5
1
An
exception
was
made
to
the
run
year
mapping
for
an
IPM
sensitivity
run
that
examined
the
impact
of
a
NOx
Compliance
Supplement
Pool
(
CSP).
In
that
run
the
years
2009
through
2012
were
mapped
to
2010
and
2008
was
mapped
to
2008.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
assumptions
on
performance
of
NOx
combustion
controls;
updated
title
IV
SO2
bank
assumptions;
updated
heat
rates
and
SO2
and
NOx
emission
rates;
and,
updated
repowering
costs.

The
National
Electric
Energy
Data
System
(
NEEDS)
contains
the
generation
unit
records
used
to
construct
model
plants
that
represent
existing
and
planned/
committed
units
in
EPA
modeling
applications
of
IPM.
The
NEEDS
includes
basic
geographic,

operating,
air
emissions,
and
other
data
on
all
the
generation
units
that
are
represented
by
model
plants
in
EPA's
v.
2.1.9
update
of
IPM.

The
IPM
uses
model
run
years
to
represent
the
full
planning
horizon
being
modeled.
That
is,
several
years
in
the
planning
horizon
are
mapped
into
a
representative
model
run
year,
enabling
IPM
to
perform
multiple
year
analyses
while
keeping
the
model
size
manageable.
Although
IPM
reports
results
only
for
model
run
years,
it
takes
into
account
the
costs
in
all
years
in
the
planning
horizon.
In
EPA's
v.
2.1.9
update
of
IPM,
the
years
2008
through
2012
are
mapped
to
run
year
2010,
and
the
years
2013
through
2017
are
mapped
to
run
year
2015.1
Model
outputs
for
2009
and
2010
are
from
the
2010
run
year.
Model
outputs
for
2015
are
from
the
2015
run
year.
6
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
The
EPA
used
IPM
to
conduct
the
cost
effectiveness
analysis
for
the
emissions
control
program
required
by
today's
action.

The
model
was
used
to
project
the
incremental
electric
generation
production
costs
that
result
from
the
CAIR
program.
These
estimates
are
used
as
the
basis
for
EPA's
estimate
of
average
cost
and
marginal
cost
of
emissions
reduction
on
a
per
ton
basis.

The
model
was
also
used
to
project
the
marginal
cost
of
several
State
programs
that
EPA
considers
as
part
of
its
base
case.

In
modeling
CAIR
with
IPM,
EPA
assumes
interstate
emissions
trading.
While
EPA
is
not
requiring
States
to
participate
in
an
interstate
trading
program
for
EGUs,
we
believe
it
is
reasonable
to
evaluate
control
costs
assuming
States
choose
to
participate
in
such
a
program
since
that
will
result
in
less
expensive
reductions.
The
EPA's
IPM
analyses
for
CAIR
includes
all
fossil
fuel
fired
EGUs
with
generating
capacity
greater
than
25
MW.

EPA's
IPM
modeling
accounts
for
the
use
of
the
existing
title
IV
bank
of
SO2
allowances.
The
projected
EGU
SO2
emissions
in
2010
and
2015
are
above
the
cap
levels,
because
of
the
use
of
the
title
IV
bank.
The
annual
SO2
emission
reductions
that
are
achieved
in
2010
and
2015
are
based
on
the
caps
that
EPA
determined
to
be
highly
cost­
effective,
including
the
existence
of
the
title
IV
bank.

The
final
CAIR
requires
annual
SO2
and
NOx
reductions
in
23
7
2
EPA
began
our
emissions
and
economic
analyses
for
CAIR
before
the
air
quality
analysis,
which
affects
the
States
covered
by
the
final
rule,
was
completed.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
States
and
the
District
of
Columbia,
and
also
requires
ozone
season
NOx
reductions
in
25
States
and
the
District
of
Columbia.

Many
of
the
CAIR
States
are
affected
by
both
the
annual
SO2
and
NOx
reduction
requirements
and
the
ozone
season
NOx
requirements.

The
EPA
initially
conducted
IPM
modeling
for
today's
final
action
using
a
control
strategy
that
is
similar
but
not
identical
to
the
final
CAIR
requirements.
2
Many
of
the
analyses
for
the
final
CAIR
are
based
on
that
initial
modeling,
as
explained
further
below.
The
control
strategy
that
EPA
initially
modeled
included
three
additional
States
(
Arkansas,
Delaware
and
New
Jersey)
within
the
region
required
to
make
annual
SO2
and
NOx
reductions,
however
these
three
States
are
not
required
to
make
annual
reductions
under
the
final
CAIR.
(
In
the
"
Proposed
Rules"

section
of
today's
Federal
Register
publication,
EPA
is
publishing
a
proposal
to
include
Delaware
and
New
Jersey
in
the
CAIR
region
for
annual
SO2
and
NOx
reductions.)
The
addition
of
these
three
States
made
a
total
of
26
States
and
the
District
of
Columbia
covered
by
annual
SO2
and
NOx
caps
for
the
initial
model
run.
The
initial
model
run
also
included
individual
State
ozone
season
NOx
caps
for
Connecticut
and
Massachusetts,
and
did
not
include
ozone
season
NOx
caps
for
any
other
States.
8
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
The
Agency
conducted
revised
final
IPM
modeling
that
reflects
the
final
CAIR
control
strategy.
The
final
IPM
modeling
includes
regionwide
annual
SO2
and
NOx
caps
on
the
23
States
and
the
District
of
Columbia
that
are
required
to
make
annual
reductions,
and
includes
a
regionwide
ozone
season
NOx
cap
on
the
25
States
and
the
District
of
Columbia
that
are
required
to
make
ozone
season
reductions.
The
EPA
modeled
the
final
CAIR
NOx
strategy
as
an
annual
NOx
cap
with
a
nested,
separate
ozone
season
NOx
cap.

In
this
section
of
today's
preamble,
the
projected
CAIR
costs
and
emissions
are
generally
derived
from
the
final
IPM
run
reflecting
the
final
CAIR.
However,
some
of
EPA's
analyses
are
based
on
the
initial
IPM
run,
described
above,
which
reflected
a
similar
but
not
identical
control
strategy
to
the
final
CAIR.

Analyses
that
are
presented
in
this
section
of
the
preamble
that
are
based
on
the
initial
IPM
run
include:
IPM
sensitivity
runs
that
examine
the
effects
of
using
EIA
natural
gas
price
and
electricity
growth
assumptions;
marginal
cost
effectiveness
curves
developed
using
the
Technology
Retrofitting
Updating
Model;
estimates
of
average
annual
SO2
and
NOx
control
costs
and
average
non­
ozone
season
NOx
control
costs,
and
projected
control
retrofits
used
in
the
feasibility
analysis.
The
air
quality
analysis
in
Section
III
in
today's
preamble
and
the
benefits
9
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
analysis
in
Section
X,
as
well
as
the
analyses
presented
in
the
Regulatory
Impact
Analysis
(
RIA),
are
based
on
emissions
projections
from
the
initial
IPM
run.

EPA
believes
that
the
differences
between
the
initial
IPM
run
that
the
Agency
used
for
many
of
the
analyses
for
CAIR,
and
the
final
IPM
run
reflecting
the
final
CAIR
requirements,
have
very
little
impact
on
projected
control
costs
and
emissions.
For
the
two
IPM
runs,
projected
marginal
costs
of
CAIR
annual
NOx
reductions
in
2009
and
2015
are
identical.
In
addition,
for
the
two
IPM
runs,
projected
marginal
costs
of
CAIR
annual
SO2
reductions
in
2010
and
2015
are
almost
identical.
Also,
the
2009
and
2015
projected
annual
NOx
emissions
in
the
region
encompassing
the
States
that
are
affected
by
the
final
CAIR
annual
NOx
requirements
are
virtually
identical
when
compared
between
the
two
model
runs
(
difference
between
projected
NOx
emissions
is
less
than
1%
for
2009
and
less
than
2%
for
2015).

In
addition,
the
2010
and
2015
projected
annual
SO2
emissions
in
the
region
encompassing
the
States
that
are
affected
by
the
final
CAIR
annual
SO2
requirements
are
virtually
the
same
when
compared
between
the
two
runs
(
difference
between
projected
SO2
emissions
is
less
than
1%
for
2010
and
less
than
2%
for
2015).
These
comparisons
confirm
EPA's
belief
that
the
initial
IPM
run
very
closely
represents
the
final
CAIR
program.
10
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
IPM
output
files
for
the
model
runs
used
in
CAIR
analyses
are
available
in
the
CAIR
docket.
A
Technical
Support
Document
in
the
CAIR
docket
entitled
"
Modeling
of
Control
Costs,

Emissions,
and
Control
Retrofits
for
Cost
Effectiveness
and
Feasibility
Analyses"
further
explains
the
IPM
runs
used
in
the
analyses
for
section
IV
of
the
preamble.

2.
EPA's
Proposed
Methodology
to
Determine
Amounts
of
Emissions
that
Must
be
Eliminated
a.
Overview
of
EPA
Proposal
for
the
Levels
of
Reductions
and
Resulting
Caps,
and
their
Timing
In
the
NPR,
the
amounts
of
SO2
and
NOx
emissions
reductions
that
EPA
proposed
could
be
cost­
effectively
eliminated
in
the
CAIR
region
in
2010
and
2015,
and
the
amount
of
the
proposed
EGU
emissions
caps
for
SO2
and
NOx
that
would
exist
if
all
affected
States
achieved
those
reductions
by
capping
EGU
emissions,
appear
in
Tables
IV­
1
and
IV­
2,
respectively.

TABLE
IV­
1.
­
PROJECTED
SO2
AND
NOx
EMISSION
REDUCTIONS
IN
THE
CAIR
REGION
IN
2010
AND
2015
FOR
THE
PROPOSED
RULE
(
MILLION
TONS)
1
Pollutant
2010
2015
SO2
3.6
3.7
NOx
1.5
1.8
1
CAIR
Notice
of
Proposed
Rulemaking
(
69
FR
4618,
January
30,
2004).
The
proposed
annual
SO2
and
NOx
caps
covered
a
28­
State
(
AL,
AR,
DE,
FL,
GA,
IL,
IN,
IA,
KS,
KY,
LA,
MD,
MA,
MI,
MN,
MI,
MO,
NJ,
NY,
NC,
OH,
PA,
SC,
TN,
TX,
VA,
WV,
WI)
plus
DC
region.
In
addition,
we
proposed
an
ozone­
season
only
cap
for
Connecticut.
11
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
TABLE
IV­
2.
­
PROPOSED
ANNUAL
ELECTRIC
GENERATION
UNIT
SO2
AND
NOx
EMISSIONS
CAPS
IN
THE
CAIR
REGION
(
MILLION
TONS)
1
Pollutant
2010
­
2014
2015
and
later
SO2
3.9
2.7
NOx
1.6
1.3
1
CAIR
Notice
of
Proposed
Rulemaking
(
69
FR
4618,
January
30,
2004).
The
proposed
annual
SO2
and
NOx
caps
covered
a
28­
State
(
AL,
AR,
DE,
FL,
GA,
IL,
IN,
IA,
KS,
KY,
LA,
MD,
MA,
MI,
MN,
MI,
MO,
NJ,
NY,
NC,
OH,
PA,
SC,
TN,
TX,
VA,
WV,
WI)
plus
DC
region.
In
addition,
we
proposed
an
ozone­
season
only
cap
for
Connecticut.

In
the
NPR,
EPA
evaluated
the
amounts
of
SO2
and
NOx
emissions
in
upwind
States
that
contribute
significantly
to
downwind
PM2.5
nonattainment
and
the
amounts
of
NOx
emissions
in
upwind
States
that
contribute
significantly
to
downwind
ozone
nonattainment.
That
is,
EPA
determined
the
amounts
of
emissions
reductions
that
must
be
eliminated
to
help
downwind
States
achieve
attainment,
by
applying
highly
cost­
effective
control
measures
to
EGUs
and
determining
the
emissions
reductions
that
would
result.

From
past
experience
in
examining
multi­
pollutant
emissions
trading
programs
for
SO2
and
NOx,
EPA
recognized
that
the
air
pollution
control
retrofits
that
result
from
a
program
to
achieve
highly
cost­
effective
reductions
are
quite
significant
and
can
not
be
immediately
installed.
Such
retrofits
require
a
large
pool
of
specialized
labor
resources,
in
particular,
boilermakers,

the
availability
of
which
will
be
a
major
limiting
factor
in
the
12
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
amount
and
timing
of
reductions.

EPA
also
recognized
that
the
regulated
industry
will
need
to
secure
large
amounts
of
capital
to
meet
the
control
requirements
while
managing
an
already
large
debt
load,
and
is
facing
other
large
capital
requirements
to
improve
the
transmission
system.

Furthermore,
allowing
pollution
control
retrofits
to
be
installed
over
time
enables
the
industry
to
take
advantage
of
planned
outages
at
power
plants
(
unplanned
outages
can
lead
to
lost
revenue)
and
to
enable
project
management
to
learn
from
early
installations
how
to
deal
with
some
of
the
engineering
challenges
that
will
exist,
especially
for
the
smaller
units
that
often
present
space
limitations.

Based
on
these
and
other
considerations,
EPA
determined
in
the
NPR
that
the
earliest
reasonable
deadline
for
compliance
with
the
final
highly
cost­
effective
control
levels
for
reducing
emissions
was
2015
(
taking
into
consideration
the
existing
bank
of
title
IV
SO2
allowances).
First,
the
Agency
confirmed
that
the
levels
of
SO2
and
NOx
emissions
it
believed
were
reasonable
to
set
as
annual
emissions
caps
for
2015
lead
to
highly
costeffective
controls
for
the
CAIR
region.

Once
EPA
determined
the
2015
emissions
reduction
levels,
the
Agency
determined
a
proposed
first
(
interim)
phase
control
level
that
would
commence
January
1,
2010,
the
earliest
the
Agency
13
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
believed
initial
pollution
controls
could
be
fully
operational
(
in
today's
final
action
the
first
NOx
control
phase
commences
in
2009
instead
of
in
2010,
as
explained
in
detail
in
Section
IV.
C).

The
first
phase
would
be
the
initial
step
on
the
slope
of
emissions
reduction
(
the
glide­
path)
leading
to
the
final
(
second)
control
phase
to
commence
in
2015.
EPA
determined
the
first
phase
based
on
the
feasibility
of
installing
the
necessary
emission
control
retrofits,
as
described
in
Section
IV.
C.

Although
EPA's
primary
cost
effectiveness
determination
is
for
the
2015
emissions
reduction
levels,
the
Agency
also
evaluated
the
cost
effectiveness
of
the
first
phase
control
levels
to
ensure
that
they
were
also
highly
cost­
effective.

Throughout
this
preamble
section,
EPA
reports
both
the
2015
and
2010
(
and
2009
for
NOx)
cost
effectiveness
results,
although
the
first
phase
levels
were
determined
based
on
feasibility
rather
than
cost
effectiveness.
The
2015
emissions
reductions
include
the
2010
(
and
2009
for
NOx)
emissions
reductions
as
a
subset
of
the
more
stringent
requirements
that
EPA
is
imposing
in
the
second
phase.

b.
Regulatory
History:
NOx
SIP
Call
In
the
NPR,
EPA
generally
followed
the
statutory
interpretation
and
approach
under
CAA
section
110(
a)(
2)(
D)

developed
in
the
NOx
SIP
Call
rulemaking.
Under
this
14
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
interpretation,
the
emissions
in
each
upwind
State
that
contribute
significantly
to
nonattainment
are
identified
as
being
those
emissions
that
can
be
eliminated
through
highly
costeffective
controls.

In
the
NOx
SIP
Call,
EPA
relied
primarily
on
the
application
of
highly
cost­
effective
controls
in
determining
the
amount
of
emissions
that
the
affected
States
were
required
to
eliminate.

Specifically,
EPA
developed
a
reference
list
of
the
average
cost
effectiveness
of
recently
promulgated
or
proposed
controls,
and
compared
the
cost
effectiveness
of
those
controls
to
the
cost
effectiveness
of
the
NOx
SIP
Call
controls
under
consideration.

In
addition,
EPA
considered
several
other
factors,
including
the
fact
that
downwind
nonattainment
areas
had
already
implemented
ozone
controls
but
upwind
areas
generally
had
not,
the
fact
that
some
otherwise
required
local
controls
would
be
less
costeffective
than
the
regional
controls,
and
the
overall
ambient
effects
of
the
reductions
required
in
the
NOx
SIP
Call.
(
63
FR
57399­
57403,
Oct.
27,
1998).

i.
Highly
Cost­
effective
Controls
In
the
NOx
SIP
Call,
EPA
presented
control
costs
in
1990
dollars
(
1990$).
For
the
electric
power
industry,
these
expenditures
were
the
increase
in
annual
electric
generation
production
costs
in
the
control
region
that
result
from
the
rule.
15
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
In
the
CAIR
NPR,
SNPR,
and
today's
final
action,
EPA
presents
the
same
type
of
electric
generation
as
well
as
other
costs
in
1999
dollars
(
1999$),
and
rounds
all
values
related
to
the
cost
per
ton
of
air
emissions
controls
to
the
nearest
100
dollars.

In
the
NOx
SIP
Call,
EPA's
decision
on
the
amount
of
required
NOx
emissions
reductions
was
that
this
amount
must
be
computed
on
the
assumption
of
implementing
highly
cost­
effective
controls.
The
determination
of
what
constituted
highly
cost
effective
controls
was
described
as
a
two­
part
process:
(
1)
the
setting
of
a
dollar­
limit
upper
bound
of
highly
cost­
effective
emission
reductions;
and
(
2)
a
determination
of
what
level
of
control
below
this
upper­
bound
was
appropriate
based
upon
achievability
and
other
factors.

With
respect
to
setting
the
upper
bound
of
potential
highly
cost­
effective
controls,
EPA
determined
this
level
on
the
basis
of
average
cost
effectiveness
(
the
average
cost
per
ton
of
pollutant
removed).
The
EPA
explained
that
it
relied
on
average
cost
effectiveness
for
two
reasons:

Since
EPA's
determination
for
the
core
group
of
sources
is
based
on
the
adoption
of
a
broad­
based
trading
program,
average
cost
effectiveness
serves
as
an
adequate
measure
across
sources
because
sources
with
high
marginal
costs
will
be
able
to
take
advantage
of
this
program
to
lower
their
costs.
In
addition,
average
cost
effectiveness
estimates
are
readily
available
for
other
recently
adopted
NOx
control
measures.
(
63
FR
57399)
16
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
At
that
time,
EPA
acknowledged
that
average
cost
effectiveness
did
not
directly
address
the
fact
that
certain
units
might
have
higher
costs
relative
to
the
average
cost
of
reduction
(
e.
g.,
units
with
lower
capacity
factors
tend
to
have
higher
costs):

[
I]
ncremental
cost
effectiveness
helps
to
identify
whether
a
more
stringent
control
option
imposes
much
higher
costs
relative
to
the
average
cost
per
ton
for
further
control.
The
use
of
an
average
cost
effectiveness
measure
may
not
fully
reveal
costly
incremental
requirements
where
control
options
achieve
large
reductions
in
emissions
(
relative
to
the
baseline).
(
63
FR
57399)

Examination
of
marginal
cost
effectiveness
 
which
examines
what
the
cost
would
be
of
the
next
ton
of
reduction
after
the
defined
control
level
 
would
fill
this
gap.
However,
for
the
NOx
SIP
Call
rulemaking,
adequate
information
concerning
marginal
cost
effectiveness
was
not
available.

For
the
NOx
SIP
Call,
to
determine
the
average
cost
effectiveness
that
should
be
considered
to
be
highly
costeffective
EPA
developed
a
"
reference
list"
of
NOx
emissions
controls
that
are
available
and
of
comparable
cost
to
other
recently
undertaken
or
planned
NOx
measures.
The
EPA
explained
that
"
the
cost
effectiveness
of
measures
that
EPA
or
States
have
adopted,
or
proposed
to
adopt,
forms
a
good
reference
point
for
determining
which
of
the
available
additional
NOx
control
measures
can
most
easily
be
implemented
by
upwind
States
whose
17
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
emissions
impact
downwind
nonattainment
problems."
(
63
FR
57400).
The
EPA
explained
that
the
measures
on
the
reference
list
had
already
been
implemented
or
were
planned
to
be
implemented,
and
therefore
could
be
assumed
to
be
less
expensive
than
other
measures
to
be
implemented
in
the
future.
The
EPA
found
that
the
costs
of
the
measures
on
the
reference
list
approached
but
were
below
$
2,000
per
ton
(
1990$).
The
EPA
concluded
that
"
controls
with
an
average
cost
effectiveness
[
of]

less
than
$
2,000
[
1990$,
or
$
2,500
(
1999$)]
per
ton
of
NOx
removed
[
should
be
considered]
to
be
highly
cost­
effective."
(
63
FR
57400).
Notably,
the
reference
costs
were
taken
from
the
supporting
analyses
used
for
the
regulatory
actions
covering
the
NOx
pollution
controls
 
they
are
what
regulatory
decision­
makers
and
the
public
believed
were
the
control
costs.

Mindful
of
this
$
2,000
limit
[
1990$,
or
$
2,500
(
1999$)],
EPA
considered
a
control
level
that
would
have
resulted
in
estimated
average
costs
of
approximately
$
1,800
(
1990$)
per
ton.
However,

EPA
concluded
that
because
the
corresponding
level
of
controls
 
nominally
a
0.12
lb/
mmBtu
control
level
 
was
not
well
enough
established,
EPA
was
"
not
as
confident
about
the
robustness"
of
the
cost
estimates.
Moreover,
EPA
expressed
concern
that
its
"
level
of
comfort"
was
not
as
high
as
it
would
have
liked
that
the
nominal
0.12
lb/
mmBtu
control
level
"
will
not
lead
to
18
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
installation
of
SCR
technology
at
a
level
and
in
a
manner
that
will
be
difficult
to
implement
or
result
in
reliability
problems
for
electric
power
generation"
(
63
FR
57401).

Accordingly,
EPA
selected
the
next
control
level
that
it
had
evaluated
 
a
nominal
0.15
lb/
mmBtu
level
 
which
would
result
in
an
average
cost
of
approximately
$
1,500
(
1990$,
or
$
1,900
1999$)

per
ton.
The
EPA
determined
that
this
control
level
did
not
present
the
uncertainty
concerns
associated
with
the
0.12
level.

The
EPA
added,
in
this
1998
rule:
"
With
a
strong
need
to
implement
a
program
by
2003
that
is
recognized
by
the
States
as
practical,
necessary,
and
broadly
accepted
as
highly
costeffective
the
Agency
has
decided
to
base
the
emissions
budgets
for
EGUs
on
a
0.15
...
level."
(
63
FR
57401
­
57402).
The
EPA
summarized
its
approach
as
determining
"
the
required
emission
levels
...
based
on
the
application
of
NOx
controls
that
achieve
the
greatest
feasible
emissions
reduction
while
still
falling
within
a
cost­
per­
ton
reduced
range
that
EPA
considers
to
be
highly
cost­
effective...."
(
63
FR
57399).

The
bulk
of
the
cost
for
reducing
NOx
emissions
for
EGUs
is
in
the
capital
investment
in
the
control
equipment,
which
would
be
the
same
whether
controls
are
installed
for
ozone
season
only,

or
for
annual
controls.
The
increased
costs
to
run
the
equipment
annually
instead
of
only
in
the
ozone
season
is
relatively
small.
19
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Although
the
NOx
SIP
Call
is
an
ozone
season
NOx
reduction
program,
most
of
the
NOx
control
costs
on
the
reference
list
are
for
annual
reductions.
If
the
NOx
SIP
Call
were
an
annual
program
instead
of
seasonal
its
average
control
costs
would
be
lower,
relative
to
the
annual
control
costs
in
the
reference
list.

ii.
Other
Factors
In
the
NOx
SIP
Call,
although
considering
air
quality
and
cost
to
be
the
primary
factors
for
determining
significant
contribution,
EPA
identified
several
other
factors
that
it
generally
considered.
As
one
factor,
EPA
reviewed
"
overall
considerations
of
fairness
related
to
the
control
regimes
required
of
the
downwind
and
upwind
areas,"
particularly,
the
fact
that
the
major
urban
nonattainment
areas
in
the
East
had
implemented
controls
on
virtually
all
portions
of
their
inventory
of
ozone
precursors,
but
upwind
sources
had
not
implemented
reductions
intended
to
reduce
their
impacts
downwind
(
63
FR
57404).

As
another
factor,
EPA
generally
considered
"
the
cost
effectiveness
of
additional
local
reductions
in
the
...
ozone
nonattainment
areas."
EPA
included
in
the
record
information
that
nationally,
on
average,
additional
local
measures
would
cost
more
than
the
cost
of
the
upwind
controls
required
under
the
SIP
20
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Call.
This
consideration
further
indicated
that
the
regional
controls
under
the
SIP
Call
were
highly
cost­
effective
(
63
FR
57404).

In
addition,
EPA
conducted
air
quality
modeling
to
determine
the
impact
of
the
controls,
and
found
that
they
benefitted
the
downwind
areas
without
being
more
than
necessary
for
those
areas
to
attain
(
63
FR
57403
­
57404).

c.
Proposed
Criteria
for
Emissions
Reduction
Requirements
i.
General
Criteria
In
the
CAIR
NPR,
EPA
proposed
criteria
for
determining
the
appropriate
levels
of
annual
emissions
reductions
for
SO2
and
NOx
and
ozone­
season
emissions
reductions
for
NOx.
The
EPA
stated
that
it
considers
a
variety
of
factors
in
evaluating
the
source
categories
from
which
highly
cost­
effective
reductions
may
be
available
and
the
level
of
reduction
assumed
from
that
sector.

These
include:


The
availability
of
information

The
identification
of
source
categories
emitting
relatively
large
amounts
of
the
relevant
emissions

The
performance
and
applicability
of
control
measures

The
cost
effectiveness
of
control
measures,
and

Engineering
and
financial
factors
that
affect
the
availability
of
control
measures
(
69
FR
4611).
21
3
U.
S.
Environmental
Protection
Agency,
Office
of
Air
and
Radiation,
EPA's
Clean
Air
Power
Initiative,
October
1996.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
EPA
further
stated
that
overall,
"
We
are
striving
...
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."
(
69
FR
4612)

EPA
has
used
these
types
of
criteria
in
a
number
of
efforts
to
develop
regional
and
national
strategies
to
reduce
interstate
transport
of
SO2
and
NOx.
Starting
in
1996,
EPA
performed
analysis
and
engaged
in
dialogue
with
power
companies,
States,

environmental
groups
and
other
interested
groups
in
the
Clean
Air
Power
Initiative
(
CAPI).
3
In
that
study
of
national
emission
reduction
strategies,
EPA
initially
considered
an
emissions
cap
based
on
a
50%
reduction
in
SO2
emissions
from
title
IV
levels
(
i.
e.,
4.5
million
tons
nationwide)
in
2010.
For
NOx,
EPA
initially
looked
at
ozone
season
and
non­
ozone
season
caps.

Commencing
in
2000,
the
ozone
season
emissions
cap
would
be
based
on
an
emission
rate
of
0.20
lb/
mmBtu,
and
in
2005,
the
ozone
season
cap
would
be
reduced
to
a
level
based
on
0.15
lb/
mmBtu
(
these
cap
levels
would
be
similar
to
the
phased
caps
adopted
by
the
Ozone
Transport
Commission
(
OTC)
States).
The
non­
ozone
season
cap
would
be
based
on
the
proposed
title
IV
phase
II
NOx
22
4
U.
S.
Environmental
Protection
Agency,
Office
of
Air
and
Radiation,
Analysis
of
Emission
Reduction
Options
for
the
Electric
Power
Industry,
March
1999.

5
EPA's
Clear
Skies
Act
analysis
is
on
the
web
at:
www.
epa.
gov/
air/
clearskies/
technical.
html
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
rule.
The
EPA
also
considered
other
options
in
the
CAPI
study,

including
setting
NOx
caps
based
on
emission
rates
of
0.20
lb/
mmBtu
and
0.25
lb/
mmBtu;
setting
NOx
caps
based
on
rates
of
0.15
lb/
mmBtu
and
0.20
lb/
mmBtu
but
lowering
the
SO2
allowance
cap
by
60%
instead
of
50%;
and,
keeping
a
NOx
cap
based
on
a
rate
of
0.15
lb/
mmBtu
but
lowering
the
SO2
allowance
cap
by
50%
in
2005
instead
of
in
2010.

EPA
did
a
follow­
up
study
in
1999
and
discussed
those
results
with
various
stakeholder
groups,
as
well.
4
That
study
considered
a
variety
of
SO2
emission
caps
ranging
from
a
40%

reduction
from
title
IV
cap
levels
in
2010
to
a
55%
reduction
from
title
IV
cap
levels
in
2010.
The
1999
study
did
not
consider
additional
reductions
in
NOx
emissions
beyond
those
required
under
the
NOx
SIP
Call.

In
the
last
several
years,
EPA
has
performed
significant
additional
analysis
in
support
of
the
proposed
Clear
Skies
Act.
5
That
legislation,
proposed
in
2002
and
2003,
would
include
nationwide
SO2
caps
of
4.5
million
tons
in
2010
and
3.0
million
tons
in
2018
(
i.
e.,
50%
and
67%
reductions
from
title
IV
cap
levels).
The
Clear
Skies
Act
also
includes
a
two
phase,
two
zone
23
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
NOx
emission
cap
program,
with
the
first
phase
in
2008
and
the
second
phase
in
2018.
In
the
2003
legislation,
the
first
phase
NOx
caps
would
result
in
effective
NOx
emissions
rates
of
0.16
lb/
mmBtu
in
the
east
and
0.20
lb/
mmBtu
in
the
west,
and
the
second
phase
would
result
in
effective
emission
rates
of
0.12
lb/
mmBtu
in
the
east
and
0.20
lb/
mmBtu
in
the
west.

ii.
Reliance
on
Average
and
Marginal
Cost
Effectiveness
In
the
CAIR
NPR,
EPA
supported
the
conclusion
that
its
emissions
caps
are
highly
cost­
effective
based
upon
"(
1)

comparison
to
the
average
cost
effectiveness
of
other
regulatory
actions
and
(
2)
comparison
to
the
marginal
cost
effectiveness
of
other
regulatory
actions."
(
69
FR
4585).
We
supplemented
these
comparisons
of
cost
effectiveness
tables
with
an
auxiliary
evaluation
of
the
marginal
costs
curves,
which
allowed
us
to
show
that
the
selected
control
levels
would
be
"
below
the
point
at
which
there
would
be
significant
diminishing
returns
on
the
dollars
spent
for
pollution
control."
(
69
FR
4614).

Although
in
the
NOx
SIP
Call
EPA
based
the
required
controls
on
average
cost
alone,
in
today's
rule
EPA
uses
both
average
and
marginal
costs,
including
an
evaluation
of
the
marginal
cost
curves.
At
the
time
of
the
NOx
SIP
Call,
marginal
cost
information
was
not
as
readily
available.
Today,
such
information
is
available
for
both
SO2
and
NOx
controls,
although
24
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
marginal
cost
information
remains
more
limited
and
EPA
has
had
to
specifically
develop
marginal
cost
estimates
for
use
in
this
rulemaking.

Marginal
costs
are
a
useful
measure
of
cost
effectiveness
because
they
indicate
how
much
any
additional
level
of
control
at
the
margin
will
cost
relative
to
other
actions
that
are
available.
Using
both
average
and
marginal
control
costs
provides
a
more
complete
picture
of
the
costs
of
controls
than
using
average
costs
alone.
Average
costs
provide
a
means
for
a
straightforward
comparison
between
CAIR
and
other
emissions
reductions
programs
for
which
average
costs
are
generally
the
only
type
of
costs
available.
Where
marginal
cost
information
is
available,
it
enables
EPA
to
compare
the
costs
of
CAIR
at
the
stringency
level
being
considered
to
the
costs
of
the
last
increment
of
control
in
other
programs.
Moreover,
evaluation
of
marginal
cost
curves
allows
us
to
corroborate
that
the
selected
level
of
stringency
of
the
selected
program
stops
short
of
the
point
where
the
returns
begin
to
diminish
significantly.

Projected
marginal
cost
information
for
controlling
emissions
from
EGUs
is
now
available
for
some
State
programs,

because
EPA
includes
the
programs
in
its
Base
Case
power
sector
modeling
using
IPM
to
develop
the
incremental
costs
of
electricity
production
for
CAIR.
Marginal
EGU
control
costs
from
25
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
State
programs
modeled
using
IPM
were
compared
to
projected
marginal
EGU
control
costs
under
CAIR,
as
discussed
in
more
detail
below.

3.
What
Are
the
Most
Significant
Comments
that
EPA
Received
about
its
Proposed
Methodology
for
Determining
the
Amounts
of
SO2
and
NOx
Emissions
that
Must
Be
Eliminated,
and
What
Are
EPA's
Responses?

Some
commenters
took
issue
with
EPA's
reliance
on
cost­
per­
ton­
of­
emissions­
reduction
as
the
metric
for
determining
cost­
effectiveness.
These
commenters
observed
that
this
metric
does
not
take
into
account
that
any
given
ton
of
pollutant
reduction
may
have
different
impacts
on
ambient
concentration
and
human
exposure.
Some
of
these
commenters
advocated
use
of
a
metric
based
on
cost
per
unit
of
pollutant
concentration
reduced.

Another
stated
that
the
EPA
should
account
for
cost­
effectiveness
based
on
geographical
location
relative
to
the
area
of
non­
attainment.

Still
other
commenters
took
a
contrasting
view.
They
argued
that
a
metric
based
on
cost­
per­
ambient­
impact
might
be
useful
in
justifying
control
cost
effectiveness
for
source
categories
within
an
individual
nonattainment
area
as
part
of
an
attainment
SIP,
but
not
for
evaluating
costs
of
controlling
long­
range
transport.
These
commenters
stated
that
it
is
impractical
to
calculate
cost
effectiveness
of
control
on
the
basis
of
cost
per
unit
reduction
in
ambient
concentration.
One
queried:
"
Where
26
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
would
the
ambient
reduction
be
measured?
100
miles
downwind?

1,500
miles
downwind?"

EPA
agrees
that
optimally,
the
cost­
per­
ambient­
impact
of
controls
could
play
a
major
role
in
determining
upwind
control
obligations
(
although
equitable
considerations
and
other
factors
identified
in
the
NOx
SIP
Call
rulemaking
and
today's
action
may
also
play
a
role).
The
EPA
recognized
the
potential
importance
of
this
factor
during
the
NOx
SIP
Call
rulemaking
and
endeavored
to
develop
technical
information
to
support
it.
However,
in
that
rulemaking,
EPA
was
not
able
to
develop
an
approach
to
quantify,

with
sufficient
accuracy,
cost­
per­
ambient
impact
because
the
NOx
SIP
Call
region
was
large
B
covering
approximately
half
of
the
continental
United
States
and
including
approximately
half
the
States
B
and
many
upwind
States
with
different
emissions
inventories
had
widely
varied
impacts
on
many
different
nonattainment
areas
downwind.

This
problem
B
the
complexity
of
the
task
and
the
dearth
of
analytic
tools
B
remains
today
for
both
PM2.5
and
8­
hour
ozone
regional
transport.
Not
surprisingly,
no
commenter
presented
to
EPA
the
analytic
tools,
which
we
would
expect
would
consist
of
a
complex,
computerized
program
that
could
integrate,
on
a
State­
by­
State
basis,
both
control
costs
and
ambient
impacts
by
each
State
on
each
of
its
downwind
receptors
under
the
CAIR
control
scenario.

In
the
absence
of
a
scientifically
defensible,
practicable
27
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
method
for
implementing
a
program
design
approach
based
on
the
cost­
per­
ambient­
impact
of
emissions
reductions,
EPA
is
not
able
to
employ
such
an
approach.
However,
EPA
believes
it
appropriate
to
continue
to
examine
ways
to
develop
such
an
approach
for
future
use.

A
few
commenters
suggested
that
the
EPA
should
use
a
cost­
benefit
analysis
for
determining
reduction
levels.
One
noted
that
cost­
benefit
analysis
can
help
find
the
reduction
levels
that
maximize
societal
net
benefit
(
benefits
minus
costs),

and
suggested
the
Agency
should
compare
the
marginal
cost
of
each
ton
of
pollutant
reduced
to
the
marginal
benefit
achieved,
as
well
as
compare
the
total
costs
to
the
total
benefits.
Another
stated
that
an
optimal
allocation
of
resources
is
where
the
marginal
cost
equals
the
marginal
benefit,
and
observed
that
comparing
the
average
cost
to
the
average
benefit
of
the
controls
proposed
in
the
CAIR
NPR
yields
an
average
benefit
significantly
higher
than
the
average
cost.
This
commenter
concluded
that
EPA
should
require
controls
beyond
the
controls
described
in
the
NPR
as
highly
cost­
effective.

Although
the
EPA
strongly
agrees
that
examination
of
costs
and
benefits
is
very
useful,
in
today's
rulemaking,
EPA
does
not
interpret
CAA
section
110(
a)(
2)(
D)
to
base
the
amount
of
emissions
reductions
on
benefits
other
than
progress
towards
attainment
of
the
PM2.5
or
the
8­
hour
ozone
NAAQS.
EPA's
28
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
interpretation
does,
however,
use
cost
effectiveness
per
ton
of
pollutant
reduced,
and
we
are
using
that
analytic
tool
for
setting
SO2
and
NOx
emission
reduction
requirements.

Additionally,
EPA
has
prepared
a
cost­
benefit
analysis
to
inform
the
Agency
and
public
of
the
many
other
important
impacts
of
this
rulemaking.

A
few
commenters
suggested
that
the
Agency
should
set
its
NOx
and
SO2
reduction
requirements
based
on
best
available
control
technology
(
BACT)
emission
rates
for
EGUs.
Although
not
clearly
stated,
the
commenters
appear
to
suggest
BACT
level
controls
for
both
existing
and
new
units.

The
emission
reduction
requirements
that
the
EPA
determined
are
based
on
the
application
of
highly
cost­
effective
controls
that
are
a
step
that
the
Agency
is
taking
at
this
time
to
eliminate
emissions
that
contribute
significantly
to
nonattainment
of
the
ozone
and
fine
particle
NAAQS.
As
explained
elsewhere,
this
step
is
reasonable
in
light
of
the
current
status
of
implementation
for
those
NAAQS.

Basing
emission
reduction
requirements
on
a
presumption
of
BACT
emission
rates
across
the
board
would
require
scrubbers
and
SCRs
on
all
coal­
fired
units
and
SCRs
on
all
gas­
fired
and
oilfired
units.
The
cost
of
these
controls
would
vary
considerably
from
source
to
source,
be
expensive
for
many
sources,
and
may
29
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
cause
substantial
fuel
switching
to
natural
gas
and
closure
of
smaller
coal­
fired
units.
Having
considered
this
suggestion
for
deeper
regional
reductions
that
would
not
be
as
cost­
effective
as
the
highly
cost­
effective
reductions
in
today's
rule,
EPA
believes
that
a
more
tailored
approach,
such
as
CAIR
level
control
as
well
as
local
controls
under
SIPs
(
where
necessary),

is
a
more
reasonable
approach
to
achieving
the
level
of
ambient
improvement
needed
for
attainment
throughout
the
United
States.

4.
EPA's
Evaluation
of
Highly
Cost­
effective
SO2
and
NOx
Emission
Reductions
Based
on
Controlling
EGUs
a.
SO2
Emissions
Reduction
Requirements
i.
CAIR
Proposal
for
SO2
The
NPR
focused
primarily
on
determining
highly
costeffective
amounts
of
emissions
reductions
based
on,
as
in
the
NOx
SIP
call,
comparison
to
reference
lists
of
the
cost
effectiveness
of
other
regulatory
controls.
In
the
NPR,
EPA
developed
reference
lists
for
both
the
average
cost
effectiveness
and
the
marginal
cost
effectiveness
of
those
other
controls.
These
reference
lists
indicated
that
the
average
annual
costs
per
ton
of
SO2
removed
ranged
from
$
500
to
$
2,100;
and
marginal
costs
of
SO2
removal
ranged
from
$
800
to
$
2,200.

Moreover,
EPA
further
considered
the
cost
effectiveness
of
alternative
stringency
levels
for
this
regulatory
proposal.
That
30
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
is,
EPA
examined
changes
in
the
marginal
cost
curve
at
varying
levels
of
emissions
reductions.
The
EPA
determined
in
the
NPR
that
the
"
knee"
in
the
marginal
cost
effectiveness
curve
­
the
point
at
which
the
marginal
cost
per
ton
of
SO2
removed
begins
to
increase
at
a
noticeably
higher
rate
 
appears
to
start
above
$
1,200
per
ton
(
69
FR
4613
­
4615).

In
the
NPR,
EPA
then
provided
further
analysis
of
a
two­
phase
SO2
reduction
program.
The
final
(
second)
phase,
in
2015,
would
reduce
SO2
emissions
in
the
CAIR
region
by
the
amount
that
results
from
making
a
65
percent
reduction
from
the
title
IV
Phase­
II
allowance
levels
(
taking
into
consideration
the
existing
bank
of
title
IV
SO2
allowances).
The
first
phase,
in
2010,

would
reduce
SO2
emissions
in
the
CAIR
region
by
a
lesser
amount,

i.
e.,
a
50
percent
reduction
from
title
IV
Phase
II
allowance
levels
(
again,
taking
into
consideration
the
banked
title
IV
SO2
allowances).
The
EPA
developed
this
target
SO2
control
level
for
further
evaluation
because,
based
on
all
of
the
earlier
work
performed
on
multi­
pollutant
power
plant
reduction
programs
and
general
consideration,
with
technical
support,
of
overall
emissions
reductions,
costs
to
industry
and
the
general
public,

ambient
improvement,
and
consistency
with
the
emerging
PM2.5
implementation
program,
we
believed
it
would
meet
the
criteria
set
forth
above.
31
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
EPA
then
conducted
cost
analyses
of
this
control
level
using
IPM
as
well
as
additional
analysis
of
the
implications
of
this
control
level
to
determine
if
it
did
indeed
meet
those
criteria.

The
IPM
analysis
considered
the
increase
in
annual
electric
generation
production
costs
in
the
CAIR
region
that
result
from
the
rule.
The
EPA
evaluated
the
cost
effectiveness
of
the
final
phase
(
2015)
cap
to
determine
if
it
is
highly
cost­
effective;

and,
we
also
evaluated
the
cost
effectiveness
of
the
2010
cap.

The
EPA
used
IPM
to
estimate
cost
effectiveness
of
CAIR
in
the
future.
The
IPM
incorporates
projections
of
future
electricity
demand,
and
thus
heat
input
growth.
The
EPA's
IPM
analyses
for
CAIR
includes
all
fossil
fuel
fired
EGUs
with
capacity
greater
than
25
MW.
A
description
of
IPM
is
included
elsewhere
in
this
preamble,
and
detailed
model
documentation
is
in
the
docket.

The
SO2
annual
control
costs
that
were
presented
in
the
CAIR
NPR
were
average
costs
of
$
700
per
ton
and
$
800
per
ton
for
years
2010
and
2015,
respectively,
and
marginal
costs
of
$
700
per
ton
and
$
1,000
per
ton
for
years
2010
and
2015.
In
addition,
the
NPR
included
the
results
of
sensitivity
analyses
that
examined
costs
of
the
proposed
SO2
controls
based
on
the
Energy
Information
Administration's
projections
for
electricity
growth
and
natural
gas
prices.
These
sensitivity
analyses
showed
marginal
SO2
control
costs
of
$
900
per
ton
and
$
1,100
per
ton
for
years
2010
32
6
The
updated
reference
list
includes
estimated
average
costs
for
SO2
reductions
from
EGUs
under
best
available
retrofit
technology
(
BART)
requirements.
The
BART
rule
was
proposed
and
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
and
2015,
respectively.
The
EPA
proposed
to
consider
the
SO2
emissions
reductions
proposed
in
the
NPR
as
highly
cost­
effective
because
they
were
consistent
with
the
lower
end
of
the
reference
list
range
of
cost
per
ton
of
SO2
reduction
for
controls
on
both
an
average
and
a
marginal
cost
basis
(
69
FR
4613
­
4615).

ii.
Analysis
of
SO2
Emission
Reduction
Requirements
for
Today's
Final
Rule
(
I)
Reference
Lists
of
Cost­
effective
SO2
Controls
For
today's
action,
EPA
updated
the
reference
list
of
controls
included
in
the
NPR
of
the
average
and
marginal
costs
per
ton
of
recent
SO2
control
actions.
The
EPA
systematically
developed
a
list
of
cost
information
from
both
recent
actions
and
proposed
actions.
The
EPA
compiled
cost
information
for
actions
taken
by
the
Agency,
and
examined
the
public
comments
submitted
after
the
NPR
was
published,
to
identify
all
available
control
cost
information
to
provide
the
updated
reference
list
for
today's
preamble.
The
updated
reference
list
includes
both
average
and
marginal
costs
of
control,
to
which
EPA
compares
the
CAIR
control
costs,
and
the
list
represents
what
regulatory
decision­
makers
and/
or
the
public
believes
are
the
control
costs.
6
33
has
not
been
finalized.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Table
IV­
3
provides
average
costs
of
SO2
controls.
This
table
includes
average
costs
for
recent
Best
Available
Control
Technology
(
BACT)
permitting
decisions
for
SO2.
Under
EPA's
New
Source
Review
(
NSR)
program,
if
a
company
is
planning
to
build
a
new
plant
or
modify
an
existing
plant
such
that
a
significant
net
increase
in
emissions
will
occur,
the
company
must
obtain
an
NSR
permit
that
addresses
controls
for
air
emissions.
BACT
is
the
type
of
control
required
by
the
NSR
program
for
existing
sources
in
attainment
areas.
The
BACT
decisions
are
determined
on
a
case­
by­
case
basis,
usually
by
State
or
local
permitting
agencies,
and
reflect
consideration
of
average
and
incremental
cost
effectiveness.
These
decisions
are
relevant
for
EPA's
reference
list
of
average
costs
of
SO2
controls,
because
they
represent
cost­
effective
controls
that
have
been
demonstrated.

TABLE
IV­
3.
 
AVERAGE
COSTS
PER
TON
OF
ANNUAL
SO2
CONTROLS
SO
2
Control
Action
Average
Cost
per
Ton
Best
Available
Control
Technology
(
BACT)
Determinations
$
400
B
$
2,100
1
Nonroad
Diesel
Engines
and
Fuel
$
800
2
Best
Available
Retrofit
Technology
(
BART)
for
Electric
Power
Sector
$
2,600
­
$
3,400
3
1
These
numbers
reflect
a
range
of
cost
effectiveness
data
entered
into
EPA's
RACT/
BACT/
LAER
Clearinghouse
(
RBLC)
for
add­
on
SO2
controls.
We
identified
actions
in
the
database
for
large,
utility­
scale,
coal­
fired
boiler
units
for
which
cost
effectiveness
data
were
reported.
The
range
of
costs
34
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
shown
here
is
for
boilers
ranging
from
30
MW
to
an
estimated
790
MW
(
we
used
a
conversion
factor
of
10
mmBtu/
hr
=
1
MW
for
units
for
which
size
was
reported
in
mmBtu/
hr).
Emission
limits
for
these
actions
ranged
from
0.10
lb/
mmBtu
to
0.27
lb/
mmBtu.
Add­
on
controls
reported
for
these
units
are
dry
or
wet
scrubbers
(
in
one
case
with
added
alkali
and
in
one
case
with
a
baghouse).
Where
the
dollar­
year
was
not
reported
we
assumed
1999
dollars.
The
cost
range
presented
in
the
NPR
was
$
500
­
$
2,100
B
today's
range
includes
additional
BACT
costs
that
were
entered
into
the
clearinghouse
after
the
NPR
was
published.
2
Control
of
Emissions
of
Air
Pollution
From
Nonroad
Diesel
Engines
and
Fuel;
Final
Rule
(
69
FR
39131;
June
29,
2004).
The
value
in
this
table
represents
the
long­
term
cost
per
ton
of
emissions
reduced
from
the
total
fuel
and
engine
program
(
cost
per
ton
of
emissions
reduced
in
the
year
2030).
1999$
per
ton.
3
The
EPA
IPM
modeling
2004,
available
in
the
docket.
The
EPA
modeled
the
Regional
Haze
Requirements
as
source
specific
limits
(
90%
SO2
reduction
or
0.1
lb/
mmBtu
rate;
except
the
five
state
WRAP
region
for
which
we
did
not
model
SO2
controls
beyond
what
is
done
for
the
WRAP
cap
in
the
base
case
modeling).
Estimated
average
costs
based
on
this
modeling
are
$
2,600
per
ton
in
2015
and
$
3,400
per
ton
in
2020.
1999$
per
ton.

Table
IV­
4
provides
the
marginal
cost
per
ton
of
recent
State
and
regional
decisions
for
annual
SO2
controls.

TABLE
IV­
4.
 
MARGINAL
COSTS
PER
TON
OF
ANNUAL
SO2
CONTROLS
SO
2
Control
Action
Marginal
Cost
per
Ton
New
Hampshire
Rule
$
600
1
WRAP
Regional
SO
2
Trading
Program
$
1,100
B
$
2,200
2
1
The
EPA
IPM
Base
Case
modeling
August
2004,
available
in
the
docket.
(
1999$
per
ton).
We
modeled
New
Hampshire's
State
Bill
ENV­
A2900,
which
caps
SO2
emissions
at
all
existing
fossil
steam
units.
2
"
An
Assessment
of
Critical
Mass
for
the
Regional
SO
2
Trading
Program,"
prepared
for
Western
Regional
Air
Partnership
Market
Trading
Forum
by
ICF
Consulting
Group,
September
27,
2002,
available
in
the
docket.
This
analysis
looked
at
the
implications
of
one
or
more
States
choosing
to
opt­
out
of
the
WRAP
regional
SO
2
trading
program.
(
1999$
per
ton)

(
II)
Cost
Effectiveness
of
CAIR
Annual
SO2
Reductions
In
the
NPR,
EPA
evaluated
an
annual
SO2
control
strategy
based
on
a
specified
level
of
emissions
reductions
from
electricity
generating
units.
Available
information
indicated
that
emissions
reductions
from
this
industry
would
be
the
most
35
7
The
EPA
used
the
difference
between
EIA's
estimates
for
well­
head
natural
gas
prices
and
minemouth
coal
prices
to
determine
the
sensitivity
of
IPM's
results
to
higher
natural
gas
prices.
The
EPA
describes
this
sensitivity
analysis
as
"
EIA
natural
gas
prices".
For
electric
demand,
we
replaced
EPA's
assumed
annual
growth
of
1.6%
with
EIA's
projection
of
annual
growth
of
1.8
%.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
cost­
effective.
(
As
noted
elsewhere,
EPA
considered
control
strategies
for
other
source
categories,
but
concluded
that
they
would
not
qualify
as
highly
cost­
effective
controls.)
Of
course,

under
today's
rule,
although
EPA
calculates
the
amount
of
emissions
reductions
States
must
achieve
by
evaluation
of
the
EGU
control
strategy,
States
remain
free
to
achieve
those
reductions
by
implementing
controls
on
any
sources
they
wish.

For
today's
action,
EPA
updated
the
predicted
annual
SO2
control
costs
included
in
the
NPR.
The
EPA
analyzed
the
costs
of
the
CAIR
using
an
updated
version
of
IPM
(
documentation
for
the
IPM
update
is
in
the
docket).
Further,
EPA
modified
the
modeling
to
match
the
final
CAIR
strategy
(
see
Section
IV.
A.
1
for
a
description
of
EPA's
CAIR
IPM
modeling).

The
EPA
also
updated
its
analysis
of
the
sensitivity
of
the
marginal
cost
results
to
assumptions
of
higher
electric
growth
and
natural
gas
prices
than
we
used
in
the
base
case.
These
sensitivity
analyses
were
based
on
the
Energy
Information
Administration's
Annual
Energy
Outlook
for
2004.7
In
determining
whether
our
control
strategy
is
highly
cost­
36
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
effective,
EPA
believes
it
is
important
to
account
for
the
variable
levels
of
cost
effectiveness
that
these
sensitivity
analyses
indicate
may
occur
if
electricity
demand
or
natural
gas
prices
are
appreciably
higher
than
assumed
in
IPM.
Those
two
factors
are
key
determinants
of
control
costs
and,
over
the
relatively
long
implementation
period
provided
under
today's
action,
a
meaningful
degree
of
risk
arises
that
these
factors
may
well
vary
to
the
extent
indicated
by
the
sensitivity
analyses.

As
a
result,
EPA
wanted
to
examine
the
marginal
costs
that
would
occur
under
the
scenarios
modeled
in
the
sensitivity
analyses
to
see
how
they
differed
from
the
costs
using
EPA's
assumptions.

Table
IV­
5
provides
the
average
and
marginal
costs
of
annual
SO2
reductions
under
CAIR
for
2010
and
2015.
(
When
presenting
estimated
CAIR
control
costs
in
section
IV
of
this
preamble,
EPA
uses
"
Main
Case"
to
indicate
the
primary
CAIR
IPM
analyses,
as
differentiated
from
other
IPM
analyses
such
as
sensitivity
runs
used
to
examine
the
impacts
of
varying
assumptions
about
natural
gas
price
and
electric
growth.)

TABLE
IV­
5.
 
ESTIMATED
COSTS
PER
TON
OF
SO2
CONTROLLED
UNDER
CAIR,
CAP
LEVELS
BEGINNING
IN
2010
AND
2015
1
Type
of
Cost
Effectiveness
2010
2015
Average
Cost
­
Main
Case
$
500
$
700
Marginal
Cost
­
Main
Case
$
700
$
1,000
Sensitivity
Analysis:
Marginal
Cost
Using
EIA
Electric
Growth
and
Natural
Gas
Prices
$
800
$
1,200
37
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
1
The
EPA
IPM
modeling
2004,
available
in
the
docket.
1999$
per
ton.

These
estimated
SO2
control
costs
under
CAIR
reflect
annual
EGU
SO2
caps
of
3.6
million
tons
in
2010
and
2.5
million
tons
in
2015
within
the
CAIR
region.
Based
on
IPM
modeling,
EPA
projects
that
SO2
emissions
in
the
CAIR
region
will
be
about
5.1
million
tons
in
2010
and
4.0
million
tons
in
2015.
The
projected
emissions
are
above
the
cap
levels
because
of
the
use
of
the
existing
title
IV
bank
of
SO2
allowances.
Average
costs
shown
for
2015
are
an
estimate
of
the
average
cost
per
ton
to
achieve
the
total
difference
in
projected
emissions
between
the
base
case
conditions
and
CAIR
in
the
year
2015
(
the
2015
average
costs
are
not
based
on
the
increment
in
reductions
between
2010
and
2015).

(
A
more
detailed
description
of
the
final
CAIR
SO2
and
NOx
control
requirements
is
provided
below
in
today's
preamble.)

(
III)
SO2
Cost
Comparison
for
CAIR
Requirements
EPA
believes
that
if
an
SO2
control
strategy
has
a
cost
effectiveness
that
is
at
the
low
end
of
the
updated
reference
tables,
the
approach
should
be
considered
to
be
highly
costeffective
The
costs
in
the
reference
range
should
be
considered
to
be
cost­
effective
because
they
represent
actions
that
have
already
been
taken
to
reduce
emissions.
In
deciding
to
require
these
actions,
policy­
makers
at
the
local,
State
and
Federal
levels
have
determined
them
to
be
cost­
effective
reductions
to
38
8
The
updated
reference
list
of
average
SO2
control
costs
includes
estimated
average
EGU
costs
under
BART.
The
BART
rule
has
been
proposed
but
not
finalized.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
limit
or
reduce
emissions.
Thus,
costs
at
the
bottom
of
the
range
must
necessarily
be
considered
highly
cost­
effective.

Today's
action
requires
SO2
emissions
reductions
(
or
an
EGU
emissions
cap)
in
2015.
The
EPA
has
determined
that
those
emissions
reductions
are
highly
cost­
effective.
In
addition,

today's
action
requires
that
some
of
those
SO2
emissions
reductions
(
or
a
higher
EGU
emissions
cap)
be
implemented
by
2010.
The
EPA
has
examined
the
cost­
effectiveness
of
implementing
those
earlier
emissions
reductions
(
or
cap)
by
2010,

and
determined
that
they
are
also
highly
cost­
effective.

The
cost
of
the
SO2
reductions
required
under
today's
action
 
if
the
States
choose
to
implement
those
reductions
through
EGUs,
for
which
the
most
cost­
effective
reductions
are
available
 
on
average
and
at
the
margin,
are
at
the
lower
end
of
the
range
of
cost
effectiveness
of
other,
recent
SO2
control
requirements.
8
This
is
true
for
our
analysis
of
both
the
costs
EPA
generally
expects
as
well
as
the
somewhat
higher
costs
that
would
result
from
higher
than
expected
electricity
demand
and
natural
gas
prices,
as
indicated
in
the
sensitivity
analyses
that
EPA
has
done.

Specifically,
the
average
cost
effectiveness
of
the
SO2
39
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
requirements
is
$
700
per
ton
removed
in
2015.
This
amount
falls
toward
the
low
end
of
the
reference
range
of
average
costs
per
ton
removed
of
$
400
to
$
3,400.
Similarly,
the
marginal
cost
effectiveness
of
the
SO2
requirements
ranges
from
$
1,000
to
$
1,200
for
2015
(
with
the
higher
end
of
the
range
based
on
the
sensitivity
analyses).
These
amounts
fall
toward
the
lower
end
of
the
reference
range
of
marginal
cost
per
ton
removed
of
$
600
to
$
2,200.

The
EPA
believes
that
selecting
as
highly
cost­
effective
amounts
toward
the
lower
end
of
our
average
and
marginal
cost
ranges
for
SO2
and
NOx
control
is
appropriate
because
today's
rulemaking
is
an
early
step
in
the
process
of
addressing
PM2.5
and
8­
hour
ozone
nonattainment
and
maintenance
requirements.
The
Clean
Air
Act
requires
States
to
submit
section
110(
a)(
2)(
D)

plans
to
address
interstate
transport,
and
overall
attainment
plans
to
ensure
the
NAAQS
are
met
in
local
areas.
By
taking
the
early
step
of
finalizing
CAIR,
we
are
requiring
a
very
substantial
air
emissions
reduction
that
addresses
interstate
transport
of
PM2.5
as
well
as
a
further
reduction
in
interstate
transport
of
ozone
beyond
that
required
by
the
NOx
SIP
Call
Rule.

Much
of
the
air
quality
improvement
resulting
from
reduced
transport
is
likely
to
occur
through
broad
and
deep
emission
reductions
from
the
electric
power
sector,
which
has
been
a
major
40
9
EPA
did
promulgate
phase
I
of
the
ozone
implementation
rule
in
April
2004
but
has
not
issued
phase
II
of
the
rule,
which
will
interpret
CAA
requirements
relating
to
local
controls
(
e.
g.,
RACT,
RACM,
RFP).

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
part
of
the
transport
problem.
Other
air
quality
benefits
will
occur
as
the
result
of
Federal
mobile
source
regulations
for
new
sources,
which
cover
passenger
vehicles
and
light
trucks,

heavyduty
trucks
and
buses,
and
non­
road
diesel
equipment.

Next,
against
a
backdrop
of
Federal
actions
that
lower
air
emissions
and
some
substantial
State
programs,
States
will
develop
plans
designed
to
achieve
the
standards
in
their
local
nonattainment
areas.
EPA
has
not
yet
promulgated
rules
interpreting
the
Act's
requirements
for
State
implementation
plans
for
PM2.5
and
ozone
nonattainment
areas9,
nor
have
States
developed
plans
to
demonstrate
attainment.
As
a
result,
there
are
significant
uncertainties
regarding
potential
reductions
and
control
costs
associated
with
State
plans.
We
believe
that
some
areas
are
likely
to
attain
the
standards
in
the
near
term
through
early
CAIR
reductions
and
local
controls
that
have
costs
per
ton
similar
to
the
levels
we
have
determined
to
be
highly
costeffective
We
expect
that
other
areas
with
higher
PM2.5
or
ozone
levels
will
determine
through
the
attainment
planning
process
that
they
need
greater
emissions
reductions,
at
higher
costs
per
ton,
to
reach
attainment
within
the
Act's
time
frames.
For
those
41
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
areas
States
will
need
to
assess
targeted
measures
for
achieving
local
attainment
in
a
cost­
effective
(
but
not
necessarily
highly
cost­
effective)
manner,
in
combination
with
CAIR's
significant
reductions.
Given
the
uncertainties
that
exist
at
this
early
stage
of
the
implementation
process,
EPA
believes
this
rule
is
a
rational
approach
to
determining
the
highly
cost­
effective
reductions
in
PM2.5
and
ozone
precursors
that
should
be
required
for
interstate
transport
purposes.

As
discussed
above,
the
Agency
believes
this
approach
is
consistent
with
our
action
in
the
NOx
SIP
Call.
While
the
cost
level
selected
for
the
NOx
SIP
Call
was
not
at
the
low
end
of
the
reference
range
of
costs,
if
the
NOx
SIP
Call
costs
were
for
annual
rather
than
seasonal
controls
they
would
have
been
lower
relative
to
the
annual
control
costs
on
the
list,
similar
to
relative
costs
of
CAIR
compared
to
its
reference
lists.
Also,

significant
local
controls
for
meeting
the
1­
hour
ozone
standard
had
already
been
adopted
in
many
areas.

Although
EPA's
primary
cost
effectiveness
determination
is
for
the
2015
emissions
reduction
levels,
the
Agency
also
evaluated
the
cost
effectiveness
of
the
interim
phase
control
levels
to
ensure
that
they
were
also
highly
cost­
effective.
For
the
SO2
requirements
for
2010,
the
average
cost­
effectiveness
is
$
500
per
ton
removed,
and
the
marginal
cost­
effectiveness
ranges
42
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
from
$
700
to
$
800.
The
2010
costs
indicate
that
the
interim
phase
CAIR
reductions
are
also
highly
cost­
effective.

(
IV)
Cost
Effectiveness:
Marginal
Cost
Curves
for
SO2
Control
As
noted
above,
the
Agency
also
considered
another
factor
to
corroborate
its
conclusion
concerning
the
cost
effectiveness
of
the
selected
levels
of
control:
the
cost
effectiveness
of
alternative
stringency
levels
for
today's
action.
Specifically,

EPA
examined
changes
in
the
marginal
cost
curve
at
varying
levels
of
emissions
reductions
for
EGUs.
Figure
IV­
1
shows
that
the
"
knee"
in
the
2010
marginal
cost
effectiveness
curve
 
the
point
where
the
cost
of
controlling
a
ton
of
SO2
from
EGUs
is
increasing
at
a
noticeably
higher
rate
 
appears
to
occur
at
about
$
2,000
per
ton
of
SO2.
Figure
IV­
2
shows
that
the
"
knee"

in
the
2015
marginal
cost
effectiveness
curve
also
appears
to
occur
at
about
$
2,000
per
ton
of
SO2.
(
As
discussed
above,
the
projected
marginal
costs
of
SO2
reductions
for
CAIR
are
$
700
per
ton
in
2010
and
$
1,000
per
ton
in
2015.)
The
EPA
used
the
Technology
Retrofitting
Updating
Model
(
TRUM),
a
spreadsheet
model
based
on
the
IPM,
for
this
analysis.
(
The
EPA
based
these
marginal
SO2
cost
effectiveness
curves
on
the
electric
growth
and
natural
gas
price
assumptions
in
the
main
CAIR
IPM
modeling
run.

Marginal
cost
effectiveness
curves
based
on
other
electric
growth
and
natural
gas
price
assumptions
would
look
different,
therefore
43
10
EPA
is
using
the
knee
in
the
curve
analysis
solely
to
show
that
the
required
emissions
reductions
are
very
cost
effective.
The
marginal
cost
curve
reflects
only
emissions
reduction
and
cost
information,
and
not
other
considerations.
We
note
that
it
might
be
reasonable
in
a
particular
regulatory
action
to
require
emissions
reductions
past
the
knee
of
the
curve
to
reduce
overall
costs
of
meeting
the
NAAQS
or
to
achieve
benefits
that
exceed
costs.
It
should
be
noted
that
similar
analysis
for
other
source
categories
may
yield
different
curves.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
it
would
not
be
appropriate
to
compare
the
curves
here
to
the
marginal
costs
based
on
the
IPM
modeling
sensitivity
run
that
used
EIA
assumptions.)
These
results
make
clear
that
this
rule
is
very
cost­
effective
because
the
control
level
is
below
the
point
at
which
the
cost
begins
to
increase
at
a
significantly
higher
rate.

In
this
manner,
these
results
corroborate
EPA's
findings
above
concerning
the
cost
effectiveness
of
the
emissions
reductions.
10
44
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Marginal
Cost
Curve
of
Abatement
for
SO2
Emissions
from
EGUs
in
2010
(
NOx
Emissions
at
1.5
million
tons)

$­
$
500
$
1,000
$
1,500
$
2,000
$
2,500
$
3,000
1.00
2.00
3.00
4.00
5.00
6.00
Million
Tons
of
SO2
Emitted
in
CAIR
Region
Source:
EPA
TRUM
Analysis,
August
2004
Marginal
Cost
(
1999$/
ton)

SO2
Price
($/
ton)
FIGURE
IV­
1
45
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Marginal
Cost
Curve
of
Abatement
for
SO2
Emissions
from
EGUs
in
2015
(
NOx
Emissions
at
1.3
million
tons)

$­
$
500
$
1,000
$
1,500
$
2,000
$
2,500
$
3,000
1.00
2.00
3.00
4.00
5.00
6.00
7.00
Million
Tons
of
SO2
Emitted
in
CAIR
Region
Source:
EPA
TRUM
Analysis,
August
2004
Marginal
Cost
(
1999$/
ton)

SO2
Price
($/
ton)
FIGURE
IV­
2
46
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
b.
NOx
Emissions
Reductions
Requirements
i.
CAIR
Proposal
for
NOx
and
Subsequent
Analyses
for
Regionwide
Annual
and
Ozone
Season
NOx
Control
Levels
In
this
section,
EPA
describes
its
proposed
method
for
determining
regionwide
NOx
control
levels
and
the
method
used
for
the
final
CAIR.

In
the
CAIR
NPR,
EPA
updated
the
reference
list
included
in
the
NOx
SIP
Call
for
the
average
annual
cost
effectiveness
of
recent
or
proposed
NOx
controls,
and
determined
that
these
amounts
ranged
from
approximately
$
200
to
$
2,800.
In
addition,

in
the
NPR,
EPA
developed
a
reference
list
for
marginal
annual
cost
effectiveness
for
NOx
controls,
and
determined
that
these
amounts
ranged
from
approximately
$
1,400
to
$
3,000
(
69
FR
4614
­

4615).

In
the
NPR,
EPA
proposed
a
two­
phased
annual
NOx
control
program,
with
a
final
phase
in
2015
and
a
first
phase
in
2010.

The
regionwide
emissions
reduction
requirements
that
EPA
proposed
 
and
the
budget
levels
that
would
apply
if
all
States
chose
to
implement
the
reductions
from
EGUs
 
were
based
on
using
a
combination
of
recent
historical
heat
input
and
NOx
emissions
rates
for
fossil
fuel­
fired
EGUs.
For
historical
heat
input,
EPA
proposed
determining
the
highest
heat
input
from
units
affected
by
the
Acid
Rain
program
for
each
affected
State
for
the
years
47
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
1999­
2002.
The
EPA
then
summed
this
heat
input
for
all
of
the
States
affected
for
annual
NOx
reductions.
For
2015,
EPA
calculated
a
proposed
regionwide
annual
NOx
budget
by
multiplying
this
heat
input
by
an
emission
rate
of
0.125
lb/
mmBtu,
and
for
2010
by
multiplying
by
0.15
lb/
mmBtu.

In
developing
the
CAIR
NPR,
when
EPA
considered
the
appropriate
amount
of
annual
SO2
emission
reductions,
EPA
relied
on
the
existing
title
IV
annual
SO2
cap
as
a
starting
point.

However,
in
considering
the
appropriate
amount
of
NOx
reductions,

the
situation
is
different
because
title
IV
does
not
cap
NOx
emissions.
Therefore,
EPA
and
the
States
have
focused
on
emissions
caps
based
on
a
combination
of
heat
input
and
NOx
emission
rates.
Emission
rates
similar
to
the
rates
used
to
develop
the
CAIR
NPR
have
been
considered
in
the
past.
For
example,
the
CAPI
1996
study,
noted
above,
contemplated
NOx
caps
based
on
an
emission
rate
of
0.15
lb/
mmBtu
(
and
other
options
based
on
NOx
rates
of
0.20
lb/
mmBtu
and
0.25
lb/
mmBtu).
The
NOx
SIP
Call
is
based
on
an
emission
rate
of
0.15
lb/
mmBtu.

The
methodology
described
in
the
NPR
is
best
understood
as
the
means
for
developing
the
target
2015
annual
NOx
control
level
(
or
emissions
budget)
for
further
evaluation
through
IPM.
The
EPA
developed
this
level
mindful
of
its
experience
to
date
with
the
NOx
SIP
Call
and
the
earlier
work
EPA
has
performed
on
48
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
multi­
pollutant
power
plant
reduction
programs.
The
EPA
also
considered
available
technical
information
on
pollution
controls,

costs
to
industry
and
the
general
public,
ambient
air
improvement,
and
consistency
with
the
emerging
PM2.5
implementation
program,
in
developing
its
target
control
level.

Recent
advances
in
combustion
control
technology
for
NOx
reductions,
as
well
as
widespread
use
of
selective
catalytic
reduction
(
SCR)
on
U.
S.
coal­
fired
EGU
boilers
achieving
NOx
emission
rates
of
0.06
lb/
mmBtu
and
below,
provide
evidence
that
even
lower
average
NOx
emission
rates
are
highly
cost­
effective
than
rates
considered
in
the
past
(
based
on
analyzing
EGUs),

possibly
on
the
order
of
0.12
lb/
mmBtu
or
less.
The
EPA
developed
the
target
annual
NOx
control
level
(
or
emissions
budget)
with
the
understanding
that
the
evaluation
of
that
level
might
indicate
that
average
emission
rates
on
the
order
of
0.12
lb/
mmBtu
or
less
might
be
highly
cost­
effective
for
the
final
(
2015)
control
phase,
and
an
interim
level
resulting
in
an
average
emission
rate
of
less
than
0.15
lb/
mmBtu
might
be
feasible
for
the
first
phase.

EPA
did
evaluate
the
target
annual
NOx
control
levels
(
or
emissions
budgets)
using
IPM.
The
EPA
confirmed
that
the
2015
level
is
highly
cost­
effective.
The
Agency
also
evaluated
the
cost
effectiveness
of
the
proposed
2010
cap
to
assure
that
the
49
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
interim
phase
reductions
would
also
be
highly
cost­
effective.

The
EPA's
IPM
analyses
for
CAIR
includes
all
fossil
fuel
fired
EGUs
with
generating
capacity
greater
than
25
MW.

The
proposed
cap
for
the
first
phase
was
developed
taking
into
consideration
how
much
pollution
control
for
NOx
and
SO2
could
be
installed
without
running
into
a
shortage
of
skilled
labor,
in
particular
boilermakers
(
EPA's
assumptions
regarding
boilermaker
labor
are
described
in
Section
IV.
C.
2
of
this
preamble).
The
Agency
focused
on
providing
substantial
reductions
of
both
SO2
and
NOx
emissions
at
the
outset
of
the
proposed
program,
leading
to
significant
retrofits
of
Flue
Gas
Desulfurization
units
(
FGD)
for
SO2
control
and
Selective
Catalytic
Reduction
(
SCR)
for
NOx
control.

In
the
NPR,
EPA
explained
that
using
the
highest
Acid
Rain
Program
heat
input
for
each
State
to
develop
a
regionwide
heat
input
amount,
rather
than
the
average
Acid
Rain
Program
heat
input,
provided
a
cushion
that
represented
a
reasonable
adjustment
to
reflect
that
there
are
some
non­
Acid
Rain
units
that
operate
in
these
States
that
will
be
subject
to
the
proposed
CAIR
emission
reduction
levels.
The
EPA
explained
that
it
did
not
use
heat
input
data
from
non­
Acid
Rain
units
in
the
proposal
because
it
did
not
have
all
the
necessary
data
available
at
the
50
11
The
EPA
does
not
collect
annual
heat
input
data
from
these
non­
Acid
Rain
units.
EIA
does
collect
heat
input
from
such
units,
however
there
are
some
limitations
to
the
data.
First,
there
are
no
requirements
specifying
how
the
data
should
be
collected
or
quality
assured.
Second,
the
data
is
collected
on
a
plant­
wide
basis
rather
than
on
a
unit­
by­
unit
basis.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
time
the
NPR
was
developed.
11
Using
the
highest
of
recent
years'

Acid
Rain
Program
heat
input
provided
an
approximation
of
the
regionwide
heat
input,
although
it
did
not
include
heat
input
from
non­
Acid
Rain
sources.
Multiplying
the
approximate
recent
heat
input
by
0.125
lb/
mmBtu
to
develop
a
proposed
regionwide
annual
2015
NOx
cap
could
reasonably
be
expected
to
yield
an
average
effective
NOx
emission
rate
(
considering
all
EGUs
potentially
affected
by
CAIR
for
annual
reductions,
not
only
the
Acid
Rain
units,
and
considering
growth
in
heat
input)
somewhat
less
than
0.125
lb/
mmBtu.
Likewise,
multiplying
the
approximate
recent
heat
input
by
0.15
lb/
mmBtu
to
develop
a
regionwide
annual
2010
NOx
cap
could
reasonably
be
expected
to
yield
an
average
effective
NOx
emission
rate
for
all
CAIR
units
of
about
0.15
lb/
mmBtu
or
less.

Although
EPA
calculated
 
in
essence,
as
a
target
level
for
further
evaluation
 
the
proposed
regionwide
annual
NOx
control
levels
(
or
emissions
budgets)
based
on
heat
input
from
only
Acid
Rain
program
units,
the
Agency
evaluated
the
cost
effectiveness
of
the
control
levels
using
heat
input
from
all
EGUs
that
potentially
would
be
affected
by
the
proposed
CAIR.
The
EPA
51
12
These
projected
average
NOx
emissions
rates
are
from
updated
IPM
modeling
done
in
2004.
The
IPM
modeling
done
prior
to
the
NPR
also
projected
similar
average
emission
rates,
about
0.15
lb/
mmBtu
and
0.11
lb/
mmBtu
in
2010
and
2015,
respectively.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
evaluated
cost
effectiveness
using
the
IPM,
which
includes
both
Acid
Rain
units
and
non­
Acid
Rain
units.
Further,
IPM
incorporates
assumptions
for
electricity
demand
growth,
and
thus
heat
input
growth.

Specifically,
EPA
evaluated
these
target
annual
NOx
caps
on
EGUs
for
2010
and
2015
 
and
therefore
the
associated
regionwide
emissions
reductions
 
using
IPM,
which,
in
effect,
demonstrated
that
these
proposed
NOx
emissions
cap
levels
can
be
met
using
highly
cost­
effective
controls
with
the
expected
levels
of
electricity
demand
in
2010
and
2015,
respectively.
Those
expected
levels
of
electricity
demand
are
higher
than
the
electricity
demand
during
the
1999
to
2002
years
upon
which
EPA
based
heat
input;
and
as
a
result,
the
amount
of
heat
input
necessary
to
meet
the
projected
electricity
demand
is
expected
to
be
higher
than
the
amount
that
EPA
developed
for
evaluation
purposes
through
the
method
described
above.
The
projected
average
future
emissions
rates
that
would
be
associated
with
the
2010
and
2015
heat
input
levels
needed
to
meet
electricity
demand
(
coupled
with
the
NOx
emissions
budgets
developed
through
the
methodology
described
above)
would
be
about
0.14
lb/
mmBtu
and
0.11
lb/
mmBtu
in
2010
and
2015,
respectively.
12
These
average
52
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
rates
would
be
for
all
units
affected
by
annual
NOx
controls
under
CAIR,
including
non­
Acid
Rain
units.
Thus,
the
heat
input
is
projected
to
be
higher
in
2010
and
2015
than
the
recent
historic
heat
input
used
to
develop
the
target
emissions
budgets,

and
the
projected
NOx
emission
rates
in
2010
and
2015
are
lower
than
the
0.15
lb/
mmBtu
and
0.125
lb/
mmBtu
rates
that
were
used
to
develop
the
budgets.
IPM
determined
the
costs
of
meeting
these
average
future
NOx
emission
rates
of
0.14
lb/
mmBtu
and
0.11
lb/
mmBtu.
EPA
considers
these
emission
rates
to
be
highly
costeffective
and
feasible.

In
the
NPR,
EPA
proposed
an
interim
(
Phase
I)
annual
NOx
phase
in
2010
and
a
final
(
Phase
II)
annual
NOx
phase
in
2015.

However,
in
today's
final
rule
EPA
is
promulgating
a
Phase
I
for
NOx
in
2009
(
with
the
Phase
II
for
NOx
in
2015,
as
proposed).

EPA
determined
the
regionwide
NOx
control
levels
for
2009
and
2015
for
today's
final
action
using
the
same
methodology
as
we
used
to
determine
proposed
levels.
The
Agency
evaluated
the
cost
effectiveness
of
the
final
reduction
requirements
(
and
average
NOx
emission
rates)
using
IPM
and
determined
them
to
be
highly
cost­
effective,
assuming
controls
on
EGUs.
EPA's
evaluation
of
the
cost
effectiveness
of
the
emission
reduction
strategy
we
assumed
in
establishing
the
final
CAIR
control
levels
is
discussed
further
below.
53
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
The
average
NOx
emission
rates
in
the
first
and
second
phases
of
CAIR
will
be
lower
than
the
nominal
emission
rate
on
which
the
NOx
SIP
Call
was
based,
which
was
0.15
lb/
mmBtu.
In
the
NOx
SIP
Call,
EPA
also
considered
a
control
level
based
on
a
lower
nominal
emission
rate,
0.12
lb/
mmBtu.
However,
at
that
time
the
use
of
SCR
was
not
sufficiently
widespread
to
allow
EPA
to
conclude
that
the
controls
necessary
to
meet
a
tighter
cap
could
be
installed
in
the
required
timeframe,
without
causing
reliability
problems
for
the
electric
power
sector.
Now,
through
the
experience
gained
from
the
NOx
SIP
Call,
EPA
has
confidence
that
with
SCR
technology
average
emissions
rates
lower
than
the
NOx
SIP
Call
nominal
emission
rate
can
be
achieved
on
a
regionwide
basis.

In
the
CAIR
NPR,
after
determining
the
regionwide
control
level
and
evaluating
it
to
assure
that
it
is
highly
costeffective
the
Agency
then
apportioned
the
regionwide
budgets
to
the
affected
States.
The
EPA
proposed
to
apportion
regionwide
NOx
budgets
to
individual
States
on
the
basis
of
each
State's
share
of
recent
average
heat
input.
In
the
NPR,
EPA
used
the
average
share
of
Acid
Rain
Program
heat
input.
However,
as
discussed
in
the
SNPR
and
the
NODA,
in
order
to
distribute
more
equitably
to
States
their
share
of
the
regionwide
NOx
budgets,

EPA
then
considered
each
State's
proportional
share
of
recent
54
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
average
heat
input
using
data
from
non­
Acid
Rain
Program
sources
as
well
as
Acid
Rain
Program
sources.
The
EPA
obtained
EIA
heat
input
data
reported
for
non­
Acid
Rain
sources
and
combined
the
EIA
heat
inputs
with
Acid
Rain
heat
inputs
to
determine
each
State's
share
of
combined
average
recent
heat
input.

The
fact
that
EPA
distributed
the
regionwide
budget
to
individual
States
based
on
their
proportional
share
of
heat
input
from
Acid
Rain
and
non­
Acid
Rain
units
combined
does
not
affect
the
determination
of
the
regionwide
budgets
themselves.
The
regionwide
budgets
were
determined
to
be
highly
cost­
effective
when
tested
for
all
units
 
both
non­
Acid
Rain
units
as
well
as
Acid
Rain
units
 
that
would
be
affected
by
CAIR.
(
EPA's
method
for
apportioning
regionwide
NOx
budgets
to
States
is
discussed
in
more
detail
elsewhere
in
today's
preamble.
That
discussion
includes
an
explanation
of
the
differences
between
the
State
budgets
that
were
presented
in
the
NPR,
the
SNPR,
and
the
NODA.

In
addition,
see
the
TSD
entitled
"
Regional
and
State
SO2
and
NOx
Emissions
Budgets.")

In
the
NPR,
EPA
proposed
that
Connecticut
contributed
significantly
to
downwind
ozone
nonattainment,
but
not
to
PM2.5
nonattainment.
Thus,
the
Agency
proposed
that
Connecticut
would
not
be
subject
to
an
annual
NOx
control
requirement
and
was
not
included
in
the
region
proposed
for
annual
controls.
We
proposed
55
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
that
Connecticut
would
be
affected
by
an
ozone
season­
only
NOx
control
level,
and
proposed
to
calculate
Connecticut's
ozone
season
control
level
in
a
parallel
way
to
how
the
regionwide
annual
NOx
control
levels
were
calculated.
That
is,
EPA
selected
the
highest
of
the
same
four
years
of
(
ozone
season­
only)
heat
input
used
for
the
regionwide
budget
calculation,
and
multiplied
that
heat
input
by
the
same
NOx
emission
rates
used
to
calculate
the
regionwide
control
levels.
Connecticut
is
the
only
State
for
which
an
ozone
season
budget
was
proposed.

The
EPA
used
the
same
methodology
for
developing
regionwide
budgets
for
today's
final
rule
as
was
proposed
in
the
NPR.
For
the
final
CAIR,
EPA
found
that
23
States
and
the
District
of
Columbia
contribute
significantly
to
downwind
PM2.5
nonattainment
and
found
that
25
States
and
the
District
of
Columbia
contribute
significantly
to
downwind
ozone
nonattainment
(
section
III
in
today's
preamble
describes
the
significance
determinations).

CAIR
requires
annual
NOx
reductions
in
all
States
determined
to
contribute
significantly
to
downwind
PM2.5
nonattainment,
and
requires
ozone
season
NOx
reductions
in
all
States
determined
to
contribute
significantly
to
downwind
ozone
nonattainment
(
many
of
the
CAIR
States
are
affected
by
both
annual
and
ozone
season
NOx
reduction
requirements).
The
final
CAIR
ozone
season
NOx
reductions
are
required
in
two
phases,
with
Phase
I
commencing
in
56
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
2009
and
Phase
II
in
2015,
the
same
years
as
the
annual
NOx
reduction
requirements.

As
described
above,
the
Agency
proposed
ozone
season
NOx
reduction
requirements
for
Connecticut,
and
did
not
propose
ozone
season
reductions
in
any
other
State.
For
today's
final
rule,

EPA
requires
ozone
season
reductions
in
all
States
contributing
significantly
to
downwind
ozone
nonattainment.
The
EPA
determined
regionwide
ozone
season
NOx
control
levels
for
the
final
CAIR
using
the
same
methodology
as
was
used
for
the
annual
NOx
reduction
requirements
(
which
is
the
same
method
that
was
proposed
for
Connecticut's
ozone
season
budget).
That
is,
EPA
determined
the
highest
(
ozone
season)
heat
input
from
Acid
Rain
program
units
for
the
years
1999­
2002
for
each
State,
then
summed
this
heat
input
for
all
of
the
States
affected
for
ozone
season
NOx
reductions.
For
the
final
2015
control
level,
EPA
calculated
a
regionwide
ozone
season
NOx
budget
by
multiplying
this
heat
input
by
an
emission
rate
of
0.125
lb/
mmBtu,
and
for
2009
by
multiplying
by
0.15
lb/
mmBtu.
The
Agency
evaluated
the
cost
effectiveness
of
these
ozone
season
NOx
control
levels
(
and
average
NOx
emission
rates)
using
IPM
and
determined
them
to
be
highly
cost­
effective,
assuming
controls
on
EGUs.
EPA's
evaluation
of
the
cost
effectiveness
of
the
final
CAIR
control
requirements
is
discussed
further
below.
57
13
The
control
costs
for
this
model
sensitivity
that
were
presented
in
the
NPR
were
in
error
(
69
FR
4615).
The
EPA
corrected
the
error
in
a
memorandum
from
Jeffrey
Holmstead
and
Lisa
Friedman
to
the
Administrator
on
January
8,
2004.
The
memo
is
on
the
web
at
www.
epa.
gov/
interstateairquality/
rule.
html.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Based
on
EPA's
analysis
of
proposed
annual
NOx
control
levels,
in
the
NPR
the
Agency
presented
average
costs
for
annual
NOx
control
of
$
800
per
ton
and
$
700
per
ton
for
2010
and
2015,

and
marginal
costs
of
$
1,300
per
ton
and
$
1,500
per
ton
for
2010
and
2015.
In
the
NPR,
the
EPA
also
presented
marginal
costs
of
annual
NOx
control
from
sensitivity
analyses
that
used
EIA
assumptions
for
electricity
growth
and
natural
gas
prices.
Those
marginal
control
costs
were
$
1,300
per
ton
and
$
1,600
per
ton
for
2010
and
2015,
respectively.
The
EPA
also
presented
costs
from
a
sensitivity
model
run
that
used
EIA
assumptions
for
electricity
growth
and
natural
gas
price
and
higher
SCR
costs.
These
marginal
control
costs
were
$
1,700
per
ton
and
$
2,200
per
ton
for
2010
and
2015,
respectively.
13
In
the
NPR,
EPA
also
presented
the
average
cost
effectiveness
for
ozone
season­
only
NOx
control
of
$
1,000
per
ton
and
$
1,500
per
ton
for
2010
and
2015,
respectively,
and
a
marginal
cost
for
ozone
season­
only
control
of
$
2,200
per
ton
and
$
2,600
per
ton
for
2010
and
2015.
The
EPA
also
presented
average
costs
for
the
non­
ozone
season
(
remaining
seven
months
of
the
year)
control
of
$
700
per
ton
and
$
500
per
ton
in
2010
and
2015,
58
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
respectively.
(
As
noted
above,
the
capital
costs
of
installing
NOx
control
equipment
would
be
largely
identical
whether
the
equipment
will
be
operated
during
the
ozone
season
only
or
for
the
entire
year.
However,
the
amount
of
reductions
would
be
less
if
the
control
equipment
were
operated
only
during
the
ozone
season
compared
to
annual
operation.)

EPA
proposed
the
conclusion
that
these
costs
met
the
criteria
for
highly
cost­
effective
emissions
reductions
for
NOx
(
69
FR
4613
­
4615).

As
with
SO2,
EPA
also
considered
the
cost
effectiveness
of
alternative
stringency
levels
for
this
regulatory
proposal
(
examining
changes
in
the
marginal
cost
curve
at
varying
levels
of
emission
reductions).

ii.
What
Are
the
Most
Significant
Comments
that
EPA
Received
about
Proposed
NOx
Emission
Reduction
Requirements,
and
What
Are
EPA's
Responses?

Some
commenters
expressed
concern
that
EPA
did
not
account
for
growth
of
heat
input
in
calculating
regionwide
NOx
emissions
budgets,
noting
that
growth
was
used
in
the
calculation
of
the
regional
budget
for
the
NOx
SIP
Call.
Commenters
suggest
that,

by
not
taking
heat
input
growth
into
account,
EPA
developed
regionwide
budgets
that
are
unduly
stringent.

On
the
other
hand,
some
commenters
noted
that
they
supported
59
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
EPA's
proposal
to
base
regionwide
budgets
on
historical
heat
input
and
did
not
want
EPA
to
use
growth
projections
for
calculating
regionwide
NOx
emissions
budgets.
Some
stated
that
using
actual,
historic
heat
input
numbers
would
be
more
straightforward
than
using
growth
projections,
and
some
pointed
to
complications
with
the
growth
projection
methodologies
used
in
the
NOx
SIP
Call.

EPA
recognizes
that
it
employed
a
growth
factor
in
the
NOx
SIP
Call.
There,
EPA
determined
the
amount
of
the
regional
emissions
reductions
and
budgets
by
applying
a
growth
factor
to
a
historic
heat
input
baseline.
The
D.
C.
Circuit,
after
first
remanding
that
growth
methodology
for
a
better
explanation,

upheld
it.
West
Virginia
v.
EPA,
362
F.
3d
861
(
D.
C.
Cir.
2004).

See
67
FR
21,868
(
May
1,
2002).

For
CAIR,
as
described
above,
EPA
developed
a
target
level
for
the
proposed
NOx
regionwide
cap
based
on
recent
historic
heat
input
and
assumed
emission
rates
of
0.125
lb/
mmBtu
and
0.15
lb/
mmBtu
for
2015
and
2010,
respectively.
The
EPA
evaluated
these
target
NOx
emissions
levels
using
IPM,
which
indicated
that
those
target
caps
 
in
conjunction
with
expected
electricity
demand
for
2015
and
2010
 
would
result
from
higher
heat
input
levels
and
lower
average
emissions
rates
(
about
0.11
lb/
mmBtu
and
0.14
lb/
mmBtu
for
2015
and
2010,
respectively)
than
the
amounts
60
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
assumed
in
developing
the
target
NOx
caps.
Most
importantly,
IPM
indicated
the
cost
levels
associated
with
those
projected
2015
and
2010
average
NOx
emission
rates,
and
EPA
has
determined
that
those
cost
levels
are
highly
cost­
effective.
For
the
final
rule,

EPA
revised
its
analyses
to
reflect
the
2009
initial
NOx
control
phase,
and
determined
that
the
final
CAIR
requirements
are
highly
cost­
effective.
EPA's
methodology,
in
which
the
CAIR
emissions
reductions
are
predicted
to
be
cost­
effective
under
conditions
of
projected
electricity
growth
that,
in
turn,
projects
heat
input
growth,
in
effect
accounts
for
heat
input
growth.
Moreover,
the
amount
of
heat
input
growth
is
the
amount
determined
by
IPM,
a
state­
of­
the­
art
model
of
the
electricity
sector
(
detailed
documentation
for
IPM
is
in
the
docket).

Some
commenters
suggested
that
EPA
adjust
the
NOx
regionwide
budget
amounts
to
include
heat
input
from
non­
Acid
Rain
units.

For
example,
some
suggested
adding
the
non­
Acid
Rain
unit
heat
input
amounts
that
EPA
used
in
apportioning
regionwide
NOx
budgets
to
the
States,
to
the
total
regionwide
heat
inputs
that
EPA
used
to
calculate
regionwide
NOx
budgets.

The
regionwide
budgets
determined
in
the
NPR
were
target
levels
developed
as
a
starting
point
for
further
evaluation.
The
regionwide
heat
input
amounts
and
NOx
emission
rates
used
to
develop
target
budget
levels
were
inherently
imprecise.
As
61
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
discussed
above,
IPM
modeling
indicates
that
the
projected
future
heat
input
amounts
(
based
on
electricity
growth)
are
greater
than
the
recent
historic
regionwide
amount
used
to
develop
the
target
budget
levels,
and
the
future
average
emission
rates
for
all
units
affected
by
CAIR
annual
NOx
controls
(
including
non­
Acid
Rain
units)
are
less
than
the
rates
used
to
develop
the
target
budget
levels.
IPM
indicates
that
the
target
regionwide
NOx
budget
levels
(
and
corresponding
future
average
NOx
emission
rates
and
heat
input
levels)
are
highly
cost­
effective
for
all
CAIR
units,
including
non­
Acid
Rain
units.
The
EPA
does
not
believe
it
is
necessary
to
adjust
the
target
regionwide
budget
levels
to
include
the
relatively
small
additional
amount
of
heat
input
from
non­
Acid
Rain
units.
The
method
the
Agency
used
to
develop
target
levels
was
not
intended
to
be
a
precise
methodology
for
determining
the
NOx
caps;
rather,
it
was
a
reasonable
method
for
selecting
a
target
level
to
be
evaluated
further.
Upon
evaluation
of
the
target
level,
EPA
determined
that
it
can
be
achieved
using
highly
cost­
effective
controls
for
all
affected
EGUs,
including
non­
Acid
Rain
units.

iii.
Analysis
of
NOx
Emission
Reduction
Requirements
for
Today's
Final
Rule
(
I)
Reference
Lists
of
Cost­
effective
Controls
For
today's
action,
EPA
updated
the
reference
list
of
62
14
The
updated
reference
list
includes
estimated
average
NOx
control
costs
under
BART.
The
BART
rule
has
been
proposed
but
not
finalized.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
controls
included
in
the
NPR
of
the
average
and
marginal
costs
per
ton
of
recent
NOx
control
actions.
The
EPA
systematically
developed
a
list
of
cost
information
from
recent
actions
and
proposed
actions.
The
Agency
sought
cost
information
for
actions
taken
by
EPA,
and
examined
the
comments
submitted
after
the
NPR
was
published,
to
identify
all
available
control
cost
information
to
provide
the
updated
reference
list
for
today's
preamble.
The
updated
reference
list
includes
both
average
and
marginal
costs
of
control
to
which
EPA
compares
the
CAIR
control
costs,
although
the
Agency
has
limited
information
on
marginal
costs
of
other
programs.

EPA's
updated
summary
of
average
costs
of
annual
NOx
controls
are
shown
in
Table
IV­
6.
The
results
of
this
reexamination
show
that
costs
of
recent
actions
are
generally
very
similar
to
those
identified
in
the
NOx
SIP
Call.
The
cost
figures
are
presented
in
1999
dollars.
14
63
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
TABLE
IV­
6.
 
AVERAGE
COSTS
PER
TON
OF
ANNUAL
NOx
CONTROLS
NO
x
Control
Action
Average
Cost
per
Ton
Marine
CI
Engines
Up
to
$
200
2
Off­
highway
Diesel
Engine
$
400
­
$
700
2
Nonroad
Diesel
Engines
and
Fuel
$
600
1
Marine
SI
Engines
$
1,200
­
$
1,800
2
Tier
2
Vehicle
Gasoline
Sulfur
$
1,300
­
$
2,300
2
Revision
of
New
Source
Performance
Standards
for
NOx
Emissions
­
EGUs
$
1,700
3
2007
Highway
Heavy
Duty
Diesel
Standards
$
1,600
­
$
2,100
2
National
Low
Emission
Vehicle
$
1,900
2
Tier
1
Vehicle
Standards
$
2,100
­
$
2,800
2
Revision
of
New
Source
Performance
Standards
for
NOx
Emissions
­
Industrial
Units
$
2,200
3
On­
board
Diagnostics
$
2,300
2
Texas
NO
x
Emission
Reduction
Grants
FY
2002
­
2003
$
300
­
$
12,700
4
Best
Available
Retrofit
Technology
(
BART)
for
Electric
Power
Sector
$
800
5
1
Control
of
Emissions
of
Air
Pollution
From
Nonroad
Diesel
Engines
and
Fuel;
Final
Rule
(
69
FR
39131;
June
29,
2004).
The
value
in
this
table
represents
the
long­
term
cost
per
ton
of
emissions
reduced
from
the
total
fuel
and
engine
program
(
cost
per
ton
of
emissions
reduced
in
the
year
2030).
This
value
includes
the
cost
for
NOx
plus
NMHC
reductions.
1999$
per
ton.
2
Control
of
Air
Pollution
from
New
Motor
Vehicles:
Heavy­
Duty
Engine
and
Vehicle
Standards
and
Highway
Diesel
Fuel
Sulfur
Control
Requirements;
Final
Rule
(
66
FR
5102;
January
18,
2001).
The
values
shown
for
2007
Highway
HD
Diesel
Stds
are
discounted
costs.
Costs
shown
in
this
table
include
a
VOC
component.
1999$
per
ton.
3
Proposed
Revision
of
Standards
of
Performance
for
Nitrogen
Oxide
Emissions
From
New
Fossil­
Fuel
Fired
Steam
Generating
Units;
Proposed
Revision
to
Reporting
Requirements
for
Standards
of
Performance
for
New
Fossil­
Fuel
Fired
Steam
Generating
Units;
Proposed
Rule
(
62
FR
36953;
July
9,
1997),
Table
4
(
the
Agency's
estimate
of
average
control
costs
was
unchanged
for
the
NSPS
revisions
final
rule,
published
September
5,
1998).
In
the
CAIR
NPR,
we
included
a
value
from
the
range
of
NOx
controls
for
coal­
fired
EGUs
from
Table
2
in
the
proposed
NSPS
proposed
rule
(
62
FR
36951).
1999$
per
ton.
4
Costs
shown
in
this
table
are
the
range
of
project
costs
reported
for
projects
that
were
FY
2002
­
2003
recipients
of
the
TERP
Emission
Reductions
Incentive
Grants
Program.
These
costs
may
not
be
in
1999
dollars.
(
www.
tnrcc.
state.
tx.
us/
oprd/
sips/
grants.
html)
5
The
EPA
IPM
modeling
2004,
available
in
the
docket.
The
EPA
modeled
the
Regional
Haze
Requirements
as
a
source
specific
0.2
lb/
mmBtu
NOx
emission
rate
limit.
Estimated
average
costs
based
on
this
modeling
are
$
800
per
ton
in
2015
64
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
and
2020.
1999$
per
ton.

Table
IV­
7
presents
modeled
marginal
costs
for
recent
State
annual
NOx
rules.

TABLE
IV­
7.
B
MARGINAL
COSTS
PER
TON
OF
REDUCTION,
RECENT
ANNUAL
NO
x
RULES
NO
X
Control
Action
Marginal
Cost
per
Ton
Texas
Rules
$
2,000
­
$
19,600
1
1
The
EPA
IPM
Base
Case
modeling
August
2004,
available
in
the
docket.
1999$
per
ton.
We
modeled
Senate
Bill
7
and
Ch.
117,
which
impose
varying
NOx
control
requirements
in
different
areas
of
the
State;
the
range
of
marginal
costs
shown
here
reflects
the
range
of
requirements.

The
EPA
does
not
believe
that
it
has
sufficient
information,

for
today's
rulemaking,
to
treat
controls
on
source
categories
other
than
certain
EGUs
as
providing
highly
cost­
effective
emissions
reductions.
The
CAA
§
110
permits
States
to
choose
the
sources
and
source
categories
that
will
be
controlled
in
order
to
meet
applicable
emission
and
air
quality
requirements.
This
means
that
some
States
may
choose
to
meet
their
CAIR
obligations
by
imposing
control
requirements
on
sources
other
than
EGUs.

As
examples
of
cost­
effective
actions
that
States
can
take
in
efforts
to
provide
for
attainment
with
the
air
quality
standards,
Table
IV­
8
presents
estimated
average
costs
for
potential
local
mobile
source
NOx
control
actions.
The
EPA
received
these
cost
data
during
the
public
comments
on
the
NPR.

TABLE
IV­
8.
 
AVERAGE
COSTS
OF
POTENTIAL
LOCAL
MOBILE
SOURCE
CONTROL
ACTIONS
TO
REDUCE
NOx
EMISSIONS
($
PER
TON)
1
65
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Source
Category
Average
Cost
per
Ton
MWCOG
Analysis:
Mobile
Source,
Bicycle
racks
in
DC
$
9,000
MWCOG
Analysis:
Mobile
Source,
Telecommuting
Centers
$
7,300
MWCOG
Analysis:
Mobile
Source,
Government
Action
Days
(
ozone
action
days)
$
5,000
MWCOG
Analysis:
Mobile
Source,
Permit
Right
Turn
on
Red
$
1,200
MWCOG
Analysis:
Mobile
Source,
Employer
Outreach
$
3,500
MWCOG
Analysis:
Mobile
Source,
Mass
Marketing
Campaign
$
2,900
MWCOG
Analysis:
Mobile
Source,
Transit
Prioritization
$
8,500
1
Washington
DC
Metro
Area
MWCOG
Analysis
of
Potential
Reasonably
Available
Control
Measures
(
RACM).
Projects
determined
to
be
"
Possible"
by
MWCOG
but
not
RACM
because
benefits
from
the
possible
control
measures
do
not
meet
the
8.8
tpd
NOx
or
34.0
tpd
VOC
threshold
necessary
for
RACM.
These
costs
may
not
be
in
1999
dollars.
(
www.
mwcog.
org/
uploads/
committeedocuments
z1ZZXg20040217144350.
pdf)
Comments
submitted
to
the
EPA
CAIR
docket
from
the
Clean
Air
Task
Force
et
al.,
dated
March
30,
2004,
included
costs
from
the
MWCOG
analysis.

(
II)
Cost
Effectiveness
of
CAIR
Annual
NOx
Reductions
Table
IV­
9
provides
the
average
and
marginal
costs
of
annual
NOx
reductions
under
CAIR
for
2009
and
2015.
These
costs
are
updated
from
the
NPR
figures
 
the
EPA
analyzed
the
costs
of
the
CAIR
using
an
updated
version
of
IPM
(
documentation
for
the
IPM
update
is
in
the
docket).
Further,
EPA
modified
the
modeling
to
match
the
final
CAIR
strategy
(
see
Section
IV.
A.
1
for
a
description
of
EPA's
CAIR
IPM
modeling).

CAIR
provides
for
a
Compliance
Supplement
Pool
(
CSP)
of
NOx
allowances
that
can
be
used
for
compliance
with
the
annual
NOx
66
15
The
CSP
consists
of
200,000
tons,
which
is
apportioned
to
each
of
the
23
States
and
the
District
of
Columbia
that
are
required
by
CAIR
to
make
annual
NOx
reductions,
as
well
as
the
2
States
(
Delaware
and
New
Jersey)
for
which
EPA
is
proposing
to
require
annual
NOx
reductions.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
reduction
requirements.
The
CSP
is
discussed
in
detail
later
in
this
preamble.
The
EPA
used
IPM
to
model
marginal
costs
of
CAIR
with
the
CSP.
The
magnitude
of
the
NOx
CSP
is
relatively
small
compared
to
the
annual
NOx
budget15,
thus
the
CSP
does
not
significantly
impact
the
marginal
costs
(
see
Table
IV­
9).

As
with
SO2
marginal
costs,
EPA
considered
the
sensitivity
of
the
NOx
marginal
cost
results
to
assumptions
of
higher
electric
growth
and
future
natural
gas
prices
than
the
Agency
used
in
the
base
case,
as
shown
in
Table
IV­
9.

TABLE
IV­
9.
 
ESTIMATED
COSTS
PER
TON
OF
ANNUAL
NOx
CONTROLLED
UNDER
CAIR
1
Type
of
Cost
Effectiveness
2009
2015
Average
Cost
­
Main
Case
$
500
$
700
Marginal
Cost
­
Main
Case
$
1,300
$
1,600
Marginal
Cost
B
With
Compliance
Supplement
Pool
(
CSP)
$
1,300
$
1,600
Sensitivity
Analysis:
Marginal
Cost
Using
Alternate
Electricity
Growth
and
Natural
Gas
Price
Assumptions
$
1,400
$
1,700
1
The
EPA
IPM
modeling
2004,
available
in
the
docket.
1999$
per
ton.

These
estimated
NOx
control
costs
under
CAIR
reflect
annual
EGU
NOx
caps
of
1.5
million
tons
in
2009
and
1.3
million
tons
in
67
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
2015
within
the
CAIR
annual
NOx
control
region
(
the
23
States
and
DC
that
must
make
annual
reductions).
In
both
the
main
IPM
modeling
case
and
the
modeling
case
that
includes
the
CSP,

projected
annual
NOx
emissions
in
the
CAIR
region
will
be
about
1.5
million
tons
in
2009
and
1.3
million
tons
in
2015.
The
projected
emissions
are
very
similar
in
both
modeling
cases
because
the
CSP
is
relatively
small
compared
to
the
annual
NOx
budget.

Average
costs
shown
for
2015
are
based
on
the
amount
of
reductions
that
would
achieve
the
total
difference
in
projected
emissions
between
the
base
case
conditions
and
CAIR
in
the
year
2015.
These
costs
are
not
based
on
the
increment
in
reductions
between
2009
and
2015.
(
A
more
detailed
description
of
the
final
CAIR
SO2
and
NOx
control
requirements
is
provided
later
in
today's
preamble.)

Most
of
the
States
subject
to
today's
PM2.5
control
requirements
have
been
subject
to
the
NOx
SIP
Call
requirements.

Some
sources
in
these
States
have
installed
SCRs,
and
run
them
during
the
ozone
season.
These
sources
might
comply
with
the
PM2.5
annual
NOx
requirements
by,
at
least
in
part,
running
the
SCR
controls
for
the
remaining
months
of
the
year.
Under
these
circumstances,
the
compliance
costs
for
the
PM2.5
SIP
requirements
are
lower.
68
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Table
IV­
10
provides
estimated
costs
per
ton
of
NOx
for
nonozone
season
reductions
under
CAIR.
These
figures
are
updated
from
the
NPR
calculations
 
the
EPA
analyzed
the
costs
of
the
CAIR
using
an
updated
version
of
IPM
(
documentation
for
the
IPM
update
is
in
the
docket)
and
modeled
controls
on
a
region
that
more
closely
matches
the
region
affected
by
CAIR.

TABLE
IV­
10.
 
PREDICTED
COSTS
PER
TON
OF
NON­
OZONE
SEASON
NOx
CONTROLLED
UNDER
CAIR
1
Type
of
Cost
Effectiveness
2009
2015
Average
Cost
$
500
$
500
1
The
EPA
IPM
modeling
2004,
available
in
the
docket.
1999$
per
ton.

The
estimated
non­
ozone
season
NOx
costs,
like
the
annual
NOx
costs,
are
on
the
low
end
of
the
cost
effectiveness
range
described
in
Table
IV­
6.
The
EPA
considers
the
2015
and
also
the
2009
costs
to
represent
highly
cost­
effective
controls.

Environmental
Defense
reached
similar
conclusions
regarding
the
cost
effectiveness
of
non­
ozone
season
NOx
reductions,
as
described
in
their
report
"
A
Plan
for
All
Seasons:
Costs
and
Benefits
of
Year­
Round
NOx
Reductions
in
Eastern
States
(
2002)".

As
stated
in
that
report,
"[
As
Figure
4
shows,]
extending
NOx
reductions
throughout
the
year
results
in
dramatic
decreases
in
the
per­
ton
costs
of
NOx
emission
reductions
for
the
19
NOx
SIP
Call
States.
This
is
because
the
bulk
of
the
cost
for
reducing
69
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
NOx
emissions
from
power
plants
lies
in
the
capital
investment
in
the
control
equipment.
Once
the
primary
investment
has
been
made,
it
costs
relatively
little
to
continue
running
the
control
equipment
beyond
the
summer
months
required
by
EPA's
NOx
SIP
Call."
Environmental
Defense
based
these
conclusions
on
analysis
conducted
by
Resources
for
the
Future
(
RFF).
In
an
RFF
paper,

"
Cost­
Effective
Reduction
of
NOx
Emissions
from
Electricity
Generation
(
July
2001)",
RFF
draws
similar
conclusions.

(
III)
NOx
Cost
Comparison
for
CAIR
Requirements
The
EPA
believes
that
selecting
as
highly
cost­
effective
amounts
at
the
lower
end
of
these
average
and
marginal
cost
ranges
is
appropriate
for
reasons
explained
above
in
section
IV
of
this
preamble.

As
discussed
above,
although
in
the
NOx
SIP
Call
the
cost
level
selected
was
not
at
the
low
end
of
the
reference
range
of
costs,
if
the
SIP
Call
costs
were
for
annual
rather
than
seasonal
controls
they
would
have
been
lower
relative
to
the
other
control
costs
on
the
reference
list
which
were
mostly
for
annual
programs.

For
annual
NOx,
the
range
of
average
cost
effectiveness
extends
broadly,
from
under
$
200
to
thousands
of
dollars
(
Table
IV­
6).
The
2015
estimated
average
costs
for
CAIR
annual
NOx
control
of
$
700
are
consistent
with
the
lower
end
of
this
range.
70
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Less
information
is
available
for
the
marginal
costs
of
controls
than
for
average
costs.
Looking
at
the
available
marginal
costs
(
Table
IV­
7),
the
2015
CAIR
marginal
costs
for
annual
NOx
controls
are
at
the
lower
end
of
the
range.
The
EPA
also
evaluated
the
cost
effectiveness
of
the
2009
cap,
and
concluded
that
the
2009
requirements
are
highly
cost­
effective.

(
IV)
Cost
Effectiveness:
Marginal
Cost
Curves
for
Annual
NOx
Control
As
with
SO2
controls,
EPA
also
considered
the
cost
effectiveness
of
alternative
stringency
levels
for
NOx
control
for
today's
action
by
examining
changes
in
the
marginal
cost
curve
at
varying
levels
of
emissions
reductions.
Figure
IV­
3
shows
that
the
"
knee"
in
the
2010
marginal
cost
effectiveness
curve
for
EGUs
 
the
point
where
the
cost
of
controlling
a
ton
of
NOx
begins
to
increase
at
a
noticeably
higher
rate
 
appears
to
occur
at
over
$
1,700
per
ton
of
NOx.
Although
EPA
conducted
this
marginal
cost
curve
analysis
based
on
an
initial
NOx
control
phase
in
2010,
the
results
would
be
very
similar
for
2009,
which
is
the
initial
NOx
phase
in
the
final
CAIR.
Figure
IV­
4
shows
that
the
"
knee"
in
the
2015
marginal
cost
effectiveness
curve
for
EGUs
appears
to
occur
at
over
$
1,700
per
ton
of
NOx.
(
The
EPA
based
these
marginal
NOx
cost
effectiveness
curves
on
the
71
16
EPA
is
using
the
knee
in
the
curve
analysis
solely
to
show
that
the
required
emissions
reductions
are
very
cost
effective.
The
marginal
cost
curve
reflects
only
emissions
reduction
and
cost
information,
and
not
other
considerations.
We
note
that
it
might
be
reasonable
in
a
particular
regulatory
action
to
require
emissions
reductions
past
the
knee
of
the
curve
to
reduce
overall
costs
of
meeting
the
NAAQS
or
to
achieve
benefits
that
exceed
costs.
As
in
the
case
of
SO2
controls,
described
above,
it
should
be
noted
that
similar
analysis
for
other
source
categories
may
yield
different
curves.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
electricity
growth
and
natural
gas
price
assumptions
in
the
main
CAIR
IPM
modeling
run.
Marginal
cost
effectiveness
curves
based
on
other
electric
growth
and
natural
gas
price
assumptions
would
look
different,
therefore
it
would
not
be
appropriate
to
compare
the
curves
here
to
the
marginal
costs
based
on
the
IPM
modeling
sensitivity
run
that
used
EIA
assumptions.)
The
EPA
used
the
Technology
Retrofitting
Updating
Model
(
TRUM),
a
spreadsheet
model
based
on
IPM,
for
this
analysis.
These
results
make
clear
that
this
rule
is
very
cost­
effective
because
the
control
level
is
below
the
point
at
which
the
cost
begins
to
increase
at
a
significantly
higher
rate.

In
this
manner,
these
results
corroborate
EPA's
findings
above
concerning
the
cost
effectiveness
of
the
emissions
reductions.
16
Figure
IV­
3
72
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Marginal
Cost
Curve
of
Abatement
for
Annual
NOX
Emissions
from
EGUs
in
2010
(
SO2
Emissions
at
5.3
million
tons)

$
1,000
$
1,500
$
2,000
$
2,500
$
3,000
0.50
1.00
1.50
2.00
2.50
Million
Tons
of
NOx
Emitted
in
CAIR
Region
Source:
EPA
TRUM
Analysis,
August
2004
Marginal
Cost
(
1999$/
ton)
NOx
Price
($/
ton)

Figure
IV­
4
73
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Marginal
Cost
Curve
of
Abatement
for
Annual
NOX
Emissions
from
EGUs
in
2015
(
SO2
Emissions
at
4.1
million
tons)

$
1,000
$
1,500
$
2,000
$
2,500
$
3,000
0.50
1.00
1.50
2.00
2.50
Million
Tons
o
f
NOx
Em
itte
d
in
CAIR
Region
Source
:
EPA
TRUM
Analy
sis,
August
2004
Marginal
Cost
(
1999$/
ton)

NOx
P
rice
($/
ton)
74
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
(
V)
Cost
Effectiveness
of
Ozone
Season
NOx
Reductions
The
CAIR
requires
ozone
season
NOx
emissions
reduction
for
all
States
determined
to
contribute
significantly
to
ozone
nonattainment
downwind
(
25
States
and
the
District
of
Columbia).

The
EPA
used
IPM
to
model
average
and
marginal
costs
of
the
ozone
season
reductions
assuming
EGU
controls.
In
this
modeling
case,

EPA
modeled
an
ozone
season
NOx
cap
for
the
region
affected
by
CAIR
for
downwind
ozone
nonattainment,
but
did
not
include
the
CAIR
annual
SO2
or
NOx
caps.
Based
on
that
modeling,
Table
IV­
11
provides
estimated
average
and
marginal
costs
of
regionwide
ozone
season
NOx
reductions
for
2009
and
2015.
Table
IV­
11
shows
the
estimated
cost
effectiveness
of
today's
ozone
season
NOx
control
requirements
for
8­
hour
transport
SIPs.

TABLE
IV­
11.
B
ESTIMATED
COSTS
PER
TON
OF
OZONE
SEASON
NO
x
CONTROLLED
UNDER
CAIR
1
Type
of
Cost
Effectiveness
2009
2015
Average
Cost
$
900
$
1,800
Marginal
Cost
$
2,400
$
3,000
1
The
EPA
IPM
modeling
2004,
available
in
the
docket.
1999$
per
ton.

These
estimated
NOx
control
costs
are
based
on
ozone
season
EGU
NOx
caps
of
0.6
million
tons
in
2009
and
0.5
million
tons
in
2015
within
the
CAIR
ozone
season
NOx
control
region.
Average
costs
shown
for
2015
are
based
on
the
amount
of
reductions
that
75
17
For
both
the
NOx
SIP
Call
and
CAIR,
the
NOx
control
costs
on
the
reference
lists
are
generally
for
annual
reductions.
The
EPA
compared
the
costs
of
ozone
season
reductions
under
the
NOx
SIP
Call,
as
well
as
ozone
season
CAIR
NOx
reductions,
to
the
annual
reduction
programs
on
the
reference
lists.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
would
achieve
the
total
difference
in
projected
emissions
between
the
base
case
conditions
and
CAIR
in
the
year
2015.
These
costs
are
not
based
on
the
increment
in
reductions
between
2009
and
2015.
(
A
more
detailed
description
of
the
final
CAIR
SO2
and
NOx
control
requirements
is
provided
later
in
today's
preamble.)

The
EPA
believes
that
selecting
as
highly
cost­
effective
amounts
at
the
lower
end
of
the
average
and
marginal
cost
ranges
is
appropriate
for
reasons
explained
above
in
section
IV
in
this
preamble.

In
the
NOx
SIP
Call,
EPA
identified
average
costs
of
$
2,500
(
1999$)
(
or
$
2,000
(
1990$))
as
highly
cost­
effective.
17
The
estimated
average
costs
of
regionwide
ozone
season
NOx
control
under
CAIR
are
$
1,800
per
ton
in
2015
and
$
900
per
ton
in
2009.

Thus,
with
respect
to
average
costs
the
controls
for
the
final
phase
(
2015)
cap,
which
are
below
the
$
2,500
identified
in
the
NOx
SIP
Call,
are
also
highly
cost­
effective,
as
are
those
for
the
2009
cap.
In
addition,
the
estimated
average
costs
of
CAIR
ozone
season
NOx
control
are
at
the
lower
end
of
the
reference
range
of
average
annual
NOx
control
costs
(
the
reference
list
of
average
annual
NOx
control
costs
is
presented
above).
76
18
In
the
NOx
SIP
Call
EPA
used
average,
not
marginal,
costs
to
evaluate
cost
effectiveness.
For
the
reasons
discussed
above
we
are
evaluating
both
average
and
marginal
costs
for
CAIR.

19
Estimated
costs
for
regionwide
CAIR
NOx
controls
during
the
ozone
season
are
higher
than
the
average
and
marginal
costs
for
CAIR
annual
NOx
controls.
This
is
because,
as
noted
above,
the
capital
costs
of
installing
NOx
control
equipment
would
be
largely
identical
whether
the
SCR
will
be
operated
during
the
ozone
season
only
or
for
the
entire
year.
However,
the
amount
of
reductions
would
be
less
if
the
control
equipment
were
operated
only
during
the
ozone
season
compared
to
annual
operation.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Similarly,
the
estimated
marginal
costs18
of
ozone
season
CAIR
NOx
controls
are
within
EPA's
reference
range
of
marginal
costs,
at
the
lower
end
of
the
range
(
the
reference
list
of
marginal
annual
NOx
control
costs
is
presented
above).
We
note
that
the
marginal
costs
in
the
reference
range
are
for
annual
NOx
reductions,
and
would
likely
be
higher
for
ozone
season
only
programs.
Considering
both
average
and
marginal
costs,
the
CAIR
ozone
season
control
level
is
highly
cost­
effective.

For
purposes
of
estimating
costs
of
ozone
season
control
under
CAIR,
EPA
set
up
this
modeling
case
with
CAIR
ozone
season
NOx
requirements
but
without
the
annual
NOx
requirements.
The
Agency
believes
that
the
cost
of
the
ozone
season
CAIR
requirements
will
actually
be
lower
than
the
costs
presented
here
because
interactions
will
occur
between
the
CAIR
annual
and
ozone
season
NOx
control
requirements.
19
In
addition,
for
States
in
both
programs,
the
same
controls
achieving
annual
reductions
for
77
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
PM
purposes
will
achieve
ozone
season
reductions
for
ozone
purposes;
this
is
not
reflected
in
our
cost­
per­
ton
estimates.

As
with
SO2
controls,
and
annual
NOx
controls,
EPA
also
considered
the
cost
effectiveness
of
alternative
stringency
levels
for
CAIR
NOx
reductions
for
ozone
purposes
by
examining
changes
in
the
marginal
cost
curve
at
varying
levels
of
emissions
reductions.
Figure
IV­
5
shows
that
the
"
knee"
in
the
2010
marginal
cost
effectiveness
curve
for
ozone
season
NOx
reductions
from
EGUs
 
the
point
where
the
cost
of
controlling
an
ozone
season
ton
of
NOx
begins
to
increase
at
a
noticeably
higher
rate
 
appears
to
occur
somewhere
between
$
3,000
and
$
4,000
per
ton
of
NOx.
Although
EPA
conducted
this
marginal
cost
curve
analysis
based
on
an
initial
NOx
control
phase
in
2010
the
results
would
be
very
similar
for
2009,
which
is
the
initial
NOx
phase
in
the
final
CAIR.
Figure
IV­
6
shows
that
the
"
knee"
in
the
2015
marginal
cost
effectiveness
curve
for
ozone
season
NOx
reductions
from
EGUs
appears
to
occur
somewhere
between
$
3,000
and
$
4,000
per
ton
of
NOx.
The
EPA
used
the
Technology
Retrofitting
Updating
Model
(
TRUM),
a
spreadsheet
model
based
on
the
IPM,
for
this
analysis.
These
results
make
clear
that
CAIR
NOx
reductions
for
ozone
purposes
are
very
cost­
effective
because
the
control
level
is
below
the
point
at
which
the
cost
begins
to
increase
at
a
significantly
higher
rate.
78
20
EPA
is
using
the
knee
in
the
curve
analysis
solely
to
show
that
the
required
emissions
reductions
are
very
cost
effective.
The
marginal
cost
curve
reflects
only
emissions
reduction
and
cost
information,
and
not
other
considerations.
We
note
that
it
might
be
reasonable
in
a
particular
regulatory
action
to
require
emissions
reductions
past
the
knee
of
the
curve
to
reduce
overall
costs
of
meeting
the
NAAQS
or
to
achieve
benefits
that
exceed
costs.
As
in
the
case
of
SO2
controls,
described
above,
it
should
be
noted
that
similar
analysis
for
other
source
categories
may
yield
different
curves.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
In
this
manner,
these
results
corroborate
EPA's
findings
above
concerning
the
cost
effectiveness
of
the
emissions
reductions.
20
79
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Marginal
Cost
Curve
of
Ozone
Season
NOx
Abatement
in
2010
(
Base
case
SO2
emissions)

$
2,000
$
2,500
$
3,000
$
3,500
$
4,000
$
4,500
$
5,000
$
5,500
$
6,000
$
6,500
$
7,000
­
0.10
0.20
0.30
0.40
0.50
0.60
0.70
Million
Tons
of
NOx
Emitted
in
CAIR
Ozone
Region
during
Ozone
Season
Marginal
Cost
(
1999
$/
ton)

NOx
Price
($/
ton)

Results
using
TRUM;
IPM
results
would
differ.
Figure
IV­
5
80
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
M
a
r
g
in
a
l
C
o
s
t
C
u
r
v
e
o
f
O
z
o
n
e
S
e
a
s
o
n
N
O
x
A
b
a
t
e
m
e
n
t
in
2
0
1
5
(
B
a
s
e
c
a
s
e
S
O
2
e
m
i
s
s
io
n
s
)

$
2
,
0
0
0
$
2
,
5
0
0
$
3
,
0
0
0
$
3
,
5
0
0
$
4
,
0
0
0
$
4
,
5
0
0
$
5
,
0
0
0
$
5
,
5
0
0
$
6
,
0
0
0
$
6
,
5
0
0
$
7
,
0
0
0
­
0
.1
0
0
.2
0
0
.
3
0
0
.4
0
0
.5
0
0
.
6
0
0
.7
0
M
i
l
l
i
o
n
T
o
n
s
o
f
N
O
x
E
m
i
t
t
e
d
i
n
C
A
IR
O
z
o
n
e
R
e
g
i
o
n
d
u
r
i
n
g
O
z
o
n
e
S
e
a
s
o
n
Marginal
Cost
(
1999
$/
ton)
N
O
x
P
r
i
c
e
(
$
/
t
o
n
)

R
e
s
u
lt
s
u
s
in
g
T
R
U
M
;
I
P
M
r
e
s
u
l
t
s
w
o
u
ld
d
i
f
f
e
r
.
Figure
IV­
6
81
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
B.
What
Other
Sources
Did
EPA
Consider
when
Determining
Emission
Reduction
Requirements?

1.
Potential
Sources
of
Highly
Cost­
Effective
Emissions
Reductions
In
today's
rulemaking,
EPA
determines
the
amount
of
regionwide
emission
reductions
required
by
determining
the
amount
of
emission
reductions
that
could
be
achieved
through
the
application
of
highly
cost­
effective
controls
on
certain
EGUs.

The
EPA
has
reviewed
other
source
categories,
but
concludes
that
for
purposes
of
today's
rulemaking,
there
is
insufficient
information
to
conclude
that
highly
cost­
effective
controls
are
available
for
other
source
categories.

b.
Mobile
and
Area
Sources
In
the
NPR
69
FR
4610,
EPA
explained
that
"
it
did
not
identify
highly
cost­
effective
controls
on
mobile
or
area
sources."
No
comments
were
received
suggesting
that
mobile
or
area
sources
should
be
controlled.
Therefore,
in
developing
emission
reduction
requirements,
EPA
is
not
assuming
any
emission
reductions
from
mobile
or
area
sources.

b.
Non­
EGU
Boilers
and
Turbines
The
largest
single
category
of
stationary
source
non­
EGUs
are
large
non­
EGU
boilers
and
turbines.
This
source
category
emits
both
SO2
and
NOx.
In
the
CAIR
NPR,
EPA
proposed
not
to
82
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
include
any
potential
SO2
or
NOx
emissions
reductions
from
non­
EGU
boilers
and
turbines
as
constituting
"
highly
costeffective
reductions
and
thus
to
be
taken
into
account
in
establishing
emissions
requirements
because
EPA
believed
it
had
insufficient
information
on
their
control
costs,
particularly
costs
associated
with
the
integration
of
NOx
and
SO2
controls.

In
addition,
based
on
information
EPA
does
have,
projected
base
case
(
without
CAIR)
emissions
of
SO2
and
NOx
from
these
sources
are
significantly
lower
than
projected
EGU
emissions.
The
EPA
projects
that
in
2010
under
base
case
conditions,
EGUs
would
contribute
70%
of
SO2
in
the
CAIR
region
compared
to
15%
from
non­
EGU
boilers
and
turbines
in
the
CAIR
region.
The
Agency
also
predicts
that
in
2010
under
the
base
case,
EGUs
would
contribute
25%
of
NOx
emissions
in
the
CAIR
region
compared
to
16%
from
non­

EGU
boilers
and
turbines
in
the
CAIR
region.
Thus,
simply
on
an
absolute
basis,
non­
EGU
emissions
are
relatively
less
significant
than
emissions
from
EGUs.
EPA
is
finalizing
its
proposed
approach
to
these
sources
and
has
not
based
today's
requirements
on
any
presumed
availability
of
highly
cost­
effective
emissions
reductions
from
non­
EGU
boilers
and
turbines.

A
number
of
commenters
believe
EPA
should
determine
that
emissions
reductions
from
non­
EGUs
should
be
taken
into
account
in
establishing
emission
requirements
because,
they
believe,
83
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
highly
cost­
effective
controls
are
available
for
these
sources.

These
commenters
argued
that
highly
cost­
effective
controls
are
available
for
these
sources
and
that
EPA
should
have
sufficient
emissions
and
control
cost
information
because
the
same
sources
were
included
in
the
NOx
SIP
Call.

In
addition,
while
it
is
true
that
these
sources
were
included
in
the
NOx
SIP
call,
EPA
only
addressed
NOx
reductions
from
these
sources.
Neither
SO2
reductions
nor
monitoring
of
SO2
emissions
is
required
by
the
NOx
SIP
call.
As
a
result,
for
these
sources,
EPA
has
less
reliable
SO2
emissions
data
and
very
little
information
on
the
integration
of
NOx
and
SO2
controls.

Although
EPA
has
more
information
on
NOx
emissions
from
these
sources
because
of
the
NOx
SIP
call
(
and
other
programs
in
the
northeastern
U.
S.),
the
geographic
coverage
of
the
CAIR
includes
some
States
that
were
not
included
in
the
NOx
SIP
call,
some
of
which
States
contain
significant
amounts
of
industry.
The
EPA
has
even
less
emissions
data
from
non­
EGUs
in
these
non­
SIP
call
States
affected
by
the
CAIR.
While
EPA
has
incorporated
State­
submitted
emissions
inventory
data
for
1999
into
its
analysis
for
the
CAIR,
even
this
data
is
generally
lacking
information
on
fuel,
sulfur
content,
and
existing
controls.

Without
this
data
it
is
very
difficult
to
assess
the
emission
reduction
opportunities
available
for
non­
EGU
boilers
and
84
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
turbines.
Furthermore,
with
regards
to
NOx,
many
non­
EGU
boilers
and
turbines
are
making
reductions
using
low
NOx
burners
(
the
control
technology
EPA
assumed
in
making
the
cost
effectiveness
determinations
in
the
SIP
Call).
Since
these
controls
are
operated
year­
round,
annual
emission
reductions
are
already
being
obtained
from
many
of
these
units.
Additional
reductions
would
likely
be
less
cost
effective.

Another
commenter
stated
that
non­
EGU
"
major
sources"
are
subject
to
the
requirements
of
title
V
of
the
Clean
Air
Act
and
therefore
EPA
should
have
adequate
emissions
data
provided
as
part
of
the
sources'
permitting
obligations.
However,
title
V
simply
requires
that
a
source's
permit
include
the
substantive
requirements
(
such
as
emission
monitoring
requirements)
imposed
by
other
sections
of
the
Clean
Air
Act
and
does
not
itself
impose
any
substantive
requirements.
Thus,
the
mere
fact
that
a
source
is
a
major
source
required
to
have
a
title
V
permit
does
not
mean
that
the
source
is
monitoring
and
submitting
emissions,
fuel,
and
control
device
data.
Many
such
sources
do
not,
in
fact,
provide
such
data.

One
commenter
submitted
cost
information
for
Flue
Gas
Desulfurization
(
FGD)
technology
applications
on
industrial
boilers.
However,
the
information
submitted
by
the
commenter
was
based
on
the
use
of
a
limited
number
of
technologies
and
for
a
85
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
limited
number
of
boiler
sizes.
The
EPA
does
not
believe
that
the
limited
information
demonstrates
that
SO2
emissions
from
these
sources
could
be
controlled
in
a
highly
cost­
effective
manner
across
the
entire
sector
in
question,
or
to
what
level
the
emissions
could
be
controlled.

Some
commenters
recommended
including
non­
EGU
boilers
and
turbines
because
in
the
future,
after
reductions
from
EGUs
are
made,
the
relative
contribution
of
non­
EGU
boilers
and
turbines
to
the
total
NOx
and
SO2
emissions
will
increase.
The
EPA
agrees
that
the
relative
contribution
of
non­
EGUs
to
total
NOx
and
SO2
emissions
will
increase
in
the
future
if
State's
choose
to
meet
their
CAIR
emission
reduction
obligations
solely
by
way
of
emission
reductions
made
by
EGUs.
However,
EPA
does
not
believe
that
this,
by
itself,
provides
any
basis
for
determining
that
in
the
context
of
this
rule
emissions
reductions
from
non­
EGUs
should
be
determined
to
be
highly
cost­
effective.
As
discussed
above,
EPA
believes
it
is
necessary
to
have
more
reliable
emissions
data
and
better
control
cost
information
for
these
sources
before
assuming
reductions
from
them
in
the
CAIR.
The
EPA
is
working
to
improve
its
inventory
of
emissions
and
control
cost
information
for
non­
EGU
boilers
and
turbines.
Specifically,
we
are
assessing
the
emission
inventory
submittals
for
2002
made
by
States
in
response
to
the
relatively
new
requirements
of
40
CFR
86
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Part
51
(
the
Consolidated
Emission
Reporting
Rule),
and
we
will
work
with
States
whose
submissions
appear
to
have
gaps
in
required
data.
We
also
note
that
EPA
provides
financial
and
technical
support
for
the
efforts
of
the
five
Regional
Planning
Organizations
to
coordinate
among
and
assist
States
in
improving
emission
inventories.

Another
commenter
expressed
concern
that
if
the
decision
whether
to
control
large
industrial
boilers
is
left
to
the
States,
the
result
may
be
inequitable
treatment
of
EGUs
on
a
State­
by­
State
basis,
particularly
with
respect
to
allowances,

and
therefore
it
would
make
sense
to
require
NOx
and
SO2
reductions
from
large
industrial
boilers.
Clean
Air
Act
section
110
leaves
the
ultimate
choice
of
what
sources
to
control
to
the
States,
and
EPA
cannot
require
States
to
control
non­
EGUs.
Even
if
EPA
had
included
reductions
from
non­
EGUs
in
determining
the
total
amount
of
reductions
required
under
the
CAIR,
EPA
could
not
have
required
any
State
to
achieve
those
reductions
through
emission
limitations
on
non­
EGUs.

The
recent
economic
circumstances
faced
by
the
manufacturing
sector
accentuates
EPA's
concerns
about
the
lack
of
reliable
emissions
data
and
control
information
regarding
non­
EGUs.
We
note
that
the
U.
S.
manufacturing
sector
was
adversely
affected
by
the
latest
business
cycle
slowdown.
As
noted
in
the
2004
87
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Economic
Report
of
the
President,
the
manufacturing
sector
was
hit
earlier,
longer,
and
harder
than
other
sectors
of
the
economy.
The
2004
Report
also
points
out
that,
although
manufacturing
output
has
dropped
much
more
than
real
GDP
during
past
business
cycles,
the
latest
recovery
has
been
unusual
because
it
has
been
weaker
for
the
manufacturing
sector
than
the
recovery
in
real
GDP.
The
disparity
across
sectors
(
and
even
within
individual
sectors)
in
the
economic
condition
of
firms
reinforces
EPA's
concerns
about
moving
forward
to
consider
emission
controls
on
non­
EGUs
at
this
time.

As
explained
elsewhere
in
this
preamble,
although
CAIR
does
not
require
that
States
achieve
the
required
emission
reductions
by
controlling
particular
source
categories,
we
expect
that
States
will
meet
their
CAIR
obligations
by
requiring
emission
reductions
from
EGUs
because
such
reductions
are
highly
cost­
effective.
We
believe
the
States
are
in
the
best
position
to
make
decisions
regarding
any
additional
control
requirements
for
non­
EGU
sources.
In
making
such
decisions,
States
may
take
into
consideration
all
relevant
factors
and
information,
such
as
differences
across
States
in
the
need
for
control,
differences
in
relative
contribution
of
various
sources,
and
differences
in
the
operating
and
economic
conditions
across
sources.

c.
Other
Non­
EGU
Stationary
Sources
88
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
In
the
NPR
and
in
the
technical
support
document
entitled
"
Identification
and
Discussion
of
Sources
of
Regional
Point
Source
NOx
and
SO2
Emissions
Other
Than
EGUs
(
January
2004)",
EPA
applied
a
similar
rationale
for
non­
EGU
stationary
sources
other
than
boilers
and
turbines.
For
SO2,
EPA
noted
that
the
emissions
from
such
sources
were
a
relatively
small
part
of
the
emissions
inventory,
and
we
also
noted
the
lack
of
information
on
costs.

For
NOx,
we
explained
that
more
information
was
available
than
for
SO2.
This
is
because
the
NOx
SIP
Call
included
consideration
of
emissions
control
measures
for
internal
combustion
(
IC)

engines
and
cement
kilns,
and
developed
cost
estimates
for
other
NOx­
emitting
categories
such
as
process
heaters
and
glass
manufacturing.
However,
we
believed
 
as
for
boilers
and
turbines,
discussed
above
 
that
insufficient
information
on
emission
control
options
and
costs,
was
available
to
apply
these
measures
to
the
entire
geographic
area
covered
by
the
proposed
rule.

No
adverse
comments
were
received
suggesting
inclusion
of
SO2
emission
reductions
from
non­
EGU
stationary
sources
other
than
boilers
and
turbines.
Accordingly,
EPA
has
determined
not
to
consider
SO2
reductions
from
these
other
non­
EGU
stationary
sources.

Several
commenters
suggested
that
EPA
should
have
been
able
89
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
to
consider
NOx
emissions
reductions
from
non­
EGU
categories
other
than
boilers
and
turbines,
such
as
internal
combustion
(
IC)

engines
and
refinery
fluid
catalytic
cracking
units.
These
commenters
believed
such
reductions
were
demonstrated
to
be
cost­
effective,
and
questioned
EPA's
assertion
that
insufficient
information
is
available.
Finally,
some
commenters
believe
EPA
should
have,
at
a
minimum,
required
that
controls
for
NOx
SIP
Call
sources
 
including
large
internal
combustion
engines
and
cement
kilns
 
should
be
extended
from
the
ozone
season
to
the
entire
year.

We
believe
it
likely
that
inclusion
in
today's
requirements
of
reductions
from
any
highly
cost­
effective
controls
 
if
available
 
for
these
categories
would
have
very
small
effects.

First,
most
of
the
States
included
in
the
CAIR
rule
were
also
included
in
the
NOx
SIP
Call,
so
that
many
of
the
emissions
reductions
that
would
be
available
from
these
sources
have
already
occurred
due
to
implementation
of
the
NOx
SIP
Call.

Second,
in
the
States
included
in
the
CAIR
rule,
but
which
were
not
covered
by
the
NOx
SIP
Call,
only
a
small
portion
of
NOx
emissions
come
from
cement
kilns
and
IC
engines
compared
to
EGUs.

Moreover,
in
some
parts
of
this
geographic
area,
in
particular
for
Texas,
many
sources
in
these
source
categories
are
already
regulated
under
ozone
nonattainment
plans
(
including
SIPs
for
the
90
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Texas
cities
of
Houston,
Galveston,
and
Dallas).

Regarding
the
commenters'
recommendation
that
extending
NOx
SIP
call
control
requirements
to
a
year­
round
basis
for
large
IC
engines
and
cement
kilns
should
be
considered
to
be
highly
costeffective
EPA
believes
that
few
emissions
reductions
would
be
achieved
from
doing
so.
The
types
of
controls
that
were
applied
in
the
NOx
SIP
Call
States,
while
required
to
be
in
place
only
during
the
ozone
season,
will,
as
a
practical
matter,
be
applied
on
a
year­
round
basis,
whether
or
not
so
required
by
today's
rule.
Most,
if
not
all,
of
the
NOx
SIP
Call
States
have
developed
regulations
to
control
NOx
emissions
from
IC
engines
and
cement
kilns
during
the
ozone
season.
The
control
of
choice
to
meet
these
reductions
from
large
lean
burn
IC
engines
is
low
emission
combustion
(
LEC),
which
for
retrofit
applications
is
a
substantial
equipment
modification
of
the
engine's
combustion
system.
The
engine
will
operate
with
LEC
year
round
because
this
modification
is
a
permanent
change
to
the
engine.
Most,
if
not
all,
new
large
lean­
burn
IC
engines
have
LEC.
In
addition,

yearround
emissions
controls
are
already
required
for
rich­
burn
engines
which
install
nonselective
catalyst
reduction
to
comply
with
the
recently
adopted
hazardous
air
pollutant
standards.

(
see
final
rule
for
reciprocating
internal
combustion
engines,
69
FR
33474,
June
15,
2004).
For
cement
kilns,
the
controls
of
91
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
choice
are
low
NOx
burners
and
mid­
kiln
firing.
Low
NOx
burners
(
LNB)
are
a
permanent
part
of
the
kiln,
so
that
the
kiln
will
operate
year­
round
with
LNB.
Mid­
kiln
firing
is
a
kiln
modification
for
which
a
solid
and
slow
burning
fuel
(
typically
tires)
is
injected
in
the
mid­
kiln
area.
Due
to
tipping
fees
and
fuel
credits,
mid­
kiln
firing
results
in
an
operating
cost
savings.
After
this
system
is
installed,
year­
round
operation
is
expected.
92
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
C.
Schedule
for
Implementing
SO2
and
NOx
Emissions
Reduction
Requirements
for
PM2.5
and
Ozone
1.
Overview
In
the
NPR,
EPA
proposed
a
two­
phased
schedule
for
implementing
the
CAIR
annual
emission
reduction
requirements:

implementation
of
the
first
phase
would
be
required
by
January
1,

2010
(
covering
2010­
2014),
and
that
for
the
second
phase
by
January
1,
2015
(
covering
after
2014).
The
EPA
based
its
proposal
on
its
analysis
of
engineering,
financial,
and
other
factors
that
affect
the
timing
for
installing
the
emission
controls
that
would
be
most
cost­
effective
 
and
are
therefore
the
most
likely
to
be
adopted
­
for
States
to
meet
the
CAIR
requirements.
Those
air
pollution
controls
are
primarily
retrofitted
flue
gas
desulfurization
(
FGD)
systems
(
scrubbers)
for
SO2
and
selective
catalytic
reduction
(
SCR)
systems
for
NOx
on
coal­
fired
power
plants.

The
EPA's
projections
showed
a
significant
number
of
affected
sources
installing
these
controls.
The
proposed
twophased
schedule
allowed
the
implementation
of
as
much
of
the
controls
as
feasible
by
an
early
date,
with
a
later
time
for
the
remaining
controls.

The
EPA
received
detailed,
technical
comments
from
commenters
who
argued
that
the
controls
could
not
be
implemented
93
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
until
later
than
proposed,
and
from
other
commenters
who
argued
that
the
controls
could
be
implemented
sooner
than
proposed.
The
EPA
has
reviewed
the
comments
and
has
conducted
additional
research
and
analyses
to
verify
availability
of
adequate
industrial
resources,
including
boilermakers,
for
constructing
the
emission
control
retrofits
required
by
CAIR.
These
analyses
are
based
on
conservative
assumptions,
including
those
suggested
by
the
commenters,
to
ensure
that
the
requirements
imposed
by
CAIR
do
not
result
in
shortages
of
the
required
resources
that
could
substantially
increase
construction
costs
for
pollution
controls
and
reduce
the
cost
effectiveness
of
this
program.

Today,
EPA
is
taking
final
action
to
require
the
annual
emissions
reductions
on
the
same
two­
phase
schedule
as
proposed.

However,
the
requirements
for
the
first
phase
include
two
separate
compliance
deadlines:
implementation
of
NOx
reductions
are
required
by
January
1,
2009
(
covering
2009­
2014)
and
that
for
SO2
reductions
by
January
1,
2010
(
covering
2010­
2014).
The
compliance
deadline
requirements
for
the
second
phase
are
the
same
as
proposed.
The
EPA
believes
that
its
action
is
consistent
with
the
Agency's
obligations
under
the
Clean
Air
Act
to
require
emission
reductions
for
obtaining
NAAQS
to
be
achieved
as
soon
as
practicable.
The
EPA
applied
the
same
criterion
in
implementing
94
21
The
NOx
SIP
Call
Rule
allowed
approximately
3­
1/
2
years
for
implementation
of
all
NOx
Controls.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
the
NOx
SIP
Call,
which
was
based
on
a
single­
phased
schedule.
21
2.
Engineering
Factors
Affecting
Timing
for
Control
Retrofits
a.
NPR
In
the
NPR,
EPA
identified
the
availability
of
boilermakers
as
an
important
constraint
for
the
installation
of
significant
amounts
of
SCR
and
FGD
retrofits.
Boilermakers
are
skilled
laborers
that
perform
various
specialized
construction
activities,
including
welding
and
rigging,
for
boilers
and
high
pressure
vessels.
The
air
pollution
control
devices,
such
as
scrubber
and
SCR
vessels,
require
boilermakers
for
their
construction.
Apprentices
with
no
prior
work­
related
experience
complete
a
four­
year
training
program,
to
become
full
boilermakers.
For
apprentices
with
relevant
experience,
this
training
period
could
be
shorter.
For
example,
union
members
representing
the
shipbuilding
trade
could
be
expedited
into
the
boilermaker
division
within
a
year.

The
boilermaker
constraint
was
considered
more
important
for
the
initiation
of
the
first
phase
of
CAIR,
since
the
NOx
SIP
Call
experience
had
shown
that
many
sources
would
be
adverse
to
committing
significant
funds
to
install
controls
until
after
SIPs
were
finalized.
With
the
States
required
to
finalize
SIPs
in
18
95
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
months
after
the
signing
of
the
final
rule,
the
sources
would
have
three
years
in
which
to
complete
purchasing,
construction,

and
startup
activities
associated
with
these
controls,
to
meet
the
proposed
CAIR
deadline.

The
EPA's
projections
showed
power
plants
installing
51.4
gigawatts
(
GW)
of
FGD
and
28.2
GW
of
SCR
retrofits
during
the
first
CAIR
phase.
These
projections
include
retrofits
for
CAIR
as
well
as
retrofits
for
Base
Case
policies
(
i.
e.,
retrofits
for
existing
regulatory
requirements).
We
estimated
the
total
boilermaker­
years
required
for
installing
these
controls
at
12,700,
which
was
based
on
the
boilermakers
being
utilized
over
a
period
of
18
months
during
the
installation
process.
Also,
based
on
the
projected
boilermaker
population
in
the
timeframe
relevant
to
the
installation
of
these
controls,
we
estimated
that
14,700
boilermaker­
years
were
available
over
the
same
18­
month
period.

The
availability
of
approximately
15
percent
more
boilermakeryears
than
required,
as
shown
by
these
estimates,
confirms
the
adequacy
of
this
critical
resource
for
CAIR
and
EPA
assumed
this
to
be
a
reasonable
contingency
factor.

The
EPA
also
determined
that
installation
of
the
projected
amounts
of
FGD
and
SCR
retrofits
could
be
completed
within
the
three­
year
period
available
for
CAIR.
This
determination
was
based
on
a
previous
report
prepared
by
EPA
for
the
proposed
Clear
96
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Skies
Act,
"
Engineering
and
Economic
Factors
Affecting
the
Installation
of
Control
Technologies
for
Multi­
Pollutant
Strategies",
(
docket
no.
OAR­
2003­
0053­
0106).
According
to
this
report,
an
average
of
21
months
are
required
to
install
SCR
on
one
unit,
and
27
months
to
install
a
scrubber
on
one
unit.
For
multiple
units
within
the
same
plant,
installation
of
controls
would
normally
be
staggered
to
avoid
operational
disruptions.
The
EPA
projected
that
the
maximum
number
of
multiple­
unit
controls
required
for
each
affected
facility
could
all
be
installed
within
three
years.
The
NPR
proposal
included
a
second
phase,
with
a
compliance
deadline
of
January
1,
2015.
The
EPA's
projections
showed
power
plants
installing
19.1
GW
of
FGD
and
31.7
GW
of
SCR
retrofits
by
2015,
which
included
retrofits
for
CAIR
as
well
as
retrofits
for
Base
Case
policies
(
i.
e.,
retrofits
for
existing
regulatory
requirements).
Availability
of
boilermaker
labor
was
not
an
important
constraint
for
this
phase.

b.
Comments
The
EPA
received
several
comments
relating
to
the
requirements
for
the
two­
phased
implementation
program,
the
emission
caps
and
compliance
deadline
for
each
phase,
and
resources
required
to
install
necessary
controls.
The
commenters
offered
opposing
viewpoints,
which
can
be
broadly
categorized
as
follows:
97
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
i.
Several
commenters
indicated
that
the
compliance
deadline
of
2010
for
the
first
phase
was
not
attainable
and
argued
that
EPA
should
either
extend
the
deadline,
or
set
higher
emission
caps
for
this
phase.
The
commenters
raised
the
following
specific
points
in
support
of
their
concerns:

(
I)
The
time
allowed
for
completing
various
activities
from
planning
to
startup
of
the
required
controls
was
not
sufficient.

Other
related
activities,
including
project
financing
and
obtaining
a
landfill
permit
for
the
scrubber
waste,
could
also
require
more
time
than
what
the
rule
allowed.
In
addition,
the
short
implementation
period
would
require
simultaneous
outages
of
too
many
units
to
tie
the
new
equipment
into
the
existing
systems,
which
would
affect
the
reliability
of
the
electrical
grid.

(
II)
Implementation
of
controls
to
the
required
large
number
of
units
would
cause
shortages
in
the
supply
of
critical
industrial
resources,
especially
boilermakers.
An
analysis
performed
by
a
commenter
showed
a
shortfall
in
the
supply
of
boilermaker
labor
during
the
construction
period
relevant
to
CAIR
retrofits.
This
commenter
anticipated
that
certain
key
variables
would
be
greater
in
value
than
those
used
by
EPA
and
based
their
analysis
on
higher
SCR
prices,
EIA­
projected
higher
natural
gas
prices
and
electricity
demand
factors,
and
more
stringent
98
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
boilermaker
duty
rates
(
boilermaker­
year/
MW)
and
availability
factors.

ii.
Commenters
who
favored
more
stringent
compliance
deadlines
argued
that
the
required
controls
could
be
installed
in
less
time
and
more
controls
could
be
built
in
early
years.
These
commenters
raised
the
following
specific
points
in
support
of
their
concerns:

(
I)
The
compliance
deadlines
for
the
two
phases
did
not
support
the
ozone
and
fine
particulate
(
PM2.5)
attainment
dates
mandated
by
the
Clean
Air
Act.
The
Phase
I
deadline
should
be
accelerated
to
meet
these
attainment
dates.
Sufficient
industrial
resources,
including
boilermakers,
would
be
available
to
support
such
an
acceleration.
While
some
commenters
supported
an
earlier
Phase
I
deadline
of
January
1,
2008,
the
others
supported
a
deadline
of
January
1,
2009.
Some
of
these
commenters
also
suggested
that
the
Phase
I
deadline
be
accelerated
only
for
NOx.

(
II)
The
EPA's
estimates
for
the
boilermaker
availability
were
too
conservative.
A
boilermaker
labor
analysis
performed
by
one
commenter
showed
an
adequate
supply
of
this
resource
to
support
installation
of
all
Phase
I
and
II
controls
by
the
start
of
the
first
phase
(
by
2010),
thereby
eliminating
the
need
for
two
phases.
99
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
(
III)
The
time
allowed
for
installing
controls
for
Phase
II
was
excessive.
The
initiation
of
this
phase
could
be
moved
forward.

iii.
Several
commenters
supported
EPA's
assumptions
used
in
support
of
the
adequacy
of
the
implementation
period
and
resources
to
build
the
required
CAIR
controls.
These
assumptions
included
the
overall
construction
schedule
durations
for
SCR
and
FGD
systems
and
boilermaker
unit
rates.

c.
Responses
The
EPA
reviewed
the
above
comments
and
performed
additional
research
and
analyses,
including
new
IPM
runs
that
incorporated
higher
SCR
and
natural
gas
costs
and
greater
electric
demand.
We
also
found
that
more
units
had
installed
SCR
under
the
NOx
SIP
Call
and
other
regulatory
actions
than
what
our
records
previously
showed.
This
increase
in
the
number
of
existing
SCR
installations
was
also
incorporated
into
these
IPM
runs.
In
addition,
the
number
of
existing
FGD
installations
was
also
revised
slightly
downward,
for
the
same
reason.

The
revised
IPM
analyses
for
today's
final
action
show
that
the
amounts
of
controls
that
need
to
be
put
on
for
Phase
I
are
39.6
GW
of
FGD
and
23.9
GW
of
SCR.
These
amounts
represent
a
reduction
from
the
estimates
for
the
NPR.
For
Phase
II,
the
amount
of
the
required
controls
are
32.4
GW
of
FGD
and
26.6
GW
of
100
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
SCR.
These
amounts
represent
an
increase
from
the
estimates
for
the
NPR.
The
amounts
shown
for
both
phases
reflect
all
retrofits
required
for
the
CAIR
and
Base
Case
(
Non­
CAIR)
policies.
The
retrofit
projections
for
the
Base
Case
policies
are
included,

since
some
of
the
available
boilermaker
labor
would
be
consumed
in
building
these
retrofits
during
the
CAIR
time­
frame.

The
EPA
also
contacted
the
International
Brotherhood
of
Boilermakers
(
IBB),
U.
S.
Bureau
of
Labor
Statistics
(
BLS),
and
National
Association
of
Construction
Boilermaker
Employers
(
NACBE)
to
verify
its
assumptions
on
boilermakers
population,

percentage
of
boilermakers
available
to
work
on
the
control
retrofit
projects,
and
average
annual
hours
of
boilermaker
employment.
Except
for
the
boilermaker
population,
the
information
received
as
a
result
of
these
investigations
validated
EPA's
assumptions.
IBB
also
confirmed
that
the
boilermaker
population
would
at
least
be
maintained
at
the
current
level
of
26,000
members,
during
the
period
relevant
to
construction
of
CAIR
retrofits.
It
did
not
want
to
forecast
growth
and
historically
has
not
done
so.
Therefore,
instead
of
the
28,000
boilermaker
forecasted
population
used
in
the
NPR,
we
have
conservatively
used
a
boilermaker
population
of
26,000
for
the
final
CAIR.
A
detailed
discussion
on
these
assumptions
and
the
information
received
from
these
sources
is
available
in
the
101
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
docket
to
this
rulemaking
as
a
technical
support
document
(
TSD),

entitled
"
Boilermaker
Labor
and
Installation
Timing
Analysis."

The
responses
to
the
most
significant
comments
on
these
issues
are
summarized
in
the
following
sections.

i.
Issues
Related
to
Compliance
Deadline
Extension
(
I)
Adequacy
of
Phase
I
Implementation
Period
Today's
action
initiates
State
activities
in
conjunction
with
EPA
to
set
up
the
administrative
details
of
CAIR.
With
the
first
phase
compliance
deadline
of
January
1,
2009,
for
NOx
and
January
1,
2010,
for
SO2,
the
affected
sources
would
have
approximately
3­
3/
4
and
4­
3/
4
years
for
the
implementation
of
the
overall
requirements
for
this
phase,
respectively.
The
final
SIPs
would
be
submitted
at
the
end
of
the
first
18
months
of
these
implementation
periods.
The
remaining
2­
1/
4
and
3­
1/
4
years
would
be
available
for
the
sources
to
complete
activities
required
for
the
procurement
and
installation
of
NOx
and
SO2
controls,
respectively.
For
the
reasons
outlined
below,
EPA
believes
that
these
deadlines
provide
enough
time
to
install
the
required
Phase
I
controls.

(
A)
Engineering/
Construction
Schedule
Issues
The
EPA
notes
that,
for
CAIR,
the
States
would
finalize
the
SIPs
in
18
months
after
the
rule
is
signed,
and
that
until
then,

the
majority
of
sources
required
to
install
controls
may
not
102
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
initiate
activities
that
require
commitment
of
major
funds.

However,
some
activities,
such
as
planning,
preparation
of
conceptual
designs,
selection
of
technologies,
and
contacts
with
equipment
suppliers
can
be
started
or
completed
prior
to
the
finalization
of
SIPs,
at
least
for
major
sources
expected
to
require
longer
implementation
periods.
In
addition,
other
activities,
such
as
permitting
and
financing
can
be
started
after
the
rule
is
finalized.
This
is
based
on
the
NOx
SIP
Call
experience.

After
the
SIPs
are
finalized,
the
sources
would
have
approximately
2­
1/
4
and
3­
1/
4
years
in
which
to
complete
purchasing,
detailed
design,
fabrication,
construction,
and
startup
of
the
required
NOx
and
SO2
controls,
respectively.
This
assumes
that
activities,
such
as
planning
and
selection
of
technologies,
have
already
been
started
or
completed,
prior
to
the
start
of
these
2­
1/
4­
and
3­
1/
4­
year
periods.
As
discussed
in
the
NPR
proposal,
EPA
projects
an
average
single­
unit
installation
time
of
21
months
for
SCR
and
27
months
for
a
scrubber.
Our
revised
IPM
analysis
for
the
final
rule
shows
that
many
facilities
would
install
controls
on
multiple
units
(
a
maximum
of
six
for
SCR
and
five
for
FGD)
at
the
same
plant.
We
expect
these
facilities
to
stagger
these
installations
to
minimize
operational
disruptions.
103
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
The
EPA
also
projects
that
SCRs
and
scrubbers
could
be
installed
on
the
multiple
units
in
the
available
time
periods
of
2­
1/
4
and
3­
1/
4
years,
respectively.
The
issues
related
to
the
availability
of
boilermakers
and
the
ability
of
the
plants
requiring
multiple­
unit
controls
to
stagger
their
installations
during
these
periods
are
discussed
later
in
this
preamble.

As
compared
to
projections
in
the
NPR
proposal,
earlier
signing
of
the
final
rule
adds
approximately
three
additional
months
to
the
overall
implementation
periods
for
both
NOx
and
SO2
controls.
Furthermore,
EPA's
projections
for
the
final
rule
show
fewer
Phase
I
NOx
and
SO2
controls
being
added
than
the
projections
in
the
NPR
proposal.
Since
the
compliance
deadline
for
NOx
has
been
moved
up
a
year
from
the
proposal,
a
three­
month
earlier
rule
promulgation
provides
more
time
for
implementing
SO2
controls
only.
However,
since
it
does
allow
use
of
critical
resources,
such
as
boilermakers,
for
SO2
controls
to
be
spread
over
a
longer
period
of
time,
the
net
effect
would
be
to
make
more
of
these
resources
available
for
both
SO2
and
NOx
controls
(
as
compared
to
a
scenario
where
promulgation
was
not
three
months
earlier).
This
is
especially
true
since
the
implementation
periods
for
both
NOx
and
SO2
controls
would
start
at
the
same
time
and
the
plants
installing
these
controls
would
be
competing
for
the
same
resources
until
January
1,
2009,
the
104
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
compliance
deadline
for
NOx.
The
EPA,
therefore,
believes
that
2­
1/
4­
and
3­
1/
4­
year
time
periods
provide
reasonable
amounts
of
time
from
the
approval
of
State
programs
by
September
2006,
until
the
commencement
of
compliance
deadlines
for
meeting
the
NOx
and
SO2
emission
requirements.

Certain
commenters
have
provided
their
own
estimates
of
schedule
requirements
for
installing
the
required
controls.
In
some
cases,
these
estimates
are
longer
than
those
determined
by
EPA.
For
scrubbers,
including
spray
dryer
and
wet
limestone
or
lime
type
systems,
the
control
implementation
requirements
provided
by
the
commenters
range
from
30
to
54
months
for
the
overall
project
and
18
to
36
months
for
the
phase
following
equipment
awards.
In
this
case,
the
lowest
18­
month
schedule
requirement
cited
applies
to
spray
dryers,
whereas
the
shortest
schedule
cited
for
wet
scrubbers
for
the
activities
following
the
equipment
awards
is
24
months.
For
SCR,
the
control
implementation
requirements
cited
by
the
commenters
range
from
24
to
36
months
for
the
overall
project
and
17
to
25
months
for
the
phase
following
the
equipment
awards.

One
commenter
has
pointed
out
that
the
construction
schedule
requirements
for
the
FGD
and
SCR
retrofit
projects
have
shortened,
because
of
the
lessons
learned
from
a
significant
number
of
such
projects
completed
during
the
last
few
years.
The
105
22
Reference:
Announcement
by
Wheelabrator
Air
Pollution
Control
Inc.
for
award
of
a
wet
limestone
scrubber
system
for
K.
C.
Coleman
Generating
Station,
Western
Kentucky
Energy
Corp.,
August
2,
2004,
and
other
related
documents.
(
docket
no.
OAR­
2003­
0053­
1953)

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
EPA
notes
that
a
recent
announcement
for
a
new
485
MW
limestone
scrubber
facility
indicates
a
construction
schedule
duration
(
from
equipment
award
to
startup)
of
only
18
months.
22
This
is
well
below
the
schedule
requirement
cited
by
the
commenters
for
a
wet
limestone
scrubber.

The
EPA
also
notes
that
most
of
the
commenters'
schedule
estimates
are
consistent
with
the
time
periods
available
for
completing
the
CAIR­
related
NOx
and
SO2
projects.
Some
of
the
longer
schedules
submitted
by
commenters
would
exceed
the
CAIR
Phase
I
dates.
However,
EPA
considers
these
longer
schedules
to
be
speculative,
as
these
commenters
did
not
justify
them.
The
major
factors
that
influence
schedule
requirements
include
size
of
the
installation,
degree
of
retrofit
difficulty,
and
plant
location.
The
EPA
does
not
expect
these
factors
to
make
a
difference
of
more
than
a
few
months
between
the
schedule
requirements
of
various
installations.
The
commenters
who
have
cited
long
schedule
requirements
that
fall
at
the
higher
end
of
the
above
ranges
have
not
provided
any
data
to
support
the
wide
differences
between
their
schedules
and
those
proposed
by
others,

including
EPA.
It
should
also
be
noted
that
EPA's
schedules
are
106
23
Summary
of
telephone
calls
with
States
to
discuss
landfill
permit
timing
(
docket
no.
OAR­
2003­
0053­
1927)

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
based
on
information
from
several
actual
SCR
and
scrubber
installations.
Therefore,
EPA
cannot
accept
the
excessive
schedule
requirements
proposed
by
these
commenters.

(
B)
Landfill
Permit
Issue
The
EPA
contacted
several
key
States
requiring
FGD
retrofits,
to
investigate
the
amount
of
time
required
to
obtain
a
landfill
permit
for
scrubber
waste.
We
note
that
not
all
scrubber
installations
would
require
landfills,
as
some
scrubber
designs
produce
saleable
waste
products,
such
as
gypsum.

Specifically,
EPA
contacted
Georgia,
Ohio,
Indiana,
Alabama,

Pennsylvania,
West
Virginia,
Tennessee,
and
Kentucky.
23
Except
for
Kentucky,
all
States
indicated
that
their
permit
approval
periods
ranged
from
12
to
27
months.
Some
of
these
States
indicated
that
permit
approval
may
require
more
time
than
27
months,
but
only
for
the
cases
in
which
major
landfill
design
issues
persist
or
the
permit
applicant
has
not
provided
complete
and
proper
information
with
the
permit
application.

The
Kentucky
Department
of
Environmental
Protection
indicated
that,
based
on
their
historical
records,
the
average
permit
approval
period
was
3­
1/
2
years.
They
also
stated
that
the
State
was
sensitive
to
an
applicant's
time
restrictions
and
107
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
the
permit
approval
times
had
varied
depending
on
the
level
of
urgency
surrounding
a
permit
application.
They
further
confirmed
that
they
would
work
with
the
industry
to
meet
compliance
deadlines,
such
as
those
required
by
CAIR,
as
efficiently
as
possible.

Based
on
the
above
investigations,
EPA
notes
that
the
landfill
permitting
requirements
quoted
by
all
States
fall
well
within
the
4­
3/
4­
year
implementation
period
for
Phase
I.
Also,

landfill
permitting
activities
as
well
as
its
design
and
construction
can
be
accomplished,
independent
of
the
design
and
construction
of
the
FGD
system.
The
EPA,
therefore,
believes
that
landfill
permitting
is
not
a
constraint
for
compliance
with
the
rule.

(
C)
Project
Financing
Issue
Commenters
representing
small
units
or
units
owned
by
the
co­
operatives
raised
concerns
that
arrangement
of
financing
for
control
retrofits
could
take
long
periods
of
time.
However,

EPA's
projections
show
a
larger
portion
of
the
smaller
units
installing
controls
only
during
the
second
phase.
These
projections
also
show
that
only
a
few
co­
operative
units
would
require
installation
of
controls.
Therefore,
EPA
believes
that
the
Phase
I
implementation
periods
of
approximately
3­
3/
4
and
4­

3/
4
years
for
NOx
and
SO2
controls,
respectively,
provide
enough
108
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
time
for
completing
the
financing
activity
for
all
controls.
Of
course,
if
individual
sources
face
difficulties
in
meeting
deadlines
to
implement
controls,
they
may
use
the
allowance­
trading
provisions
of
CAIR
to
defer
implementation
of
controls.

(
D)
Electrical
Grid
Reliability
Issue
Based
on
available
data
for
the
NOx
SIP
Call,
approximately
68
GW
of
SCR
retrofits
were
started
up
during
the
years
from
2001
to
2003.
This
included
approximately
42
GW
of
SCRs
in
2003
alone,
which
exceeds
the
combined
capacity
of
SCR
and
FGD
retrofits
for
CAIR
that
we
expect
to
be
started
up
in
any
one
year.
The
EPA
projects
that
startup
of
the
23.9
GW
of
SCR
and
39.6
GW
of
FGD
capacity
required
for
Phase
I
would
be
spread
over
a
period
of
two
years
(
2008
and
2009).
The
total
capacity
of
units
starting
up
in
each
year
is
therefore
expected
to
be
approximately
32
GW
(
half
of
the
combined
SCR
and
FGD
capacity
of
63.5
GW).

The
NOx
SIP
Call
experience
shows
that
outages
required
to
complete
installation
of
the
large
SCR
capacity,
especially
during
2003,
did
not
have
an
adverse
impact
on
the
electrical
grid
reliability.
The
EPA
notes
that
the
outage
requirement
for
SCR
usually
exceeds
that
for
scrubber,
since
SCR
is
located
closer
to
the
boiler
and
it
may
be
more
intrusive
to
the
existing
109
24
Reference:
"
NERC,
Generating
Availability
Data
System:
All
MW
Sizes
­
Coal­
Fired
Generation
Report,
http://
www.
nerc.
com/~
filez/
gar.
html,
October
17,
2003
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
equipment.
As
shown
above,
the
CAIR
retrofits
are
projected
to
include
more
scrubbers
than
SCRs
and
the
capacity
of
these
retrofits
starting
up
in
any
one
year
is
below
the
capacity
of
the
NOx
SIP
Call
units
that
started
up
in
2003.
Therefore,
the
overall
outage
requirement
for
CAIR
would
be
less
than
that
experienced
for
the
NOx
SIP
Call.

Based
on
published
industry
data,
the
planned
outage
times
for
coal­
fired
units
from
2001­
2002
(
SCR
buildup
years)
decreased
by
over
two
percent
compared
to
the
previous
two
years
from
1998­
1999.24
The
reduction
in
the
overall
outage
time
in
the
2001­
2002
period
also
shows
that
the
SCR
retrofits
did
not
adversely
affect
the
grid
reliability.
Therefore,
EPA
believes
that
the
concern
regarding
electrical
grid
reliability
is
unwarranted
for
CAIR
retrofits.

(
II)
Availability
of
Boilermaker
Labor
in
Phase
I
The
EPA
has
performed
several
analyses
to
verify
the
adequacy
of
the
available
boilermaker
labor
for
the
installation
of
CAIR's
Phase
I
controls.
These
analyses
were
not
just
based
on
using
EPA's
assumptions
for
the
key
factors
affecting
the
boilermaker
availability,
but
also
the
assumptions
suggested
by
commenters
for
these
factors
to
determine
how
sure
we
could
be
on
110
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
our
key
conclusions.
If
there
was
insufficient
labor
for
the
amount
of
air
pollution
controls
that
will
need
to
be
installed,

the
program
would
be
in
jeopardy.
For
instance,
shortages
in
manpower
could
lead
to
high
wage
rates
that
could
substantially
increase
construction
costs
for
pollution
controls
and
reduce
the
cost
effectiveness
of
this
program.
During
the
peak
of
the
NOx
SIP
Call
SCR
construction
period,
the
power
industry
did
experience
an
increase
in
the
SCR
construction
costs.
One
of
the
reasons
cited
for
these
higher
costs
was
an
increased
demand
for
boilermaker
labor.
The
EPA
strongly
wanted
to
avert
this
possibility
for
CAIR.
The
EPA
also
wanted
to
be
very
sure
that
the
levels
of
controls
and
timing
of
the
program's
start
were
appropriate.
Therefore,
EPA
tended
to
make
conservative
assumptions
and
to
test
the
sensitivity
of
key
assumptions
that
were
uncertain.

Boilermakers
population,
percentage
of
boilermakers
available
to
work
on
the
control
retrofit
projects,
and
average
annual
hours
of
boilermaker
employment
are
some
of
the
key
factors
that
affect
boilermaker
availability.
As
discussed
previously,
EPA's
assumptions
on
these
factors
were
validated
or
revised
through
our
discussions
with
IBB,
BLS,
and
NACBE.

Two
other
key
factors
that
also
have
an
impact
on
boilermaker
availability
include
the
number
of
required
SCR
and
111
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
FGD
retrofits
and
boilermaker
duty
rates
(
boilermaker­
year/
MW,

i.
e.,
the
number
of
boilermaker
years
needed
to
install
SCR
or
FGD
on
one
MW
of
electric
generation
capacity).
The
EPA's
projections
for
the
required
SCR
and
FGD
retrofits
are
based
on
the
IPM
analyses
performed
for
the
final
rule.
The
basis
for
the
boilermaker
duty
rates
used
by
EPA
is
a
report
prepared
by
EPA
for
the
proposed
Clear
Skies
Act,
"
Engineering
and
Economic
Factors
Affecting
the
Installation
of
Control
Technologies
for
Multi­
Pollutant
Strategies."

Some
commenters
have
suggested
use
of
EIA's
projections
of
natural
gas
prices
and
electricity
demand
rates
that
are
higher
than
EPA's
projections
used
in
the
IPM
analyses.
Use
of
higher
values
for
these
parameters
would
increase
the
number
of
required
control
retrofits.
While
not
agreeing
with
these
commenters
that
EIA's
projections
should
replace
the
data
that
EPA
uses,
we
acknowledge
that
there
is
reasonable
uncertainty
concerning
these
assumptions
and
that
addressing
the
uncertainty
explicitly
by
considering
EIA's
alternative
assumptions
is
prudent,
given
the
importance
of
having
sufficient
labor
resources
to
meet
the
program's
requirements
in
2010.
Therefore,
EPA
has
performed
a
sensitivity
analysis
to
determine
the
required
control
retrofits
resulting
from
the
use
of
these
EIA
projections,
and
then
used
112
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
the
increased
amounts
of
the
required
control
retrofits
to
determine
their
impacts
on
the
boilermaker
availability.

The
EPA
also
received
comments
suggesting
that
the
SCR
costs
used
in
our
IPM
analyses
were
below
the
levels
experienced
in
recent
SCR
installations.
We
note
that
the
SCR
costs
were
revised
in
the
IPM
analyses
performed
for
the
final
rule,
to
reflect
recent
industry
experience.
One
commenter
reported
SCR
capital
costs
that
exceeded
our
revised
costs.
The
EPA
does
not
agree
with
these
reported
costs,
as
they
are
not
supported
by
the
overall
cost
data
submitted
by
the
commenter.
However,
to
address
the
concern
with
the
SCR
costs
in
general,
we
have
performed
a
sensitivity
analysis
to
determine
the
impact
of
increasing
the
SCR
capital
and
fixed
O&
M
costs
by
30
percent.

An
increase
in
the
SCR
costs
would
affect
the
amounts
of
the
required
control
retrofits.
Table
IV­
12
shows
the
projected
Phase
I
SCR
and
FGD
retrofits
for
the
above
two
alternate
cases,

based
on
using
EIA's
projections
for
natural
gas
prices
and
electricity
demand
rates
and
higher
SCR
costs.
113
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
TABLE
IV­
12.
B
IPM
Projections
for
Total
Capacities
of
FGD
and
SCR
Retrofit
Projects
for
Coal­
Fired
Electric
Generation
Units
for
CAIR
Phase
I
Using
EPA
and
Commenter
Assumptions
Retrofit
Type
EPA
Base
Case
Assumptions
EIA
Projections1
EIA
Projections
and
Higher
SCR
Costs2
CAIR
FGD,
GW
37
45.4
47.9
Non­
CAIR
FGD,
GW
2.6
3.7
Included
Above
CAIR
SCR,
GW
18.2
20.6
25.2
Non­
CAIR
SCR,
GW
5.7
4.6
Included
Above
1
The
required
control
retrofits
shown
are
based
on
using
EIA
projections
for
natural
gas
prices
and
electricity
demand
rates.

2
The
required
control
retrofits
shown
are
based
on
using
EIA
projections
for
natural
gas
prices
and
electricity
demand
rates
as
well
as
30
percent
higher
SCR
capital
and
fixed
O&
M
costs.

As
shown
in
the
above
Table
IV­
12,
the
alternate
case
using
just
the
EIA's
projections
for
natural
gas
prices
and
electricity
demand
rates
requires
the
largest
amounts
of
control
retrofits.

Therefore,
a
boilermaker
availability
analysis
was
performed
for
just
this
case.

One
commenter
has
suggested
use
of
higher
boilermaker
duty
rates
for
both
SCR
and
FGD
retrofits,
based
on
an
industry
survey
they
had
conducted.
Use
of
higher
duty
rates
would
result
in
114
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
more
boilermakers
being
needed
to
install
the
controls.
Table
IV­
13
shows
the
boilermaker
duty
rates
used
by
EPA
as
well
as
those
suggested
by
this
commenter.

TABLE
IV­
13.
B
Boilermaker
Duty
Rates
for
SCR
and
FGD
Systems
for
Coal­
Fired
Electric
Generation
Units
Source
FGD
SCR
EPA's
estimate,
boilermaker­
year/
MW
0.152
0.175
Commenter­
suggested,
boilermaker­
year/
MW1
0.269
0.343
1The
duty
rate
values
shown
are
average
values
calculated
by
using
the
FGD
and
SCR
correlations
provided
by
the
commenter
along
with
the
MW
size
of
individual
units
projected
by
the
IPM
to
require
FGD
or
SCR
controls
for
Phase
I
of
CAIR.

Our
review
of
the
limited
supporting
information
submitted
by
the
commenter
about
their
survey
for
these
duty
rates
shows
that
they
are
based
on
data
from
a
small
number
of
installations
and
represent
scope
of
work
at
each
power
plant
that
is
well
above
the
average
installation
conditions
used
in
determining
the
duty
rates
used
by
EPA.
Therefore,
EPA
considers
these
commenter­
suggested
duty
rates
to
represent
the
upper
end
of
the
range
of
values
that
would
be
expected
for
the
SCR
and
FGD
controls
under
consideration.
This
is
also
supported
by
the
average
duty
rate
(
0.199)
submitted
by
one
other
commenter
for
installing
FGDs,
which
is
well
below
the
average
duty
rate
(
0.269)
suggested
by
the
first
commenter.
However,
EPA
also
notes
that
the
duty
rate
suggested
by
the
second
commenter
is
higher
than
that
(
0.152)
used
by
EPA.
115
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
The
EPA
conducted
the
boilermaker
analysis
for
the
final
rule
using
alternative
assumptions
for
boilermaker
duty
rates.

These
alternative
assumptions
yield
a
range
of
estimates
of
the
amount
of
control
that
could
feasibly
be
installed.
In
keeping
with
EPA's
desire
to
be
very
sure
that
there
is
sufficient
boilermaker
labor
available
during
the
CAIR's
Phase
I
construction
period,
the
Agency
has
considered
the
most
stringent
duty
rates
suggested
by
the
first
commenter,
as
well
as
other
duty
rates
(
see
Table
IV­
13),
in
analyzing
the
impact
on
the
boilermaker
availability.
The
EPA
considers
this
to
be
a
bounding
analysis
in
which
the
estimates
based
on
the
most
stringent
duty
rates
reflect
conditions
with
the
highest
retrofit
difficulty
level
that
EPA
could
realistically
expect
to
occur.
We
expect
that
the
average
boilermaker
duty
rates
applicable
to
the
overall
boiler
population
required
to
retrofit
controls
under
this
rule
would
not
fall
outside
of
the
values
used
by
EPA
and
those
suggested
by
the
first
commenter.

In
the
NPR,
only
the
union
boilermakers
belonging
to
the
IBB
were
considered
in
the
EPA's
availability
analysis.
Some
commenters
have
pointed
out
that
additional
sources
of
boilermakers
will
be
available
for
CAIR.
Two
such
sources
include
non­
union
and
Canadian
boilermakers.
IBB
has
confirmed
that
1,325
Canadian
boilermakers
were
brought
in
to
support
the
116
25
Reference:
"
Email
from
Institute
of
Clean
Air
Companies,"
September
15,
2004
(
see
Appendix
B,
docket_______)

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
NOx
SIP
Call
SCR
work
in
2003.
The
EPA
also
projects
that
approximately
15
percent
of
FGDs
and
43
percent
of
SCRs
will
be
installed
for
Phase
I
in
the
traditionally
non­
union
States
and
believes
there
will
be
nonunion
labor
available
in
these
States.

One
source
has
confirmed
that
substantial
amount
of
SCR
retrofit
work
during
the
2000­
2002
period
was
executed
by
non­
union
labor.
25
Based
on
these
data,
we
have
conservatively
assumed
that
1,000
boilermakers
from
Canada
will
be
available
and
10
percent
of
the
retrofits
would
be
installed
by
non­
union
boilermakers
for
Phase
I.

Based
on
EPA
data,
an
average
32
GW
of
new
gas­
fired,

combined
cycle
generating
capacity
was
being
added
annually,

during
the
NOx
SIP
Call
SCR
construction
years
of
2002
and
2003.

A
substantial
number
of
boilermakers
were
involved
in
the
construction
of
these
gas­
fired
projects.
Since
projections
for
the
timeframe
relevant
to
CAIR
retrofits
show
only
a
small
amount
of
new
electric
generating
capacity
being
added,
the
number
of
boilermakers
involved
in
the
building
of
new
plants
would
be
smaller
and
more
of
the
boilermaker
population
would
be
available
to
work
on
the
Phase
I
retrofits.
As
pointed
out
by
one
commenter,
the
boilermakers
available
due
to
this
projected
drop
117
26
Reference:
"
Annual
Energy
Outlook
2005
(
Early
Release),
Tables
A9
and
9,"
December
2004,
http://
www.
eia.
doe.
gov/
oiaf/
aeo/
index.
html
27
TSD,
"
Boilermaker
Labor
and
Installation
Timing
Analysis,"
(
docket
no.______)

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
in
the
building
of
new
generation
capacity
represents
a
third
additional
source
of
boilermakers
for
CAIR.

The
EPA
projects
only
an
insignificant
amount
of
new
coal­
fired
generating
capacity
being
added
during
Phase
I.
The
most
recent
EIA's
projections
also
do
not
show
any
new
coal
fired
capacity
being
added
between
2007
and
2010,
the
timeframe
relevant
to
boilermaker­
related
construction
activities
for
CAIR.
26
However,
EPA's
projections
do
show
approximately
15
GW
of
new
or
repowered
gas­
fired
capacity
being
added,
during
2007­

2010.
The
EIA's
projections
for
new
gas­
fired
capacity
addition
during
Phase
I
are
well
below
those
of
EPA's.
We
used
the
more
conservative
EPA
projections
for
new
generating
capacity
additions
and
the
gas­
fired
capacity
additions
during
the
NOx
SIP
Call
period
to
estimate
the
additional
boilermaker
labor
that
would
become
available
for
the
Phase
I
retrofits.
This
estimate
shows
that
approximately
28
percent
more
boilermakers
would
be
available
to
work
on
the
CAIR
retrofits,
because
of
a
slowdown
in
the
construction
of
new
power
plants.
27
118
Section
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DRAFT
Do
Not
Quote
or
Cite
In
the
boilermaker
availability
analyses
performed
by
EPA,

the
required
boilermaker­
years
were
determined
for
each
case,

based
on
the
amounts
of
SCR
and
FGD
retrofits
being
installed
and
the
pertinent
boilermaker
availability
factors
and
duty
rates.

The
required
boilermaker­
years
were
then
compared
to
the
available
boilermaker
years
to
verify
adequacy
of
the
boilermaker
labor.
All
sources
of
boilermakers
were
considered
in
these
analyses,
including
the
union
boilermakers
and
the
boilermakers
from
the
three
additional
sources
discussed
previously.

The
EPA's
boilermaker
availability
analyses
firmly
support
CAIR's
Phase
I
requirements.
Using
EPA's
projections
of
FGD
and
SCR
retrofits
installed
for
Phase
I
and
EPA's
assumptions
for
boilermaker
duty
rates,
there
are
ample
boilermakers
available
with
a
large
contingency
factor
to
support
the
predicted
levels
of
CAIR
retrofits.
For
the
most
conservative
analysis
using
the
boilermaker
duty
rates
suggested
by
one
commenter
and
the
EIA's
projections
for
natural
gas
prices
and
electricity
demand
rates,

there
are
sufficient
boilermakers
available
with
a
contingency
factor
of
approximately
14
percent.

In
the
NPR
proposal,
EPA
estimated
that
a
contingency
factor
of
15
percent
was
available
to
offset
any
increases
in
boilermaker
requirements
due
to
unforeseen
events,
such
as
sick
leave,
time
lost
due
to
inclement
weather,
time
lost
due
to
119
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DRAFT
Do
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or
Cite
travel
between
job­
sites,
inefficiencies
created
due
to
project
scheduling
issues,
etc.
The
EPA
had
considered
this
15
percent
contingency
factor
to
be
adequate
for
these
unforeseen
events.

We
also
note
that
EPA
did
not
receive
any
comments
suggesting
a
need
for
a
higher
contingency
factor.

The
EPA
also
notes
that
the
above
boilermaker
labor
estimates
have
not
considered
the
benefits
of
the
experiences
gained
by
the
US
construction
industry
from
the
recent
buildup
of
large
amounts
of
air
pollution
controls,
including
the
NOx
SIP
Call
SCRs.
As
pointed
out
by
one
commenter,
such
experiences
include
use
of
modular
construction,
which
can
result
in
a
significant
reduction
in
the
required
boilermaker
labor
for
CAIR
retrofits.
Also,
as
a
result
of
this
controls
buildup,
an
increased
number
of
experienced
designers
and
construction
personnel
have
become
available
to
the
industry.
Some
of
these
benefits
may
be
offset
by
factors,
such
as
the
increased
level
of
retrofit
difficulty
expected
for
the
CAIR
retrofits,
especially
for
the
small
size
units.
However,
we
believe
that
the
net
effect
of
this
experience
is
a
more
efficient
use
of
the
boilermaker
labor
in
the
construction
of
the
air
pollution
control
retrofits
projects.
Unfortunately,
EPA
cannot
quantify
the
value
of
this
experience
in
determining
its
overall
impact
on
boilermaker
requirements.
120
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DRAFT
Do
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or
Cite
Therefore,
EPA
considers
the
14
percent
contingency
in
the
available
boilermaker­
years
for
the
above
bounding
analysis
using
commenter­
suggested
assumptions
to
be
adequate.

ii.
Issues
Related
to
Compliance
Deadline
Acceleration
(
I)
Acceleration
of
Phase
I
Compliance
Deadline
As
a
result
of
EPA's
review
of
the
comments
received
and
further
investigations
conducted
by
the
Agency
for
the
final
rule,
the
compliance
deadline
for
implementing
Phase
I
NOx
controls
only
has
been
moved
up
by
one
year.
We
believe
that
the
affected
plants
would
have
sufficient
time
with
this
change
to
meet
the
CAIR
requirements
associated
with
NOx
emissions,
as
long
as
the
compliance
deadline
for
implementing
SO2
controls
in
not
changed.
The
EPA
does
not
agree
that
accelerating
the
originally
proposed
Phase
I
compliance
deadline
of
January
1,
2010,
for
implementing
both
NOx
and
SO2
controls
is
possible.
These
issues
are
discussed
below::

(
A)
Two­
Year
Phase
I
Acceleration
With
today's
final
action
and
allowing
18
months
for
the
SIPs,
sources
installing
controls
would
have
approximately
3­
1/
4
years
for
implementing
the
rule's
requirements.
Some
commenters
suggested
moving
Phase
I
forward
by
two
years,
with
a
new
compliance
deadline
of
January
1,
2008,
which
would
reduce
the
implementation
period
to
1­
1/
4
years.
It
is
recognized
that
121
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DRAFT
Do
Not
Quote
or
Cite
sources
generally
would
not
initiate
any
implementation
activities
that
require
major
funding,
before
the
final
SIPs
are
available.

The
EPA's
projections
show
that,
for
SCR
installation
on
one
unit,
an
average
21­
month
schedule
is
required
to
complete
purchasing,
construction,
and
startup
activities.
For
the
same
activities
for
FGD,
an
average
27­
month
schedule
is
required.
As
can
be
seen,
that
the
total
time
required
for
just
one
SCR
or
FGD
installation
exceeds
the
1­
1/
4­
year
implementation
period
available
for
Phase
I,
if
the
compliance
deadline
is
moved
to
January
1,
2008.

(
B)
One­
Year
Phase
I
Acceleration
for
NOx
and
SO2
Controls
If
the
Phase
I
compliance
deadline
for
both
NOx
and
SO2
controls
is
moved
up
by
one
year,
the
affected
facilities
would
have
2­
1/
4
years
or
27
months
to
complete
installation
of
these
controls.
As
discussed
in
the
preceding
section,
FGD
installation
on
one
unit
requires
an
average
27­
month
schedule
to
complete
purchasing,
construction,
and
startup
activities.

The
sources
installing
controls
on
more
than
one
unit
at
the
same
facility
would
likely
stagger
the
outage­
related
activities,

such
as
final
hookup
of
the
new
equipment
into
the
existing
plant
settings
and
startup,
to
minimize
operational
disruptions
and
avoid
losing
too
much
generating
capacity
at
one
time.
The
EPA
122
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DRAFT
Do
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Quote
or
Cite
projects
that
an
average
2­
month
period
is
required
to
complete
the
outage
construction
activities
and
a
one­
month
period
to
complete
the
startup
activities
for
FGD.
Therefore,
if
back­

toback
outages
are
assumed
for
a
plant
installing
FGD
on
just
two
units,
the
27
months
needed
to
install
FGD
on
the
first
unit
and
an
additional
three
months
needed
for
outage
activities
on
the
second
unit
would
result
in
an
overall
schedule
requirement
of
30
months.
This
30­
month
schedule
exceeds
the
available
27­
month
implementation
period,
if
the
compliance
deadline
is
moved
up
by
one
year.
For
plants
installing
FGD
controls
on
more
than
two
units
and
performing
hookup
construction
and
startup
activities
in
back­
to­
back
outages,
an
additional
three
months
would
be
added
to
the
30­
month
schedule
requirement
for
each
additional
unit.

The
EPA
notes
that
certain
plants
installing
multiple­
unit
controls
may
be
able
to
meet
the
compliance
deadline
requirement
by
using
alternative
approaches,
such
as
simultaneous
unit
outages
and
purchase
of
allowances
to
defer
installation
of
controls
on
some
units.
However,
our
projections
for
the
final
rule
show
that
some
facilities
would
be
installing
FGD
controls
on
five
multiple
units
at
a
single
site.
Moreover,
these
projections
show
26
plants
requiring
FGD
retrofit
on
more
than
one
unit,
which
represents
a
major
portion
of
the
total
number
of
123
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2005
DRAFT
Do
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Quote
or
Cite
plants
required
to
install
such
controls
under
CAIR.
We
believe
it
would
not
be
appropriate
to
expect
this
number
of
plants
to
resort
to
alternative
means
to
accommodate
such
installations,

such
as
simultaneous
unit
outages
or
purchasing
of
allowances.

For
FGD
retrofits,
some
plants
would
be
required
to
obtain
solid
waste
landfill
permits.
As
discussed
previously,
the
time
required
to
obtain
these
permits
could
range
from
one
to
3­
1/
2
years.
With
the
compliance
deadline
moved
up
by
one
year,
the
overall
implementation
period
would
be
reduced
from
4­
3/
4
to
3­

3/
4
years.
For
those
plants
subjected
to
a
3­
1/
2­
year
permit
approval
period,
only
three
months
would
be
available
to
prepare
the
permit
applications
at
the
beginning
of
the
compliance
period
and
to
prepare
the
landfill
area
for
accepting
the
waste
after
permit
approval.
The
EPA
does
not
believe
that
three
months
is
adequate
for
such
activities.
These
plants
would,
therefore,

need
the
4­
3/
4­
year
implementation
period
to
complete
activities
related
to
landfills
associated
with
the
FGD
systems.

The
EPA
also
performed
an
analysis
to
verify
if
the
available
boilermaker
labor
is
adequate
to
support
the
January
1,

2009,
compliance
deadline
for
both
NOx
and
SO2.
This
analysis
was
performed,
using
commenter­
suggested
boilermaker
duty
rates
and
EIA's
assumptions
for
the
natural
gas
prices
and
electricity
demand
rates.
The
results
show
that
given
these
assumptions
sufficient
number
of
boilermakers
will
not
be
available
and
that
124
Section
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2005
DRAFT
Do
Not
Quote
or
Cite
there
will
be
a
shortfall
of
approximately
32
percent
in
the
boilermakers
available
to
support
Phase
I
activities
for
this
case.

Considering
the
constraints
identified
in
the
above
analyses
for
the
FGD
installation
schedule
requirements
and
boilermaker
labor
availability,
EPA
believes
that
it
is
not
reasonable
to
move
the
Phase
I
compliance
deadline
for
both
NOx
and
SO2
caps
to
January
1,
2009.

(
C)
One­
Year
Phase
I
Acceleration
for
NOx
Controls
Only
An
one
year
acceleration
would
result
in
a
compliance
deadline
of
January
1,
2009,
for
installing
Phase
I
NOx
controls.

With
this
change,
the
affected
sources
installing
these
controls
would
have
approximately
2­
1/
4
years
for
implementing
the
rule's
requirements,
following
the
approval
of
State
programs.
However
the
implementation
period
for
installing
FGD
controls
would
still
be
at
3­
1/
4
years.

As
shown
previously,
21
months
would
be
required
to
complete
purchasing,
construction,
and
startup
of
SCR
on
one
unit.
For
multiple­
unit
installations
with
back­
to­
back
unit
outages
for
the
tie­
in
construction
and
startup,
the
available
2­
1/
4­
year
implementation
period
would
permit
staggering
of
SCR
installations
on
a
maximum
of
three
units
(
see
the
above
referenced
TSD).
For
a
plant
requiring
SCR
retrofit
on
more
than
125
28
The
200,000­
ton
Compliance
Supplement
Pool
is
apportioned
to
each
of
the
23
States
and
the
District
of
Columbia
that
are
required
by
CAIR
to
make
annual
NOx
reductions,
as
well
as
the
2
States
(
Delaware
and
New
Jersey)
for
which
EPA
is
proposing
to
require
annual
NOx
reductions.

Section
IV
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04/
2005
DRAFT
Do
Not
Quote
or
Cite
three
units,
simultaneous
outages
of
two
units
would
become
necessary.
However,
EPA
notes
that
there
are
only
six
plants
projected
to
require
SCR
installation
on
more
than
three
units
and,
therefore,
it
is
expected
that
simultaneous
outages
of
two
units
at
each
of
these
plants
would
not
have
an
adverse
impact
on
the
reliability
of
the
electrical
grid.

In
addition,
the
plants
installing
SCR
on
more
than
three
units
at
the
same
site
would
have
two
other
options
to
meet
the
rule's
requirements,
without
having
to
resort
to
simultaneous
two­
unit
outages.
First,
these
plants
would
be
able
to
defer
installation
of
SCRs
on
some
of
the
units
by
receiving
allocated
allowances
or
purchasing
allowances
from
the
200,000­
ton
Compliance
Supplement
Pool
being
made
available
as
part
of
CAIR.
28
Second,
the
outage
activities
for
some
of
the
units
at
these
plants
could
be
extended
into
the
first
quarter
of
2009,
which
is
beyond
the
compliance
deadline
of
January
1,
2009,
since
these
units
would
not
generate
NOx
emissions
during
an
outage
and
therefore
not
require
any
allowances
to
compensate
for
them.
The
EPA's
projections
show
that,
of
the
above
six
plants
installing
SCR
on
more
than
three
units,
four
of
them
require
SCR
retrofits
126
Section
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2005
DRAFT
Do
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Quote
or
Cite
on
four
units
each.
If
it
is
assumed
that
these
four
plants
would
perform
outage
activities
on
the
fourth
unit
during
the
first
quarter
of
2009,
there
would
only
be
two
plants
left
that
would
be
required
to
either
purchase
allowances
or
perform
work
during
simultaneous
outages.

The
EPA
also
notes
that
the
total
schedule
requirements
for
multiple­
unit
plants
can
be
reduced
further
by
performing
some
of
the
activities,
especially
those
related
to
planning
and
engineering,
prior
to
the
2­
1/
4­
year
period.
Also,
with
the
total
installation
time
requirement
for
FGD
being
more
than
that
for
SCR,
EPA
expects
the
outages
associated
with
most
Phase
I
FGDs
to
take
place
after
January
1,
2009.
The
overall
impact
of
the
outages
taken
for
these
SCR
and
FGD
retrofits
would,

therefore,
be
minimized.

The
EPA
also
performed
an
analysis
to
determine
the
impact
of
an
one­
year
acceleration
in
the
NOx
compliance
deadline
on
Phase
I
boilermaker
labor
requirements.
Since
the
amounts
of
the
required
Phase
I
NOx
and
FGD
retrofits
are
not
affected
by
this
change,
the
overall
boilermaker
requirements
for
this
phase
will
remain
the
same
as
previously
reported
for
the
case
with
the
same
compliance
deadline
for
both
NOx
and
SO2.
However,
with
the
new
NOx
compliance
deadline,
installation
of
all
NOx
retrofits
would
have
to
be
completed
by
January
1,
2009,
and
some
of
the
FGD
127
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DRAFT
Do
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or
Cite
construction
work
requiring
boilermakers
would
also
be
done
during
this
period.
The
EPA
assumed
that,
along
with
completing
installation
of
all
SCRs,
35
percent
of
the
boilermaker
labor
required
to
install
all
FGDs
would
be
used
in
the
period
prior
to
January
1,
2009.
This
is
a
conservative
assumption,
since
the
amount
of
boilermaker
labor
used
for
this
period
would
be
greater
than
50
percent
of
the
total
Phase
I
boilermaker
labor
requirement.
The
analysis
performed
by
EPA
shows
that
sufficient
boilermakers
would
be
available
with
a
contingency
factor
of
approximately
14
percent
to
install
all
SCR
controls
and
35
percent
of
the
FGD
retrofit
work
by
January
1,
2009.
This
analysis
is
based
on
the
most
conservative
assumptions,
using
the
boilermaker
duty
rates
suggested
by
one
commenter
and
the
EIA's
projections
for
natural
gas
prices
and
electricity
demand
rates.

Based
on
the
above
analyses,
EPA
believes
that
moving
the
compliance
deadline
for
Phase
I
for
both
NOx
and
SO2
is
not
practical.
However,
a
one
year
acceleration
in
the
compliance
deadline
for
NOx
only
is
feasible.
Since
EPA
is
obligated
under
the
Clean
Air
Act
to
require
emission
reductions
for
obtaining
NAAQS
to
be
achieved
as
soon
as
practicable,
we
have
based
the
final
rule
on
two
separate
Phase
I
compliance
deadlines
of
January
1,
2009,
and
January
1,
2010,
for
NOx
and
SO2,

respectively.
128
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
(
II)
Implementing
All
Controls
in
Phase
I
The
EPA
proposed
a
phased
program
with
the
consideration
that
for
engineering
and
financial
reasons,
it
would
take
a
substantial
amount
of
time
to
install
the
projected
controls.

This
program
would
require
one
of
the
most
extensive
capital
investment
and
engineering
retrofit
programs
ever
undertaken
in
the
U.
S.
for
pollution
control.
The
capital
investment
for
pollution
control
for
CAIR
that
would
be
installed
by
2015
is
estimated
to
be
approximately
15
billion
dollars.
By
2015,
close
to
340
control
unit
retrofits
will
occur.
This
is
occurring
at
a
time
when
the
industry
also
faces
another
major
infrastructure
challenge
 
upgrading
transmission
capacity
to
make
the
grid
more
reliable
and
economic
to
operate.
This
also
will
cost
tens
of
billions
of
dollars.

The
proposed
program's
objective
was
to
eliminate
upwind
states'
significant
contribution
to
downwind
nonattainment,

providing
air
quality
benefits
as
soon
as
feasible.
A
phased
approach
was
also
considered
necessary
because
more
of
the
difficult­
to­
retrofit
and
finance,
smaller
size
units
would
be
included
in
the
second
phase,
which
would
allow
them
to
complete
activities
necessary
for
implementing
the
required
controls
as
well
as
provide
them
an
opportunity
to
benefit
from
the
lessons
learned
during
the
first
phase.
129
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
In
general,
environmental
controls
resulting
from
legislative
or
regulatory
actions
are
applied
to
those
units
first
that
offer
superior
choices
from
constructability
and
costeffectiveness
standpoints.
Experience
gained
by
the
industry
from
these
installations
can
then
be
used
to
develop
innovative
solutions
for
any
constructability
issues
and
to
improve
cost
effectiveness,
as
these
technologies
are
applied
to
harder­

tocontrol
units.
The
EPA
believes
that
this
phenomenon
applies
to
the
application
of
the
SCR
and
FGD
technologies
at
coal­
fired
power
plants.

In
the
last
few
years,
SCR
and
FGD
systems
have
been
added
to
several
existing
coal­
fired
units,
under
the
NOx
SIP
Call
and
Acid
Rain
Program.
These
were
mainly
large
units
that
had
features,
such
as
spacious
layouts,
amenable
to
the
retrofit
of
the
new
air
pollution
control
equipment.
The
units
installing
controls
during
Phase
I
of
CAIR
would,
in
general,
be
smaller
in
size
and
would
offer
relatively
more
difficult
settings
to
accommodate
the
new
equipment.
These
units
would
certainly
benefit
from
the
experience
the
industry
has
gained
from
the
installations
completed
in
recent
years.

A
large
portion
of
the
units
(
47%)
projected
to
implement
controls
during
the
second
phase
consists
of
even
smaller
units,

less
than
200
MW
in
size.
Compared
to
larger
units,
the
retrofits
for
these
smaller
units
would
be
more
difficult
to
plan,
design,
and
build.
Historically,
smaller
units
have
been
130
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
built
with
less
equipment
redundancy,
smaller
capacity
margins,

and
more
congested
layouts.
It
is
likely,
therefore,
to
be
more
difficult
and
require
additional
design
efforts
to
accommodate
the
new
equipment
into
the
existing
settings
for
the
smaller
units.
Use
of
lessons
learned
by
firms
constructing
these
units
from
the
previous
installations,
including
those
to
be
built
during
the
first
phase,
would
help
streamline
this
process
and
maintain
the
cost
effectiveness
of
these
installations.
Moving
a
large
portion
of
the
retrofits
required
for
these
smaller
units
to
the
second
phase
also
provides
more
time
to
complete
the
required
retrofit
activities.

Because
EPA's
projections
for
the
second
phase
include
a
large
proportion
of
smaller
units,
the
total
number
of
units
requiring
NOx
and
SO2
controls
exceeds
that
in
the
first
phase
(
186
vs.
153).
Requiring
an
acceleration
of
the
second
phase
controls
to
be
completed
in
the
first
phase
would,
therefore,

more
than
double
the
number
of
retrofits
required
for
the
first
phase
from
153
to
339.
Based
on
data
available
from
EPA
and
other
sources,
the
industry
completed
95
SCR
installations
for
the
NOx
SIP
Call
in
2002
and
2003.
If
the
2004
projections
for
the
NOx
SIP
Call
are
added
to
this
number,
the
total
number
of
SCR
retrofits
over
the
2002­
2004
period
would
be
140.
This
is
less
than
half
the
number
that
would
be
required
for
CAIR
during
131
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
a
similar
period,
if
the
Phase
II
requirements
are
implemented
along
with
the
Phase
I
requirements.
Also,
the
combined
capacity
for
FGD
and
SCR
retrofits
required
for
Phase
I
would
be
122.5
GW,

which
is
approximately
57
percent
greater
than
the
installed
SIP­
Call
SCR
capacity
for
the
2002­
2004
period.
Such
a
change
in
the
rule
would
therefore
amount
to
imposing
a
requirement
over
the
power
industry
that
is
significantly
more
demanding
and
burdensome
than
what
the
industry
was
required
to
do
under
the
NOx
SIP
Call
rule.

The
EPA
notes
that
critical
resources
other
than
the
boilermakers
are
needed
for
the
installation
of
SCR
and
FGD
controls,
such
as
construction
equipment,
engineering
and
construction
staffs
belonging
to
different
trades,
construction
materials,
and
equipment
manufacturers.
Some
commenters,
based
on
their
experience
with
NOx
SIP
Call,
also
pointed
out
that
the
requirement
for
some
of
these
resources,
especially
construction
equipment
(
e.
g.,
large
cranes
used
to
mount
SCR
and
scrubber
vessels
above
ground),
construction
materials,
equipment
manufacturing
shop
capacities,
and
engineering
and
construction
management
teams
overseeing
these
projects,
is
affected
directly
by
the
number
of
installations.
The
greater
the
requirement
is
to
install
a
large
number
of
retrofits
by
2010,
the
greater
would
be
the
need
for
all
these
resources,
which
would
be
limited
in
132
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
the
short
term,
as
demands
from
equipment
vendors,
project
teams,

and
material
suppliers
ramp
up.
In
the
NOx
SIP
Call,
this
led
to
shortages
and
bottlenecks
in
projects
in
certain
areas,
causing
increased
project
times
and
costs.
The
EPA
wants
to
avoid
creating
a
similar
situation
by
requiring
too
much
at
once.

The
EPA
has
also
acknowledged
the
increase
in
SCR
costs
during
the
NOx
SIP
Call
implementation
period,
most
likely
due
to
an
increase
in
construction
costs
(
resulting
from
increased
demand
for
boilermaker
labor)
and
steel
prices.
The
EPA
has
revised
its
estimates
of
SCR
capital
costs
in
the
IPM
runs
for
the
final
rule
and
believes
the
conservatism
in
its
FGD
capital
costs
also
accounts
for
this
factor.

The
EPA
believes
that
moving
the
Phase
II
requirements
to
the
Phase
I
period
could
cause
near­
term
shortages
in
some
of
the
critical
resources.
This
would
further
increase
compliance
costs
and
could
remove
the
highly
cost­
effective
nature
of
these
controls
and
lead
to
a
greater
demand
for
natural
gas.

In
addition
to
the
above,
financing
a
large
amount
of
controls
for
Phase
I
may
prove
challenging,
especially
for
the
coal
plants
owned
by
deregulated
generators.
As
discussed
later
in
this
section,
such
generators
are
continuing
to
face
serious
financial
challenges,
and
many
have
below
investment
grade
credit
ratings.
This
significantly
complicates
the
financing
of
costly
133
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
retrofit
controls.
Such
plants
would
also
not
have
the
certainty
of
regulatory
recovery
of
investments
in
pollution
control,
and
would
have
to
rely
on
the
market
to
recover
their
costs.
Having
a
second
phase
cap
would
allow
these
companies
additional
time
to
strengthen
their
finances
and
improve
their
cash
flow.

In
the
interest
of
being
prudent
in
evaluating
the
need
to
phase
in
the
program,
EPA
also
performed
an
analysis
to
determine
if
the
available
boilermaker
labor
would
be
adequate
to
support
installation
of
all
Phase
I
and
II
controls
in
2010.
This
analysis
was
conservatively
based
on
using
commenter­
suggested
boilermaker
duty
rates
and
EIA's
projections
for
gas
prices
and
electricity
demand
rates.
The
results
show
that
sufficient
number
of
boilermakers
will
not
be
available
and
that
there
will
be
a
shortfall
of
approximately
25
percent
in
the
boilermakers
available
to
support
Phase
I
activities
for
this
case.

Based
on
the
above
analyses,
EPA
believes
that
implementation
of
controls
for
both
phases
in
Phase
I
is
impractical.
We
also
believe
that
it
is
prudent
and
reasonable
in
requiring
the
industry
to
undertake
this
massive
retrofit
program
on
a
two­
phase
schedule,
to
be
largely
completed
in
less
than
a
decade.

(
III)
Acceleration
of
Phase
II
Compliance
Deadline
The
EPA
does
not
believe
that
acceleration
of
the
compliance
deadline
for
the
second
phase
is
reasonable.
As
pointed
out
134
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
earlier,
a
large
portion
of
the
units
projected
to
install
controls
during
the
second
phase
consists
of
small
units,
less
than
200
MW
in
size.
Due
to
the
issues
related
to
financing
of
the
retrofit
projects
for
some
of
these
units
and
considering
that
planning
and
designing
of
controls
for
these
units
is
likely
to
take
longer,
EPA
does
not
consider
the
schedule
acceleration
to
be
appropriate.

EPA
notes
that
Phase
I
of
CAIR
is
the
initial
step
on
the
slope
of
emissions
reduction
(
the
glide­
path)
leading
to
the
final
control
levels.
Because
of
the
incentive
to
make
early
emission
reductions
that
the
cap­
and­
trade
program
provides,

reductions
will
begin
early
and
will
continue
to
increase
through
Phases
I
and
II.
The
EPA,
therefore,
does
not
believe
that
all
of
the
required
Phase
II
emission
reductions
would
take
place
on
January
1,
2015,
the
compliance
deadline.
These
reductions
are
expected
to
accrue
throughout
the
implementation
period,
as
the
sources
install
controls
and
start
to
test
and
operate
them.

The
EPA
also
notes
that
the
five­
year
implementation
period
for
Phase
II
is
consistent
with
other
regulations
and
statutory
requirements,
such
as
title
IV
for
SO2
and
NOx
controls.
In
addition,
some
commenters
have
cited
a
need
for
a
six­
year
period
for
obtaining
financing
for
plants
owned
by
the
co­
operatives.

These
facilities
are
likely
to
commit
funds
for
major
activities,

only
after
financing
has
been
obtained.
Therefore,
for
such
135
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
facilities,
a
period
of
approximately
four
years
would
be
available
for
procuring,
installing,
and
startup
activities,

assuming
that
the
financing
activities
were
started
right
after
the
rule
is
finalized.
Since
the
plants
owned
by
co­
operatives
are
usually
small
in
size,
they
are
likely
to
require
and
be
benefitted
by
the
extra
time
allowed
to
them
by
this
four­
year
implementation
period.

The
EPA
also
performed
an
analysis
to
verify
adequacy
of
the
available
boilermaker
labor
for
pollution
control
retrofits
the
power
industry
will
install
to
comply
with
the
Phase
II
CAIR
requirements.
A
36­
month
construction
period
requiring
boilermakers
was
conservatively
selected
for
this
analysis.

Based
on
the
IPM
analysis
for
the
final
rule,
conservatively,
the
power
industry
will
build
27.5
GW
of
FGD
and
26.6
GW
of
SCR
retrofits
for
compliance
with
lower
emission
caps
that
go
into
effect
for
NOx
and
SO2
in
2015.
The
analysis
was
based
on
using
EIA's
projections
for
the
natural
gas
prices
and
electricity
demand
rates
and
the
commenter­
suggested
boilermaker
duty
rates.

The
results
show
availability
of
ample
boilermakers
with
a
contingency
factor
of
46
percent
to
support
Phase
II
activities.

The
EPA
notes
that
the
retrofits
that
will
occur
in
Phase
II
will
be
smaller,
more
numerous,
and
more
challenging,
since
the
easiest
controls
will
likely
be
installed
in
Phase
I.
Therefore,
136
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
having
a
greater
contingency
factor
(
as
we
do)
is
warranted.

This
is
further
supported
when
the
uncertainty
in
predicting
the
construction
activities
in
the
areas
outside
of
air
pollution
controls
is
considered.
Notably
after
2010,
the
excess
generation
capacity
that
we
have
today
is
no
longer
expected
to
be
present
and
there
may
be
a
shift
towards
a
requirement
for
increasing
generation
capacity.
Increased
construction
of
new
power
plants
will
have
a
direct
impact
on
the
availability
of
boilermakers
for
the
Phase
II
controls.
The
EPA
believes
that
a
higher
contingency
factor
for
Phase
II
is
desirable
to
ensure
that
the
industry
will
succeed
in
getting
the
required
reductions
at
the
required
time.

Any
acceleration
of
Phase
II
compliance
deadline
will
also
cause
an
appreciable
reduction
in
the
above
estimated
contingency
factor.
For
example,
an
acceleration
of
one
year
will
reduce
this
contingency
factor
to
only
about
one
percent.
Therefore,

EPA
believes
that
acceleration
of
the
Phase
II
compliance
deadline
cannot
be
justified.

3.
Assure
Financial
Stability
The
EPA
recognizes
that
the
power
sector
will
need
to
devote
large
amounts
of
capital
to
meet
the
control
requirements
of
the
first
phase.
Among
the
consideration
of
other
factors,
EPA
137
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
believes
it
is
important
to
take
into
account
the
ability
of
the
power
sector
to
finance
the
controls
required
under
CAIR.

A
detailed
assessment
of
the
status
of
the
financial
health
of
the
U.
S.
Utility
Industry,
particularly
of
the
unregulated
sector
is
offered
in
the
TSD
"
U.
S.
Utility
Industry
Financial
Status
and
Potential
Recovery."

Commenters
have
noted
that
they
appreciate
EPA's
growing
realization
that
many
companies
may
have
difficulty
securing
financing,
and
the
agency's
establishment
of
a
two­
phase
reduction
program
on
both
technical
and
financial
grounds.

Utilities
and
non­
utility
generating
companies
have
felt
significant
financial
pressure
over
the
past
5
years.
The
years
2000
and
2001
saw
the
escalation
and
fallout
from
the
California
energy
crisis,
the
bankruptcy
of
Enron,
and
a
massive
building
program,
largely
on
the
side
of
the
merchant
generating
sector.

Subsequent
low
power
margins
and
large
debt
obligations
have
led
to
a
significant
number
of
credit
downgrades
of
utilities
and
power
generators
and
the
bankruptcy
of
coal­
generating
merchant
companies.
According
to
Standard
and
Poor's,
a
leading
provider
of
investment
ratings,
there
were
almost
ten
times
more
downgrades
of
utility
credit
in
2002
and
2003
than
there
were
upgrades.
While
more
recently
the
sector
has
stabilized,
a
significant
number
of
owners
of
coal­
fired
capacity
in
the
CAIR
138
29
In
fact,
between
nine
and
eleven
(
depending
on
the
credit
agency)
of
the
twenty
largest
owners
of
deregulated
coal
capacity
in
the
U.
S.
currently
have
below­
investment­
grade
credit
ratings.

Section
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DRAFT
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or
Cite
region,
particularly
those
with
deregulated
capacity,
are
still
at
below
investment­
grade
credit
ratings.

In
general,
EPA
believes
that
regulated
plants,
given
appropriate
regulatory
requirements,
should
not
face
significant
financial
problems
meeting
their
obligations
under
CAIR.
While
EPA
recognizes
that
issues
such
as
the
expiration
of
rate
caps
and
the
time
lags
associated
with
regulatory
approval
and
recovery
may
provide
cash
flow
challenges,
regulation
is
generally
seen
as
a
positive
factor
in
credit
ratings,
as
entities
are
allowed
a
recovery
on
prudent
investment
through
rate
cases
(
and,
in
some
jurisdictions,
the
recovery
of
allowance
expenditures
through
fuel
adjustment
clauses).

Deregulated
coal
capacity
nationwide
has
no
such
guarantees,

and
would
need
to
recover
investments
in
pollution
control
from
market
prices
(
which
in
many
cases
are
not
set
by
coal
units).

Additionally,
deregulated
entities,
because
of
their
more
aggressive
building
and
borrowing
strategies
and
reliance
on
market
prices
(
which
now
reflect
the
capacity
overbuild),
have
faced
more
significant
financial
difficulties
(
including
a
number
of
bankruptcies)
and
are
currently
in
a
weaker
position
financially.
29
A
number
of
firms
that
have
avoided
financial
139
Section
IV
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2005
DRAFT
Do
Not
Quote
or
Cite
distress
in
the
near
term
have
done
so
by
renegotiating
their
pending
debt,
postponing
payment.
A
good
portion
of
this
debt
is
of
a
shorter­
term
nature,
and
will
be
coming
due
in
the
next
five
years.

Such
financial
difficulties
increase
the
cost
of
capital
necessary
for
capital
expenditures
and
affect
the
availability
of
such
capital,
making
required
controls
more
expensive.
Recent
financial
troubles
have
been
cited
as
the
reason
for
the
deferment
or
cancellation
of
pollution
control
expenditures.

Should
interest
rates
rise
in
the
future,
it
will
become
more
difficult
and
costly
for
utilities
seeking
financing.

These
problems
impact
a
significant
segment
of
coal
generators,
as
deregulated
coal
capacity
makes
up
about
a
third
of
all
U.
S.
coal
capacity
and
almost
90%
of
this
deregulated
capacity
would
be
affected
by
CAIR
requirements.

Given
the
lead
times
needed
to
plan
and
construct
such
equipment,
as
well
as
the
financial
uncertainty
many
of
the
plant
owners
are
confronting,
companies
may
find
it
difficult
to
install
controls
at
their
plants
too
quickly.
The
EPA
believes
that
the
choice
of
timing
of
the
emission
caps
in
CAIR
would
allow
firms
time
to
improve
their
current
and
near­
term
financial
difficulties
(
through
reorganization,
mergers,
sales,
etc.).

Phasing
in
the
more
stringent
emission
caps
by
2015
would
also
140
Section
IV
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2005
DRAFT
Do
Not
Quote
or
Cite
spread
investment
requirements
and
resulting
cash
flow
demands,

rather
than
forcing
firms
to
finance
a
large
spike
in
investments
in
a
very
short
time
period,
while
they
are
still
trying
to
recover
financially.

The
timing
of
controls
expected
to
be
installed
as
a
result
of
CAIR
are
similar
to
that
noted
in
EPA's
analysis
of
the
Clear
Skies
proposal.
The
EPA
looked
in
detail
at
the
potential
financial
impact
of
the
Clear
Skies
program
(
particularly
focusing
on
the
deregulated
coal
sector).
The
EPA
found
that
some
individual
deregulated
coal
plants
might
be
adversely
affected,
but
on
average
such
plants
would
actually
experience
a
small
financial
improvement
under
Clear
Skies.
Baseload
deregulated
coal
plants
would
benefit
from
increases
in
the
price
of
natural
gas
(
which
generally
sets
the
wholesale
price
of
electricity
on
the
margin
in
the
regions
where
deregulated
coal
is
located)
as
well
as
from
allocations
of
allowances.
This
impact
is
also
attributed
specifically
to
the
phased­
in
nature
of
Clear
Skies,
and
to
the
facts
that
most
coal
plants
continue
to
be
regulated
and
would
also
receive
allowances.

EPA
believes
that
the
timing
requirements
finalized
today
reflect
a
prudent
and
cautious
approach
designed
to
assure
that
the
industry
will
succeed
in
implementing
this
program.
The
EPA
believes
that
deferring
the
second
phase
to
2015
will
provide
141
30
The
survey
results
are
in
"
A
Survey
of
State
Incentives
Encouraging
Improved
Environmental
Performance
of
Base­
Load
Electric
Generation
Facilities:
Policy
and
Regulatory
Initiatives",
at
http://
www.
naruc.
org/
displayindustryarticle.
cfm?
articlenbr=
21826
Section
IV
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04/
2005
DRAFT
Do
Not
Quote
or
Cite
enough
time
for
companies
to
raise
additional
capital
needed
to
install
controls.
Also,
we
believe
that
the
implementation
period
should
account
(
at
least
broadly)
for
the
possibility
that
electricity
demand
or
natural
gas
prices
may
increase
more
than
assumed,
and
therefore
that
additional
control
equipment
would
be
needed.
Allowing
until
2015
for
implementation
of
the
more
stringent
control
levels
in
today's
rule
will
provide
more
flexibility
in
the
event
of
greater
electricity
demand
and
will
ensure
that
power
plants
in
the
CAIR
region
will
have
the
ability,
both
technical
and
financial,
to
make
the
pollution
control
retrofits
required.

EPA
is
currently
cooperating
with
the
National
Association
of
Regulatory
Utility
Commissioners
(
NARUC)
in
developing
a
menu
of
policy
options
and
financial
incentives
for
encouraging
improved
environmental
performance
for
generation.
A
survey
of
a
number
of
States
was
conducted
as
part
of
this
effort,
and
policies
such
as
pre­
approval
statutes
for
compliance
plans,

state
income
tax
credits,
accelerated
depreciation,
and
special
treatment
of
allowance
transactions
were
cited
as
examples
of
such
policies30.
Such
policies
will
ease
some
of
the
financial
142
Section
IV
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04/
2005
DRAFT
Do
Not
Quote
or
Cite
pressures
of
CAIR
by
providing
greater
regulatory
certainty
and
lowering
the
effective
costs
of
controls.

D.
Control
Requirements
in
Today's
Final
Rule
1.
Criteria
Used
to
Determine
Final
Control
Requirements
The
EPA's
general
approach
to
developing
emission
reduction
requirements
 
basing
the
requirements
on
the
application
of
highly
cost­
effective
controls
 
was
adopted
in
the
NOx
SIP
Call
and
has
been
sustained
in
court.
In
the
NPR,
the
Agency
proposed
this
approach
for
developing
SO2
and
NOx
emission
reduction
requirements.
The
majority
of
commenters
accepted
this
basic
approach
for
determining
reduction
requirements.
Some
commenters
did
suggest
other
approaches,
however,
as
discussed
above.

Many
commenters
suggested
that
the
CAIR
regionwide
SO2
and
NOx
control
levels
should
be
more
or
less
stringent
than
the
levels
proposed
in
the
NPR.
The
EPA
has
determined
that
the
control
levels
that
we
are
finalizing
today
are
highly
costeffective
and
feasible,
and
constitute
substantial
reductions
that
address
interstate
transport,
at
the
outset
of
State
and
EPA
efforts
to
bring
about
attainment
of
the
PM2.5
NAAQS
(
the
EPA
believes
that
most
if
not
all
States
will
obtain
these
reductions
by
capping
emissions
from
the
power
sector).
Today,
EPA
finalizes
the
use
of
both
average
and
marginal
cost
effectiveness
143
Section
IV
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04/
2005
DRAFT
Do
Not
Quote
or
Cite
of
controls
as
the
basis
for
determining
the
highly
costeffective
amounts.

In
the
CAIR
NPR,
EPA
proposed
criteria
for
determining
the
appropriate
levels
of
SO2
and
NOx
emissions
reductions,
and
stated
that
EPA
considered
a
variety
of
factors
in
evaluating
the
source
categories
from
which
highly
cost­
effective
reductions
may
be
available
and
the
level
of
reduction
assumed
from
that
sector
(
69
FR
4611).
The
EPA
has
reviewed
comments
on
its
NPR,
SNPR
and
NODA
and
conducted
further
analyses
with
respect
to
the
proposed
criteria,
and
is
finalizing
its
control
requirements
in
today's
action.
Following
is
a
brief
summary
of
EPA's
conclusions
based
on
the
criteria.

The
availability
of
information,
and
the
identification
of
source
categories
emitting
relatively
large
amounts
of
the
relevant
emissions,
are
two
criteria
used
in
EPA's
evaluation
of
the
CAIR
program.
In
the
NPR,
EPA
stated
that
EGUs
are
the
most
significant
source
of
SO2
emissions
and
a
very
substantial
source
of
NOx
in
the
affected
region,
and
further
stated
that
highly
cost­
effective
control
technologies
are
available
for
achieving
significant
SO2
and
NOx
emissions
reductions
from
EGUs.
We
requested
comment
on
sources
of
information
for
emissions
and
costs
from
other
sectors
(
69
FR
4610).
A
detailed
discussion
regarding
non­
EGU
sources
is
provided
above.
The
EPA
has
not
144
Section
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2005
DRAFT
Do
Not
Quote
or
Cite
received
additional
information
that
would
change
its
proposed
control
strategy.

Another
criterion
is
the
performance
and
applicability
of
control
measures.
The
NPR
included
a
detailed
discussion
of
the
performance
and
applicability
of
SO2
and
NOx
control
technologies
for
EGUs.
In
particular,
EPA
discussed
FGD
for
SO2
removal
and
SCR
for
NOx
removal,
both
of
which
are
fully
demonstrated
and
available
pollution
control
technologies
on
coal­
fired
EGU
boilers
(
69
FR
4612).
None
of
the
commenters
provided
information
that
differed
from
EPA's
assessment
of
the
performance
of
these
control
measures.
In
addition,
the
commenters
generally
supported
EPA's
assumptions
on
the
applicability
of
these
controls.

The
cost
effectiveness
of
control
measures
is
another
criterion
used
in
EPA's
analysis.
As
discussed
in
detail
above,

EPA
determined
that
the
proposed
control
levels
are
highly
costeffective
and
is
finalizing
the
levels
in
today's
action.
The
EPA
used
IPM
to
analyze
the
cost
effectiveness
of
the
proposed
and
final
CAIR
control
requirements.
IPM
incorporates
assumptions
about
the
capital
costs
and
fixed
and
variable
operations
and
maintenance
costs
of
control
measures
for
EGUs.

Several
commenters
suggested
that
the
SCR
control
cost
assumptions
that
we
used
in
IPM
analysis
for
the
NPR
were
too
145
31
Detailed
documentation
of
EPA's
IPM
update,
including
updated
control
cost
assumptions,
is
in
the
docket.
The
SCR
control
cost
assumptions
were
presented
in
a
peer­
reviewed
paper
by
Sikander
Khan
and
Ravi
Srivastava,
"
Updating
Performance
and
Cost
of
NOx
Control
Technologies
in
the
Integrated
Planning
Model",
at
the
Combined
Power
Plant
Air
Pollution
Control
Mega
Symposium,
August
30­
September
2,
2004,
Washington
D.
C.

Section
IV
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04/
2005
DRAFT
Do
Not
Quote
or
Cite
low.
Consequently,
we
increased
the
SCR
control
cost
assumptions
in
IPM
and
conducted
cost
effectiveness
modeling
for
the
final
control
requirements
using
these
updated
costs.
31
Commenters
generally
supported
our
FGD
control
costs
assumptions,
which
are
largely
unchanged
from
the
NPR
modeling
to
the
modeling
for
today's
final
rule.

And
finally,
EPA
considered
engineering
and
financial
factors
that
affect
the
availability
of
control
measures.
The
EPA
conducted
a
detailed
analysis
of
engineering
factors
that
affect
timing
of
control
retrofits,
including
an
evaluation
of
the
comments
received.
EPA's
analysis
supports
its
proposed
compliance
schedule,
a
two­
phase
emissions
control
program
with
the
final
phase
commencing
in
2015,
and
with
a
first
phase
commencing
in
2010
for
SO2
reductions
and
in
2009
for
NOx
reductions.
Further,
EPA's
analysis
demonstrates
that
it
would
not
be
realistically
possible
to
start
the
program
sooner,
or
to
impose
more
stringent
emissions
caps
in
the
first
phase.

Based
on
EPA's
review
of
comments
and
analysis,
EPA
determined
that
the
proposed
control
requirements
are
reasonable
146
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
with
respect
to
engineering
factors.
As
discussed
above,
EPA
also
considered
how
to
avoid
creating
financial
instability
for
the
affected
sector,
and
how
to
ensure
the
capital
needed
for
the
required
controls
would
be
readily
available.
Assuming
States
choose
to
control
EGUs,
the
power
sector
will
need
to
devote
large
amounts
of
capital
to
meet
the
CAIR
control
requirements.

The
EPA
explained
that
implementing
CAIR
as
a
two­
phase
program,
with
the
more
stringent
control
levels
commencing
in
the
second
phase,
will
allow
time
for
the
power
sector
to
address
any
financial
challenges.
EPA's
evaluation
of
engineering
and
financial
factors
supports
the
decision
to
implement
CAIR
as
a
two­
phase
program,
with
the
final
(
second)
compliance
level
commencing
in
2015
and
a
first
phased­
in
level
starting
in
2010
for
SO2
reductions
and
in
2009
for
NOx
reductions.
A
description
of
the
final
CAIR
control
requirements
follows.

2.
Final
Control
Requirements
Today's
final
rule
implements
new
annual
SO2
and
NOx
emissions
control
requirements
to
reduce
emissions
that
significantly
contribute
to
PM2.5
nonattainment.
The
final
rule
also
requires
new
ozone
season
NOx
emissions
control
requirements
to
reduce
emissions
that
significantly
contribute
to
ozone
nonattainment.
147
Section
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2005
DRAFT
Do
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or
Cite
The
final
rule
requires
annual
SO2
and
NOx
reductions
in
the
District
of
Columbia
and
the
following
23
States:
Alabama,

Florida,
Georgia,
Illinois,
Indiana,
Iowa,
Kentucky,
Louisiana,

Maryland,
Michigan,
Minnesota,
Mississippi,
Missouri,
New
York,

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

Texas,
Virginia,
West
Virginia,
and
Wisconsin.
(
In
the
"
Proposed
Rules"
section
of
today's
Federal
Register
publication,
EPA
is
publishing
a
proposal
to
include
Delaware
and
New
Jersey
in
the
CAIR
region
for
annual
SO2
and
NOx
reductions.)

In
addition,
the
final
rule
requires
ozone
season
NOx
reductions
in
the
District
of
Columbia
and
the
following
25
States:
Alabama,
Arkansas,
Connecticut,
Delaware,
Florida,

Illinois,
Indiana,
Iowa,
Kentucky,
Louisiana,
Maryland,

Massachusetts,
Michigan,
Mississippi,
Missouri,
New
Jersey,
New
York,
North
Carolina,
Ohio,
Pennsylvania,
South
Carolina,

Tennessee,
Virginia,
West
Virginia,
and
Wisconsin.

The
CAIR
requires
many
of
the
affected
States
to
reduce
annual
SO2
and
NOx
emissions
as
well
as
ozone
season
NOx
emissions.
However,
there
are
3
States
for
which
only
annual
emission
reductions
are
required
(
Georgia,
Minnesota
and
Texas).

Likewise,
there
are
5
States
for
which
only
ozone
season
reductions
are
required
(
Arkansas,
Connecticut,
Delaware,

Massachusetts,
and
New
Jersey).
The
following
20
States
and
the
148
32
For
a
discussion
of
the
emission
reduction
requirements
if
States
choose
to
control
sources
other
than
EGUs,
see
section
VII
of
this
preamble.

Section
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04/
2005
DRAFT
Do
Not
Quote
or
Cite
District
of
Columbia
are
required
to
make
both
annual
and
ozone
season
reductions:
Alabama,
Florida,
Illinois,
Indiana,
Iowa,

Kentucky,
Louisiana,
Maryland,
Michigan,
Mississippi,
Missouri,

New
York,
North
Carolina,
Ohio,
Pennsylvania,
South
Carolina,

Tennessee,
Virginia,
West
Virginia
and
Wisconsin.

Table
IV­
14
shows
the
amounts
of
regionwide
annual
SO2
and
NOx
emissions
reductions
under
CAIR
that
EPA
projects,
if
States
choose
to
meet
their
CAIR
obligations
by
controlling
EGUs.
Table
IV­
15
shows
the
amounts
of
regionwide
ozone
season
NOx
emissions
reductions
under
CAIR
that
EPA
projects,
if
States
choose
to
meet
their
CAIR
obligations
by
controlling
EGUs.
If
all
affected
States
choose
to
implement
these
reductions
through
controls
on
EGUs,
the
regionwide
annual
SO2
and
NOx
emissions
caps
that
would
apply
for
EGUs
are
also
shown
in
the
Table
IV­
14,
and
ozone
season
NOx
caps
for
EGUs
are
in
Table
IV­
15.
Base
case
emissions
levels
for
affected
EGUs
as
well
as
emissions
with
CAIR
are
also
shown
in
Table
IV­
14
and
Table
IV­
15,
based
on
IPM
modeling.

EPA
is
finalizing
the
regionwide
EGU
SO2
emissions
caps
 
if
States
choose
to
comply
by
controlling
EGUs
 
as
shown
in
Table
IV­
1432.
As
indicated
above,
EPA
identified
SO2
budget
amounts,

as
target
levels
for
further
evaluation,
by
adding
together
the
149
33
For
a
discussion
of
the
emission
reduction
requirements
if
States
choose
to
control
sources
other
than
EGUs,
see
section
VII
of
this
preamble.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
title
IV
Phase­
II
allowances
for
all
of
the
States
in
the
CAIR
region,
and
making
a
50
percent
reduction
for
the
2010
cap
and
a
65
percent
reduction
for
the
2015
cap.
The
EPA
determined,

through
IPM
analysis,
that
the
resulting
regionwide
emissions
caps
(
if
all
States
choose
to
obtain
reductions
from
EGUs)
are
highly
cost­
effective
levels.

EPA
is
also
finalizing
the
regionwide
EGU
annual
and
ozone
season
NOx
emission
caps
 
if
States
choose
to
comply
by
controlling
EGUs
 
as
shown
in
Table
IV­
14
and
Table
IV­
1533.
As
indicated
above,
EPA
identified
NOx
budget
amounts,
as
target
levels
for
further
evaluation,
through
the
methodology
of
determining
the
highest
recent
Acid
Rain
Program
heat
input
from
years
1999­
2002
for
each
affected
State,
summing
the
highest
State
heat
inputs
into
a
regionwide
heat
input,
and
multiplying
the
regionwide
heat
input
by
0.15
lb/
mmBtu
and
0.125
lb/
mmBtu
for
2009
and
2015,
respectively.
The
EPA
determined,
through
IPM
analysis,
that
the
resulting
regionwide
emissions
caps
(
if
all
States
choose
to
obtain
reductions
from
EGUs)
are
highly
costeffective
levels.

The
emission
reductions,
EGU
emissions
caps,
and
emissions
shown
in
Table
IV­
14
are
for
the
23
States
and
the
District
of
150
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Columbia
that
are
required
to
make
annual
SO2
and
NOx
reductions
for
CAIR.
(
Table
IV­
14
does
not
include
information
for
the
5
States
that
are
required
to
make
ozone
season
reductions
only.)

The
emission
reductions,
EGU
emissions
caps,
and
emissions
shown
in
Table
IV­
15
are
for
the
25
States
and
the
District
of
Columbia
that
are
required
to
make
ozone
season
NOx
reductions
for
CAIR.
(
Table
IV­
15
does
not
include
information
for
the
3
States
that
are
required
to
make
annual
reductions
only.)

EPA
is
requiring
the
CAIR
SO2
and
NOx
emissions
reductions
in
two
phases.
For
States
affected
by
annual
SO2
and
NOx
emission
reductions
requirements,
the
final
(
second)
phase
commences
January
1,
2015,
and
the
first
phase
begins
January
1,

2010
for
SO2
reductions
and
January
1,
2009
for
NOx
reductions.

For
States
affected
by
ozone
season
NOx
emission
reductions
requirements,
the
final
(
second)
phase
commences
May
1,
2015
and
the
first
phase
starts
May
1,
2009.
Notably,
the
first
phase
control
requirements
are
effective
in
years
2010
through
2014
for
SO2
and
in
years
2009
through
2014
for
NOx,
and
the
2015
requirements
are
for
that
year
and
thereafter.
151
34
Table
IV­
14
includes
regionwide
information
for
the
23
States
and
DC
that
are
required
by
CAIR
to
make
annual
emission
reductions.
It
does
not
include
information
for
the
5
CAIR
States
that
are
required
to
make
ozone
season
reductions
only.
The
CAIR
requires
NOx
emission
reductions
in
a
total
of
28
States
and
DC.
For
20
States
and
DC,
both
annual
and
ozone
season
NOx
reductions
are
required.
For
3
States
only
annual
reductions
are
required,
and
for
5
States
only
ozone
season
reductions
are
required.
The
total
projected
NOx
emission
reductions
that
will
result
from
CAIR
B
if
all
States
control
EGUs
B
include
the
annual
reductions
shown
in
Table
IV­
14
(
for
23
States
and
DC)
plus
the
ozone
season
reductions
in
the
5
States
required
to
make
ozone
season
reductions
only.
EPA
projects
the
total
NOx
reductions,
in
all
28
CAIR
States
and
DC,
to
be
1.2
million
tons
in
2009
and
1.5
million
tons
in
2015.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
TABLE
IV­
14.
­
FINAL
RULE
SO2
AND
NOx
ANNUAL
BASE
CASE
EMISSIONS,
EMISSIONS
CAPS,
EMISSIONS
AFTER
CAIR
AND
EMISSION
REDUCTIONS
IN
THE
REGION
REQUIRED
TO
MAKE
ANNUAL
SO2
AND
NOx
REDUCTIONS
(
23
STATES
AND
DC)
FOR
THE
INTERIM
PHASE
(
2010
FOR
SO2
AND
2009
FOR
NOx)
AND
FINAL
PHASE
(
2015
FOR
SO2
AND
NOx)
FOR
ELECTRIC
GENERATION
UNITS
(
MILLION
TONS)
34
First
Phase
(
2010
for
SO2
and
2009
for
NOx)

Base
Case
Emissions
CAIR
Emissions
Caps
Emissions
After
CAIR
Emissions
Reduced
SO2
8.7
3.6
5.1
3.5
NOx
2.7
1.5
1.5
1.2
Sum
11.4
NA
6.6
4.8
Second
Phase
(
2015
for
SO2
and
NOx)

Base
Case
Emissions
CAIR
Emissions
Caps
Emissions
After
CAIR
Emissions
Reduced
SO2
7.9
2.5
4.0
3.8
NOx
2.8
1.3
1.3
1.5
Sum
10.6
NA
5.3
5.3
NOTE:
Numbers
may
not
add
due
to
rounding.

1
The
emission
caps
that
EPA
used
to
make
its
determination
of
highly
cost­
effective
controls
and
the
emission
reductions
associated
with
those
caps
are
shown
in
Table
IV­
14.
For
a
discussion
of
the
emission
reduction
requirements
if
States
control
source
categories
other
than
EGUs,
see
section
VII
in
this
preamble.
Emissions
shown
here
are
for
EGUs
with
capacity
greater
than
25
MW.
152
35
Table
IV­
15
shows
regionwide
information
for
the
25
States
and
DC
that
are
required
to
make
ozone
season
emission
reductions
under
CAIR.
It
does
not
include
information
for
the
3
States
that
are
required
to
make
annual
emission
reductions
only.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
2
The
District
of
Columbia
and
the
following
23
States
are
affected
by
CAIR
for
annual
SO2
and
NOx
controls:
AL,
FL,
GA,
IA,
IL,
IN,
KY,
LA,
MD,
MI,
MN,
MO,
MS,
NY,
NC,
OH,
PA,
SC,
TN,
TX,
VA,
WV,
WI.
3
The
2010
SO2
emissions
cap
applies
to
years
2010
through
2014.
The
2009
NOx
emissions
cap
applies
to
years
2009
through
2014.
The
2015
caps
apply
to
2015
and
beyond.
4
Due
to
the
use
of
the
existing
bank
of
SO2
allowances,
the
estimated
SO2
emissions
in
the
CAIR
region
in
2010
and
2015
are
higher
than
the
emissions
caps.
5
Over
time
the
banked
SO2
emissions
allowances
will
be
consumed
and
the
2015
cap
level
will
be
reached.
SO2
emissions
levels
can
be
thought
of
as
on
a
flexible
"
glide
path"
to
meet
the
2015
CAIR
cap
with
increasing
reductions
over
time.
The
annual
SO2
emissions
levels
in
2020
with
CAIR
are
forecasted
to
be
3.3
million
tons
within
the
region
encompassing
States
required
to
make
annual
reductions,
an
annual
reduction
of
4.4
million
tons
from
base
case
levels.

TABLE
IV­
15.
­
FINAL
RULE
NOx
OZONE
SEASON
BASE
CASE
EMISSIONS,
EMISSIONS
CAPS,
EMISSIONS
AFTER
CAIR
AND
EMISSION
REDUCTIONS
IN
THE
REGION
REQUIRED
TO
MAKE
OZONE
SEASON
NOx
REDUCTIONS
(
25
STATES
AND
DC)
FOR
THE
INTERIM
PHASE
(
2009)
AND
FINAL
PHASE
(
2015)
FOR
ELECTRIC
GENERATION
UNITS
(
MILLION
TONS)
35
Ozone
Season
NOx
Phase
Base
Case
Emissions
CAIR
Emissions
Caps
Emissions
after
CAIR
Emissions
Reduced
2009
0.7
0.6
0.6
0.1
2015
0.7
0.5
0.5
0.2
1
The
emission
caps
that
EPA
used
to
make
its
determination
of
highly
cost­
effective
controls
and
the
emission
reductions
associated
with
those
caps
are
shown
in
Table
IV­
15.
For
a
discussion
of
the
emission
reduction
requirements
if
States
control
source
categories
other
than
EGUs,
see
section
VII
in
this
preamble.
Emissions
shown
here
are
for
EGUs
with
capacity
greater
than
25
MW.
2
The
District
of
Columbia
and
the
following
25
States
are
affected
by
CAIR
for
ozone
season
NOx
controls:
AL,
AR,
CT,
DE,
FL,
IA,
IL,
IN,
KY,
LA,
MA,
MD,
MI,
MO,
MS,
NJ,
NY,
NC,
OH,
PA,
SC,
TN,
VA,
WV,
WI.
3
The
2009
NOx
emissions
cap
applies
to
years
2009
through
2014.
The
2015
cap
applies
to
2015
and
beyond.
153
36
For
a
discussion
of
the
emission
reduction
requirements
if
States
choose
to
control
sources
other
than
EGUs,
see
section
VII
of
this
preamble.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
Table
IV­
16
shows
the
estimated
amounts
of
regionwide
annual
SO2
and
NOx
emissions
reductions
that
would
occur
if
EPA
finalizes
its
proposal
to
find
that
Delaware
and
New
Jersey
contribute
significantly
to
downwind
PM2.5
nonattainment,
and
if
all
affected
States
choose
to
control
EGUs
(
the
proposal
is
published
in
the
"
Proposed
Rules"
section
of
today's
Federal
Register
publication).
In
that
case,
the
estimated
regionwide
annual
SO2
and
NOx
emissions
caps
that
would
apply
for
EGUs
are
as
shown
in
Table
IV­
16.
Annual
base
case
emissions
levels
for
EGUs
in
the
CAIR
region
(
including
Delaware
and
New
Jersey)
as
well
as
emissions
with
CAIR
are
also
shown
in
the
Table,
based
on
IPM
modeling.
If
EPA
finalizes
its
proposal
to
include
Delaware
and
New
Jersey
for
PM2.5
requirements,
then
the
ozone
season
requirements
would
not
change
for
States
required
to
make
ozone
season
reductions
for
CAIR.
Based
on
EPA
modeling
with
Delaware
and
New
Jersey
included
in
the
PM2.5
region
(
and
if
all
affected
States
choose
to
control
EGUs),
the
EGU
emissions
caps
and
the
ozone
season
NOx
emissions
and
emission
reductions
associated
with
those
caps,
for
the
25
States
and
the
District
of
Columbia
that
are
required
to
make
ozone
season
NOx
reductions,
would
be
as
shown
in
Table
IV­
15,
above36.
154
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
155
37
Table
IV­
16
includes
regionwide
information
for
the
25
States
and
DC
that
will
be
required
to
make
annual
emission
reductions
if
EPA
finalizes
its
proposal
to
require
annual
reductions
in
Delaware
and
New
Jersey
under
CAIR.
The
table
does
not
include
information
for
the
3
States
(
Arkansas,
Connecticut,
and
Massachusetts)
that
would
be
affected
by
CAIR
for
ozone
season
reductions
only.

Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
TABLE
IV­
16.
­
SO2
AND
NOx
ANNUAL
BASE
CASE
EMISSIONS,
EMISSIONS
CAPS,
EMISSIONS
AFTER
CAIR
AND
EMISSION
REDUCTIONS
IN
THE
REGION
REQUIRED
TO
MAKE
ANNUAL
SO2
AND
NOx
REDUCTIONS
(
25
STATES
AND
DC)
FOR
THE
INITIAL
PHASE
(
2010
FOR
SO2
AND
2009
FOR
NOx)
AND
FINAL
PHASE
(
2015
FOR
SO2
AND
NOx)
FOR
ELECTRIC
GENERATION
UNITS
IF
EPA
FINALIZES
ITS
PROPOSAL
TO
INCLUDE
DELAWARE
AND
NEW
JERSEY
FOR
PM2.5
REQUIREMENTS
(
MILLION
TONS)
37
First
Phase
(
2010
for
SO2
and
2009
for
NOx)

Base
Case
Emissions
CAIR
Emissions
Caps
Emissions
After
CAIR
Emissions
Reduced
SO2
8.8
3.7
5.2
3.6
NOx
2.8
1.5
1.5
1.2
Sum
11.5
NA
6.7
4.8
Second
Phase
(
2015
for
SO2
and
NOx)

Base
Case
Emissions
CAIR
Emissions
Caps
Emissions
After
CAIR
Emissions
Reduced
SO2
7.9
2.6
4.1
3.9
NOx
2.8
1.3
1.3
1.5
Sum
10.7
NA
5.3
5.4
NOTE:
Numbers
may
not
add
due
to
rounding.

1
The
emission
caps
that
EPA
used
to
make
its
determination
of
highly
cost­
effective
controls
and
the
emission
reductions
associated
with
those
caps
are
shown
in
Table
IV­
16.
For
a
discussion
of
the
emission
reduction
requirements
if
States
control
source
categories
other
than
EGUs,
see
section
VII
in
this
preamble.
Emissions
shown
here
are
for
EGUs
with
capacity
greater
than
25
MW.
2
The
District
of
Columbia
and
the
following
25
States
would
be
affected
by
CAIR
for
annual
SO2
and
NOx
controls
if
EPA
finalizes
its
proposal
to
include
DE
and
NJ:
AL,
DE,
FL,
GA,
IA,
IL,
IN,
KY,
LA,
MD,
MI,
MN,
MO,
MS,
NJ,
NY,
NC,
OH,
PA,
SC,
TN,
TX,
VA,
WV,
WI.
3
The
2010
SO2
emissions
cap
would
apply
to
years
2010
through
2014.
The
2009
NOx
emissions
cap
would
apply
to
years
2009
through
2014.
The
2015
caps
would
apply
to
2015
and
beyond.
156
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
4
Due
to
the
use
of
the
existing
bank
of
SO2
allowances,
the
estimated
SO2
emissions
in
the
CAIR
region
in
2010
and
2015
would
be
higher
than
the
emissions
caps.
5
Over
time
the
banked
SO2
emissions
allowances
would
be
consumed
and
the
2015
cap
level
would
be
reached.
SO2
emissions
levels
can
be
thought
of
as
on
a
flexible
"
glide
path"
to
meet
the
2015
CAIR
cap
with
increasing
reductions
over
time.
The
annual
SO2
emissions
levels
in
2020
with
CAIR,
within
the
region
of
States
required
to
make
annual
reductions
(
including
Delaware
and
New
Jersey),
are
forecasted
to
be
3.3
million
tons,
an
annual
reduction
of
4.4
million
tons
from
base
case
levels.

EPA
apportioned
the
EGU
caps
B
and
associated
required
regionwide
emission
reductions
B
on
a
State­
by­
State
basis.
The
affected
States
may
determine
the
necessary
controls
on
SO2
and
NOx
emissions
to
achieve
the
required
reductions.
EPA's
apportionment
method
and
the
resulting
State
EGU
emissions
budgets
are
described
in
Section
V
in
today's
preamble.

To
achieve
the
required
SO2
and
NOx
reductions
in
the
most
cost­
effective
manner,
EPA
suggests
that
States
implement
these
reductions
by
controlling
EGUs
under
a
cap­
and­
trade
program
that
EPA
would
implement.

However,
the
States
have
flexibility
in
choosing
the
sources
that
must
reduce
emissions.
If
the
States
choose
to
require
EGUs
to
reduce
their
emissions,
then
States
must
impose
a
cap
on
EGU
emissions,
which
would
in
effect
be
an
annual
emissions
budget.

Provisions
for
allocating
SO2
and
NOx
allowances
to
individual
EGUs
 
which
apply
if
a
State
chooses
to
control
EGUs
and
elects
to
allow
them
to
participate
in
the
interstate
cap­
and­
trade
program
 
are
presented
elsewhere
in
today's
preamble.
If
a
State
wants
to
control
EGUs,
but
does
not
want
to
allow
EGUs
to
157
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
participate
in
the
interstate
cap­
and­
trade
program,
the
State
has
flexibility
in
allocating
allowances,
but
it
must
cap
EGUs.

Sources
that
are
subject
to
the
emission
reduction
requirements
under
title
IV
continue
to
be
subject
to
those
requirements.

If
the
States
choose
to
control
other
sources,
then
they
must
employ
methods
to
assure
that
those
other
sources
implement
controls
that
will
yield
the
appropriate
amount
of
annual
emissions
reduction.
See
Section
VII
(
SIP
Criteria
and
Emissions
Reporting
Requirements)
in
today's
preamble.

Implementation
of
the
cap­
and­
trade
program
is
discussed
in
Section
VIII
in
today's
preamble.

For
convenience,
we
use
specific
terminology
to
refer
to
certain
concepts.
"
State
budget"
refers
to
the
Statewide
emissions
that
may
be
used
as
an
accounting
technique
to
determine
the
amount
of
annual
or
ozone
season
emissions
reductions
that
controls
may
yield.
It
does
not
imply
that
there
is
a
legally
enforceable
Statewide
cap
on
emissions
from
all
SO2
or
NOx
sources.
"
Regionwide
budget"
refers
to
the
amount
of
emissions,
computed
on
a
regionwide
basis,
which
may
be
used
to
determine
State­
by­
State
requirements.
It
does
not
imply
that
there
is
a
legally
enforceable
regionwide
cap
on
emissions
from
all
SO2
or
NOx
sources.
"
State
EGU
budget"
refers
to
the
legally
158
Section
IV
3/
04/
2005
DRAFT
Do
Not
Quote
or
Cite
enforceable
annual
or
ozone
season
emissions
cap
on
EGUs
a
State
would
apply
should
it
decide
to
control
EGUs.
