indeed,
all
but
two
ARIPPA
facilities
would
expend
more
than
3%
of
their
revenues
under
this
analysis.
In
fact,
the
average
ARIPPA
plant
would
spend
6%
of
its
revenue
in
2010
to
purchase
SO2
allowances
and
8%
in
2015,
with
some
plants
required
to
spend
over
10%
of
their
revenues
to
comply
with
CAIR.
[[
(
2280.1,
p.
10­
11)
]]
This
analysis
reflects
the
highlyconservative
assumption
that
the
ARIPPA
facilities
could
sell
power
at
retail
prices
equivalent
to
those
estimated
by
the
Agency
in
the
RIA
for
the
MAAC
Power
region.
Under
a
less
conservative,
but
more
realistic,
Analysis
using
estimates
of
wholesale
power
prices
prepared
by
Cinergy
in
its
review
of
the
IARQ
rule,
the
average
ARIPPA
facility
would
expend
11%
of
its
total
revenue
in
2010
and
23%
in
2015
to
comply
with
CAIR.
Clearly,
the
ARIPPA
facilities
cannot
remain
viable
if
forced
to
bear
such
economic
burdens.
In
addition,
the
result
is
particularly
inequitable
when
considering
that
larger
affected
sources
would
be
provided
allowance
allocations
under
the
CAIR
Allocation
Methodology.
[[
(
2280.1,
p.
11)
]]
EPA
asserts
within
the
RIA
that
the
small
entities
projected
to
be
affected
by
CAIR
do
not
operate
in
a
competitive
market
environment,
and
thus
should
be
able
to
pass
compliance
costs
on
to
consumers.
These
statements
do
not
reflect
the
situation
confronted
by
the
ARIPPA
plants.
The
ARIPPA
facilities
all
operate
either
under
Power
Purchase
Agreements
(
PPAs)
or
are
marketbased
plants,
competitively
bidding
into
the
PJM
market.
The
facility
operators
have
no
opportunity
to
pass
along
the
additional,
significant
costs
of
purchasing
SO2
allowances.
Indeed,
recognition
of
this
circumstance
is
one
of
the
primary
reasons
identified
by
Congress
for
exempting
these
sources
from
the
Acid
Rain
Program.[[
(
2280.1,
pp.
11­
12)
]]
EPA=
s
inequitable
treatment
of
the
ARIPPA
sources
under
CAIR
threatens
to
prematurely
shutdown
these
sources.
In
fact,
the
ARIPPA
sources
emit
SO2
at
rates
substantially
lower
than
other
coal­
fired
sources
that
would
receive
allowance
allocations
under
CAIR,
and
will
face
shutdown
merely
because
Congress
determined
that
such
sources
deserve
preferential
treatment
under
the
acid
rain
program
and
the
Agency=
s
CAIR
program
therefore
penalizes
such
sources.
The
shutdown
of
these
sources
would
result
in
the
loss
of
the
significant
environmental
benefits
associated
with
waste
coal
combustion,
including
mitigation
of
acid
mine
drainage
and
restoration
of
abandoned
mine
land.
[[
(
2280.1,
p.
12)
]]
Moreover,
EPA
fails
to
justify
its
linkage
of
the
acid
rain
allowance
provisions
to
the
implementation
of
CAIR,
except
to
contend
that
such
linkage
is
necessary
to
maintain
the
integrity
and
vibrancy
of
the
acid
rain
allowance
trading
market.
To
the
extent
that
a
universe
of
sources
is
required
to
demonstrate
compliance
with
acid
rain
standards
using
acid
rain
allowances,
the
viability
of
that
allowance
market
is
driven
by
the
acid
rain
requirements,
and
not
dependent
upon
a
distinct
CAIR
program.
Further,
EPA
fails
to
acknowledge
the
distinct
objectives
of
the
SO2
emission
trading
program
under
the
acid
rain
provisions
and
the
SO2
emission
control
program
addressed
by
CAIR,
Congress=
determination
to
establish
an
acid
rain
emission
control
program
and
provide
for
the
allocation
of
acid
rain
allowances
to
specific
sources
in
1990
clearly
did
not
envision
any
application
of
such
program
to
non­
acid
rain
sources
­­
for
distinct
environmental
purposes
­­
fifteen
years
later.
[[
(
2280.1,
p.
12­
13)
]]
In
addition,
in
determining
to
utilize
the
allowance
provisions
of
the
Acid
Rain
Program
for
purposes
of
CAIR
implementation,
EPA
completely
ignores
other
closely
related
and
significant
aspects
of
the
acid
rain
program,
including
the
exemption
of
certain
sources
from
the
allowance
requirements.
The
Agency=
s
partial
incorporation
of
the
acid
rain
allowance
program
greatly
contributes
to
the
inequity
of
CAIR
as
it
relates
to
non­
acid
rain
sources.
[[
(
2280.1,
p.
13)
]]
The
combination
of
these
factors
has
resulted
in
an
SO2
program
under
CAIR
that
imposes
unjustifiable
and
unworkable
burdens
upon
ARIPPA=
s
waste
coal­
fired
sources.
EPA
has
established
an
allowance
trading
program
under
CAIR
that
unjustifiably
and
inequitably
differentiates
and
penalizes
those
low
emitting
sources
which
Congress
determined
deserved
favorable
treatment
under
the
acid
rain
program
­­
precisely
because
Congress
isolated
these
sources
for
preferential
treatment.
Finally,
because
these
sources
are
smaller
than
most
conventional
utility
units,
coupled
with
fixed
long­
term
contracts
in
most
cases,
the
ARIPPA
facilities
operate
with
much
leaner
financial
budgets;
accordingly,
the
implications
to
these
sources
of
not
receiving
an
allowance
allocation
is
far
more
severe.
[[
(
2280.1,
p.
13)
]]

Response:
See
response
to
comment
XVIII.
A.
1
and
CAIR
FIP/
126
final
rule,
Section
VI.
E.
Inaccuracies
in
the
commenter's
assumptions
about
projected
cost
per
ton
resulted
in
an
overestimation
of
its
cost
of
compliance
estimates.
One
specific
assumption
made
by
the
commenter
is
that
the
projected
cost
per
ton
were
allowance
prices.
As
a
result,
the
commenter
multiplied
the
projected
cost
per
ton
by
the
CAIR
SO2
programs
retirement
ratios
(
i.
e.,
2­
to­
1
in
2010
and
2.86­
to­
1
in
2015).
In
fact,
EPA
modeling
has
projected
the
cost
of
emitting
one
ton
of
SO2
under
the
CAIR
to
be
$
686/
ton
and
$
994/
ton
in
2010
and
2015,
respectively.
(
The
modeling,
and
resulting
cost
per
ton,
already
incorporates
the
CAIR
SO2
retirement
ratios.)

XVIII.
E.
3
Document
No.:
OAR­
2003­
0053­
2277.1
Commenter:
Primary
Energy
of
North
Carolina
LLC
Comment:
Primary
Energy
of
North
Carolina
strongly
objects
to
the
characterization
by
EPA
in
the
Notice
of
Reconsideration
that
the
selected
approach
for
allocating
SO2
allowances
produces
a
reasonable
result.
Simply
stated,
numerous
non­
utility
facilities
that
are
more
efficient
than
the
electric
utility
generating
facilities
that
they
displace
will
be
subject
to
expensive
regulatory
requirements
to
acquire
SO2
allowances
while
the
more
traditional
electric
generating
utilities
with
which
they
compete
will
be
protected
by
their
advantaged
status
under
Title
IV.
These
disproportionate
costs
will
not
only
directly
impact
the
economics
of
our
own
operations
but,
because
we
have
no
ability
to
pass
on
the
costs
of
SO2
allowances
to
the
utilities
to
which
we
sell
electricity,
will
force
higher
costs
on
our
thermal
energy
customers
affecting
their
global
competitiveness.
[[
Docket
number
2277.1,
p.
1]]
In
CAIR,
EPA
has
not
adopted
the
Acid
Rain
exemption
for
QFs
even
though
EPA
is
exclusively
using
the
allowance
allocations
under
the
Acid
Rain
Program
as
the
foundation
for
implementing
reductions
in
SO2
emissions
in
CAIRaffected
states.
There
is
a
long
history
of
EPA
rulemaking
and
voluntary
program
implementation
aimed
at
encouraging
more
efficient
energy
generation
in
general
and
CHP
specifically.
Unlike
those
initiatives,
this
CAIR
rulemaking
specifically
and
negatively
targets
CHP
facilities
that
have
met
the
exemption
criteria
of
the
Acid
Rain
program
but
are
now
denied
an
allocation
of
SO2
allowances
under
the
CAIR
program.
This
is
more
onerous
since
these
QF
facilities
that
receive
no
allowance
allocations
will
be
required
to
retire
more
than
one
allowance
per
ton
of
emissions
under
CAIR.
[[
docket
number
2277.1,
p.
2]]
With
specific
regard
to
our
facilities,
the
draft
rule
out
for
comment
from
the
State
of
North
Carolina
is
based
on
the
premise
that
they
have
no
authority
or
mechanism
for
allocating
any
other
SO2
allowances
to
facilities
that
do
not
already
have
an
allocation
under
Acid
Rain.
This
is
a
very
different
process
than
what
has
been
used
under
the
NOx
trading
rule
in
which
states
had
significant
flexibility
to
allocate
allowances
using
different
methodologies,
create
energy
efficiency
and
renewable
energy
setasides
and
otherwise
put
in
place
a
program
that
was
equitable
and
cost
effective
across
the
entire
universe
of
affected
sources.
[[
Docket
number
2277.1,
p.
3]]
It
is
our
view
that
if
EPA
is
unable
or
unwilling
to
proactively
allocate
SO2
allowances
to
units
that
were
exempted
under
the
Acid
Rain
Program,
then
the
Agency
must
retain
the
entire
underlying
structure
of
the
Acid
Rain
program
including
the
exemptions.
The
distribution
of
allowances
under
Acid
Rain
was
effectively
a
distribution
of
money.
Generally
speaking,
the
higher
your
historic
emissions,
the
more
money
you
received.
This
was
done
under
the
assumption
that
a
public
good
was
served
both
by
the
allocation
methodology
and
the
exemption.
By
eliminating
the
exemption
but
not
the
allocation
methodology,
the
agency
is
doing
direct
and
substantial
economic
harm
to
a
group
of
facilities
that,
at
that
time
and
now,
are
applauded
for
the
many
societal
benefits
they
provide
(
i.
e.
efficient
generation,
grid
reliability
and
stability,
etc).
This
is
clearly
inequitable
and
must
be
addressed
by
the
agency
in
the
reconsideration
process
by
preserving
the
Acid
Rain
exemption
to
exempted
facilities
that
maintain
their
QF
status.
[[
Docket
number
2277.1,
p.
3]]

Response:
See
responses
to
comments
XVIII.
A.
1
and
XVIII.
E.
1
and/
or
FIP/
126
final
rule.
This
commenter
also
appears
to
ignore
the
opt­
in
provisions
of
CAIR.

XVIII.
E.
4
Document
No.:
OAR­
2003­
0053­
2293.1
Commenter:
Constellation
Generation
Group
Comment:
Constellation
supports
the
CAIR
in
most
aspects;
however,
we
have
concerns
with
some
of
the
assumptions
used
by
EPA
as
well
as
concerns
with
EPA=
s
failure
to
contemplate
other
matters
in
the
May
12,
2005
CAIR
final
rule.
Specifically,
CAIR
failed
to
properly
consider
the
effects
of
waste
coal­
fired
plants
in
its
modeling,
effectively
forcing
these
plants
to
add
cost­
prohibitive
controls
and/
or
acquire
SO2
allowances.
Moreover,
CAIR
failed
to
afford
waste­
coal
fired
plants
allocation
of
SO2
allowances
under
CAIR
or
the
acid
rain
program.
[[
(
2293.1,
p.
1)
]]
Constellation
owns
interests
in
waste
coal­
fired
assets.
Waste
coal­
fired
plants
are
relatively
new
and
have
been
long
considered
to
be
environmentally
favorable
because
of
their
ability
to
consume
waste
coal
piles
left
over
from
decades
of
coal
mining.
These
abandoned,
aesthetically
displeasing,
coal
piles
are
known
to
cause
acid
mine
drainage
when
rainfall
infiltrates
the
coal
piles
producing
a
low
pH
acid
water
which
contaminates
surface
water
and
groundwater.
Using
Circulating
Fluidized
Bed
(
CFB)
technology
enables
companies
like
Constellation
to
use
waste
coals.
CFB=
s
are
considered
to
be
a
state­
of­
the­
art
>
clean
coal
technology=
meaning
that
they
emit
less
harmful
emissions
than
conventional
coal
plants.
[[
(
2293.1,
pp.
1­
2)
]]
Limestone
injection
by
CFBs
yield
lower
emissions
of
SO2.
Additional
add­
on
controls
for
SO2,
such
as
Flue
Gas
Desulfurization,
are
economically
not
feasible
due
to
the
fact
that
CFB
plants
are
constrained
by
long­
term,
fixed­
price
contracts
resulting
in
limited
profit
margins
and
reduced
financial
efficacy.
Additionally,
it
becomes
more
cost­
prohibitive
(
by
orders
of
magnitude
on
a
cost
per
ton
basis)
to
control
SO2
over
and
above
levels
already
achieved
by
waste
coal­
fired
units
since
plants
have
effectively
maximized
existing
SO2
controls.
It
is
for
this
reason
that
Congress
expressly
exempted
Independent
Power
Producers
(>
IPP=)
like
waste­
coal
plants
from
acid
rain
requirements
in
1990.
Moreover,
Congress
attempted
to
encourage
clean
energy
sources
like
waste
coal­
fired
plants
and
believed
that
IPPs
deserved
favorable
treatment
under
the
acid
rain
program.
Interestingly,
EPA
has
established
an
exemption
from
CAIR
for
certain
cogenerating
facilities
applying
the
same
IPP
exemption
under
the
acid
rain
program,
but
not
for
waste
coal­
fired
plants.
[[
(
2293.1,
p.
2)
]]
EPA
analysis
of
SO2
control
technology
in
developing
CAIR
did
not
entertain
specifics
relating
to
small
waste­
coal
plants.
Instead,
the
agency
based
its
analysis
on
large
Electric
Generating
Units
(
EGU=
s
are
those
units
that
generate
more
than
25MW
and
sell
more
than
one­
third
of
their
output)
having
back­
end
controls.
Under
the
current
CAIR
allocation
approach,
CAIR
requires
waste
coal­
fired
plants
to
either
control
SO2
emissions
and/
or
purchase
allowances.
However,
CAIR
fails
to
provide
allocation
of
allowances
effectively
penalizing
waste
coal­
fired
plants,
that
otherwise
were
favorably
considered
and
exempted
by
Congress
under
the
1990
acid
rain
rules.
[[
(
2293.1,
p.
2)
]]
Under
the
current
CAIR
allocation
approach,
EPA
prohibits
states
from
exercising
discretion
and
flexibility
in
allocating
allowances
among
affected
sources
within
those
states.
While
EPA
attempts
to
make
partial
linkage
with
the
acid
rain
program,
it
fails
to
incorporate
the
rationale
behind
exempting
specific
sources
like
waste
coal­
fired
plants,
thereby
underscoring
the
inequity
of
the
existing
CAIR
program.
[[
(
2293.1,
p.
2)
]]
Constellation
respectfully
requests
that
EPA
take
the
following
CAIR­
related
actions
as
it
reconsiders
the
rule:
1.
Revise
the
SO2
portion
of
CAIR
to
continue
the
acid
rain
SO2
exemption
that
Congress,
in
their
wisdom
believing
that
waste
coal
plants
are
to
be
treated
preferentially,
enacted
for
IPPs
under
long­
term
contracts
­
an
exemption
currently
enjoyed
by
certain
cogenerating
plants
under
CAIR.
2.
To
the
extent
that
EPA
continues
to
include
waste
coal­
fired
plants
in
the
SO2
portion
of
CAIR,
the
agency
must
ensure,
at
a
minimum,
that
waste
coal­
fired
plants
are
afforded
equitable
allowance
allocation
treatment,
preventing
the
loss
of
the
environmental
benefits
of
low­
emitting
waste
coal­
fired
plants.
[[
(
2293.1,
p.
2)
]]

Response:
See
response
to
comment
XVIII.
A.
1
and/
or
FIP/
126
final
rule.

EPA
believes
that
analysis
presented
in
today's
CAIR
FIP/
126
rulemaking
(
preamble,
response
to
comment
document,
and
Waste
Coal­
Fired
Units
in
the
CAIR
and
CAIR
FIP
TSD)
demonstrates
that
these
units
would
continue
to
operate
and
could
be
profitable
under
CAIR.

In
addition
to
the
evaluation
of
the
cost
to
revenue
ratios,
EPA
further
investigated
the
potential
impacts
of
CAIR
on
waste
coal­
fired
units
while
their
PPAs
remain
in
effect
by
examining
how
their
contract
prices
might
compare
with
their
potential
costs
to
operate.
An
EPA
search
of
publicly
available
information
produced
a
contract
for
a
Pennsylvania
waste
coal­
fired
facility
that
commenced
operation
in
1993.
Environmental
Power
Corporation
Form
10­
K
filing
is
located
in
the
docket.
The
contract
indicates
that
the
PPA
agreement
compensates
the
waste
coal­
fired
facility
at
$
62.72
per
MWh
in
1999.
Price
is
escalated
to
1999
for
comparison
purposes.
In
other
words,
this
waste
coal­
fired
facility,
while
being
bound
by
a
fixed
price
contract,
was
being
compensated
at
levels
will
above
their
EPA­
estimated
likely
cost
of
operation
(
discussed
below
and
in
the
Waste
Coal­
Fired
Units
in
the
CAIR
and
CAIR
FIP
TSD)
and
EPA
projected
wholesale
electricity
prices
in
2010
and
2015.
Additional,
limited
information
submitted
by
commenters
also
suggest
that
at
least
some
waste
coal­
fired
units,
while
constrained
by
their
PPAs,
are
compensated
at
levels
well
above
market
rates
 
rates
that
would
allow
them
to
absorb
compliance
costs.
Specifically,
the
commenter
states
that
one
facility
"
happens
to
have
a
PPA
that
includes
very
attractive
current
energy
prices."
The
commenter
continues
that
when
the
PPA
expires,
"
revenue
is
estimated
to
drop 
with
the
switch
to
market
prices."
In
other
words,
when
this
unit
must
compete
on
the
market,
its
income
will
drop.
This
supports
EPA's
belief
that
at
least
some
waste
coal­
fired
units
are
well
compensated
by
their
PPAs
and
the
cost
of
complying
with
CAIR
would
not
make
them
economically
unviable.

Waste
Coal­
Fired
Units
After
PPAs
Expire
Because
the
unit­
specific
information
and
analysis
provided
by
the
commenters
was
limited,
EPA
conducted
an
analysis
using
generally
available
information
to
evaluate
the
potential
impact
of
the
cost
of
complying
with
CAIR
for
a
typical
CFB
combusting
waste
coal.
This
analysis
specifically
applies
to
periods
of
time
when
the
power
purchase
agreements
have
expired
(
i.
e.,
the
units
have
lost
the
exemption
from
title
IV
and
can
not
receive
title
IV
opt­
in
allowances)
and
the
units
are
free
to
participate
in
the
electricity
markets.
This
analysis
examined
how
the
potential
cost
to
operate
a
typical
waste
coal­
fired
CFB
unit
(
including
the
cost
of
complying
with
CAIR)
compares
to
the
potential
price
it
would
receive
on
the
electricity
market.
As
shown
in
table
VI.
A­
1,
the
estimated
cost
of
producing
electricity
for
a
typical
waste
coal­
fired
CFB
would
be
significantly
less
than
the
EPA
projected
wholesale
price
and
the
forecasted
price
of
electricity.
In
other
words,
the
typical
facility
would
produce
electricity,
even
with
the
cost
of
complying
with
CAIR,
at
a
cost
that
below
what
they
market
would
be
willing
to
pay.
In
general,
waste
coal­
fired
facilities
will
continue
to
be
profitable,
even
when
factoring
in
the
cost
of
complying
with
CAIR.

Table
VI.
A­
1:
Costs
of
Operating
a
Typical
CFB
Plant
Burning
Waste
Coal
Components
of
Operating
Costs
Cost
to
Operate
2010
($/
MWh)
Cost
to
Operate
2015
($/
MWh)

Variable
O&
M
$
2.11
$
2.11
Fixed
O&
M
$
5.31
$
5.31
Fuel
Cost
$
7.28
$
7.20
SO2
Allowance
Cost
$
1.53
$
2.17
NOx
Allowance
Cost
$
0.77
$
0.95
Total
Operating
Cost*
$
17.00
$
17.74
Base
Case
Wholesale
Electricity
Price**
$
25.43
$
33.46
CAIR
Wholesale
Electricity
Price**
$
27.10
$
36.06
*
The
total
operating
cost
estimate,
as
well
as
component
costs,
are
described
in
the
TSD
Waste
Coal­
Fired
Units
in
the
CAIR
and
CAIR
FIP.
**
IPM
projected
wholesale
electricity
prices
in
the
under
the
Base
Case
and
CAIR
(
EPA
2006).
Other
Considerations
While
EPA
evaluated
the
commenters'
claims
by
analyzing
the
potential
financial
impacts
of
complying
with
the
CAIR
SO2
annual
program
only,
EPA
believes
that
there
are
other
consideration
that
can
influence
the
economic
viability
(
i.
e.,
whether
they
will
cease
to
operate)
of
the
plants.
First,
the
CAIR
includes
two
NOx
control
programs
 
one
annual
and
one
summertime
 
that
each
provide
CAIR
allowance
budgets
that
States
can
allocate
to
any
units
they
wish.
(
EPA
notes
that
these
units
have
not
expressed
concern
over
the
cost
of
compliance
with
either
of
the
CAIR
NOx
programs.)
In
addition,
coal­
fired
units
(
including
units
fired
with
waste
coal)
can
receive
mercury
allowances
under
the
Clean
Air
Mercury
Rule
(
CAMR).
Allowances
from
all
three
programs
(
the
CAIR
NOx
annual
program,
the
CAIR
NOx
ozone
season
program,
and
the
CAMR)
are
valuable
commodities
and
can
provide
mechanisms
for
States
wishing
to
encourage
certain
types
of
generation
to
do
so.
Finally,
there
are
environmental
programs,
outside
of
the
CAIR
and
CAMR
programs,
that
also
provide
benefit
to
these
waste
coal­
fired
units
and
could
be
considered
in
the
overall
viability
of
the
plants.
One
example
is
the
potential
benefits
of
waste
coal­
fired
units
generating
renewable
energy
credits
(
RECs)
as
part
of
statewide
renewable
portfolio
standards
(
RPSs).
When
taken
as
a
whole,
these
other
factors
in
a
waste
coal­
fired
units
environmental
compliance
costs
could
provide
significant
benefit
to
these
units.

XVIII.
E.
5
Document
No.:
OAR­
2003­
0053­
2281.1
Commenter:
Northern
Indiana
Public
Service
Company
(
NIPSCO)
Comment:
USEPA=
s
assertion
that
any
approach
is
going
to
be
inequitable
to
someone
misses
the
point.
USEPA
definitely
misses
the
point
in
the
reconsideration.
To
clarify
for
USEPA,
the
final
CAIR
allocation
methodology
is
inequitable
not
because
lower
emitting
units
would
buy
allowances
from
higher
emitting
units,
but
because
lower
emitting
units
would
be
required
to
meet
more
stringent
effective
emissions
requirements
and,
as
a
result,
would
be
required
to
purchase
allowances
in
the
market,
possibly
from
higher
emitting
units
that
install
emission
controls.
The
program
is
inequitable
because
it
subjects
these
lower
emitting
units
to
a
more
costly,
yet
avoidable,
compliance
requirement.
Since
the
affected
utilities
would
need
to
meet
a
more
stringent
requirement,
there
would
not
be
cost
effective
controls
to
install
that
would
allow
the
utility
to
comply
without
purchasing
allowances
from
the
market.
In
fact,
IPM
predicts
that
NIPSCO
would
fit
this
profile
and
would
meet
compliance
with
CAIR
SO2
allocation
solely
by
purchasing
allowances
from
the
market.
One
need
only
look
at
the
market
today
to
understand
that
the
SO2
allowance
market
is
not
efficient
and
subjects
forced
participants
to
an
undue
amount
of
financial
burden
and/
or
risk.
[[
(
2281.1,
p.
2)
]]
The
commenter
also
asserts
that
EPA's
approach
ignores
the
Acid
Rain
Bonus
allowance
program,
which
ends
in
2009,
just
before
the
CAIR
SO2
program
begins.

Response:
See
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A,
and
response
to
comment
XVIII.
E.
1.
The
Agency
would
also
like
to
note
that
by
giving
NIPSCO
the
flexibility
of
meeting
the
reduction
requirements
through
trading,
or
by
improving
efficiency
of
existing
scrubbers,
we
allow
NIPSCO
the
cheapest
way
to
comply
with
our
reduction
goals.
EPA's
modeling
shows
that
NIPSCO's
units
will
not
have
to
shut
down
because
of
the
CAIR
constraints.
The
fact
that
allowance
purchase
is
the
cheapest
way
to
comply
with
CAIR
is
an
unwarranted
complaint.
EPA
believes
that
the
commenter's
claims
about
the
state
of
the
SO2
allowance
market
are
unfounded.
As
is
discussed
in
the
Acid
Rain
Program
Report
(
EPA
43­
R­
05­
012,
October
2005),
about
20,000
allowance
transactions,
affecting
about
15.3
million
allowances
were
recorded
in
the
EPA
Allowance
Tracking
System
in
2004.
In
addition,
title
IV
compliance
costs
have
been
much
lower
than
projected
and
allowance
prices
in
the
SO2
allowance
market
have
generally
reflected
this.
Sources
also
have
the
option
of
purchasing
allowances
directly
from
the
annual
auction.
Finally,
while
the
commenter
suggests
that
it
is
unfair
that
the
CAIR
program
begins
just
as
the
Bonus
allowance
program
is
ending,
the
two
events
are
unrelated.
Companies
have
had
ample
notice
of
the
end
of
the
Bonus
allowance
program.
The
CAIR
requirements
begin
for
all
effected
units
in
2010,
and
thus
treat
all
units
equally.
EPA
does
not
believe
that
this
coincidental
timing
warrants
the
provision
of
additional
bonus
allowances
to
certain
units.

XVIII.
E.
6
Document
No.:
OAR­
2003­
0053­
2269.1
Commenter:
AES
Corporation
Comment:
The
units
that
are
exempted
under
Title
IV
are
all
well
controlled
for
SO2.
The
inequity
of
being
pulled
back
into
a
program
based
on
the
Title
IV
allocation
and
compliance
scheme
is
exacerbated
by
the
fact
that
the
facilities
(
which
already
have
low
emission
rates)
will
be
hard
pressed
to
reduce
to
make
up
for
the
allowance
deficiency.
That
is
they
likely
cannot
reduce
their
SO2
emissions
much,
if
at
all,
to
help
the
make
up
for
the
allowance
shortfall.
[[
Docket
umber
2269.1,
pp.
2­
3]]
In
our
July
22,
2004
comments
on
CAIR,
AES
described
the
inequitable
situation
created
under
CAIR
for
low
emitting
units
that
had
their
Title
IV
allocation
based
on
their
low
emission
rates
during
the
baseline
period
(
please
see
page
5
of
the
attached
July
22,2004
comments)
[[
See
Docket
number
2269.1,
p.
11
for
the
July
22,
2004
comments.]].
As
noted
in
for
the
CAIR
cap
and
trade
program
results
in
the
perverse
situation
whereby
these
>
clean=
units,
that
oftentimes
emit
SO2
at
rates
less
than
0.6
lbs/
MMBtu,
are
placed
at
a
significant
Financial
disadvantage
compared
to
much
higher
emitting
units
in
the
nation
that
had
their
Title
IV
allowance
allocations
determined
by
the
default
1.2
lbs/
MMBtu
emission
rate.
[[
Docket
number
2269.1,
pp.
4­
5]]
At
70
Fed.
Reg.
72276
of
the
December
2,2005
Notice
of
Reconsideration
it
states,>
EPA
also
notes
that,
while
the
Petitioner
states
that
the
CAIR
final
allocation
methodology
is
>
inequitable=
because
lower
emitting
units
would
buy
allowances
from
higher
emitting
units
that
install
emission
controls,
it
is
unclear
why
such
a
result
would
actually
be
inequitable.
On
the
contrary,
the
owner
of
each
of
the
units
involved
would
be
choosing
to
adopt
the
most
economic
compliance
strategy
in
light
of
the
unit=
s
emission
control
costs
and
the
market
value
of
allowances.
The
ability
of
the
owners
to
make
such
choices
reflects
the
flexibility
provided
by
a
cap
and
trade.=
(
Emphasis
added).
[[
Docket
number
2269.1,
p.
5]]
AES
contends
that
having
a
clean
unit
that=
s
been
emitting
at
low
emission
rates
for
20+/­
years
being
put
in
a
situation
where
it
needs
to
expend
significant
amounts
of
money
to
purchase
allowances,
while
units
that
have
subsequently
reduced
their
emissions
have
excess
allowances
to
sell,
when
both
may
currently
be
achieving
the
exact
same
emission
rate,
should
be
considered
to
be
the
definition
of
inequitable
treatment.
This
treatment
places
the
historically
clean
unit
at
a
significant
competitive
disadvantage.
The
SO2
allocation
mechanism
should
be
adjusted
to
rectify
this
situation.
[[
Docket
number
2269.1,
p.
5]]
In
Summary,
AES
respectfully
request
that
EPA
take
the
following
CAIR­
related
actions:
.
.
.3.
As
a
consequence
of
the
impacts
of
the
CAIR
SO2
program,
revise
existing
facility
Title
IV
allowances
that
were
based
on
a
>
clean
unit=
emission
rate
to
the
higher
SO2
emission
standard
basis
that
was
used
for
other
facilities
(
i.
e.,
1.2
lbs/
MMBtu).
This
will
avoid
the
unintended
consequence
of
a
lower
emitting
resource
being
forced
to
buy
allowances
from
a
higher
emitting
resource.
[[
Docket
number
2269.1,
pp.
5­
6]]

Response:
See
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A,
and
response
to
comment
XVIII.
E.
1.
EPA
also
disagrees
that
the
CAIR
SO2
allocation
method
places
"
historically
clean
unit[
s]
at
a
significant
competitive
disadvantage."
In
terms
of
actual
dispatch
economics,
historically
clean
units
would
have
similar
variable
operating
costs
to
other
units
and
would
remain
competitive
in
dispatch
order.

XVIII.
F.
EPA
inappropriately
assumed
that
units
can
opt
into
the
Acid
Rain
Program
XVIII.
F.
1
Document
No.:
OAR­
2003­
0053­
2277.1
Commenter:
Primary
Energy
of
North
Carolina
LLC
Comment:
EPA=
s
CAIR
SO2
regulations
take
away
an
exemption
that
Congress
specifically
granted
to
certain
qualifying
facilities
(>
QFs=)
under
the
Acid
Rain
Program
in
the
1990
Clean
Air
Act
Amendments.
These
QF=
s
were
not
provided
an
allocation
of
allowances
as
was
granted
to
utility
plants
because
the
QF=
s
were
not
included
in
the
program.
Now
EPA
has
stated
in
the
preamble
to
the
CAIR
rule
that
the
exemption
under
the
Acid
Rain
Program
was
aimed
at
>
easing
the
transition
of
the
facilities
into
the
Acid
Rain
Program=
and
that
>
there
was
no
basis
for
maintaining
this
exemption
for
every
subsequent
cap
and
trade
program.=
See
70
Fed.
Reg.
25162,25278
(
May
12,
2005).
This
is
a
dubious
assertion.
In
fact,
these
QF=
s
were
exempted
because
Title
IV
was
designed
to
control
emissions
from
regulated
electric
utilities
eligible
for
cost
recovery
on
their
capital
expenditures.
The
exemptions
for
QF=
s
were
a
recognition
that
they
were
not
designed
or
developed
as
utility
generators.
In
states
such
as
North
Carolina
in
which
power
generation
is
still
subject
to
traditional
regulation,
this
distinction
still
holds.
[[
Docket
number
2277.1,
pp.
1­
2]]
Even
if
the
exemption
had
been
predicated
on
transition,
none
of
the
other
transitional
events
EPA
might
have
expected
to
occur
over
the
last
15
years
have
occurred
­
competitive
energy
markets
have
not
substantially
evolved
from
where
they
were
in
1990,
the
national
utility
plant
inventory
has
not
significantly
turned
over
since
1990
and
our
plants
still
have
no
means
to
pass
on
the
costs
of
SO2
control
or
allowance
purchases
to
the
electric
utility
to
which
we
sell
the
electricity.
It
is
completely
inappropriate
to
change
the
ground
rules
for
one
piece
of
the
picture
(
the
SO2
compliance
requirement)
when
none
of
the
other
components
of
the
market/
regulatory
environment
have
changed.
[[
Docket
number
2277.1,
p.
2]]
In
the
Clean
Air
Act
Amendments
of
1990,
Congress
exempted
QFs
from
compliance
with
the
Acid
Rain
Program
if
they
had
entered
into
qualifying
power
purchase
commitments
as
of
November
15,
1990
to
sell
at
least
15%
of
their
net
output
capacity.
The
Primary
Energy
of
North
Carolina
facilities
in
Roxboro
and
Southport
(
originally
developed,
constructed,
owned
and
operated
by
Cogentrix)
both
met
the
criteria
of
the
exemption
as
they
do
today.
The
Primary
Energy
of
North
Carolina
plants
are
both
cogeneration
or
combined
heat
and
power
(
CHP)
facilities.
CHP
facilities
provide
electricity
and
thermal
energy
with
increased
efficiency
of
energy
conversion
and
can
provide
significant
energy
savings
and
reduced
environmental
impacts
when
compared
to
the
electricity
and
heat
supplied
by
more
conventional
central
plants.
Our
Southport
facility
provides
steam
to
an
Archer
Daniels
Midland
citric
acid
plant
and
the
Roxboro
facility
provides
steam
to
a
Collins
and
Aikman
facility.
Both
of
these
facilities
are
significant
employers
in
the
local
area
and
rely
to
a
significant
extent
on
the
economic
benefits
of
purchasing
cogenerated
steam.
[[
Docket
number
2277.1,
p.
2]]

Response:
See
response
to
comment
XVIII.
F.
2.
Also,
see
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A..

XVIII.
F.
2
Document
No.:
OAR­
2003­
0053­
2285
Commenter:
Virginia
Independent
Power
Producers
Comment:
In
the
December
2,
2005
notice
announcing
the
reconsideration
of
the
four
CAIR
issues,
EPA
noted
that
its
analysis
of
the
CAIR
SO2
methodology
considered
the
allocation
of
Title
IV
SO2
allowances
to
electric
generating
units
not
currently
in
the
Acid
Rain
Program
through
the
voluntary
opt­
in
provisions
.
The
agency
seems
to
assume
that
voluntary
opt­
in
would
eliminate
any
undue
hardship
on
IPPs
and
QFs
that
opt­
in
to
the
Acid
Rain
Program
by
providing
an
allocation
of
a
certain
amount
of
SO2
opt­
in
allowances.
The
voluntary
opt­
in
option
is
not
a
sufficient
solution
and
would
generally
result
in
the
allocation
of
a
wholly
inadequate
number
of
allowances
to
IPPs
and
QFs
for
the
following
reason.
[[
(
p.
5)
]]
Under
the
EPA
opt­
in
regulations,
the
allocation
of
allowances
would
be
based
on
the
SO2
emissions
of
the
units
during
the
first
three
calendar
years
of
their
operation,
and
during
this
period
many
of
the
units
were
dispatched
by
the
purchasing
utilities
on
a
reduced
basis
when
compared
to
the
more
current
dispatch
levels.
Under
the
fixed
price
formula
PPAs,
the
IPPs
and
QFs
are
compensated
by
(
i)
a
fixed
capacity
price
that
is
tied
to
minimum
dispatch
availability
requirements
and
(
ii)
a
variable
energy
price
that
is
linked
to
the
amount
of
electricity
that
is
actually
dispatched
and
a
pass
through
on
the
costs
of
fuel
to
generate
that
electricity.
The
Public
Utilities
Regulatory
Policy
Act
of
1978
mandated
that
utilities
enter
into
electricity
offtake
contracts
with
IPPs
and
QFs,
but
they
did
not
mandate
that
the
plants
had
to
be
dispatched
at
near
full
capacity
levels.
Utilities
generally
will
dispatch
their
least
cost
generation
facilities
first,
and
the
IPPs
and
QFs
under
contract
to
utilities
were
not
necessarily
the
lowest
cost
units.
If
EPA
does
not
grant
an
exemption
for
IPPs
and
QFs
substantially
similar
to
the
statutory
exemption
under
the
Acid
Rain
Program,
then
it
should
at
least
modify
the
opt­
in
rules
to
allow
IPPs
and
QFs
to
select
three
years
of
operation
that
are
more
representative
of
the
plant=
s
highest
dispatch
levels.
Nevertheless,
even
if
the
CAIR
affected
IPPs
and
QFs
did
receive
opt­
in
SO2
allowance
allocations
based
on
emission
rates
that
are
more
representative
of
full
capacity
operation,
the
units
would
still
face
significant
SO2
allowance
costs
to
meet
CAIR
reduction
targets
and
such
compliance
costs
would
not
be
able
to
be
passed
through
to
the
purchasing
utilities.
This
is
in
marked
contrast
with
the
purchasing
utility=
s
ability
to
seek
a
full
recovery
of
any
CAIR
SO2
compliance
costs
incurred
by
its
own
generation
units.
[[
(
p.
5)
]]

Response:

The
commenters
claim
that
their
costs
to
comply
with
the
CAIR
SO2
annual
program
are
excessively
high.
The
economics
of
an
IPP
are
different
depending
upon
whether
the
unit
has
a
fixed
price
power
purchase
agreement
in
place
or
whether
it
is
selling
electricity
on
the
wholesale
market.
Units
that
had
power
purchase
agreements
(
PPAs)
with
fixed
prices
in
place
on
November
15,
1990,
are
exempt
from
title
IV
and
do
not
receive
title
IV
allowances.
The
commenters
state
that,
while
their
agreements
are
in
effect,
these
units
are
not
able
to
pass
through
cost
increases,
such
as
the
cost
of
compliance
with
CAIR,
except
where
specific
escalations
are
provided
(
e.
g.,
compensation
for
increases
in
fuel
costs
or
inflation).

While
under
the
agreements
and
exempt
from
title
IV,
the
units
can
opt
into
the
title
IV
program
and
receive
allowances
as
opt­
in
units.
Commenters
claim
that
the
title
IV
opt­
in
provisions
could
allocate
allowances
to
them
at
levels
below
their
projected
emissions
because
the
units
may
operate
more
in
the
future.
The
commenters
add
that
it
is
not
cost
effective
for
the
units
to
reduce
SO2
emissions
by
installing
advanced
emission
controls
because
the
units
already
achieve
significant
reductions
and
have
fixed
price
contracts
that
do
not
allow
them
to
pass
through
control
costs.

The
second
scenario
is
the
period
beginning
when
the
units'
power
purchase
agreements
expire
and
the
units
lose
their
title
IV
exemption.
As
title
IV
affected
units,
they
lose
their
title
IV
optin
status
and
can
no
longer
receive
title
IV
allowances
under
the
title
IV
opt­
in
provisions.
These
units
are
no
longer
locked
into
their
power
purchase
contracts
and
are
free
to
participate
in
the
wholesale
electricity
markets.
The
commenters
contend
that
reducing
emissions
 
even
when
they
are
free
to
pass
through
the
cost
of
compliance
 
is
not
cost­
effective,
because
most
IPPs
already
operate
at
lower
SO2
emission
rates
than
many
other
sources.
This,
however,
belies
the
real
issue,
since
under
a
trading
program,
sources
have
multiple
compliance
options
including
installing
emission
controls,
switching
fuels
or
purchasing
allowances.
If
a
source's
control
costs
are
above
the
marginal
cost
of
control
in
the
region,
the
unit
is
likely
to
comply
by
purchasing
allowances,
thereby
reducing
the
cost
of
control
to
the
market
price.

EPA
disagrees
with
the
commenters'
claim
that
complying
with
the
CAIR
would
result
in
these
units
being
economically
unviable.
The
commenters
provided
only
limited
information
to
support
their
claim.
When
examined
by
EPA
in
greater
detail,
this
commenter­
provided
information
shows
that
these
units
would,
at
a
minimum,
incur
significantly
lower
compliance
costs
than
they
estimate
and
would
generally
continue
to
operate
at
a
profit.
The
commenter
has
not
substantiated
their
claim.
Further,
the
commenter­
provided
information
suggests
that
the
potential
financial
impacts
to
these
units
would
vary
from
unit­
to­
unit
and
does
not
support
providing
an
exemption
for
the
entire
source
category.
In
addition,
EPA
analysis
done
in
the
absence
of
substantial
information
provided
by
the
commenters
(
i.
e.,
the
analysis
of
the
typical
cost
of
production
for
a
CFB
combusting
waste
coal)
indicated
that
IPP
would
continue
to
operate
and
profit,
in
contradiction
to
the
commenters'
claims.
EPA
notes
that
the
commenters
expressed
concern
for
the
potential
compliance
costs
of
the
CAIR
SO2
program
but
not
for
the
CAIR
NOx
annual
and
ozone
season
programs.

Below,
EPA
responds
to
the
commenters'
claims
that
CAIR
will
make
them
economically
unviable
by
considering
(
1)
the
period
of
time
in
which
their
power
purchase
agreements
are
in
effect
and
(
2)
the
period
of
time
after
their
contracts
have
expired.
Additional
discussion
and
supporting
analysis
is
presented
in
the
Technical
Support
Document
for
the
Rule
to
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Clean
Air
Interstate
Rule),
Final
Notice
of
Reconsideration:
IPP
in
the
CAIR
and
CAIR
FIP
(
IPP
in
the
CAIR
and
CAIR
FIP
TSD).

IPPs
with
PPAs
in
Effect
EPA
disagrees
with
the
commenters
claim
that
complying
with
CAIR
would
result
in
these
units
being
economically
unviable
for
the
period
of
time
when
their
PPAs
are
in
effect
and
they
could
receive
allowances
by
opting
into
title
IV.
EPA
believes
that
opting
into
title
IV
can
significantly
offset
potential
compliance
costs.
EPA
analysis
presented
in
the
IPP
in
the
CAIR
and
CAIR
FIP
TSD
supports
EPA's
belief
that
IPP
generally
could
receive
enough
SO2
allowances
to
account
for
their
current
emission
levels
by
opting
into
title
IV.
The
commenters'
analysis
of
the
potential
impacts
of
CAIR
compliance,
and
EPA's
evaluation
of
this
analysis,
is
discussed
below.

EPA
evaluated
the
limited
analysis
submitted
by
the
commenters
to
support
their
claim
that
CAIR
would
make
them
economically
unviable
during
the
period
of
time
when
the
units
have
PPAs
in
effect.
More
specifically,
EPA
evaluated
the
commenters'
analysis
of
the
ratio
of
their
estimated
cost
of
compliance
with
CAIR
to
their
projected
revenue.
As
shown
in
the
IPP
in
the
CAIR
and
CAIR
FIP
TSD,
the
commenter
overestimated
the
ratio
for
their
units
by
an
average
of
493
percent
and
297
percent
in
2010
and
2015,
respectively.
EPA
based
its
recalculation
of
the
estimated
cost
of
compliance
under
CAIR
on
the
unit­
level
emissions
reported
by
the
commenter
and
the
proper
value
for
the
projected
cost
of
emitting
one
ton
of
SO2
under
CAIR
in
2010
and
2015
($
616/
ton
and
$
892/
ton
respectively).
1
These
recalculated
ratios
range
from
under
1%
to
4%.

The
commenter
also
neglected
to
provide
information
on
a
particular
cut­
off
ratio
that
defines
a
point
at
which
the
units
would
become
economically
unviable.
EPA
also
notes
that
consideration
of
cost
to
revenue
ratios
in
the
RIA
is
not
used
as
a
determination
of
economic
viability,
but
rather
as
a
conservative
screening
measure
to
identify
groups
of
units
for
which
the
Agency
should
evaluate
the
potential
financial
impacts.
A
finding
that
a
unit
or
group
of
units
might
have
a
cost
to
revenue
ratio
of
greater
than
3%
does
not
preclude
the
Agency
from
regulating
them,
but
is
used
as
an
means
of
identifying
types
of
units
that
could
be
have
significant
financial
impacts.

EPA
believes
that
analysis
presented
in
today's
rulemaking
(
preamble,
response
to
comment
document,
and
IPP
in
the
CAIR
and
CAIR
FIP
TSD)
demonstrates
that
these
units
would
continue
to
operate
and
could
be
profitable
under
CAIR.
The
commenters
have
not
shown
that
1
The
$
616/
ton
and
$
892/
ton
cost
of
emitting
one
ton
of
SO2
are
projections
from
EPA
modeling
that
includes
the
impacts
of
the
other
programs,
such
as
the
Clean
Air
Mercury
Rule
and
Clean
Air
Visibility
Rule.
the
cost
to
revenue
ratios,
especially
when
recalculated
to
appropriately
account
for
costs,
would
result
in
their
units
being,
as
they
claim,
"
economically
unviable."

In
addition
to
the
evaluation
of
the
cost
to
revenue
ratios,
EPA
further
investigated
the
potential
impacts
of
CAIR
on
IPP
while
their
PPAs
remain
in
effect
by
examining
how
their
contract
prices
might
compare
with
their
potential
costs
to
operate.
An
EPA
search
of
publicly
available
information
produced
a
contract
for
a
Pennsylvania
IPP
that
commenced
operation
in
1993.2
The
contract
indicates
that
the
PPA
agreement
compensates
the
IPP
at
$
62.72
per
MWh
in
1999.3
In
other
words,
this
IPP,
while
being
bound
by
a
fixed
price
contract,
was
being
compensated
at
levels
well
above
their
EPA­
estimated
likely
cost
of
operation
(
discussed
below
and
in
the
IPP
in
the
CAIR
and
CAIR
FIP
TSD)
and
EPA
projected
wholesale
electricity
prices
in
2010
and
2015.
Additional,
limited
information
submitted
by
commenters
also
suggest
that
at
least
some
IPP,
while
constrained
by
their
PPAs,
are
compensated
at
levels
well
above
market
rates
 
rates
that
would
allow
them
to
absorb
compliance
costs.
Specifically,
the
commenter
states
that
one
facility
"
happens
to
have
a
PPA
that
includes
very
attractive
current
energy
prices."
The
commenter
continues
that
when
the
PPA
expires,
"
revenue
is
estimated
to
drop 
with
the
switch
to
market
prices."
In
other
words,
when
this
unit
must
compete
on
the
market,
its
income
will
drop.
This
supports
EPA's
belief
that
at
least
some
IPP
are
well
compensated
by
their
PPAs
and
the
cost
of
complying
with
CAIR
would
not
make
them
economically
unviable.

IPP
After
PPAs
Expire
Because
the
unit­
specific
information
and
analysis
provided
by
the
commenters
was
limited,
EPA
conducted
an
analysis
using
generally
available
information
to
evaluate
the
potential
impact
of
the
cost
of
complying
with
CAIR
for
a
typical
CFB
combusting
waste
coal.
While
this
analysis
was
conducted
to
evaluate
the
potential
financial
impacts
of
complying
with
CAIR
on
units
combusting
waste
coal,
EPA
believes
it
is
applicable
to
IPPs
in
general.
EPA
notes
that
there
may
be
some
slightly
differences
in
the
price
of
fuel
but
the
costs
assumed
in
the
EPA
analysis
should
reasonably
similar
to
those
of
a
typical
IPP
burning
coal.

This
analysis
specifically
applies
to
periods
of
time
when
the
power
purchase
agreements
have
expired
(
i.
e.,
the
units
have
lost
the
exemption
from
title
IV
and
can
not
receive
title
IV
opt­
in
allowances)
and
the
units
are
free
to
participate
in
the
electricity
markets.
This
analysis
examined
how
the
potential
cost
to
operate
a
typical
waste
coal­
fired
CFB
unit
(
including
the
cost
of
complying
with
CAIR)
compares
to
the
potential
price
it
would
receive
on
the
electricity
market.
As
shown
in
table
VI.
A­
1,
the
estimated
cost
of
producing
electricity
for
a
typical
waste
coal­
fired
CFB
would
be
significantly
less
than
the
EPA
projected
wholesale
price
and
the
forecasted
price
of
electricity.
In
other
words,
the
typical
facility
would
produce
electricity,
even
with
the
cost
of
complying
with
CAIR,
at
a
cost
that
below
what
the
market
would
be
willing
to
pay.
In
general,
waste
coal­
fired
facilities
will
continue
to
be
profitable,
even
when
factoring
in
the
cost
of
complying
with
CAIR.

Table
VI.
A­
1:
Costs
of
Operating
a
Typical
CFB
Plant
Burning
Waste
Coal
Components
of
Operating
Costs
Cost
to
Operate
Cost
to
Operate
2
Environmental
Power
Corporation
Form
10­
K
filing
is
located
in
the
docket.
3
Price
is
escalated
to
1999
for
comparison
purposes.
2010
($/
MWh)
2015
($/
MWh)
Variable
O&
M
$
2.11
$
2.11
Fixed
O&
M
$
5.31
$
5.31
Fuel
Cost
$
7.28
$
7.20
SO2
Allowance
Cost
$
1.53
$
2.17
NOx
Allowance
Cost
$
0.77
$
0.95
Total
Operating
Cost*
$
17.00
$
17.74
Base
Case
Wholesale
Electricity
Price**
$
25.43
$
33.46
CAIR
Wholesale
Electricity
Price**
$
27.10
$
36.06
*
The
total
operating
cost
estimate,
as
well
as
component
costs,
are
described
in
the
TSD
IPP
in
the
CAIR
and
CAIR
FIP.
**
IPM
projected
wholesale
electricity
prices
in
the
under
the
Base
Case
and
CAIR
(
EPA
2006).

Other
Considerations
While
EPA
evaluated
the
commenters'
claims
by
analyzing
the
potential
financial
impacts
of
complying
with
the
CAIR
SO2
annual
program
only
and
found
no
basis
on
record
for
the
commenters
claims
of
being
economically
unviable,
EPA
believes
that
there
are
other
consideration
that
can
influence
the
economic
viability
(
i.
e.,
whether
they
will
cease
to
operate)
of
the
plants.
First,
the
CAIR
includes
two
NOx
control
programs
 
one
annual
and
one
summertime
 
that
each
provide
CAIR
allowance
budgets
that
States
can
allocate
to
any
units
they
wish.
(
EPA
notes
that
these
units
have
not
expressed
concern
over
the
cost
of
compliance
with
either
of
the
CAIR
NOx
programs.)
In
addition,
coal­
fired
units
(
including
units
fired
with
waste
coal)
can
receive
mercury
allowances
under
the
Clean
Air
Mercury
Rule
(
CAMR).
Allowances
from
all
three
programs
(
the
CAIR
NOx
annual
program,
the
CAIR
NOx
ozone
season
program,
and
the
CAMR)
are
valuable
commodities
and
can
provide
mechanisms
for
States
wishing
to
encourage
certain
types
of
generation
to
do
so.
Finally,
there
are
environmental
programs,
outside
of
the
CAIR
and
CAMR
programs,
that
also
provide
benefit
to
these
IPP
and
could
be
considered
in
the
overall
viability
of
the
plants.
One
example
is
the
potential
benefits
of
IPP
generating
renewable
energy
credits
(
RECs)
as
part
of
statewide
renewable
portfolio
standards
(
RPSs).
In
Pennsylvania,
where
some
of
the
commenters'
units
are
located,
an
IPP
can
generate
valuable
RECs.
When
taken
as
a
whole,
these
other
factors
in
a
IPP
environmental
compliance
costs
could
provide
significant
benefit
to
these
units.

In
summary,
EPA
does
not
agree
with
commenters
that
believe
that
complying
with
the
CAIR
FIP
or
CAIR
SO2
annual
program
or
would
result
in
this
category
of
units
being
economically
unviable.
EPA
rationale
for
this
is
described
in
the
CAIR
FIP
NFR
preamble,
this
response,
and
the
IPP
in
the
CAIR
and
CAIR
FIP
TSD.
This
response
provides
additional
discussion
of
the
EPA
evaluation
of
the
commenters'
analysis
of
the
unit­
specific
cost
to
revenue
ratios
as
well
as
the
EPA's
analysis
of
estimated
cost
of
typical
waste
coal­
fired
CFB.
The
evaluation
of
the
commenters'
analysis,
provided
to
support
their
claim
of
economic
burden
for
periods
of
time
when
the
IPP
have
PPAs
in
effect,
indicated
that
they
had
significantly
overestimated
the
cost
of
complying
with
CAIR
and,
as
a
result,
did
substantiate
their
claim.
In
addition,
EPA's
analysis
of
a
typical
unit
showed
that,
when
the
units'
PPA
have
expired,
the
units
would
likely
operate
and
continue
to
make
a
profit
once
they
were
free
to
enter
the
electricity
markets.
For
these
reasons,
EPA
has
not
included
an
exemption
for
IPP
or
IPPs
in
the
CAIR
FIP
or
CAIR
trading
programs.

XVIII.
F.
3
Document
No.:
OAR­
2003­
0053­
2282.1
Commenter:
South
Carolina
Public
Service
Authority
and
JEA
Comment:
The
Notice
of
Reconsideration
explains
that
EPA
is
assuming
that,
under
an
Acid
Rain
Programbased
SO2
trading
system,
companies
owning
non­
Acid
Rain
units
subject
to
CAIR
would
opt
into
the
Acid
Rain
Program
in
order
to
receive
allowances
to
cover
their
units=
emissions
under
CAIR.
EPA
further
assumes
that
companies
that
own
both
non­
CAIR
and
CAIR
units
would
transfer
Acid
Rain
Program
allowances
from
the
former
to
the
latter.
EPAs
data
for
2010
show
surrender
of
25,000
allowances
from
title
IV
opt­
in
units
and
131,000
allowances
acquired
by
companies
from
their
non­
CAIR
EGUs.
These
actions
would
not
be
possible
under
alternative
allocation
methods
that
do
not
make
use
of
title
IV
allowances.
[[
Docket
number
2282.1,
p.
16]][[
See
docket
number
2282.1,
pp.
16­
17
for
further
discussion
of
this
issue.]]

Response:
See
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A,
"
Potential
for
Regional
Emissions
Increases."
It
should
be
noted
that
EPA
estimates
that
if
the
Agency
were
to
not
use
the
title
IV
approach,
there
would
be
approximately
260,000
title
IV
allowances,
representing
that
many
tons
of
SO2
emissions,
that
sources
in
non­
CAIR
States
would
have
incentive
to
use
to
cover
emissions
at
little
to
no
cost
(
an
increase
equal
to
about
30
percent
of
the
0.9
million
tons
of
emissions
EPA
projects
for
non­
CAIR
region).
This
increase
would
occur
because
title
IV
allowances
would
have
no
economic
value.

XVIII.
F.
4
Document
No.:
OAR­
2003­
0053­
2301
Commenter:
Pennsylvania
Department
of
Environmental
Protection
(
PADEP)
Comment:
EPA=
s
CAIR
affects
units
that
are
exempt
from
the
Acid
Rain
Program
and,
therefore,
were
not
issued
SO2
allowances.
Requiring
these
units
to
hold
SO2
allowances
under
CAIR
will
cause
the
owners
or
operators
severe
and
irreversible
financial
damage
owing
to
the
fact
that
these
units
produce
power
and
steam
under
long­
term,
fixed­
price
contracts
that
cannot
be
adjusted
to
compensate
for
the
costs
of
complying
with
the
CAIR.
[[
(
p.
1)
]]
EPA
assumed
that
these
units
might
be
able
to
opt­
in,
but
this
is
incorrect
for
these
units.
EPA
also
chose
to
exempt
Municipal
Waste
Combustors
(
MWC)
that
meet
the
criteria
as
affected
units
based
on
the
fact
that
a
proper
cost­
effectiveness
analysis
was
not
conducted.
Similarly,
EPA
has
failed
to
properly
evaluate
cost­
effectiveness
of
cogeneration
units
and
waste
coal
combustors
that
cannot
control
emissions
any
more
cost­
effectively
than
the
MWCs.
Either
MWCs
should
be
affected
or
waste
coal
combustors
should
also
be
exempted.
[[
(
pp.
1­
2)
]]
EPA=
s
position
is
unsustainable.
It
is
highly
inequitable
to
issue
allowances
to
one
set
of
generators
and
require
a
50%
reduction,
while
as
a
result
of
having
issued
them
no
allowances
effectively
impose
a
100%
reduction
on
the
waste
coal
combustors
and
cogeneration
units.
EPA=
s
contention
that
these
facilities
have
subsidiary
relationships
from
which
to
draw
allowances
is
incorrect.
The
underlying
justification
for
the
control
strategy
is
that
it
presumes
the
trading
program
distributes
compliance
costs
among
units
and
does
not
create
inequitable
and
energy
market
competitive
distortions­
in
this
case
unallocated
units
are
forced
to
bear
highly
disproportionate
compliance
costs,
thereby
providing
a
significant
competitive
advantage
to
allocated
units.
[[
(
p.
2)
]]
In
addition,
the
SO2
emissions
from
these
units
were
not
included
in
the
original
Acid
Rain
Program.
Therefore,
their
emissions
are
in
excess
of
the
budget
set
by
the
Acid
Rain
Program.
Congress
effectively
authorized
the
emissions
by
not
including
these
units
in
the
Acid
Rain
Program.
EPA
can,
therefore,
either
add
these
emissions
to
the
CAIR
SO2
budget
and
issue
the
units
allowances,
or
exempt
the
units
from
CAIR.
In
either
case,
EPA
could
increase
the
retirement
ratio
from
existing
Acid
Rain
units
to
achieve
the
level
of
reductions
needed
by
the
CAIR.
The
small
adjustment
would
not
upset
the
cost
effectiveness
of
CAIR
compliance
for
existing
Acid
Rain
units,
while
it
would
alleviate
the
severe
financial
harm
the
CAIR
imposes
on
non­
Acid
Rain
units.
[[
(
p.
2)
]]
Waste
coal
burners
and
cogeneration
units
that
were
not
included
in
the
Acid
Rain
Program
did
not
fall
under
the
original
Acid
Rain
cap.
By
bringing
them
into
the
CAIR
program
without
issuing
them
SO2
allowances,
EPA
has
imposed
upon
them
standards
and
requirements
not
placed
on
any
other
existing
facility
under
CAIR.
The
units
are
relatively
clean
and
provide
a
useful
environmental
benefit
to
Pennsylvania
by
cleaning
up
old
waste
coal
piles.
The
Commonwealth
strongly
urges
EPA
to
exempt
these
units
from
CAIR
requirements
or
allocate
SO2
allowances
under
CAIR.
[[
(
p.
3)
]]

Response:

See
response
to
comment
XVIII.
A.
1
and
XVIII.
E.
4,
as
well
as
the
CAIR
FIP/
126
Response
to
Comments,
Section
VI.
A.

Also,
EPA
further
investigated
the
potential
impacts
of
CAIR
on
waste
coal­
fired
units
while
their
PPAs
remain
in
effect
by
examining
how
their
contract
prices
might
compare
with
their
potential
costs
to
operate.
An
EPA
search
of
publicly
available
information
produced
a
contract
for
a
Pennsylvania
waste
coal­
fired
facility
that
commenced
operation
in
1993.
Environmental
Power
Corporation
Form
10­
K
filing
is
located
in
the
docket.
The
contract
indicates
that
the
PPA
agreement
compensates
the
waste
coal­
fired
facility
at
$
62.72
per
MWh
in
1999.
Price
is
escalated
to
1999
for
comparison
purposes.
In
other
words,
this
waste
coal­
fired
facility,
while
being
bound
by
a
fixed
price
contract,
was
being
compensated
at
levels
will
above
their
EPA­
estimated
likely
cost
of
operation
(
discussed
below
and
in
the
Waste
Coal­
Fired
Units
in
the
CAIR
and
CAIR
FIP
TSD)
and
EPA
projected
wholesale
electricity
prices
in
2010
and
2015.
Additional,
limited
information
submitted
by
commenters
also
suggest
that
at
least
some
waste
coal­
fired
units,
while
constrained
by
their
PPAs,
are
compensated
at
levels
well
above
market
rates
 
rates
that
would
allow
them
to
absorb
compliance
costs.
Specifically,
the
commenter
states
that
one
facility
"
happens
to
have
a
PPA
that
includes
very
attractive
current
energy
prices."
The
commenter
continues
that
when
the
PPA
expires,
"
revenue
is
estimated
to
drop 
with
the
switch
to
market
prices."
In
other
words,
when
this
unit
must
compete
on
the
market,
its
income
will
drop.
This
supports
EPA's
belief
that
at
least
some
waste
coal­
fired
units
are
well
compensated
by
their
PPAs
and
the
cost
of
complying
with
CAIR
would
not
make
them
economically
unviable.
Document
No.:
OAR­
2003­
0053­
2288.1
Commenter:
GE
Energy
Financial
Services
Comment:
In
the
December
2,
2005
notice
announcing
the
reconsideration
of
the
four
CAIR
issues,
EPA
noted
that
its
analysis
of
the
CAIR
SO2
methodology
considered
the
allocation
of
Title
IV
SO2
allowances
to
electric
generating
units
not
currently
in
the
Acid
Rain
Program
through
the
voluntary
opt­
in
provisions.
The
agency
seems
to
assume
that
voluntary
opt­
in
would
eliminate
any
undue
hardship
on
IPPs
and
QFs
that
opt­
in
to
the
Acid
Rain
Program
by
providing
an
allocation
of
a
certain
amount
of
SO2
opt­
in
allowances.
The
voluntary
opt­
in
option
is
not
a
sufficient
solution
and
would
generally
result
in
the
allocation
of
a
wholly
inadequate
number
of
allowances
to
IPPs
and
QFs
for
the
following
reason.
[[
(
2288.1,
p.
4)
]]
Under
the
EPA
opt­
in
regulations,
the
allocation
of
allowances
would
be
based
on
the
SO2
emissions
of
the
units
during
the
first
three
calendar
years
of
their
operation,
and
during
this
period
many
of
the
units
were
dispatched
by
the
purchasing
utilities
on
a
reduced
basis
when
compared
to
the
more
current
dispatch
levels.
Under
the
fixed
price
formula
PPAs,
the
IPPs
and
QFs
are
compensated
by
(
i)
a
fixed
capacity
price
that
is
tied
to
minimum
dispatch
availability
requirements
and
(
ii)
a
variable
energy
price
that
is
linked
to
the
amount
of
electricity
that
is
actually
dispatched
and
a
pass
through
on
the
costs
of
fuel
to
generate
that
electricity.
The
Public
Utilities
Regulatory
Policy
Act
of
1978
mandated
that
utilities
enter
into
electricity
offtake
contracts
with
IPPs
and
QFs,
but
they
did
not
mandate
that
the
plants
had
to
be
dispatched
at
near
full
capacity
levels.
Utilities
generally
will
dispatch
their
least
cost
generation
facilities
first,
and
the
IPPs
and
QFs
under
contract
to
utilities
were
not
necessarily
the
lowest
cost
units.
If
EPA
does
not
grant
an
exemption
for
IPPs
and
QFs
substantially
similar
to
the
statutory
exemption
under
the
Acid
Rain
Program,
then
it
should
at
least
modify
the
apt­
in
rules
to
allow
IPPs
and
QFs
to
select
three
years
of
operation
that
are
more
representative
of
the
plant=
s
highest
dispatch
levels.
Of
course,
even
if
the
CAIR
affected
IPPs
and
QFs
did
receive
opt­
in
SO2
allowance
allocations
based
on
emission
rates
that
are
more
representative
of
full
capacity
operation,
the
units
would
still
face
significant
SO2
allowance
costs
to
meet
CAIR
reduction
targets
and
such
compliance
costs
would
not
be
able
to
be
passed
through
to
the
purchasing
utilities.
This
is
in
marked
contrast
with
the
purchasing
utility=
s
ability
to
seek
a
full
recovery
of
any
CAIR
SO2
compliance
costs
incurred
by
its
own
generation
units."
[[
(
2288.1,
p.
5)
]]

Response:
See
response
to
comment
XVIII.
F.
2.

XVIII.
F.
6
Document
No.:
OAR­
2003­
0053­
2269.1
Commenter:
AES
Corporation
Comment:
At
70
Fed.
Reg.
72273
of
the
Notice
of
Reconsideration,
EPA
states
>
This
analysis
assumed
that
companies
owning
non­
Acid
Rain
units
affected
by
CAIR
would
opt
into
the
Acid
Rain
Program
because
they
would
receive
title
TV
allowances
to
cover
a
portion
of
the
unit=
s
emissions
under
CAIR=
[[
Docket
number
2269.1,
p.
3]]
While
this
option
may
appear
to
be
a
solution
to
the
problem
created
by
EPA=
s
failure
to
recognize
and
honor
the
Congressional
determination
to
exempt
these
facilities
from
the
SO2
cap
and
trading
program,
it
would
provide
significantly
fewer
allowances
than
these
units
would
need
to
operate.
Two
examples
illustrate
the
inadequacy
of
this
option:
[[
Docket
number
2269.1,
p.
3]]
i.
A
unit
that
commenced
operation
after
January
1,
1985
(
e.
g.,
Warrior
Run)
would
have
its
Title
IV
opt­
in
allocation
calculated
based
on
heat
input,
sulfur
content
and
fuel
consumption
for
its
first
three
years
of
operation,
and
its
actual
emission
rate
(
which
should
be
lower
than
its
allowable
emission
rate).
Therefore,
it
would
get
an
allocation
roughly
equivalent
to
its
current
emissions.
With
this
allocation
it
would
be
granted
only
50%
and
35%
of
the
allowances
needed
for
compliance
in
Phase
1
and
2
of
CAIR,
respectively,
due
to
the
rule=
s
2:
l
and
2.86:
l
surrender
ratios.
[[
Docket
number
2269.1,
p.
3]]
ii.
For
units
that
commenced
operating
prior
to
January
1,
1985,
the
data
used
to
determine
baseline
conditions
are
1985,
1986
and
1987.
This
is
the
situation
for
Beaver
Valley.
However,
not
only
does
the
allowance
shortfall
outlined
above
exist,
but
the
plant=
s
utilization
rate
during
those
years
is
not
representative
of
subsequent
year,
or
current
operations.
Therefore,
Beaver
Valley=
s
allocation
under
the
opt­
in
scenario
would
be
significantly
lower
than
the
50%
and
35%
of
actual
SO2
emissions
allocation
outlined
above.
The
Acid
Rain
opt­
in
regulations
do
not
allow
for
alternative
baseline
years
to
be
used
to
rectify
this
type
of
situation.
[[
Docket
number
2269.1,
p.
3]]
These
units
are
well
controlled,
with
low
SO2
emission
rates.
While
the
Title
IV
opt­
in
provision
would
provide
some
allowances,
the
actual
number
would
be
very
small
compared
to
the
plants=
need.
This
would
result
in
the
inequitable
situation
where
well
controlled,
low
emitting
units
with
contract
prices
that
were
set
before
passage
of
the
CAA
Amendments
of
1990
(
therefore,
having
no
opportunity
of
cost
passthrough)
would
need
to
buy
allowances,
when
comparable
or
even
higher
emitting
units
(
most
with
the
ability
to
passthough
new
compliance
costs)
may
even
have
excess
allowances
to
sell.
It
is
hard
to
see
where
this
was
the
intent
of
CAIR.
[[
Docket
number
2269.1,
pp.
3­
4]]
Accordingly,
AES
believes
that
CAIR
needs
to
be
revised
to
continue
the
Title
IV
SO2
exemption
that
Congress
enacted
for
IPPs
under
long­
term
contracts
that
was
in
place
previously
for
both
the
legal
and
equity
reasons
identified
above.
[[
Docket
number
2269.1,
p.
4]]

Response:
See
responses
to
comment
XVIII.
A.
1
and
XVIII.
F.
2,
FIP/
126
final
rule,
Section
VI.
E.,
and
FIP/
126
response
to
comments,
Section
VI.
A.

XVIII.
F.
7
Document
No.:
OAR­
2003­
0053­
2287.1
Commenter:
Birchwood
Power
Partners,
L.
P.
Comment:
In
the
December
2,2005
notice
announcing
the
reconsideration
of
the
four
CAIR
issues,
EPA
noted
that
its
analysis
of
the
CAIR
SO2
methodology
considered
the
allocation
of
Title
IV
SO2
allowances
to
electric
generating
units
not
currently
in
the
Acid
Rain
Program
through
the
voluntary
opt­
in
provisions.
The
agency
seems
to
assume
that
voluntary
opt­
in
would
eliminate
any
undue
hardship
on
IPPs
and
QFs
that
opt­
in
to
the
Acid
Rain
Program
by
providing
an
allocation
of
a
certain
amount
of
SO2
opt­
in
allowances.
The
voluntary
opt­
in
option
is
not
a
sufficient
solution
and
would
generally
result
in
the
allocation
of
a
wholly
inadequate
number
of
allowances
to
IPPs
and
QFs
for
the
following
reason.
[[
(
2287.1,
p.
5)
]]
Under
the
EPA
opt­
in
regulations,
the
allocation
of
allowances
would
be
based
on
the
SO2
emissions
of
the
units
during
the
first
three
calendar
years
of
their
operation,
and
during
this
period
many
of
the
units
were
dispatched
by
the
purchasing
utilities
on
a
reduced
basis
when
compared
to
the
more
current
dispatch
levels.*
Under
the
fixed
price
formula
PPAs,
the
IPPs
and
QFs
are
compensated
by
(
i)
a
fixed
capacity
price
that
is
tied
to
minimum
dispatch
availability
requirements
and
(
ii)
a
variable
energy
price
that
is
linked
to
the
amount
of
electricity
that
is
actually
dispatched
and
a
pass
through
on
the
costs
of
fuel
to
generate
that
electricity.
The
Public
Utilities
Regulatory
Policy
Act
of
1978
mandated
that
utilities
enter
into
electricity
offtake
contracts
with
IPPs
and
QFs,
but
they
did
not
mandate
that
the
plants
had
to
be
dispatched
at
near
full
capacity
levels.
Utilities
generally
will
dispatch
their
least
cost
generation
facilities
first,
and
the
IPPs
and
QFs
under
contract
to
utilities
were
not
necessarily
the
lowest
cost
units.
During
the
first
three
calendar
years
of
operation,
the
Birchwood
Power
facility
was
dispatched
at
capacity
rates
that
were
not
nearly
as
high
as
dispatch
rates
in
more
recent
years,
and
the
plant
would
be
disadvantaged
by
using
its
early
years
of
operation
as
an
opt­
in
baseline.
[[
(
2287.1,
p.
5)
]]
If
EPA
does
not
grant
an
exemption
for
IPPs
and
QFs
substantially
similar
to
the
statutory
exemption
under
the
Acid
Rain
Program,
then
it
should
at
least
modify
the
option
rules
to
allow
IPPs
and
QFs
to
select
three
years
of
operation
that
are
more
representative
of
the
plant=
s
highest
dispatch
levels.
Nevertheless,
even
if
the
CAIR
affected
IPPs
and
QFs
did
receive
out­
in
SO2
allowance
allocations
based
on
emission
rates
that
are
more
representative
of
full
capacity
operation,
the
units
would
still
face
significant
SO2
allowance
costs
to
meet
CAIR
reduction
targets
and
such
compliance
costs
would
not
be
able
to
be
passed
through
to
the
purchasing
utilities.
This
is
in
marked
contrast
with
the
purchasing
utility=
s
ability
to
seek
a
full
recovery
of
any
CAIR
SO2
compliance
costs
incurred
by
its
own
generation
units.
[[
(
2287.1,
p.
5)
]]

Response:
See
response
to
comment
XVIII.
F.
2.

XVIII.
G.
Comments
on
late
notice
of
data
corrections
documents
[
There
are
no
comments
in
this
section.]

XVIII.
H.
General
XVIII.
H.
1
Document
No.:
OAR­
2003­
0053­
2268.1
Commenter:
Northeast
States
for
Coordinated
Air
Use
Management
(
NESCAUM)
Comment:
Sulfur
dioxide
(
SO2)
allocation
methodology
in
the
Clean
Air
Interstate
Rule
(
CAIR)
model
trading
rules:
EPA
has
asked
for
comment
on
analyses
conducted
of
its
SO2
allocation
methodology.
EPA
has
relied
on
the
use
of
Title
IV
(
Acid
Rain
Program)
SO2
allowances
for
the
CAIR
model
trading
program.
As
stated
in
previous
comments,
we
do
not
support
EPA=
s
choice
to
use
the
Acid
Rain
Program
as
the
vehicle
to
implement
CAIR.
Notwithstanding,
EPA
should
establish,
and
explicitly
allow
States
to
establish,
higher
retirement
ratios
than
those
promulgated
for
SO2
and
NOx
in
order
for
additional
reductions
to
occur
and
to
help
States
meet
their
attainment
and
transport
obligations
as
required
under
section
110(
a)
of
the
Clean
Air
Act.
[[
(
2268.1,
p.
1)
]]

Response:
EPA's
legal
authority
to
use
title
IV
allocations
under
CAIR
and
its
reasons
for
doing
so
are
discussed
in
the
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A.
EPA
did
not
open
for
reconsideration
the
cap
levels
for
SO2.

Document
No.:
OAR­
2003­
0053­
2282.1
Commenter:
South
Carolina
Public
Service
Authority
and
JEA
Comment:
South
Carolina
Public
Service
Authority
and
JEA
are
supportive
of
most
aspects
of
the
CAIR,
including
the
CAIR=
s
overall
environmental
objective
to
reduce
interstate
transport
of
fine
particles
and
ozone
through
regional
emission
limits.
However,
South
Carolina
Public
Service
Authority
and
JEA
are
strongly
opposed
to
one
key
element
of
the
CAIR
implementation
framework:
EPA=
s
approach
of
using
the
statutory
title
IV
Acid
Rain
Program
to
implement
the
CAIR
sulfur
dioxide
(
SO2)
reduction
requirements
and
the
CAIR
SO2
model
trading
program.
[[
Docket
number
2282.1,
p.
2]]
Another
serious
oversight
in
EPA=
s
new
analysis
is
the
omission
of
any
evaluation
of
the
environmental
impacts
associated
with
the
different
allowance
allocation
methodologies.
[[
Docket
number
2282.1,
p.
16]]

Response:
EPA
appreciates
the
commenter's
support
for
most
aspects
of
the
CAIR,
including
the
overall
environmental
objective
to
reduce
interstate
transport
of
fine
particles
and
ozone
through
regional
emission
limits.
Responses
to
their
concerns
about
the
SO2
allocations
approach
used
in
CAIR
and
the
environmental
impacts
related
are
discussed
in
the
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A.,
and
in
response
to
comment
XVIII.
C.
3.

XVIII.
H.
3
Document
No.:
OAR­
2003­
0053­
2271.1
Commenter:
National
Mining
Association
Comment:
[[
This
comment
also
applies
to
Outline
Heading
XIX.
G.
]]
NMA=
s
comments
are
specific
to
two
issues:
the
fuel
adjustment
factors
used
to
set
state
NOx
budgets
and
the
SO2
allocation
methodology
in
the
CAIR
model
trading
rule.
As
detailed
in
the
attached,
in
each
case
EPA
has
applied
a
reasonable
allocation
methodology
that
is
consistent
with
statutory
requirements.
EPA
should
not
make
any
changes
to
the
CAIR
as
a
result
of
its
reconsideration
of
these
issues.
[[
(
2271.1,
p.
1)
]][[
This
comment
also
applies
to
Outline
Heading
XIX.
G.
]]
NMA=
s
comments
focus
on
the
following
issues:
(
1)
Fuel
Adjustment
Factors
Used
To
Set
State
NOx
Budgets
and
(
2)
SO2
Allocation
Methodology
in
the
CAIR
Model
Trading
Rules.
In
each
case
NMA
believes
that
EPA
should
not
make
any
changes
to
the
CAIR
as
a
result
of
its
reconsideration
of
those
issues.
However,
NMA
urges
EPA
to
provide
additional
rationale
with
respect
to
both
the
NOx
and
SO2
issues
along
the
lines
set
forth
in
these
NMA
comments
and
as
EPA
may
otherwise
develop.
[[
(
2271.1,
pp.
2­
3)
]]
With
respect
to
the
SO2
Allocation
Methodology,
NMA
believes
the
CAIR
final
allocation
methodology
represents
a
reasonable
interpretation
of
the
statutory
mandate
to
prohibit
SO2
emissions
in
any
state
from
contributing
significantly
to
fine
particle
nonattainment
in
another
state.
[[
(
2271.1,
p.
3)
]]

Response:
EPA
thanks
the
commenter
for
supporting
the
aspects
of
CAIR
mentioned
above.
Additional
rationale
for
NOx
State
budgets
can
be
found
in
the
Notice
of
Final
Action
on
Reconsideration,
Section
III.
B,
as
well
as
Section
XIX
of
this
RTC.
Further
rationale
for
SO2
allocations
can
be
found
in
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A.

XVIII.
H.
4
Document
No.:
OAR­
2003­
0053­
2279.1
Commenter:
Midwest
Generation
Comment:
[[
This
comment
also
applies
to
Outline
Heading
XIX.
G.
]]
Midwest
Generation
continues
to
support
EPA=
s
final
Clean
Air
Interstate
Rule,
generally,
and
EPA=
s
inclusion
of
a
cap­
and­
trade
compliance
alternative,
in
particular.
Midwest
Generation
supports
the
implementation
of
a
market­
based
approach
as
the
most
efficient,
cost­
effective
means
for
achieving
sizeable
reductions
in
NOx
and
SO2
emissions.
As
set
forth
in
the
final
rule,
the
two­
phase
CAIR
trading
program
will
assist
downwind
states
with
attaining
and
maintaining
applicable
PM2.5
and
8­
hour
ozone
National
Ambient
Air
Quality
Standards
(>
NAAQS=)
by
requiring
states
in
the
CAIR
region
to
cap
emissions
of
the
relevant
precursor
emissions
­
namely,
SO2
and
NOx.
According
to
EPA=
s
estimates,
the
final
CAIR=
s
Phase
II
caps
reflect
emissions
reductions
equal
to
3.8
million
tons
for
SO2
and
1.5
million
tons
for
NOx.
[[
(
2279.1,
p.
3)
]]
The
implementation
of
a
CAIR
trading
program
­
integrated
with
other
air
quality
programs
such
as
Title
IV=
s
Acid
Rain
program
and
the
NOx
SIP
Call
­
represents
a
thoughtful,
reasoned
approach
for
maximizing
air
quality
benefits
at
minimized
costs.
Under
the
CAIR
trading
program,
important
environmental
benefits
will
be
secured
by
way
of
caps
that
limit
emissions
­
absolutely.
In
contrast
to
command­
and­
control
regulation,
CAIR=
s
cap­
and­
trade
program
places
absolute
limits
on
SO2
and
NOx
emissions.
And
the
Phase
II
cap
will
not
give
way
to
the
upward
pressures
of
a
growing
power
generation
sector.
If
power
generation
increases
such
that
emissions
threaten
to
exceed
the
caps,
sources
will
have
to
compensate
by
achieving
increasingly
stringent
emissions
rates.
[[
(
2279.1,
p.
3)
]]
The
model
trading
program
will
give
sources
an
economic
incentive
for
achieving
reductions
greater
than
those
required
by
the
CAIR.
Thus,
sources
that
can
implement
emissions
control
cost
effectively
will
be
encouraged
to
reduce
emissions
beyond
the
requirements
of
the
final
CAIR
to
generate
emissions
credits
which
owners
can
sell
or
use
to
bring
other
of
their
sources
under
control.
Also,
financial
incentives
created
by
the
CAIR
trading
program
will
spur
the
innovation
of
increasingly
effective
and
efficient
control
technology
­
sources
will
more
readily
experiment
with
unproven
approaches
to
emissions
control
because
they
will
have
a
means
of
compliance
should
their
investment
in
new
technology
fail.
Finally,
the
compliance
flexibility
that
CAIR=
s
cap­
and­
trade
program
provides
will
enhance
overall
compliance
rates
as
such
programs
have
in
the
past.
[[
(
2279.1,
pp.
3­
4)
]]
Based
on
the
foregoing,
Midwest
Generation
affirms
its
support
for
EPA=
s
final
CAIR
as
a
sound
strategy
for
emissions
reduction
in
the
eastern
United
States.
EPA
should
not
reconsider
its
fundamental
approach
­
specifically,
the
inclusion
of
a
cap­
and­
trade
compliance
mechanism
­
when
it
reconsiders
other
aspects
of
the
final
rule
in
response
to
the
Petitions
for
Reconsideration.
[[
(
2279.1,
p.
4)
]]

Response:
EPA
appreciates
the
commenter's
support
for
CAIR.
Through
the
final
Reconsideration
action,
EPA
maintains
the
cap­
and­
trade
system
as
defined
in
the
final
CAIR
(
70
FR
25161).

XVIII.
H.
5
Document
No.:
OAR­
2003­
0053­
2301
Commenter:
Pennsylvania
Department
of
Environmental
Protection
(
PADEP)
Comment:
The
final
outcome
of
EPA=
s
reconsideration
on
two
aspects
of
the
final
rule
will
have
significant
impacts
on
Pennsylvania.
The
financial
harm
of
failing
to
exempt
or
allocate
SO2
allowances
to
previously
exempted
cogeneration
units
and
waste
coal
burners
will
result
in
the
inability
of
Pennsylvania
to
efficiently
and
effectively
clean
up
waste
coal
piles
throughout
the
state.
[[
(
p.
1)
]]

Response:
See
responses
to
comment
XVIII.
A.
1,
and
XVIII.
E.
4,
FIP/
126
final
rule,
Section
VI.
E.,
and
FIP/
126
response
to
comments,
Section
VI.
A.
PADEP
did
not
provide
any
evidence
of
their
allegations
and
EPA's
analysis
shows
the
contrary.

XVIII.
H.
6
Document
No.:
OAR­
2003­
0053­
2270.1
Commenter:
Tennessee
Valley
Authority
(
TVA)
Comment:
[[
This
comment
also
applies
to
Outline
Heading
XIX.
G.
]]
CAIR
imposes
a
significant
challenge
to
utilities.
It
requires
steep
reductions
in
SO2
and
NOx
emissions
on
a
very
tight
schedule.
It
is
a
challenge
that
TVA
is
prepared
to
meet
and
is
meeting.
We
continue
to
support
CAIR
as
promulgated.
TVA
does
not
support
changing
CAIR
as
requested
by
the
reconsideration
petitions
to
which
EPA
is
responding.
We
want
to
re­
emphasize
our
position
on
two
of
the
issues
raised
in
this
reconsideration.
[[
(
2270.1,
p.
1)
]]
The
SO2
allocation
method
established
by
the
final
rule
.
.
.
is
based
on
that
used
in
EPA=
s
highly­
successful
Title
IV
program
for
acid
rain.
It
is
a
method
chosen
by
Congress
and
using
it
for
CAIR
is
consistent
with
congressional
policies.
This
allocation
method
provides
for
the
permanent
allocation
of
SO2
allowances.
The
permanent
allocation
of
SO2
allowances
facilitates
utility
system
planning
and
provides
an
incentive
to
retire
older,
less
efficient
generating
units.
Replacing
the
established
allocation
method
would
also
undermine
completed
and
ongoing
state
rulemakings
implementing
CAIR
that
are
based
on
that
method.
EPA
should
retain
CAIR=
s
SO2
allocation
method.
[[
(
2270.1,
p.
1)
]]

Response:
EPA
appreciates
the
commenter's
support
for
CAIR
and
the
SO2
allocation
approach
as
finalized.
Through
this
Notice
of
Final
Action
on
Reconsideration,
EPA
is
not
altering
the
SO2
allocations
approach.

XVIII.
I.
Comments
incorporated
by
reference
XVIII.
I.
1
Document
No.:
OAR­
2003­
0053­
2282.1
Commenter:
South
Carolina
Public
Service
Authority
and
JEA
Comment:
Last
year,
South
Carolina
Public
Service
Authority
and
JEA
provided
EPA
with
a
more
detailed
analysis
of
some
of
these
issues
in
comments
filed
in
the
proceeding
on
EPA=
s
proposed
rule
to
address
North
Carolina=
s
Section
126
petition
and
to
establish
CAIR
Federal
Implementation
Plans.
A
copy
of
the
companies=
comments
from
that
proceeding
is
provided
in
Attachment
A
to
these
comments.
[[
Docket
number
2282.1,
p.
2]]
See
docket
number
2282.1,
pp
22­
28
for
Attachment
A.]]

Response:
See
CAIR
FIP/
126
final
rule,
Section
VI.
G,
and
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A.
In
order
to
accentuate
this
point,
EPA
has
examined
the
total
costs
for
the
three
example
units
brought
up
by
this
commenter
(
see
docket
OAR­
2003­
0053­
2282.1
Appendix
A).
These
three
units
are
supposed
to
represent
(
1)
a
unit
that
was
clean
early
and
was
included
in
Title
IV,
(
2)
a
similar
sized
unit
that
was
dirty
under
Title
IV
but
installs
FGD
for
CAIR,
and
(
3)
a
new
clean
unit.
While
the
commenter's
allowance
cost
estimations
may
be
reasonable,
the
overall
cost
impact
is
significantly
off,
since
the
commenter
did
not
examine
capital
costs
associated
installation
of
the
new
FGD.
For
this
reason,
EPA
has
performed
a
more
accurate
cost
estimation
for
the
commenter's
three
examples,
the
results
of
which
are
shown
in
the
table
below.
Based
on
these
numbers,
EPA
concludes
that
the
old
previously
uncontrolled
EGU
will
bear
the
greater
cost
for
CAIR
compliance
than
previously
controlled
EGUs
and
new
clean
EGUs
because
of
the
incremental
expenses
of
installing
and
operating
an
FGD.
This
runs
counter
to
the
commenters'
conclusion.
(
See
Memo
from
Barry
Galef
and
Jason
Lee,
ICF
Consulting,
March
14,
2006
(
Docket:
EPA­
HQ­
OAR­
2003­
0053).

Net
Impact
of
the
Combined
Costs
Example
1
Example
2
Example
3
Net
Impact
of
the
Combined
Costs
Phase
1
($/
MWh)
$
0.68
$
1.18
­
$
3.68
$
0.41
Net
Impact
of
the
Combined
Costs
Phase
2
($/
MWh)
$
1.30
$
2.07
­
$
4.73
$
0.60
XVIII.
I.
2
Document
No.:
OAR­
2003­
0053­
2284.2
Commenter:
Minnesota
Power
Comment:
[[
This
comment
also
applies
to
Outline
Heading
XIX.
H.
]]
On
August
5,
2005,
Minnesota
Power
had
submitted
to
EPA
our
Petition
for
Reconsideration
and
request
for
Stay
with
regard
to
the
final
rule
entitled,
>
Rule
to
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Clean
Air
Interstate
Rule;
Revisions
to
Acid
Rain
Program:
Revisions
to
the
NOx
SIP
Call,=
which
was
published
at
70
Fed.
Reg.
25,162
(
May
12,
2005).
Minnesota
Power
had
also
submitted
previous
comments
to
EPA
on
matters
related
to
the
Clean
Air
Interstate
Rule,
including:­
March
30,
2004,
Regarding
the
Proposed
Rule
To
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Interstate
Air
Quality
Rule
(
IAQR))
published
in
the
January
30,2004,
Federal
Register;­
July
26,
2004,
Regarding
EPA=
s
Supplemental
Proposal
for
the
Rule
to
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Clean
Air
Interstate
Rule)
published
in
the
June
10,
2004
Federal
Register;­
August
27,
2004,
Regarding
EPA=
s
Notice
of
Availability
of
Additional
Information
Supporting
the
Rule
to
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Clean
Air
Interstate
Rule);
and­
May
10,
2005
Regarding
a
Minnesota
Power
(
ALLETE)
request
for
correction
of
data
errors
related
to
the
characterization
of
Minnesota
Power
electric
generating
units
and
related
emission
rates
assessed
in
EPA=
s
final
Rule
to
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Clean
Air
Interstate
Rule).
These
Minnesota
Power
comments
provide
supportive
information
for
Minnesota
Power=
s
comments
directed
towards
EPA=
s
December
2,
2005
Federal
Register,
CAIR
reconsideration
request
for
comments.
[[
(
2284.2,
p.
1)
]]

Response:
See
final
CAIR
response
to
comments
and
Notice
of
Final
Action
on
Reconsideration
preamble
section
III.
C.

XVIII.
I.
3
Document
No.:
OAR­
2003­
0053­
2276.1
Commenter:
Duke
Energy
Comment:
Duke
Energy
strongly
objects
to
EPA=
s
decision
to
apportion
that
budget
on
the
basis
of
Title
IV
allowances,
as
opposed
to
more
recent
(
e.
g.,
1999­
2002)
heat
input
values,
the
basis
it
used
to
set
the
NOx
budgets
for
the
CAIR
states.
The
reasons
for
that
objection
are
detailed
in
these
comments,
and
in
the
company=
s
prior
comments,
which
are
incorporated
herein
by
reference.
[[
Docket
number
2276.1,
p.
1]]

Response:
See
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A
and
the
Technical
Support
Document,
"
SO2
Allocation
Approach
Analysis."

XVIII.
I.
4
Document
No.:
OAR­
2003­
0053­
2270.1
Commenter:
Tennessee
Valley
Authority
(
TVA)
Comment:
[[
This
comment
also
applies
to
Outline
Heading
XIX.
H.
]]
TVA
previously
submitted
comments
on
the
primary
CAIR
proposal,
published
at
69
Fed.
Reg.
4566­
4650
(
January
30,
2004),
by
letters
dated
March
30
and
April
5,
2004,
and
supplemental
comments
on
July
26,
2004.
TVA
incorporates
those
comments
by
reference
here.
[[
(
2270.1,
p.
1)
]]

Response:
See
final
CAIR
response
to
comments.

XVIII.
I.
5
Document
No.:
OAR­
2003­
0053­
2269.1
Commenter:
AES
Corporation
Comment:
These
comments
supplement
our
previous
comments
that
were
submitted
to
EPA
on
July
22,
2004
on
the
Supplemental
Proposal
for
the
Rule
to
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(>
CAIR=)
that
are
enclosed
and
made
part
of
our
comments
on
the
Notice
of
Reconsideration.
[[
Docket
number
2269.1,
p.
1]][[
See
docket
number
2269.1,
pp.
7­
14
for
previously
submitted
AES
comments
(
submitted
by
Piper
Rudnick
on
behalf
of
AES
Corporation)
dated
July
22,
2004.]]

Response:
See
final
CAIR
response
to
comments
and
Notice
of
Final
Action
on
Reconsideration,
Section
III.
A.

XIX.
A.
EPA
did
not
provide
sufficient
notice
of
use
of
fuel
factor
methodology
and
/
or
values
of
factors
Document
No.:
OAR­
2003­
0053­
2290.1
Commenter:
Michigan
Department
of
Environmental
Quality
(
MI
DEQ)
Comment:
The
MDEQ
believes
that
EPA
failed
to
provide
the
background
data
and
information
in
a
timely
and
adequate
manner
to
the
states.
This
resulted
in
the
inability
of
states
to
appropriately
address
the
inequities
in
the
methods
used
for
the
fuel­
neutral
calculations.
[[
(
2290.1,
p.
1)
]]
The
EPA
indicated
that
they
used
fuel
adjustment
factors
(
1.0
for
coal,
0.4
for
gas,
and
0.6
for
fuel
oil)
when
setting
state
NOx
budgets.
The
EPA
also
stated
that
they
described
this
methodology
in
the
proposed
and
supplemental
proposed
rules
as
published
in
the
Federal
Register
on
January
30,
2004
and
June
10,
2004,
respectively.
[[
(
2290.1,
p.
2)
]]
However,
the
actual
verbiage
in
the
proposed
CAIR
states
that
EPA
propose(
s)
to
apply
the
efficiency
standards
under
Title
18,
Section
292.205
to
coal,
oil,
and
gas­
fired
units
instead
of
applying
the
efficiency
standards
only
to
oil
and
gas­
fired
units.
The
efficiency
standard
definitions
referenced
are
pursuant
to
the
Federal
Energy
Regulatory
Commission=
s
Qualifying
Facility.
The
proposed
rule
did
not
identify
what
specific
numeric
factors
would
be
used.
The
proposed
rule
did
not
indicate
how
the
efficiency
standards
and
fuel
adjustments
were
related;
nor
did
it
include
text
from
the
section
referenced
above.
[[
(
2290.1,
p.
2)
]]
The
MDEQ
believes
that
the
EPA
implied
through
this
language
that
the
efficiency
standards
were
the
guiding
principles
behind
the
fuel­
neutral
calculations.
The
Title
28
Section
292.205
regulations
do
not
reference
fuel
neutrality.
[[
(
2290.1,
p.
2)
]]
Further,
the
actual
verbiage
in
the
Supplemental
Notice
of
Proposed
Rulemaking
states,
for
example,
factors
could
be
calculated
based
on
average
historic
NOx
emissions
rates
by
fuel
type
(
i.
e.,
coal,
gas
and
oil)
throughout
the
proposed
CAIR
region
for
the
years
1999­
2002
at
1.0
for
coal,
0.4
for
gas
and
0.6
for
oil.
The
actual
fuel
adjustment
values
were
discussed
within
the
SNPR.
However,
the
EPA
did
not
specifically
state
that
these
values
would
be
used
in
the
final
budget
calculations
and
determinations
and
only
requested
comments
on
possible
fuel
adjustments.
[[
(
2290.1,
pp.
2­
3)
]]

The
MDEQ
believes
that
the
EPA=
s
obscure
and
potentially
misleading
statements
in
the
proposed
and
supplemental
CAIR
regulations
regarding
the
efficiency
standards
and
fuel
neutral
ratios
were
inappropriate.
[[
(
2290.1,
p.
3)
]]
The
MDEQ
further
believes
that
the
EPA
failed
to
adequately
allow
states
to
review
the
budget
amount
differences
that
occurred
using
the
fuel
type
ratios.
The
supporting
technical
data
was
not
finalized
until
late
March
2005
and
not
made
available
to
the
states
until
after
the
final
rule
was
published
in
the
Federal
Register
on
May
12,
2005.
States
did
not
have
the
opportunity
to
dispute
the
budget
amounts
based
on
the
fuel
factors
or
the
methods
the
EPA
used
to
determine
subject
sources.
[[
(
2290.1,
p.
3)
]]
The
support
document
referenced
above
is
titled
"
Technical
Support
Document
for
the
Clean
Air
Interstate
Rule
Notice
of
Final
Rulemaking
Regional
and
State
SO2
and
NOx
Emissions
Budgets
March
2005"
and
contains
the
statement
"
As
is
discussed
in
the
Notice
of
Final
Rulemaking
(
NFR)
.
.
."
[[
(
2290.1,
p.
3)
]]

In
the
final
rule,
the
EPA
established
state
NOx
budgets
using
an
adjusted
heat
input
method.
The
specific
fuel
factors
used
to
adjust
heat
input
data
were
1.0
for
coal,
0.4
for
gas
and
0.6
for
oil.
The
EPA
further
noted
that
analyses
were
conducted
for
state
annual
NOx
budgets
established
in
the
CAIR,
citing
that
CAIR
also
establishes
seasonal
NOx
budgets
using
the
fuel
factor
approach.
[[
(
2290.1,
p.
3)
]]
The
MDEQ
believes
that
the
EPA
did
not
adequately
demonstrate
the
differences
between
using
and
not
using
the
fuel
adjustment
factors.
States
were
not
given
the
data
or
the
opportunity
to
conduct
their
own
evaluation
of
the
differences
between
the
two
levels.
States
were
expected
to
rely
on
the
EPA=
s
statement
in
the
final
rule
that
the
EPA
"...
adjusted
heat
input
for
type
of
fuel
used.
The
EPA
believes
that
this
method
is
a
reasonable
indicator
of
each
state=
s
appropriate
share
of
the
requirements."
[[
(
2290.1,
p.
3)
]]

Response:
EPA
believes
that
appropriate
notice
was
provided
on
the
use
of
the
FAF
methodology
and
the
adjustment
factors
through
the
CAIR
SNPR
and
CAIR
NFR.
However,
because
of
public
interest
in
the
issue,
EPA
granted
reconsideration.
By
requesting
public
comment
through
the
Notice
of
Reconsideration,
EPA
has
provided
an
additional
opportunity
to
the
public
to
comment
on
the
approach
and
the
factors.
As
a
result,
EPA
believes
that
all
procedural
requirements
for
providing
public
notice
have
been
fulfilled.
Document
No.:
OAR­
2003­
0053­
2279.1
Commenter:
Midwest
Generation
Comment:
Midwest
Generation
supports
EPA=
s
use
of
fuel
adjustment
factors
based
on
fuel
type
as
an
important
feature
of
the
model
trading
program
that
ensures
an
equitable
distribution
of
the
regulatory
burden
among
the
regulated
community.
As
a
preliminary
matter,
Midwest
Generation
notes
that
EPA
provided
to
all
participants
in
the
rulemaking
process,
including
Petitioners,
adequate
notice
that
the
Agency
was
considering
the
use
of
specific
fuel
adjustment
factors
to
set
state
budgets
for
NOx
emissions.
Indeed,
nearly
a
year
and
a
half
ago,
EPA
published
the
Supplemental
Notice
of
Proposed
Rulemaking
(
SNPR),
in
which
the
Agency
proposed
the
model
trading
rule
for
SO2
and
NOx
emissions.
With
respect
to
NOx
allocations,
EPA
proposed
to
determine
budgets
for
states
within
the
CAIR
region
based
on
unadjusted
heat
input
data
for
years
1999
through
2002.
However,
in
that
context,
EPA
suggested
as
follows:[
t]
his
heat
input
data
for
existing
units
could
be
adjusted
by
multiplying
it
by
different
factors
based
on
fuel­
type,
reflecting
the
inherent
higher
emissions
of
coal­
fired
plants.
For
example
factors
could
be
calculated
based
on
average
historic
NOx
emissions
rates
by
fuel
type
(
i.
e.,
coal,
gas
and
oil)
throughout
the
proposed
CAIR
region
for
the
years
1999­
2000
at
1.0
for
coal,
0.4
for
gas
and
0.6
for
oil.
70
Fed.
Reg.,
32712
(
emphasis
added).

The
foregoing
is
sufficient
to
put
all
participants
to
the
rulemaking
on
notice
that
EPA
was
considering
the
use
of
fuel­
type
multipliers
and
that,
at
least
informally,
it
was
entertaining
multipliers
in
the
range
of
1.0
for
coal,
0.4
for
gas
and
0.6
for
oil.
This
is
so
regardless
of
the
fact
that
EPA
did
not
invoke
the
talismanic
word
"
propose"
in
the
SNPR.
EPA
unequivocally
stated
that
it
could
use
such
multipliers,
explained
the
basis
on
which
the
multipliers
could
be
calculated
and
gave
specific
examples
for
coal,
gas
and
oil.
It
would
be
absurd
to
read
EPA=
s
statements
as
anything
other
than
an
indication
that
the
Agency
was
open
to
comment
regarding
the
formula
for
setting
state
NOx
budgets.
Petitioners
offer
no
sound
reason
for
having
disregarded
EPA=
s
statements
in
the
SNPR
and
foregoing
comment
until
now.
In
any
event,
EPA=
s
reconsideration
renders
Petitioners=
claim
of
insufficient
notice
moot.
[[
(
2279.1,
pp.
4­
5)
]]

Response:
The
commenter
generally
supports
use
of
the
fuel
adjustment
factor
(
FAF)
methodology,
the
approach
taken
in
the
CAIR
and
CAIR
FIP.

Document
No.:
OAR­
2003­
0053­
2275.1
Commenter:
FPL
Group
Comment:
Fuel
adjustment
factors
(
FAFs)
should
not
be
used
to
set
state
NOx
budgets.
(
Reconsideration
Issue
No.
2)
While
EPA
granted
reconsideration
with
respect
to
its
eleventh­
hour
decision
to
use
FAFs
to
set
state
NOx
budgets,
the
Notice
of
Reconsideration
states
that
"
EPA
believes
that
it
provided
adequate
notice
both
that
fuel
adjustment
factors
might
be
used
and
of
the
calculation
procedures
that
it
would
use
to
determine
the
specific
factors
(
70
Fed
Reg
72276).
It
cites
as
support
for
this
proposition
a
discussion
of
FAFs
in
the
SNPR
(
69
Fed
Reg
32689).
But
the
SNPR
clearly
does
not
give
the
notice
of
EPA=
s
intent
to
use
FAFs
that
is
attributed
to
it
by
EPA.
The
SNPR
simply
reports
that
"
commenters
have
also
suggested
adjusting
the
heat
input
data"
with
FAFs.
Nothing
in
the
SNPR
suggests
that
EPA
agreed
with
those
commenters,
intended
to
adopt
their
proposal,
or
was
soliciting
comments
on
whether
doing
so
would
be
a
good
idea.
No
one
could
have
reasonably
anticipated
from
the
SNPR
that
EPA
intended
to
reverse
course
and
use
FAFs
to
set
state
NOx
budgets
in
the
Final
Rule.
[[
(
2275.1,
p.
8)
]]
FPL
Group
objects
to
the
use
of
FAFs
to
set
state
NOx
budgets
for
several
reasons,
as
discussed
below.
(
2275.1,
p.
8)
]]

Response:
See
response
to
comment
from
the
Michigan
Department
of
Environmental
Quality.

Document
No.:
OAR­
2003­
0053­
2270.1
Commenter:
Tennessee
Valley
Authority
(
TVA)
Comment:
TVA
has
addressed
this
issue
in
the
docket
previously.
TVA
disagrees
that
notice
of
this
feature
of
CAIR
was
lacking
or
inadequate.
In
its
earlier
comments,
TVA
noted
that
without
a
fuel
adjustment
factor,
gas­
fired
generation
would
essentially
be
subsidized
because
it
would
be
allocated
allowances
at
rates
above
current
or
projected
future
emission
levels.
The
purpose
of
CAIR
is
to
reduce
emissions
of
SO2
and
NOx
from
utilities
in
support
of
efforts
to
attain
and
maintain
the
eight­
hour
ozone
and
fine
particle
ambient
air
quality
standards.
The
purpose
is
not
to
provide
a
windfall
to
states
with
high­
gas
generation.
Providing
such
a
windfall
to
sources
that
have
no
incentive
to
make
reductions
undermines
the
economic
basis
of
cap
and
trade
programs,
like
CAIR.
When
subsidized
sources
dump
their
emission
allowances
on
the
market,
they
reduce
the
value
of
emission
allowances
which
creates
a
discrepancy
with
marginal
cost
of
controls.
This
discrepancy
adds
uncertainty
to
control
decisions
and
makes
delaying
control
decisions
more
economically
attractive.
EPA
should
retain
its
fuel­
adjustment
factors.
[[
(
2270.1,
p.
2)
]]

Response:
The
commenter
generally
supports
use
of
the
FAF
methodology,
the
approach
taken
in
the
CAIR
and
CAIR
FIP.

XIX.
B.
Fuel
factor
approach
unfairly
penalizes
non­
coal
fired
units
(
gas
and
oil
units)
and
/
or
benefits
coal­
fired
units
Document
No.:
OAR­
2003­
0053­
2279.1
Commenter:
Midwest
Generation
Comment:
Midwest
Generation
supports
EPA=
s
use
of
fuel­
type
adjustment
factors
to
account
for
differences
in
the
emissions
profiles
of
units
that
burn
coal,
gas
and
oil.
EPA=
s
inclusion
of
such
multipliers
appropriately
distributes
the
regulatory
burden
more
equitably
among
affected
sources.
If
allocations
were
based
on
unadjusted
heat
input
data,
as
EPA
proposed
in
the
NPR,
the
sources
that
need
greater
allocations
due
to
the
type
of
fuel
they
combust
would
actually
receive
fewer
while
sources
that
need
few
would
be
allocated
a
surplus.
For
example,
coal­
fired
units
emit
considerably
more
NOx
per
Btu
than
gas­
fired
units.
Gas­
fired
sources,
on
the
other
hand,
emit
relatively
little
NOx
per
Btu.
If
allowances
are
allocated
to
states
based
on
unadjusted
heat
input
and
states
pass
such
allocations
on
to
their
EGUs,
coal­
fired
sources
will
have
insufficient
allowances
for
complying
with
the
applicable
emissions
rate
and
the
shortfall
will
go
to
gas­
fired
sources
that
do
not
need
them.
As
a
result,
coal­
fired
sources
effectively
will
be
required
to
comply
with
a
more
stringent
emissions
rate.
[[
(
2279.1,
pp.
5­
6)
]]

To
meet
the
more
stringent
emissions
rate,
coal­
fired
sources
will
have
two
options,
both
of
which
place
on
them
a
disproportionate
share
of
the
burden
for
emissions
reductions.
Coal­
fired
units
can
install
and
operate
costly
control
technology
in
order
to
meet
the
more
stringent
emissions
limit.
Alternatively,
sources
that
do
not
meet
the
emissions
rate
will
be
able
to
purchase
allowances
from
gas­
fired
units
that
do
not
need
them.
Put
simply,
allocations
based
on
unmodified
heat
input
data
tax
coal­
fired
sources
by
subjecting
them
to
greater
compliance
costs
and
subsidize
gas­
fired
sources
by
conferring
on
them
a
windfall
of
valuable
allowances
they
do
not
need.
[[
(
2279.1,
p.
6)
]]

Analyses
conducted
by
EPA
demonstrate
that
the
use
of
fuel­
type
multipliers
to
set
allocations
helps
to
ameliorate
the
disparity.
EPA=
s
region­
wide
analysis
shows
that
under
either
approach
for
setting
allocations
unadjusted
heat
input
or
heat
input
adjusted
by
fuel­
type
multipliers
oiland
gas­
fired
units
are
projected
to
receive
allowances
more
than
sufficient
to
cover
emissions
without
installation
of
additional
control
technology.
The
fuel­
adjustment
factor
approach
addresses
the
inequity
by
providing
additional
allocations
to
states
with
large
numbers
of
coalfired
units
that
are
investing
considerable
sums
in
control
technology.
Moreover,
EPA=
s
state­
bystate
analysis
shows
that
states
receiving
fewer
allocations
under
a
fuel­
factor
approach
in
most
cases
still
receive
statewide
budgets
greater
than
emissions
projected
in
2009
and
2015.
In
fact,
even
when
allocations
are
adjusted
to
account
for
fuel
type,
states
with
greater
than
40%
gas­
or
oil­
fired
generation
generally
receive
NOx
budgets
that
exceed
emissions
projections.
[[
(
2279.1,
p.
6)
]]
The
use
of
unadjusted
heat
input
to
set
state
NOx
budgets
for
the
next
decade
will
exact
an
extraordinary
tax
from
coal­
fired
generation
to
the
benefit
of
gas­
and
oil­
fired
generation.
EPA=
s
fuel­
type
multipliers
minimize
the
inequity
by
shifting
allowances
to
sources
proportionate
to
their
need.
EPA
should
not
change
this
aspect
of
CAIR
in
response
to
the
requests
for
reconsideration.
[[
(
2279.1,
pp.
6­
7)
]]

Response:
The
commenter
generally
supports
use
of
the
FAF
methodology,
the
approach
taken
in
the
CAIR
and
CAIR
FIP.

Document
No.:
OAR­
2003­
0053­
2295.1
Commenter:
Tampa
Electric
Company
Comment:
TEC
supports
EPA=
s
procedure
for
allocating
allowances
based
on
heat
input
and
fuel
factors.
TEC
strongly
supports
the
allocation
of
NOx
allowances
on
a
heat
input
basis
using
fuel
factors
for
the
following
reasons:

a)
TEC
believes
that
the
use
of
fuel
factors
appropriately
recognizes
that
reduced
emissions
from
coal
units
is
technologically
more
difficult
and
expensive
than
for
gas
units
and
that
coal
units
require
more
allowances
to
operate
on
a
day­
to­
day
basis
than
do
gas
units.

b)
Clean
coal
technology
continues
to
emerge
as
a
significant
part
of
the
solution
to
our
nation=
s
energy
problems
and
provides
us
with
a
safe,
clean
and
efficient
way
to
use
our
nation=
s
most
abundant
fuel
to
produce
needed
electricity.
With
the
scarcity
of
natural
gas
and
its
skyrocketing
prices,
it
does
not
appear
to
us
to
make
sense
to
provide
incentives
to
continue
to
burn
more
natural
gas
when
coal
is
available
and
can
be
utilized
in
this
manner.
We
believe
that
the
use
of
fuel
factors
will
further
the
goal
of
coal
utilization.

c)
The
elimination
of
fuel
factors
would
provide
a
windfall
of
NOx
allowances
to
natural
gas
units
and
require
coal
units
to
purchase
NOx
allowances
from
natural
gas
units
in
order
to
continue
to
operate,
resulting
in
increased
costs
to
the
customer.

d)
It
is
in
the
best
interest
of
the
State
of
Florida
and
the
nation
to
encourage
fuel
diversity.
Providing
subsidies
through
allowance
allocations
for
natural
gas
generation
at
the
expense
of
coal
is
in
direct
conflict
with
this
concept.

e)
Allocating
allowances
using
this
fuel­
based
methodology
should
be
encouraged
as
accurate
fuel
monitoring
and
reporting
methods
are
already
available.

f)
The
use
of
proposed
alternative
systems
to
fuel
factors
directly
conflicts
with
the
established
SO2
Acid
Rain
and
proposed
SO2
CAIR
allocation
and
compliance
methodologies.
The
program
should
remain
simple
with
baseline
allocations,
reporting
and
compliance
based
on
the
heat
input
basis
with
fuel
factors.
Otherwise,
there
would
be
an
unnecessary
burden
in
requiring
sources
to
use
different
methodologies
for
SO2
and
NOx
CAIR
compliance.
[[
(
2295.1,
pp.
6­
7)
]]

In
the
interest
of
fairness
and
consistency,
EPA
should
also
encourage
the
states
to
use
the
fuel
factor
procedure
in
allocating
allowances
to
the
individual
sources.[[
(
2295.1,
p.
7)
]]
In
addition,
EPA
should
uphold
the
CAIR
procedure
for
allocating
allowances
based
on
fuel
factors.
This
enhancement
to
the
initial
version
of
the
rule
was
based
on
sound
judgment
and
is
in
the
best
interest
of
fairness
and
promoting
the
necessary
fuel
diversity.
[[
(
2295.1,
p.
7)
]]

Response:
The
commenter
generally
supports
use
of
the
FAF
methodology,
the
approach
taken
in
the
CAIR
and
CAIR
FIP.

Document
No.:
OAR­
2003­
0053­
2301
Commenter:
Pennsylvania
Department
of
Environmental
Protection
(
PADEP)
Comment:
EPA
set
out
initially
to
base
the
feasible
amount
of
control
an
area
should
contribute
based
on
a
"
highly
cost­
effective
control"
determination.
Cost
effective
emission
controls
for
natural
gas
result
in
far
lower
emissions
per
unit
of
heat
input
than
for
coal
or
oil
units,
therefore,
it
is
illogical
to
determine
"
highly
cost­
effective
control"
requirements
for
gas
units
based
on
coal
unit
metrics­
a
large
amount
of
"
highly
cost­
effective
control"
will
be
left
on
the
table.
In
addition,
weighting
the
budgets
by
fuel
simply
equalizes
the
costs
of
the
control
effort
contribution
each
type
of
unit
can
and
should
make.
[[
(
p.
2)
]]

A
fuel­
neutral
budget
allocation
would
give
natural
gas
units
and
states
with
large
natural
gas
resources
and
generating
capacity
huge
allowance
and
financial
windfalls.
This
would
result
in
both
an
inequitable
economic
transfer
of
wealth
between
states
as
well
as
inadequate
emission
control
within
and
adjacent
to
the
Northeast
corridor.
EPA
should
retain
the
current
fuelweighted
methodology.
[[
(
p.
2)
]]
Natural
gas
consumption
estimates
for
2003
as
reported
by
the
Energy
Information
Agency,
and
considering
only
those
states
in
the
CAIR
program,
indicate
that
the
largest
amount
of
natural
gas
consumed
for
electricity
production
occurred
in
Texas
at
1483.8
trillion
Btu
of
natural
gas,
Florida
at
553.5
trillion
Btu,
North
Carolina
at
267.1
trillion
Btu,
and
Louisiana
at
244.1
trillion
Btu.
In
comparison,
Pennsylvania
used
only
42.8
trillion
Btu,
Ohio
used
19.4
trillion
Btu,
Indiana
used
27.2
trillion
Btu,
Virginia
used
36.2
trillion
Btu,
West
Virginia
used
2.2
trillion
Btu,
Tennessee
used
5.8
trillion
Btu,
and
Kentucky
used
3.8
trillion
Btu.

When
using
a
fuel­
neutral
approach,
the
implications
and
results
of
the
disparity
result
in
large
amounts
of
allowances
controlled
by
a
few
natural
gas
intensive
states
or
a
small
number
of
corporations
in
those
states.
There
could
be
a
significant
transfer
of
wealth
from
coal
states
to
natural
gas
states
with
little
benefit
for
the
air
in
the
Northeast.
The
Commonwealth
supports
EPA=
s
fuel­
based
state
allocation
process
and
the
state
budgets
as
proposed.
[[
(
pp.
2­
3)
]]

Response:
The
commenter
generally
supports
use
of
the
FAF
methodology,
the
approach
taken
in
the
CAIR
and
CAIR
FIP.

Document
No.:
OAR­
2003­
0053­
2272.1
Commenter:
Cinergy
Corp.
Comment:
Cinergy
supports
the
use
of
fuel­
type
multipliers
for
purposes
of
calculating
statewide
NOx
allowance
budgets.
Heat
input
allocations
that
distribute
allowances
based
on
each
unit=
s
pro
rata
share
of
heat
input
alone
inappropriately
disadvantage
coal­
fired
EGUs.
Coal­
fired
units
emit
more
NOx
per
Btu
than
gas­
fired
units,
for
example.
If
allocations
to
coal­
fired
units
are
based
on
heat
input
alone,
rather
than
weighted
according
to
fuel
type,
coal­
fired
units
will
not
receive
allowances
sufficient
to
meet
the
relevant
NOx
emissions
rate
on
which
CAIR
is
based.
Instead,
the
shortfall
of
allowances
to
coal­
fired
units
will
go
to
gas­
fired
units,
which
intrinsically
emit
less
NOx
per
Btu
and,
therefore,
do
not
need
the
additional
allowances.
To
compensate,
coal­
fired
sources
will
be
required
to
comply
with
an
emission
rate
that
is
more
stringent
than
the
highly
cost­
effective
basis
for
the
rule.
Alternatively,
coal­
fired
units
that
do
not
meet
the
emissions
rate
may
purchase
additional
allowances
from
gas­
fired
units
that
do
not
need
them.
This
unmodified
heat
input
allocation
methodology
produces
a
windfall
for
sources
that
do
not
combust
coal
and
simultaneously
imposes
greater
compliance
costs
on
coal­
fired
units.
There
is
no
policy
reason
to
support
what
amounts
to
little
more
than
a
transfer
of
wealth.
The
use
of
fuel­
type
adjustment
factors
ensures
that
the
regulatory
burden
namely,
costs
for
compliance
is
distributed
equitably
among
affected
sources.
[[
(
2272.1,
p.
3)
]]

To
assess
the
wealth­
transfer
effect
that
would
result
from
unadjusted
allocations,
Cinergy=
s
engineers
used
EPA=
s
data
to
calculate
the
effective
emissions
rates
for
gas­
fired
units
within
the
CAIR
region
­
first,
assuming
no
fuel­
type
adjustment,
and
once
again,
incorporating
EPA=
s
multipliers.
Our
internal
analysis
shows
that,
if
EPA=
s
multipliers
are
used,
gas­
fired
units
must
meet,
on
average,
an
effective
emission
rate
of
approximately
0.065
lb/
mmBtu.
Although
this
may
seem
extraordinarily
low,
in
fact,
it
closely
approximates
what
most
gas­
fired
combustion
turbines
currently
achieve
without
the
installation
of
additional
control
equipment.
In
other
words,
it
will
cost
gas­
fired
units
very
little
to
comply
with
the
rule,
even
if
it
includes
the
fueltype
multipliers.
[[
(
2272.1,
p.
3)
]]

In
contrast,
if
the
multipliers
are
eliminated,
gas­
fired
units
will
be
required
to
meet,
on
average,
an
effective
emission
rate
of
approximately
0.14
lb/
mmBtu.
This
rate
is
significantly
higher
than
the
emission
rate
currently
achieved
by
the
majority
of
gas­
fired
units
and,
thus,
amounts
to
nothing
more
than
a
windfall
of
allowances
that
companies
can
sell
for
profit
or
use
to
cover
emissions
at
their
non­
gas­
fired
plants.
Coal­
fired
units,
however,
will
be
required
to
expend
significant
resources
to
comply
with
this
rule
even
if
the
fuel
type
multipliers
are
used.
If
EPA
eliminates
these
multipliers,
costs
to
coal­
fired
units
will
increase
­
while
valuable
allowances
will
be
allocated
to
sources
that
do
no
need
them.
As
noted
above,
no
policy
would
justify
EPA=
s
grant
of
an
allowance
windfall
to
gas­
fired
units.
[[
(
2272.1,
pp.
3­
4)
]]
The
results
of
our
internal
analysis
are
consistent
with
additional
analyses
that
EPA
conducted
in
response
to
the
requests
for
reconsideration.

Petitioners
argue
that
the
fuel
adjustment
factors
penalized
gas­
fired
units
and
should
be
eliminated.
In
response,
EPA
conducted
two
analyses
to
evaluate
the
impact
of
using
fuel
multipliers
versus
no
multipliers,
both
on
a
region­
wide
scale
and
on
a
state­
by­
state
basis.
The
Agency=
s
analysis
demonstrates
that
both
gas­
and
oil­
fired
units
will
get
the
allowances
they
need
to
operate
­
without
installing
control
equipment
­
even
if
allocations
are
adjusted
to
account
for
fuel
type.
Thus,
EPA=
s
analysis
supports
the
conclusion
that
there
is
no
reason
to
modify
the
fuel
adjustment
factors.
That
is,
CAIR
is
not
supposed
to
be
a
"
freebie"
for
non­
coalfired
units,
but
EPA=
s
analysis
shows
that
gas­
fired
units
are
unlikely
to
experience
any
shortfall
in
allowances
­
and
at
most
will
experience
a
small
shortfall.
Yet
even
if
these
units
encounter
a
small
allowance
shortfall
with
these
fuel
adjustment
factors,
that
surely
does
not
support
changing
the
factors
given
the
enormous
reductions
(
and
costs)
that
must
be
borne
by
coal­
fired
units.
[[
(
2272.1,
p.
4)
]]

EPA
also
specifically
concluded
that,
where
a
fuel
adjustment
of
0.4
is
applied
to
gas­
fired
units,
the
portion
of
the
State
budgets
derived
from
the
heat
input
from
the
gas­
fired
units
generally
exceeds
both
the
historical
and
the
future
projected
emissions
from
these
units.
Indeed,
EPA=
s
analysis
shows
that
states
with
greater
than
40%
gas­
or
oil­
fired
generation
generally
receive
NOx
budgets
that
exceed
their
projected
emissions.
Major
coal­
burning
states,
in
contrast,
must
make
dramatic
NOx
emission
reductions
under
CAIR.
For
example,
CAIR
represents
annual
NOx
emissions
reductions
of
48%
and
66%
in
Indiana
for
2009
and
2015,
respectively;
in
Kentucky
of
44%
and
58%,
and
in
Ohio
of
66%
and
67%.
EPA=
s
analysis
demonstrates
that
even
using
a
multiplier
of
0.4,
virtually
none
of
these
reductions
will
be
borne
by
gas­
fired
units;
rather,
coal­
fired
units
will
make
dramatic
reductions
and
gas­
fired
units
will
do
almost
nothing.
[[
(
23272.1,
pp.
4­
5)
]]
Under
such
circumstances,
it
makes
no
sense
for
EPA
to
provide
an
additional
windfall
to
gas­
fired
units.
Such
a
shifting
of
allowances
away
from
coal­
fired
generation,
when
multiplied
by
the
estimated
price
for
NOx
allowances
and
added
over
a
10­
year
period,
amounts
to
a
substantial
penalty
to
coal­
fired
generation
and
an
equally
substantial
subsidy
to
gas­
fired
generation.
Again,
there
is
no
policy
justification
for
granting
such
an
allowance
windfall
to
gas­
fired
units.
[[
(
2272.1,
p.
5)
]]
Response:
The
commenter
generally
supports
use
of
the
FAF
methodology,
the
approach
taken
in
the
CAIR
and
CAIR
FIP.

Document
No.:
OAR­
2003­
0053­
2275.1
Commenter:
FPL
Group
Comment:
The
use
of
FAFs
is
inconsistent
with
the
approach
used
by
EPA
to
determine
the
regional
NOx
budget.
For
the
CAIR
region,
EPA
determined
how
much
baseline
emissions
would
be
reduced
by
the
installation
of
cost­
effective
controls.
At
a
meeting
on
November
30,
2005,
EPA
acknowledged
to
FPL
Group
that
it
considered
controls
to
be
cost­
effective
only
on
coal­
fired
EGUs.
However,
the
FAFs
will
result
in
ratcheting
down
the
allowances
available
in
states
with
a
high
proportion
of
non­
coal
EGUs
to
the
extent
that
EGUs
in
those
states
will
be
forced
either
to
install
pollution
controls
that
are
not
cost­
effective,
or
else
to
buy
expensive
allowances
in
spite
of
the
fact
that
they
are
cost­
effectively
controlling
their
emissions.
This
problem
will
be
exacerbated
for
non­
coal
EGUs
in
states
that
also
apply
FAFs
to
allocate
their
budgeted
NOx
allowances
to
particular
types
of
EGUs,
as
Florida
currently
proposes
to
do.
[[
(
2275.1,
p.
8)
]]

In
the
Notice
of
Reconsideration,
EPA
defends
the
use
of
FAFs
essentially
by
arguing
that
coal
EGUs
need
to
be
subsidized
to
offset
the
greater
burden
on
them
of
complying
with
CAIR=
s
emission
reductions.
This
rationale
is
untenable.
Consciously
subsidizing
coal
EGUs
would
be
unfair
and
counter­
productive.[[
(
2275.1,
p.
8)
]]

FAFs
are
an
economic
subsidy
that
coal­
fired
EGUs
do
not
need
or
deserve.
The
fuel
cost
for
coal
EGUs
is
much
lower
than
for
oil
or
gas
EGUs.
The
cost
spread
has
become
even
wider
recently.
Using
EPA
and
United
States
Department
of
Energy
(
DOE)
data,
FPL
Group
has
calculated
an
average
delivered
fuel
cost
for
Florida=
s
coal
EGUs
of=
about
$
1
l/
MWh
in
2010,
whereas
the
average
delivered
fuel
cost
for
gas
EGUs
will
be
about
$
36/
Mwh
in
that
same
year.
This
is
a
difference
of
approximately
$
25/
Mwh
In
contrast,
EPA
has
estimated
that
the
retail
cost
of
electricity
will
increase
by
about
$
3
90
Mwh
as
a
result
of
implementing
CAIR,
as
well
as
EPA=
s
Clean
Air
Mercury
Rule
and
the
Clean
Air
Visibility
Rule
See
Multi­
Pollutant
Regulatory
Analysis
CAIR/
CAIR/
CAIR,
EPA
Office
of
Air
and
Radiation,
October
2005.
Clearly,
the
differential
cost
to
coal
and
gas
EGUs
of
complying
with
CAIR
will
not
be
as
large
as
this
$
3.90
Mwh
total
compliance
cost,
but
even
if
it
were,
the
fuel
cost
differential
is
more
than
six
times
as
great.
[[
(
2275.1,
pp.
8­
9)
]]

Moreover,
using
FAFs
to
subsidize
coal
EGUs
would
be
economically
inefficient.
Economic
efficiency
dictates
that
EGUs
with
the
lowest
overall
operating
costs
should
be
built
and
operated
preferentially.
Operating
costs
consist
of
several
components,
including
both
the
cost
of
fuel
and
the
cost
of
pollution
control.
The
use
of
FAFs
effectively
taxes
oil
and
gas
EGUs
and
transfers
the
proceeds
to
coal
EGUs
to
help
them
pay
for
their
higher
costs
of
pollution
control.
This
tax
sends
an
artificial
price
signal
that
coal­
fired
plants
are
cheaper
to
build
and
operate
than
they
actually
are.
It
is
no
different
from
an
economic
perspective
than
taxing
EGUs
and
transferring
the
proceeds
to
oil
and
gas
EGUs
to
help
them
pay
for
their
higher­
priced
fuel.
EGUs
should
be
evaluated
on
the
basis
of
their
actual
costs
the
cross­
subsidies
that
will
result
from
the
FAFs
interfere
with
that
goal.
[[
(
2275.1,
p.
9)
]]
Finally,
EPA
has
made
an
erroneous
assumption
about
the
impact
of
CAIR
on
Florida
that
invalidates
EPA=
s
conclusion
that
Florida
would
be
a
winner
under
CAIR
with
or
without
FAFs.
Tables
1,
2
and
3
in
the
Notice
of
Reconsideration
purport
to
show
that
states
such
as
Florida
with
a
high
percentage
of
non­
coal
EGUs
will
have
more
NOx
allowances
than
they
will
need
to
accommodate
the
emissions
from
their
EGUs,
once
cost­
effective
CAIR
emission
controls
have
been
installed.
They
suggest
that
this
is
so
with
or
without
FAFs.
From
this
analysis,
EPA
then
concludes
that
transferring
NOx
allowances
to
states
with
a
high
percentage
of
coal
EGUs
is
fair
because
it
distributes
the
burden
of
CAIR
compliance
more
equally.
The
analysis
upon
which
these
tables
are
based
excludes
numerous
older
oil
and
gas
EGUs
from
the
base
case
emissions
used
to
establish
the
NOx
allocations,
on
the
assumption
that
those
EGUs
will
no
longer
be
operated
by
the
time
the
CAIR
budgets
become
effective.
[[
(
2275.1,
p.
9)
]]

For
Florida
in
general
and
FPL
Group
in
particular,
this
assumption
is
incorrect
and
it
results
in
a
major
misrepresentation
of
the
>
fairness=
of
the
CAIR
NOx
budgets
to
Florida
and
to
FPL
Group.
EPA
apparently
assumes
that
the
older
oil
and
gas
EGUs
will
be
retired
because
they
are
not
as
cost­
effective
to
operate
as
either
coal
EGUs
or
combined
cycle
gas
EGUs.
In
fact,
high­
growth
states
such
as
Florida
do
not
have
the
luxury
of
retiring
older
less­
efficient
EGUs
as
they
build
new
ones:
both
the
old
and
new
units
are
needed
to
meet
rapid
load
growth.
Illustrative
of
this
point
is
A
Review
of
Florida
Electric
Utility
2005
Ten­
Year
Site
Plans,
prepared
by
the
Florida
Public
Service
Commission
in
December
2005
and
attached
hereto
as
Attachment
6
(
the
TYSP
Review).
The
TYSP
Review
summarizes
the
types
of
generating
resources
with
which
each
electric
utility
in
Florida
intends
to
meet
its
customers=
demand
for
electricity
over
the
period
2005
to
2014.
One
of
the
generating
resource
types
is
>
fossil
steam,
which
comprises
older
oil
and
gas
EGUs,
as
opposed
to
the
more
modern
combined
cycle
gas
EGUs.
The
TYSP
Review
shows
that
Florida
currently
has
9.890
MW
of
fossil
steam
EGUs
in
service
and
that
this
total
will
be
reduced
only
by
41
MW
(
about
4%)
over
the
period
ending
2014.
[[
(
2275.1,
pp.
9­
10)
]]

Clearly,
EPA=
s
assumption
that
most
of
the
older,
fossil
steam
units
will
be
retired
is
wildly
off
target.
If
one
were
to
correct
Table
2
for
this
inaccurate
assumption
about
retiring
older
oil
and
gas
EGUs,
the
CAIR
emissions
for
Other
Fossil
EGUs
in
Florida
would
increase
from
17,000
tons
per
year
of
NOx
to
approximately
70,000
to
75,000
tons,
which
is
well
above
both
the
58,000
tons
that
is
shown
for
a
"
simple
heat
input
budget"
and
the
34,000
tons
that
is
shown
for
the
>
fuel
adjusted
budget=.
Moreover,
Florida=
s
total
CAIR
emissions
would
increase
from
69,000
tons
to
about
124,000
tons,
which
exceeds
even
the
>
simple
heat
input
budget
of
116,000
tons
and
is
well
above
the
>
fuel
adjusted
budget
of
99,000
tons.
[[
(
2275.1,
p.
10)
]]

Thus,
even
without
FAFs,
utilities
in
Florida
will
have
to
buy
a
large
number
of
expensive
allowances
in
order
to
operate
their
older
oil
and
gas
EGUs
and
that
this
burden
will
be
even
greater
if
FAFs
are
used.
This
is
in
spite
of
the
fact
that
those
older
oil
and
gas
EGUs
inherently
have
lower
emissions
than
coal
EGUs
FPL
Group
fails
to
see
how
the
use
of
FAFs
could
possibly
be
said
to
increase
fairness
in
this
situation.
[[
(
2275.1,
p.
10)
]]

Beyond
the
issues
of
fairness
and
economic
efficiency,
the
use
of
FAFs
also
calls
into
question
the
entire
premise
for
CAIR.
The
rule
is
not
about
reducing
SO2
or
NOx
emissions
generally
throughout
the
CAIR
region;
rather,
CAIR
is
targeted
at
(
and
justified
by)
reducing
impacts
on
specific
downwind
non­
attainment
areas
by
specific
upwind
states.
EPA
determined
what
the
impact
of
CAIR
would
be
on
downwind
non­
attainment
areas
by
modeling
the
impact
of
costeffective
emission
reductions
throughout
the
regulated
upwind
states.
That
modeling
did
not
assume
the
use
of
FAFs
to
redistribute
the
allowable
emissions
among
those
upwind
states.
So
far
as
FPL
Group
can
discern
from
the
CAIR
rulemaking
record,
EPA
has
not
determined
the
effect
of
FAFs
on
those
modeling
results.
Unless
and
until
it
does
so,
EPA
cannot
be
confident
that
CAIR
will
work
as
intended
if
it
uses
FAFs
to
redistribute
the
regional
NOx
budget
among
the
upwind
states.
[[
(
2275.1,
pp.
10­
11)
]]

EPA=
s
efficient
trading
markets
theory
does
not
allay
this
concern.
It
may
be
true
that
NOx
allowances
will
ultimately
end
up
in
the
hands
of
the
EGUs
that
most
need
them,
regardless
of
where
those
allowances
are
initially
allocated.
However,
the
decrease
in
operating
costs
for
EGUs
in
states
that
are
rewarded
by
the
FAFs
could
result
in
additional
electric
output
and
thus
higher
emission
levels
in
those
states.
Without
additional
analysis
and
modeling,
EPA
cannot
how
where
and
to
what
extent
this
shift
in
emissions
will
occur
or
what
the
impact
would
be
on
downwind
non­
attainment
areas.
Simply
put,
using
FAFs
to
allocate
state
NOx
budgets
without
further
analysis
of
their
impact
invalidates
the
analytical
rationale
for
CAIR.
EPA
must
either
reallocate
the
NOx
budgets
without
using
FAFs
or
start
over
again
in
its
modeling
of
the
impact
of
CAIR
on
downwind
non­
attainment
areas.
[[
(
2275.1,
p.
11)
]]

Response:
EPA
disagrees
with
the
commenter's
claim
that
use
of
the
FAF
methodology
subsidizes
coalfired
generation.
In
fact,
the
use
of
the
FAF
methodology
provides
allowances
to
types
of
generation
that
is
more
proportionate
to
their
projected
investment
in
advanced
emission
controls
as
a
result
of
CAIR.
If
EPA
provided
allocations
to
gas­
fired
units,
which
typically
have
NOx
emission
rates
much
lower
than
coal
units,
using
a
simple
heat
input
approach
(
non­
FAF
approach),
then
the
gas­
fired
units
would
have
and
even
greater
excess
of
NOx
allowances
to
sell
to
the
coal­
fired
generation
(
i.
e.,
the
units
that
are
projected
to
invest
in
advanced
emission
controls),
effectively
subsidizing
gas­
units.
By
using
a
FAF
approach,
EPA
has
chosen
to
use
a
system
that
reduces
disparity
between
the
projected
emissions
and
the
budgets,
and
avoids
subsidizing
any
one
type
of
generation.

EPA
disagrees
with
the
commenter's
contention
that
the
use
of
FAF
methodology
to
apportion
CAIR
NOx
budgets
to
the
States
would
significantly
impact
States
with
predominantly
gas­
fired
generation.
Analysis
presented
in
the
CAIR
Notice
of
Reconsideration
(
December
2005)
demonstrated
that
use
of
the
FAF
methodology
is
reasonable
and
generally
decreases
the
disparity
between
most
States'
projected
emissions
and
statewide
NOx
budgets.
More
specifically,
EPA
presented
analysis
in
the
CAIR
Notice
of
Reconsideration
that
showed
that
States
with
predominantly
non­
coal
fired
generation
would
have
budgets
that
are
greater
than
their
projected
emissions
in
2009
and
2015.
In
the
case
of
Florida,
the
analysis
showed
that
they
would
have
coverage
ratios
of
1.45
and
1.35
under
CAIR
in
2009
and
2015,
respectively.
In
other
words
they
have
allowances
equal
to
145%
and
135%
of
their
projected
emissions
in
2010
and
2015,
respectively.

EPA
modeling
in
support
of
CAIR
included
gas­
and
oil­
fired
units
and
demonstrated
that
highly
cost­
effective
NOx
emission
reductions
are
available
from
the
power
sector.
The
marginal
cost
of
control
and
the
average
cost
of
control,
shown
to
be
"
highly
cost­
effective,"
reflect
a
range
of
power
sector
control
costs
that
include
costs
from
sources
such
as
older
gas­
and
oil­
fired
units.
In
projecting
which
units
will
operate,
the
model
considers
where
control
will
be
least
expensive
and
that
some
units
will
purchase
allowances.
The
market
provides
a
mechanism
to
find
least
cost
reductions,
so
that
units
that
would
have
a
high
cost
of
control,
can
choose
to
purchase
allowances
from
other
sources
at
a
price
below
their
control
costs.

EPA
disagrees
with
the
commenter
that
it
is
inappropriate
to
provide
additional
allowances
to
States
with
predominantly
coal­
fired
generation
because
they
will
make
the
largest
investment
in
advanced
emission
controls
under
the
CAIR.
EPA
analysis
has
shown
that
the
use
of
the
fuel
adjustment
factor
(
FAF)
methodology
reduces
the
disparity
between
the
projected
emissions
in
predominantly
coal­
fired
States
and
their
budgets.
EPA
believes
it
is
appropriate
to
consider
which
types
of
sources
are
making
reductions
for
the
CAIR.
EPA
disagrees
with
the
commenter's
assertion
that
in
determining
the
cost
of
compliance
CAIR,
the
cost
of
historical
decisions
 
such
as
the
decision
to
build
a
gas­
or
oil­
fired
plant
in
the
past
 
should
be
considered
as
part
of
CAIR.

EPA
disagrees
with
the
commenter
that
the
use
of
FAF
or
simple
heat
input
methodologies
for
apportioning
the
region
wide
NOx
emissions
budgets
to
the
States
will
significantly
impact
the
air
quality
modeling
results.
Because
allowances
can
be
traded
across
the
entire
region,
the
market
may
find
the
least­
cost
reductions
regardless
of
where
the
allowances
are
initially
allocated.
That
is,
sources
that
can
reduce
their
emissions
for
the
least
cost
will
do
so
whether
they
are
avoiding
having
to
purchase
an
allowance
or
reducing
their
emissions
and
selling
an
allowance
to
offset
the
control
costs.
In
this
case,
the
use
of
an
allowance,
whether
it
is
purchased
or
whether
it
is
an
opportunity
cost,
is
a
cost
to
the
unit.
As
a
result,
the
air
quality
modeling,
and
subsequent
findings
of
significant
contributions,
will
not
be
significantly
changed
by
the
approach
taken
for
the
apportionment
of
the
region
wide
budget.
EPA
has
over
15
years
of
experience
with
market
based
cap
and
trade
programs,
and
with
the
use
of
different
allocation
methods.
Markets
continue
to
operate
efficiently.
Sources
may
choose
from
many
alternatives
for
reducing
emissions,
including
installing
pollution
control
equipment,
switching
from
highsulfur
coal,
employing
energy
efficiency
measures
and/
or
renewable
generation,
and
buying
excess
allowances
from
other
sources
that
have
reduced
their
emissions,
or
using
a
combination
of
these
options.
The
flexibility
of
compliance
options
afforded
sources
has
lead
to
advancements
in
technology
and
costs
continuing
to
go
down.
A
cap
and
trade
system
allows
companies
to
choose
the
lowest
cost
compliance
option.
Cap
and
trade
programs
are
a
proven
mechanism
to
deliver
and
sustain
significant
mandatory
emission
reductions
and
have
been
recognized
worldwide
as
a
model
for
flexible
and
effective
air
pollution
regulation.
Through
cost­
effective,
market­
based
approaches,
environmental
and
economic
interests
can
be
aligned
rather
than
at
odds.

EPA
disagrees
with
the
commenter
that
our
analysis
is
flawed
because
we
under­
project
the
operation
of
existing
inefficient
gas­
and
oil­
fired
units,
and
therefore
under­
project
future
emissions
from
those
units.
As
noted
above,
EPA's
modeling
does,
in
fact,
include
the
generation
and
emissions
of
older
gas­
and
oil­
fired
units.
For
Florida,
the
CAIR
analysis
indicated
that
only
23
percent
of
these
units
would
be
retired
with
the
remainder
of
these
units
in
reserve
capacity.
Based
upon
information
submitted
by
the
commenter,
Florida
maintains
a
reserve
margin
of
at
least
20
percent
(
and
as
high
as
28
percent)
in
order
to
meet
annual
peak
demand,
allow
for
flexibility
in
which
units
are
dispatched,
allow
for
growth
in
demand,
and
allow
for
some
routine
outages.
4
As
a
result,
if
these
existing
oil­
and
gas­
fired
units
were
to
remain
in
the
generation
fleet,
they
would
likely
be
part
of
the
reserve
capacity
that
would
operate
infrequently.
If
EPA
modeling
results
for
these
infrequently
operated
units
differed
from
their
future
dispatch,
they
would
likely
not
significantly
change
the
statewide
emission
projections
due
to
their
low
total
emissions.

In
addition,
should
these
uneconomical
units
stay
in
operation
as
the
commenter
contends,
they
have
a
several
emission
control
options
available
to
them.
While
EPA
modeling
suggests
that
most
cost­
effective
controls
on
coal­
fired
plants,
this
does
not
mean
that
there
are
not
"
highly
cost
effective"
control
options
for
other
types
of
units.
There
are
limits
to
the
number
of
control
options
that
considered
in
a
model
and,
because
there
are
significantly
less
options
for
existing
oil­
and
gas­
fired
boilers,
EPA
has
not
provided
as
wide
a
range
of
control
options
for
these
units.
However,
EPA
analysis
has
shown
that
some
gas­
and
oil­
fired
units
have
already
achieved
emission
rates
as
low
as
0.18
lbs/
mmBtu
and
0.16
lbs/
mmBtu,
respectively,
without
having
to
install
post­
combustion
controls.
5
(
EPA
notes
that
IPM
does
not
model
the
installation
of
these
non­
post
combustion
control
strategies.)

While
the
commenter
has
claimed
that
existing
oil­
and
gas­
fired
units
would
remain
in
service,
they
have
not
provided
evidence
to
substantiate
it.
The
commenter
cites
"
A
Review
of
Florida
Electric
Utility
2005
Ten­
Year
Site
Plans."
However,
this
report
is
a
collection
of
information
provided
by
the
power
companies.
The
report
caveats
the
information
provided
by
saying
"
the
Ten­
Year
Site
Plans
are
not
a
binding
plan
of
action
on
electric
utilities"
and
continues
that
"
the
Ten­
Year
Site
Plans
are
planning
documents
containing
tentative
data."
Even
so,
the
commenter­
provided
report
shows
that
oil­
and
gas­
fired
capacity
(
identified
by
the
commenter
as
the
"
oil
and
gas
fossil
steam"
category)
oil­
and
gas­
fired
units
were
projected
to
dramatically
decline
in
the
2004
forecast,
with
the
2005
forecast
changing
to
show
a
slight
increase
in
capacity
 
showing
the
volatility
in
forecasts
of
this
nature.
This
2004
forecast
of
commenterprovided
report
is
consistent
with
actual
data
reported
to
EPA
under
the
Acid
Rain
Program
showing
that
operation
of
the
existing
oil­
fired
units
in
Florida
shows
a
declining
trend
for
the
years
2002
through
2005.6
In
summary,
the
commenter
has
not
provided
conclusive
information
of
their
claim
that
these
existing
gas­
and
oil­
fired
units
would
remain
in
service.
Further,
the
commenter
has
not
shown
that,
should
some
of
these
existing
units
remain
in
the
fleet,
they
would
operate
and
emit
at
levels
that
would
significantly
change
to
EPA
analysis
of
the
coverage
ratios.

4
The
commenter
cites
"
A
Review
of
Florida
Electric
Utility
2005
Ten­
Year
Site
Plans"
that
may
be
found
as
an
attachment
to
the
Florida
Power
and
Light
comments
in
the
docket
for
today's
rulemaking.
5
EPA
analysis
of
data
submitted
under
the
Acid
Rain
Program.
See
spreadsheet
"
Florida
Emission
Rates
Oil­
Gas
Units"
in
the
docket.
Emission
rates
are
for
combustion
control
strategies
(
i.
e.,
low
NOx
burners,
combustion
modification,
or
over­
fire
air
technologies)
other
than
the
installation
of
post­
combustion
controls.
Emission
rates
are
for
application
to
boilers
and
lower
emission
rates
can
be
expected
if
installed
on
simple
cycle
turbines.
In
general,
combustion
controls
are
less
expensive
than
installing
advanced
controls.
6
Data
reported
to
EPA
under
the
Acid
Rain
Program
shows
that,
for
Florida
oil­
fired
units,
heat
input
declined
from
approximately
408
million
mmBtu
in
2002
to
378million
mmBtu
in
2005.
Document
No.:
OAR­
2003­
0053­
2268.1
Commenter:
Northeast
States
for
Coordinated
Air
Use
Management
(
NESCAUM)
Comment:
Fuel
adjustment
factors
used
to
set
State
nitrogen
oxides
(
NOx)
budgets:
EPA
has
chosen
to
adjust
heat
input
data
for
allocations
based
on
factors
that
reflect
the
inherently
higher
emissions
rate
of
coal­
fired
plants.
EPA=
s
adjustment
factors
favor
the
sources
with
the
highest
emitting
fuel
and
disregard
the
economic
impact
of
having
fewer
allowances
allocated
to
States
where
electricity
costs
are
already
higher,
in
some
part,
due
to
a
higher
percentage
of
cleaner
natural
gas
facilities.
We
disagree
with
this
approach
as
it
effectively
results
in
allowance
subsidies
for
the
biggest
polluters.
States
that
have
already
benefited
from
lower
electricity
prices
because
of
the
lack
of
controls
on
coal­
fired
units
are
now
rewarded
with
additional
allowances,
and
States
that
have
more
energy
efficient
facilities
are
penalized
because
the
allocation
to
States
is
based
on
heat
input.
While
gas­
fired
plant
owners
have
been
paying
for
cleaner
fuel,
under
EPAs
chosen
approach,
they
may
be
penalized
with
the
additional
cost
of
purchasing
allowances
in
order
to
comply
with
CAIR.
Such
costs
would
be
passed
on
to
ratepayers
in
the
form
of
higher
electric
rates.
Furthermore,
EPA=
s
use
of
fuel
adjustment
factors
would
not
only
discourage
investment
in
new
cleaner
natural
gas
electric
generating
units,
but
also
discourage
investment
in
new
cleaner
coal­
fired
electric
generating
units
such
as
Integrated
Gasification
Combined
Cycle
(
IGCC)
technology.
In
addition,
EPA=
s
approach
locks
States
with
a
lower
percentage
of
coalfired
generation
into
a
lower
budget
that
may
not
accurately
account
for
future
emissions
under
different
conditions
(
e.
g.,
increasing
natural
gas
prices).
EPA
should
revert
to
the
fuel­
neutral
budget
calculation
methodology
it
proposed
for
CAIR
(
69
FR
4566)
so
that
cleaner,
more
efficient
sources
are
not
at
a
disadvantage
in
the
budget­
setting
process.
[[
(
2268.1,
pp.
1­
2)
]]

Response:
EPA
disagrees
with
the
commenter
for
reasons
explained
in
the
response
to
the
Connecticut
Department
of
Environmental
Protection.
In
addition,
EPA
disagrees
with
the
commenter's
assertion
that
the
use
of
a
FAF
methodology
would
"
discourage
investment
in
new
cleaner
coalfired
electric
generating
units
such
as
Integrated
Gasification
Combined
Cycle
(
IGCC)
technology."
EPA
notes
that
the
commenter
did
not
provide
analysis
to
support
this
claim.
Further,
EPA
believes
that
the
use
of
a
cap­
and­
trade
approach
inherently
provides
incentives
for
sources
to
generate
electricity
while
emitting
less.

Document
No.:
OAR­
2003­
0053­
2271.1
Commenter:
National
Mining
Association
Comment:
EPA=
s
application
of
equitable
concerns
is
logical
and
in
compliance
with
the
statute.
Entergy
is
mistaken
in
claiming
that
use
of
the
fuel
adjustment
factors
is
supported
by
no
more
than
EPA=
s
subjective
view
of
the
equities.
As
seen,
the
fuel
adjustment
factors
are
firmly
rooted
in
the
statute.
Nevertheless,
use
of
the
fuel
adjustment
factors
is
also
equitable.
EPA
partially
relied
on
equity
in
justifying
the
factors
and
that
reliance
is
authorized
by
the
statute.
[[
(
2271.1,
p.
11)
]]
In
its
December
2,
2005
Notice
of
Reconsideration,
EPA
aptly
described
the
equitable
factors
supporting
the
fuel
adjustment
factors.
Because
coal
plants
have
inherently
higher
emission
rates,
there
is
a
greater
burden
on
them
to
control
emissions.
The
fuel
adjustment
factors
would
not
penalize
coal
plants
that
had
already
installed
pollution
control
equipment.
Assuming
states
allocate
allowances
to
sources
in
the
same
way
they
are
allocated
to
the
states
gas­
fired
units
still
generally
receive
more
allowances
than
they
need
to
operate.
Use
of
the
fuel
adjustment
methodology
reduces
the
disparity
between
the
number
of
allowances
provided
and
emissions
as
compared
with
the
simple
heat
input
method.
As
EPA
found
the
fuel
factor
approach
generally
provides
additional
allowances
to
States
with
large
amounts
of
coal­
fired
units
that
are
making
the
investments
in
emission
control
measures
and
technologies.
Conversely,
the
simple
heat
input
approach
provides
more
allowances
to
States
with
larger
amounts
of
gas­
fired
units
that
are
not
making
reductions.
EPA=
s
results
did
not
change
even
when
tested
against
different
scenarios
of
electricity
demand
and
gas
and
oil
prices.
[[
(
2271.1,
pp.
11­
12)
]]

These
types
of
equitable
considerations
fit
comfortably
within
the
cost­
benefit
analysis
that
the
Michigan
Court
endorsed
under
Section
110(
a)(
2)(
D).
The
Michigan
Court
determined
that
the
word
"
significant"
in
the
phrase
"
significant
contribution"
expressed
Congress=
s
intent
that
EPA
balance
costs
and
benefits
in
determining
controls
states
would
be
required
to
implement.
According
to
the
Court,
EPA
may
consider
cost
that
go
beyond
simple
dollar
per
ton
control
costs
and
include
non­
health
tradeoffs.
The
Court=
s
discussion
is
plainly
framed
in
traditional
cost­
benefit
terms,
where
the
benefits
of
the
regulation
are
weighed
against
the
costs
to
society
of
achieving
those
benefits.
The
equitable
considerations
underlying
the
fuel
adjustment
factors
are
societal
costs
that
EPA
properly
considered
in
weighing
the
>
significance=
of
an
individual
state=
s
contribution
to
downwind
nonattainment.
[[
(
2271.1,
p.
12)
]]
Indeed,
both
the
NOX
SIP
Call
and
CAIR
as
proposed
in
the
NOPR
were
based
on
equitable
considerations
that
affect
the
cost
and
feasibility
of
complying
with
those
programs.

Both
programs
considered
the
feasibility
of
controls
(
in
terms
of
available
labor,
capital,
materials
and
equipment)
in
establishing
the
level
of
highly
cost­
effective
controls
and
the
deadlines
for
complying
with
the
programs.
In
determining
highly
cost­
effective
controls
under
CAIR,
EPA
stated:
The
second
major
factor
that
EPA
applies
is
the
cost
factor.
EPA
interprets
this
factor
as
mandating
emissions
reductions
in
amounts
that
would
result
from
application
of
highly­
cost
effective
controls.
We
ascertain
the
level
of
costs
as
highly
cost­
effective
by
reference
to
the
cost
effectiveness
of
recent
controls.
As
we
stated
in
the
CAIR
NPR,
in
determining
the
appropriate
level
of
controls,
we
considered
feasibility
issues
as
we
did
in
the
NOX
SIP
Call.
Specifically,
the
applicability,
performance,
and
reliability
of
different
types
of
pollution
control
technologies
for
different
types
of
sources,
and
other
implementation
costs
of
a
regulatory
program
for
any
particular
group
of
sources
(
NPR,
69
FR
4585).

That
rationale
applies
to
the
use
of
fuel
adjustment
factors,
which
reduce
the
burden
of
compliance
with
the
program
by
those
sources,
i.
e.,
coal­
fired
units
that
will
be
required
to
make
the
lion=
s
share
of
emissions
reductions.
Using
these
factors
promotes
program
feasibility,
a
goal
of
both
the
NOX
SIP
Call
and
the
CAIR
NOPR.
[[
(
2271.1,
p.
13)
]]
EPA
in
both
the
NOX
SIP
Call
and
the
CAIR
NOPR
also
explicitly
recognized
the
role
of
equity.
As
with
the
NOX
SIP
Call,
EPA
considers
other
factors
that
influence
the
application
of
the
air
quality
and
cost
factors,
and
that
confirm
the
conclusions
concerning
the
amounts
of
emissions
that
upwind
States
must
eliminate
as
contributing
significantly
to
downwind
nonattainment.
Specifically,
as
we
stated
in
the
CAIR
NPR
"
We
are
striving
in
this
proposal
to
set
up
a
reasonable
balance
of
regional
and
local
controls
to
provide
a
cost
effective
and
equitable
governmental
approach
to
attainment
with
the
NAAQS
for
fine
particles
and
ozone"
(
See
69
FR
4612).
In
this
manner,
we
broadly
incorporate
the
fairness
concept
and
relative­
cost­
of­
control
(
regional
costs
compared
to
local
costs)
concepts
that
we
generally
considered
in
the
NOX
SIP
Call
(
70
Fed.
Reg.
25,175.)
In
sum,
EPA=
s
use
of
equity
to
justify
the
fuel
adjustment
factors
is
authorized
by
the
statute.

Response:
The
commenter
generally
supports
use
of
the
FAF
methodology,
the
approach
taken
in
the
CAIR
and
CAIR
FIP.

Document
No.:
OAR­
2003­
0053­
2281.1
Commenter:
Northern
Indian
Public
Service
Company
(
NIPSCO)
Comment:
The
problems
of
inequity
are
not
present
in
the
CAIR
NOx
trading
programs.
The
approach
in
the
NOx
trading
programs
is
based
upon
a
more
recent
baseline,
is
not
rooted
in
the
Acid
Rain
Program,
and
is
more
relevant
to
today=
s
emissions
and
air
quality
circumstances.
It
is
poor
regulatory
policy
to
reward
coal­
fired
sources
that
have
not
taken
steps
to
reduce
emissions,
and
at
the
same
time
effectively
punish
low­
emitters
who
have
already
invested
in
equipment
to
reduce
emissions
from
their
coal­
tired
units.
It
sends
the
wrong
message.
It
discourages
actions
on
the
parts
of
industry
and
states
to
reduce
emissions
or
require
reductions
before
USEPA
has
decided
to
address
the
air
quality
issue.
Historically,
USEPA
has
recognized
and
given
credit
for
actions
taken
by
a
source
or
state
to
reduce
emissions
after
a
baseline
year.
USEPA
is
following
this
laudable
approach
in
the
8­
hour
ozone
Phase
II
Implementation
rule.
However,
USEPA
is
effectively
departing
from
this
approach
in
the
CAIR
SO2
program
by
clinging
to
the
Acid
Rain
Program
in
the
manner
it
has.
The
analyses
USEPA
performed
during
its
reconsideration
should
have
demonstrated
this
point.

Response:
The
commenter
generally
supports
use
of
the
FAF
methodology,
the
approach
taken
in
the
CAIR
and
CAIR
FIP.

XIX.
C.
EPA
did
not
properly
analyze
regionwide
or
state­
by­
state
impacts
of
using
fuel
factor
approach
(
both
preamble
and
TSD)

Document
No.:
OAR­
2003­
0053­
2282.1
Commenter:
South
Carolina
Public
Service
Authority
and
JEA
Comment:
EPA
correctly
asserts
in
its
analysis
of
the
methods
for
setting
state
NOx
budgets
that
there
is
a
strong
public
interest
in
an
allocation
method
that
has
the
lowest
possible
disparity
between
the
allowances
provided
to
a
state
and
the
state=
s
projected
emissions.
South
Carolina
Public
Service
Authority
and
JEA
believe
that,
in
the
Notice
of
Reconsideration=
s
discussion
of
the
issue
of
state
NOx
emission
budgets,
EPA
has
used
the
correct
criteria
and
analytical
approach
to
evaluate
the
reasonableness
of
its
methodology
against
alternatives:
(
1)
whether
the
EPA
method
avoids
penalizing
coal­
fired
generation
units
that
already
have
installed
emission
controls
and
(
2)
whether,
relative
to
the
alternatives,
the
EPA
method
better
minimizes
for
each
state
the
disparity
between
allowances
provided
and
projected
emissions.
On
these
bases,
EPA
concludes
that
its
method
­
which
is
based
on
recent
heat
input
data
adjusted
for
fuel
type
is
the
most
rational
approach.
[[
Docket
number
2282.1,
p.
4]][[
See
docket
number
2282.1,
pp4­
6
for
further
discussion
of
this
issue.]]

Response:
The
commenter
generally
supports
use
of
the
FAF
methodology,
the
approach
taken
in
the
CAIR
and
CAIR
FIP.

Document
No.:
OAR­
2003­
0053­
2290.1
Commenter:
Michigan
Department
of
Environmental
Quality
(
MI
DEQ)
Comment:
Additionally,
the
MDEQ
believes
that
EPA
failed
to
properly
count
the
total
number
of
subject
units
within
the
state,
therefore
underestimating
Michigan=
s
budget,
to
the
detriment
of
the
utilities
and
their
operations.
[[
(
2290.1,
p.
1)
]]
The
MDEQ
has
reviewed
the
data
that
the
EPA
provided
and
believes
that
since
Michigan
was
a
partial
state
during
the
NOx
SIP
Call
process,
the
EPA
failed
to
account
for
all
the
sources
in
the
state
when
they
calculated
the
budgets.
The
EPA=
s
data
indicates
that
only
130
units
were
included
in
the
calculations.
Michigan
data
indicates
there
are
155
units
that
should
have
been
included
in
the
calculations.
The
MDEQ
previously
requested
more
information
regarding
this
issue
on
October
12,
2005
through
an
email
sent
to
both
EPA
Region
5
and
Clean
Air
Markets
Division
staff.
See
Table
1
that
lists
Michigan
sources.
[[
(
2290.1,
p.
3)
]]
[[
(
Table
1
can
be
found
on
p.
4
of
docket
number
2290.1)
]]
The
MDEQ
believes
that
the
budget
amounts
for
Michigan
should
be
corrected
and
adjusted
upwards
to
account
for
the
16
percent
of
units
that
the
EPA
failed
to
include
in
their
calculations.
The
MDEQ
believes
that
the
NOx
CAIR
ozone
season
budget
should
be
adjusted
upwards,
as
indicated
in
Table
2
below.
[[
(
2290.1,
p.
3)
]]
[[
(
Table
2
can
be
found
on
p.
5
of
docket
number
2290.1)
]]

Response:
EPA
disagrees
with
the
commenter
that
Michigan's
heat
input
used
in
the
determination
of
budgets
should
be
adjusted
to
reflect
concerns
the
MI
DEQ
recently
communicated
to
EPA.
The
commenter
notes
that
they
"
requested
more
information
regarding
this
issue
on
October
12,
2005
through
an
e­
mail
sent
to
both
EPA
Region
5
and
Clean
Air
Markets
Division
staff."
EPA
is
taking
comment
through
this
rulemaking
on
only
certain
aspects
and
is
not
opening
for
comment
other
aspects,
such
as
the
heat
input
used
to
establish
regionwide
or
statewide
budgets,
that
were
finalized
in
the
CAIR
NFR.
As
a
result,
EPA
is
not
revising
the
Michigan's
heat
input
data
used
to
establish
CAIR
budgets.
However,
EPA
has
been
working
with
the
States
to
improve
unit
inventories
to
be
used
in
other,
future
processes,
such
as
applicability
determinations
and
the
development
of
unit­
by­
unit
allocations.
EPA
looks
forward
to
continuing
to
work
with
States
to
improve
the
information
used
in
the
implementation
of
the
CAIR.

In
setting
budgets,
EPA
used
data
reported
to
EPA
under
title
IV,
supplemented
by
data
reported
to
EIA
for
units
that
do
not
report
to
EPA.
Data
from
both
these
sources
cover
the
entire
State
of
Michigan,
not
just
the
portion
of
the
State
covered
by
the
NOx
SIP
Call.
Document
No.:
OAR­
2003­
0053­
2271.1
Commenter:
National
Mining
Association
Comment:
EPA
has
determined
each
state=
s
NOx
budget
as
a
pro
rata
share
of
a
region­
wide,
annual
cap
on
NOx
emissions.
Initially,
in
the
proposed
rulemaking,
each
state=
s
share
was
calculated
as
the
ratio
of
that
State=
s
annual
heat
input
to
the
CAIR
region=
s
annual
heat
input.
Subsequently,
in
the
final
CAIR
rule,
the
Agency
revised
its
method
for
calculating
each
state=
s
share
by
first
adjusting
that
state=
s
heat
input
from
each
fuel
type
by
a
fuel
adjustment
factor
for
that
fuel
type,
and
by
then
dividing
the
State=
s
aggregate
adjusted
heat
input
by
the
CAIR
region=
s
aggregate
adjusted
heat
input.
[[
(
2271.1,
pp.
3­
4)
]]

Petitioner
Entergy
Corporation
(
Entergy)
asserts
that
EPA=
s
fuel­
adjusted
heat
input
methodology
exceeds
the
Agency=
s
authority
under
Section
110(
a)(
2)(
D)
of
the
Clean
Air
Act.
Entergy=
s
primary
argument
is
that
EPA=
s
methodology
contradicts
EPA=
s
determination
that
the
amount
of
each
state=
s
emissions
reduction
should
reflect
the
use
of
>
highly
cost­
effective=
controls
on
EGUs
and
is
otherwise
not
authorized
by
the
statute.
Entergy
claims
that
use
of
the
fuel
adjustment
factors
is
based
on
no
more
than
EPA=
s
>
subjective
view
of
the
equities=
and
has
no
relationship
to
the
air
quality
objectives
of
the
statute.
[[
(
2271.1,
p.
4)
]]
Entergy
is
mistaken.
As
shown
below:

(
1)
use
of
the
fuel
adjustment
factors
is
neither
arbitrary
nor
capricious
but
rather
is
in
accordance
with
the
statutory
command
of
Section
110(
a)(
2)(
D)
that
each
state
eliminate
its
significant
contribution
to
nonattainment
in
a
different
state;

(
2)
as
a
reasonable
interpretation
of
its
authority
under
Section
110(
a)(
2)(
D),
EPA=
s
decision
to
use
fuel
adjustment
factors
will
be
entitled
to
deference
by
a
reviewing
court;

(
3)
EPA=
s
partial
reliance
on
equitable
considerations
was
reasonable
and
in
accordance
with
the
statute;
and
(
4)
use
of
the
fuel
adjustment
factors
promotes
rather
than
undermines
the
air
quality
purposes
of
the
statute.
[[
(
2271.1,
pp.
4­
5)
]]
The
fuel
adjustment
factors
accord
with
Section
110(
a)(
2)(
D).
In
the
NOPR,
EPA
computed
a
State=
s
NOx
budget
based
upon
its
pro
rata
share
of
the
CAIR
region=
s
annual
heat
input.
Under
this
approach,
each
state=
s
annual
NOx
emission
rate
from
EGUs
under
the
CAIR
would
have
been
the
same
as
the
region­
wide,
average
annual
emission
rate
from
EGUs,
i.
e.,
0.125
lb/
mmBtu
in
2015
(
0.15
lb/
mmBtu
in
2009).
[[
(
2271.1,
p.
5)
]]

Entergy
claims
that
EPA=
s
original
approach
is
the
only
rational
way
to
determine
a
state=
s
NOx
budget
consistent
with
the
statute.
According
to
Entergy,
unless
state
NOx
budgets
are
set
according
to
a
straight
heat
input
method
(
and
therefore
each
state
is
effectively
subject
to
the
same
annual
NOx
emission
rates),
there
can
be
no
assurance
that
emission
reductions
required
in
each
state
will
reflect
the
use
of
highly
cost­
effective
controls
on
EGUs.
[[
(
2271.1,
p.
5)
]]
Entergy=
s
view
of
the
fuel
adjustment
factors
is
incorrect.
In
fact,
EPA=
s
adoption
of
the
fuel
adjustment
factors
in
the
final
CAIR
is
a
more
accurate
method
of
ensuring
that
CAIR
emissions
reductions
are
set
according
to
the
statutory
"
significant
contribution"
standard
than
EPA=
s
original
approach
in
the
CAIR
NOPR.
This
is
because
the
final
rule
methodology,
unlike
the
NOPR
approach,
accounts
for
the
fact
that
each
state
has
a
different
mix
of
coal,
oil
and
gas
EGUs.

Because
of
these
differing
fuel
mixes,
application
of
highly
cost­
effective
controls
on
a
state­
bystate
basis
will
logically
yield
different
emission
reduction
profiles
among
the
different
states.
[[
(
2271.1,
p.
5)
]]
No
parties
dispute
the
facts
that:
(
1)
NOx
emissions
from
EGUs
are
a
strong
function
of
fuel
type
and
(
2)
the
relative
mix
of
EGU­
firing
by
coal,
oil
and
gas
varies
significantly
among
the
CAIR
states.
Furthermore,
the
application
of
highly
cost­
effective
controls
to
a
coal­
fired
EGU
will
consistently
result
in
a
NOx
emission
rate
higher
than
the
comparable
rate
obtained
by
applying
those
controls
to
either
a
gas­
fired
or
an
oil­
fired
unit.
Therefore,
the
application
of
highly
cost­
effective
controls
to
NOx
emissions
from
each
state=
s
EGUs
realistically
cannot
result
in
each
state=
s
controlled
NOx
emission
rate
being
identical
because
the
amounts
of
EGU
NOx
emissions
from
(
1)
coal,
(
2)
oil
and
(
3)
gas
each
vary
appreciably
among
the
states.
[[
(
2271.1,
p.
6)
]]
Indeed,
from
NOx
emission
data
for
each
fuel
type
recently
burned
in
the
CAIR
region=
s
EGUs,
EPA
determined
that
the
NOx
emission
rate
from
those
EGUs
firing
gas
was
only
40%
of
the
NOx
emission
rate
from
the
region=
s
coal­
fired
units.
Similarly,
the
Agency
found
that
the
NOx
emission
rate
from
the
region=
s
oil­
fired
EGUs
was
only
60%
of
that
emission
rate
from
the
EGUs
firing
coal.
Therefore,
to
account
for
this
inherent
NOx
emission
variability
as
a
function
of
fuel
type,
EPA
multiplied
each
state=
s
annual
heat
input
from
each
fuel
type
by
a
>
fuel
factor=
for
that
fuel
type
(
1.0
for
coal,
0.6
for
oil
and
0.4
for
gas)
to
obtain
an
>
adjusted
heat
input=
for
that
fuel
type.
[[
(
2271.1,
p.
6)
]]

In
this
fashion,
EPA
accounted
for
the
fact
that
some
states
have
a
greater
percentage
of
coal
units
in
their
generation
mixes
than
others.
The
only
justification
for
calculating
state
NOx
budgets
using
a
uniform
NOx
emission
rate,
as
Entergy
urges,
would
be
if
every
state
had
the
same
mix
of
fossil
resources.
But
they
don=
t.
[[
(
2271.1,
p.
6)
]]
It
is
true,
as
Entergy
says,
that
use
of
fuel
adjustment
factors
increases
NOx
budgets
for
the
more
coal­
fired
states
at
the
expense
of
the
more
gas­
fired
states
as
compared
with
the
NOPR
allocation
methodology.
But
this
is
reflective
of
the
fact
that
the
NOPR
allocation
method
failed
to
account
for
the
different
generation
mixes
and
therefore
different
NOx
emission
rates
in
each
state.

If
one
performed
a
state­
by­
state
analysis
of
the
emission
reductions
each
state
would
make
through
application
of
highly
cost­
effective
controls,
there
is
no
question
that
states
with
a
greater
proportion
of
gas­
fired
units
would
be
subject
to
less
extensive
control
requirements
than
states
with
a
greater
proportion
of
coal­
fired
units.
Gas­
fired
plants
emit
much
less
NOx
than
coal­
fired
plants,
and
the
cost
of
control
at
gas­
fired
plants
is
much
higher
than
at
coal­
fired
plants.
Thus,
EPA=
s
use
of
fuel
adjustment
factors
does
no
more
than
reflect
the
fact
that
states
with
the
higher
amounts
of
coal
power
in
their
generating
mixes
are,
as
compared
with
states
with
higher
amounts
of
gas
power,
(
a)
greater
NOx
emitters,
(
b)
would
be
required
to
control
more
through
the
application
of
highly
cost­
effective
controls,
and
(
c)
therefore
are
assigned
higher
budgets.
[[
(
2271.1,
p.
7)
]]
As
EPA
found,
although
states
such
as
Louisiana
will
indeed
receive
a
lower
NOx
budget
than
they
would
under
the
NOPR
methodology,
in
general
Louisiana
and
the
other
gas­
fired
states
will
receive
sufficient
allowances
to
continue
operations
without
having
to
purchase
allowances.
States
that
are
not
primarily
coal­
fired
should
not
be
assigned
budgets
as
if
they
were,
and
as
if
they
were
going
to
have
emission
reduction
costs
that
they
will
not
in
fact
bear.
[[
(
2271.1,
p.
7)
]]
As
a
reasonable
response
to
Section
110(
a)(
2)(
D),
EPA=
s
methodology
will
be
entitled
to
judicial
deference.
Section
110(
a)(
2)(
D)
prohibits
any
state=
s
emissions
from
contributing
significantly
to
another
state=
s
nonattainment.
The
statute
is
silent
on
the
meaning
of
the
term
>
significant
contribution.=
In
Michigan
v.
EPA,
213
F.
3d
663,
678
(
D.
C.
Cir.
2000),
the
Court
found
this
phrase
was
ambiguous.
The
Court
upheld
as
permissible
EPA=
s
interpretation
of
that
term
as
the
quantity
of
out­
of­
state
contribution
that
would
be
eliminated
if
a
state=
s
emissions
were
reduced
by
an
amount
achievable
using
>
highly
cost­
effective=
controls
on
EGUs
in
that
state.
Id.
At
678­
79.
[[
(
2271.1,
p.
8)
]]
Because
the
statute
is
silent
on
how
EPA
must
interpret
the
term
"
significant
contribution"
a
reviewing
court
will
ask
whether
EPA=
s
interpretation
is
based
on
a
permissible
construction
of
the
statute.
EPA
must
demonstrate
a
reasonable
connection
between
the
facts
on
the
record
and
its
decision
made
pursuant
to
its
statutory
authority.
[[
(
2271.1,
p.
8)
]]

The
facts
in
this
case
overwhelmingly
confirm
the
reasonableness
of
EPA=
s
decision
to
use
fuel
factors
in
determining
state
NOx
budgets.
As
noted,
the
initial
methodology
considered
by
EPA
in
the
CAIR
NOPR
for
setting
State
NOx
budgets
required
all
states
to
have
the
same
NOx
emission
rate
after
application
of
controls
to
eliminate
each
state=
s
significant
contribution.
That
result
plainly
does
not
accurately
depict,
or
even
approximate,
what
the
result
would
be
in
each
state
if
each
was
required
to
install
highly
cost­
effective
controls.
As
such,
that
approach
provides
no
assurance
that
each
state=
s
significant
contribution
to
downwind
nonattainment
will
actually
be
eliminated.
[[
(
2271.1,
pp.
8­
9)
]]
By
contrast,
the
alternate
methodology,
using
fuel
factors
to
account
for
variations
in
NOx
emissions
as
a
function
of
fuel
type,
provides
a
realistic
approximation
of
the
NOx
emissions
actually
remaining
in
each
state
after
application
of
highly
cost­
effective
controls
to
EGUs.
In
doing
so,
that
methodology
provides
confidence
that
it
will
result
in
eliminating
each
state=
s
significant
contribution.
[[
(
2271.1,
p.
9)
]]
EPA=
s
use
of
fuel
factors
to
more
accurately
quantify
remaining
NOx
emissions
in
each
state,
thereby
providing
greater
assurance
that
the
State=
s
significant
contribution
is
eliminated,
is
clearly
a
reasonable
decision
and
one
that
will
therefore
be
entitled
to
judicial
deference.

After
all,
the
better
a
regulatory
provision
satisfies
its
statutory
objective,
the
more
rational
that
agency
decision
is.
[[
(
2271.1,
p.
9)
]]
Entergy
misinterprets
the
Michigan
case
by
claiming
the
Court
endorsed
the
CAIR
NOPR
methodology,
which
was
the
same
methodology
used
in
the
NOX
SIP
Call,
as
the
only
one
allowable
under
Section
110(
a)(
2)(
D).
To
the
contrary,
the
Michigan
Court
found
that
EPA=
s
interpretation
of
Section
110(
a)(
2)(
D)
was
permissible,
not
exclusive.
As
shown
above,
the
methodology
used
in
the
final
CAIR
improves
on
the
methodology
proposed
in
the
NOPR
by
providing
a
better
approximation
of
what
a
state=
s
actual
significant
contribution
to
downwind
nonattainment
may
be.
For
that
reason,
the
final
CAIR
methodology
is
also
a
permissible
interpretation
of
the
statute.
[[
(
2271.1,
p.
9)
]]
Entergy
also
argues
that
use
of
the
fuel
adjustment
factors
contradicts
EPA=
s
own
determination
that
the
amount
of
each
state=
s
emissions
reductions
should
reflect
the
use
of>
highly
cost­
effective
controls
on
EGUs.
Relying
on
statements
in
the
NOPR
preamble,
Entergy
maintains
that
EPA
has
previously
determined
that
highly
cost­
effective
controls
on
EGUs
were
those
that
could
achieve
an
emission
rate
of
0.15
lb/
mmBtu
by
2009
and
0.125
lb/
mmBtu
by
2015.
[[
(
2271.1,
pp.
9­
10)
]]
Again,
Entergy
misapprehends
EPA=
s
underlying
methodology.
EPA
applied
highly
costeffective
controls
to
EGUs
throughout
the
region
and
determined
a
region­
wide
average
emission
rate
(
and
therefore
determined
the
regional
significant
contribution
to
downwind
nonattainment).
EPA
never
determined
that
this
region­
wide
average
emission
rate
necessarily
reflects
the
emission
rate
that
would
result
in
a
particular
state
through
the
application
of
highly
costeffective
controls
in
that
state.
As
shown
above,
such
a
conclusion
would
not
be
correct.
As
seen,
the
states
within
the
CAIR
region
have
different
mixes
of
generation
and
therefore
logically
should
not
have
their
budgets
calculated
using
the
same
NOX
rate
per
MMBtu.
It
is,
therefore,
entirely
rational
for
EPA,
having
computed
a
region­
wide
average
NOX
rate
per
MMBtu,
to
utilize
fuel
adjustment
factors
to
ensure
that
an
individual
state=
s
budget
reflects
that
state=
s
individual
fuel
mix,
control
costs,
and
significant
contribution
to
downwind
nonattainment.
[[
(
2271.1,
p.
10)
]]
It
is
true
the
simple
heat
input
methodology
proposed
in
the
NOPR
preamble
would
have
resulted
in
all
of
the
CAIR
region
states
having
the
identical
NOX
emissions
rates
after
application
of
CAIR
controls.
But
EPA
is
certainly
not
precluded
from
developing
a
modified
methodology
in
the
final
rule
as
a
result
of
comments,
one
that
more
accurately
reflects
individual
states=
significant
contribution
to
downwind
nonattainment.
After
all,
obtaining
the
best
result
is
the
purpose
of
notice
and
comment
rulemaking.
[[
(
2271.1,
pp.
10­
11)
]]

Response:
The
commenter
generally
supports
use
of
the
FAF
methodology,
the
approach
taken
in
the
CAIR
and
CAIR
FIP.

Document
No.:
OAR­
2003­
0053­
2283.1
Commenter:
Entergy
Corporation
Comment:
Entergy
owns
and
operates
power
plants
that
are
directly
affected
by
CAIR
and
the
fuel
adjustment.
Entergy
is
an
integrated
energy
company
engaged
primarily
in
electric
power
production,
transmission,
retail
distribution
operations,
energy
marketing
and
trading,
and
gas
transportation.
Entergy
owns
and
operates
power
plants
with
approximately
30,000
megawatts
of
electric
generating
capacity
and
is
the
second
largest
nuclear
generator
in
the
United
States.
Through
power
plants
located
in
Louisiana,
Mississippi,
Texas,
and
Arkansas,
Entergy
delivers
electricity
to
2.6
million
utility
customers
in
those
States.
Each
of
these
states
is
regulated
under
CAIR
and
the
annual
NOx
budgets
for
Louisiana,
Mississippi
and
Texas
(
Arkansas
is
not
subject
to
annual
NOx
reductions)
were
significantly
reduced
by
the
fuel
adjustment.
[[
docket
number
2283.1,
p.
1]]

Entergy
strenuously
objects
to
the
use
of
the
fuel
adjustment
in
setting
the
states=
annual
and
ozone­
season
NOx
budgets
under
CAIR.
Entergy
urges
EPA
to
revise
CAIR
so
that
the
state=
s
NOx
budgets
are
those
set
forth
in
the
Final
Rule
without
the
application
of
the
fuel
adjustment.
Entergy=
s
comments
are
provided
below.
[[
docket
number
2283.1,
p.
1]]

The
Fuel
Adjustment
Significantly
Redistributed
the
States=
NOx
Budgets
from
the
Periphery
to
the
Center
of
the
CAIR
Region.[[
docket
number
2283.1,
p.
1]]
[[
See
docket
number
2283.1,
pp.
1­
2
for
further
discussion
of
this
issue.
Also
see
Attachments
1­
3
at
docket
number
2283.1,
pp.
16­
18.]]]]
V.
EPA=
s
Claim
that
the
Budgets
of
States
Disadvantaged
by
the
Fuel
Adjustment
are
Sufficient
to
Cover
Their
Future
Emissions
Belies
any
Justification
for
Including
These
States
in
CAIR.
EPAs
claim
that
the
fuel
adjustment
does
no
harm
to
states
with
significant
gas
and
oil
generation
contradicts
the
very
rationale
for
requiring
these
States
to
make
NOx
reductions
under
CAIR
in
the
first
place.
This
contradiction
reveals
the
arbitrariness
of
the
fuel
adjustment
EPA
attempts
to
justify.
[[
docket
number
2283.1,
p.
6]]
[[
See
docket
number
2283.1,
pp.
6­
8
for
discussion
of
this
issue.]]
VI.
The
Fuel
Adjustment
Contradicts
EPA=
s
Own
Determination
that
Each
State=
s
Reduction
is
Based
on
Highly
Cost
Effective
Controls.
[
docket
number
2283.1,
p.
8]]
[[
See
docket
number
2283.1,
pp.
8­
9
for
discussion
of
this
issue.]]
VII.

The
Clean
Air
Act
Does
Not
Authorize
EPA
to
Base
a
State=
s
Budget
on
Factors
Wholly
Unrelated
to
Air
Quality.
[[
docket
number
2283.1,
p.
9]]
See
docket
number
2283.1,
pp.
9­
12
for
discussion
of
this
issue.]]
VIII.
EPA=
s
Claim
that
the
Fuel
Adjustment
will
not
Materially
Affect
the
Magnitude
and
Location
of
Emission
Reductions
Is
Erroneous.
[
Docket
number
2283.1,
p.
12]]
[[
See
docket
number
2283.1,
pp.
12­
14
for
discussion
of
this
issue.
Also
see
Attachments
4
and
5
at
docket
number
2283.1,
pp.
19
and
20.]]
IX.
EPA=
s
Failure
to
Re­
run
the
Air
Quality
Models
to
Assess
the
Effects
of
the
Changes
in
Emission
Reductions
Resulting
from
the
Fuel
Adjustment
is
Arbitrary.
[
docket
number
2283.1,
p.
14]]
[[
See
docket
number
2283.1,
pp.
14­
15
for
discussion
of
this
issue.]]

The
Fuel
adjustment
inappropriately
rewards
higher­
emitting
coal
generation
and
penalizes
prior
investments
in
lower­
emitting
gas
and
oil
generation.
[[
docket
number
2281.1,
p.
2]]
[[
See
docket
number
2283.1,
pp.
2­
4
for
further
discussion
of
this
issue.]]
III.
EPA=
s
Assumption
that
Coal­
Fired
Units
Will
Bear
the
Burden
of
Emission
Reductions
under
CAIR
is
Wrong.
[[
docket
number
2283.1,
p.
4]]
See
docket
number
2283.1,
pp.
4­
5
for
discussion
of
this
issue.]]
IV.
EPA=
s
Assumptions
about
the
Early
Retirement
of
Gas
and
Oil
Units
are
Erroneous.
[[
docket
number
2283.1,
p.
5]]
See
docket
number
2283.1,
pp.
5­
6
for
discussion
of
this
issue.]]

Response:

EPA
disagrees
with
the
commenters
claim
that
the
use
of
a
FAF
approach
effectively
increases
the
levels
of
emission
reductions
mandated
for
Louisiana
(
or
any
of
the
CAIR
States).
Because
CAIR
uses
a
regionwide
cap­
and­
trade
approach,
it
is
possible
for
sources
in
any
State
to
purchase
emission
allowances
on
the
market
 
effectively
finding
least
cost
reductions
no
matter
where
in
the
CAIR
region
the
controlling
source
is
located.
This
is
independent
of
the
original
distribution
of
allowances.
EPA's
position
is
based
upon
experience
with
the
highly
successful
Acid
Rain
Program,
the
NOx
SIP
Call
program,
and
extensive
modeling
that
the
Agency,
the
Energy
Information
Administration,
and
other
groups
have
done
with
optimization
models
designed
to
consider
this
issue.
The
commenter
provided
no
analysis
to
support
their
claim.
In
addition,
EPA
analysis
presented
in
the
Notice
of
Reconsideration
demonstrates
that
the
States
with
predominantly
non­
coal
generation
will
have
an
excess
of
allowances
under
either
the
FAF
or
simple
heat
input
approaches.

Similarly,
EPA
also
disagrees
with
the
commenter
that
the
use
of
a
FAF
approach
"
contradicts
EPA's
own
decision
to
base
emission
reductions
on
the
use
of
highly
cost
effective
controls."
EPA
determined
that
"
highly
cost­
effective
reductions"
were
available
from
the
power
sector
in
the
entire
CAIR
region.
This
regionwide
determination
was
independent
of
any
particular
method
of
apportioning
the
regionwide
emission
cap
to
the
States.
As
a
result,
the
commenters'
contention
that
EPA
must
conduct
a
new
cost­
effectiveness
determination
using
the
FAF
approach
statewide
budgets
is
not
justified.
As
mentioned
above,
determination
of
emissions
reductions
that
are
highly
cost
effective
depends
on
the
cost
of
pollution
controls
that
are
used
to
minimize
compliance
costs,
not
the
distribution
of
allowances
to
any
one
source
or
State
within
the
CAIR
region
where
emission
reductions
that
free­
up
allowances
that
can
be
sold
to
other
electric
generation
units
covered
by
the
program.
Additionally,
under
a
regionwide
cap­
andtrade
approach,
the
market
approach
allows
sources
to
find
the
least
cost
reductions.
Furthermore,
EPA
chose
to
implement
the
FAF
methodology
because
it
generally
reduced
the
disparity
between
the
projected
statewide
emissions
under
CAIR
and
the
allowance
budgets
of
the
States.

The
commenter
claims
that
use
of
the
FAF
approach
would
shift
the
"
burden
of
emission
reductions"
to
the
"
outer
edges
of
the
CAIR
region."
Some
limited
analysis
to
support
this
claim
was
provided
by
the
commenter.
However,
EPA
disagrees
with
the
commenter's
claim
the
use
of
the
FAF
approach
leads
to
"
shifting 
emissions 
closer
to
the
affected
downwind
nonattainment
areas
intended
to
benefit
from
CAIR."
EPA
analysis
has
shown
that
using
either
the
simple
heat
input
or
the
FAF
methodologies,
the
CAIR
results
in
the
same
emission
reductions
taking
place
at
the
same
sources.
Use
of
the
FAF
approach
simply
shifts
who
pays
and
how
much
they
pay
for
emission
reductions,
as
well
as
the
amount
some
States
with
lower
emission
rates
already
might
stand
to
make
without
doing
anything
to
benefit
the
environment.
As
stated
earlier,
EPA
modeling
shows
that
States
with
predominantly
coal­
fired
generation
(
i.
e.,
those
States
that
receive
slightly
more
allowances
under
a
FAF
approach)
are
projected
to
make
larger
investments
in
emission
controls
under
CAIR.
The
commenter
did
not
provide
analysis
to
demonstrate
that
emissions
would
increase
in
States
that
are
closer
to
affected
downwind
nonattainment
areas.

EPA
also
disagrees
with
the
commenters
claim
that
"
EPA's
assumption
that
coal­
fired
units
will
bear
the
burden
of
emission
reductions
under
CAIR
is
wrong."
In
support
of
their
claim,
the
commenter
submitted
some
limited
data
produced
by
Entergy
modeling.
This
limited
information
shows
3
units
owned
by
the
commenter
projected
to
emit
at
levels
greater
than
their
projected
allocations.
However,
it
is
not
possible
for
the
commenter
to
determine
their
unit­
level
allocations
as
these
States
have
not
finalized
their
CAIR
SIP
rules.
EPA's
comparison
of
projected
emissions
to
the
regionwide
and
State
budgets
finalized
in
CAIR
provides
a
more
appropriate
measure.
In
addition,
EPA
disagrees
with
the
commenter
that
their
claimed
demonstration
that
3
of
their
units
might
have
to
purchase
allowances
shows
that
coal­
fired
generation
would
not
"
bear
the
burden
of
[
the]
emission
reductions
under
CAIR."
EPA
modeling
shows
all
additional
pollution
control
occurring
on
coal­
fired
units.
From
this
EPA,
believes
that
coal­
fired
generation
would
bear
the
burden
of
reducing
emissions
in
the
CAIR.
The
commenter
has
provided
no
analysis
to
demonstrate
that,
as
a
group,
coal­
fired
units
would
not
make
the
bulk
of
the
significant
emission
reductions
under
CAIR.
Finally,
the
commenter
did
not
provide
the
modeling
results,
information
on
the
model
or
its
assumptions,
or
even
the
name
of
the
model
used
in
reference
to
this
claim.
As
a
result,
the
commenter
has
not
substantiated
the
limited
results
of
their
analysis
and
has
not
demonstrated
that
it
is
more
valid
that
EPA
modeling
that
is
based
upon
the
IPM
model.
Again,
commenters
claim
that
use
of
a
FAF
approach
invalidates
the
air
quality
modeling.
Under
a
cap­
and­
trade
approach,
the
market
allows
emission
reductions
take
place
at
the
facilities
with
lowest
control
costs.
This
is
independent
of
the
original
allowance
distribution.
Whether
a
unit
is
avoiding
the
need
to
purchase
an
allowance
or
freeing­
up
an
allowance
for
sale,
the
unit
has
incentive
to
control
its
emissions
if
it
can
do
so
for
less
than
the
market
price
for
an
allowance.
As
a
result,
EPA
believes
the
environmental
impacts
would
not
differ
by
the
approach
taken
to
develop
statewide
budgets
or
unit­
by­
unit
allocations.
EPA's
position
is
based
upon
experience
with
the
highly
successful
Acid
Rain
Program
and
NOx
SIP
Call
and
its
modeling
has
withstood
litigation.
EPA
notes
that
the
modeling,
in
the
context
of
the
NOx
SIP
Call,
has
not
been
challenged
on
this
aspect
by
anyone
but
Entergy.
Notably,
Entergy
challenges
EPA
with
rhetorical
arguments.
The
commenter
provided
no
analysis
to
support
their
claim
or
indicate
that
the
selection
of
any
approach
for
developing
the
State­
level
budgets
would
significantly
impact
the
air
quality
modeling.

EPA
disagrees
with
the
comment
challenging
EPA's
decision
to
base
a
state's
budget
on
heat
input
adjusted
by
fuel
type
on
the
basis
that
the
Clean
Air
Act
doesn't
authorize
this
approach.
The
Clean
Air
Act
does
not
require
a
program
like
CAIR,
but
EPA
believes
we
have
the
authority
to
put
it
into
place
as
we
did
in
similar
circumstances
to
address
ozone
problems
with
the
NOx
SIP
Call.
In
that
case,
the
also
was
not
an
explicit
authorization
for
an
allocation
methodology
to
apportion
the
regionwide
budget
to
the
States
and
the
Agency
did
what
makes
sense.
EPA
is
doing
what
makes
sense
in
the
CAIR
as
well.
EPA
believes
the
comment
doesn't
accurately
characterize
the
approach
taken
by
EPA
in
promulgating
the
NOx
SIP
Call
and
the
CAIR.
EPA
further
disagrees
with
the
suggestion
that
the
only
approach
to
developing
state
budgets
authorized
by
the
CAA,
is
an
approach
based
on
heat
input,
unadjusted
by
fuel
factors.
In
developing
CAIR,
EPA
examined
various
methods
for
allocating
shares
of
the
regional
cap
to
the
states.
For
reasons
explained
in
the
preamble
to
the
final
CAIR
and
in
the
Notice
of
Final
Action
on
Reconsideration,
EPA
decided
to
use
a
method
that
considered
the
heat
input
of
sources
in
each
state,
adjusted
by
fuel
factors.
EPA
determined
that
this
approach
provides
states
with
allowances
more
in
proportion
with
their
historical
emissions.
It
also
provides
for
a
more
equitable
budget
distribution
by
recognizing
that
different
states
are
facing
the
reduction
requirements
with
different
starting
stocks
of
generation
and
different
starting
emission
profiles.
EPA
further
believes
that
states
receiving
larger
budgets
under
the
fuel
factor
approach
are
generally
expected
to
be
those
having
to
make
the
most
reductions.
(
70
FR
25231).
EPA's
decision
to
use
the
fuel
factor
approach
to
divide
the
regional
cap
into
state
budgets
thus
was
based,
in
part,
on
considerations
related
to
the
cost
burden
of
installing
controls
in
that
state.
The
Courts
have
held
that
"
it
is
only
where
there
is
'
clear
congressional
intent
to
preclude
consideration
of
costs'
that
we
find
agencies
barred
from
considering
costs.
Michigan
v.
EPA,
213
F.
3d
663,
687
(
D.
C.
Cir.
2000);
see
also,
Grand
Canyon
Air
Tour
Coalition
v.
FAA,
154
F.
3d
455,
475
(
D.
C.
Cir.
1998).
Further,
commenter
has
not
shown
that
their
preferred
method
of
developing
state
budgets
(
using
heat
input
unadjusted
by
fuel
factor)
has
any
more
connection
to
air
quality
than
EPA's
approach.
Developing
state
budgets
based
on
petitioners
preferred
approach
would
simply
result
in
a
different
allocation
of
the
cost
burden.

EPA
disagrees
with
the
commenters'
claim
that
fuel
adjustment
factors
are
inequitable
or
unfairly
impact
the
citizens
of
Louisiana,
Texas,
and
Mississippi,
simply
because
they
reduce
the
budgets
for
States
with
predominantly
oil­
and
gas­
fired
generation.
Notably,
the
State
governments
representing
the
citizens
of
Louisiana,
Texas,
and
Mississippi
have
not
made
this
argument.
As
explained
in
the
preamble
for
today's
rule,
EPA
analysis
has
demonstrated
that
the
use
of
an
FAF
approach
reduces
the
disparity
between
a
States'
projected
emissions
and
its
budget.
In
addition,
it
is
appropriate
to
provide
additional
allowances
to
predominantly
coalfired
States
because
they
are
projected
make
most
of
the
CAIR­
driven
investment
in
advanced
emission
controls.
Further,
EPA
analysis
presented
in
the
Notice
of
Reconsideration
demonstrates
that
the
States
with
predominantly
non­
coal
generation
will
have
an
excess
of
allowances
under
either
the
FAF
or
simple
heat
input
approaches.
The
commenter
provided
no
analysis
to
show
that
these
States
would
be
disproportionately
impacts
compared
to
other
States.
(
The
EPA
response
to
comments
from
the
Connecticut
Department
of
Environmental
Protection
and
the
Northeast
States
for
Coordinated
Air
Use
Management
also
discusses
this
point.)

EPA
also
disagrees
with
the
commenters
assertion
that
the
use
of
the
FAF
approach
forces
States
with
relatively
high
gas­
and
oil­
fired
capacity
to
meet
the
CAIR
obligation
by
using
the
EPAadministered
cap­
and­
trade
program.
EPA
maintains
that
States
have
flexibility
to
attain
reductions
how
they
wish.
Our
analysis
indicates
the
allowance
allocations
like
this
have
no
bearing
on
fuel
choice.
Entergy
fails
to
show
in
any
way
that
it
does
have
an
impact
 
they
simply
assert.
In
fact,
EPA
analysis
for
the
Notice
of
Reconsideration
demonstrated
that
States
with
predominantly
non­
coal
fired
generation
would
have
an
excess
of
allowances
relative
to
their
projected
emissions.
In
other
words,
States
with
predominantly
non­
coal
fired
generation
would
likely
a
sufficient
emissions
budget
using
the
EPA­
administered,
regionwide
trading
program
or
another
mechanism.

Given
the
sophistication
of
a
major
company
like
Entergy
we
believe
they
are
simply
resorting
to
a
set
of
rhetorical
blasts
on
an
approach
that
redistributes
the
wealth
gained
from
allowance
holding
in
a
less
beneficial
way
to
their
company.

Document
No.:
OAR­
2003­
0053­
2266
Commenter:
Environmental
Energy
Alliance
of
New
York
Comment:

The
Notice
of
Reconsideration
states
"
In
the
absence
of
other
considerations,
EPA
believes
that
it
is
in
the
public
interest
to
reduce
the
disparity
between
the
number
of
allowances
in
a
State
budget
and
total
projected
State
ECU
emissions."
These
comments
argue
that
EPA=
s
total
projected
State
EGU
emissions
are
not
accurate
or
representative
and
as
a
result,
fuel
adjustment
factors
exacerbate
a
potential
problem.
[[
(
p.
1)
]]

These
comments
have
described
several
potential
problems
with
CAIR
implementation.
This
is
of
particular
concern
because
the
fuel
adjustment
factors
used
by
EPA
exacerbate
the
problems
identified.
The
CAIR
IPM
modeling
analyses
apparently
predict
much
more
optimistic
emission
reductions
in
the
base
case
than
is
likely
in
the
Northeast
in
general
and
New
York,
in
particular.

The
CAIR
baseline
appears
to
inadequately
represent
typical
annual
energy
use
for
a
majority
of
sites
in
the
region
so
more
baseline
NOX
than
was
modeled
is
expected.
Since
the
implementation
of
the
Acid
Rain
Program,
there
has
been
a
persistent
trend
of
source
ownership
consolidation
and
fewer
trading
entities.
For
New
York
sources
these
factors
and
the
inappropriate
fuel
adjustment
factor
adjustment
will
require
more
stringent
and
therefore
inequitable
control
efficiencies
or
reliance
on
the
market.
[[
(
pp.
6­
7)
]]
Individually,
issues
raised
here
may
not
affect
the
viability
of
a
future
program.
However,
the
overarching
concern
is
that
if
the
effects
of
these
problems
turn
out
to
be
significant
individually
and
all
turn
out
worse
than
expected,
the
combined
impact
may
affect
the
viability
of
a
robust
trading
market.
If
there
is
not
a
robust
market,
sources
will
be
forced
into
internal
control
programs
stringent
enough
to
meet
their
level
of
allotted
allowances
and
at
costs
significantly
higher
than
expected.
The
worst
case
would
be
if
sources
cannot
implement
internal
control
programs
soon
enough
to
meet
their
compliance
obligations
and
the
market
has
no
allowances
available.
At
that
point,
sources
may
have
no
option
but
to
stop
operating,
putting
electric
system
reliability
at
risk.
[[
(
p.
7)
]]

When
the
CAIR
cap
and
trade
program
was
developed,
it
was
necessary
to
project
future
emissions
and
energy
use.
The
impact
of
the
trading
program
was
compared
to
the
modeled
baseline
to
predict
the
emission
reductions
and
cost
of
the
program.
In
order
for
those
impacts
to
be
accurate,
the
baseline
emission
modeling
must
project
a
reasonable
description
of
the
future.
[[
(
pp.
1­
2)
]]
EPA
used
ICF=
s
Integrated
Planning
Model
(
IPM)
to
evaluate
the
energy
and
emissions
effects
of
CAIR.
In
this
evaluation,
modelers
compared
a
base
case
without
the
proposed
trading
program
to
a
projected
case
that
includes
the
proposed
trading
program.
A
particular
concern
for
the
CAIR
analysis
is
that
the
CAIR
baseline
emissions
analysis
for
New
York
is
significantly
different
and
less
representative
than
subsequent
IPM
modeling
performed
for
the
Regional
Greenhouse
Gas
Initiative
(
RGGI)
recently
proposed
for
9
Northeast
and
Mid­
Atlantic
States.
[[
(
p.
2)
]]

Many
influential
assumptions
used
in
the
RGGI
IPM
model
runs
are
not
consistent
with
those
used
in
the
CAIR
analysis.
For
example,
in
the
CAIR
base
case
the­
model
predicts
that
45.6%
of
the
electric
generation
capacity
has
no
annual
heat
input
and
22.7%
of
the
capacity
will
retire.
This
reduction
in
generation
and
the
resulting
drop
in
emissions
is
most
likely
a
modeling
artifact.
IPM
predicts
that
oil
(
dual­
fueled)
units
nearly
fall
out
of
the
generation
profile
for
New
York
as
they
are
displaced
by
other
sources
of
new
generation
or
by
increases
of
imported
power.
Mandatory
local
reliability
rules
will
not
allow
that
to
happen.
The
RGGI
modeling
analysis
appropriately
incorporated
the
impact
of
these
rules
by
forcing
the
model
to
include
oilfired
generation
based
on
historical
observations
when
the
reliability
rules
were
in
effect.
As
a
result,
the
dual­
fueled
units
operated
within
the
model
and
projected
emissions
increased.
There
are
probably
other
local
reliability
rules
in
other
areas
of
the
CAIR
region
that
were
most
likely
not
addressed
raising
similar
concerns.

The
predicted
loss
of
oil­
fired
generation
in
the
CAIR
analysis
represents
a
significant
loss
in
fuel
diversity,
which
could
adversely
impact
reliability
by
increasing
the
likelihood
of
outages
related
to
gas
infrastructure
or
supply
disruptions.
We
note
the
New
York
State
Energy
Plan
explicitly
advocates
fuel
diversity
and
would
discourage
the
effects
shown
in
the
CAIR
baseline
modeling.
[[
(
p.
2)
]]
CAIR
IPM
also
predicts
that
there
will
be
2,572
MW
of
new
combined
cycle
generation
in
the
base
case
and
an
additional
460
MW
of
turbine
generation
for
New
York.
It
appears
that
this
generation
would
be
built
near
the
New
York
City
metropolitan
area
.
In
the
initial
RGGI
modeling,
the
IPM
model
predicted
similarly
unrealistic
results.
Stakeholder
recommendations
for
the
RGGI
modeling
of
new
capacity
stated
that
the
modeling
should
reflect
current
official
future
capacity
additions
with
assessment
of
likelihood
of
operation.
Modeling
that
accounts
for
environmental
issues
in
New
York
State,
should
be
able
to
address
the
potential
for
new
facilities
to
receive
regulatory
approvals
and
the
likelihood
that
regulated
and
nonregulated
owners
of
new
facilities
will
obtain
needed
financing
to
build
their
facility.
It
is
assumed
that
the
IPM
modeling
for
CAIR
used
the
EPA
average
costs
for
new
construction
of
power
plants,
on
the
order
of
$
500
­
600/
kw.
Recent
experience
in
New
York
City
indicates
that
this
value
should
be
at
least
$
1300/
kw,
and
over
$
700/
kw
in
the
upstate
area.
By
significantly
underestimating
the
cost
of
new
builds,
the
modeling
could
assume
an
unrealistic
amount
of
new
builds,
underestimate
future
emissions
and
thereby
under­
predict
the
difficulty
of
complying
with
the
new
regulations.
Final
IPM
RGGI
baseline
projections
reflecting
stakeholder
concerns
and
more
realistic
$/
kw
construction
costs
resulted
in
higher
predicted
emissions
than
those
predicted
in
the
CAIR
modeling.
[[
(
pp.
2­
3)
]]

Finally,
analysis
of
IPM
in
the
RGGI
modeling
has
shown
that
there
are
significant
implications
regarding
several
other
fundamental
assumptions.
The
potential
use
of
natural
gas
as
a
compliance
strategy
is
a
favored
approach
by
IPM.
However,
disregarding
limitations
to
increased
natural
gas
use
and
relying
on
LNG
as
a
source
of
the
gas
needed,
while
not
considering
alternate
future
price
curves
could
significantly
change
this
predicted
compliance
approach,
Additionally,
arguable
assumptions
for
load
growth
and
potentially
optimistic
modeling
assumptions
regarding
nuclear
generation
up­
rates
and
re­
licensing
in
New
York
and
New
England
could
have
significant
ramifications
on
the
IPM
results,
All
these
modeling
concerns
bias
the
CAIR
future
projections
to
lower
emissions
and
imply
easier
compliance
than
we
can
reasonably
expect.
[[
(
p.
3)
]]

Baseline
Energy
Projection:
The
baseline
energy
projection
is
one
of
two
parameters
used
to
calculate
the
emissions
cap.
The
emission
cap
is
calculated
by
multiplying
the
target
emission
rate
(
lb/
mmBtu)
by
the
baseline
energy
(
mmBtu)
projection.
An
analysis
of
the
CAIR
energy
baseline
projection
shows
how
the
energy
projection
component
can
problematically
affect
the
cap
level.
EPA
calculated
the
initial
CAIR
cap
by
>
determining
the
highest
recent
Acid
Rain
Program
(
ARP)
heat
input
from
years
1999­
2002
for
each
affected
State,
summing
the
highest
State
heat
inputs
into
a
region
wide
heat
input,
and
multiplying
the
region
wide
heat
input
by
0.15
lb/
mmBtu
and
0.125
lb/
mmBtu
for
2009
and
2015,
respectively=.
[[
(
p.
3)
]]
[[
(
See
pp.
3­
5
of
Docket
Number
2266
for
a
detailed
discussion
of
this
issue.)
]]

Other
Factors:
Although
the
size
of
the
cap
as
determined
by
emissions
and
energy
use
is
the
most
important
concern
for
the
success
of
a
trading
program,
there
are
other
factors
that
can
have
an
effect.
The
number
of
trading
entities
and
implementation
schedule
all
affect
the
availability
of
allowances.
If
there
are
too
few
entities
with
surplus
allowances
available,
the
sources
with
surplus
allowances
can
control
the
market.
As
in
any
market,
lack
of
competitive
pressure
equates
with
no
incentive
to
lower
costs.
If
a
limited
number
of
entities
or
groups
of
sources
control
the
market,
prices
can
be
set
arbitrarily.
Because
many
changes
have
occurred
(
including
large
mergers)
in
the
electricity
generating
industry
subsequent
to
the
Acid
Rain
Program,
market
control
is
more
likely
to
be
a
CAIR
issue
of
concern.
A
company
with
a
large
number
of
sources
can
develop
a
strategy
to
over­
control
at
specific
plants
to
provide
allowances
for
other
plants
that
may
not
have
cost­
effective
options.
However,
this
also
could
affect
the
overall
number
of
allowances
available
for
the
smaller
market
participants
since
large
companies
will
likely
not
invest
in
control
equipment
to
provide
surplus
allowances
beyond
those
needed
for
their
system.
[[
(
p.
5)
]]

The
success
of
the
program
requires
ample
time
in
the
implementation
schedule
for
source
owners
to
evaluate,
select,
and
install
the
most
appropriate
and
cost­
effective
compliance
strategies.
If
the
projected
schedule
is
overly
restrictive,
source
owners
will
be
forced
into
the
market
to
buy
allowances
to
cover
higher
than
expected
emissions.
Reliance
on
the
results
of
the
IPM
CAIR
modeling
for
the
base
case
likely
also
influenced
the
implementation
schedule.
The
modeling
predicted
that
many
states
were
already
at
the
necessary
limits
so
not
as
much
time
was
needed
for
implementation.
However,
as
shown
below,
NY
sources
will
have
to
exceed
the
2015
target
rate
or
rely
on
the
market
for
allowances
needed
for
compliance.
[[
(
p.
6)
]]

Table
2
in
the
Notice
of
Reconsideration
lists
those
States
in
the
CAIR
region
that
have
significant
amounts
(
i.
e.,
40
percent
or
greater)
of
generation
sources
that
combust
fossil
fuels
other
than
coal.
EPA
asserts
NY,
while
receiving
fewer
allowances
under
a
fuel
factor
approach,
is
provided
with
a
reasonable
statewide
budget
that
is
comparable
to
the
IPM
projected
emissions
in
2009
and
2015.
The
CAIR
projection
for
annual
2009
NOX
emissions
in
NY
is
45,617
tons.
[[
(
p.
6)
]]
New
York
already
has
an
effective
annual
NOX
trading
program
that
has
a
significantly
different
budget
(
70,313
tons).
The
New
York
Acid
Deposition
Reduction
Program
non­
ozone
season
budget
for
EGU
units
is
39,908
tons.
The
New
York
NOX
Budget
Program
ozone
season
budget
from
EGU
units
and
others
is
30,405
tons.
The
CAIR
baseline
aggregated
energy
use
over
each
state
by
picking
the
highest
total
energy
use
over
four
years.
An
alternative
approach
would
have
been
to
consider
individual
unit
or
station
energy
use,
pick
the
highest
year
for
each,
and
sum
those
totals
such
as
New
York
used
in
its
Acid
Deposition
Reduction
Program
(
6NYCRR
Part
237).
In
this
alternate
approach
the
effect
of
unit
outages
and
state­
wide
climatic
effects
are
reduced.
[[
(
p.
6)
]]
In
fact,
the
numbers
show
that
the
methodology
used
significantly
negatively
impacts
New
York.
The
New
York
unweighted
heat
input
estimated
using
the
EPA
methodology
is
713,705,400
mmBtu
and
the
2009
NY
CAIR
allocation
is
45,617.
The
effective
emission
rate
for
those
values
is
0.128.
As
a
result,
the
CAIR
regulation
will
require
NY
sources
to
reduce
emissions
15%
beyond
the
2009
target.
Moreover,
using
a
unit
by
unit
maximum
and
summing
the
totals
generates
higher
heat
inputs
that
account
for
changes
in
unit
usage
and
weather,
The
NY
Part
238
heat
input
total
is
840,900,614.
Using
that
heat
input
and
the
NY
CAIR
allocation
yields
an
effective
emission
rate
of
0.108.
In
other
words,
the
proposed
methodology
could
require
NY
sources
to
reduce
emissions
in
2009
28%
beyond
the
0.15
2009
target
emission
rate
.
[[
(
p.
6)
]]

Response:
The
commenter
states
that
"
Individually,
issues
raised
here
may
not
affect
the
viability
of
a
future
program.
However
the
concern
is
that
if
the
effects
of
these
problems
turn
out
to
be
significant
individually
and
all
turn
out
worse
than
expected,
the
combined
impact
may
effect
the
viability
of
a
robust
trading
market."
As
is
further
explained
below,
EPA
disagrees
with
most,
if
not
all
of
the
commenters
assertions.
Therefore
EPA
believes
that
the
convergence
of
all
of
these
assertions
will
not
affect
the
viability
of
the
trading
program.

First,
EPA
disagrees
that
EPA
has
picked
an
inadequate
baseline.
Despite
the
fact
that
the
commenter
asserts
that
the
CAIR
baseline
appears
to
inadequately
represent
typical
annual
energy
use,
the
assumptions
the
commenter
bases
this
on
are
not
average
but
are
worst
case.
For
instance,
the
commenter
suggests
the
use
of
a
baseline
using
unit
by
unit
maximums
which
account
for
changes
in
unit
usage
and
weather.
The
very
fact
that
the
commenter
wants
to
sum
unit
maximums
from
different
years,
makes
it
clear
that
those
unit
maximums
do
not
typically
occur
in
the
same
year.
Furthermore,
the
trading
program
is
designed
to
handle
variations
in
weather,
because
allowances
can
be
traded
both
spatially
and
temporally
(
through
banking).
All
three
programs
have
design
features
that
assure
there
will
be
a
bank
in
the
early
years
of
the
program
so
that
if
one
of
the
early
years
of
the
program
has
extreme
weather,
allowances
will
be
available.

The
commenter
also
seems
to
insinuate
that
the
CAIR
budget
for
New
York
is
too
low
because
it
is
lower
than
the
budget
for
an
existing
program.
The
commenter
fails
to
explain
why
a
budget
for
an
unrelated
program
with
unspecified
stringency
is
relevant
to
the
budget
that
EPA
has
assigned
New
York.

The
commenter
also
expressed
concern
about
the
feasibility
of
installing
controls,
but
provided
no
evidence
that
they
could
not
be
installed.
EPA
has
done
extensive
analysis
of
the
feasibility
of
installing
controls.
See
the
final
CAIR
rulemaking.

EPA
disagrees
with
the
commenter's
claim
that
IPM
has
inappropriately
projected
future
emissions
in
New
York.
First,
EPA
believes
that
we
have
appropriately
considered
the
constraints
on
the
operation
of
older
gas­
and
oil­
fired
units
and
the
construction
of
new
units.
EPA
analysis
projects
that
much
of
the
existing
oil­
and
gas­
fired
fleet
would
remain
in
operation
and
dispatch.
Under
the
EPA
modeling
some
older
oil­
and
gas­
fired
units
do
retire
or
remain
as
reserve
capacity.
The
commenter
claims
that
"
mandatory
local
reliability
rules
will
not
allow
that
to
happen."
However,
the
commenter
does
not
indicate
what
the
requirements
are
and
how
they
would
impact
the
retirement
and
dispatch
of
these
units
and
simple
states
"
the
Regional
Greenhouse
Gas
Initiative
(
REGGI)
modeling
analysis
appropriately
incorporated 
oil­
fired
generation
based
on
historical
observations
when
the
reliability
rules
were
in
effect."
The
commenter
has
not
shown
that
the
EPA
modeling
is
inaccurate
but
has
noted
that
there
are
differences
between
the
modeling
performed
for
in
the
context
of
the
development
of
the
RGGI
and
the
CAIR.

The
commenter
claims
that
"
the
[
EPA]
predicted
loss
of
oil­
fired
generation
in
CAIR
analysis
represents
a
significant
loss
in
fuel
diversity "
EPA
modeling
projects
much
of
the
existing
oil­
and
gas­
fired
fleet
to
remain
in
operation
(
or
as
reserve
capacity)
and
additional
new,
gasfired
combined
cycle
turbine
capacity
to
come
online.
The
commenter
does
not
show
that
this
new
generation
portfolio
projected
in
CAIR
modeling
does
not
meet
the
requirements
of
local
reliability
laws
and
is,
therefore,
inaccurate.

In
addition,
the
commenter
also
claims
that
EPA
over
projects
that
amount
of
new,
gas­
fired
combined
cycle
turbines
that
would
come
online
because
EPA
modeling
assumptions
about
the
cost
of
building
new
combined
cycle
units
are
too
low.
However,
EPA
modeling
assumptions
consider
location
specific
aspects
of
the
cost
of
building
new
generation.
IPM
assumes
the
cost
of
building
new
combined
cycle
units
in
New
York
is
$
554/
kw.
In
support
of
the
commenter's
claim,
they
state
the
"
recent
experience
in
New
York
City
indicates
that
this
value
should
be
at
least
$
1,300/
kw,
and
over
$
700/
kw
in
the
upstate
area."
However,
the
commenter
does
not
provide
data
to
demonstrate
that
the
cost
assumptions
used
in
the
CAIR
modeling
are
inaccurate
or
specify
the
type
of
new
unit
for
which
their
claimed
costs
would
apply.
Further,
the
commenter
does
not
demonstrate
that
the
IPM
assumptions
for
the
cost
of
building
new
gas­
fired
combined
cycle
units
are
unrepresentative
relative
to
the
cost
of
building
other
types
of
units
or
operating
existing
units,
which
may
change
the
results
of
the
projected
future
dispatch.

The
commenter
contends
that
EPA's
methodology
for
determining
statewide
heat
input
for
use
in
the
apportionment
of
the
region
wide
NOx
budgets
to
the
States
is
unrepresentative
of
future
operation.
EPA
believes
the
method
proposed
in
the
CAIR
SNPR
and
the
finalized
in
the
CAIR
NFR
is
appropriate.
EPA
also
notes
that
commenters
were
provided
adequate
notice
of
the
State­
by­
State
heat
input
that
would
be
used
develop
statewide
budgets
and
is
not
reopening
this
issue
for
comment
in
the
context
of
this
Notice
of
Reconsideration.

In
addition,
the
commenter
expresses
concerns
that
the
CAIR
trading
markets
would
be
deleteriously
impacts
by
having
too
few
trading
entities
and
the
implementation
timelines.
While
the
commenter
expressed
concern,
they
did
not
provide
analysis
to
demonstrate
that
the
CAIR
markets
would
not
function
as
EPA
expects.
There
is
no
reason
to
believe
that
the
CAIR
allowance
trading
markets
would
behave
differently
than
the
robust
trading
markets
of
the
title
IV
and
NOx
SIP
Call
programs.
The
commenter
continues
by
expressing
concern
that
smaller
entities
would
not
be
able
to
acquire
allowances.
For
the
CAIR
NOx
programs,
States
may
allocate
allowances
to
any
source
they
wish
including
small
entities.
In
the
context
of
the
CAIR
SO2
program,
there
is
not
evidence
that
the
SO2
market
would
not
continue
to
be
robust.
In
addition,
new
sources
could
acquire
S02
allowances
through
the
title
IV
allowance
action.
On
the
issue
of
the
CAIR
implementation
timing
negatively
impacting
the
trading
markets,
the
commenter
has
not
provided
any
evidence
to
counter
EPA's
demonstration
(
presented
in
the
CAIR
rulemaking
docket)
that
the
CAIR
timelines
are
feasible.

Document
No.:
OAR­
2003­
0053­
2264
Commenter:
Connecticut
Department
of
Environmental
Protection
(
CTDEP)
Comment:
The
Connecticut
Department
of
Environmental
Protection
(
CTDEP)
is
encouraged
that
the
U.
S.
Environmental
Protection
Agency
(
EPA)
is
reevaluating
certain
aspects
of
the
Clean
Air
Interstate
Rule
(
CAIR).
CTDEP
is
currently
planning
to
implement
emissions
reductions
necessary
to
attain
the
federal
8­
hour
ozone
National
Ambient
Air
Quality
Standard
(
NAAQS)
and
thus
welcomes
federal
measures
such
as
CAIR
that
reduce
ozone
precursor
emissions
in
upwind
states.
While
CAIR
is
projected
to
achieve
valuable
sulfur
dioxide
(
SO2)
and
nitrogen
oxides
(
NOx)
reductions,
EPA=
s
modeling
shows
that
CAIR
alone
is
not
likely
to
allow
Connecticut
to
attain
the
ozone
NAAQS.
To
maximize
the
potential
benefits
of
CAIR
given
the
limited
number
of
additional
emission
reductions
that
Connecticut
may
achieve
within
its
borders,
CTDEP
offers
the
following
comment
on
the
above­
referenced
reconsideration
(
CAIR
Reconsideration).
In
short,
CTDEP
remains
concerned
that
EPA=
s
use
of
fuel
adjustment
factors
(
FAFs)
to
establish
state
NOX
budgets
creates
an
unfair
economic
and
environmental
penalty
for
Northeastern
states,
thereby
adding
an
unnecessary
barrier
to
CTDEP=
s
efforts
to
provide
improved
air
quality
for
its
citizens.
[[
(
p.
1)
]]
EPA=
s
application
of
the
FAFs
apportions
larger
NOx
budgets
to
states
that
have
a
higher
proportion
of
coal­
fired
electric
generating
units.
EPA
speaks
of
greater
burdens
on
the
owners
of
coal
plants
to
control
emissions
to
justify
applying
the
FAFs,
but
EPA
ignores
the
inherent
burden
on
cleaner
burning
plant
owners
and
investors
caused
by
the
FAFs.
States
with
a
higher
proportion
of
gas­
fired
electric
generating
units
receive
fewer
allowances
as
a
result
of
CAIR=
s
FAF.
Gas­
fired
electric
generating
unit
owners
have
incurred
historical
costs
to
burn
a
cleaner
but
higher­
priced
fuel.
While
gas­
fired
plant
owners
have
continually
paid
the
price
for
cleaner
fuel,
under
CAIR
these
owners
may
be
penalized
with
the
additional
cost
of
purchasing
allowances
in
order
to
comply
with
CAIR.
Such
costs
will
be
passed
on
to
ratepayers
in
the
form
of
higher
electric
rates.
[[
(
p.
1)
]]

Just
as
FAFs
may
inherently
burden
the
gas­
fired
unit
owners,
investors
and
ratepayers,
the
FAFs
also
disproportionately
burden
Northeast
states.
Citizens
in
the
Northeast
now
bear
the
public
health
and
attainment
burden
of
transported
air
pollution
from
dirtier
coal­
fired
units.
Under
the
FAF
methodology,
due
to
the
high
proportion
of
gas­
fired
electric
generation
in
the
Northeast
the
citizens
in
the
Northeast
also
effectively
bear
the
economic
burden
of
paying
higher
rates
for
controls
installed
in
Midwest
states.
Because
of
the
disproportionate
burdens
described
above,
EPA
should
not
apply
the
FAFs
in
the
final
CAIR
and
should
instead
return
to
the
fuel­
neutral
state
NOX
budget
calculation
methodology
proposed
in
the
CAIR
notice
of
proposed
rulemaking
(
69
FR
4566).
CTDEP
is
not
suggesting
that
EPA
in
any
way
reduce
the
overall
air
quality
benefits
possible
with
CAIR,
only
that
EPA
require
equitable,
cost­
effective
reductions
from
coal­
fired
electric
generating
units.
[[
(
p.
2)
]]

Response:

EPA
disagrees
with
the
commenter
that
the
EPA's
analysis
of
the
potential
impacts
of
using
the
FAF
methodology
should
consider,
as
the
commenter's
claim,
that
"
gas­
fired
electric
generating
unit
owners
have
incurred
historical
costs
to
burn
a
cleaner
but
higher­
priced
fuel."
EPA's
analysis
of
the
potential
impacts
of
the
CAIR
appropriately
considers
the
incremental
cost
of
compliance
for
CAIR
(
i.
e.,
the
cost
of
CAIR
less
the
cost
of
complying
with
existing
Federal
and
State
environmental
regulations).
EPA
disagrees
with
commenter's
contention
that
CAIR
should
consider
the
"
historical"
cost
of
decisions
made
by
owners.
These
existing
units
were
built
based
upon
the
owners
consideration
of
a
variety
of
factors,
including
the
forecasts
of
fuel
costs
and
potential
risk
of
these
units
being
regulated
by
future
environmental
programs,
and
EPA
believes
it
is
inappropriate
to
consider
the
a
single
operational
factor
(
e.
g.,
fuel
costs)
as
part
of
the
CAIR
compliance
costs.
EPA
believes
it
is
appropriate
to
provide
additional
CAIR
NOx
allowances
to
the
coal­
fired
generation
in
consideration
of
the
potential
costs
of
installing
advanced
emission
controls
in
response
to
CAIR.

The
commenter
claims
that
the
owners
of
existing
gas­
fired
units
will
have
"
the
additional
cost
of
purchasing
allowances
in
order
to
comply
with
CAIR."
However,
the
commenter
does
not
provide
any
analysis
to
substantiate
this
claim.
EPA
analysis
in
support
of
the
Notice
of
Reconsideration
shows
that
States
with
predominantly
non­
coal
fired
generation
would
have
an
excess
of
allowances.
In
fact,
gas­
fired
units
because
non­
coal
fired
generation
would
receive
CAIR
NOx
allowances
at
levels
above
their
projected
emissions,
it
is
likely
that,
even
with
the
use
of
the
FAF
methodology,
these
units
would
be
in
a
position
to
sell
excess
allowances
to
higher
emitting
sources
and
use
the
proceeds
to
offset
other
operational
costs.

The
commenter
claims
that
the
FAF
approach
would
disproportionately
burden
Northeast
States
because
they
have
a
greater
reliance
on
oil­
and
gas­
fired
generation
than
other
parts
of
the
CAIR
region.
EPA
notes
that,
of
the
States
EPA
identified
as
having
predominantly
gas­
and
oil­
fired
generation,
all
(
i.
e.,
Florida,
Louisiana,
Mississippi,
and
Texas)
but
the
District
of
Columbia
and
New
York
are
located
in
the
South.
The
commenter
did
not
provide
analysis
to
demonstrate
the
Northeastern
States
are
disproportionately
impacted
by
the
use
of
the
FAF
approach.

XIX.
F.
EPA
did
not
properly
analyze
impacts
of
modeling
using
EIA
(
i.
e.,
high
gas
prices)
assumptions
Document
No.:
OAR­
2003­
0053­
2271.1
Commenter:
National
Mining
Association
Comment:
The
fuel
adjustment
factors
are
not
unrelated
to
the
air
quality
goal
of
the
statute.
Entergy
is
wrong
that
the
fuel
adjustment
factors
are
unrelated
to
air
quality
considerations.
As
discussed
above,
the
fuel
adjustment
factors
provide
a
better
approximation
of
a
state=
s
significant
contribution
to
downwind
nonattainment
than
the
simple
heat
input
method.
[[
(
2271.1,
p.
14)
]]
Moreover,
as
EPA
explains,
because
of
the
trading
program,
emission
reductions
will
not
necessarily
be
made
in
proportion
to
the
states=
emissions
budgets.
Instead,
emissions
reductions
will
be
made
where
it
is
lowest
cost
to
do
so.
In
this
sense,
it
does
not
matter
what
allocation
methodology
EPA
uses
in
fixing
state
budgets,
since
the
relative
amount
of
each
state=
s
emission
allowances
does
not
determine
where
emissions
actually
take
place.
Accordingly,
it
was
not
arbitrary
and
capricious,
as
Entergy
claims,
for
EPA
not
to
have
re­
run
the
IPM
model
to
forecast
air
quality
impacts
after
deciding
to
adopt
the
fuel
adjustment
factors,
since
use
of
those
factors
will
not
change
emissions
sources
or
downwind
impacts.
[[
(
2271.1,
p.
14)
]]
Entergy
claims
that
trading
programs
are
imperfect
and
that
the
allocation
methodology
therefore
could
be
relevant
in
determining
emissions
sources.
But
in
making
this
claim,
Entergy
relies
solely
on
rhetoric
and
provides
no
factual
or
technical
support.
Entergy=
s
claim
belies
fifteen
years
of
experience
under
the
highly
successful
acid
rain
program.
Without
more
justification,
Entergy=
s
argument
cannot
stand.
[[
(
2271.1,
p.
14)
]]

Response:
The
commenter
generally
supports
use
of
the
FAF
methodology,
the
approach
taken
in
the
CAIR
and
CAIR
FIP.

XIX.
G.
General
Document
No.:
OAR­
2003­
0053­
2272.1
Commenter:
Cinergy
Corp
Comment:
As
an
initial
matter,
I
affirm
Cinergy=
s
support
for
the
final
CAIR.
As
set
forth
in
the
final
rule,
Phase
II
of
the
CAIR
within
the
affected
region
requires
reductions
of
SO2
equal
to
3.8
million
tons
and
of
NOx
equal
to
1.5
million
tons
relative
to
EPA=
s
base
case
emissions.
A
significant
portion
of
the
foregoing
reductions
stand
to
be
achieved
through
a
market­
based
system
that
appropriately
leaves
to
the
regulated
community
important
decisions
regarding
how
and
where
emissions
reductions
will
be
attained.
At
the
same
time,
the
program=
s
absolute
caps
ensure
that
significant
air
quality
improvements
will
be
achieved
­
efficiently
and
effectively
­
within
the
next
decade.

We
support
the
CAIR
trading
program,
in
part,
because
it
will
create
incentives
for
sources
to
maximize
efficient
reductions
as
soon
as
possible,
encourage
investment
in
new
control
technology,
and
afford
affected
sources
much­
needed
compliance
flexibility.
[[
(
2272.1,
p.
2)
]]
For
these
same
reasons,
Cinergy
was
a
strong
supporter
of
the
Clear
Skies
Act
of
2005.
The
NOx
cap­
and­
trade
language
contained
in
Section
451
of
the
bill
mirrors
many
parts
of
the
CAIR
program.
For
example,
Section
451(
2)
provides
that
NOx
allocations
would
be
adjusted
based
on
factors
that
are
nearly
identical
to
the
factors
contained
in
the
final
CAIR.
The
inclusion
of
fueltype
adjustment
factors
in
the
proposed
legislation
demonstrates
that
it
is
reasonable
for
EPA
to
apportion
NOx
allowances
to
CAIR­
affected
states
based
on
the
use
of
comparable
fuel­
type
adjustment
multipliers.

We
at
Cinergy
urge
EPA
to
retain
this
fundamental
aspect
of
the
final
CAIR.
[[
(
2272.1,
p.
2)
]]
As
you
well
know,
the
final
CAIR
establishes
that
states
will
be
allocated
a
percentage
of
NOx
allowances
commensurate
with
the
percentage
of
region­
wide
heat
input
attributable
to
the
sources
within
each
state.
Unlike
EPA=
s
initial
proposal
to
allocate
allowances
based
on
unadjusted
heat
input
data,
the
final
CAIR
adjusts
the
allocations
according
to
multipliers
that
account
for
the
emissions
profiles
unique
to
each
fuel
type.
As
EPA
suggested
in
its
Supplemental
Notice
of
Proposed
Rulemaking
(
SNPR),
EPA=
s
final
CAIR
assigns
an
adjustment
factor
of
1.0
for
coal,
0.6
for
oil
and
0.4
for
gas.

Petitioners
complain
that
EPA=
s
express
reference
to
the
multipliers
in
the
SNPR
was
insufficient
to
put
them
on
notice
that
EPA
was
considering
multipliers
for
use
in
the
CAIR
trading
program.
Even
if
Petitioners=
argument
had
merit,
EPA=
s
grant
of
reconsideration
renders
it
moot.
That
notwithstanding,
EPA
has
requested
comment
on
the
use
of
fuel
adjustment
factors
in
setting
state
NOx
budgets.
[[
(
2272.1,
pp.
2­
3)
]]
In
sum,
EPA
should
retain
the
use
of
fuel­
type
multipliers
for
purposes
of
establishing
statewide
NOx
budgets.
The
use
of
adjustment
factors
will
minimize
the
inequity
that
would
result
from
allocations
based
on
unadjusted
heat
input
by
shifting
allowances
to
sources
that
most
need
them.
[[
(
2272.1,
p.
5)
]]
I
appreciate
this
opportunity
to
comment
on
issues
raised
in
the
Petitions
for
Reconsideration.
My
colleagues
at
Cinergy
and
I
support
EPA=
s
implementation
of
a
cap­
and­
trade
alternative
for
compliance
with
CAIR
emissions
limits.
In
particular,
we
support
EPA=
s
allocation
of
statewide
NOx
budgets
based
on
fuel­
type
multipliers
as
set
forth
in
the
final
CAIR.
EPA=
s
fuel­
factor
approach
properly
minimizes
the
disproportionate
burden
on
coal­
fired
sources
and
the
corresponding
windfall
to
gas­
fired
units
that
would
result
using
an
allocation
methodology
based
on
unadjusted
heat
input
alone.
[[
(
2272.1,
p.
5)
]]

Response:
The
commenter
generally
supports
use
of
the
FAF
methodology,
the
approach
taken
in
the
CAIR
and
CAIR
FIP.

Document
No.:
OAR­
2003­
0053­
2301
Commenter:
Pennsylvania
Department
of
Environmental
Protection
(
PADEP)
Comment:
The
final
outcome
of
EPA=
s
reconsideration
on
two
aspects
of
the
final
rule
will
have
significant
impacts
on
Pennsylvania.
The
switch
to
fuel
neutral
standards
rather
than
fuel
adjustment
factors
is
severely
detrimental
environmentally
and
economically
to
CAIR­
affected
sources
in
the
Commonwealth
of
Pennsylvania
and
sources
in
states
that
burn
coal
as
the
primary
source
of
electricity
generation.
[[
(
p.
1)
]]
Fuel
adjustment
factors
provide
a
good
breakdown
of
state
allowance
allocations
in
that
they
take
into
account
technology
and
resource
differences
throughout
the
CAIR
region
and
prevent
Pennsylvania
from
maintaining
dirty
air
by
buying
allowances
from
states
that
have
little
impact
on
its
Air
Quality.
The
Commonwealth
agrees
with
EPA=
s
position
to
maintain
the
fuel
adjustment
factors.
[[
(
p.
3)
]]

Response:
The
commenter
generally
supports
use
of
the
FAF
methodology,
the
approach
taken
in
the
CAIR
and
CAIR
FIP.

Document
No.:
OAR­
2003­
0053­
2271.1
Commenter:
National
Mining
Association
Comment:
NMA
believes
that
the
affected
petition
for
reconsideration
misunderstands
the
purpose
of
EPA=
s
use
of
fuel
adjustment
factors.
Those
factors
result
in
much
greater
assurance
that
each
State=
s
relative
amount
of
>
significant
contribution
to
downwind
nonattainment
will
actually
be
eliminated
as
compared
with
the
methodology
EPA
had
initially
proposed
in
its
Notice
of
Proposed
Rulemaking
(
NOPR=).
The
final
CAIR
regulatory
scheme
for
distributing
NOx
budgets
has
a
reasonable
foundation
in
the
statute
and
cannot
be
found
unlawful
merely
because
it
fails
to
deliver
budgets
in
the
amounts
desired
by
some
parties.
[[
(
2271.1,
p.
3)
]]

Response:
The
commenter
generally
supports
use
of
the
FAF
methodology,
the
approach
taken
in
the
CAIR
and
CAIR
FIP.

XX.
PM2.5
Modeling
for
Minnesota
Document
No.:
OAR­
2003­
0053­
2284.2
Commenter:
Minnesota
Power
Phase:
Reconsideration
Notes:
Docket
Number
2284
is
the
general
comment
cover
letter
(
FDMS
version).
Docket
Number
2284.1
is
the
cover
letter.
Docket
Number
2284.2
is
the
comment
letter.
Also
submitted
were
the
following
attachments:
Docket
Numbers
2284.3,
2284.5,
2284.6,
2284.7,
and
2284.8.
Comment:
MP
is
an
investor
owned
utility
providing
energy
services
to
customers
in
central
and
northeastern
Minnesota
and
Wisconsin.
The
majority
of
MP=
s
electrical
generation
is
from
combustion
of
low
sulfur,
low
mercury
subbituminous
coal.
MP=
s
northern
location
and
high
percentage
of
industrial
customers
who
operate
around­
the­
clock
make
MP
a
winter­
peaking
utility.
Thirteen
large
power
customers
(
requiring
at
least
10
megawatts
of
generating
capacity)
purchase
about
half
the
electricity
IMP
sells.
Because
of
MP=
s
high
percentage
of
industrial
customers
who
are
high
energy
users
and
struggling
to
compete
in
a
competitive
global
market
economy,
we
are
concerned
that
any
further
emission
reductions
applicable
to
electric
generating
units
(
EGU)
be
implemented
with
reasonable
timeframes
and
cost
to
minimize
the
impact
to
residential
and
industrial
customers
alike.
[[
(
2284.2,
p.
2)
]]
In
the
August
5,
2005
CAIR
Petition
for
Reconsideration,
MP
noted
concern
about
several
issues
related
to
CAIR,
including
whether
the
significance
of
Minnesota
emissions
was
correctly
characterized
when
EPA
made
its
determination
for
states
that
will
be
subject
to
the
CAIR
and
whether
EPA=
s
decision
to
carry
over
Acid
Rain
Program
sulfur
dioxide
allowance
allocations
into
the
CAIR
while
applying
a
greater
surrender
ratio
(
required
allowances
per
ton
SO2
emissions)
gives
equitable
treatment
for
National
Ambient
Air
Quality
Standard
attainment
states
like
Minnesota,
where
Acid
Rain
Program
allocations
were
applied
to
a
baseline
in
which
the
majority
of
coal
fired
electric
generating
units
were
already
scrubbed
and
burning
low
sulfur
coal.
These
concerns
were
reinforced
when
EPA
established
that
Minnesota
was
the
only
state
that
EPA=
s
air
quality
modeling
had
determined
to
be
exhibiting
emissions
significance
on
a
nonattainment
area
right
at
the
0.20
ug/
m3
PM2.5
significant
contribution
value
established
by
EPA
in
the
final
CAIR.
[[
(
2284.2,
p.
2)
]]
In
its
November
22,
2005
CAIR
reconsideration
announcement,
EPA
noted
that
it
is
accepting
comments
on
four
issues
related
to
the
final
rule,
including
two
that
relate
directly
to
issues
identified
in
the
Minnesota
Power
August
5,
2005,
Petition
for
Reconsideration
(
inequities
in
sulfur
dioxide
allocation
methodology
and
certain
inputs
to
the
fine
particle
(
PM2.5)
modeling
used
to
determine
Minnesota=
s
inclusion
in
the
CAIR
region
for
PM2.5).
EPA
also
requested
comments
about
EPA=
s
use
of
fuel
adjustment
factors
when
establishing
state
nitrogen
oxides
(
Nox)
budgets
and
EPA=
s
determination
that
Florida
should
be
included
in
the
CAIR
region.
MP
is
directing
our
comments
to
the
issues
addressed
in
the
MP
Petition
for
Reconsideration.
[[
(
2284.2,
p.
2)
]]
Modeling
used
to
determine
Minnesota=
s
inclusion
in
the
CAIR
region
for
PM2.5When
EPA
had
begun
to
make
CAIR
related
modeling
available
to
the
public,
it
became
apparent
that
EPA
had
not
given
proper
consideration
to
emissions
and
emission
rates
from
Minnesota
electric
generation
units.
Specifically,
2010
emissions
performance
from
electric
generating
units
(
EGUs)
affected
by
Xcel
Energy=
s
Metropolitan
Emission
Reduction
Program
(
MEW)
and
emission
rates
for
other
Minnesota
EGUs
(
ref.
May
20,
2005
letter)
had
been
incorrectly
characterized.
EPA
responded
to
some
of
these
concerns
in
its
March
9,2005
(
posted
incorrectly
as
3/
9/
2004)
Memorandum
to
the
CAIR
Docket
in
which
it
assessed
the
impact
on
Minnesota=
s
significance
calculation
from
a
corrected
characterization
of
MERP
emission
reductions
by
applying
a
Minnesota
SO2
and
Nox
emissions
prorating
technique
to
the
result
of
EPA=
s
CMAQ
Version
4.3
modeling
results
released
just
before
the
May
12,2005
posting
of
the
final
CAIR
in
the
Federal
Register.
In
this
>
Emissions
in
Minnesota:
Additional
Analysis=
memorandum,
EPA=
s
proration
methodology
estimated
that
an
adjustment
of
about
16,500
tons
of
Nox
emissions
and
5800
tons
of
SO2
emissions
result
in
a
4.3%
to
4.6%
reduction
in
overall
Minnesota
emissions,
which
in
turn,
results
in
an
estimated
0.01
ug/
m3
PM2.5
shift
in
the
significance
calculation
in
the
Chicago
area,
to
0.20
ug/
m3.
[[
(
2284.2,
pp.
2­
3)
]]
Minnesota
Power's
contractor
(
Environ/
AG)
modeled
Minnesota's
emissions
impacts
on
nonattainment
areas
by
obtaining
files
from
EPA
used
to
run
CMAQ
version
4.3
for
the
CAIR
Final
Rule.
Environ/
AG
CMAQ
version
4.3
model
run
results
replicated
EPA's
Minnesota
model
run
results
as
characterized
in
the
CAIR
Technical
Support
Document,
validating
the
Environ/
AG
modeling
as
a
means
for
characterizing
the
impact
of
Minnesota
emissions.
However,
applying
the
EPA
truncation
technique
resulted
in
an
Environ/
AG
modeled,
Minnesota
PM2.5
contribution
to
the
Chicago
area
that
is
0.01
ug/
m3
lower
than
EPA.
Environ/
AG
also
brought
to
Minnesota
Power's
attention
that
EPA
had
discovered
problems
with
the
CMAQ
version
4.3
model
used
to
characterize
PM2.5
significance,
where
CMAQ
version
4.3
is
not
stable
for
mass
analysis.
Environ/
AG
reported
that
the
use
of
the
more
stable
CMAQ
version
4.5
model
determined
a
result
for
Minnesota's
modeled
PM2.5
contribution
to
Chicago
that
was
0.01
ug/
m3
lower
than
was
determined
by
Environ/
AG
using
CMAQ
version
4.3
when
applying
EPA's
truncating
methodology,
which
is
about
a
5%
shift.
[[
(
See
pp.
3­
7
of
Docket
Number
2284.2
for
a
detailed
discussion
of
this
issue.)
]]

Response:
The
commenter
(
Minnesota
Power,
or
MP)
asked
EPA
to
reconsider
whether
emissions
from
Minnesota
significantly
contribute
to
downwind
nonattainment
of
the
PM2.5
NAAQS.
MP
asserts
that
EPA's
modeling
failed
to
account
for
certain
emissions
reductions
required
by
State
programs
(
especially
those
required
under
the
Minnesota
Emissions
Reduction
Program
or
MERP).
In
granting
reconsideration,
EPA
explained
that
it
was
aware
of
the
emission
reductions
in
question
when
it
made
the
significant
contribution
determinations
in
the
final
CAIR.
EPA
had
accounted
for
these
reductions
during
the
rulemaking
by
conducting
a
sensitivity
analysis
(
available
in
the
CAIR
docket),
but
had
not
conducted
revised
air
quality
modeling
(
70
FR
at
72279­
280).
In
response
to
the
reconsideration
petition,
EPA
conducted
revised
air
quality
modeling
which
used
the
inputs
reflecting
emission
reductions
required
by
the
MERP.
This
modeling
showed
(
consistent
with
the
sensitivity
analysis)
that
Minnesota
contributes
a
maximum
of
0.20
ug/
m3
to
the
downwind
PM
2.5
nonattainment
area
of
Chicago­
Gary­
Lake
County,
IL­
IN.
This
modeling
thus
supported
EPA's
conclusion
that
Minnesota's
contribution
met
the
criteria
in
CAIR
for
determining
"
significant
contribution."
Id.
This
revised
air
quality
modeling
used
the
same
modeling
platform
used
for
all
of
the
air
quality
modeling
in
CAIR.
In
the
Notice
of
Reconsideration,
EPA
solicited
comment
on
the
inputs
used
to
model
Minnesota
emissions,
but
declined
to
reconsider
or
reopen
for
public
comment
issues
relating
to
the
air
quality
modeling
platform
itself.
Id.
at
72280.

Most
of
the
comments
received
on
this
issue
in
response
to
the
Notice
of
Reconsideration
supported
EPA's
conclusion.
These
include
comments
from
the
Minnesota
Pollution
Control
Agency
(
MPCA),
the
entity
with
the
most
direct
knowledge
of
emission
reductions
required
by
state
programs.
EPA
also
received
no
adverse
comments
from
Xcel
Energy,
the
entity
that
entered
into
the
MERP
with
the
MPCA
and
whose
projected
emission
levels
were
the
centerpiece
of
the
reconsideration
petition.
In
fact,
no
other
power
generation
source
in
Minnesota
besides
Minnesota
Power
offered
adverse
comments.
EPA
views
these
comments
as
confirmation
of
the
reasonableness
of
the
modeling
approach
used
by
EPA
to
assess
significance
of
contribution
of
the
State.
EPA
also
views
these
comments
as
confirmation
that
its
revised
modeling
accurately
accounts
for
the
MERP
reductions.
Minnesota
Power
(
MP)
did
not
comment
on
the
revised
emissions
modeling
done
for
power
sector
units
in
Minnesota
and
instead
directed
its
comments
to
the
original
emissions
modeling
done
for
the
final
CAIR
that
did
not
fully
account
for
the
MERP
reductions.
MP
does
not
directly
challenge
EPA's
conclusion
that
the
revised
modeling
accurately
accounts
for
the
emission
reductions
required
by
the
MERP.
MP
claims,
nonetheless,
that
the
model
inputs
for
the
final
CAIR
modeling
(
not
the
modeling
done
for
the
Notice
of
Reconsideration,
as
just
noted)
contain
errors.
To
the
extent
these
alleged
errors
relate
to
the
MERP,
EPA
has
corrected
the
errors
as
explained
above.
The
additional
"
errors"
of
which
MP
complains
relate
to
inputs
regarding
the
projected
2010
emissions
for
certain
units
in
Minnesota.
Although
MP
states
that
EPA
has
mischaracterized
emissions
from
some
units,
EPA
believes
that
the
emissions
projections
done
to
provide
inputs
for
the
revised
air
quality
modeling
described
in
the
Notice
of
Reconsideration
are
appropriate.

EPA
believes
its
method
of
projecting
power
sector
emissions
for
units
in
Minnesota
reflects
a
more
accurate
and
robust
method
for
projecting
emissions
than
the
method
used
by
MP.
However,
MP
claims
that
if
its
own
lower
emissions
were
used
as
inputs
to
the
PM2.5
modeling,
that
modeling
would
show
that
Minnesota's
contribution
is
below
the
PM2.5
significance
threshold
of
0.2
µ
g/
m3.
MP
was
selective
in
its
application
of
its
methodology
for
projecting
emissions
and
EPA
does
not
believe
that
it
is
an
appropriate
method
for
projecting
emissions.

MP
also
comments
that
"
EPA
had
erroneously
assigned
2010
sulfur
dioxide
emission
rates
on
scrubbed
Minnesota
units
at
values
as
much
as
double
that
of
the
performance
levels
posted
in
2001."
MP
Comment
p.
4.
After
reviewing
the
modeling
results,
EPA
is
unable
to
find
any
instances
in
Minnesota
where
EPA
projected
SO2
emission
rates
of
scrubbed
units
from
the
revised
power
sector
modeling
that
are
double
that
of
the
2001
performance
level.

MP
also
claims
that
"
NOx
emission
rates
deviated
between
2001
and
2010
without
supportive
operating
rationale."
The
difference
in
NOx
rates
that
MP
alludes
to
is
again
based
upon
the
modeling
for
the
Final
CAIR,
not
for
the
Notice
of
Reconsideration.
In
addition,
MP's
characterization
is
inaccurate.
EPA's
2010
projections
of
NOx
emission
rates
are
generally
lower
than
2001
NOx
emission
rate
data
for
Minnesota
units.
Also,
the
petitioner
has
also
failed
to
demonstrate
that
EPA's
projected
NOx
emission
rates
are
inaccurate.

Another
comment
from
MP
stated
that
"
the
EPA
IPM
modeling
had
shifted
heat
input
from
large,
lower
emission
units
to
higher
emission
units."
Id.
A
comparison
of
the
historical
data
from
2001
and
2004
with
the
revised
emissions
modeling
does
not
support
this
broad
conclusion.
Heat
input
usage
does
not
change
significantly,
and
although
there
are
some
shifts
in
heat
input
usage
between
2010
EPA
projections
and
the
2001
data,
these
shifts
occur
where
the
IPM
projects
it
will
be
cost­
effective
to
make
relatively
small
changes
to
where
electricity
is
produced.
In
addition,
EPA
does
not
accept
the
suggestion
that
because
a
certain
rate
applied
in
2001
it
should
be
applied
in
2010.
This
argument
is
not
adequate
and
ignores
the
many
other
factors
that
may
change
in
the
future
which
could
cause
a
change
in
the
way
a
unit
produces
electricity.
The
power
sector
is
a
complicated,
interrelated,
and
interdependent
system
of
operation,
and
must
be
looked
at
holistically
to
ascertain
the
sector's
response
to
a
certain
set
of
conditions
or
constraints.
The
petitioner's
approach
selectively
chooses
the
methodology
for
determining
emissions
at
certain
units
and
ignores
the
changes
that
may
occur
at
other
units
as
a
result.
In
addition,
it
is
easy
to
question
the
choices
or
assumptions
that
one
makes
for
selective
forecasts
of
this
nature,
since
methodologies
can
be
developed
to
support
foregone
conclusions,
like
lower
emission
levels
in
a
future
year.
For
this
reason,
EPA
uses
the
Integrated
Planning
Model
to
develop
its
power
sector
emissions
projections.

IPM
is
a
detailed,
sophisticated,
and
comprehensive
electric
power
sector
model
that
is
used
to
derive
all
manner
of
projections
for
the
power
sector
and
is
used
to
develop
the
power
sector
emissions
projections
that
are
used
in
air
quality
modeling.
The
model
accurately
reflects
the
power
sector
and
contains
millions
of
variables
to
best
ascertain
how
specific
facilities
will
produce
electricity
to
meet
demand
in
the
most
cost­
effective
manner
possible.
The
variables
are
based
upon
the
best
available
data,
both
current
and
anticipated,
and
include
permitted
emission
rates
for
units,
unit
efficiency,
cost
data,
and
operational
constraints.
This
model
has
been
used
to
support
the
development
of
Title
IV
of
the
Clean
Air
Act
(
the
Acid
Rain
Program),
the
NOx
SIP
Call,
the
Clean
Air
Interstate
Rule,
the
Clean
Air
Mercury
Rule,
and
the
Clean
Air
Visibility
Rule.
In
addition,
it
is
used
by
the
Federal
Energy
Regulatory
Commission,
private
sector,
nonprofits
research
groups,
States,
and
regional
planning
organizations
for
power
sector
projections.
The
model
has
undergone
extensive
peer­
review
and
scrutiny,
and
EPA
believes
it
is
an
appropriate
tool
for
use
in
developing
power
sector
emission
projections
and
better
accounts
for
the
many
dynamics
that
exist
in
the
power
sector
(
http://
www.
epa.
gov/
airmarkets/
epaipm
index.
html).

MP
does
not
challenge
the
use
of
IPM
for
developing
power
sector
emission
projections
for
certain
units,
but
comments
that
at
other
units,
a
revised
methodology
should
be
used.
EPA
believes
that
a
holistic
approach
is
necessary
and
using
a
modeling
tool
that
reflects
the
integrated
nature
of
the
power
sector
as
accurately
as
possible
is
the
most
rational
approach
to
forecasting
emissions
for
all
units
comprehensively.

To
its
credit,
MP
also
points
out
that
emissions
from
the
Taconite
Harbor
Facility
(
a
facility
that
was
recently
converted
from
an
industrial
source
to
an
electricity
generating
source)
were
not
included
by
EPA
in
either
the
power
sector
emissions
data
or
in
other
emissions
inventory
used
for
CAIR
modeling.
EPA
will
include
the
facility
in
the
next
version
of
the
IPM.
If
the
facility
had
been
included
in
the
inventory,
emissions
in
Minnesota
would
have
been
higher
by
almost
2,000
tons
of
SO2
and
about
1,150
tons
NOx
than
what
EPA
projected
(
according
to
the
commenter).
Since
EPA
did
not
include
this
facility,
EPA
believes
that
its
own
projections
of
emissions
in
Minnesota
underestimate
likely
future
emissions.

MP
also
stated
that
it
is
"
noteworthy
that
there
are
other
reductions
that
Minnesota
Power
has
not
modeled
that
should
warrant
consideration
by
EPA,
including
those
resulting
from
emission
controls
provided
on
Minnesota
BART
eligible
units
for
the
regional
haze
program."
MP
Comment
p.
6.
The
Regional
Haze
program
requires
Best
Available
Retrofit
Technology
or
BART
to
be
installed
and
operational
on
sources
that
the
State
finds
subject
to
BART
within
five
years
after
EPA
approves
a
State's
regional
haze
SIP.
These
SIPs
are
due
in
December,
2007.
EPA
does
not
believe
that
States
will
require
the
installation
of
operation
of
BART
before
2010.
Thus
it
is
highly
unlikely
that
2010
emissions
would
be
affected
by
the
BART
requirements.
In
addition,
MP
does
not
quantify
any
reductions
it
believes
will
occur
due
to
the
application
of
BART
in
Minnesota.
Thus,
MP
has
not
established
that
there
will
be
additional
reductions
due
to
BART
that
must
be
taken
into
account
when
projecting
2010
emissions
for
units
in
MN.
It
is
also
important
to
note
that
EPA
has
determined
that
CAIR
achieves
greater
progress
than
BART,
and
may
be
used
by
States
in
the
CAIR
region
as
an
alternative
to
BART.

In
sum,
EPA
continues
to
believe
its
emission
projections
have
reasonably
accounted
for
emission
trends
within
Minnesota
and
fully
account
for
emission
reductions
attributable
to
the
MERP.
EPA
believes
the
inputs
used
for
the
modeling
discussed
in
the
Notice
of
Reconsideration
are
reasonable
and
rational
projections
of
2010
emissions
in
Minnesota.
For
these
reasons,
EPA
is
not
making
any
additional
changes
to
the
inputs
to
the
PM2.5
modeling
for
Minnesota,
beyond
those
changes
described
in
the
Notice
of
Reconsideration.
For
more
detail
regarding
Minnesota
EGUs
and
EPA
modeling,
please
see
Xcel
spreadsheet
titled
"
Minnesota
EGU
Unit
Summary_
CAIR
Reconsideration.
xls"
in
the
CAIR
docket.

MP
also
notes
that
Environ/
AG's
CMAQ
version
4.3
modeling
shows
a
PM2.5
contribution
to
the
Chicago
area
that
is
0.01
ug/
m3
lower
than
EPA's
modeling
shows.
This
difference
was
caused
by
an
error
of
the
petitioners.
The
petitioner
was
not
properly
following
EPA's
truncation
methodology
for
calculating
PM2.5
contributions,
as
described
in
the
CAIR
Air
Quality
Modeling
Technical
Support
Document
(
EPA­
HQ­
OAR­
2003­
0053­
2151)
(
See
pp
21,
41­
43).
The
petitioner
corrected
this
error
and
submitted
revised
PM2.5
contributions
to
Chicago
(
EPA­
HQ­
OAR­
2003­
0053­
2312)
based
on
petitioner's
CMAQ
version
4.3
modeling.
These
results
replicate
EPA's
contribution
to
Chicago.

MP
also
raises
a
new
issue
in
their
comments.
They
argue
EPA
should
use
a
more
recent
version
of
its
modeling
platform
to
conduct
air
quality
modeling.
However,
EPA
stated
when
granting
reconsideration
that
it
was
not
reopening
any
issues
dealing
with
the
modeling
platforms
used
for
the
CAIR
modeling.
We
reiterate
that
position
here.
EPA
used
CMAQ
4.3
for
all
of
the
air
quality
analyses
conducted
for
the
final
CAIR,
and
provided
full
notice
and
opportunity
to
comment
on
the
appropriateness
of
the
model.
See
69
FR
47828
(
August
6,
2004)(
announcing
plan
to
use
CMAQ
4.3
for
the
final
rule);
see
also
70
FR
25234­
36
(
summarizing
the
use
of
CMAQ
4.3).
There
was
ample
opportunity
to
comment
on
any
issues
regarding
the
adequacy
of
the
model
during
the
rulemaking.
Nor
is
the
existence
of
a
new
iteration
of
the
model
"
grounds
for
 
objection
ar[
ising]
after
the
period
for
public
comment"
(
CAA
section
307
(
d)
(
7)
(
B)).
Predictive
models
are
of
course
open
to
the
possibility
of
updating
and
so
are
often
adjusted.
Such
adjustments
do
not
normally
occasion
new
opportunities
for
comment,
particularly
after
the
close
of
a
rulemaking.
Indeed,
doing
so
would
create
a
perverse
incentive
to
leave
models
unadjusted.
The
ultimate
issue
is
whether
the
model
used
in
the
rulemaking
bears
a
"
rational
relationship
to
the
characteristics
of
the
data
to
which
it
is
applied".
Appalachian
Power
v.
EPA,
249
F.
3d
1032,
1052
(
D.
C.
Cir.
2001).
There
has
already
been
full
opportunity
to
comment
on
this
issue.

For
more
discussion
on
all
issues
related
to
MP's
comments,
see
the
CAIR
Notice
of
Final
Action
on
Reconsideration.

Document
No.:
OAR­
2003­
0053­
2274
Commenter:
Minnesota
Pollution
Control
Agency
Phase:
Reconsideration
Comment:
The
Minnesota
Pollution
Control
Agency
has
reviewed
the
reconsideration
notice
(
EPA­
HQOAR
2003­
0053­
2215)
and
in
particular,
the
information
in
this
notice
relating
to
itemC.
>
PM2.5
Modeling
for
Minnesota=.
We
have
also
reviewed
and
evaluated
information
related
to
item
C.
Contained
in
the
docket.
Based
on
our
review,
we
believe
that
Xcel
Energy=
s
Metropolitan
Emission
Reduction
Project
emission
reductions
have
been
accounted
for
in
a
reasonable
manner
in
the
emission
projections
EPA
used
for
contribution
modeling.
[[
(
p.
1)
]]

Response:
EPA
has
performed
revised
modeling
of
emission
in
Minnesota
and
believes
that
Minnesota
still
meets
EPA's
threshold
for
inclusion
in
the
Clean
Air
Interstate
Rule.
See
the
CAIR
Notice
of
Final
Action
on
Reconsideration
for
further
discussion.

Document
No.:
OAR­
2003­
0053­
2268.1
Commenter:
Northeast
States
for
Coordinated
Air
Use
Management
(
NESCAUM)
Phase:
Reconsideration
Notes:
Docket
Number
2268
is
the
cover
letter.
Docket
Number
2268.1
is
the
comment
letter.
Comment:
Fine
particulate
matter
(
PM2.5)
modeling
for
Minnesota
and
including
Florida
in
the
CAIR
region
for
ozone.
EPA
has
asked
for
comment
on
the
inclusion
of
Florida
in
the
CAIR
region
for
ozone
and
on
revised
modeling
inputs
for
Minnesota.
NESCAUM
is
not
commenting
on
those
specific
issues.
However,
EPA
must
include
States
in
the
CAIR
program
for
which
analyses
demonstrate
that
they
contribute
to
non­
attainment
under
section
110(
a)(
2)(
d)
of
the
Clean
Air
Act.
Should
EPA
choose
to
remove
any
jurisdiction
from
the
CAIR
program,
EPA
must
reduce
the
total
Nox
and
SO2
CAIR
budgets
by
amounts
equal
to
that
jurisdiction=
s
Nox
and
SO2
budgets,
respectively.
The
NESCAUM
States
cannot
attain
the
eight­
hour
ozone
and
PM2.5
National
Ambient
Air
Quality
Standards
without
substantial
reductions
in
direct
and
transported
emissions
of
Nox
and
SO2
across
the
Eastern
U.
S.
We
urge
EPA
to
ensure
that
the
CAIR
program
maximizes
reductions
of
transported
Nox
and
SO2
to
the
extent
feasible.
[[
(
2268.1,
p.
2)
]]

Response:
EPA
is
including
in
CAIR
all
States
that
it
has
determined
significantly
contribute
to
downwind
nonattainment
of
or
interfere
with
maintenance
of
the
PM2.5
and/
or
8­
hour
ozone
NAAQS.
EPA
has
determined
that
Minnesota
is
properly
included
in
the
CAIR
region
for
PM2.5
and
that
Florida
is
properly
included
in
the
CAIR
regions
for
PM2.5
and
8­
hour
ozone..
See
the
CAIR
Notice
of
Final
Action
on
Reconsideration
for
further
discussion.

Document
No.:
OAR­
2003­
0053­
2279.1
Commenter:
Midwest
Generation
Phase:
Reconsideration
Notes:
Docket
Number
2279
is
the
cover
letter.
Docket
Number
2279.1
is
the
comment
letter.
Docket
Number
2278
is
a
duplicate
of
2279
(
cover
letter).
Comment:
MIDWEST
GENERATION
SUPPORTS
EPAS
DETERMINATION
THAT
PM2.5
EMISSIONS
FROM
MINNESOTA
CONTRIBUTE
SIGNIFICANTLY
TO
NONATTAINMENT
IN
ILLINOIS.
Midwest
Generation
supports
EPA=
s
conclusion
that
Minnesota
is
subject
to
the
final
CAIR
based
on
the
Agency's
most
recent
analyses
confirming
that
Minnesota
contributes
significantly
to
nonattainment
of
PM2.5
NAAQS
in
Cook
County,
Illinois.
Generally,
Midwest
Generation
submits
that
air
quality
challenges
should
be
addressed
just
as
they
develop
irrespective
of
political
boundaries.
Indeed,
Congress
recognized
as
much
when
it
enacted
the
>
good
neighbor=
provision
of
the
Clean
Air
Act,
CAA
'
110(
a)(
2)(
D).
Section
110(
a)(
2)(
D)
provides
that
state
SIPs
must
contain
adequate
provisions
prohibiting
in­
state
sources
from
emitting
any
pollutant
in
amounts
that
contribute
significantly
to
nonattainment
of
NAAQS
in
a
downwind
state.
Notably,
in
the
preamble
to
the
final
CAIR,
EPA
noted
the
regional
nature
of
PM2.5
nonattainment,
in
particular.
EPA
explained
its
relatively
low
air
quality
impact
threshold
of
0.20
µ
g/
m3
for
PM2.5,
noting
that
>
PM2.5
nonattainment,
like
ozone,
is
caused
by
many
sources
in
a
broad
region,
and
therefore
may
be
solved
only
by
controlling
sources
throughout
the
region.=
[[
(
2279.1,
p.
7)
]]
In
response
to
Petitioners=
questions
regarding
whether
EPA=
s
modeling
supporting
the
final
CAIR
sufficiently
accounted
for
certain
emissions
reductions
required
by
Minnesota
regulation
(
and,
thus,
whether
Minnesota
was
properly
a
CAIR­
affected
state),
EPA
reviewed
its
prior
analysis
and
concluded
that,
indeed,
the
analysis
did
not
fully
account
for
such
effects
on
future
PM2.5
emissions.
As
a
result,
EPA
projected
future
emissions
a
second
time
using
inputs
revised
downward.
As
revised,
EPA=
s
estimate
of
statewide
Nox
emissions
was
approximately
16,500
tons
lower
and
the
estimate
for
SO2
emissions
about
5,800
tons
lower
relative
to
EPA=
s
prior
analysis.
Even
based
on
these
more
conservative
emissions
projections,
the
same
IPM
modeling
consistently
demonstrated
that
PM2.5
emissions
from
Minnesota
result
in
an
air
quality
impact
in
Cook
County,
Illinois
of
0.2
µ
g/
m3.
[[
(
2279.1,
pp.
7­
8)
]]
EPA
defines
>
significant
contribution=
for
purposes
of
the
>
good
neighbor=
provision
in
terms
of
air
quality
impact.
In
the
final
CAIR,
EPA
makes
clear
that
any
air
quality
impact
on
PM2.5
equal
to
0.2
µ
g/
m3
or
higher
amounts
to
>
significant
contribution,=
interfering
with
attainment
or
maintenance
such
that
imposition
of
CAIR
is
triggered.
Because
EPA=
s
IPM
modeling
showed
that
emissions
within
Minnesota=
s
borders
impact
air
quality
in
Cook
County
at
the
threshold
­
even
after
fully
accounting
for
emissions
reductions
that
are
expected
as
a
result
of
state
regulation
­
EPA
properly
concluded
that
fine
particulate
emissions
in
Minnesota
contribute
significantly
to
the
nonattainment
of
the
PM2.5
NAAQS
in
Cook
County,
Illinois.
Sources
in
Minnesota
aggravate
air
quality
problems
in
the
region
and,
thus,
should
be
required
to
achieve
their
fair
share
of
emissions
reductions.
A
decision
by
EPA
to
exclude
Minnesota
from
the
CAIR
region
would
unfairly
burden
affected
sources
in
Cook
County.
Sources
in
Minnesota
would
be
permitted
to
benefit
from
activity
that
results
in
the
deterioration
of
air
quality
in
Cook
County
without
being
required
to
ameliorate
the
damage.
Sources
in
Cook
County,
on
the
other
hand,
would
be
saddled
unfairly
with
the
costs
of
reducing
emissions
sufficient
to
offset
out­
of­
state
emissions
in
order
to
bring
the
area
into
attainment.[[
(
2279.1,
p.
8)
]]
EPA=
s
determination
represents
sound
policy
as
it
fairly
requires
sources
to
whom
the
exceedance
of
the
relevant
NAAQS
can
fairly
be
traced
to
bear
a
proportionate
share
of
the
costs
for
emissions
control.
Indeed,
it
would
be
unfair
for
EPA
to
not
include
Minnesota
within
the
CAIR
region
given
EPA=
s
analyses
showing
that
upwind
sources
cause
air
quality
impacts
downwind
to
a
degree
that
constitutes
significant
contribution
based
on
EPA=
s
empirical
threshold
for
regulation.
[[
(
2279.1,
p.
8)
]]

Response:
EPA
is
including
in
CAIR
all
States
that
it
has
determined
significantly
contribute
to
downwind
nonattainment
of
or
interfere
with
maintenance
of
the
PM2.5
and/
or
8­
hour
ozone
NAAQS.
EPA
has
determined
that
Minnesota
is
properly
included
in
the
CAIR
region
for
PM2.5
and
that
Florida
is
properly
included
in
the
CAIR
regions
for
PM2.5
and
8­
hour
ozone..
See
the
CAIR
Notice
of
Final
Action
on
Reconsideration
for
further
discussion.

XXII.
IMPACT
ON
CAIR
ANALYSES
OF
D.
C.
CIRCUIT
DECISION
IN
NEW
YORK
VS.
EPA
(
VACATURE
OF
NSR
PCP
EXCLUSION)

XXII.
A.
 
EPA
did
not
provide
sufficient
analysis
of
the
impacts
on
CAIR­
affected
sources
Document
No.:
OAR­
2003­
0053­
2303.1
Commenter:
Northern
Indiana
Public
Service
Utility
(
NIPSCO)
Comment:
"
USEPA
incorrectly
asserts
that
the
Supplemental
Petition
did
not
ask
USEPA
to
reconsider
implementation
dates
under
CAIR
and
related
timing
issues
in
light
of
the
PCP
Exclusion
Decision
(
70
FR
77104).
[ ]
The
Reconsideration
Decision
is
deficient
to
the
extent
that
USEPA
has
failed
to
reconsider
the
potential
impact
of
the
PCP
Exclusion
Decision
on
the
those
(
sic)
dates
and
whether
those
dates
should
he
deferred
in
light
of
that
decision."

Response:
It
is
EPA's
position
that
NIPSCO
did
not
explicitly
request
reconsideration
of
the
implementation
dates
under
the
CAIR
in
its
petition.
Nonetheless,
because
it
was
an
integral
part
of
the
issue,
the
Agency
did
analyze
the
impact
of
D.
C.
Circuit
Decision
in
New
York
v.
EPA
on
timing.
The
EPA
explicitly
discussed,
and
believes
it
has
adequately
addressed,
the
timing
implications
relating
to
this
issue
in
the
CAIR
Supplemental
Notice
of
Reconsideration
(
See
70
FR
77107­
11).
XXI.
INCLUSION
OF
FLORIDA
IN
THE
CAIR
REGION
FOR
OZONE
Document
No.:
OAR­
2003­
0053­
2289.1
Commenter:
City
of
Lakeland,
Florida
Department
of
Electric
Utilities
Phase:
Reconsideration
Notes:
Docket
Number
2289
is
the
cover
letter.
Docket
Number
2289.1
is
the
comment
letter.
Comment:
The
City
of
Lakeland
(
COL)
submits
the
following
comments
regarding
EPA=
s
notice
of
reconsideration
and
request
for
comment
on
four
specific
aspects
of
the
Clean
Air
Interstate
Rule
(
CAIR).
70
Fed.
Reg.
72268
(
December
2,
2005).
[[
(
2289.1,
p.
1)
]]]]
The
Entire
State
of
Florida
should
be
excluded
from
the
CAIR­
ozone
Program.
[[
(
2289.1,
p.
1)
]]
[[
(
See
pp.
1­
3
of
Docket
Number
2289.1
for
a
detailed
discussion
of
this
issue.)
]]
Even
if
some
portion
of
Florida
should
be
included
in
the
CAIR­
ozone
program,
a
substantial
portion
of
southern
Florida
should
be
excluded.
[[
(
2289.1,
p.
3)
]]
[[
(
See
pp.
3­
4
of
Docket
Number
2289.1
for
a
detailed
discussion
of
this
issue.)
]]
Florida
emissions
do
not
>
interfere
with
maintenance=
in
Fulton
County.
[[
(
2289.1,
p.
4)
]][[
(
See
p.
3
of
Docket
Number
2289.1
for
a
detailed
discussion
of
this
issue.)
]]

Response:
EPA
considered
this
issue
at
length
in
the
CAIR
rulemaking,
and
especially
in
response
to
comment
C.
17
in
the
CAIR
Response
to
Comment
Document.
As
stated
there,
Fulton
County
remains
at
risk
of
nonattainment
of
the
8­
hour
ozone
NAAQS
even
in
2015
because
projected
levels
of
attainment
remain
less
than
the
historic
levels
of
ozone
variability
in
Fulton
County.
Thus,
out­
of­
state
emissions
can
reasonably
be
viewed
as
significantly
interfering
with
maintenance
of
the
NAAQS
at
that
time.
The
same
comment
response
notes
that
CAIR
is
one
remedy,
not
two,
so
that
there
is
no
reason
to
have
to
separately
justify
the
2015
standards.

EPA
should
revise
CAIR
to
exclude
the
entire
state
of
Florida
from
the
CAIR­
ozone
program
because
Florida=
s
contribution
is
less
than
the
conservative
screening
criteria
developed
by
EPA.
EPA=
s
refusal
to
utilize
the
precise
data
it
developed
for
Florida=
s
average
percent
contribution
to
Fulton
County,
and
instead
put
blinders
on
until
it
arbitrarily
rounds
the
number
to
a
value
above
the
screening
criteria,
is
inappropriate,
inconsistent
with
prior
practice,
arbitrary,
capricious
and
an
abuse
of
discretion.

Response:
This
comment
is
addressed
in
the
preamble
to
the
rule
as
well
as
in
EPA's
response
to
judicial
stay
motions
on
the
issue
(
which
response
is
part
of
the
administrative
record
to
this
proceeding).
In
sum,
EPA
reasonably
used
a
standard
rounding
protocol
here,
and
doing
so
is
not
inconsistent
with
past
practice
or
otherwise
arbitrary.
.
Nonetheless,
even
if
EPA=
s
approach
is
upheld,
EPA
should
revise
CAIR
to
exclude
southern
Florida
from
the
CAIR­
ozone
program
because
unrefuted
modeling
data
demonstrates
that
southern
Florida
does
not
>
contribute
significantly=
to
nonattainment
or
>
interfere
with
maintenance=
in
another
state.
[[
(
2289.1,
pp.
4­
5)
]]
Response:
EPA
disagrees
for
the
reasons
given
in
the
preamble
to
the
final
rule
and
EPA's
response
to
the
judicial
stay
motions.
EPA
notes
further
that
the
commenter
has
the
burden
of
showing
that
EPA's
use
of
collective
contribution
from
the
entire
state
is
unreasonable,
and
the
comment
fails
to
satisfy
that
burden.
See
Appalachian
Power
Co.
v.
EPA,
249
F.
3d
1032,
1059
(
D.
C.
Cir.
2001)
(
burden
is
on
entity
challenging
statewide
collective
contribution
determination
to
EPA
to
show
that
EPA's
approach
is
irrational).

Document
No.:
OAR­
2003­
0053­
2275.1
Commenter:
FPL
Group
Phase:
Reconsideration
Notes:
Docket
Number
2275
is
the
cover
letter.
Docket
Number
2275.1
is
the
comment
letter.
Also
included
in
the
submittal
where
the
following
attachments:
Docket
Numbers
2275.2,
2275.3,
2275.4,
2275.5,
2275.6,
2275.7,
2275.8,
2275.9,
2275.10a,
2275.10b,
2275.10c,
2275.10d,
and
2275.10e.
Comment:
Florida
should
not
be
included
in
the
CAIR
region
for
ozone,
because
EPA=
s
decision
to
do
so
is
based
on
a
fatally
flawed
rounding
protocol.
Even
if
that
rounding
protocol
could
be
properly
applied
to
Florida,
modeling
submitted
with
the
petition
shows
that
the
portion
of
Florida
below
28.66
degrees
north
latitude
must
be
excluded
from
the
CAIR
region
for
ozone
because
it
does
not
significantly
contribute
to
ozone
nonattainment
in
any
downwind
area.
(
Reconsideration
Issue
No.
4)
[[
(
2275.1,
p.
2)
]]
Unlike
the
other
three
reconsideration
issues,
the
Notice
of
Reconsideration
provides
no
guidance
as
to
what
concerns
EPA
wants
commenters
to
address
with
respect
to
Reconsideration
Issue
No
4
It
states
only
that
reconsideration
is
being
granted
because
EPA
first
included
Florida
in
the
CAIR
region
for
ozone
in
the
Final
Rule,
thus
providing
no
meaningful
opportunity
for
comments
on
whether
doing
so
was
appropriate
See
70
Fed
Reg
72268,72280.
In
the
absence
of
guidance,
FPL
Group
and
other
commenters
are
forced
to
address
this
issue
in
a
vacuum
FPL
Group
has
two
comments
on
EPA=
s
inclusion
of
Florida
in
the
CAIR
region
for
ozone,
which
show
that
all
or
a
significant
portion
of
Florida
should
be
excluded
Those
comments
are
discussed
below
If
EPA
intends
that
other
concerns
be
addressed,
it
needs
to
state
those
concerns
and
then
provide
a
separate
opportunity
for
FPL
Group
and
others
to
comment
on
them.
([[
2275.1,
p.
2)
]]

Response:
Senior
EPA
staff
met
with
representatives
of
the
commenter
on
November
30,
2005
and
told
them
to
concentrate
comments
on
the
points
raised
in
EPA's
response
to
their
stay
motion
filed
in
the
D.
C.
Circuit.
The
comments
submitted
here
appear
to
have
followed
that
advice.

The
entire
state
of
Florida
should
be
excluded
from
the
CAIR
region
for
ozone.
Because
EPA=
s
own
modeling
shows
that
Florida
contributes
less
than
one
percent
of
the
total
non­
attainment
for
ozone.
[[
(
2275.1,
p.
2)
]]
[[
(
See
pp.
2­
4
of
docket
number
2275.1
for
a
detailed
discussion
of
this
issue.)
]]
If
the
entire
state
of
Florida
is
not
excluded
from
the
CAIR
region
for
ozone,
the
portion
of
Florida
below
28.66
degrees
north
latitude
must
be
excluded
because
it
does
not
significantly
contribute
to
ozone
non­
attainment
in
any
downwind
area.
[[
(
2275.1,
p.
5)
]]
[[
(
See
pp.
5­
7
of
docket
number
2275.1
for
a
detailed
discussion
of
this
issue.)
]]

Response:
See
preamble
and
other
comment
responses.

Document
No.:
OAR­
2003­
0053­
2275.1
Commenter:
FPL
Group
Phase:
Reconsideration
Comment:
This
comment
substantially
tracks
those
of
Tampa,
Gulf,
and
FAEU,
and
EPA's
responses
to
these
comments,
as
well
as
the
preamble
discussion
and
EPA's
response
to
the
Florida
Utilities'
stay
motion
to
the
D.
C.
Circuit
serve
as
the
principal
response.
EPA
is
responding
here
only
to
points
raised
in
this
comment
not
already
addressed
elsewhere.

1.
Inclusion
of
Florida
in
the
CAIR
region
for
ozone
is
marginal
at
best,
and
cannot
be
justified
by
any
secondary
benefits
of
helping
to
achieve
regulatory
compliance
in
Florida.
If
EPA
does
not
remove
Florida
from
the
CAIR
region
for
ozone,
Florida
EGUs
will
be
required
to
make
enormous
expenditures
on
pollution
control
equipment
and/
or
purchases
of
CAIR
NOx
allowances
that
otherwise
would
not
be
needed
or
warranted.

Response:
Whether
or
not
an
upwind
emitting
state
is
in
attainment
or
not
is
not
relevant
under
section
110
(
a)
(
2)
(
D),
which
concerns
itself
exclusively
with
whether
upwind
pollution
contributes
significantly
to
downwind
nonattainment
or
maintenance
problems.
Ambient
pollution
levels
in
the
upwind
state
are
irrelevant
to
this
inquiry.
However,
EPA
is
confused
somewhat
by
this
comment,
since
Florida
is
in
the
CAIR
region
for
PM2.5
in
any
case,
and
so
must
control
NOx
emissions
to
meet
those
NOx
budgets
in
any
case.

2.
EPA
(
in
its
responsive
papers
in
the
D.
C.
Circuit)
states
that
it
utilized
the
same
rounding
protocol
when
applying
the
percent
of
nonattainment
metric
in
the
NOx
SIP
Call
and
cited
to
63
FR
56377
in
support.
That
page
contains
no
discussion
of
this
issue.

Response:
EPA
was
simply
citing
to
the
page
in
the
Federal
Register
where
the
NOx
SIP
Call
is
located.
It
remains
correct,
however,
that
EPA
utilized
the
identical
rounding
protocol
in
the
NOx
SIP
Call.
See
also
Technical
Support
Document
for
Air
Quality
Modeling
for
CAIR,
Docket
number
2151
at
IV.
A
p.
26
stating
that
EPA
used
the
same
metrics
and
technical
approach
in
assessing
significant
contribution
for
ozone
in
both
the
CAIR
and
the
NOx
SIP
Call.
EPA
notes
further
that
its
approach
to
rounding
in
applying
this
screening
metric,
is
quite
standardized.
Under
this
approach,
1)
EPA
calculated
the
relative
amount
of
nonattainment
based
on
the
CAIR
CAMx
modeling,
which
results
in
a
long
decimal
number
(
as
many
as
16
significant
figures).
2)
EPA
identified
the
screening
criteria
to
be
"
less
than
1
percent
...".
This
threshold
has
one
significant
figure.

3)
The
number
of
significant
figures
in
the
threshold
dictates
the
rounding
convention
for
comparing
the
modeled
value
of
relative
amount
of
nonattainment,
i.
e.,
it
must
have
the
same
number
of
significant
figures
as
the
criteria.

4)
EPA
followed
the
rounding
method
outlined
in
ASTM
Practice
E­
29,
which
is
the
same
as
International
Standards
Organization
(
ISO)
standard
31­
0,
Annex
B,
Rule
B
to
round
the
relative
amount
of
nonattainment
values
to
one
significant
figure
(
i.
e.,
match
the
threshold)

x.
0y
through
x.
4y:
round
to
x
x.
5y
through
x.
9y:
round
to
x+
1,
where
"
y"
is
all
values
from
the
second
decimal
on.

This
rounding
convention
is
alternatively
referred
to
as
the
"
common"
method
of
rounding,
or
the
"
bottom
half
up"
method
of
rounding.
It
is
a
very
common
rounding
technique
and
is
used
in
most
accounting
applications.

5)
Note
that
the
approach
used
for
rounding
this
metric
in
the
NOx
SIP
Call
(
and
by
extension
in
the
CAIR
analyses)
is
the
same
approach
as
discussed
in
the
EPA
1998
guidance
document:
"
Guideline
on
Data
Handling
Conventions
for
the
8­
Hour
Ozone
NAAQS"
(
EPA­
454/
R­
98­
017)
and
later
codified
within
40
CFR
50,
Appendix
I,
2.3.

3.
EPA's
approach
to
rounding
is
inconsistent
with
its
application
of
the
PM2.5
significant
contribution
metric,
citing
to
the
discussion
at
70
FR
25191
and
n.
42.

Response:
EPA
does
not
perceive
the
inconsistency
pointed
to
by
the
commenter.
The
PM
significance
of
contribution
metric
assesses
magnitude
of
contribution.
The
proper
ozone
contribution
metrics
for
comparison
purposes
therefore
are
those
which
assess
magnitude
of
contribution,
not
(
as
the
commenter
would
have
it)
the
relative
contribution
to
nonattainment
metric.
In
applying
the
PM2.5
magnitude
of
contribution
metric,
EPA
applies
a
truncation
protocol.
Similarly,
in
applying
the
ozone
magnitude
of
contribution
metrics
(
both
the
initial
screening
metrics
and
the
subsequent
second
step
metrics),
EPA
uses
truncation
protocols,
as
explained
in
the
preamble
to
the
final
rule;
see
also
70
FR
at
25191
n.
41
making
the
same
point
and
noting
the
similarity
of
approach.
Since
EPA
uses
the
same
protocols
when
assessing
magnitude
of
contribution
for
both
ozone
and
PM2.5,
EPA
does
not
agree
with
the
commenter
tht
there
is
some
fundamental
inconsistency
in
approach.
See
also
the
preamble
discussion
on
this
issue.

4.
EPA's
true
relative
amount
of
contribution
metric
is
.5%
due
to
the
rounding
convention,
not
1%,
and
EPA
has
failed
to
justify
why
that
value
is
significant.
Response:
First,
the
value
used
in
the
metric
is
1%,
using
standard
rounding
conventions
to
round
to
the
nearest
integer,
so
no
independent
justification
is
necessary.
Second,
even
if
such
justification
is
deemed
necessary,
the
comment
seems
not
to
understand
the
significance
determination
process.
The
significance
determination
process,
as
described
on
pp
32­
35
of
the
CAIR
Air
Quality
Modeling
Technical
Support
Document,
contains
four
steps:
1)
evaluation
of
contributions
against
screening
criteria,
2)
evaluation
of
contributions
from
zero
out
modeling,
3)
evaluation
of
contributions
from
source
apportionment
modeling,
and
4)
a
final
aggregate
determination
of
significance.
The
purpose
of
the
initial
screening
(
the
only
step
in
the
process
at
issue
here)
is
to
distinguish
contributions
that
are
clearly
small
from
those
which
require
further
analysis
to
evaluate
significance.
The
>=
1%
(
0.5%,
pre­
rounding)
average
percent
contribution
determination
is
thus
not
to
determine
significance,
but
rather
to
determine
whether
further
analysis
of
significance
is
needed.
In
the
case
of
the
Florida
contribution,
steps
2
and
3
of
the
determination
process
indicated
that
there
are
large
and
frequent
contributions
from
that
State
to
elevated
ozone
concentrations
in
Fulton
Co.,
GA.
The
CAIR
modeling
estimates
that
Florida
can
contribute
as
much
as
3.2
­
5.5
ppb
(
depending
on
modeling
technique)
toward
modeled
eight
hour
ozone
exceedance
periods
in
Fulton
Co.,
GA..
Further,
it
was
determined
that
between
10
­
13
percent
of
the
modeled
periods
above
85
ppb
in
Fulton
Co.,
GA
were
affected
by
at
least
2
ppb
of
ozone
that
resulted
from
emissions
from
Florida.
The
relative
amount
of
contribution
ranges
between
0.8
­
2.2
percent.
(
None
of
these
results
are
questioned
by
the
commenter.)
The
criteria
used
to
distinguish
which
values
comprise
a
significant
contribution
are
set
out
at
page
40
of
the
TSD.
Based
on
these
criteria,
Florida
was
determined
to
have
a
significant
contribution
to
Fulton
Co.,
GA
based
on
the
magnitude
and
frequency,
but
not
the
relative
amount
of
contribution.
As
explained
on
p.
33
of
the
TSD,
for
linkages
in
which
the
three
contribution
factors
were
not
unanimous,
we
required
that
two
of
the
three
factors
had
to
indicate
high
magnitude,
frequent,
and/
or
relatively
large
contributions
in
order
to
find
that
the
linkage
was
significant.
This
approach
was
applied
consistently
to
each
of
the
linkages
for
which
a
significance
determination
was
made.
In
sum,
we
have
concluded
that
the
Florida
contribution
to
Fulton
Co.,
GA
represents
a
significant
contribution
by
any
rational
measure.

5.
EPA
did
not
follow
through
on
its
own
decision
not
to
include
some
of
southern
Florida
from
the
CAIR
ozone
region.

Response:
The
comment
is
mistaken.
All
of
Florida
is
included
in
the
CAIR
ozone
region.
EPA
chose
not
to
model
a
small
bit
of
southern
Florida
as
part
of
the
modeling
exercise
supporting
the
significant
contribution
analysis.
We
did
so
largely
because
meteorological
inputs
were
lacking
for
this
small
part
of
the
state,
and
because
460.9
of
Florida's
total
of
461.0
2010
based
EGU
NOx
emissions
are
in
the
domain
of
the
state
which
EPA
did
model
(
although
other
sources,
such
as
mobile
sources,
contribute
NOx
from
the
small
region
EPA
did
not
model
).
EPA's
decision
not
to
model
the
small
bit
of
southern
Florida
is
thus
justified
by
these
practical
considerations,
and
indeed,
EPA's
decision
could
only
work
to
the
commenter's
advantage,
since
EPA's
approach
actually
understates
the
total
NOx
contribution
from
the
State.

6.
The
Commenter
states
that
EPA
in
its
stay
papers
(
p.
18)
argued
that
Florida
should
be
in
the
CAIR
ozone
region
because
its
emission
are
"
material"
and
"
measurable"
and
that
this
is
not
the
test
under
section
110
(
a)
(
2)
(
D)
(
i),
or
is
a
different
approach
then
that
set
forth
in
the
CAIR
rulemaking.

Response:
EPA
did
not
intend
to
enunciate
any
different
test
for
assessing
significance
of
contribution
than
that
used
in
the
CAIR
rulemaking,
and
believes
that
the
commenter
is
misinterpreting
EPA's
response
to
the
stay
motion.

7.
FPL
used
a
dividing
line
for
northern
and
southern
Florida
based
on
the
same
intuitive
understanding
that
led
EPA
to
exclude
a
smaller
portion
of
southern
Florida,
that
an
area
will
have
less
effect
than
northern
portions
of
the
state.
However,
FPL's
suggested
division
is
not
merely
intuitive,
but
grounded
in
a
reasoned
modeling
exercise.

Response:
As
noted
above,
EPA
did
not
exclude
any
of
Florida
from
the
CAIR
ozone
region.
Our
response
to
the
modeling
submitted
by
the
commenter
is
set
out
in
the
preamble
to
the
final
rule
and
in
other
comment
responses,
and
states,
in
brief,
that
the
commenter
did
not
satisfy
its
burden
of
showing
that
EPA's
statewide
approach
to
evaluating
significant
contribution
is
irrational
or
otherwise
show
that
areas
it
would
exclude
are
devoid
of
material
contribution
to
upwind
ozone
nonattainment.
Further,
we
sharply
disagree
that
there
is
any
validity
in
comparing
EPA's
practical
decision
to
exclude
from
the
modeling
analysis
a
very
small
part
of
the
total
emissions
from
the
State
(
i.
e.
0.02%
of
the
total
Florida
EGU
NOx
emissions
inventory)
to
the
commenter's
decision
to
draw
a
line
that
distinguishes
between
portions
of
the
State
that
contribute
69%
and
31
%
of
Florida's
overall
contribution
to
Fulton
Co.,
GA.
There
are
three
orders
of
magnitude
difference
between
the
results.

Document
No.:
OAR­
2003­
0053­
2295.1
Commenter:
Tampa
Electric
Company
Phase:
Reconsideration
Notes:
Docket
Number
2295
is
the
cover
letter.
Docket
Number
2295.1
is
the
comment
letter.
Comment:
The
Entire
State
of
Florida
should
be
excluded
from
the
CAIR­
ozone
Program.
A)
EPA
should
use
the
precise
data
that
it
generated.
Florida
should
not
be
included
in
the
CAIR­
ozone
program
because
Florida=
s
modeled
contribution
to
Fulton
County,
Georgia
is
below
EPA=
s
threshold
for
a
>
significant=
contribution.
Specifically,
EPA
established
three
>
insignificant=
thresholds
for
automatically
excluding
a
state
from
the
CAIR­
ozone
program
­
a
state
is
excluded
if
any
one
of
the
three
is
met.
The
relevant
threshold
for
Florida
is
whether
the
average
percent
contribution
to
the
nonattainment
target
is
above
or
below
1
percent,
and
EPA
intended
this
to
be
a
conservative
threshold:
>
The
first
step
in
evaluating
the
contribution
factors
is
to
screen
out
linkages
for
which
the
contribution
is
clearly
small.=
EPA
has
confirmed
that
its
data
shows
that
Florida=
s
average
percent
contribution
to
Fulton
County,
Georgia
(
the
only
nonattainment
target
at
issue
for
Florida)
is
0.81,
and
is
therefore
clearly
below
EPA=
s
own
conservative,
insignificance
threshold.
Very
simply,
EPA
should
honor
the
precise
data
that
it
generated
and
exclude
Florida
from
the
CAR­
ozone
program.
[[
(
2295.1,
p.
2)
]]

Response:
EPA
agrees
that
it
would
have
been
preferable
had
EPA
explicitly
stated
that
it
used
the
standard
rounding
protocol
of
rounding
up
or
down
to
the
next
significant
integer
rather
than
simply
applying
that
rounding
protocol
uniformly
(
both
in
CAIR
and
in
the
NOx
SIP
Call).
EPA
has
revised
Appendix
G
of
the
Technical
Support
Document
to
make
this
explicit.
However,
EPA
applied
this
approach
uniformly
in
both
this
rule
and
in
the
NOx
SIP
Call,
and
there
is
nothing
remarkable
in
rounding
0.81%
up
to
one
percent.

b)
EPA=
s
rounding
approach
is
arbitrary,
capricious
and
inconsistent
with
its
own
guidance.
EPA=
s
decision
to
round
the
>
average
percent
contribution=
screening
criteria
to
the
nearest
whole
number
before
it
evaluates
the
answer
is
arbitrary,
capricious
and
inconsistent
with
its
own
practices
and
guidance.
First,
as
explained
in
paragraph
2(
a),
EPA=
s
approach
fails
to
recognize
the
actual
value
it
generated,
and
this
failure
creates
a
nonsense
result.

Response:
.
The
fact
that
Florida
concededly
fails
the
other
two
ozone
metrics
(
magnitude
and
frequency
of
contribution)
likewise
shows
that
including
Florida
within
the
CAIR
ozone
region
is
a
reasonable
outcome.

Second,
EPA=
s
approach
is
deceptive
and
misleading
because
the
actual
threshold
is
actually
>
less
than
0.5
percent,=
and
not
>
less
than
one
percent=
as
EPA
states.
To
require
a
state=
s
average
percent
contribution
to
actually
be
less
than
0.50
(
or
0.449
if
EPA
erroneously
rounds
twice)
Response:
The
commenter
is
correct,
but
this
point
has
no
practical
consequence,
because
the
contribution
of
Florida
to
Fulton
County
8­
hour
NOx
nonattainment
is
0.81
%,
not
0.45
%.,
is
a
dramatically
different
threshold
than
requiring
the
value
to
be
less
than
1.

Response:
EPA
does
not
perceive
how
using
the
standard
rounding
protocol
of
rounding
.81
up
to
one
is
a
dramatically
different
result.
Florida,
on
its
own,
is
still
contributing
substantial
amounts
of
the
nonattainment
ozone
to
Fulton
County.
As
noted
earlier,
Florida
also
concededly
contributes
significantly
to
Fulton
County
nonattainment
in
terms
of
magnitude
and
frequency
of
ozone
contribution.
This
determination
was
based
on
the
criteria
outlined
in
the
CAIR
Air
Quality
Modeling
TSD
and
is
consistent
with
a
rational
understanding
of
significant
contribution.
Third,
EPA=
s
approach
is
inconsistent
with
its
truncating
approach
for
the
other
two
screening
criteria.
EPA=
s
after­
the­
fact
explanation
for
this
discrepancy
is
that
the
average
percent
contribution
metric
is
not
a
concentration
measurement
that
is
tied
to
an
ambient
standard.
But
that
is
exactly
how
the
average
percent
contribution
is
calculated:
EPA
takes
the
concentration
of
total
ozone
in
the
nonattainment
area,
and
the
state=
s
concentration
contribution
to
that
total
to
determine
the
percentage.
Arguing
that
one
number
is
a
percentage
and
the
other
two
are
concentrations
is
therefore
erroneous
and
misleading.
Response:
As
stated
in
the
preamble,
EPA's
approach
to
rounding
here
is
commonplace,
not
arbitrary.
Nor
was
EPA
arbitrary
in
choosing
to
round
rather
than
truncate.
The
form
of
the
8­
hour
NAAQS
includes
a
truncation
feature,
as
set
out
in
Appendix
I
to
Part
50.
Significant
contribution
metrics
that
are
expressed
as
direct
percentages
of
that
NAAQS
thus
use
the
same
truncation
protocol.
The
relative
contribution
to
nonattainment
metric
is
not
one
of
these
.
It
determines
what
extent
of
the
downwind
area's
nonattainment
with
the
8­
hour
ozone
NAAQS
results
from
upwind
state
emissions.
The
metric
is
not
directly
derived
from
the
form
of
the
NAAQS,
and
thus
there
is
no
reason
to
apply
truncation
protocols
that
are
part
of
that
form.
EPA
thus
did
not
do
so
(
either
in
the
CAIR
or
in
the
earlier
NOx
SIP
Call),
and
used
the
standard,
unremarkable
rounding
protocol
of
rounding
up
(.
5%
or
higher)
or
down
(.
4%
of
lower)
to
the
closest
integer
value.

And
fourth,
EPA=
s
approach
is
inconsistent
with
its
own
guidance,
which
requires
that
standards
(
thresholds),
as
well
as
the
calculated
values
the
agency
is
comparing
them
against,
contain
at
least
two
significant
figures.
If
EPA
followed
its
own
guidance,
its
>
less
than
one
percent=
threshold
would
actually
be
>
less
than
1.0
percent,=
and
the
calculated
value
would
also
need
to
contain
at
least
two
significant
figures.
Accordingly,
Florida=
s
average
percent
contribution
of
0.81
already
contains
two
significant
figures
and
would
not
be
rounded
further;
this
value
should
simply
be
compared
to
1.0,
and
0.81
is
clearly
less
than
1.0.
[[
(
2295.1,
pp­
3)
]]

Response:
The
commenter
cites
a
June
6,
1990
memorandum
from
William
G.
Laxton
and
John
S.
Seitz
to
the
compliance
contacts
for
New
Source
Performance
Standards
(
NSPS)
and
National
Emissions
Standards
for
Hazardous
Pollutants
(
NESHAPs).
The
memorandum
identified
guidelines
to
be
used
when
calculating
emission
rates
and
concentrations
when
determining
compliance
with
NSPS/
NESHAPs.
The
issue
of
how
to
interpret
modeling
results
to
determine
whether
an
upwind
State
significantly
contributes
to
violations
of
the
eight­
hour
ozone
NAAQS
is
not
related
to
the
matters
dealt
with
in
the
cited
1990
memorandum.
The
commenter
did
not
explain
the
relevance
of
the
memorandum
(
the
comment
simply
cites
language
from
the
memorandum
out
of
context),
and
no
relevance
is
apparent
to
EPA.

EPA
also
confuses
the
threshold
by
describing
it
as
>
less
than
1
percent=
in
the
Technical
Support
Document
(
p.
32)
and
>
had
to
be
greater
than
1
percent=
in
the
preamble
to
the
final
rule
(
70
Fed.
Reg.
2524612).
If
the
threshold
is
>
greater
than
1
percent,=
EPA
should
exclude
Florida
from
the
CAIR­
ozone
program
regardless
of
the
credibility
of
EPA=
s
rounding
approach.
If
rounding
is
appropriate,
EPA=
s
final
preamble
statement
quoted
above
articulates
the
proper
threshold
­
it
is
deceptive,
at
best,
to
transform
(
via
rounding)
a
number
that
is
clearly
>
less
than
1
percent=
(
0.81
in
Florida=
s
case)
to
one,
and
then
conclude
that
because
one
is
not
>
less
than
one,=
the
entire
state
should
be
included.
[[
(
2295.1,
p.
3)
]]

Response:
EPA
agrees
that
the
rounding
protocol
should
have
been
explicitly
referred
to.
In
the
preamble
to
the
final
rule
and
in
these
responses,
as
well
as
in
the
revised
Appendix
G
to
the
Technical
Support
Document,
EPA
is
making
clear
that
it
is
applying
this
usual
rounding
protocol
in
computing
the
amount
of
contribution
ozone
metric.
EPA
reiterates
that
it
followed
this
protocol
uniformly
both
in
the
CAIR
and
in
the
earlier
NOx
SIP
Call.

c)
Additional
policy
and
scientific
reasons
that
justify
excluding
Florida.
There
are
many
additional
policy
and
scientific
factors
that
support
Florida=
s
exclusion
from
the
CAIR­
ozone
program:
1)
EPA
included
Florida
in
the
CAIR­
ozone
program
based
on
its
contribution
to
only
one
nonattainment
county,
whereas
EPA
highlights
in
the
preamble
to
the
final
rule
the
fact
that
all
other
states
in
the
CAIR­
ozone
program
(
except
Louisiana
and
Arkansas)
contribute
to
more
than
one
nonattainment
county.

Response:
This
comment
is
not
legally
relevant,
since
section
110
(
a)
(
2)
(
D)
(
i)
requires
SIPs
to
prohibit
any
significant
contribution
to
downwind
nonattainment,
and
does
not
require
that
such
contribution
be
to
more
than
one
area.
EPA
also
notes
that
the
Delaware­
New
Jersey
combined
entity,
which
are
considered
together
for
assessing
significance
of
contribution
by
virtue
of
other
final
action
taken
today,
are
linked
to
a
single
downwind
area
(
a
large
metropolitan
area,
New
York
County
(
New
York
City),
which
is
similar
to
the
link
with
Florida
and
Fulton
County,
which
contains
the
large
metropolitan
area
Atlanta).
Minnesota
is
likewise
included
within
the
CAIR
PM
region
due
to
a
single
link
with
an
Illinois
nonattainment
area.

2)
EPA=
s
modeling
shows
that
Fulton
County
will
achieve
attainment
by
2015
without
any
benefit
from
CAIR.
Including
Florida
in
the
CAIR
ozone
program,
therefore,
will
provide
a
less
than
one­
percent
benefit
to
a
county
that
does
need
assistance
to
achieve
attainment.

Response:
First,
the
8­
hour
ozone
attainment
date
is
2009,
not
2015.
Controls
on
upwind
state
emissions
which
contribute
significantly
to
nonattainment
as
of
that
time
are
the
proper
trigger
for
evaluating
significance
of
contribution
for
purposes
of
section
110
(
a)
(
2)
(
D)
(
i).
See
also
response
to
comment
C.
17
to
the
CAIR
Response
to
Comment
Document,
explaining
first
that
CAIR
is
a
single
remedy
which
for
feasibility
reasons
occurs
in
two
steps,
and
second,
that
even
if
one
does
not
accept
this
view,
the
2015
CAIR
controls
are
needed
to
prevent
significant
interference
with
maintenance
in
all
linked
areas
in
the
CAIR
ozone
region.
This
includes
Fulton
County,
where
historic
ozone
variability
patterns
exceed
the
amount
by
which
the
county
is
projected
to
attain
the
8­
hour
NAAQS
in
both
the
base
and
CAIR
cases
in
2015.

3)
Fulton
County=
s
current
air
quality
is
primarily
a
locally­
caused
problem,
so
limiting
emissions
from
other
states
will
provide
minimal
benefit.
EPA
states
that
76
percent
of
the
ozone
in
Fulton
County
is
due
to
in­
state
emissions,
the
highest
percentage
of
any
of
the
40
nonattainment
targets.

Response:
Nonetheless,
the
out
of
state
contribution
to
nonattainment
in
Fulton
County
remains
nearly
25
%
of
the
total
and
it
reasonably
meets
the
goal
of
section
110
(
a)
(
2)
(
D)
to
achieve
a
reasonable
balance
between
in­
state
and
out­
of­
state
controls
to
control
this
significant
contribution.
Fulton
County
is
not
projected
to
attain
the
8­
hour
ozone
standard
in
the
2010
CAIR
case
(
i.
e.
after
2009
NOx
controls),
so
that
local
controls
remain
necessary
for
the
area
to
attain.

4)
Florida=
s
average
percent
contribution
to
Fulton
County=
s
ozone
level
is
less
than
the
contribution
from
four
states
that
EPA
concluded
do
not
contribute
significantly
to
Fulton
County:
Arkansas,
Indiana,
Illinois
and
Missouri.
Response:
This
is
because
these
other
states
contribute
less
than
Florida
in
terms
of
magnitude
and
frequency
of
contribution.
5)
Florida
is
already
doing
its
part
as
a
good
neighbor,
as
evidenced
by
the
fact
that
Florida
is
one
of
only
three
states
east
of
the
Mississippi
River
in
attainment
for
all
criteria
pollutants.
[[
(
2295.1,
pp.
3­
4)
]]

Response:
This
is
not
legally
relevant
in
determining
whether
or
not
Florida
contributes
significantly
to
out­
of­
state
nonattainment.
See
CAA
section
110
(
a)
(
2)
(
D).

Even
if
some
portion
of
Florida
should
be
included
in
the
CAIR­
ozone
program,
a
substantial
portion
of
southern
Florida
should
be
excluded.
Assuming
for
comment
purposes
that
EPA=
s
approach
to
rounding
is
proper,
Section
110(
a)(
2)(
D)
of
the
Clean
Air
Act
and
the
[
State
of]
Michigan
case
prohibit
EPA
from
including
sources
in
CAIR
that
do
not
>
contribute
significantly=
to
nonattainment
in
another
state.

Response:
This
is
a
misreading
of
the
relevant
caselaw,
which
makes
clear
that
the
burden
is
on
a
commenter
to
show
why
EPA's
approach
of
assessing
significant
contribution
on
a
statewide,
collective
contribution
basis,
is
irrational.
Appalachian
Power,
126
F.
3d
at
1050;
State
of
Michigan,
213
F.
3d
at
684.
Certainly,
there
is
no
showing
in
this
comment
or
any
other
that
the
portion
of
the
state
they
seek
to
exclude
from
the
CAIR
ozone
region
is
"
innocent
of
material
contributions".
213
F.
3d
at
684.
To
the
contrary.
The
Ozone
Report
submitted
in
comments
shows
that
there
are
large
NOx
emitting
sources
(
both
EGUs
and
others)
in
the
southern
portion
of
the
state
the
commenters
would
exclude,
and
that
the
collective
contribution
of
sources
in
the
southern
portion
of
the
state
that
the
commenters
would
exclude
is
a
substantial
fraction
(
nearly
one­
third)
of
the
entire
state
contribution.
Rather
than
showing
that
the
southern
portion
of
the
state
is
"
innocent
of
material
contributions",
EPA
believes
these
facts
demonstrate
a
classic
instance
of
collective
contribution.

These
arguments,
as
well
as
supporting
modeling
data,
are
presented
and
explained
in
detail
in
filings
by
the
Florida
Association
of
Electric
Utilities
(
FAEU)
with
the
D.
C.
Circuit.
Specifically,
FAEU
provided
detailed
modeling
data
that
demonstrates
that
a
substantial
portion
of
southern
Florida
does
not,
in
fact,
contribute
significantly
to
ozone
nonattainment
in
Fulton
County,
Georgia.
Specifically,
sources
below
latitude
(
approximately)
28.67
should
not
be
subjected
to
CAIR
because
they
do
not
contribute
significantly
to
nonattainment
in
Fulton
County.
TEC
asks
EPA
to
honor
these
findings.
[[
(
2295.1,
p.
4)
]]
Response:
See
preamble,
other
comment
responses,
and
EPA's
response
to
the
D.
C.
Circuit
to
judicial
stay
motions.
In
sum,
EPA
believes
the
modeling
data
presented
demonstrate
state­
wide
significant
contribution
due
to
collective
contribution
and
believes
further
that
the
comments
fall
well
short
of
the
demonstration
required
to
justify
partial
state
control
under
both
Appalachian
Power
and
State
of
Michigan.

The
Clean
Air
Act
authority
upon
which
EPA
relies
for
CAIR
(
Section
110(
a)(
2)(
D))
is
limited
to
>
prohibiting
.
.
.
any
source
or
other
type
of
emissions
activity
within
the
State
from
emitting
any
air
pollutant
in
amounts
which
will
.
.
.
contribute
significantly
to
nonattainment
in,
or
interfere
with
maintenance
by,
and
other
State.=
If
undisputed
data
shows
that
certain
sources
do
not
>
contribute
significantly
to
nonattainment
in=
or
>
interfere
with
maintenance=
in
another
state,
they
cannot
be
regulated
under
Section
110(
a)(
a)(
D).
The
modeling
data
filed
by
FAEU
shows
precisely
which
sources
contribute
significantly,
and
which
ones
do
not;
using
such
data
to
define
which
sources
should
be
subject
to
CAIR,
and
which
ones
should
not,
is
compelled
by
the
Clean
Air
Act,
rational
and
objective.
[[
(
2295.1,
p.
4)
]]

Response:
The
argument
that
significant
contribution
for
purposes
of
section
110
(
a)
(
2)
(
D)
must
be
assessed
on
a
source­
by­
source
basis
was
rejected
in
State
of
Michigan,
213
F.
3d
at
679,
and
in
the
closely­
related
context
of
section
126
in
Appalachian
Power,
249
F.
3d
at
1048­
51
(
both
cases
upholding
uniform
controls
based
on
collective
contribution
which
overall
are
significant).
Nor
did
the
commenters
present
any
data
showing
that
individual
sources
do
not
contribute.
Their
modeling
assessed
collective
emissions
from
various
geographic
divisions
of
the
State.

Also,
not
subjecting
southern
Florida
to
CAIR
follows
common
sense.
First,
EPA
and
the
D.
C.
Circuit
have
recognized
the
common
sense
expectation
that
proximity
to
a
nonattainment
area
is
a
key
factor
in
determining
the
extent
of
contribution
that
that
area=
s
sources
will
have
on
the
nonattainment
area.
Fulton
County
is
in
north­
central
Georgia,
a
substantial
distance
from
the
Florida
line
and
even
further
from
latitude
28.67
(
the
boundary
demonstrated
in
FAEU=
s
modeling).
Florida
is
a
peninsular
state,
oriented
essentially
north­
south,
and
Fulton
County
is
essentially
due
north
of
Florida.
So
the
further
south
a
se
ource
is
in
Florida,
the
further
away
the
source
is
from
Fulton
County,
and
the
less
its
emissions
are
expected
to
cause
an
impact.
Importantly,
latitude
28.67
is
approximately
the
same
distance
from
Fulton
County
as
the
states
of
Arkansas,
Indiana,
Missouri
and
Illinois,
four
states
that
EPA
expressly
determined
do
not
contribute
significantly
to
Fulton
County.

Response:
Even
under
the
commenters'
own
modeling,
ozone
emissions
from
the
southern
part
of
the
state
are
nearly
a
third
of
the
total.
Moreover,
the
maps
of
model­
predicted
contribution
from
southern
Florida
provided
in
the
comments
show
that
southern
Florida
emissions
can
impact
air
quality
across
Fulton
County.
See
PM
Report
at
Figures
4­
1a
(
June)
and
4­
1b
(
August)
showing
that
emissions
from
south
Florida
reach
Atlanta
during
the
summertime
ozone
season.
The
magnitude
and
frequency
of
contribution
from
the
four
states
mentioned
in
the
comment
are
less
than
those
of
Florida,
and
below
the
relevant
metrics,
which
explains
why
these
states
are
not
linked
to
nonattainment
of
the
8­
hour
ozone
NAAQS
in
Fulton
County.

Second,
based
on
the
sheer
geographic
size
of
Florida
(
which
is
larger
than
eight
states
that
EPA
expressly
excluded
from
CAIR),
it
makes
sense
that
a
group
of
sources
in
one
portion
of
Florida
will
have
a
different
impact
from
sources
in
another
portion.

Response:
The
geographic
size
of
a
State
is
not
important,
in
and
of
itself,
as
to
whether
or
not
the
contribution
from
the
State
contributes
significantly.
Rather,
the
amount,
magnitude
and
frequency
of
emissions
in
the
State
are
what
matter.
Indeed,.
as
indicated
on
Table
1­
1
of
the
Ozone
Report
submitted
by
commenters,
there
are
States
that
are
larger
and
smaller
than
south
Florida
which
make
a
significant
contribution
to
downwind
nonattainment
of
ozone.
There
are
also
States
that
are
larger
and
smaller
than
south
Florida
which
were
determined
not
to
so
contribute.
Thus,
the
geographic
size
of
a
State
is
not
the
determinant
factor
in
assessing
significant
contribution.

And
third,
PM2.5
modeling
submitted
by
FAEU
resulted
in
the
same
common­
sense
conclusion
as
the
ozone
modeling:
a
substantial
portion
of
Florida
does
not,
in
fact,
>
contribute
significantly=
to
nonattainment
in
another
state.
[[
(
2295.1,
pp.
4­
5)
]]

Response:
EPA
is
denying
the
petition
to
reconsider
inclusion
of
Florida
in
the
CAIR
PM2.5
region.
This
comment
is
consequently
beyond
the
scope
of
this
proceeding.

As
just
explained,
PM2.5
modeling
data
submitted
by
FAEU
also
demonstrates
which
sources
in
Florida
contribute
significantly
to
PM2.5
nonattainment
in
another
state,
and
which
ones
do
not.
EPA
claims
that
because
the
boundary
FAEU
defined
for
PM2.5
is
slightly
different
than
the
boundary
FAEU
defined
for
ozone,
the
boundaries
are
arbitrary.

Response:
The
fact
that
commenters
suggested
different
boundaries
for
PM
and
ozone
suggests
a
results­
oriented
approach.
In
any
case,
the
southern
portion
of
Florida,
even
under
the
commenter's
definition,
contributes
roughly
a
third
of
the
ozone
that
reaches
Fulton
County.
This
is
a
significant
portion
of
the
total
Florida
contribution
and
confirms
that
EPA's
statewide
collective
contribution
approach
is
reasonable.

EPA=
s
claim
is
flawed
on
numerous
levels.
First,
the
Clean
Air
Act
(
Section
110(
A)(
2)(
D))
sets
the
definition
of
sources
that
can
be
regulated;
FAEU=
s
modeling
simply
demonstrates
where
the
boundary
is
in
Florida.

Result:
Boundary
here
should
be
pluralized,
since
the
commenters
suggested
different
boundaries,
potentially
influenced
by
the
results
of
the
different
line
drawings
for
PM2.5
and
for
ozone.
Second,
EPA=
s
own
modeling
approach
dictates
that
the
lines
for
PM2.5
and
ozone
must
be
different.
As
seen
in
Figure
1
below
(
and
reflected
in
the
PM2.5
and
ozone
modeling
reports
and
other
attachments
in
Section
I),
EPA=
s
grid
cell
layouts
for
PM2.5
and
ozone
are
different.

Response:
A
statewide
approach
based
on
collective
contribution
avoids
these
debates
about
arbitrary
geographic
line
drawing
and
whether
such
divisions
should
be
identical
for
PM
and
ozone
contribution.
This
is
another
reason
the
statewide
approach
is
reasonable.

Third,
EPA=
s
definition
for
a
>
significant=
contribution
is
dramatically
different
between
PM2.5
and
ozone.

Response:
The
commenter
is
correct
that
EPA
uses
different
metrics
to
assess
significance
of
contribution
for
PM2.5
and
for
ozone.

Fourth,
the
PM2.5
and
ozone
ambient
standards
are
based
on
different
values
with
different
averaging
times.

Response:
The
commenter
is
correct
that
the
values
and
averaging
time
differ
for
these
standards.
EPA's
approach,
however,
assesses
contribution
for
each
based
on
the
same
geographic
basis
(
i.
e.
statewide
collective
contribution).

Fifth,
the
modeling
for
PM2.5
is
an
annual
simulation,
whereas
ozone
is
measuring
an
8­
hour
contribution.

Response:
The
commenter
correctly
notes
a
difference,
although
EPA
reiterates
the
overall
reasonableness
of
its
approach.

And
finally,
there
are
different
nonattainment
targets
for
PM2.5
and
ozone,
in
different
locations
and
proximities
to
northern
and
southern
Florida.

Response:
And
EPA
has
assessed
these
potential
links
individually,
and
found
that
Florida
contributes
significantly
to
nonattainment
of
the
8­
hour
ozone
NAAQS
in
the
downwind
receptor
Fulton
County,
Georgia.

EPA
is
well
aware
of
these
factors,
and
its
claim
that
because
FAEU=
s
boundaries
for
PM2.5
and
ozone
are
different,
they
must
be
arbitrary,
is
disingenuous.
In
sum,
despite
specific
requests
during
the
comment
period
on
the
proposed
rule
for
EPA
to
conduct
intrastate
modeling,
EPA
did
not
fulfill
its
obligations
under
the
Clean
Air
Act
to
tailor
CAIR
to
regulate
only
those
sources
that
>
contribute
significantly,=
and
continues
to
refuse
to
utilize
FAEU=
s
data
which
would
allow
for
the
appropriate
tailoring.
[[
(
2295.1,
p.
5)
]]

Response:
See
preamble,
other
responses,
and
EPA's
response
to
motion
for
a
judicial
stay.
Florida
emissions
do
not
>
interfere
with
maintenance=
in
Fulton
County.
As
demonstrated
above,
southern
Florida
does
not
>
contribute
significantly=
to
nonattainment
in
another
state
(
using
EPA=
s
own
approach),
and
EPA
has
implied
that
it
could
still
subject
southern
Florida
to
the
CAIR­
ozone
program
based
on
the
idea
that
this
area
will
interfere
with
Fulton
County=
s
ability
to
maintain
its
attainment
status
(
which
it
will
achieve
without
benefit
from
CAIR).
But
EPA
has
expressly
stated
that
the
same
criteria
apply
to
the
>
interfere
with
maintenance=
prong
as
apply
to
the
>
contribute
significantly=
prong.
And
as
explained
in
Section
2
above,
modeling
data
submitted
by
FAEU
shows
which
portion
of
Florida
meets
this
>
significance=
test.
[[
(
2295.1,
pp.
5­
6)
]]
In
practice,
EPA
does
not
reach
the
>
interfere
with
maintenance=
prong
unless
it
has
already
concluded
that
a
state
contributes
significantly
to
a
nonattainment
target
in
another
state,
and
then
that
target
achieves
attainment.

Response:
This
is
a
correct
summary
of
EPA's
position
on
maintenance,
and
Fulton
County
fits
this
description.
It
is
presently
in
nonattainment
of
the
8­
hour
ozone
NAAQS,
and
is
projected
to
remain
in
nonattainment
in
the
2010
base
case
(
and
CAIR
case
for
that
matter).
70
FR
at
25251
(
Table
VI­
10).
We
demonstrated
in
comment
response
C.
17
to
the
CAIR
Response
to
Comments
(
summarized
in
other
comment
responses
here)
why
further
upwind
NOx
emissions
could
reasonably
be
deemed
to
interfere
significantly
with
Fulton
County's
ability
to
maintain
the
standard
thereafter.

In
Florida,
the
position
is
simply
that
this
same
approach
should
be
applied
to
southern
Florida,
which
does
not
contribute
significantly
to
nonattainment
in
Fulton
County,
and
therefore
there
is
no
basis
to
evaluate
whether
it
will
>
interfere
with
maintenance.=
To
act
otherwise
is
contrary
to
EPA=
s
own
approach,
and
would
be
analogous
to
assessing
an
excluded
state=
s
impact
on
maintenance;
EPA
has
not
made
such
assessments
in
CAIR,
and
there
is
no
reason
to
begin
now.
[[
(
2295.1,
p.
6)
]]

Response:
See
previous
response.

EPA
should
revise
CAIR
to
exclude
the
entire
state
of
Florida
from
the
CAIR
ozone
program
because
Florida=
s
contribution
is
less
than
the
conservative
screening
criteria
developed
by
EPA.
EPA=
s
refusal
to
utilize
the
precise
data
it
developed
for
Florida=
s
average
percent
contribution
to
Fulton
County,
and
instead
put
blinders
on
until
it
arbitrarily
sounds
the
number
to
a
value
above
the
screening
criteria,
is
inappropriate,
inconsistent
with
prior
practice,
arbitrary,
capricious
and
an
abuse
of
discretion.
Nonetheless,
even
if
EPA=
s
approach
is
upheld,
EPA
should
revise
CAIR
to
exclude
southern
Florida
from
the
CAIR­
ozone
program
because
unrefuted
modeling
data
demonstrates
that
southern
Florida
does
not
>
contribute
significantly=
to
nonattainment
or
>
interfere
with
maintenance=
in
another
state.
[[
(
2295.1,
p.
7)
]]

Response:
See
preamble,
previous
comment
responses,
and
EPA's
response
to
motions
for
a
judicial
stay
by
Florida
utilities.

Document
No.:
OAR­
2003­
0053­
2301
Commenter:
Pennsylvania
Department
of
Environmental
Protection
(
PADEP)
Phase:
Reconsideration
Comment:
The
Commonwealth
believes
that
any
state
that
can
contribute
to
the
transport
of
SO2
or
Nox
to
another
state
should
be
included
in
the
CAIR
program.
[[
(
p.
3)
]]

Response:
This
overstates
the
requirements
of
section
110
(
a)
(
2)
(
D),
which
requires
that
the
contribution
be
significant.

Document
No.:
OAR­
2003­
0053­
2268.1
Commenter:
Northeast
States
for
Coordinated
Air
Use
Management
(
NESCAUM)
Phase:
Reconsideration
Notes:
Docket
Number
2268
is
the
cover
letter.
Docket
Number
2268.1
is
the
comment
letter.
Comment:
Fine
particulate
matter
(
PM2.5)
modeling
for
Minnesota
and
including
Florida
in
the
CAIR
region
for
ozone:
EPA
has
asked
for
comment
on
the
inclusion
of
Florida
in
the
CAIR
region
for
ozone
and
on
revised
modeling
inputs
for
Minnesota.
NESCAUM
is
not
commenting
on
those
specific
issues.
However,
EPA
must
include
States
in
the
CAIR
program
for
which
analyses
demonstrate
that
they
contribute
to
non­
attainment
under
section
110(
a)(
2)(
d)
of
the
Clean
Air
Act.
Should
EPA
choose
to
remove
any
jurisdiction
from
the
CAIR
program,
EPA
must
reduce
the
total
Nox
and
SO2
CAIR
budgets
by
amounts
equal
to
that
jurisdictions
Nox
and
SO2
budgets,
respectively.
[[
(
2268.1,
p.
2)
]]
The
NESCAUM
States
cannot
attain
the
eight­
hour
ozone
and
PM2.5
National
Ambient
Air
Quality
Standards
without
substantial
reductions
in
direct
and
transported
emissions
of
Nox
and
SO2
across
the
Eastern
U.
S.
We
urge
EPA
to
ensure
that
the
CAIR
program
maximizes
reductions
of
transported
Nox
and
SO2
to
the
extent
feasible.
[[
(
2268.1,
p.
2)
]]

Response:
Since
no
state
is
being
removed
from
the
CAIR
region,
this
comment
is
moot.

Document
No.:
OAR­
2003­
0053­
2265
Commenter:
Alabama
Department
of
Environmental
Management
(
ADEM)
Phase:
Reconsideration
Comment:
ADEM
is
submitting
comments
on
the
fourth
issue
under
reconsideration
by
EPA.
This
issue
relates
to
the
inclusion
of
the
State
of
Florida
in
the
CAIR
region
for
ozone.
ADEM
believes
that
the
State
of
Florida
should
be
included
in
the
CAIR
region
for
ozone
in
addition
to
fine
particles.
[[
(
p.
1)
]]

Response:
As
should
be
evident,
EPA
agrees.
The
basis
for
the
Florida
petitioners=
argument
for
the
state
of
Florida
to
be
excluded
from
the
CAIR
Region
for
ozone
stems
from
both
the
lack
of
adequate
notice
that
Florida
would
be
found
a
significant
contributor
and
the
lack
of
opportunity
to
comment
on
the
modeling
inputs
that
resulted
in
such
a
determination.
While
it
is
true
that
Florida
was
not
indicated
as
a
significant
contributor
for
ozone
in
the
proposed
rule
or
the
supplemental
proposal,
the
implications
of
the
notice
of
additional
data
availability
were
such
that
the
entire
modeling
platform
changed
(
i.
e.
new
model,
new
meteorology,
updated
emissions,
etc).
The
notice
of
additional
data
availability
documents
were
placed
on
the
docket
on
or
about
July
27,
2004
and
30­
day
comment
period
was
allowed.
Many
of
the
details
from
the
proposed
rules
changed
in
the
final
rule
as
well
(
i.
e.
EGUs
only,
first
phase
of
Nox
begins
in
2009,
compliance
supplement
pool
added
for
annual
Nox).
Current
modeling
indicates
that
Florida
is
a
significant
contributor
to
8­
hour
ozone
in
Fulton
County,
Georgia.
Florida=
s
contribution
is
more
significant
than
three
other
states
(
West
Virginia,
Virginia,
and
Mississippi).
[[
(
p.
1)
]]

Response:
EPA
agrees
that
it
was
a
close
question
whether
to
grant
the
petition
for
inclusion
of
Florida
in
the
CAIR
ozone
region.
EPA
has
done
so,
however.
On
the
merits,
we
agree
with
the
commenter
that
inclusion
of
the
entire
state
in
the
CAIR
ozone
region
is
appropriate.

Also,
the
CAIR
ozone
season
trading
system
would
be
made
less
robust
by
the
exclusion
of
Florida.
Without
an
emissions
cap,
Florida
sources
that
would
be
subject
to
the
CAIR
for
ozone
would
not
be
required
to
purchase
allowances
if
CAIR
emissions
levels
are
exceeded.
Even
if
Nox
emissions
from
Florida
sources
that
would
be
subject
to
CAIR
do
not
significantly
contribute
to
downwind
ozone
nonattainment,
these
Nox
emissions
would
not
be
subject
to
an
emissions
cap
as
is
the
case
for
sources
located
in
neighboring
states
that
are
subject
to
CAIR.

The
lack
of
an
emissions
cap
on
Florida
sources
that
would
be
subject
to
CAIR
for
ozone
may
impede
the
ability
of
neighboring
states
to
meet
and
maintain
the
8­
hour
ozone
NAAQS.
[[
(
p.
1)
]]

Response:
Florida
can
only
be
included
in
the
CAIR
ozone
region
if
its
emission
contribute
significantly
to
nonattainment
in
a
downwind
area,
or
interfere
significantly
with
a
downwind
area's
maintenance
of
a
NAAQS.
These
are
the
only
grounds
EPA
has
considered
in
making
its
decision.

Document
No.:
OAR­
2003­
0053­
2296
Commenter:
Florida
Association
of
Electric
Utilities
(
FAEU)
Phase:
Reconsideration
Notes:
The
Reconsideration
comment
letter
is
part
of
docket
number
2296,
pp.
1­
9.
Attachment
1:
Petition
for
Reconsideration
(
July
11,
2005).
See
docket
number
2296.
Attachment
2:
Supplement
to
Petition
for
Reconsideration,
attaching
Florida­
specific
PM
2.5
modeling
data
(
October
11,
2005).
See
docket
number
2296.
Attachment
3
:
Second
Supplement
to
Petition
for
Reconsideration,
attaching
Florida­
specific
ozone
modeling
data
(
October
18,
2005).
See
docket
number
2296.
Attachment
4:
Motion
for
Stay
Pending
Judicial
Review,
filed
in
the
D
.
C.
Circuit
(
August
18,
2005).
See
docket
numbers
2296­
2298.
Attachment
5
:
Reply
to
Responses
in
Opposition
to
Motion
for
Stay
Pending
Judicial
Review,
filed
in
the
D
.
C.
Circuit
(
December
2,
2005).
See
docket
number
2298.
Attachment
6:
Transcript
of
Testimony
of
Robert
Manning,
on
behalf
of
FAEU,
at
public
hearing
on
Reconsideration
(
December
14,
2005).
See
docket
number
2298.
Comment:
FAEU
is
focusing
its
comments
on
.
.
.
the
inclusion
of
Florida
in
the
CAIR­
ozone
program.
70
Fed.
Reg.
72280.
[[
p.
1]].
FAEU
appreciates
this
opportunity
to
comment
on
the
inclusion
of
Florida
in
the
CAIR­
ozone
program,
given
that
Florida
was
expressly
excluded
from
the
CAIR
ozone
program
until
the
final
rule
was
published
on
May
12,
2005,
and
reiterates
its
request
that
EPA
re­
open
for
comment
the
other
issues
raised
in
FAEU=
s
Petition
for
Reconsideration.
[[
p.
1]]

Response:
EPA
is
denying
these
requests
by
separate
action.

II.
How
can
EPA
justify
including
the
entire
state
of
Florida
in
the
CAIR­
ozone
program
when
EPA=
s
own
data
shows
that
Florida=
s
contribution
is
less
than
EPA=
s
conservative
screening
criteria
for
>
average
percent
contribution=?
[[
p.
2]]
a)
EPA
should
use
the
precise
data
that
it
generated.
[[
p.
2]]
[[
See
docket
number
2296,
p.
2
for
further
discussion
of
this
issue.]]

Response:
See
preamble
and
other
comment
responses,
especially
responses
to
the
Tampa
Electric
comment,
which
largely
tracks
the
comments
of
FAEU.

b)
EPA=
s
rounding
approach
is
arbitrary,
capricious
and
inconsistent
with
its
own
guidance.
[[
p.
2]]
[[
See
docket
number
2296,
pp.
2­
4
for
further
discussion
of
this
issue.]]

Response:
See
previous
response.

c)
Additional
policy
and
scientific
reasons
that
justify
excluding
Florida.
To
add
to
and
amplify
some
of
the
additional
reasons
supporting
Florida=
s
exclusion
from
the
CAIR­
ozone
program,
as
presented
in
the
attachments
listed
in
Section
I,
[[
see
docket
number
2296,
p.
2
for
list
of
attachments.]]
FAEU
offers
the
following
[[
p.
4]]
[[
See
docket
number
2296,
pp.
4­
5
for
further
discussion
of
this
issue]]

Response:
See
previous
response.

III.
How
can
EPA
justify
subjecting
sources
in
southern
Florida
to
the
CAIR­
ozone
program
when
there
is
unrefuted
data
showing
that
these
sources
do
not
>
contribute
significantly=
to
nonattainment
in
another
state?
[[
p.
5]]
[[
See
docket
number
2296,
pp.
5­
7
for
further
discussion
of
this
issue.
Also
see
Figure
1
on
p.
8.]]
Response:
As
explained
in
the
preamble
and
other
comment
responses,
statewide
collective
contributions
contribute
significantly
to
ozone
nonattainment
in
Fulton
County,
Georgia.
EPA
thus
disagrees
that
`
unrefuted
evidence'
shows
a
lack
of
contribution.

IV.
How
can
EPA
be
concerned
that
southern
Florida
may
>
interfere
with
maintenance=
in
Fulton
County,
when
it
uses
the
same
threshold
as
for
the
>
contribute
significantly=
prong,
and
the
unrefuted
data
shows
that
southern
Florida
does
not
>
contribute
significantly=?
[[
p.
7]]
[[
See
docket
number
2296,
p.
7
for
further
discussion
of
this
issue.]]

Response:
See
previous
responses.

V.
ConclusionEPA
should
revise
CAIR
to
exclude
the
entire
state
of
Florida
from
the
CAIRozone
program
because
Florida=
s
contribution
is
less
than
the
conservative
screening
criteria
developed
by
EPA.
EPA=
s
refusal
to
utilize
the
precise
data
it
developed
for
Florida=
s
average
percent
contribution
to
Fulton
County,
and
instead
arbitrarily
round
it
to
a
value
greater
than
the
screening
criteria,
is
inappropriate,
inconsistent
with
prior
practice,
arbitrary,
capricious
and
an
abuse
of
discretion.
Nonetheless,
if
EPA=
s
approach
is
upheld,
EPA
should
revise
CAIR
to
exclude
southern
Florida
from
the
CAIR­
ozone
program
because
unrefuted
modeling
data
demonstrates
that
southern
Florida
does
not
>
contribute
significantly=
to
nonattainment
or
>
interfere
with
maintenance=
in
another
state.
[[
p.
9]]

Response:
See
preamble
and
other
comment
responses.

Document
No.:
OAR­
2003­
0053­
2299
Commenter:
Gulf
Power
Company
Phase:
Reconsideration
Comment:
Gulf
Power
is
focusing
its
comments
on
.
.
.
the
inclusion
of
Florida
in
the
CAIR­
ozone
program.
70
Fed.
Reg.
72280.
[[
p.
1]]
.
I.
The
Entire
State
of
Florida
Should
be
excluded
from
the
CAIRozone
Program.
A)
EPA
should
use
the
precise
data
that
it
generated.
[[
p.
1]]
[[
See
docket
number
2299,
pp.
1­
2
for
further
discussion
of
this
issue.]]

Response:
See
preamble
and
other
comment
responses.

b)
EPA=
s
rounding
approach
is
arbitrary,
capricious
and
inconsistent
with
its
own
guidance.
[[
p.
2]]
[[
See
docket
number
2299,
pp.
2­
3
for
further
discussion
of
this
issue.]]

Response;
See
preamble
and
other
comment
responses.

c)
Additional
policy
and
scientific
reasons
that
justify
excluding
Florida.
There
are
many
additional
policy
and
scientific
factors
that
support
Florida=
s
exclusion
from
the
CAIR­
ozone
program
[[
p.
3]]
[[
See
docket
number
2299,
pp.
3­
4
for
discussion
of
the
factors.]
Response:
EPA
disagrees
for
reasons
given
in
the
preamble
and
in
other
comment
responses.

]
II.
Even
if
some
portion
of
Florida
should
be
included
in
the
CAIR­
ozone
program,
a
substantial
portion
of
southern
Florida
should
be
excluded.
[[
p.
4]]
[[
See
docket
number
2299,
pp.
4­
5
for
further
discussion
of
this
issue.]]

Response:
See
preamble
and
other
comment
responses.

III.
Florida
emissions
do
not
>
interfere
with
maintenance=
in
Fulton
County.
[[
p.
5]]
[[
See
docket
number
2299
for
further
discussion
of
this
issue.]]

Response:
See
other
comment
responses.

IV.
Conclusion
EPA
should
revise
CAIR
to
exclude
the
entire
state
of
Florida
from
the
CAIR
ozone
program
because
Florida=
s
contribution
is
less
than
the
conservative
screening
criteria
developed
by
EPA.
EPA=
s
refusal
to
utilize
the
precise
data
it
developed
for
Florida=
s
average
percent
contribution
to
Fulton
County,
and
instead
put
blinders
on
until
it
arbitrarily
sounds
the
number
to
a
value
above
the
screening
criteria,
is
inappropriate,
inconsistent
with
prior
practice,
arbitrary,
capricious
and
an
abuse
of
discretion.
Nonetheless,
even
if
EPA=
s
approach
is
upheld,
EPA
should
revise
CAIR
to
exclude
southern
Florida
from
the
CAIR­
ozone
program
because
unrefuted
modeling
data
demonstrates
that
southern
Florida
does
not
>
contribute
significantly=
to
nonattainment
or
>
interfere
with
maintenance=
in
another
state.
[[
p.
6]]

Response:
See
preamble
and
other
comment
responses.

XXII.
B.
 
EPA
did
not
properly
analyze
the
potential
impacts
on
SO3
/
H2SO4
emissions
Document
No.:
OAR­
2003­
0053­
2305.1
Commenter:
Utility
Air
Regulatory
Group
(
UARG)
Comment:
"
In
the
reconsideration
notice,
EPA
also
examines
the
potential
impact
of
the
vacatur
of
the
PCP
exclusion
on
the
compliance
deadlines
in
CAIR.
In
its
re­
analysis
of
the
CAIR
deadlines,
EPA
assumes,
as
it
did
in
its
cost­
effectiveness
re­
analysis,
that
EGUs
would
install
wet
ESPs
to
prevent
collateral
significant
emission
increases
in
sulfuric
acid
mist
from
CAIR
PCPs.
[ ]
UARG
believes
that
this
assumption
is
wrong.
Rather
than
choosing
to
install
wet
ESPs
to
prevent
those
emission
increases,
EGUs
would
choose
to
obtain
a
PSD
permit
that
reflects
a
determination
that
BACT
for
sulfuric
acid
mist
emissions
is
no
additional
control
(
or,
at
most,
something
far
less
costly
than
wet
ESP
or
injection
technology)."

Response:
As
mentioned
in
the
CAIR
Supplemental
Notice
of
Reconsideration,
EPA
made
the
conservative
assumptions
that
all
EGUs
that
will
install
SCR
and/
or
wet
FGD
will
experience
a
significant
emissions
increase
in
sulfuric
acid
mist
and
that
all
of
those
EGUs
will
install
a
wet
ESP
to
mitigate
those
emissions.
The
Agency
agrees
with
UARG
that
these
assumptions
lead
to
an
overestimate
of
the
cost
of
the
decision
in
New
York
v.
EPA,
since
the
number
of
EGUs
with
collateral
increases
in
sulfuric
acid
mist
will
be
much
fewer
than
the
universe
assumed
in
EPA's
analysis
and
that
the
BACT
determination
in
those
cases
with
significant
increases
in
sulfuric
acid
mist
may
not
involve
the
installation
of
wet
ESP
due
to
its
high
cost.
As
mentioned
in
the
CAIR
Supplemental
Notice
of
Reconsideration,
historically,
the
BACT
for
affected
units
has
generally
involved
switching
to
lower
sulfur
coal,
installation
of
wet
FGD,
or
no
additional
controls.

Document
No.:
OAR­
2003­
0053­
2305.1
Commenter:
Utility
Air
Regulatory
Group
(
UARG)
Comment:
UARG
believes
that
the
coal
switching
included
in
EPA's
analysis
"
typically
would
not
be
considered
in
calculating
collateral
emission
increases,
due
to
application
of
the
fuel
switching
exclusion
in
the
definition
of
>
major
modification.=
Specifically,
a
>
major
modification=
does
not
include
physical
changes
or
changes
in
the
method
of
operation
that
involve
the
use
of
an
alternative
fuel
which
the
source
was
capable
of
accommodating
before
January
6,
1975
(
unless
prohibited
by
an
NSR
permit
condition).
See
40
C.
F.
R.
'
52.21(
b)(
2)
iii)(
e)(
1)."

"
Although
wet
FGD
will
remove
some
sulfuric
acid
mist,
UARG
believes
that,
for
EGUs
over
about
350
MW
that
burn
coal
with
sulfur
content
at
or
above
2%,
wet
FGD
typically
will
not
reduce
the
SCR­
caused
sulfuric
acid
mist
emission
increase
to
below
the
7
tons­
per­
year
significance
level.
Thus,
for
the
control
technology
category
consisting
of
the
installation
of
SCR
and
wet
FGD
without
a
switch
to
higher
sulfur
coal,
EPA
may
have
underestimated
the
amount
of
EGU
capacity
that
would
experience
a
collateral
significant
emissions
increase
in
sulfuric
acid
mist
under
the
NSR
regulations."

"
EPA
makes
two
unrealistically
conservative
assumptions
in
its
analysis.
First,
rather
than
using
its
estimate
of
the
amount
of
EGU
capacity
that
might
experience
a
collateral
significant
emission
increase
in
sulfuric
acid
mist
as
a
result
of
CAIR
PCPs,
EPA
assumes
that
all
EGUs
that
will
install
SCR
and/
or
wet
FGD
will
experience
a
significant
emissions
increase
in
sulfuric
acid
mist.
Second,
EPA
assumes
that
all
of
those
EGUs
will
install
a
wet
ESP
to
>
mitigate=
(
prevent)
that
collateral
significant
emissions
increase.
Id.
At
77106.
UARG
has
major
concerns
with
these
assumptions."

Response:
These
issues
are
addressed
in
the
CAIR
Notice
of
Final
Action
on
Reconsideration,
Section
III.
E.

XXII.
C.
 
EPA
did
not
properly
analyze
the
potential
impacts
on
PM
emissions
Document
No.:
OAR­
2003­
0053­
2305.1
Commenter:
Utility
Air
Regulatory
Group
(
UARG)
Comment:
"
UARG
also
reiterates
its
comment,
made
recently
in
its
rulemaking
comments
on
EPA=
s
proposed
rules
for
implementation
of
the
PM­
2.5
national
ambient
air
quality
standards,
that
condensable
particulate
matter
(
including
sulfuric
acid
mist)
should
not
be
regulated
as
a
component
of
particulate
matter
under
the
NSR
program
until
EPA
develops
and
adequately
justifies
a
reliable
source
test
method
for
condensables.
[ ]
In
its
comments
on
the
proposed
PM­
2.5
implementation
rule,
UARG
urges
that
condensable
particulate
matter
not
be
regulated
under
either
the
SIP
or
NSR
programs
at
this
time.
The
reason
is
that
no
reliable,
accurate
source
test
method
exists
for
measuring
condensable
particulate
matter.
See
Comments
of
the
Utility
Air
Regulatory
Group
on
EPA=
s
Proposed
Rule
to
Implement
the
Fine
Particle
National
Ambient
Air
Quality
Standards
(
EPA
Document
No.
EPA­
HQ­
OAR­
2003­
0062­
0120.1),
at
13­
21
(
January
31,
2006),
incorporated
herein
by
reference.
See
also
Comments
of
the
PM
Group
on
the
Proposed
Rule
to
Implement
the
Fine
Particle
National
Ambient
Air
Quality
Standards
(
EPA
Document
No.
EPA­
HQ­
OAR­
2003­
0062­
0096.1),
at
39­
48
(
January
31,
2006)
(
also
incorporated
herein
by
reference)."

Response:
The
EPA
is
not
taking
action
to
change
the
manner
in
which
the
Agency
treats
condensable
emissions
and
there
is
no
final
action
on
this
issue
in
the
CAIR
Supplemental
Notice
of
Reconsideration
or
CAIR
Notice
of
Final
Action
on
Reconsideration.
The
status
of
condensable
emissions
as
a
regulated
NSR
pollutant
does
not
change
the
outcome
of
the
Agency
analysis
for
those
reconsideration
notices.
Contrary
to
the
commenter's
assertions,
the
Agency
has
long
defined
particulate
matter
to
include
the
condensable
fraction
of
particulate
emissions
(
See
70
FR
66039,
Memo
from
Thompson
G.
Pace,
Acting
Chief,
Particulate
Matter
Programs
Branch,
to
Sean
Fitzsimmons,
Iowa
Department
of
Natural
Resources,
(
Mar.
31,
1994)
http://
www.
epa.
gov/
region07/
programs/
artd/
air/
nsr/
nsrmemos/
cpm.
pdf,
56
FR
65432,
and
55
FR
41547).

XXII.
D.
 
EPA
did
not
properly
analyze
the
potential
impacts
on
CO
emissions
Document
No.:
OAR­
2003­
0053­
2306.1
Commenter:
Michigan
Department
of
Environmental
Quality,
Air
Quality
Division
Comment:
"
The
MDEQ
has
issued
several
LNB
permits
under
the
PCP
exemption
for
a
collateral
increase
in
CO
that
exceeded
the
NSR
significance
level
of
100
tons
per
year.
Each
LNB
project
was
able
to
prove
that
the
reduction
in
NOx
(
approximately
50
percent)
resulted
in
an
environmental
benefit
that
significantly
outweighed
the
environmental
detriment
of
an
increase
in
CO.
In
each
case,
dispersion
modeling
showed
a
negligible
impact
in
the
1­
hour
and
8­
hour
National
Ambient
Air
Quality
Standards
(
NAAQS)
for
CO.
Therefore,
each
LNB
installation
was
considered
a
PCP
and
exempt
from
complex
NSR
requirements.
Since
the
June
24,
2005,
decision
to
vacate
the
PCP
provisions,
the
MDEQ
has
reviewed
four
permits
regarding
LNB
installations
that
were
subject
to
NSR
regulations
for
the
collateral
increase
in
CO.
Three
of
these
permits
were
previously
issued
and
one
is
pending
the
resolution
of
comments
received
from
EPA
Region
5.
In
each
case,
the
permit
applicant
was
required
to
submit
a
Best
Available
Control
Technology
(
BACT)
analysis
for
CO.
BACT
was
determined
to
be
good
combustion
practices.
The
MDEQ
agrees
with
EPA=
s
statement
that
there
will
be
no
additional
costs
for
using
good
combustion
practices
to
mitigate
CO
emissions
since
the
industry
uses
such
practices
already.
However,
it
is
our
experience
that
requiring
NSR
for
a
collateral
increase
in
CO
could
have
substantial
financial
implications.
The
MDEQ
believes
that
a
specific
BACT
limit
for
CO
is
not
necessary
for
LNB
projects.
[ ]
The
MDEQ
believes
that
a
specific
CO
limit
is
not
appropriate
because
there
is
no
economically
reasonable
way
to
measure
the
emissions.
[ ]
Compliance
with
a
CO
limit
using
the
more
traditional
methods
of
stack­
testing
or
a
continuous
emission
monitoring
system
(
CEMS)
has
technological
and
economical
limitations."

Response:
While
EPA
believes
that
installing
combustion
control
systems
can
lead
to
collateral
increases
in
CO,
generally
LNB
will
not
significantly
affect
the
combustion
process.
It
is
the
Agency's
position
that
increases
in
CO
can
be
minimized
through
adjustments
of
combustion
control
systems
(
e.
g.,
good
combustion
practices),
and
there
are
no
other
cost­
effective
control
options
for
reducing
CO
(
See,
for
example,
permit
DAQE­
AN2529001­
04).
Other
issues
raised
by
this
commenter
fall
beyond
the
scope
of
this
reconsideration
topic,
and
we
will
not
address
them
in
this
forum.

XXII.
E.
 
EPA
did
not
properly
analyze
the
potential
impacts
on
boilermaker
labor
[
There
are
no
comments
in
this
section.]

XXII.
F.
 
EPA
did
not
properly
analyze
the
potential
impacts
on
EPA
=

s
highly
costeffective
determination
Document
No.:
OAR­
2003­
0053­
2304.1
Commenter:
Clean
Air
Task
Force,
et.
al.
Comment:
"
While
not
endorsing
all
of
EPA=
s
analysis,
Clean
Air
Task
Force
et
al.
strongly
concur
in
the
conclusion
that
the
vacatur
of
the
PCP
exemption
does
not
warrant
any
relaxation
of
emission
reduction
requirements,
that
currently
applicable
requirements
remain
highly
cost­
effective,
and
that
applicability
of
NSR
will
not
pose
a
problem.
Having
reviewed
industry's
complaints
about
alleged
negative
interactions
between
vacatur
of
the
PCP
exclusion
and
the
agency's
CAIR
determinations,
it
is
revealing
that
industry
does
not
substantiate
those
complaints
with
any
evidence.
Specifically,
industry
does
not
identify
which
collateral
pollution
increases
it
would
experience
from
installing
pollution
control
devices
to
meet
CAIR
obligations;
which
specific
pollution
control
devices
would
lead
to
this
circumstance;
and
why
it
would
alter
the
highly
cost
effective
control
determination
made
in
CAIR.
Raw
assertion
and
speculation
provide
no
basis
to
reconsider
CAIR
or
alter
its
terms.
Finally,
the
PCP
exclusion
never
took
effect
in
any
SIP­
approved
jurisdiction
prior
to
its
vacatur,
and
was
never
relied
upon
in
any
delegated
program
prior
to
the
New
York
v.
EPA
ruling;
accordingly,
industry
cannot
have
logically
or
legitimately
relied
upon
the
exclusion
in
planning
its
distant
CAIR
compliance
strategy."

Response:
The
Clean
Air
Task
Force
et
al.,
which
otherwise
agrees
with
EPA's
conclusion,
makes
two
points
that
EPA
would
like
to
address
here.
First,
this
commenter
does
not
endorse
all
of
EPA's
analysis,
but,
as
no
details
were
provided,
EPA
cannot
respond.
Second,
this
commenter
suggests
that
"
the
PCP
exclusion
never
took
effect
in
any
SIP­
approved
jurisdiction
prior
to
its
vacatur."
The
EPA
would
like
to
note
that
PCP
exclusions
have
been
relied
upon
several
times
in
the
past,
although
the
PCP
exclusion
that
was
in
the
2002
NSR
rules
was
never
in
effect
in
SIP­
approved
programs
as
it
was
finalized
in
the
rules
because
it
was
challenged
before
it
could
be
adopted
into
any
SIP.

XXII.
G.
 
EPA
did
not
properly
estimate
cost
of
SO3/
H2SO4
mitigation
[
There
are
no
comments
in
this
section.]

XXII.
H.
 
EPA
did
not
properly
analyze
the
potential
impacts
of
NSR
permitting
Document
No.:
OAR­
2003­
0053­
2305.1
Commenter:
Utility
Air
Regulatory
Group
(
UARG)
Comment:
"
EPA
examines
the
potential
effect
of
such
NSR
permitting
on
the
CAIR
compliance
deadlines.
EPA
concludes
that
any
such
permitting
would
not
prevent
EGUs
from
meeting
those
deadlines.
Id.
At
77111,
col.
2.
Although
UARG
believes
that
NSR
permitting
could,
in
some
situations,
delay
CAIR
PCPs
that
cause
collateral
significant
emission
increases
in
sulfuric
acid
mist,
UARG
agrees
with
EPA
that
these
delays
should
not
prevent
compliance
with
the
CAIR
deadlines
­­
but
only
if,
as
UARG
discusses
above,
(
1)
BACT
analyses
for
sulfuric
acid
mist
do
not
result
in
requirements
to
install
costly
additional
control
technology,
and
(
2)
sulfuric
acid
mist
is
not
regulated
as
a
component
of
particulate
matter
under
the
nonattainment
NSR
program.
To
help
assure
this
outcome,
EPA
should
issue
guidance
to
the
states
that
explains
that
EPA
expects
BACT
for
any
sulfuric
acid
mist
emission
increases
associated
with
CAIR­
related
PCPs
at
EGUs
to
be
no
additional
controls.
With
such
guidance,
the
delays
that
might
be
caused
by
NSR
permitting
of
CAIR
PCPs
should
be
minimal,
because
EGUs
and
the
regulators
would
be
on
notice,
from
the
outset,
that
EPA
would
accept
a
states
conclusion
that
BACT
for
sulfuric
acid
mist
emission
increases
caused
by
such
PCPs
is
no
additional
control.
Absent
such
guidance,
lengthy
battles
about
BACT
could
arise
­­
and
if
they
do,
lengthy
delays
in
permitting
PCPs
would
occur,
making
compliance
with
the
Phase
I
CAIR
deadlines
difficult,
if
not
impossible,
for
affected
utilities."

Response:
These
issues
are
addressed
in
the
CAIR
Notice
of
Final
Action
on
Reconsideration,
Section
III.
E,
and
in
response
to
comment
XXII.
C.
1.

XXII.
I.
 
General
Document
No.:
OAR­
2003­
0053­
2303.1
Commenter:
Northern
Indiana
Public
Service
Utility
(
NIPSCO)
Comment:
"
USEPA
concluded
that
only
a
minimal
number
of
CAIR
compliance
PCPs
potentially
could
result
in
an
increase
of
specific
air
pollutant
emissions
above
the
NSR
threshold,
and
NSR
for
many
of
those
could
be
avoided
through
mitigation.
Based
upon
USEPA=
s
discussion
in
the
Reconsideration
Decision,
NIPSCO
understands
that
only
those
analyses
performed
by
USEPA
and
described
in
the
Reconsideration
Decision
are
needed
to
asses
(
sic)
whether
a
PCP
undertaken
for
CAIR
compliance
would
increase
emissions
of
any
NSR
regulated
pollutant
in
an
amount
that
exceeds
the
applicable
NSR
significance
level.
If
there
are
other
methods
or
means
by
which
USEPA
believes
a
PCP
performed
for
CAIR
compliance
would
trigger
NSR,
or
if,
using
USEPA
emission
increase
methodologies,
USEPA
believes
or
would
find
that
other
air
pollutant
emissions
would
increase
above
an
applicable
NSR
significance
level
as
a
result
of
PCPs
that
are
expected
to
be
performed
for
CAIR
compliance,
then
the
Reconsideration
Decision
is
deficient.
[ ]
Based
upon
the
Reconsideration
Decision,
NIPSCO
understands
that
PCPs
performed
for
CAIR
compliance
are
expected
by
USEPA
to
trigger
NSR
only
in
those
very
limited
instances
identified
by
USEPA
in
the
Reconsideration
Decision.
To
the
extent
USEPA
would
expect
that
PCPs
performed
in
the
future
for
CAIR
compliance
may
otherwise
significantly
increase
collateral
pollutant
emissions
and
trigger
NSR,
the
Reconsideration
Decision
is
incomplete
and
deficient."

Response:
The
analysis
presented
in
the
CAIR
Supplemental
Notice
of
Reconsideration
addresses
only
those
general
categories
of
projects
that
would
have
qualified
as
PCPs
under
the
NSR
rules
vacated
by
the
court
and
that
we
believe
have
the
potential
to
increase
collateral
emissions
of
NSR
regulated
pollutants
enough
to
trigger
NSR.
It
is
not
our
intent,
nor
is
it
within
the
scope
of
our
analysis,
to
consider
at
this
time
what
permitting
requirements
might
apply
to
all
categories
of
pollution
control
activities
(
including
those
that
were
not
listed
as
PCPs
under
the
NSR
rules)
that
might
be
undertaken
by
EGUs
attempting
to
comply
with
the
CAIR
requirements.
The
analysis
was
conducted
to
determine
whether
the
elimination
of
the
PCP
exemption
would
impact
the
cost­
effectiveness
and
timing
analyses
for
the
CAIR.
Potential
permitting
requirements
for
categories
of
activities
that
would
not
have
been
subject
to
that
exemption
are
not
relevant
to
that
analysis.
The
analysis
addresses
all
relevant
categories
of
PCPs
of
which
EPA
is
currently
aware.
The
commenter
failed
to
identify
any
other
relevant
categories
of
PCPs.
Moreover,
in
addressing
the
relevant
general
categories
of
PCPs,
EPA
does
not
purport
to
make
determinations
about
whether
NSR
would
be
triggered
in
any
specific
PCPs
undertaken
to
comply
with
the
CAIR,
EPA
will
consider,
and
make
determinations
based
on,
the
specific
circumstances
of
those
projects.

Document
No.:
OAR­
2003­
0053­
2305.1
Commenter:
Utility
Air
Regulatory
Group
(
UARG)
Comment:
"
UARG
has
concerns
with
several
aspects
of
EPA's
analysis,
especially
the
overly
conservative
assumptions
on
which
EPA
relied
in
reaching
its
conclusion.
For
the
reasons
discussed
below,
UARG
requests
that
EPA,
in
its
final
decision,
emphasize
the
conservatism
of
these
assumptions,
and
explain
the
implications
that
these
assumptions
may
have
for
NSR
decisions
that
involve
PCPs."

Response:
The
EPA
believes
it
has
adequately
highlighted
the
conservative
nature
of
its
assumptions
in
the
CAIR
Supplemental
Notice
of
Reconsideration
and
CAIR
Notice
of
Final
Action
on
Reconsideration
regarding
its
analysis
of
the
impact
on
CAIR
analyses
of
D.
C.
Circuit
Decision
in
New
York
v.
EPA.

XXII.
J.
 
Comments
incorporated
by
reference
[
There
are
no
comments
in
this
section.]

XXIII.
Comments
Outside
Scope
of
the
Proposal
­
CAIR
Reconsideration
and
Supplemental
Reconsideration
Document
No.:
OAR­
2003­
0053­
2262
Commenter:
Citizen
Phase:
Reconsideration
Comment:
I
find
this
proposal
to
be
woefully
inadequate
and
a
waste
of
taxpayer
money.
The
average
annual
fine
particulate
matter
limit
must
be
reduced
for
there
to
be
any
significant
change
in
air
quality.
To
reject
the
EPA
Scientists=
own
recommendations
based
on
the
opinion
of
one
political
appointee
is
an
insult
to
Americans
and
puts
the
health
of
many
people
unnecessarily
at
risk.
[[
(
p.
1)
]]

Response:
This
comment
is
not
related
to
any
of
the
issues
on
which
EPA
has
granted
reconsideration
of
the
CAIR.
Thus,
no
response
is
required.
The
comment
also
is
not
related
in
any
way
to
the
CAIR
itself.
In
the
CAIR,
EPA
found
that
28
states
and
the
District
of
Columbia
contribute
significantly
to
nonattainment
of,
and
interfere
with
maintenance
by
downwind
States
with
respect
to
the
NAAQS
for
find
particles
(
PM2.5)
and/
or
8hour
ozone.
The
CAIR
requires
these
upwind
States
to
revise
their
State
implementation
plans
(
SIPs)
to
include
control
measures
to
reduce
emissions
of
SO2
and/
or
NOx.
The
CAIR
does
not
establish
or
alter
the
fine
particulate
limit.

Document
No.:
OAR­
2003­
0053­
2242
Commenter:
Citizen
Phase:
Reconsideration
Comment:
According
to
the
American
Lung
Association,
about
60,000
Americans
die
prematurely
each
year
because
of
air
pollution.
More
than
2,000
studies
have
shown
links
between
fine
particles
and
a
host
of
illnesses.
As
noted
by
John
L.
Kirkwood,
president
of
the
American
Lung
Association,
>
There
is
no
excuse
to
set
the
new
standards
at
levels
that
still
do
not
meet
the
basic
legal
requirement
outlined
in
the
Clean
Air
Act,
to
protect
the
lives
and
health
of
the
public.=
Please
follow
the
scientific
advisory
boards
proposal
to
lower
particulate
matter
standards
to
13
or
14
micrograms
per
cubic
meter,
and
setting
daily
exposure
level
to
between
30
and
35
micrograms.
This
will
likely
reduce
air
pollution­
related
deaths
in
nine
U.
S.
cities
by
48
percent
­
more
than
double
the
lives
saved
by
the
current
proposal.
[[
(
p.
1)
]]

Response:
This
comment
is
not
related
to
any
of
the
issues
on
which
EPA
has
granted
reconsideration
of
the
CAIR.
Thus,
no
response
is
required.
The
comment
also
is
not
related
in
any
way
to
the
CAIR
itself.
In
the
CAIR,
EPA
found
that
28
states
and
the
District
of
Columbia
contribute
significantly
to
nonattainment
of,
and
interfere
with
maintenance
by
downwind
States
with
respect
to
the
NAAQS
for
find
particles
(
PM2.5)
and/
or
8hour
ozone.
The
CAIR
requires
these
upwind
States
to
revise
their
State
implementation
plans
(
SIPs)
to
include
control
measures
to
reduce
emissions
of
SO2
and/
or
NOx.
The
CAIR
does
not
establish
or
alter
the
fine
particulate
limit.