Document ID: EPA-HQ-OAR-2003-0053-2360
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2006-03-17T05:00Z

Technical
Support
Document
for
the
Rule
to
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Clean
Air
Interstate
Rule):
Reconsideration
Notice
of
Proposed
Rule
CAIR
SO2
Allocation
Approach
Analysis
EPA
Docket
number:
OAR­
2003­
0053
March
2006
U.
S.
Environmental
Protection
Agency
Office
of
Air
and
Radiation
2
Introduction
This
technical
support
document
(
TSD)
presents
analysis
the
United
States
Environmental
Protection
Agency
(
EPA)
performed
to
support
its
Notice
of
Final
Action
on
Reconsideration
of
the
Clean
Air
Interstate
Rule
(
CAIR)
(
70
FR
25162)
specific
to
the
sulfur
dioxide
(
SO2)
allocation
methodology.

EPA
received
one
petition
for
reconsideration
that
asked
EPA
to
reconsider
the
SO2
allocation
approach
to
be
used
by
States
participating
in
the
EPA­
administered
CAIR
SO2
trading
program.
As
described
in
the
Notice
of
Final
Action
on
Reconsideration,
this
petitioner
argued
that
the
SO2
allowance
allocation
approach
is
unreasonable
and
inequitable.
The
petitioner
argued
that
the
approach
is
unreasonable
because
other
approaches
would
be
more
appropriate.
According
to
the
petitioner,
the
approach
is
inequitable
because
it
results
in
owners
of
units
that
have
historically
lower
emission
rates
being
forced
to
buy
allowances
from
historically
higher
emitting
units
that
install
new
emission
controls.
The
petitioner
asked
EPA
to
establish
a
different
approach.

As
described
in
the
Notice
of
Reconsideration,
EPA
does
not
agree
with
petitioner's
conclusions
about
this
issue.
EPA
continues
to
believe
that
the
approach
selected
is
reasonable
for
the
reasons
explained
in
the
CAIR
final
rule
and
further
discussed
below.
Furthermore,
numerous
opportunities
for
public
comment
on
this
issue
were
provided,
and
a
full
discussion
of
the
allowance
allocation
options
occurred
during
the
rule
development
process.
Nonetheless,
given
the
intense
public
interest
in
this
issue,
EPA
decided
to
grant
the
petition
for
reconsideration
insofar
as
it
raised
issues
regarding
alleged
inequities
resulting
from
the
application
of
EPA's
SO2
allowance
allocation
approach.

In
the
Notice
of
Reconsideration,
EPA
announced
its
decision
to
reconsider
this
issue
and
solicited
additional
public
input.
EPA
also
solicited
comment
on
additional
analyses
it
conducted
in
response
to
the
petition
for
reconsideration
concerning
the
impact
of
the
SO2
allowance
allocation
approach
adopted
in
the
CAIR
model
trading
rule.
This
additional
analysis
compared
the
SO2
allocation
approach
in
CAIR
to
various
alternatives
EPA
also
considered
during
the
rulemaking
process.
In
response
to
comment
on
the
Notice
of
Reconsideration,
EPA
has
further
refined
some
of
its
analyses
and
carefully
considered
the
arguments
of
the
petitioner.

EPA
continues
to
believe
that
these
analyses
show
that
EPA's
selected
approach
to
SO2
allowance
allocations
is
appropriate,
given
the
objectives
of
CAIR
and
other
relevant
considerations.
Moreover,
EPA
believes
that
the
Agency's
approach
produces
a
reasonable
result
in
terms
of
equity.
Therefore,
in
this
Notice
of
Final
Action
on
Reconsideration,
EPA
is
not
altering
the
approach
taken
in
CAIR
for
SO2
allowance
allocation.
EPA's
response
to
public
comments
on
the
analyses
presented
in
the
Notice
of
Reconsideration
and
further
discussion
of
the
petitioner's
concerns
are
provided
below.

The
underlying
data,
including
data
for
both
2010
and
2015,
are
available
in
the
docket
(
OAR­
2003­
0053),
as
"
SO2
Allowance
Allocation
Data."
3
Considerations
Relevant
to
Choosing
an
Allocation
Approach
While
EPA
did
not
explicitly
define
a
distinct
set
of
principles
that
should
be
used
in
developing
State
budgets
under
a
region­
wide
cap
and
trade
program,
EPA
has
made
it
clear
throughout
this
process
that
it
has
relied
upon
several
consistent,
important
factors
in
developing
both
the
SO2
and
NOx
budgets.

The
first
is
the
impact
of
allowance
allocations
on
the
specific
environmental
objectives
and
overall
cost
of
the
rule,
as
well
as
any
potential
adverse
effects.
In
general,
while
the
chosen
allocation
or
State
budget
calculation
approach
can
affect
the
distribution
of
compliance
costs
under
a
cap­
and­
trade
program,
it
will
have
little
effect
on
overall
compliance
costs
or
environmental
outcome.
This
is
because
the
incentives
provided
by
cap­
and­
trade
encourage
economically
efficient
compliance
over
the
entire
region.
However,
this
may
not
always
hold
where
there
are
interactions
with
existing
environmental
policies.
In
the
case
of
NOx,
EPA
did
not
find
this
consideration
to
be
restrictive
because
there
was
not
an
existing
annual
NOx
trading
program
and
the
SIP
Call
ozone
season
trading
program
could
be
easily
integrated
into
the
CAIR
ozone
season
trading
program.
As
a
result,
a
number
of
budget
methodologies
were
compatible.
For
SO2,
this
consideration
played
a
larger
role
because
depending
upon
how
the
program
was
integrated
within
the
existing
Title
IV
structure,
it
could
impact
emissions
before
the
program
went
into
affect
as
well
as
emissions
in
regions
not
affected
by
the
program.

Another
important
consideration
is
that
an
allocation
methodology
must
be
consistent
with
the
existing
regulatory
and
legislative
structure.
Once
again
for
NOx,
this
consideration
could
be
satisfied
with
a
wide
range
of
budget
methodologies.
However,
for
SO2,
reductions
for
EGUs
using
Title
IV
allowances
is
necessary
in
order
to
ensure
the
preservation
of
a
viable
Title
IV
program
(
70
FR
72272).
Linking
the
two
programs
maintains
the
trust
and
confidence
that
has
developed
in
the
functioning
market
for
title
IV
allowances.
The
EPA
recognizes
this
familiarity
and
confidence
(
especially
in
a
market­
based
approach)
as
a
key
source
of
the
program's
success.

A
third
factor
is
equity.
In
the
absence
of
other
considerations,
EPA
believes
that
it
is
in
the
public
interest
that
the
distribution
of
allowances
under
a
cap
and
trade
program
be
as
equitable
as
possible.
For
NOx,
since
the
other
considerations
could
be
satisfied
with
a
number
of
different
methodologies,
this
factor
was
the
primary
one.
For
SO2,
where
the
other
considerations
were
more
limiting,
this
factor
was
not
as
central
to
our
decisions,
especially
since
the
Title
IV
allocation
structure
was
erected
by
Congress
for
the
long
term.

SO2
Allocation
Options
Discussed
in
CAIR
EPA
considered
and
analyzed
a
variety
of
SO2
allowance
allocation
methodologies
during
the
CAIR
rulemaking
process.
After
careful
analysis,
EPA
decided
to
use
the
allocation
approach
chosen
by
Congress
in
title
IV
of
the
Clean
Air
Act.
EPA
also
considered
the
following
alternative
approaches,
which
are
explained
in
the
final
CAIR
"
Corrected
Response
to
Significant
Public
Comments
on
the
Proposed
Clean
Air
Interstate
Rule,"
Corrected
April
2005
(
Docket
Number
OAR­
2003­
0053):
4
­
Allocations
based
on
historic
tons
of
actual
emissions
from
more
recent
years;
­
Allocations
based
on
heat
input
(
with
alternatives
based
on
heat
input
from
all
fossil
generation,
and
heat
input
from
coal­
and
oil­
fired
generation
only);
and
­
Allocations
based
on
electricity
output
(
with
alternatives
based
on
all
generation
and
all
fossil­
fired
generation).

In
addition
to
these
alternatives,
EPA
has
analyzed
other
heat
input­
based
allocation
approaches
in
the
reconsideration
process,
explained
below.
Each
allocation
approach
suggested
by
the
petitioner
and
other
commenters
during
the
CAIR
rulemaking
and
reconsideration
process
has
advantages
and
disadvantages
for
different
companies
and
States.
However,
as
explained
in
the
final
CAIR,
EPA
believes
that
the
approach
used
in
the
final
CAIR
is
the
most
appropriate
among
the
alternatives
for
several
reasons.

First,
EPA
believes
 
based
on
strong
policy
and
air
quality
concerns
 
that
it
is
necessary
to
use
the
existing
title
IV
allowances
in
order
to
preserve
the
viability
and
emissions
reductions
of
the
highly
successful
title
IV
program.
The
disruption
of
the
title
IV
SO2
trading
program
would
also
potentially
result
in
increased
emissions
outside
of
the
CAIR
region
starting
in
2010
because,
with
title
IV
allowances
having
little
or
no
value,
the
title
IV
program
would
no
longer
constrain
SO2
emissions
in
those
States.
Further,
if
title
IV
allowances
are
not
used
for
compliance
in
the
CAIR
SO2
trading
program,
the
likely
result
will
be:
a
significant
surplus
of
title
IV
allowances;
a
collapse
of
the
price
of
title
IV
allowances;
and
a
title
IV
SO2
trading
program
that,
contrary
to
Congressional
intent,
no
longer
provides
incentives
to
minimize
emission
control
costs
and
encourage
pollution
prevention
and
innovation.

If
EPA
adopts
an
approach
that
does
not
preserve
the
structure
of
the
title
IV
allowance
market
and
the
value
of
those
allowances,
the
confidence
in
the
cap­
and­
trade
policy
instrument
and
allowance
markets
in
general,
and
in
the
CAIR
cap­
and­
trade
programs
in
particular,
would
likely
decline.
Such
an
outcome
could
result
in
a
reduced
willingness
of
the
owners
of
sources
in
cap­
and­
trade
programs
to
invest
in
control
technologies
that
would
generate
excess
allowances
for
sale,
or
to
purchase
allowances
for
compliance,
for
fear
that
the
rules
might
change.
If
owners
were
to
ignore
the
incentives
provided
by
cap­
and­
trade
in
such
a
manner,
efficiency
and
cost­
savings
provided
by
these
programs
would
be
lost.
The
preservation
of
title
IV
allowances
for
use
in
CAIR,
then,
is
integral
to
the
viability
and
effectiveness
of
both
title
IV
and
the
CAIR
trading
programs.
See
discussion
in
preamble
to
the
final
CAIR
in
section
IX
(
70
FR
25293­
25295).

Second,
EPA
relied
on
the
permanent
allocation
methodology
established
by
Congress
in
title
IV
for
purposes
of
reducing
SO2
emissions.
Congress
chose
a
policy
of
not
revisiting
and
revising
these
allocations
and,
apparently,
believed
that
its
allocation
methodology
for
title
IV
allowances
would
be
appropriate
for
future
time
periods.
Third,
title
IV
allowance
allocations
provide
a
logical
and
well
understood
starting
point
from
which
additional
electric
generation
unit
(
EGU)
SO2
emission
reductions
can
be
achieved
for
Acid
Rain
units,
which
account
for
over
90
percent
of
the
SO2
emissions
from
CAIR
EGUs.
5
Finally,
in
response
to
comments
on
the
proposed
CAIR,
EPA
performed
an
analysis
comparing
the
title
IV
methodology
to
other
methodologies.
At
the
outset,
EPA
notes
that
the
objective
of
CAIR
is
not
to
ensure
that
each
State
receives
the
maximum
amount
of
SO2
allowances
possible
under
any
approach.
The
goal
of
CAIR
is
to
reduce
SO2
emissions
that
significantly
contribute
to
non­
attainment.
As
EPA
has
noted,
selecting
the
most
appropriate
SO2
allowance
allocation
approach
for
CAIR
has
required
addressing
a
number
of
different
considerations.
The
policy
and
air
quality
concerns
specific
to
the
CAIR
SO2
trading
program
and
noted
by
EPA
above
necessitate
that
EPA
implement
the
CAIR
SO2
program
using
the
existing
structure
of
title
IV.
Nevertheless,
EPA
has
analyzed
the
impact
of
using
title
IV
allocations
on
States
relative
to
other
possible
allocation
approaches.

EPA's
analysis
indicates
that
the
use
of
title
IV
allowances
in
the
CAIR
SO2
trading
program
has
a
reasonable
result
(
See
CAIR
Corrected
Response
to
Comments,
section
X.
A.
26,
Docket
#:
EPA­
HQ­
OAR­
2003­
0053­
2172).
This
analysis
compares
State
budgets
(
as
a
percent
of
the
total
CAIR
regional
budget)
calculated
based
on
title
IV
allowances
with
State
budgets
calculated
using
the
other
suggested
SO2
allocation
approaches.
In
more
than
two­
thirds
of
CAIR
States
(
accounting
for
about
80
percent
of
the
total
heat
input
in
the
CAIR
region
from
1999­
2002),
the
use
of
title
IV
allowances
results
in
each
State
having
neither
the
highest
nor
the
lowest
percentage
of
the
region­
wide
SO2
budget,
but
instead,
a
percentage
that
is
well
within
the
range
of
percentages
that
the
States
would
receive
under
all
of
the
alternative
options
considered.

For
example,
Ohio's
trading
budget
for
2010
under
EPA's
method
is
333,520
tons,
which
is
about
9
percent
of
the
CAIR
region
trading
budget
of
3,619,196
tons.
1
If
Ohio's
budget
were
calculated
based
on
historic
tons
of
emissions,
it
would
receive
approximately
12
percent
of
the
total
CAIR
budget.
If
Ohio's
budget
were
calculated
based
on
output,
it
would
receive
approximately
5
percent
of
the
total
CAIR
budget.
The
allocation
approach
based
on
title
IV,
thus,
provides
Ohio
with
a
budget
in
the
middle
of
the
range
of
the
options
analyzed.

EPA
recognizes,
of
course,
that
the
relative
impact
of
allocations
based
on
title
IV
allowances
as
compared
to
alternative
approaches
will
vary
among
States
and
individual
companies.
However,
each
alternative
allocation
approach
would
disadvantage
some
States
or
companies
relative
to
another
alternative
allowance
allocation
approach.
EPA
must,
nevertheless,
select
a
method
for
SO2
allowance
allocation
and
must
be
sensitive
to
competing
considerations.

In
summary,
EPA's
use
of
title
IV
allowances
in
the
CAIR
SO2
trading
program
is
supported
by:
(
1)
EPA's
determination
that
this
approach
is
necessary
to
maintain
the
efficacy
of
the
title
IV
program
and
to
prevent
erosion
of
confidence
in
cap­
and­
trade
programs
in
general;
and
(
2)
EPA's
analysis
showing
that
the
allocations
resulting
from
this
approach
are
reasonable.
Nevertheless,
as
a
part
of
this
reconsideration,
EPA
performed
additional
analyses,
explained
below,
to
evaluate
the
SO2
allocation
approach
in
the
final
CAIR
in
light
of
the
petitioner's
concerns.

1
EPA's
methodology
to
calculate
the
Regional
and
State
budgets
is
described
in
the
TSD
in
the
docket
http://
www.
epa.
gov/
cair/
pdfs/
finaltech06.
pdf,
6
Response
to
Comments
on
the
Equitability
of
CAIR
SO2
Allocation
Approach
One
commenter
argued
that
EPA
should
evaluate
SO2
allowance
allocation
approaches
using
the
same
metrics
and
methods
that
it
used
for
NOx
allocations.
The
commenter
suggests
that
the
metrics
by
which
EPA
assessed
NOx
allocations
included
(
1)
whether
the
EPA
method
avoids
penalizing
coal­
fired
generation
units
that
already
have
installed
emissions
controls
and
(
2)
whether,
relative
to
the
alternative
allocation
approaches,
the
EPA
method
better
minimizes
for
each
State
the
disparity
between
allowances
provided
and
projected
emissions,
and
argued
that
EPA
cites
these
rationales
in
justifying
its
chosen
NOx
allocation
approach.
This
commenter
also
suggests
that
EPA's
use
of
title
IV
allowances
penalizes
new
units
and
independent
power
producers
(
IPPs)
and
results
in
large
wealth
transfers
from
low­
emitting
to
high­
emitting
States.

While
EPA
agrees
that
the
Agency
considered
these
factors
(
among
several
others)
in
choosing
its
allocation
approach
under
the
CAIR
NOx
trading
programs,
EPA
does
not
fully
agree
with
the
commenter's
characterization
of
EPA's
considerations.
EPA
believes
that
the
commenter
has
omitted
some
of
the
significant
context
and
caveats
that
were
included
in
the
discussion
of
NOx
allocations
and
the
use
of
fuel
adjustment
factors
in
the
reconsideration
notice,
as
well
as
a
number
of
other
factors
that
EPA
must
consider,
particularly
in
the
context
of
SO2
allocations.
First,
EPA
noted
in
the
June
10,
2004
Supplemental
Notice
of
Proposed
Rulemaking
and
in
the
Notice
of
Reconsideration
that,
"
in
contrast
to
allocations
based
on
historic
emissions,
the
factor
would
also
not
penalize
coal­
fired
plants
that
have
already
installed
pollution
controls"
(
69
FR
32869,
70
FR
72276,
emphasis
added).
This
language
explains
that
allocations
using
historic
heat
input
adjusted
for
fuel
type,
while
providing
additional
allowances
to
coal­
fired
units
that
will
likely
install
controls
under
CAIR,
would
not
simultaneously
penalize
coal­
fired
units
that
had
already
made
investments
in
emissions
controls.

An
approach
based
on
historic
emissions,
on
the
other
hand,
would
also
provide
additional
allowances
to
units
that
would
likely
have
to
install
controls,
but
would
simultaneously
penalize
units
that
had
already
done
so.
While
EPA
makes
this
argument
in
support
of
its
chosen
approach
for
NOx
allocations,
the
Agency
does
not
raise
this
point
to
establish
a
criterion
for
evaluating
allowance
allocation
approaches.
Rather,
it
simply
notes
that
its
chosen
approach
for
NOx
allocations
can
provide
an
advantage
to
one
set
of
coal­
fired
units
without
disadvantaging
another
set
of
coal­
fired
units.

Second,
while
the
commenter
is
correct
in
noting
that
EPA
stated
in
its
discussion
of
NOx
allocations
in
the
Notice
of
Reconsideration
that
it
is
in
the
public
interest
to
attempt
to
minimize
the
disparity
between
individual
State
budgets
and
projected
emissions
for
each
State,
EPA
did
not
set
this
goal
as
one
of
only
two
primary
criteria
for
adoption
of
a
given
allocation
strategy,
as
the
commenter
suggests.
Rather,
EPA
notes
that
"
In
the
absence
of
other
considerations,
EPA
believes
that
it
is
in
the
public
interest
to
reduce
the
disparity
between
the
number
of
allowances
in
a
State
budget
and
total
projected
State
EGU
emissions"
(
70
FR
72276,
emphasis
added).
As
EPA
has
noted,
equity
is
one
of
many
considerations
faced
by
EPA
in
choosing
an
SO2
allowance
allocation
approach.
In
particular,
unlike
in
the
case
of
NOx,
EPA
had
to
consider
an
existing,
nationwide
trading
program
implemented
by
statute
in
the
case
of
SO2.
7
Third,
as
EPA
discussed
in
the
CAIR
Response
to
Comments,
while
commenters
express
concern
about
the
availability
of
allowances
for
non­
Acid
Rain
units,
it
should
be
noted
that
not
all
sources
covered
under
the
Acid
Rain
program
received
allowances.
By
the
design
of
the
title
IV
program
(
as
outlined
by
Congress),
because
of
the
permanent
allocation
of
allowances,
new
units
beginning
commercial
operation
after
1995
or
beginning
construction
after
1990
did
not
receive
title
IV
allowances.
Thus,
Congress
recognized
that,
over
time,
new
units
would
be
built
and
covered
under
the
program,
but
felt
it
reasonable
that
such
units
would
obtain
title
IV
allowances
either
through
the
auction
or
from
the
market.
Under
the
auction,
250,000
title
IV
allowances
will
be
auctioned
annually
for
the
years
2012
and
beyond,
and
these
allowances
can
be
used
for
compliance
with
CAIR.
The
availability
of
these
allowances
ensures
that
all
sources,
including
new
units
and
non­
title
IV
sources,
will
have
access
to
a
pool
of
allowances,
protecting
them
from
potential
exercise
of
market
power
by
market
participants
holding
allowances.
Finally,
IPPs
have
the
option
of
opting
in
to
title
IV
until
their
exemption
expires
in
order
to
obtain
title
IV
allowances.
EPA
addresses
other
issues
specific
to
IPPs
in
section
VI.
E
of
today's
CAIR
FIP
preamble.

Fourth,
while
the
commenter
asserts
that
EPA's
use
of
title
IV
allowances
in
the
CAIR
SO2
trading
program
will
result
in
significant
wealth
transfers
from
low­
emitting
to
high­
emitting
States,
EPA's
analysis
of
SO2
coverage
ratios
(
the
ratio
of
allowances
to
projected
emissions,
discussed
to
some
degree
in
this
section
and
presented
in
the
"
CAIR
SO2
Allocation
Approach
Analysis"
Technical
Support
Document,
available
in
the
docket),
is
not
suggestive
of
this
trend.
In
fact,
looking
at
the
differences
in
States'
projected
emissions
and
coverage
ratios
between
the
base
case
and
CAIR,
it
becomes
evident
that
both
lower­
and
higher­
emitting
States
are
projected
to
make
investments
in
emissions
reductions
under
CAIR,
reducing
their
demand
for
allowances,
or
freeing
up
allowances
for
sale,
in
the
process.
States
that
might
be
categorized
as
highemitting
are
not
always
projected
to
be
net
sellers
of
allowances,
and
States
that
might
be
categorized
as
low­
emitting
are
not
always
projected
to
be
net
purchasers
of
allowances.

Another
commenter
argues
that
smaller
units
would
be
forced
to
purchase
SO2
allowances
from
the
market
in
order
to
comply
with
CAIR.
This
commenter
argues
that
the
SO2
allowance
market
is
not
efficient
and
subjects
forced
participants
to
bear
an
undue
amount
of
financial
burden
and/
or
risk.
EPA
believes
that
the
commenter's
claims
about
the
state
of
the
SO2
allowance
market
are
unfounded.
As
is
discussed
in
the
Acid
Rain
Program
Report
(
EPA
43­
R­
05­
012,
October
2005),
about
20,000
allowance
transactions,
affecting
about
15.3
million
allowances,
were
recorded
in
the
EPA
Allowance
Tracking
System
in
2004.
This
large
volume
of
transactions
is
evidence
of
a
viable
and
well­
functioning
market.
In
addition,
title
IV
compliance
costs
have
been
much
lower
than
projected
and
allowance
prices
in
the
SO2
allowance
market
have
generally
reflected
this.
Finally,
as
discussed
earlier
in
this
section,
sources
have
the
option
of
purchasing
allowances
directly
from
the
annual
auction.

Further,
in
raising
equity
concerns,
a
couple
of
commenters
argue
for
conflicting
measures
of
equity
within
their
own
comments.
These
commenters
argue
that
an
equitable
emissions
allocation
approach
will
result
in
an
equivalent
effective
emissions
rate
across
States.
These
commenters
then
point
to
EPA's
chosen
CAIR
NOx
emissions
allocation
approach
as
an
exemplary
allocation
approach
because
it
limits
the
disparity
between
individual
State
budgets
and
projected
emissions.
However,
the
commenters
fail
to
realize
that,
that
approach
does
not
8
actually
result
in
an
equivalent
emissions
rate
across
States.
Such
a
result
underscores
the
notion
that
improving
equity
along
one
metric
can
actually
reduce
it
along
another.

Finally,
some
commenters
argued
that
the
use
of
title
IV
allowance
allocations
penalizes
sources
who
have
already
installed
scrubbers
prior
to
the
start
of
the
Acid
Rain
Program.
This
is
because,
in
general,
allowances
under
title
IV
were
allocated
to
units
that
had
not
installed
controls
at
a
higher
rate
relative
to
units
that
had
installed
controls.
The
title
IV
approach,
in
that
sense,
is
somewhat
similar
to
the
approach
taken
for
NOx
under
CAIR,
in
that
it
provides
additional
allowances
for
units
expected
to
install
controls
under
the
rule.

EPA
believes
that
the
commenters'
arguments
that
the
continued
use
of
title
IV
allowances
penalizes
sources
that
installed
controls
prior
to
the
Acid
Rain
Program
are
unfounded.
First,
these
controls
were
installed
over
20
years
ago
and
are,
at
this
point,
a
sunk
cost.
Second,
these
control
installations
were
completed
within
a
regulated
electricity
sector,
such
that
in
most
cases
the
cost
of
installing
these
controls
should
have
been
recovered
through
an
electricity
price
rate
increase.
Third,
these
controls
were
installed
in
response
to
requirements
separate
from
both
CAIR
and
the
Acid
Rain
Program.
Fourth,
Congress
was
clearly
aware
of
the
issues
raised
by
commenters
when
designing
the
SO2
trading
program
in
1990,
and
consciously
used
a
formula
for
future
allocations
for
the
length
of
time
it
believed
was
reasonable.
In
general,
the
Acid
Rain
Program
has
enjoyed
10
years
of
operation
without
substantial
concern
over
this
issue
and
with
industry
at­
large
appreciating
the
program's
merits
in
providing
a
cost­
effective,
flexible,
and
fair
way
to
provide
environmental
protection.
Finally,
analysis
by
one
of
these
two
commenters,
which
estimates
the
windfall
of
allowances
that
a
hypothetical
unscrubbed
coal­
fired
unit
would
attain
by
installing
a
scrubber
and
reducing
emissions,
neglects
the
fact
that
this
unit
would
have
to
endure
the
costs
of
installing
controls.
Thus,
the
ostensible
windfall
would
be
significantly
smaller
than
was
suggested
by
the
commenter.

Analysis
of
SO2
Allocation
Options
Presented
in
the
Notice
of
Reconsideration
In
the
Notice
of
Reconsideration,
EPA
compared
three
alternative
SO2
allowance
allocation
methodologies
to
the
approach
in
the
final
CAIR.
In
these
analyses,
EPA
examined
how
allowances
would
be
distributed
to
individual
companies
instead
of
examining
how
they
would
be
distributed
to
States.
According
to
the
petitioner,
the
allowance
distribution
will
result
in
the
petitioner's
relatively
low­
emitting
units
being
forced
to
buy
allowances
from
other
companies'
relatively
high­
emitting
units.
They
thus
argue
the
allocation
approach
used
in
CAIR
is
per
se
inequitable
and
unreasonable.
To
evaluate
this
concern,
EPA
compared
projected
allocations
not
just
to
individual
units,
but
to
individual
companies
who
own
these
units
under
various
methodologies
relative
to
projected
SO2
emissions
of
all
the
units
owned
by
those
companies.
The
logic
behind
this
is
described
in
detail
in
the
Notice
of
Reconsideration
and
associated
TSD
(
docket,
EPA­
HQ­
OAR­
2003­
0053­
2229).

The
three
alternative
allowance
allocation
methodologies
EPA
analyzed
were
suggested
by
various
commenters
during
the
rulemaking
process
and
this
reconsideration
process.
These
methodologies
are:
9
1.
Allocating
allowances
based
on
more
recent
heat
input
data;
2.
Allocating
allowances
based
on
more
recent
heat
input
data
adjusted
for
fuel
type
(
e.
g.,
coal,
oil
and
gas);
and
3.
Allocating
allowances
based
on
more
recent
heat
input
data
adjusted
both
for
fuel
type
and
for
coal
type
(
e.
g.,
bituminous,
sub­
bituminous
and
lignite).

In
comparing
the
CAIR
SO2
allocation
approach
and
the
three
alternative
methodologies,
EPA
took
into
account
certain
factors
that
are
applicable
to
the
CAIR
final
allocation
approach
but
not
to
the
three
alternative
methodologies.
For
all
four
methodologies,
EPA
analyzed
the
resulting
total
allowance
allocations,
and
the
total
projected
emissions,
for
companies'
sources
located
in
the
States
subject
to
CAIR.
In
addition,
for
all
the
methodologies,
EPA
analyzed
the
relationship
between
allowances
and
emissions
in
two
ways.
First,
EPA
calculated
the
ratio
of
allowances
to
total
projected
emissions
before
CAIR
controls
(
base
case
emissions).
This
provides
a
reasonable
estimate
of
the
extent
to
which
each
company's
future
emissions
could
have
exceeded
its
allowances
and,
thus,
indicates
how
much
effort
a
company
must
expend
for
compliance
either
by
purchasing
allowances
or
installing
controls.
Second,
EPA
calculated
the
ratio
of
allowances
to
total
projected
emissions
after
the
installation
of
CAIR
controls
(
control
case
emissions).
This
provides
a
reasonable
estimate
of
the
number
of
allowances
a
company
would
need
to
purchase
or
would
be
able
to
sell
after
any
controls
are
installed.
Some
companies
with
existing
low­
emitting
units
may
have
excess
allowances
to
sell
even
if
no
controls
are
installed.

In
its
analysis
of
the
CAIR
approach,
EPA
also
considered
both
the
allowance
allocations
and
the
emissions
for
companies'
units
both
within
the
CAIR
region
and
outside
the
CAIR
region.
EPA
believes
that
this
is
appropriate
because,
under
the
CAIR
approach,
if
a
company's
units
outside
the
CAIR
region
have
more
title
IV
allowances
than
needed
to
cover
their
emissions
under
the
Acid
Rain
Program,
the
company
might
be
able
to
transfer,
at
little
or
no
net
cost,
excess
allowances
to
the
company's
units
in
the
CAIR
region
for
use
to
cover
emissions
under
the
CAIR
trading
program.
Under
the
three
alternative
methodologies,
all
of
which
would
require
creating
new
CAIR
SO2
allowances
independent
of
the
existing
title
IV
allocations,
CAIR
sources
could
not
use
title
IV
allowances
held
for
sources
outside
(
or
inside)
the
CAIR
region
for
compliance
with
the
CAIR
SO2
allowance
holding
requirement.

Further,
in
the
analysis
of
the
CAIR
approach,
EPA
considered
the
allocation
of
title
IV
allowances
to
CAIR
units
that
are
not
currently
in
the
Acid
Rain
Program
but
that
could
opt
into
the
Acid
Rain
Program
and
receive
title
IV
allowances
(
see
42
U.
S.
C.
7651i
and
18
CFR
part
74;
and
the
discussion
below
concerning
the
ability
of
units
to
opt
in).
This
analysis
assumed
that
companies
owning
non­
Acid
Rain
units
subject
to
CAIR
would
elect
to
opt
into
the
Acid
Rain
Program
because
they
would
receive
title
IV
allowances
to
cover
a
portion
of
the
units'
emissions
under
CAIR.
EPA
believes
this
assumption
is
reasonable
because
any
of
these
units
has
the
option
of
becoming
an
Acid
Rain
Program
opt­
in
unit
and
thereby
providing
the
company
additional
allowances,
at
little
or
no
additional
cost,
and
the
value
of
title
IV
allowances
could
be
substantial.
In
contrast,
the
analysis
of
the
three
alternative
methodologies
did
not
consider
the
impact
of
Acid
Rain
Program
opt­
ins
because
these
approaches
do
not
use
title
IV
allowances
for
CAIR
compliance.
10
EPA's
analysis
indicated
that
while
allocations
vary
from
company
to
company
under
the
four
methodologies,
overall
the
distributions
of
allowances
that
companies
received
relative
to
their
projected
emissions
for
the
CAIR
control
case
are
very
similar.
EPA
came
to
similar
conclusions
when
looking
at
the
base
case.
2
See
Appendix
B
for
the
results.

Changes
in
Data
Representation
In
the
Notice
of
Reconsideration,
we
displayed
data
in
figures
as
the
cumulative
number
of
companies
obtaining
a
specific
ratio
(
or
a
lower
ratio).
The
ratios
were
calculated
as
the
projected
base
case
SO2
allowance
allocations
divided
by
emissions.
By
displaying
data
in
this
manner
we
found
that
the
distributions
of
allowances
relative
to
emissions
are
similar
across
the
four
approaches.

Another
way
to
display
such
data
is
by
showing
the
percentage
of
companies
or
States
that
have
a
specific
ratio
(
or
a
lower
ratio).
This
method
of
graphing
places
the
primary
variable
of
interest,
such
as
coverage
ratio,
on
the
x­
axis,
and
shows
the
cumulative
percentage
of
companies
on
the
y­
axis.
Because
of
the
ease
of
interpreting
this
format,
we
have
chosen
to
display
all
relevant
charts,
thus.
For
example,
see
Appendix
B,
Figure
1.
In
addition,
the
statistical
analysis
discussed
in
the
Appendix
B,
provides
another
way
to
assess
system­
wide
trends
in
the
data,
which
indicate
whether
an
allocation
approach
is
biased
or
inconsistent
in
its
distribution
of
allowances
across
all
States,
as
compared
to
other
alternatives.
The
conclusion
of
that
statistical
analysis
is
that
EPA's
method
is
not
biased
or
inconsistent
compared
to
other
methods.

There
are
two
sets
of
analyses
files
associated
with
the
Reconsideration
process
in
the
CAIR
docket
(
EPA­
HQ­
OAR­
2003­
0053),
"
SO2
Allocations
Analysis
Data,"
from
this
Notice
of
Final
Action
on
Reconsideration,
March
15,
2006,
and
another
set
from
the
December
2005
Notice
of
Reconsideration
(
OAR­
2003­
0053­
2261).
EPA
used
the
following
labels
in
its
data
files
in
the
docket
for
the
corresponding
allocation
approaches
analyzed:

2b
=
EPA's
CAIR
method
3b
=
Pure
heat
input
4b
=
Heat
input
with
fuel
factors
5b
=
Heat
input
with
fuel
factors
and
coal
type
Slight
changes
in
calculations
for
the
method
5b
were
made
to
reflect
another
interpretation
of
how
such
a
heat
input
allocation
approach
could
be
handled.
In
addition,
a
few
duplicative
entries
were
found
and
removed
in
this
set
of
data
files.
Detailed
explanation
of
the
methodology
for
the
revised
data
analysis
can
be
found
in
(
Source:
Memos
from
David
Sellers,
Perrin
Quarles
Associates,
March
2006,
"
CAIR
SO2
Allocation
Analysis
Data,"
and
"
SO2
2
Note:
For
NOx,
EPA
calculated
a
separate
region­
wide
budget
for
New
Jersey
and
Delaware
using
the
same
approach
that
was
used
to
calculate
the
larger
CAIR
region­
wide
budget.
This
region­
wide
budget
was
then
apportioned
to
individual
State
budgets
using
the
same
approach
used
in
CAIR.
Because
New
Jersey
and
Delaware
were
treated
separately
in
the
context
of
NOx
allocations,
EPA
has
not
included
them
in
this
SO2
analysis.
EPA
believes
their
inclusion
would
have
made
little
difference
in
the
overall
results
given
the
relative
smallness
of
the
States'
fossil
generation
capacity
and
coal­
fired
capacity
in
particular.
11
Allocation
Data
Spreadsheets"
(
Docket:
EPA­
HQ­
OAR­
2003­
0053).
Previous
calculation
methods
can
be
found
in
Appendix
A
of
Notice
of
Reconsideration
TSD,
"
Sulfur
Dioxide
Allowance
Allocation
Methodology
Comparative
Analysis"
(
Docket:
EPA­
HQ­
OAR­
2003­
0053­
2229).
3
Company­
by­
Company
Analyses
EPA
analyzed
company­
by­
company
data
for
owner/
operating
companies,
as
well
as
parent/
holding
companies.
EPA
analyses
at
the
operating
company
level
take
into
account
that
companies
may
incur
some
cost
to
shift
allowances
across
State
lines,
e.
g.
if
the
States
involved
regulate
retail
electricity
sales.
Believing
that
taking
this
into
account
would
not
have
a
major
effect
on
the
outcome
of
these
analyses,
EPA
performed
this
portion
of
the
analyses
to
test
this
assumption.

One
commenter
criticized
EPA's
company­
by­
company
analysis
on
the
grounds
that
EPA
determined
allowance
allocations
under
the
various
allocation
alternatives
using
title
IV­
based
CAIR
State
budgets
rather
than
using
State
budgets
that
were
calculated
using
corresponding
heat
input
allocation
approach.
EPA
agrees
with
the
commenter
that
determination
of
company
allocations
under
a
given
alternative
allocation
approach
should
be
based
on
State
budgets
calculated
using
the
same
approach.
EPA
has
reanalyzed
company
level
allocations
using
this
methodology,
and
the
revised
analyses
are
included
in
this
document
(
also
see
"
SO2
State
Budget
Analysis
Data"
spreadsheet
in
the
CAIR
docket,
and
March
2006
memos
from
David
Sellers
for
underlying
data).

EPA's
revised
analyses
for
both
base
and
CAIR
control
cases
in
2010
and
2015
for
owner/
operating
companies
and
parent/
holding
companies
all
show
mostly
similar
results
to
those
described
in
the
Notice
of
Reconsideration
SO2
Analysis
TSD
with
one
exception.
As
in
the
prior
analyses,
EPA's
SO2
allowance
allocation
approach
is
shown
to
be
reasonable
compared
to
the
alternatives.
This
is
true
for
2010
and
2015
and
when
using
emissions
from
both
the
base
and
CAIR
control
cases.
However,
because
of
the
recalculation
of
the
heat
input
with
fuel
factors
approach
for
this
final
action
analysis,
the
pure
heat
input
approach
is
less
far
off
from
the
heat
input
with
fuel
and
coal
factors
approach
under
all
cases
and
years.
(
See
Appendix
B
for
more
details
related
to
company­
level
analyses.)

This
is
further
seen
in
the
results
for
the
owner/
operating
company
analyses,
which
were
slightly
different
than
the
parent/
holding
company
analyses
and
what
was
described
in
the
Notice
of
Reconsideration.
EPA's
method
provides
a
distribution
of
ratios
(
allocations
to
emissions)
similar
to
the
heat
input
with
fuel
factors
alternative,
but
not
as
close
to
the
other
two
alternatives
(
see
Appendix
B,
Figures
1,
2,
7
and
8).
One
reason
for
this
difference
is
the
owner/
operator
analyses
indicate
that
the
distributions
of
ratios
are
sensitive
to
the
number
or
sources
with
zero
allocations
(
and
therefore
a
ratio
of
zero
allowances
to
emissions).
Companies
may
have
zero
allocations
because
the
units
they
operate
commenced
operations
after
1990.
This
is
true
for
both
2010
and
2015
and
with
base
case
and
control
case
emissions
(
see
docket:
EPA­
HQ­
OAR­

3
The
District
of
Columbia
is
excluded
from
analyses
that
require
emissions
data
because
DC
is
projected
to
have
no
emissions
in
2010
or
2015.
12
2003­
0053,
"
SO2
State
Budget
Analysis").
The
vast
majority
of
these
companies
have
primarily
gas
generation,
which
has
little
or
no
emissions.
For
example
about
94%
of
the
64
companies
with
a
ratio
of
zero
allowances
to
emissions
were
gas­
fired
for
2010
CAIR
control
case.
This
is
true
for
at
least
90%
of
companies
for
other
years
and
cases,
as
well.
Since
these
units
have
negligible
SO2
emissions,
receiving
no
allowances
will
not
significantly
impact
the
operating
companies
(
see
docket,
OAR­
2003­
0053,
"
SO2
Allocations
Analysis
Data,"
for
related
data).
When
the
figures
are
redrawn
with
those
zero
values
removed
for
all
methods,
EPA's
approach,
again,
appears
to
be
very
similar
to
the
others
analyzed
(
Appendix
B,
Figures
5,
6,
11
and
12).

Among
the
three
remaining
methods
that
incorporate
a
fuel­
adjustment
factor,
neither
heat
input
methodology
stands
out
as
providing
a
more
reasonable
method
of
allocation
across
all
companies
when
examining
allowance
needs
under
either
the
base
case
or
CAIR
control
case.
In
addition,
the
CAIR
method
for
allocating
SO2
allowances
is
supported
by
EPA's
over­
riding
policy
decision
to
preserve
operation
of
the
title
IV
SO2
cap
and
trade
program
as
the
CAIR
method.

State­
by­
State
Budget
Analysis
As
described
in
the
CAIR
Notice
of
Final
Action
on
Reconsideration,
in
response
to
comment
on
the
Notice
of
Reconsideration,
EPA
performed
a
set
of
State­
level
SO2
budget
analyses.
This
section
includes
additional
tables
with
data
that
support
EPA's
conclusions
given
in
the
Notice
of
Final
Action
on
Reconsideration.

EPA
received
several
comments
on
various
aspects
of
the
SO2
allocation
analyses
presented
in
the
Notice
of
Reconsideration.
A
few
commenters
claimed
that
EPA
should
have
focused
its
analyses
on
State
budgets
rather
than
on
projected
allocations
to
companies
because,
with
an
alternative
allocation
approach,
States
would
have
the
responsibility
for
allocating
allowances
to
their
respective
affected
sources
and
could
meet
control
requirements
differently
than
assumed
in
EPA's
analyses.
Further,
these
commenters
claimed
a
State­
by­
State
analysis
is
more
consistent
with
the
analysis
of
NOx
allocation
methodologies
in
the
Notice
of
Reconsideration
and
the
final
CAIR
itself.
Finally,
one
commenter
noted
that
company­
specific
analysis
can
obscure
state­
bystate
variation
and
may
not
be
reliable
given
continual
shifts
in
ownership
structure.

EPA
agrees
with
the
commenters
that
one
method
of
evaluating
the
reasonableness
of
SO2
allocation
approaches
is
(
in
addition
to
company­
by­
company
analyses)
to
compare
State
budgets
calculated
according
to
various
methodologies.
EPA
performed
the
company­
bycompany
analyses
described
above
in
response
to
a
specific
petitioner's
claims
that
the
SO2
allowance
allocation
approach
created
inequities
at
the
company­
level.
Despite
one
commenter's
assertion
that
such
an
analysis
is
made
unreliable
by
constantly
changing
corporate
structures,
EPA
believes
that
such
an
analysis
remains
instructive.
A
State­
level
analysis
provides
additional
perspective
on
the
impact
of
various
allocation
approaches,
though
it
will,
of
course,
obscure
some
of
the
potential
company­
level
variability
among
allowance
approaches.
For
this
reason,
EPA
does
not
repeat
the
"
Select
High­
emitting
Companies"
analysis
in
this
document.
13
EPA
presented
such
a
State­
by­
State
analysis
in
the
final
CAIR
RTC
(
final
CAIR
"
Corrected
Response
to
Significant
Public
Comments
on
the
Proposed
Clean
Air
Interstate
Rule,"
Corrected
April
2005
(
Docket
Number
OAR­
2003­
0053)).
EPA
recognizes
that
the
analysis
prepared
for
the
CAIR
RTC
did
not
consider
two
of
the
alternative
allocation
approaches
discussed
above.
For
today's
notice,
EPA
has
analyzed
State
budgets
calculated
under
eight
different
approaches
(
title
IV
and
seven
alternatives).
These
eight
approaches
are
described
in
Table
1,
below.

Table
1.
Description
of
Allocation
Approaches
Included
in
EPA
Analysis
Approach
Name
Description
of
Approach
EPA
Title
IV
Title
IV
allocations
adjusted
for
the
2
to
1
allowance
retirement
ratio
in
2010­
2014
and
the
2.86
to
1
allowance
retirement
ratio
in
2015
and
thereafter.
EPA's
chosen
approach.
Average
1999
­
2002
(
Pure)
Heat
Input
For
each
State,
calculates
the
average
heat
input
over
the
years
1999­
2002.
Apportions
the
region­
wide
SO2
cap
to
individual
States
based
on
each
State's
share
of
the
total
region­
wide
average
for
those
years.
1999
­
2002
Heat
Input
w/
Fuel
Factors
For
each
State,
calculates
the
average
adjusted
heat
input
over
the
years
1999­
2002.
Adjusts
heat
input
using
factors
of
1.0
for
coal,
0.009
for
natural
gas,
and
0.3
for
oil.
Apportions
the
region­
wide
SO2
cap
to
individual
States
based
on
each
State's
share
of
the
total
region­
wide
average
adjusted
heat
input
for
those
years.
1999
­
2002
Heat
Input
w/
Fuel
Factors
&
Coal
Type
For
each
State,
calculates
the
average
adjusted
heat
input
over
the
years
1999­
2002.
Adjusts
heat
input
using
factors
of
2.6
for
bituminous
coal,
1.0
for
subbituminous
and
lignite
coals,
0.2
for
natural
gas,
and
0.7
for
oil.
Apportions
the
region­
wide
SO2
cap
to
individual
States
based
on
each
State's
share
of
the
total
region­
wide
average
adjusted
heat
input
for
those
years.
Average
1999
­
2002
Heat
Input
Coal
+
Oil
For
each
State,
calculates
the
average
heat
input
from
coal­
and
oil­
fired
units
over
the
years
1999­
2002.
Apportions
the
region­
wide
SO2
cap
to
individual
States
based
on
each
State's
share
of
the
total
regionwide
average
heat
input
from
these
units
for
those
years.
Average
1999
­
2002
SO2
Emissions
For
each
State,
calculates
the
average
emissions
over
the
years
1999­
2002.
Apportions
the
region­
wide
SO2
cap
to
individual
States
based
on
each
State's
share
of
the
total
region­
wide
average
emissions
for
those
years.
Average
1999
­
2002
Generation
Output
(
all
sources
fossil
and
non­
fossil)
For
each
State,
calculates
the
average
output
over
the
years
1999­
2002.
Apportions
the
region­
wide
SO2
cap
to
individual
States
based
on
each
State's
share
of
the
total
region­
wide
average
output
for
those
years.
1999
­
2002
Generation
Output
(
Fossil­
fuel­
fired
units
only)
For
each
State,
calculates
the
average
output
from
fossil
fuel­
fired
units
over
the
years
1999­
2002.
Apportions
the
region­
wide
SO2
cap
to
individual
States
based
on
each
State's
share
of
the
total
regionwide
average
output
from
these
units
for
those
years.
14
As
is
shown
in
Table
2,
the
first
component
of
EPA's
State­
level
analysis
compared
the
individual
State
shares
of
total
region­
wide
SO2
allocations
under
the
various
approaches.
The
revised
analysis
reaffirms
EPA's
original
conclusion,
which
was
that
calculating
State
budgets
using
the
title
IV
allowances
results
in
about
80
percent
of
the
States
receiving
a
percentage
of
total
SO2
allocations
that
is
within
the
range
of
the
percentages
that
resulted
for
these
States
under
other
suggested
SO2
allocation
approaches
("
Sulfur
Dioxide
Allowance
Allocation
Methodology
Comparative
Analysis"
Technical
Support
Document
(
Docket
ID:
EPA­
HQ­
OAR­
2003­
0053)).
In
other
words,
80
percent
of
States
get
neither
the
most
nor
the
least
allowances
relative
to
what
they
receive
under
the
other
allocation
approaches,
under
the
title
IV
approach.
Furthermore,
when
compared
specifically
to
the
methods
supported
by
commenters
(
pure
heat
input,
heat
input
with
fuel
factors,
heat
input
with
fuel
factors
and
coal
type,
coal
and
oil
heat
input
and
average
output
all),
distribution
of
State
budgets
using
title
IV
allocations
results
in
an
individual
State
receiving
its
smallest
or
greatest
share
of
total
SO2
allocations
relative
to
what
the
individual
State
receives
under
the
alternative
approaches
the
same
number
of
times
as
the
pure
heat
input
methodology
and
fewer
times
than
the
other
methodologies
supported
by
commenters
(
see
the
last
three
rows
of
Table
2).
Such
results
suggest
that
this
approach
performs
as
well
as
three
of
the
other
allocation
approaches
suggested
by
commenters,
indicating
that
EPA's
argument
that
its
chosen
allocation
approach
is
reasonable.
While
the
coal
and
oil
heat
input
approach
appears
to
perform
best
in
this
analysis,
this
approach
received
more
limited
commenter
support.

In
examining
the
results
of
this
analysis
for
the
States
where
commenters
that
submitted
adverse
comments
on
the
use
of
title
IV
own
generating
units
(
FL,
IN,
MD
MN,
NY
NC,
PA,
SC,
TX),
it
becomes
apparent
that
each
allocation
approach
makes
some
States
better
off
and
others
worse
off.
For
example,
North
Carolina
receives
3.8
percent
of
the
total
region­
wide
SO2
budget
under
the
title
IV
approach,
and
Florida
receives
7.0
percent.
Under
a
heat
input
with
fuel
factors
approach,
North
Carolina
receives
4.5
percent
of
the
total
budget,
while
Florida
receives
its
lowest
share
of
the
total
budget
(
5.6
percent)
of
all
eight
allocation
approaches.
Similarly,
while
Florida
and
Texas
receive
their
largest
share
of
allowances
under
a
fossil
output­
based
approach
or
pure
heat
input
approach,
Maryland
actually
receives
its
lowest
share
of
allowances
under
that
approach.
Florida,
Maryland,
Pennsylvania,
and
New
York
all
receive
more
allowances
under
the
title
IV
approach
than
they
would
under
the
heat
input
with
fuel
factors
approach.
4
Further,
while
using
a
heat
input
with
fuel
factors
approach
would
provide
an
advantage
to
many
of
the
States
that
provided
adverse
comments
on
title
IV,
shifting
to
this
approach
would
disadvantage
10
of
the
23
States
(
DC
is
not
counted)
relative
to
the
title
IV
approach.

4
Also,
it
is
worth
noting
that
the
five
most
significant
commenters
from
FL,
IN,
MN,
NC,
and
SC
are
all
in
cost­
ofservice
States,
where
they
should
be
able
to
pass
through
costs.
In
other
words,
sources
in
these
States
are
likely
to
recover
their
cost
of
compliance,
and
the
rate
impact
in
these
States,
spread
over
all
generation,
transmission,
and
distribution
is
likely
to
be
minimal.
EPA's
Regulatory
Impact
Analysis
for
CAIR
forecasts
an
increase
of
only
about
2.0
percent
and
2.7
percent
in
average
electricity
prices
in
the
CAIR
region
in
2010
and
2015,
respectively.
Florida
is
projected
to
experience
an
increase
in
retail
electricity
prices
of
0.8
percent
in
2010
and
1.4
percent
in
2015.
Also,
the
region
containing
North
Carolina
and
South
Carolina
is
forecast
to
have
retail
electricity
price
increases
lower
than
the
regional
average
increases
under
CAIR
in
2010
and
2015.

Notably,
EPA
found
that
commenters
that
did
not
like
EPA's
approach
to
SO2
allocations
owned
less
than
10
percent
of
the
coal­
fire
capacity
in
the
CAIR
region
(
see
Appendix
C).
15
Table
2.
State
Percentage
of
Regionwide
Budget
State
EPA
Title
IV
Average
1999
­
2002
(
Pure)
Heat
Input
1999
­
2002
Heat
Input
w/
Fuel
Factors
1999
­
2002
Heat
Input
w/
Fuel
Factors
&
Coal
Type
Average
1999
­
2002
Heat
Input
Coal
+
Oil
Average
1999
­
2002
Emissions
Average1
999
­
2002
Output
All
Average
1999
­
2002
Output
Fossil
AL
4.4%
4.3%
4.9%
5.2%
4.7%
5.0%
4.7%
4.2%
DC
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
FL
7.0%
7.7%
5.6%
6.7%
7.3%
6.0%
7.2%
7.7%
GA
5.9%
4.1%
4.7%
5.3%
4.5%
5.2%
4.5%
4.2%
IA
1.8%
1.9%
2.4%
1.2%
2.3%
1.4%
1.5%
1.8%
IL
5.3%
4.7%
5.4%
4.4%
5.2%
4.7%
6.6%
4.4%
IN
7.0%
6.5%
7.9%
7.9%
7.5%
8.6%
4.6%
6.2%
KY
5.2%
4.9%
6.0%
7.3%
5.8%
5.8%
3.5%
4.5%
LA
1.7%
3.3%
1.6%
1.0%
1.5%
1.1%
3.4%
3.6%
MD
2.0%
1.8%
1.9%
2.3%
2.0%
2.7%
1.9%
1.7%
MI
4.9%
4.2%
4.4%
3.7%
4.3%
3.7%
4.1%
4.2%
MN
1.4%
1.9%
2.3%
1.1%
2.2%
1.0%
1.9%
1.7%
MO
3.8%
3.6%
4.3%
2.3%
4.1%
2.4%
2.9%
3.4%
MS
0.9%
1.4%
1.0%
1.0%
1.1%
1.2%
1.6%
1.6%
NC
3.8%
3.7%
4.5%
5.5%
4.3%
4.7%
4.5%
3.8%
NY
3.7%
4.0%
2.2%
2.7%
3.4%
2.7%
5.3%
3.9%
OH
9.2%
6.4%
7.9%
9.6%
7.5%
12.2%
5.4%
6.5%
PA
7.6%
6.0%
7.1%
8.4%
6.9%
9.5%
7.4%
6.1%
SC
1.6%
2.0%
2.3%
2.9%
2.2%
2.1%
3.4%
2.0%
TN
3.8%
3.0%
3.7%
4.4%
3.5%
4.0%
3.5%
3.0%
TX
8.9%
15.3%
9.4%
5.5%
9.0%
6.0%
13.9%
16.6%
VA
1.8%
2.3%
2.5%
3.1%
2.5%
2.3%
2.8%
2.3%
WI
2.4%
2.5%
2.9%
1.8%
2.8%
2.0%
2.2%
2.2%
WV
6.0%
4.4%
5.4%
6.7%
5.2%
5.8%
3.4%
4.5%
100%
100%
100%
100%
100%
100%
100%
100%
#
of
times
method
provides
least
allowances
3
4
2
7
0
2
4
4
#
of
times
method
provides
most
allowances
2
1
4
6
0
4
4
4
Total
(
most
+
least)
5
5
6
13
0
6
8
8
Two
commenters
performed
alternative
analyses
of
State
budgets,
modeled
after
the
calculations
done
for
the
CAIR
Reconsideration
related
to
NOx
budgets
(
CAIR
Statewide
NOx
Budget
Calculations,
EPA
Docket
Number
OAR­
2003­
0053,
December
2005).
The
commenters
claim
that
their
analysis
proves
that
EPA's
SO2
allowance
allocation
approach
is
inferior
to
a
fueladjusted
heat
input
method,
such
as
the
allocation
approach
used
in
the
CAIR
NOx
model
16
trading
rule.
They
assert
that
EPA's
analysis
of
NOx
allocation
methodologies
is
also
the
appropriate
way
to
compare
the
reasonableness
of
the
SO2
allocation
alternatives.

As
EPA
explained
in
the
NOx
TSD,
to
quantitatively
evaluate
whether
the
fuel
factor
approach
is
providing
States
with
annual
NOx
budgets
that
more
closely
reflected
their
projected
emissions,
EPA
calculated
the
arithmetic
mean
of
the
(
absolute)
difference
between
the
ratio
of
each
State's
allowance
allocation
under
each
approach
to
its
projected
emissions
under
CAIR
(
coverage
ratio),
and
1.0
(
i.
e.,
the
value
representing
a
State's
projected
emissions
matching
the
State's
CAIR
NOx
budget).
In
other
words,
EPA
calculated
how
far
off
the
State's
coverage
ratio
was
from
1.0,
and
then
determined
the
average
value
of
this
difference
for
each
approach.

One
commenter
performed
a
similar
analysis
of
State
budgets,
comparing
each
State's
projected
emissions
to
its
projected
allowances
under
each
allocation
approach.
The
commenter
analyzed
the
results
in
relation
to
a
coverage
ratio
of
1.0
(
as
EPA
did
in
its
NOx
analysis)
and
averaged
the
values
for
each
approach.
Another
commenter
performed
a
similar
analysis
but
presented
the
results
as
the
cumulative
value
(
sum)
of
absolute
differences
between
the
coverage
ratios
and
1.0.

EPA
disagrees
with
the
commenter's
assertion
that
the
methodology
that
the
Agency
used
to
evaluate
State
NOx
allocations
should
be
the
primary
means
by
which
to
evaluate
the
reasonableness
of
the
SO2
allocation
methodology.
As
explained
in
the
CAIR
preamble,
in
the
case
of
SO2,
EPA
needs
to
balance
various
considerations,
including
the
need
to
allocate
SO2
allowances
in
a
way
that
is
less
disruptive
to
the
title
IV
program.
In
light
of
these
considerations,
minimizing
the
disparity
between
a
State's
allocation
and
projected
emissions
cannot
be
the
primary
objective.
For
SO2,
there
is
a
pre­
existing
national
trading
program
(
the
Acid
Rain
SO2
trading
program)
that
Congress
intended
to
continue
as
a
viable
program
into
the
future
and
under
which
allowances
have
been
allocated
in
perpetuity.
For
NOx,
there
is
no
preexisting
national
trading
program
where
efficiency
and
effectiveness
would
be
jeopardized
by
creating
new
CAIR
NOx
allowances.
There
is,
of
course,
a
pre­
existing
regional
NOx
ozoneseason
program
covering
a
portion
of
the
CAIR
region
(
the
NOx
Budget
Trading
Program,
established
by
regulation,
rather
than
directly
by
Congress).
Under
the
existing
NOx
ozoneseason
program,
no
State
has
allocated
allowances
past
2009
(
and
only
a
handful
of
States
have
allocated
allowances
past
2008).
Therefore,
in
contrast
with
EPA's
determination
concerning
SO2
allocations,
evaluation
of
potential
approaches
to
NOx
allocations
did
not
involve
concerns
about
Congressional
intent
to
preserve
an
existing
trading
program
and
about
preserving
the
value
of
allowances
already
allocated
in
perpetuity.
For
NOx,
EPA
does
not
need
to
consider
other
important
policy
concerns
that
are
important
for
SO2
(
as
explained
above
and
in
the
CAIR
final
rule).

While
the
methodology
used
by
EPA
to
evaluate
NOx
allocation
methodologies
for
CAIR
can
be
applied
to
analysis
of
SO2
allocations,
EPA
believes
that
the
commenters
performed
their
Stateby
State
analyses
incorrectly,
overlooking
a
fundamental
difference
between
the
CAIR
NOx
and
SO2
trading
programs,
which
is
the
existence
of
a
significant
bank
of
pre­
2010
allowances
that
will
be
eligible
for
use
for
compliance
with
CAIR.
Because
of
the
existence
of
a
SO2
allowance
bank,
EPA
believes
that
the
commenter's
comparison
of
allocation
approaches
using
a
coverage
ratio
of
1.0,
which
would
assume
that
in
a
given
year
total
SO2
emissions
in
the
region
are
equal
17
to
the
total
region­
wide
SO2
budget,
is
not
appropriate
for
evaluating
the
SO2
State
budgets
resulting
from
the
various
SO2
allocation
methodologies.
A
State
that
had
a
coverage
ratio
of
1.0
would
have
enough
allowances
to
cover
its
emissions,
and,
while
this
ratio
would
be
a
meaningful
target
in
the
context
of
the
CAIR
NOx
trading
program,
it
is
not
for
SO2,
because
2010
and
2015
emissions
will
be
higher
than
the
region­
wide
cap
due
to
the
use
of
banked
allowances.
For
SO2,
the
region­
wide
ratios
of
allowances
to
projected
emissions
are
0.70
for
2010
and
0.60
for
2015.
On
average,
one
would
expect
States
to
have
coverage
ratios
similar
to
the
region­
wide
average.

While
in
both
the
NOx
annual
and
NOx
ozone
season
trading
programs
some
allowances
beyond
the
State
Budgets
(
i.
e.,
compliance
supplement
pool
allowances
in
the
annual
program
and
banked
allowances
from
the
NOx
Budget
Trading
Program
in
the
ozone­
season
program)
will
be
available
to
sources,
the
amount
of
these
extra
allowances
will
be
too
small
to
affect
the
Stateby
State
NOx
analysis.
Consequently,
EPA
believes
that
a
more
appropriate
way
to
evaluate
SO2
allocation
methods
is
to
use
the
0.70
(
for
2010)
and
0.60
(
for
2015)
coverage
ratios,
rather
than
a
ratio
of
1.0.
Further,
because
each
allocation
approach
results
in
allocation
that
are
advantageous
for
different
companies
and
States,
EPA
believes
that
the
reasonableness
of
a
given
allocation
approach
should
be
judged
by
its
overall
impact
on
companies
and
States,
not
its
specific
impact
on
any
single
company
or
State
or
on
a
few
companies
or
States.

EPA
has
redone
the
commenters'
analysis,
using
the
methodology
used
by
EPA
in
its
analysis
of
NOx
allocations
and
corrected
coverage
ratios
described
above.
This
analysis
is
presented
in
Appendix
A,
tables
A
to
D.
The
State
budget
and
emissions
data
behind
the
tables
in
Appendix
A
are
available
in
Tables
4­
5,
as
well
as
in
the
docket,
"
SO2
Allocations
Analysis
Data."

While
the
title
IV
SO2
allocation
approach
does
not
perform
the
best
of
the
allocation
approaches
considered
using
this
metric,
the
differences
observed
among
the
approaches
are
of
a
lower
magnitude
than
those
suggested
by
the
commenters.
The
commenters
did
not
provide
any
benchmark
in
their
analysis
for
assessing
whether
or
not
a
given
allocation
approach
was
reasonable.
Further,
although
the
commenters
discuss
some
of
the
implications
of
the
differences
observed
between
an
allocation
approach
based
on
fuel
factors
and
the
allocation
approach
based
on
title
IV,
they
do
not
conclude
their
analyses
with
any
meaningful
arguments
that
EPA's
approach
is
not
reasonable.

As
EPA
noted
earlier
in
this
section,
there
are
a
number
of
ways
by
which
to
assess
the
equitability
of
a
given
allowance
allocation
approach.
EPA
believes
that
a
further
understanding
of
the
overall
relative
impacts
of
the
various
allocation
approaches,
EPA
believes
that
it
is
useful
to
apply
the
statistical
concepts
of
(
1)
bias
and
(
2)
consistency.
EPA
determined
that
an
appropriate
statistic
for
examining
the
bias
of
a
given
allocation
approach
is
the
average
difference
between
a
State's
coverage
ratio
and
the
coverage
ratio
for
the
entire
region
(
e.
g.,
0.70
for
2010
or
0.60
for
2015).
The
degree
of
bias
inherent
in
a
given
allocation
approach
cannot
be
discerned
from
the
absolute
value
statistic,
because
it
ignores
the
degree
to
which
positive
and
negative
differences
cancel
each
other
out.
A
perfectly
unbiased
distribution
under
a
given
allocation
approach
would
be
one
that
resulted
in
an
average
difference
of
zero,
meaning
that
on
average
a
State­
by­
State
coverage
ratio
higher
than
the
regional
coverage
ratio
is
balanced
out
by
a
ratio
below.
Another
useful
statistic
is
the
percent
of
instances
in
which
the
allocation
18
approach
yields
a
State
coverage
ratio
that
is
high
(
or
low)
relative
to
the
regional
coverage
ratio.
Lack
of
bias
would
be
indicated
if
50
percent
of
the
State
coverage
ratios
are
higher
than
the
regional
coverage
ratio
and
50
percent
are
lower.

EPA
evaluated
the
four
allocation
approaches
considered
during
the
CAIR
rulemaking
(
title
IV,
pure
heat
input,
heat
input
with
fuel­
factors,
and
heat
input
with
fuel
factors
and
coal
type
factors)
along
these
metrics.
From
EPA's
calculations
(
Table
3),
all
the
approaches
are
biased
high
for
2010
and
all
but
one
is
biased
high
for
2015
(
with
CAIR
controls).
The
average
differences
for
EPA's
approach,
0.06
(
range
across
approaches:
0.05
to
0.11)
in
2010
and
0.17
(
range
across
approaches:
­
0.17
to
0.18)
in
2015,
are
among
the
closest
to
zero
compared
to
the
alternatives
examined.
The
one
approach
(
heat
input
with
fuel
and
coal
adjustment
factors)
that
exhibits
less
bias
than
the
title
IV
approach
in
2010
exhibits
bias
of
the
same
magnitude
(
but
opposite
direction)
as
the
title
IV
approach
in
2015.
In
addition,
the
percent
of
positive
differences
for
EPA's
approach
for
2010
and
2015
are
near
50
percent
and
do
not
greatly
vary
from
the
alternative
methods
analyzed.
This
demonstrates
that
EPA's
approach
provides
a
reasonable
result.
(
Summary
tables
of
all
metrics
analyzed,
including
bias
and
consistency,
are
available
in
Tables
6
and
7
below.

Table
3.
Evaluation
of
Bias
and
Consistency
of
Four
Different
SO2
Allocation
Approaches,
2010
and
2015
2010
2015
EPA
Title
IV
Avera
ge
1999
­
2002
(
Pure)
Heat
Input
1999
­
2002
Heat
Input
w/
Fuel
Factors
1999
­
2002
Heat
Input
w/
Fuel
Factors
&
Coal
Type
EPA
Title
IV
Avera
ge
1999
­
2002
(
Pure)
Heat
Input
1999
­
2002
Heat
Input
w/
Fuel
Factors
1999
­
2002
Heat
Input
w/
Fuel
Factors
&
Coal
Type
Average
Difference
0.06
0.11
0.06
0.05
0.17
0.18
0.14
­
0.17
Percent
Positive
43%
39%
52%
48%
43%
43%
43%
52%

Source:
EPA
2006
One
commenter,
who
disagreed
with
EPA's
focus
on
how
States
fare
under
different
methodologies,
suggested
using
an
"
effective
emission
rate
comparison."
However,
the
commenter
proceeded
to
perform
this
comparison
using
of
the
ratio
of
the
adjusted
state
SO2
budgets
to
recent
adjusted
heat
input
in
each
affected
state.
The
commenter
failed
to
realize
that
using
the
adjusted
state
SO2
budget
in
the
numerator
and
adjusted
heat
input
(
i.
e.,
the
heat
input
values
adjusted
with
fuel
factors,
which
were
used
to
calculate
the
State
budgets)
in
the
denominator
results
in
a
constant
ratio
across
States.
Based
on
the
commenter's
arguments,
it
appears
it
should
have
used
the
adjusted
State
budget
divided
by
the
actual
projected
heat
input.
This
approach,
however,
would
not
result
in
the
constant
effective
emission
rates,
which
the
commenter
insinuates
is
most
desirable.
The
commenter's
argument,
therefore,
is
based
on
fatally
flawed
analysis.
19
Several
commenters
have
raised
concerns
about
the
cost
of
purchasing
allowances
to
meet
projected
emissions
under
EPA's
approach,
relative
to
another
alternative.
To
provide
some
perspective
of
the
significance
of
these
purchases,
EPA
calculated
the
projected
cost
of
purchasing
allowances
as
a
percentage
of
revenue
from
electricity
sales
in
2004
for
select
States
in
CAIR
for
SO2
(
Tables
4
and
5).
The
CAIR
region­
wide
cost
as
a
percentage
of
revenue
is
a
fraction
of
one
percent
for
either
2010
or
2015.
These
States
are
projected
to
spend
less
than
2%
of
their
revenue
on
purchasing
allowances
in
either
2010
or
2015.
Most
States
from
which
commenting
companies
operate
are
projected
to
spend
even
less
than
1
percent
or
less
of
revenues
on
allowances,
and
Florida
is
projected
to
be
a
net
seller
of
allowances
(
signified
by
the
negative
sign
for
both
2010
and
2015).
5
In
fact,
the
States
that
are
projected
to
spend
the
most
on
purchasing
allowances
as
a
percentage
of
revenue
(
Kentucky
in
2010
and
Michigan
in
2015)
do
not
have
companies
commenting
on
this
Reconsideration
process.

Table
4:
2010
State
Budgets,
Projected
Emissions
and
Allowance
Costs
for
States
with
Commenters
Opposing
EPA
Approach
State
2010
CAIR
SO2
Emissions
(
Tons)
2010
Base
Case
SO2
Emissions
(
Tons)
Final
CAIR
2010
State
SO2
Budget
Heat
Input
Method
2010
State
Budget
Heat
Input
w/
Fuel
Factors
2010
State
Budget
Heat
Input
w/
Fuel
Factors
&
Coal
Type
2010
State
Budget
2010
Projected
Allowance
Cost
(
2004$)
2004
State
Electric
Power
Revenue
(
2004$)
2010
Projected
Allowance
Cost
as
Percent
of
Current
Revenue
FL
217,697
220,670
253,450
279,084
203,650
244,120
­
24,526,627
17,834,520,000
­
0.1%

IL
239,867
401,522
192,671
168,592
195,590
158,976
32,376,250
9,464,950,000
0.3%

MD
61,815
309,968
70,697
63,847
68,691
83,869
­
6,092,778
4,785,324,000
­
0.1%

MN
68,734
83,110
49,987
68,420
81,572
40,045
12,860,442
3,950,079,000
0.3%

NC
252,132
261,352
137,342
134,643
161,807
199,711
78,745,940
8,756,173,000
0.9%

PA
234,757
907,768
275,990
217,369
255,227
302,565
­
28,285,975
11,485,558,000
­
0.2%

SC
141,276
196,065
57,271
71,616
84,298
104,757
57,627,704
4,971,537,000
1.2%

TX
398,088
417,397
320,946
555,455
339,975
199,493
52,919,275
25,482,302,000
0.2%

Note:
Projected
allowance
costs
are
estimated
at
$
686
per
ton
using
IPM
modeling
run
CAIR_
CAMR_
CAVR
available
at
www.
epa.
gov/
airmarkets/
mp
adjusted
to
2004$.
Electric
power
revenues
are
based
on
U.
S.
Department
of
Energy,
Energy
Information
Administration,
"
Electric
Power
Annual
2004,"
available
at
www.
eia.
doe.
gov/
cneaf/
electricity/
epa/
epa_
sum.
html
5
Based
on
EPA
calculations
of
Acid
Rain
Program
emissions
data
from
2003
to
2004
compared
to
SO2
allocations
over
the
same
time
period,
EPA
sees
that
Minnesota
Power
and
Florida
Power
and
Light
have
had
more
allowances
than
they
needed
to
cover
their
emissions
in
recent
years.
As
net
"
sellers"
of
allowances,
companies
in
these
States
have
been
able
to
either
build
up
an
allowance
bank
for
future
use
or
sell
their
excess
allowances.
20
Table
5:
2015
State
Budgets,
Projected
Emissions
and
Allowance
Costs
for
States
with
Commenters
Opposing
EPA
Approach
State
2015
CAIR
SO2
Emissions
(
Tons)
2015
Base
Case
SO2
Emissions
(
Tons)
Final
CAIR
2015
State
SO2
Budget
Heat
Input
Method
2015
State
Budget
Heat
Input
w/
Fuel
Factors
2015
State
Budget
Heat
Input
w/
Fuel
Factors
&
Coal
Type
2015
State
Budget
2015
Projected
Allowance
Cost
(
2004$)
2004
State
Electric
Power
Revenue
(
2004$)
2015
Projected
Allowance
Cost
as
Percent
of
Current
Revenue
FL
167,154
220,670
177,415
195,359
142,555
170,884
­
10,199,335
17,834,520,000
­
0.1%

IL
239,660
446,728
134,869
118,015
136,913
111,283
104,162,453
9,464,950,000
1.1%

MD
23,813
312,974
49,488
44,693
48,084
58,708
­
25,520,851
4,785,324,000
­
0.5%

MN
71,988
82,046
34,991
47,894
57,100
28,031
36,774,521
3,950,079,000
0.9%

NC
137,886
142,109
96,139
94,250
113,264
139,798
41,496,518
8,756,173,000
0.5%

PA
132,469
851,260
193,193
152,158
178,659
211,795
­
60,359,557
11,485,558,000
­
0.5%

SC
104,436
170,353
40,089
50,131
59,008
73,330
63,960,421
4,971,537,000
1.3%

TX
352,064
417,558
224,662
388,818
237,982
139,645
126,637,389
25,482,302,000
0.5%

Note:
Projected
allowance
costs
are
estimated
at
$
994
per
ton
using
IPM
modeling
run
CAIR_
CAMR_
CAVR
available
at
www.
epa.
gov/
airmarkets/
mp
adjusted
to
2004$.
Electric
power
revenues
are
based
on
U.
S.
Department
of
Energy,
Energy
Information
Administration,
"
Electric
Power
Annual
2004,"
available
at
www.
eia.
doe.
gov/
cneaf/
electricity/
epa/
epa_
sum.
html
EPA's
approach
provides
values
within
the
range
of
alternatives
considered
for
all
of
the
metrics
examined
in
the
SO2
analyses
as
presented
in
the
following
tables
(
6­
7).
Furthermore,
when
examining
metrics
using
base
case
emissions,
EPA's
approach
performs
better
than
the
heat
input
with
fuel
factors
approach.
By
these
measures,
EPA's
approach
better
distributes
allowances
across
the
system
before
control
decisions
are
made
to
meet
CAIR
emission
reduction
goals.
21
Table
6.
Summary
­­
CAIR
Control
Case
Difference
of
State­
by­
State
SO2
Coverage
Ratios
(
Budget:
Emission)
from
Region­
wide
Percent
Reduction
2010
2015
Final
CAIR
SO2
Heat
Input
(
3b)
Heat
Input
w/
Fuel
Factors
(
4b)
Heat
Input
w/
Fuel
Factors
&
Coal
Type
(
5b)
Final
CAIR
SO2
Heat
Input
(
3b)
Heat
Input
w/
Fuel
Factors
(
4b)
Heat
Input
w/
Fuel
Factors
&
Coal
Type
(
5b)

Average
Coverage
Ratio
0.76
0.81
0.76
0.75
0.77
0.78
0.74
0.77
Average
Difference
0.06
0.11
0.06
0.05
0.17
0.18
0.14
­
0.17
Percent
Positive
43%
39%
52%
48%
43%
43%
43%
52%

Cumulative
Absolute
Difference
6.13
7.29
4.37
5.94
8.06
8.36
5.97
9.03
Average
Absolute
Difference
0.27
0.32
0.19
0.26
0.35
0.36
0.26
0.39
Source:
EPA,
2006
Table
7.
Base
Case
Difference
of
State­
by­
State
SO2
Coverage
Ratios
(
Budget:
Emission)
from
Regionwide
Percent
Reduction
2010
2015
Final
CAIR
SO2
Heat
Input
(
3b)
Heat
Input
w/
Fuel
Factors
(
4b)
Heat
Input
w/
Fuel
Factors
&
Coal
Type
(
5b)
Final
CAIR
SO2
Heat
Input
(
3b)
Heat
Input
w/
Fuel
Factors
(
4b)
Heat
Input
w/
Fuel
Factors
&
Coal
Type
(
5b)

Average
Coverage
Ratio
0.48
0.54
0.50
0.46
0.35
0.39
0.36
0.34
Average
Difference
0.06
0.12
0.08
0.04
0.05
0.14
0.08
0.04
Percent
Positive
43%
43%
61%
52%
39%
43%
52%
57%

Cumulative
Absolute
Difference
3.60
5.86
3.82
2.71
2.35
4.00
2.62
2.08
Average
Absolute
Difference
0.16
0.25
0.17
0.12
0.20
0.33
0.22
0.17
Source:
EPA,
2006
22
Further
examination
of
the
analyses
shows
that
each
approach
advantages
and
disadvantages
electric
generating
units
using
fossil
fuels
some
in
States.
A
few
States
receive
coverage
ratios
that
are
consistently
on
one
end
of
the
spectrum
or
the
other
regardless
of
which
approach
is
taken,
according
to
EPA
projections.
Michigan
and
Georgia
have
coverage
ratios
in
the
bottom
5
of
all
CAIR
States
analyzed
(
low
category).
New
York
and
Maryland
receive
among
the
5
highest
coverage
ratios
in
2010
under
the
CAIR
control
case
(
high
category).
Meanwhile,
some
States
are
particularly
advantaged
or
disadvantaged
by
one
or
a
few
of
the
approaches
and
not
others
(
see
Tables
8
to
11).
For
example,
choosing
the
pure
heat
input
method
would
put
Tennessee
into
the
low
category,
while
bringing
Texas
and
Louisiana
into
the
high
category.
On
the
other
hand,
choosing
any
of
the
fuel
adjusted
methods,
including
EPA's
method,
would
guarantee
that
Ohio,
Pennsylvania,
Maryland
and
New
York
are
in
the
high
category,
while
Georgia,
Mississippi,
and
Michigan
would
be
in
the
low
category.
Minnesota
has
among
the
highest
relative
rank
with
heat
input
with
fuel
factors,
but
Iowa
joins
the
low
category
in
that
case.
South
Carolina
is
in
the
low
category
in
2010
CAIR
control
case
for
all
approaches
except
heat
input
with
fuel
factors
and
coal
type.

These
tables
further
demonstrate
that
each
allocation
approach
results
in
a
somewhat
different
mix
of
States
who,
in
general,
will
be
net
sellers
or
buyers
of
allowances.
This
alone
is
not
enough
to
assess
the
fairness
of
a
particular
method,
as
some
commenters
have
alleged.
However,
after
evaluating
multiple
approaches
compared
to
EPA's
approach
with
several
analytical
and
statistical
methods
seen
throughout
this
TSD
and
its
appendices,
EPA
has
determined
that
its
SO2
allowance
allocation
methodology
is
a
rational
choice
among
the
options
to
support
the
objectives
stated
above.
23
Table
8.
2010
State­
by­
State
CAIR
Control
Case
Coverage
Ratios
in
Descending
Order
State
CAIR
SO2
State
Heat
Input
State
Heat
Input
with
Fuel
Factors
State
Heat
Input
with
Fuel
Factors
and
Coal
Type
NY
2.04
NY
2.20
MN
1.19
NY
1.45
PA
1.18
LA
1.94
NY
1.17
MD
1.36
FL
1.16
TX
1.40
MD
1.11
PA
1.29
MD
1.14
FL
1.28
PA
1.09
OH
1.17
OH
1.12
MD
1.03
OH
0.95
FL
1.12
LA
0.97
MN
1.00
FL
0.94
WV
0.97
WV
0.86
PA
0.93
LA
0.93
VA
0.82
TX
0.81
OH
0.78
TX
0.85
NC
0.79
IL
0.80
IL
0.70
IL
0.82
KY
0.77
MN
0.73
WI
0.65
WV
0.78
TN
0.75
TN
0.65
WV
0.63
WI
0.77
SC
0.74
WI
0.64
VA
0.61
IA
0.72
IN
0.67
IN
0.59
MS
0.59
IN
0.66
IL
0.66
MO
0.57
IA
0.59
VA
0.66
AL
0.59
KY
0.55
IN
0.55
NC
0.64
LA
0.58
NC
0.54
MO
0.54
MO
0.64
MN
0.58
IA
0.54
NC
0.53
KY
0.64
TX
0.50
AL
0.49
KY
0.52
TN
0.63
WI
0.47
GA
0.48
TN
0.52
SC
0.60
MS
0.44
MI
0.47
SC
0.51
AL
0.55
GA
0.43
VA
0.47
AL
0.48
MS
0.42
IA
0.37
SC
0.41
MI
0.40
MI
0.42
MI
0.35
MS
0.39
GA
0.33
GA
0.38
MO
0.34
Source:
EPA,
2006
24
Table
9.
2010
State­
by­
State
Base
Case
Coverage
Ratios
in
Descending
Order
State
CAIR
SO2
State
Heat
Input
State
Heat
Input
with
Fuel
Factors
State
Heat
Input
with
Fuel
Factors
and
Coal
Type
FL
1.15
TX
1.33
MN
0.98
FL
1.11
NY
1.03
FL
1.26
MO
0.98
NY
0.74
TX
0.77
LA
1.21
FL
0.92
KY
0.59
LA
0.60
NY
1.12
TX
0.81
VA
0.58
MN
0.60
MN
0.82
NC
0.63
WI
0.58
MO
0.60
MO
0.82
NY
0.60
SC
0.53
NC
0.55
MS
0.59
LA
0.58
MN
0.48
IL
0.48
NC
0.53
KY
0.49
MO
0.48
MI
0.46
VA
0.44
IL
0.49
TX
0.48
KY
0.42
WI
0.44
VA
0.47
TN
0.45
MS
0.39
IL
0.42
WI
0.47
IN
0.44
IN
0.39
KY
0.40
IN
0.44
MS
0.44
TN
0.39
MI
0.40
SC
0.43
WV
0.42
WV
0.37
SC
0.37
MS
0.42
IL
0.40
GA
0.36
IN
0.36
MI
0.41
AL
0.39
IA
0.36
AL
0.32
TN
0.38
LA
0.36
VA
0.33
TN
0.31
AL
0.37
MI
0.35
WI
0.33
WV
0.27
WV
0.33
PA
0.33
AL
0.33
GA
0.25
GA
0.29
NC
0.33
PA
0.30
IA
0.25
IA
0.29
GA
0.33
SC
0.29
PA
0.24
PA
0.28
IA
0.33
OH
0.24
MD
0.21
MD
0.22
MD
0.27
MD
0.23
OH
0.17
OH
0.21
OH
0.25
Source:
EPA,
2006
25
Table
10.
2015
State­
by­
State
CAIR
Control
Case
Coverage
Ratios
in
Descending
Order
State
CAIR
SO2
State
Heat
Input
State
Heat
Input
with
Fuel
Factors
State
Heat
Input
with
Fuel
Factors
and
Coal
Type
NY
2.32
NY
2.51
MD
2.02
MD
2.47
MD
2.08
MD
1.88
PA
1.35
NY
1.65
PA
1.46
LA
1.36
NY
1.34
PA
1.60
WV
1.28
FL
1.17
WV
1.15
WV
1.44
OH
1.12
PA
1.15
OH
0.96
OH
1.17
FL
1.06
TX
1.10
FL
0.85
FL
1.02
NC
0.70
WV
0.94
NC
0.82
NC
1.01
LA
0.68
OH
0.79
MN
0.79
SC
0.70
TX
0.64
NC
0.68
TX
0.68
TN
0.69
TN
0.60
MN
0.67
LA
0.65
KY
0.68
GA
0.60
VA
0.50
TN
0.58
VA
0.67
IL
0.56
IL
0.49
IL
0.57
IN
0.57
IN
0.51
SC
0.48
SC
0.57
GA
0.54
KY
0.49
TN
0.48
KY
0.56
AL
0.52
MN
0.49
WI
0.48
IN
0.56
IL
0.46
WI
0.46
IN
0.47
WI
0.56
LA
0.41
AL
0.43
KY
0.46
VA
0.54
TX
0.40
MO
0.39
MS
0.44
AL
0.48
MN
0.39
SC
0.38
AL
0.42
IA
0.48
WI
0.34
VA
0.38
GA
0.41
GA
0.48
MS
0.33
IA
0.36
IA
0.39
MO
0.44
IA
0.25
MI
0.32
MO
0.37
MS
0.31
MI
0.24
MS
0.29
MI
0.28
MI
0.29
MO
0.23
Source:
EPA,
2006
26
Table
11.
2015
State­
by­
State
Base
Case
Coverage
Ratios
in
Descending
Order
State
CAIR
SO2
State
Heat
Input
State
Heat
Input
with
Fuel
Factors
State
Heat
Input
with
Fuel
Factors
and
Coal
Type
FL
0.80
TX
0.93
MN
0.70
FL
0.77
NY
0.72
FL
0.89
MO
0.70
NY
0.51
TX
0.54
LA
0.85
FL
0.65
KY
0.44
MN
0.43
NY
0.77
TX
0.57
VA
0.43
MO
0.43
MN
0.58
NC
0.43
WI
0.43
LA
0.42
MO
0.58
NY
0.41
SC
0.43
NC
0.38
MS
0.42
LA
0.41
IN
0.38
IN
0.34
NC
0.36
IN
0.37
TN
0.35
KY
0.32
VA
0.32
KY
0.37
WV
0.34
MI
0.31
WI
0.32
VA
0.35
MN
0.34
WV
0.31
IN
0.31
WI
0.35
MO
0.34
TN
0.30
KY
0.30
SC
0.35
TX
0.33
IL
0.30
SC
0.29
IL
0.31
AL
0.33
MS
0.28
MI
0.27
AL
0.30
MS
0.31
AL
0.27
AL
0.27
TN
0.30
LA
0.26
GA
0.25
IL
0.26
MS
0.30
IL
0.25
IA
0.25
TN
0.24
MI
0.28
PA
0.25
VA
0.25
WV
0.22
WV
0.28
MI
0.24
WI
0.25
PA
0.18
PA
0.21
GA
0.23
SC
0.24
GA
0.17
GA
0.20
IA
0.23
PA
0.23
IA
0.17
IA
0.20
OH
0.23
OH
0.22
OH
0.15
OH
0.19
NC
0.23
MD
0.16
MD
0.14
MD
0.15
MD
0.19
Source:
EPA,
2006
27
Appendix
A
 
EPA
Difference
Tables
28
1
Table
A.
2010
State­
by­
State
CAIR
Control
Case
Coverage
Ratios,
CAIR
&
Alternatives
CAIR
SO2
Heat
Input
Heat
Input
w/
Fuel
Factors
Heat
Input
w/
Fuel
Factors
&
Coal
Type
State
Coverage
Ratio:
Budget
to
Emission
Difference
(
from
0.70)
Absolute
Difference
(
from
0.70)
Coverage
Ratio:
Budget
to
Emission
Difference
(
from
0.70)
Absolute
Difference
(
from
0.70)
Coverage
Ratio:
Budget
to
Emission
Difference
(
from
0.70)
Absolute
Difference
(
from
0.70)
Coverage
Ratio:
Budget
to
Emission
Difference
(
from
0.70)
Absolute
Difference
(
from
0.70)

AL
0.49
­
0.21
0.21
0.48
­
0.22
0.22
0.55
­
0.15
0.15
0.59
­
0.11
0.11
FL
1.16
0.46
0.46
1.28
0.58
0.58
0.94
0.24
0.24
1.12
0.42
0.42
GA
0.48
­
0.23
0.23
0.33
­
0.37
0.37
0.38
­
0.32
0.32
0.43
­
0.27
0.27
IA
0.54
­
0.16
0.16
0.59
­
0.11
0.11
0.72
0.02
0.02
0.37
­
0.33
0.33
IL
0.80
0.10
0.10
0.70
0.00
0.00
0.82
0.12
0.12
0.66
­
0.04
0.04
IN
0.59
­
0.11
0.11
0.55
­
0.15
0.15
0.66
­
0.04
0.04
0.67
­
0.03
0.03
KY
0.55
­
0.15
0.15
0.52
­
0.18
0.18
0.64
­
0.06
0.06
0.77
0.07
0.07
LA
0.97
0.26
0.26
1.94
1.24
1.24
0.93
0.23
0.23
0.58
­
0.12
0.12
MD
1.14
0.44
0.44
1.03
0.33
0.33
1.11
0.41
0.41
1.36
0.66
0.66
MI
0.47
­
0.24
0.24
0.40
­
0.30
0.30
0.42
­
0.28
0.28
0.35
­
0.35
0.35
MN
0.73
0.02
0.02
1.00
0.30
0.30
1.19
0.49
0.49
0.58
­
0.12
0.12
MO
0.57
­
0.14
0.14
0.54
­
0.16
0.16
0.64
­
0.06
0.06
0.34
­
0.36
0.36
MS
0.39
­
0.31
0.31
0.59
­
0.11
0.11
0.42
­
0.28
0.28
0.44
­
0.26
0.26
NC
0.54
­
0.16
0.16
0.53
­
0.17
0.17
0.64
­
0.06
0.06
0.79
0.09
0.09
NY
2.04
1.33
1.33
2.20
1.50
1.50
1.17
0.47
0.47
1.45
0.75
0.75
OH
1.12
0.41
0.41
0.78
0.08
0.08
0.95
0.25
0.25
1.17
0.47
0.47
PA
1.18
0.47
0.47
0.93
0.23
0.23
1.09
0.39
0.39
1.29
0.59
0.59
SC
0.41
­
0.30
0.30
0.51
­
0.19
0.19
0.60
­
0.10
0.10
0.74
0.04
0.04
TN
0.65
­
0.05
0.05
0.52
­
0.18
0.18
0.63
­
0.07
0.07
0.75
0.05
0.05
TX
0.81
0.10
0.10
1.40
0.70
0.70
0.85
0.15
0.15
0.50
­
0.20
0.20
VA
0.47
­
0.24
0.24
0.61
­
0.09
0.09
0.66
­
0.04
0.04
0.82
0.12
0.12
WI
0.64
­
0.07
0.07
0.65
­
0.05
0.05
0.77
0.07
0.07
0.47
­
0.23
0.23
WV
0.86
0.16
0.16
0.63
­
0.07
0.07
0.78
0.08
0.08
0.97
0.27
0.27
Total
1.40
6.13
2.62
7.29
1.46
4.37
1.11
5.94
Average
0.76
0.06
0.27
0.81
0.11
0.32
0.76
0.06
0.19
0.75
0.05
0.26
Percent
Positive
43%
39%
52%
48%

Source:
EPA,
2006
2
Table
B.
2015
State­
by­
State
CAIR
Control
Coverage
Ratios,
CAIR
&
Alternatives
CAIR
SO2
Heat
Input
Heat
Input
w/
Fuel
Factors
Heat
Input
w/
Fuel
Factors
&
Coal
Type
State
Coverage
Ratio:

Budget
to
Emission
Difference
(
from
0.60)
Absolute
Difference
(
from
0.60)
Coverage
Ratio:
Budget
to
Emission
Difference
(
from
0.60)
Absolute
Difference
(
from
0.60)
Coverage
Ratio:

Budget
to
Emission
Difference
(
from
0.60)
Absolute
Difference
(
from
0.60)
Coverage
Ratio:

Budget
to
Emission
Difference
(
from
0.60)
Absolute
Difference
(
from
0.60)

AL
0.43
­
0.17
0.17
0.42
­
0.18
0.18
0.48
­
0.12
0.12
0.52
0.08
0.08
FL
1.06
0.46
0.46
1.17
0.57
0.57
0.85
0.25
0.25
1.02
­
0.42
0.42
GA
0.60
0.00
0.00
0.41
­
0.19
0.19
0.48
­
0.12
0.12
0.54
0.06
0.06
IL
0.56
­
0.04
0.04
0.49
­
0.11
0.11
0.57
­
0.03
0.03
0.46
0.14
0.14
IN
0.51
­
0.09
0.09
0.47
­
0.13
0.13
0.56
­
0.04
0.04
0.57
0.03
0.03
IA
0.36
­
0.24
0.24
0.39
­
0.21
0.21
0.48
­
0.12
0.12
0.25
0.35
0.35
KY
0.49
­
0.11
0.11
0.46
­
0.14
0.14
0.56
­
0.04
0.04
0.68
­
0.08
0.08
LA
0.68
0.08
0.08
1.36
0.76
0.76
0.65
0.05
0.05
0.41
0.19
0.19
MD
2.08
1.48
1.48
1.88
1.28
1.28
2.02
1.42
1.42
2.47
­
1.87
1.87
MI
0.32
­
0.28
0.28
0.28
­
0.32
0.32
0.29
­
0.31
0.31
0.24
0.36
0.36
MN
0.49
­
0.11
0.11
0.67
0.07
0.07
0.79
0.19
0.19
0.39
0.21
0.21
MS
0.29
­
0.31
0.31
0.44
­
0.16
0.16
0.31
­
0.29
0.29
0.33
0.27
0.27
MO
0.39
­
0.21
0.21
0.37
­
0.23
0.23
0.44
­
0.16
0.16
0.23
0.37
0.37
NY
2.32
1.72
1.72
2.51
1.91
1.91
1.34
0.74
0.74
1.65
­
1.05
1.05
NC
0.70
0.10
0.10
0.68
0.08
0.08
0.82
0.22
0.22
1.01
­
0.41
0.41
OH
1.12
0.52
0.52
0.79
0.19
0.19
0.96
0.36
0.36
1.17
­
0.57
0.57
PA
1.46
0.86
0.86
1.15
0.55
0.55
1.35
0.75
0.75
1.60
­
1.00
1.00
SC
0.38
­
0.22
0.22
0.48
­
0.12
0.12
0.57
­
0.03
0.03
0.70
­
0.10
0.10
TN
0.60
0.00
0.00
0.48
­
0.12
0.12
0.58
­
0.02
0.02
0.69
­
0.09
0.09
TX
0.64
0.04
0.04
1.10
0.50
0.50
0.68
0.08
0.08
0.40
0.20
0.20
VA
0.38
­
0.22
0.22
0.50
­
0.10
0.10
0.54
­
0.06
0.06
0.67
­
0.07
0.07
WV
1.28
0.68
0.68
0.94
0.34
0.34
1.15
0.55
0.55
1.44
­
0.84
0.84
WI
0.46
­
0.14
0.14
0.48
­
0.12
0.12
0.56
­
0.04
0.04
0.34
0.26
0.26
Total
3.81
8.06
4.11
8.36
3.25
5.97
­
3.99
9.03
Average
0.77
0.17
0.35
0.78
0.18
0.36
0.74
0.14
0.26
0.77
­
0.17
0.39
Percent
Positive
43%
43%
43%
52%

Source:
EPA,
2006
3
ST
ABBR
Final
CAIR
2010
State
SO2
Budget
Final
CAIR
2015
State
SO2
Budget
Method
3b
2010
State
Budget
Method
3b
2015
State
Budget
Method
4b
2010
State
Budget
Method
4b
2015
State
Budget
Method
5b
2010
State
Budget
Method
5b
2015
State
Budget
AL
157,582
110,307
154,288
108,001
175,798
123,058
188,339
131,837
DC
708
495
513
359
189
133
212
148
FL
253,450
177,415
279,084
195,359
203,650
142,555
244,120
170,884
GA
213,057
149,140
146,955
102,868
169,928
118,950
192,536
134,775
IA
64,095
44,866
70,019
49,013
85,715
60,001
43,853
30,697
IL
192,671
134,869
168,592
118,015
195,590
136,913
158,976
111,283
IN
254,599
178,219
235,113
164,579
284,195
198,936
287,174
201,022
KY
188,773
132,141
178,489
124,942
217,936
152,555
262,395
183,676
LA
59,948
41,963
120,325
84,228
57,551
40,286
36,197
25,338
MD
70,697
49,488
63,847
44,693
68,691
48,084
83,869
58,708
MI
178,605
125,024
153,030
107,121
160,502
112,351
134,708
94,295
MN
49,987
34,991
68,420
47,894
81,572
57,100
40,045
28,031
MO
137,214
96,050
130,563
91,394
155,103
108,572
81,931
57,351
MS
33,763
23,634
50,870
35,609
36,089
25,263
37,669
26,369
NC
137,342
96,139
134,643
94,250
161,807
113,264
199,711
139,798
NY
135,139
94,597
146,004
102,203
77,937
54,556
96,342
67,439
OH
333,520
233,464
233,407
163,385
284,404
199,082
348,166
243,716
PA
275,990
193,193
217,369
152,158
255,227
178,659
302,565
211,795
SC
57,271
40,089
71,616
50,131
84,298
59,008
104,757
73,330
TN
137,216
96,051
109,435
76,604
133,420
93,394
157,948
110,563
TX
320,946
224,662
555,455
388,818
339,975
237,982
199,493
139,645
VA
63,478
44,435
82,995
58,097
89,665
62,765
110,935
77,654
WI
87,264
61,085
89,598
62,719
105,025
73,518
64,197
44,938
WV
215,881
151,117
158,567
110,997
194,929
136,450
243,059
170,141
3,619,196
2,533,434
3,619,196
2,533,434
3,619,196
2,533,434
3,619,197
2,533,433
Source:
EPA,
2006
1
Table
C.
2010
State­
by­
State
Coverage
Ratios
using
Projected
Emissions
from
Base
Case,
CAIR
&
Alternatives
CAIR
SO2
Heat
Input
(
3b)
Heat
Input
w/
Fuel
Factors
(
4b)
Heat
Input
w/
Fuel
Factors
&
Coal
Type
(
5b)

State
Coverage
Ratio:
Budget
to
Emission
Difference
(
from
0.42)
Absloute
Difference
(
from
0.42)
Coverage
Ratio:

Budget
to
Emission
Difference
(
from
0.41)
Absloute
Difference
(
from
0.42)
Coverage
Ratio:
Budget
to
Emission
Difference
(
from
0.41)
Absloute
Difference
(
from
0.42)
Coverage
Ratio:
Budget
to
Emission
Difference
(
from
0.41)
Absloute
Difference
(
from
0.42)

AL
0.33
­
0.09
0.09
0.32
­
0.10
0.10
0.37
­
0.05
0.05
0.39
­
0.03
0.03
FL
1.15
0.73
0.73
1.26
0.84
0.84
0.92
0.50
0.50
1.11
0.69
0.69
GA
0.36
­
0.06
0.06
0.25
­
0.17
0.17
0.29
­
0.13
0.13
0.33
­
0.09
0.09
IL
0.48
0.06
0.06
0.42
0.00
0.00
0.49
0.07
0.07
0.40
­
0.02
0.02
IN
0.39
­
0.03
0.03
0.36
­
0.06
0.06
0.44
0.02
0.02
0.44
0.02
0.02
IA
0.36
­
0.06
0.06
0.25
­
0.17
0.17
0.29
­
0.13
0.13
0.33
­
0.09
0.09
KY
0.42
0.00
0.00
0.40
­
0.02
0.02
0.49
0.07
0.07
0.59
0.17
0.17
LA
0.60
0.18
0.18
1.21
0.79
0.79
0.58
0.16
0.16
0.36
­
0.06
0.06
MD
0.23
­
0.19
0.19
0.21
­
0.21
0.21
0.22
­
0.20
0.20
0.27
­
0.15
0.15
MI
0.46
0.04
0.04
0.40
­
0.02
0.02
0.41
­
0.01
0.01
0.35
­
0.07
0.07
MN
0.60
0.18
0.18
0.82
0.40
0.40
0.98
0.56
0.56
0.48
0.06
0.06
MS
0.39
­
0.03
0.03
0.59
0.17
0.17
0.42
0.00
0.00
0.44
0.02
0.02
MO
0.60
0.18
0.18
0.82
0.40
0.40
0.98
0.56
0.56
0.48
0.06
0.06
NY
1.03
0.61
0.61
1.12
0.70
0.70
0.60
0.18
0.18
0.74
0.32
0.32
NC
0.55
0.13
0.13
0.53
0.11
0.11
0.63
0.21
0.21
0.33
­
0.09
0.09
OH
0.24
­
0.18
0.18
0.17
­
0.25
0.25
0.21
­
0.21
0.21
0.25
­
0.17
0.17
PA
0.30
­
0.12
0.12
0.24
­
0.18
0.18
0.28
­
0.14
0.14
0.33
­
0.09
0.09
SC
0.29
­
0.13
0.13
0.37
­
0.05
0.05
0.43
0.01
0.01
0.53
0.11
0.11
TN
0.39
­
0.03
0.03
0.31
­
0.11
0.11
0.38
­
0.04
0.04
0.45
0.03
0.03
TX
0.77
0.35
0.35
1.33
0.91
0.91
0.81
0.39
0.39
0.48
0.06
0.06
VA
0.33
­
0.09
0.09
0.44
0.02
0.02
0.47
0.05
0.05
0.58
0.16
0.16
WV
0.37
­
0.05
0.05
0.27
­
0.15
0.15
0.33
­
0.09
0.09
0.42
0.00
0.00
WI
0.33
­
0.09
0.09
0.44
0.02
0.02
0.47
0.05
0.05
0.58
0.16
0.16
Total
1.35
3.60
2.87
5.86
1.83
3.82
1.01
2.71
Average
0.48
0.06
0.16
0.54
0.12
0.25
0.50
0.08
0.17
0.46
0.04
0.12
Percent
Positive
43%
43%
61%
52%

Source:
EPA,
2006
2
Table
D.
2015
State­
by­
State
Coverage
Ratios
using
Projected
Emissions
from
Base
Case,
CAIR
&
Alternatives
CAIR
SO2
Heat
Input
(
3b)
Heat
Input
w/
Fuel
Factors
(
4b)
Heat
Input
w/
Fuel
Factors
&
Coal
Type
(
5b)

State
Coverage
Ratio:

Budget
to
Emission
Difference
(
from
0.32)
Absloute
Difference
(
from
0.32)
Coverage
Ratio:
Budget
to
Emission
Difference
(
from
0.32)
Absloute
Difference
(
from
0.32)
Coverage
Ratio:
Budget
to
Emission
Difference
(
from
0.32)
Absloute
Difference
(
from
0.32)
Coverage
Ratio:
Budget
to
Emission
Difference
(
from
0.32)
Absloute
Difference
(
from
0.32)

AL
0.27
­
0.05
0.05
0.27
­
0.05
0.05
0.30
­
0.02
0.02
0.33
0.01
0.01
FL
0.80
0.48
0.48
0.89
0.57
0.57
0.65
0.33
0.33
0.77
0.45
0.45
GA
0.25
­
0.07
0.07
0.17
­
0.15
0.15
0.20
­
0.12
0.12
0.23
­
0.09
0.09
IL
0.30
­
0.02
0.02
0.26
­
0.06
0.06
0.31
­
0.01
0.01
0.25
­
0.07
0.07
IN
0.34
0.02
0.02
0.31
­
0.01
0.01
0.37
0.05
0.05
0.38
0.06
0.06
IA
0.25
­
0.07
0.07
0.17
­
0.15
0.15
0.20
­
0.12
0.12
0.23
­
0.09
0.09
KY
0.32
0.00
0.00
0.30
­
0.02
0.02
0.37
0.05
0.05
0.44
0.12
0.12
LA
0.42
0.10
0.10
0.85
0.53
0.53
0.41
0.09
0.09
0.26
­
0.06
0.06
MD
0.16
­
0.16
0.16
0.14
­
0.18
0.18
0.15
­
0.17
0.17
0.19
­
0.13
0.13
MI
0.31
­
0.01
0.01
0.27
­
0.05
0.05
0.28
­
0.04
0.04
0.24
­
0.08
0.08
MN
0.43
0.11
0.11
0.58
0.26
0.26
0.70
0.38
0.38
0.34
0.02
0.02
MS
0.28
­
0.04
0.04
0.42
0.10
0.10
0.30
­
0.02
0.02
0.31
­
0.01
0.01
MO
0.43
0.11
0.11
0.58
0.26
0.26
0.70
0.38
0.38
0.34
0.02
0.02
NY
0.72
0.40
0.40
0.77
0.45
0.45
0.41
0.09
0.09
0.51
0.19
0.19
NC
0.38
0.06
0.06
0.36
0.04
0.04
0.43
0.11
0.11
0.23
­
0.09
0.09
OH
0.22
­
0.10
0.10
0.15
­
0.17
0.17
0.19
­
0.13
0.13
0.23
­
0.09
0.09
PA
0.23
­
0.09
0.09
0.18
­
0.14
0.14
0.21
­
0.11
0.11
0.25
­
0.07
0.07
SC
0.24
­
0.08
0.08
0.29
­
0.03
0.03
0.35
0.03
0.03
0.43
0.11
0.11
TN
0.30
­
0.02
0.02
0.24
­
0.08
0.08
0.30
­
0.02
0.02
0.35
0.03
0.03
TX
0.54
0.22
0.22
0.93
0.61
0.61
0.57
0.25
0.25
0.33
0.01
0.01
VA
0.25
­
0.07
0.07
0.32
0.00
0.00
0.35
0.03
0.03
0.43
0.11
0.11
WV
0.31
­
0.01
0.01
0.22
­
0.10
0.10
0.28
­
0.04
0.04
0.34
0.02
0.02
WI
0.25
­
0.07
0.07
0.32
0.00
0.00
0.35
0.03
0.03
0.43
0.11
0.11
Total
0.63
2.35
1.67
4.00
1.00
2.62
0.48
2.08
Average
0.35
0.05
0.20
0.39
0.14
0.33
0.36
0.08
0.22
0.34
0.04
0.17
Percent
Positive
39%
43%
52%
57%

Source:
EPA,
2006
3
4
EcoStat,
Inc.
P.
O.
Box
425
Mebane,
N.
C.
27302
Ph/
Fx:
(
919)
304­
6029
billwh@
mindspring.
com
March
16,
2006
To:
Chitra
Kumar
From:
William
Warren­
Hicks,
Ph.
D.

Subject:
Evaluation
of
Alternative
SO2
Allocation
Approaches
under
CAIR
Introduction
This
memorandum
presents
an
analysis
of
alternative
approaches
for
generating
SO2
allocations
and
State
budgets
under
EPA's
Clean
Air
Interstate
Rule
(
CAIR).
The
analysis
was
conducted,
in
part,
in
response
to
petitions
for
reconsideration
of
the
SO2
allocation
approach
based
on
Title
IV
which
EPA
relied
upon
for
CAIR.
The
objective
of
the
analyses
presented
in
this
report
are
to
statistically
evaluate
the
relationship
among
allocations
and
State
budgets
generated
by
EPA's
approach
and
alternative
approaches.
All
data
evaluated
in
this
report
were
generated
by
EPA.

A
complete
description
of
EPA's
procedures
for
projecting
allocations
and
emissions
in
the
years
2010
and
2015
is
found
in
the
CAIR
SO2
Allocation
Approach
Analysis
Technical
Support
Document
(
TSD,
EPA
Docket
number
OAR­
2003­
0053)
and
a
memorandum
from
Perrin
Quarles
Associates
dated
March
2006
which
can
be
found
in
the
Docket
number
OAR­
2003­
0053.
In
the
Notice
of
Final
Action
on
Reconsideration
SO2
TSD,
EPA
evaluated
the
ratio
of
SO2
allowances
to
total
projected
emissions
before
CAIR
controls
(
called
the
base
case)
and
with
CAIR
controls
installed
(
called
the
control
case).
We
provide
further
evaluation
of
each
of
these
cases
in
this
report.
In
addition
to
the
EPA
approach,
the
following
three
alternative
approaches
(
which
were
also
evaluated
by
EPA)
are
addressed
in
this
report:

1.
allowances
based
on
heat
input
data
(
termed
heat
input
approach),

2.
allowances
based
on
heat
input
data
adjusted
for
fuel
factor
(
e.
g.,
coal,
oil,
and
gas;
termed
the
heat
input
&
fuel
factor
approach),
and
3.
allowances
based
on
heat
input
data
adjusted
both
for
fuel
type
and
coal
type
(
e.
g.,
bituminous,
sub­
bituminous,
and
lignite;
termed
the
heat
input
&
fuel
factor,
coal
type
approach).
5
Allocations
and
emissions
in
the
years
2010
and
2015
were
aggregated
at
the
company
ownerlevel
and
company
parent­
level.
A
complete
explanation
of
these
organizational
units
and
approaches
for
aggregating
emissions
is
available
in
the
TSD.

In
addition
to
the
parent­
level
and
owner­
level
allowance
allocations,
EPA
generated
allowance
budgets
for
States
(
see
memorandum
from
Perrin
Quarles
Associates,
March
2006).
In
this
report,
we
evaluate
the
ratio
(
termed
State
coverage
ratios)
of
the
2010
and
2015
CAIR
State
SO2
allowance
budgets
to
projected
State­
level
emissions
for
each
of
the
four
alternative
approaches.
EPA
also
generated
region­
wide
SO2
budgets.
The
relationship
of
a
State
allowance
budget
to
the
region­
wide
allowance
budget
was
computed
for
each
of
the
four
alternative
approaches,
as
well
as
four
additional
approaches
(
see
Notice
of
Final
Action
on
Reconsideration
in
the
docket).
We
examine
the
above
State
and
region­
wide
data
in
the
analyses
presented
in
this
report.

Statistical
Approach
The
objective
of
the
analyses
presented
in
this
report
is
to
compare
allocations
and
budgets
generated
based
on
EPA's
approach
and
alternative
approaches
proposed
by
commenters
on
the
CAIR.
We
evaluate
the
relationship
among
the
candidate
approaches
based
on
an
analysis
of
distribution
and
an
analysis
of
centrality.
In
the
context
of
the
CAIR,
an
approach
is
biased
if
it
results
in
allocations
or
budgets
that
are
consistently
higher
or
lower
than
other
possible
approaches.
Bias
is
generally
assessed
against
a
measure
of
centrality,
like
the
sample
mean.
In
this
report,
the
concept
of
bias
is
addressed
in
the
calculation
of
a
percent
difference.
Generally,
four
allocations
(
or
budgets)
are
available
for
each
source
(
e.
g.,
parent,
owner,
or
State)
in
a
data
set
(
e.
g.,
four
allocation
values,
each
from
a
different
approach,
associated
with
a
specific
parent
company
for
the
year
2015).
The
mean
of
these
four
approaches
represents
a
measure
of
central
tendency
among
the
alternative
approaches.
Calculation
of
the
approach­
specific
percent
difference
provides
a
measure
of
relative
bias
with
respect
to
the
other
approaches.
The
average
of
all
the
percent
differences
(
i.
e.,
across
all
sources
in
the
spreadsheet)
provides
an
objective
approach
for
judging
the
overall
relationship
among
the
four
approaches.
The
perfect
approach
would
have
an
average
percent
difference
of
zero,
indicating
that
allocations
generated
by
the
approach
were
on
average
near
the
center
of
all
allocations
associated
with
the
source
population.
An
approach
that
consistently
results
in
a
positive
percent
difference
could
be
considered
to
be
biased
high
relative
to
the
other
approaches.
An
approach
that
consistently
results
in
a
negative
percent
difference
could
be
considered
to
be
biased
low.
The
magnitude
of
the
percent
differences
for
any
single
source
is
not
of
particular
interest,
but
the
average
of
the
percent
differences
across
all
sources
effectively
increases
the
sample
size
available
for
judging
bias
and
provides
an
overall
measure
of
the
degree
of
bias
associated
with
a
single
approach.
The
use
of
zero
values
in
the
calculations
results
in
non­
interpretable
results,
therefore,
sources
with
zero
allocations
are
not
used
to
generate
this
statistic.
By
examining
the
average
percent
differences
calculated
across
all
sources
in
the
spreadsheet,
the
effective
sample
size
is
increased
and
the
results
are
interpretable.
6
The
other
approach
used
in
this
study
to
evaluate
allocation
approaches
extends
the
analysis
beyond
measures
of
centrality
and
examines
the
distribution
of
allocations
across
all
sources.
From
a
regulatory
perspective,
EPA
is
charged
with
reducing
SO2
emissions
that
significantly
contribute
to
non­
attainment
through
the
CAIR.
Therefore,
rather
than
examining
individual
sources
subject
to
CAIR,
a
statistical
method
that
evaluates
the
entire
population
of
sources
subject
to
the
rule
is
preferable.
Examination
of
distributions
provides
an
approach
for
assessing
allocations
across
the
entire
population
affected
by
the
program.
For
any
given
company
or
State,
EPA's
approach
may
produce
a
different
result
than
an
alternative
approach.
However,
from
a
regulatory
perspective,
the
objective
is
to
examine
the
entire
population
of
sources
subject
to
CAIR,
and
evaluate
the
relationship
among
the
competing
approaches.
Two
fundamental
approaches
are
used
for
these
evaluations.
First,
a
cumulative
distribution
of
allocations
or
State
budgets
provides
a
visual
examination
of
the
relative
consistency
among
the
results
generated
by
the
four
competing
approaches.
Overlapping
distributions
indicate
a
general
consistency
among
the
approaches.
Second,
examination
of
the
number
of
positive
and
negative
percent
differences
provides
a
semi­
qualitative
approach
for
examining
the
relative
bias
associated
with
an
approach.
The
perfect
approach
would
be
associated
with
50%
positive
readings
and
50%
negative
readings,
indicating
that
the
approach
is
not
biased
high,
nor
biased
low.

Results:
Parent­
and
Owner/
Operator­
level
Analyses
Figures
1
­
4
display
cumulative
distributions
of
the
ratio
of
allocations
to
emissions
at
the
parent­
level
and
owner/
operator­
levels
of
aggregation
in
the
years
2010
and
2015.
Data
in
the
four
figures
represent
the
CAIR
control
case.
Examination
of
the
figures
provides
the
following
findings:

°
At
the
owner­
level,
the
distributions
of
EPA
and
the
heat
input
&
fuel
factor
approaches
seem
to
be
grouped
separately
from
the
other
two
approaches.
The
owner­
level
of
aggregation
displays
a
large
variability
among
the
four
approaches,
with
each
approach
somewhat
distinct
from
the
others.
The
EPA
approach
results
in
approximately
28%
of
the
owner/
operators
having
zero
allocations.
Examination
of
the
data
indicates
that
the
zero
allocations
are
associated
with
gas­
fired
units
(
see
additional
comments
in
the
conclusions
section
of
this
report).
Regeneration
of
the
distributions
after
eliminating
those
owner/
operators
in
which
any
of
the
four
approaches
resulted
in
a
zero
allocation
(
Figures
5
and
6)
indicates
that
the
resulting
distributions
are
very
similar.

°
At
the
parent­
level,
the
ratio
of
distributions
are
similar
among
the
four
approaches.
The
EPA
approach
is
in
general
agreement
with
the
other
approaches
at
the
smaller
ratios
(
ratio
<
0.7).
As
the
cumulative
percentage
approaches
a
ratio
of
1.0,
EPA's
approach
is
shown
to
have
a
larger
number
of
owner/
operators
in
this
range
than
the
other
approaches.
The
number
of
owner/
operators
with
zero
allocations
is
similar
among
the
four
approaches.
7
Base
case
distributions
of
the
ratios
are
displayed
in
Figures
7
­
10.
Examination
of
the
figures
provides
the
following
findings:

°
The
patterns
for
the
base
case
are
similar
to
those
for
the
CAIR
control
case.
The
four
distributions
at
the
owner­
level
are
generally
distinct.
Again,
EPA
has
a
larger
number
of
owner/
operators
with
zero
allocations.
Figures
11
and
12
display
the
distributions
after
those
owners/
operators
with
a
zero
allocation
for
any
approach
are
eliminated
from
the
data.
As
in
the
CAIR
control
case,
the
elimination
of
sources
in
which
any
of
the
four
approaches
resulted
in
a
zero
allocation
dramatically
changes
the
distribution
shape
and
indicates
that
the
four
approaches
have
similar
distributions.

°
At
the
parent­
level,
the
distributions
among
the
four
approaches
are
very
close
in
the
range
of
0
<=
ratio
<=
0.7.
As
the
distribution
approaches
1.0,
EPA's
approach
incorporates
a
larger
number
of
parents
than
the
other
approaches.
This
effect
extends
to
a
ratio
of
about
1.2.
One
way
of
visualizing
this
effect
is
to
notice
that
the
EPA
curve
is
steeper
in
this
range.
Also,
in
this
range,
the
EPA
approach
separates
from
the
other
approaches,
indicating
a
larger
percentage
of
parents
associated
with
any
given
ratio
in
the
range.

Tables
1
­
4
present
the
calculations
of
percent
difference
in
allocations
for
owner/
operators
and
parents
in
the
years
2010
­
2015.
Results
using
the
base
case
and
CAIR
control
case
are
similar,
therefore
only
the
CAIR
control
case
is
presented.
For
each
owner
or
parent,
the
allocation
associated
with
each
of
the
four
approaches
is
shown.
In
addition,
the
percent
difference
from
the
mean
allocation
for
each
of
the
four
approaches
is
displayed.
At
the
bottom
of
the
table,
the
average
percent
difference
and
the
number
of
positive
percent
differences
is
indicated
for
each
of
the
four
approaches.
Examination
of
the
tables
results
in
the
following
findings:

°
Table
1
indicates
that
the
average
percent
difference
for
the
EPA
approach
(
8.8%)
is
slightly
larger
than
the
other
approaches
at
the
owner­
level
in
2010.
However,
in
2015
(
Table
2)
the
EPA
approach
has
an
average
percent
difference
near
zero
(
1.07%).
In
both
2010
(
Table
1)
and
2015
(
Table
2),
the
percent
of
positive
values
associated
with
the
EPA
approach
is
near
50%
(
44.8%
and
45.1%,
respectively).
The
heat
input
and
heat
input
&
fuel
factor
are
shown
to
have
average
percent
differences
near
zero
in
2010
and
2015
(
2.32%
and
­
2.58%,
respectively),
however,
the
number
of
positive
values
in
these
years
are
distant
from
the
ideal
50%
value
(
17.8%
and
75.9%,
respectively).
The
statistics
for
the
four
approaches
in
2015
(
Table
2)
at
the
owner­
level
indicate
that
all
of
the
approaches
are
very
similar.

°
Table
3
and
4
indicate
relatively
good
agreement
among
all
four
approaches
at
the
parent­
level
of
aggregation.
The
average
percent
difference
associated
with
the
EPA
allocation
approach
is
larger
than
the
other
approaches
in
both
2010
and
2015
(
11.1%
and
12.5%,
respectively).
However,
the
percent
of
positive
values
is
8
near
the
ideal
50%
value
in
both
years
(
51.8%
and
52.8%).
The
heat
input
&
fuel
factor,
coal
type
on
average
has
allocations
that
are
less
than
the
other
approaches
in
both
2010
and
2015
(­
13.3%
and
­
12.8%,
respectively).
The
heat
input
and
heat
input
&
fuel
factor
approaches
have
average
percent
differences
near
zero
in
both
2010
and
2015.

Results:
State
Budget
Analyses
Figures
13
and
14
present
cumulative
distributions
of
State
coverage
ratios
for
2010
and
2015,
respectively.
Examination
of
the
figures
indicates
that
the
EPA
distribution
overlaps
and
is
similar
to
the
distributions
associated
with
the
other
approaches.
Effectively,
the
distributions
associated
with
the
four
approaches
are
indistinguishable.

Figure
15
presents
cumulative
distributions
for
EPA
and
seven
alternative
approaches
based
on
the
percent
of
region­
wide
budgets
associated
with
twenty­
five
CAIR
States.
Data
used
to
generate
Figure
15
are
shown
in
Table
5.
Again,
the
distributions
are
similar.

Conclusions
The
objective
of
this
analysis
was
to
compare
allocations
and
State
budgets
generated
using
EPA
approaches
to
alternative
approaches.
An
evaluation
of
the
ratio
of
allowance
allocations
to
emissions
at
the
parent­
and
owner­
level
of
aggregation
generally
showed
that
the
approaches
perform
similarly.
At
the
owner­
level,
the
EPA
approach
results
in
a
distribution
of
ratios
that
is
similar
to
the
heat
input
with
fuel
factors
distribution,
but
is
dissimilar
to
the
distributions
associated
with
the
other
approaches.
Examination
of
the
data
indicated
that
the
distributions
were
sensitive
to
the
number
of
sources
with
zero
allocations
(
and
therefore
a
ratio
of
zero
allowances
to
emissions).
Companies
may
have
zero
allocations
because
the
units
they
operate
commenced
operations
after
1990.
This
is
true
for
both
2010
and
2015,
and
with
base
case
and
control
case
emissions.
The
vast
majority
of
these
companies
are
primarily
gas­
fired
facilities,
which
have
little
or
no
emissions.
For
example,
about
94%
of
the
64
companies
with
a
ratio
of
zero
allowances
to
emissions
were
gas­
fired
for
the
2010
CAIR
control
case.
This
is
true
for
at
least
90%
of
companies
for
other
years
and
cases,
as
well.
Since
these
units
have
negligible
SO2
emissions,
receiving
no
allowances
will
not
significantly
impact
the
operating
companies
(
see
docket
EPA­
HQ­
OAR­
2003­
0053,
`
SO2
State
Budget
Analysis',
for
related
data).
When
the
distributions
are
re­
evaluated
after
eliminating
owners/
operators
where
any
of
the
approaches
resulted
in
a
zero
allocation,
the
EPA
approach
appears
to
be
very
similar
to
the
other
approaches.

An
analysis
of
the
parent­
level
distributions
indicates
that
the
four
approaches
are
very
similar
across
all
sources.
9
Examination
of
percent
differences
based
on
allocations,
including
the
percent
of
positive
values,
indicates
that
the
four
approaches
perform
similarly.

The
EPA
approach
is
shown
to
have
a
higher
percentage
of
owner/
operators
and
parents
with
ratios
in
the
range
between
0.7
and
1.0.

Examination
of
both
State
coverage
ratios
and
the
distribution
of
percent
of
region­
wide
budgets
indicates
that
the
four
approaches
have
very
similar
distributions.

For
any
single
parent,
owner,
or
State,
the
four
approaches
can
provide
very
different
allocations.
However,
when
the
populations
of
interest
are
evaluated,
the
approaches
have
similar
characteristics.
10
Method:
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Cumulative
Percent
0
10
20
30
40
50
60
70
80
90
100
Ratio:
SO2
Allocation
to
CAIR
Control
Case
Emissions
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Method:
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Cumulative
Percent
0
10
20
30
40
50
60
70
80
90
100
Ratio:
SO2
Allocation
to
CAIR
Control
Case
Emissions
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Figure
1.
Ratio
of
SO2
Allowances
to
CAIR
Control
Case
Emissions
in
2010
for
234
Company
Owner/
Operators
under
EPA's
CAIR
Approach
and
Alternatives*

Figure
2.
Ratio
of
SO2
Allowances
to
CAIR
Control
Case
Emissions
in
2015
for
230
Company
Owner/
Operators
under
EPA's
CAIR
Approach
and
Alternatives*
11
Method:
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Cumulative
Percent
0
10
20
30
40
50
60
70
80
90
100
Ratio:
SO2
Allocation
to
CAIR
Control
Case
Emissions
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Method:
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Cumulative
Percent
0
10
20
30
40
50
60
70
80
90
100
Ratio:
SO2
Allocation
to
CAIR
Control
Case
Emissions
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Figure
3.
Ratio
of
SO2
Allowances
to
CAIR
Control
Case
Emissions
in
2010
for
111
Parent
Companies
under
EPA's
CAIR
Approach
and
Alternatives*

Figure
4.
Ratio
of
SO2
Allowances
to
CAIR
Control
Case
Emissions
in
2015
for
109
Parent
Companies
under
EPA's
CAIR
Approach
and
Alternatives*
12
Method:
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Cumulative
Percent
0
10
20
30
40
50
60
70
80
90
100
Ratio:
SO2
Allocation
to
CAIR
Control
Case
Emissions
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Method:
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Cumulative
Percent
0
10
20
30
40
50
60
70
80
90
100
Ratio:
SO2
Allocation
to
CAIR
Control
Case
Emissions
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Figure
5.
Ratio
of
SO2
Allowances
to
CAIR
Control
Case
Emissions
in
2010.
Company
Owner/
Operators
with
Zero
Allocations
Removed
From
Data*

Figure
6.
Ratio
of
SO2
Allowances
to
CAIR
Control
Case
Emissions
in
2015.
Company
Owner/
Operators
with
Zero
Allocations
Removed
From
Data*
13
Method:
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Cumulative
Percent
0
10
20
30
40
50
60
70
80
90
100
Ratio:
SO2
Allocation
to
Base
Case
Emissions
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Method:
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Cumulative
Percent
0
10
20
30
40
50
60
70
80
90
100
Ratio:
SO2
Allocation
to
Base
Case
Emissions
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Figure
7.
Ratio
of
SO2
Allowances
to
CAIR
Base
Case
Emissions
in
2010
for
234
Company
Owner/
Operators
under
EPA's
CAIR
Approach
and
Alternatives*

Figure
8.
Ratio
of
SO2
Allowances
to
CAIR
Base
Case
Emissions
in
2015
for
236
Company
Owner/
Operators
under
EPA's
CAIR
Approach
and
Alternatives*
14
Method:
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Cumulative
Percent
0
10
20
30
40
50
60
70
80
90
100
Ratio:
SO2
Allocation
to
Base
Case
Emissions
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Method:
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Cumulative
Percent
0
10
20
30
40
50
60
70
80
90
100
Ratio:
SO2
Allocation
to
Base
Case
Emissions
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Figure
9.
Ratio
of
SO2
Allowances
to
CAIR
Base
Case
Emissions
in
2010
for
113
Parent
Companies
under
EPA's
CAIR
Approach
and
Alternatives*

Figure
10.
Ratio
of
SO2
Allowances
to
CAIR
Base
Case
Emissions
in
2015
for
111
Parent
Companies
under
EPA's
CAIR
Approach
and
Alternatives*
15
Method:
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Cumulative
Percent
0
10
20
30
40
50
60
70
80
90
100
Ratio:
SO2
Allocation
to
Base
Case
Emissions
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Method:
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Cumulative
Percent
0
10
20
30
40
50
60
70
80
90
100
Ratio:
SO2
Allocation
to
Base
Case
Emissions
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Figure
11.
Ratio
of
SO2
Allowances
to
Base
Case
Emissions
in
2010.
Company
Owner/
Operators
with
Zero
Allocations
Removed
From
Data*

Figure
12.
Ratio
of
SO2
Allowances
to
Base
Case
Emissions
in
2015.
Company
Owner/
Operators
with
Zero
Allocations
Removed
From
Data*
16
Method:
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Cumulative
Percent
0
10
20
30
40
50
60
70
80
90
100
State
Coverage
Ratio
0.0
0.5
1.0
1.5
2.0
2.5
Method:
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Cumulative
Percent
0
10
20
30
40
50
60
70
80
90
100
State
Coverage
Ratio
0.0
0.5
1.0
1.5
2.0
2.5
*
Note:
Ratios
greater
than
4.0
are
not
shown
on
the
graphic.
Therefore,
the
cumulative
distributions
may
not
reach
100%
within
the
range
of
the
displayed
graphic.
Greater
than
85%
of
the
companies
with
ratios
greater
than
4.0
are
projected
to
emit
less
than
100
tons
of
SO2
under
the
both
the
CAIR
Control
Case
and
the
Base
Case.

Figure
13.
State
Coverage
Ratios
in
2010
for
23
CAIR
States
under
EPA's
CAIR
Approach
and
Alternatives
17
Figure
14.
State
Coverage
Ratios
in
2015
for
23
CAIR
States
under
EPA's
CAIR
Approach
and
Alternatives
18
Method:
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Average
Heat
Input
Coal
+
Oil
Average
Emissions
Average
Output
All
Average
Output
Fossil
Cumulative
Percent
0
10
20
30
40
50
60
70
80
90
100
State
Percentage
of
Regionwide
Budget
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Figure
15.
Percent
of
Region­
wide
Budget
for
24
CAIR
States
under
EPA's
CAIR
Approach
and
Alternatives
19
Table
1.
2010
Owner­
Level
Company
Allocations
Allocations
to
2010
Company
Owner/
Operators
Difference
from
Mean
Owner/
Operator
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
AEP
Texas
Central
Company
7,525
16,142
9,683
13,275
­
35.44%
38.48%
­
16.93%
13.89%

AEP
Texas
North
Company
362
4,386
498
1,885
­
79.69%
146.04%
­
72.06%
5.72%

AES
Beaver
Valley
1,219
2,446
3,115
4,156
­
55.41%
­
10.53%
13.94%
52.01%

AES
Cayuga
LLC
5,080
4,173
5,286
5,052
3.72%
­
14.80%
7.93%
3.15%

AES
Greenidge
2,577
2,027
2,568
2,382
7.90%
­
15.13%
7.52%
­
0.28%

AES
Somerset
LLC
6,956
8,426
10,675
12,405
­
27.66%
­
12.37%
11.02%
29.01%

AES
Westover
LLC
2,434
1,728
2,189
1,872
18.40%
­
15.94%
6.48%
­
8.94%

AES
WR
Ltd
Partnership
899
2,008
2,478
3,374
­
58.94%
­
8.30%
13.16%
54.08%

Alabama
Electric
Coop
Inc
7,534
8,634
9,674
10,754
­
17.65%
­
5.63%
5.74%
17.54%

Alabama
Power
Co
111,840
109,468
129,297
134,325
­
7.75%
­
9.70%
6.65%
10.80%

Alcoa
Generating
Corp
5,264
10,476
12,970
17,276
­
54.21%
­
8.88%
12.82%
50.27%

Allegheny
Energy
Supply
Co
LLC
100,447
76,148
94,092
83,874
13.32%
­
14.09%
6.15%
­
5.38%

Ameren
Energy
Generating
Co
46,968
37,622
45,413
41,779
9.37%
­
12.40%
5.75%
­
2.72%

American
Bituminous
Power
LP
717
1,448
1,783
2,382
­
54.67%
­
8.50%
12.67%
50.50%

Ames
City
of
1,120
981
1,207
1,190
­
0.39%
­
12.75%
7.34%
5.80%

Appalachian
Power
Co
88,571
66,508
81,578
71,893
14.82%
­
13.78%
5.76%
­
6.80%

Aquila,
Inc.
4,730
7,200
8,437
10,496
­
38.70%
­
6.68%
9.35%
36.03%

Associated
Electric
Coop
Inc
28,196
30,442
36,295
39,743
­
16.26%
­
9.58%
7.80%
18.04%

Austin
City
of
(
MN)
528
313
388
270
40.93%
­
16.46%
3.56%
­
28.02%

Austin
Energy
258
5,244
7
1,585
­
85.45%
195.67%
­
99.61%
­
10.61%

Birchwood
Power
Partners
LP
776
2,393
2,874
4,112
­
69.44%
­
5.74%
13.20%
61.98%

Black
River
Power
LLC
198
845
1,070
1,576
­
78.56%
­
8.38%
16.01%
70.93%

Brazos
Electric
Power
Coop
Inc
1,024
2,825
4
264
­
0.52%
174.45%
­
99.61%
­
74.32%

Cambria
CoGen
Co
748
1,501
1,911
2,550
­
55.42%
­
10.52%
13.93%
52.01%

Cardinal
Operating
Co
24,410
16,151
19,986
15,758
27.96%
­
15.33%
4.77%
­
17.39%

Carolina
Power
&
Light
Co
65,479
57,348
67,278
65,167
2.60%
­
10.14%
5.42%
2.11%

Cedar
Falls
City
of
278
122
149
54
84.41%
­
19.07%
­
1.16%
­
64.18%

CenterPoint
Energy
Houston
Electric,
LLC
53,249
86,097
67,645
83,393
­
26.65%
18.60%
­
6.82%
14.87%

Central
Electric
Power
Coop
2,733
702
873
­
424
181.46%
­
27.70%
­
10.09%
­
143.67%

Central
Iowa
Power
Coop
2,792
515
582
­
914
275.35%
­
30.76%
­
21.76%
­
222.83%

Central
Power
&
Lime
Inc
877
1,657
2,144
2,826
­
53.24%
­
11.68%
14.28%
50.64%

Cincinnati
Gas
&
Electric
Co
47,307
51,692
62,995
69,686
­
18.32%
­
10.75%
8.76%
20.31%

CLECO
Power
LLC
21,143
22,494
18,222
17,699
6.30%
13.10%
­
8.38%
­
11.01%

Cleveland
Electric
Illuminating
Co
27,454
14,137
17,494
9,735
59.57%
­
17.83%
1.68%
­
43.42%

Cogentrix
of
Richmond
Inc
983
3,241
3,894
5,617
­
71.39%
­
5.61%
13.40%
63.59%

Cogentrix
of
Rocky
Mount
Inc
558
1,800
2,242
3,218
­
71.47%
­
7.90%
14.72%
64.64%

Colmac
Clarion
Inc
264
537
684
915
­
56.04%
­
10.50%
14.00%
52.54%

Columbia
City
of
2,334
173
209
­
1,220
523.93%
­
53.75%
­
44.13%
­
426.04%

Columbus
Southern
Power
Co
23,556
18,225
22,554
20,443
11.14%
­
14.01%
6.41%
­
3.55%

Constellation
Power
Source
Gen
25,002
27,397
31,581
34,572
­
15.64%
­
7.56%
6.56%
16.65%
20
Table
1.
2010
Owner­
Level
Company
Allocations
Allocations
to
2010
Company
Owner/
Operators
Difference
from
Mean
Owner/
Operator
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Consumers
Energy
Co
47,623
39,280
45,748
42,342
8.86%
­
10.21%
4.57%
­
3.21%

Corn
Belt
Power
Coop
190
97
120
66
60.79%
­
17.91%
1.55%
­
44.43%

Dairyland
Power
Coop
9,179
9,167
11,339
12,055
­
12.04%
­
12.15%
8.66%
15.52%

Dayton
Power
&
Light
Co
48,054
35,034
43,085
37,089
17.73%
­
14.16%
5.56%
­
9.13%

Detroit
Edison
Co
105,695
79,349
94,568
82,077
16.89%
­
12.25%
4.58%
­
9.23%

Dominion
Energy
Services
Co
14,313
10,796
13,534
12,102
12.82%
­
14.90%
6.68%
­
4.61%

Dominion
Virginia
Power
71,177
78,603
85,994
93,408
­
13.51%
­
4.49%
4.49%
13.50%

Duke
Energy
Corp
71,382
73,583
90,974
98,238
­
14.56%
­
11.92%
8.89%
17.59%

Dynegy
Midwest
Generation
Inc
45,326
33,507
41,440
36,205
15.87%
­
14.35%
5.93%
­
7.45%

Dynegy
Northeast
Gen
Inc
19,270
11,068
7,773
1,207
96.04%
12.60%
­
20.92%
­
87.72%

E
S
Joslin
LP
105
1,017
1
270
­
69.86%
191.96%
­
99.71%
­
22.39%

East
Kentucky
Power
Coop
Inc
19,695
17,220
20,776
20,311
1.00%
­
11.69%
6.54%
4.16%

Ebensburg
Power
Co
562
968
1,233
1,592
­
48.36%
­
11.09%
13.25%
46.20%

Edison
Mission
30,454
20,999
26,739
22,349
21.16%
­
16.46%
6.38%
­
11.09%

Electric
Energy
Inc
14,520
15,673
19,648
21,742
­
18.86%
­
12.42%
9.79%
21.49%

Empire
District
Electric
Company
4,897
4,405
2,858
2,014
38.19%
24.31%
­
19.35%
­
43.16%

Entergy
Gulf
States
Inc
11,186
45,840
9,163
20,040
­
48.11%
112.64%
­
57.49%
­
7.04%

Exelon
Generation
Co
LLC
8,243
19,308
10,319
14,699
­
37.28%
46.91%
­
21.48%
11.85%

Florida
Power
&
Light
Co
59,086
85,708
21,426
17,747
28.47%
86.36%
­
53.41%
­
61.41%

Florida
Power
Corp
58,664
48,503
38,998
29,056
33.92%
10.72%
­
10.97%
­
33.67%

Gainesville
Regional
Utilities
4,234
3,581
3,220
2,664
23.63%
4.56%
­
5.98%
­
22.21%

Garland
City
of
108
2,476
4
759
­
87.09%
195.94%
­
99.52%
­
9.32%

Georgia
Power
Co
201,120
133,210
164,824
130,089
27.85%
­
15.32%
4.78%
­
17.30%

Gilberton
Power
Co
835
1,429
1,820
2,346
­
48.04%
­
11.11%
13.21%
45.93%

Grand
Haven
City
of
744
641
795
778
0.62%
­
13.31%
7.52%
5.17%

Gulf
Power
Co
22,014
17,581
19,155
16,724
16.67%
­
6.82%
1.52%
­
11.36%

Hamilton
City
of
581
518
641
640
­
2.35%
­
12.94%
7.73%
7.56%

Henderson
City
Utility
Comm
406
66
82
­
139
291.64%
­
36.33%
­
20.90%
­
234.41%

Holland
City
of
824
482
444
203
68.74%
­
1.30%
­
9.08%
­
58.36%

Hoosier
Energy
R
E
C
Inc
18,533
17,557
21,596
22,292
­
7.31%
­
12.19%
8.01%
11.49%

Independence
City
of
2,339
294
365
­
975
362.41%
­
41.88%
­
27.84%
­
292.69%

Indiana
Michigan
Power
Co
45,648
41,151
50,948
51,216
­
3.37%
­
12.89%
7.85%
8.41%

Indiana­
Kentucky
Electric
Corp
25,288
14,609
18,087
12,127
44.27%
­
16.65%
3.19%
­
30.81%

Indianapolis
Power
&
Light
Co
35,996
33,089
40,621
41,194
­
4.58%
­
12.29%
7.68%
9.19%

Indiantown
Cogeneration
LP
1,193
3,659
4,734
6,736
­
70.76%
­
10.33%
16.01%
65.08%

Interstate
Power
and
Light
Co
22,966
24,559
29,925
32,776
­
16.66%
­
10.88%
8.60%
18.94%

James
River
Cogeneration
Co
753
1,321
1,586
2,053
­
47.27%
­
7.51%
11.04%
43.74%

Jamestown
City
of
1,522
531
598
­
40
133.20%
­
18.64%
­
8.38%
­
106.18%

JEA
21,444
27,980
28,386
32,879
­
22.51%
1.11%
2.58%
18.81%

Kansas
City
Power
&
Light
Co
34,564
20,670
24,464
16,466
43.77%
­
14.02%
1.76%
­
31.51%

Kentucky
Power
Co
12,512
12,045
14,924
15,572
­
9.09%
­
12.48%
8.43%
13.14%
21
Table
1.
2010
Owner­
Level
Company
Allocations
Allocations
to
2010
Company
Owner/
Operators
Difference
from
Mean
Owner/
Operator
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Kentucky
Utilities
Co
38,767
34,627
42,200
41,964
­
1.58%
­
12.09%
7.13%
6.54%

KeySpan
Generation
LLC
26,514
22,819
6,627
­
1,234
93.79%
66.79%
­
51.56%
­
109.02%

Lakeland
City
of
6,431
7,634
6,740
7,244
­
8.29%
8.87%
­
3.88%
3.30%

Lansing
City
of
8,710
5,237
6,493
4,596
39.16%
­
16.33%
3.74%
­
26.57%

LG&
E
Power
Services
894
2,830
3,526
5,049
­
70.93%
­
7.96%
14.68%
64.21%

Lon
C
Hill,
LP
172
2,715
4
796
­
81.34%
194.58%
­
99.57%
­
13.67%

Louisiana
Generating
LLC
21,321
23,536
30,127
33,801
­
21.60%
­
13.46%
10.78%
24.28%

Louisville
Gas
&
Electric
Co
31,190
30,880
37,710
39,780
­
10.60%
­
11.49%
8.08%
14.02%

Lower
Colorado
River
Authority
21,360
27,414
26,613
30,382
­
19.22%
3.67%
0.65%
14.90%

Madison
Gas
&
Electric
Co
546
1,296
1,315
1,821
­
56.13%
4.13%
5.66%
46.34%

Manitowoc
Public
Utilities
862
628
778
672
17.28%
­
14.56%
5.85%
­
8.57%

Marquette
City
of
251
659
817
1,142
­
65.00%
­
8.11%
13.92%
59.19%

Michigan
South
Central
Pwr
Agy
907
765
948
914
2.65%
­
13.42%
7.29%
3.48%

MidAmerican
Energy
Co
32,911
40,437
49,452
57,474
­
26.98%
­
10.28%
9.73%
27.53%

Midwest
Generations
EME
LLC
57,288
58,103
66,137
69,358
­
8.66%
­
7.36%
5.45%
10.58%

Minnesota
Power
Inc
11,580
16,846
20,234
24,874
­
37.01%
­
8.36%
10.07%
35.31%

Mirant
Chalk
Point
LLC
15,249
12,659
10,760
8,400
29.59%
7.58%
­
8.56%
­
28.61%

Mirant
Mid­
Atlantic
LLC
26,285
17,912
21,716
17,402
26.20%
­
14.00%
4.26%
­
16.45%

Mirant
New
York
Inc
9,148
8,191
6,190
4,885
28.78%
15.31%
­
12.86%
­
31.23%

Mirant
Potomac
River
LLC
6,024
5,085
6,109
5,824
4.57%
­
11.73%
6.05%
1.11%

Mississippi
Power
Co
23,995
25,286
23,361
23,580
­
0.25%
5.12%
­
2.89%
­
1.98%

Monongahela
Power
Co
8,207
6,816
8,396
7,995
4.50%
­
13.21%
6.91%
1.80%

Morgantown
Energy
Associates
636
1,041
1,283
1,634
­
44.66%
­
9.35%
11.72%
42.29%

Muscatine
City
of
1,697
3,209
3,948
5,202
­
51.71%
­
8.68%
12.35%
48.04%

Northampton
Generating
Co
LP
604
1,438
1,831
2,518
­
62.23%
­
10.00%
14.60%
57.62%

Northeastern
Power
Co
557
1,272
1,620
2,213
­
60.65%
­
10.13%
14.45%
56.33%

Northern
Indiana
Pub
Serv
Co
25,352
33,752
41,011
49,031
­
32.01%
­
9.48%
9.99%
31.50%

Northern
States
Power
Co
35,221
48,441
58,587
70,782
­
33.87%
­
9.04%
10.01%
32.91%

NRG
Dunkirk
Operations
Inc
8,650
6,107
7,736
6,584
19.00%
­
15.99%
6.42%
­
9.43%

NRG
Huntley
Operations
Inc
10,847
6,492
8,225
5,899
37.90%
­
17.47%
4.57%
­
25.00%

Nueces
Bay
WLE,
LP
273
3,683
5
1,052
­
78.22%
193.86%
­
99.60%
­
16.04%

Ohio
Edison
Co
48,259
29,758
35,929
25,652
38.28%
­
14.73%
2.95%
­
26.50%

Ohio
Power
Co
86,379
63,892
78,941
68,966
15.88%
­
14.29%
5.90%
­
7.48%

Ohio
Valley
Electric
Corp
19,610
12,411
15,358
11,541
33.13%
­
15.74%
4.26%
­
21.65%

Orion
Power
Holdings
Inc
19,804
15,576
18,688
16,907
11.61%
­
12.22%
5.32%
­
4.72%

Orion
Power
Holdings­
Newcastle
5,645
3,343
4,257
3,027
38.77%
­
17.82%
4.65%
­
25.59%

Orion
Power
Midwest
LP
8,460
5,898
7,510
6,339
19.97%
­
16.36%
6.50%
­
10.10%

Orlando
Utilities
Comm
5,977
10,573
13,362
17,356
­
49.42%
­
10.53%
13.08%
46.87%

Otter
Tail
Power
Company
15,285
1,734
2,147
­
6,749
392.40%
­
44.14%
­
30.83%
­
317.43%

Owensboro
City
of
4,517
5,774
7,153
8,451
­
30.23%
­
10.81%
10.49%
30.54%

Panther
Creek
Partners
817
1,427
1,817
2,354
­
49.05%
­
11.02%
13.30%
46.77%
22
Table
1.
2010
Owner­
Level
Company
Allocations
Allocations
to
2010
Company
Owner/
Operators
Difference
from
Mean
Owner/
Operator
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Pella
City
of
882
272
333
­
53
146.08%
­
24.11%
­
7.09%
­
114.88%

Pennsylvania
Power
Co
20,666
24,844
31,634
36,683
­
27.38%
­
12.70%
11.17%
28.91%

Power
Authority
of
State
of
NY
3,225
7,613
1,906
2,929
­
17.69%
94.30%
­
51.36%
­
25.25%

PPL
Brunner
Island
LLC
24,340
13,102
16,683
10,385
50.92%
­
18.76%
3.44%
­
35.61%

PPL
Martins
Creek
LLC
18,179
5,374
4,009
­
4,983
222.05%
­
4.80%
­
28.98%
­
188.27%

PPL
Montour
LLC
24,370
14,666
18,674
13,541
36.81%
­
17.67%
4.84%
­
23.98%

PSI
Energy
Inc
71,955
64,059
76,914
75,935
­
0.36%
­
11.29%
6.51%
5.15%

Public
Service
Co
of
Oklahoma
22,012
8,068
10,923
2,579
102.03%
­
25.95%
0.25%
­
76.33%

R
J
Reynolds
Tobacco
Co
2,901
1,411
1,758
880
66.98%
­
18.80%
1.17%
­
49.35%

Reliant
Energy
Mid­
Atlantic
PH
79,188
53,327
67,686
55,232
24.01%
­
16.49%
5.99%
­
13.51%

Richmond
City
of
4,474
1,318
1,632
­
367
153.60%
­
25.29%
­
7.49%
­
120.82%

Rochester
Gas
&
Electric
Corp
4,433
2,930
3,712
2,971
26.25%
­
16.56%
5.71%
­
15.40%

Rochester
Public
Utilities
1,569
404
483
­
267
186.75%
­
26.17%
­
11.73%
­
148.86%

San
Antonio
Public
Service
Bd
21,754
29,172
24,038
27,272
­
14.89%
14.14%
­
5.95%
6.70%

San
Miguel
Electric
Coop
Inc
8,326
5,863
7,937
6,986
14.40%
­
19.44%
9.05%
­
4.01%

Savannah
Electric
&
Power
Co
5,986
4,994
5,095
4,467
16.56%
­
2.76%
­
0.79%
­
13.01%

Schuylkill
Energy
Resource
Inc
1,797
1,683
2,142
2,219
­
8.32%
­
14.14%
9.27%
13.19%

Scrubgrass
Generating
Co
LP
822
1,477
1,881
2,453
­
50.45%
­
10.92%
13.45%
47.92%

Seminole
Electric
Coop
Inc
18,420
18,090
21,437
22,333
­
8.22%
­
9.87%
6.81%
11.27%

Sempra
Energy
Resources
2,817
4,032
5,458
6,743
­
40.85%
­
15.34%
14.60%
41.59%

Sikeston
City
of
3,401
3,444
4,282
4,590
­
13.44%
­
12.35%
8.98%
16.82%

South
Carolina
Electric&
Gas
Co
22,813
22,460
26,640
27,798
­
8.48%
­
9.90%
6.87%
11.51%

South
Carolina
Genertg
Co
Inc
7,924
7,624
9,654
10,131
­
10.29%
­
13.69%
9.29%
14.69%

South
Carolina
Pub
Serv
Auth
21,577
34,920
41,801
52,990
­
42.95%
­
7.67%
10.52%
40.10%

South
Mississippi
El
Pwr
Assn
5,106
5,059
5,080
5,056
0.61%
­
0.32%
0.10%
­
0.38%

Southern
Illinois
Power
Coop
4,160
3,082
3,864
3,406
14.66%
­
15.05%
6.50%
­
6.12%

Southern
Indiana
Gas
&
Elec
Co
10,234
11,446
13,857
15,469
­
19.74%
­
10.24%
8.67%
21.31%

Southwestern
Electric
Power
Co
37,276
34,927
38,055
37,532
0.89%
­
5.47%
3.00%
1.58%

Southwestern
Public
Service
Co
26,681
35,807
38,335
45,262
­
26.94%
­
1.96%
4.97%
23.93%

Springfield
City
of
8,965
10,052
12,324
13,806
­
20.57%
­
10.94%
9.19%
22.32%

State
Line
Energy
LLC
4,742
5,295
6,556
7,345
­
20.76%
­
11.52%
9.55%
22.73%

Sunbury
Generation
LLC
8,291
4,054
5,162
2,707
64.07%
­
19.78%
2.15%
­
46.44%

Tallahassee
City
of
3,030
3,742
5
­
766
101.63%
149.01%
­
99.67%
­
150.97%

Tampa
Electric
Co
41,972
30,401
37,936
32,734
17.37%
­
14.99%
6.08%
­
8.46%

Tennessee
Valley
Authority
208,137
185,217
226,027
224,350
­
1.33%
­
12.19%
7.16%
6.36%

TES
Filer
City
Station
LP
253
961
1,191
1,740
­
75.58%
­
7.25%
14.94%
67.89%

Texas
Municipal
Power
Agency
6,952
5,218
7,064
6,523
7.96%
­
18.97%
9.70%
1.30%

TIFD
VIII­
W
Inc
2,500
4,889
1,632
2,139
­
10.39%
75.23%
­
41.51%
­
23.34%

Toledo
Edison
Co
12,059
6,529
7,697
4,400
57.20%
­
14.89%
0.34%
­
42.65%

Trigen­
Syracuse
Energy
Corp
435
1,063
1,347
1,860
­
62.98%
­
9.64%
14.50%
58.12%

TXU
Generation
Co
LP
123,836
124,513
102,722
95,910
10.82%
11.43%
­
8.07%
­
14.17%
23
Table
1.
2010
Owner­
Level
Company
Allocations
Allocations
to
2010
Company
Owner/
Operators
Difference
from
Mean
Owner/
Operator
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
UAE
Mecklenburg
Cogeneration
LP
467
1,503
1,806
2,598
­
70.71%
­
5.67%
13.34%
63.04%

UGI
Development
Co
1,130
655
764
484
49.04%
­
13.61%
0.77%
­
36.21%

Union
Electric
Co
61,989
56,996
70,452
71,609
­
5.01%
­
12.67%
7.95%
9.73%

US
Operating
Services
Co.­
Cedar
Bay
1,271
3,762
4,867
6,896
­
69.73%
­
10.41%
15.91%
64.23%

Vandolah
Power
Co
LLC
0
45
0
15
Victoria
WLE,
LP
168
1,680
2
451
­
70.79%
192.09%
­
99.65%
­
21.65%

Western
Kentucky
Energy
Corp
26,290
24,066
29,817
30,251
­
4.77%
­
12.82%
8.01%
9.58%

Wheelabrator
Environmental
Systems
637
805
1,025
1,210
­
30.68%
­
12.44%
11.49%
31.63%

Whiting
Clean
Energy
Inc
0
778
1
261
Wisconsin
Electric
Power
Co
42,903
42,759
52,168
55,208
­
11.10%
­
11.40%
8.10%
14.40%

Wisconsin
Power
&
Light
Co
28,260
26,701
32,051
32,795
­
5.65%
­
10.85%
7.01%
9.49%

Wisconsin
Public
Service
Corp
10,005
12,851
15,106
17,755
­
28.17%
­
7.74%
8.45%
27.47%

Wyandotte
Municipal
Serv
Comm
547
702
812
952
­
27.38%
­
6.80%
7.80%
26.39%

Average
8.82%
2.32%
­
2.58%
­
8.55%

Percent
Positive
44.83%
17.82%
75.86%
54.02%
24
Table
2.
2015
Owner­
Level
Company
Allocations
Allocations
to
2015
Company
Owner/
Operators
Difference
from
Mean
Owner/
Operator
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
AEP
Texas
Central
Company
5,267
11,299
6,776
7,132
­
30.87%
48.31%
­
11.06%
­
6.39%

AEP
Texas
North
Company
253
3,071
348
478
­
75.61%
196.00%
­
66.46%
­
53.93%
AES
Beaver
Valley
853
1,712
2,180
2,727
­
54.32%
­
8.36%
16.70%
45.98%
AES
Cayuga
LLC
3,556
2,921
3,700
4,826
­
5.19%
­
22.12%
­
1.35%
28.67%
AES
Greenidge
1,804
1,419
1,798
2,345
­
2.04%
­
22.94%
­
2.36%
27.34%
AES
Somerset
LLC
4,870
5,898
7,473
9,746
­
30.40%
­
15.70%
6.81%
39.29%
AES
Westover
LLC
1,704
1,209
1,532
1,998
5.79%
­
24.94%
­
4.89%
24.04%
AES
WR
Ltd
Partnership
629
1,405
1,735
2,129
­
57.32%
­
4.72%
17.66%
44.38%
Alabama
Electric
Coop
Inc
5,274
6,044
6,772
7,561
­
17.76%
­
5.75%
5.60%
17.91%
Alabama
Power
Co
78,288
76,628
90,508
88,644
­
6.26%
­
8.25%
8.37%
6.14%
Alcoa
Generating
Corp
3,684
7,333
9,079
4,455
­
39.98%
19.47%
47.92%
­
27.42%
Allegheny
Energy
Supply
Co
LLC
70,314
53,304
65,864
82,196
3.53%
­
21.52%
­
3.03%
21.02%
Ameren
Energy
Generating
Co
32,878
26,335
31,787
31,931
6.98%
­
14.31%
3.43%
3.90%
American
Bituminous
Power
LP
502
1,013
1,248
1,556
­
53.49%
­
6.19%
15.58%
44.10%
Ames
City
of
784
687
845
405
15.25%
0.99%
24.22%
­
40.46%
Appalachian
Power
Co
62,000
46,555
57,105
71,272
4.67%
­
21.40%
­
3.59%
20.32%
Aquila,
Inc.
3,310
5,041
5,906
2,852
­
22.61%
17.86%
38.08%
­
33.32%
Associated
Electric
Coop
Inc
19,737
21,309
25,407
12,262
0.30%
8.28%
29.11%
­
37.69%
Austin
City
of
(
MN)
369
219
271
339
23.21%
­
26.88%
­
9.52%
13.19%
Austin
Energy
180
3,671
5
63
­
81.63%
274.69%
­
99.49%
­
93.57%
Birchwood
Power
Partners
LP
543
1,675
2,012
2,524
­
67.84%
­
0.80%
19.16%
49.48%
Black
River
Power
LLC
138
591
749
489
­
71.86%
20.16%
52.28%
­
0.58%
Brazos
Electric
Power
Coop
Inc
717
1,978
3
33
5.02%
189.71%
­
99.56%
­
95.17%
Cambria
CoGen
Co
523
1,051
1,338
1,673
­
54.34%
­
8.32%
16.72%
45.94%
Cardinal
Operating
Co
17,086
11,305
13,990
17,432
14.26%
­
24.40%
­
6.44%
16.58%
Carolina
Power
&
Light
Co
45,835
40,143
47,094
58,315
­
4.20%
­
16.10%
­
1.57%
21.88%
Cedar
Falls
City
of
194
85
104
129
51.56%
­
33.59%
­
18.75%
0.78%
CenterPoint
Energy
Houston
Electric,
LLC
37,272
60,270
47,349
26,278
­
12.90%
40.84%
10.65%
­
38.59%

Central
Electric
Power
Coop
1,913
491
611
736
104.00%
­
47.64%
­
34.84%
­
21.51%
Central
Iowa
Power
Coop
1,955
361
407
506
142.18%
­
55.28%
­
49.58%
­
37.32%
Central
Power
&
Lime
Inc
614
1,160
1,501
1,923
­
52.74%
­
10.74%
15.50%
47.98%
Cincinnati
Gas
&
Electric
Co
33,115
36,184
44,096
54,956
­
21.32%
­
14.03%
4.77%
30.57%
CLECO
Power
LLC
14,799
15,746
12,756
7,830
15.77%
23.18%
­
0.21%
­
38.75%
Cleveland
Electric
Illuminating
Co
19,218
9,896
12,246
14,989
36.42%
­
29.75%
­
13.07%
6.40%
Cogentrix
of
Richmond
Inc
688
2,269
2,726
3,419
­
69.77%
­
0.28%
19.80%
50.26%
Cogentrix
of
Rocky
Mount
Inc
390
1,260
1,570
1,942
­
69.76%
­
2.37%
21.65%
50.47%
Colmac
Clarion
Inc
185
376
479
599
­
54.93%
­
8.21%
16.93%
46.22%
Columbia
City
of
1,634
121
146
71
231.44%
­
75.46%
­
70.39%
­
85.60%
Columbus
Southern
Power
Co
16,489
12,757
15,788
19,671
1.93%
­
21.14%
­
2.40%
21.60%
Constellation
Power
Source
Gen
17,500
19,176
22,107
27,060
­
18.46%
­
10.65%
3.01%
26.09%
Consumers
Energy
Co
33,336
27,495
32,024
31,701
7.06%
­
11.70%
2.84%
1.80%
Corn
Belt
Power
Coop
133
68
84
104
36.76%
­
30.08%
­
13.62%
6.94%
Dairyland
Power
Coop
6,425
6,417
7,937
5,915
­
3.72%
­
3.84%
18.93%
­
11.37%
Dayton
Power
&
Light
Co
33,637
24,523
30,159
37,580
6.87%
­
22.09%
­
4.18%
19.40%
Detroit
Edison
Co
73,987
55,547
66,196
50,841
20.03%
­
9.89%
7.39%
­
17.52%
Dominion
Energy
Services
Co
10,019
7,557
9,474
6,604
19.08%
­
10.18%
12.60%
­
21.51%
Dominion
Virginia
Power
49,823
55,024
60,198
75,160
­
17.03%
­
8.37%
0.24%
25.16%
Duke
Energy
Corp
49,967
51,509
63,682
78,818
­
18.08%
­
15.55%
4.41%
29.22%
25
Table
2.
2015
Owner­
Level
Company
Allocations
Allocations
to
2015
Company
Owner/
Operators
Difference
from
Mean
Owner/
Operator
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Dynegy
Midwest
Generation
Inc
31,729
23,456
29,007
35,521
6.02%
­
21.63%
­
3.08%
18.69%
Dynegy
Northeast
Gen
Inc
13,489
7,747
5,441
6,864
60.87%
­
7.61%
­
35.11%
­
18.14%
E
S
Joslin
LP
74
712
1
12
­
62.95%
256.45%
­
99.50%
­
93.99%
East
Kentucky
Power
Coop
Inc
13,787
12,054
14,542
18,137
­
5.76%
­
17.61%
­
0.60%
23.97%
Ebensburg
Power
Co
394
678
863
1,080
­
47.77%
­
10.04%
14.51%
43.30%
Edison
Mission
21,317
14,700
18,717
23,413
9.11%
­
24.76%
­
4.20%
19.84%
Electric
Energy
Inc
10,164
10,971
13,753
6,617
­
2.05%
5.73%
32.54%
­
36.23%
Empire
District
Electric
Company
3,427
3,084
2,001
1,199
41.16%
27.03%
­
17.58%
­
50.61%
Entergy
Gulf
States
Inc
7,830
32,088
6,414
4,345
­
38.20%
153.27%
­
49.37%
­
65.70%
Exelon
Generation
Co
LLC
5,771
13,515
7,224
9,036
­
35.06%
52.08%
­
18.71%
1.68%
Florida
Power
&
Light
Co
41,360
59,995
14,999
17,527
23.57%
79.25%
­
55.19%
­
47.63%
Florida
Power
Corp
41,064
33,951
27,297
34,478
20.08%
­
0.72%
­
20.18%
0.82%
Gainesville
Regional
Utilities
2,963
2,507
2,253
2,897
11.60%
­
5.57%
­
15.14%
9.11%
Georgia
Power
Co
140,781
93,246
115,376
130,230
17.41%
­
22.24%
­
3.78%
8.61%
Gilberton
Power
Co
585
1,000
1,274
613
­
32.62%
15.21%
46.78%
­
29.37%
Grand
Haven
City
of
520
449
556
700
­
6.52%
­
19.28%
­
0.04%
25.84%
Gulf
Power
Co
15,411
12,307
13,409
17,205
5.68%
­
15.61%
­
8.05%
17.98%
Hamilton
City
of
407
363
449
559
­
8.44%
­
18.34%
1.01%
25.76%
Henderson
City
Utility
Comm
284
46
57
71
148.03%
­
59.83%
­
50.22%
­
37.99%
Holland
City
of
577
338
311
392
42.65%
­
16.44%
­
23.11%
­
3.09%
Hoosier
Energy
R
E
C
Inc
12,973
12,291
15,117
18,851
­
12.39%
­
17.00%
2.09%
27.30%
Independence
City
of
1,637
206
256
320
170.69%
­
65.94%
­
57.67%
­
47.09%
Indiana
Michigan
Power
Co
31,953
28,806
35,664
23,838
6.28%
­
4.19%
18.62%
­
20.71%
Indiana­
Kentucky
Electric
Corp
17,702
10,226
12,661
9,613
41.05%
­
18.52%
0.88%
­
23.41%
Indianapolis
Power
&
Light
Co
25,196
23,163
28,435
35,223
­
10.03%
­
17.29%
1.54%
25.78%
Indiantown
Cogeneration
LP
835
2,561
3,314
4,246
­
69.50%
­
6.50%
20.99%
55.01%
Interstate
Power
and
Light
Co
16,073
17,191
20,948
11,530
­
2.21%
4.60%
27.46%
­
29.85%
James
River
Cogeneration
Co
527
924
1,111
536
­
31.94%
19.30%
43.44%
­
30.80%
Jamestown
City
of
1,065
372
419
211
106.10%
­
28.01%
­
18.92%
­
59.17%
JEA
15,010
19,585
19,870
20,345
­
19.74%
4.72%
6.24%
8.78%
Kansas
City
Power
&
Light
Co
24,195
14,469
17,125
8,306
50.99%
­
9.70%
6.87%
­
48.16%
Kentucky
Power
Co
8,759
8,432
10,447
13,027
­
13.84%
­
17.06%
2.76%
28.14%
Kentucky
Utilities
Co
27,136
24,239
29,539
35,950
­
7.12%
­
17.04%
1.11%
23.05%
KeySpan
Generation
LLC
18,561
15,973
4,638
5,478
66.28%
43.10%
­
58.45%
­
50.92%
Lakeland
City
of
4,501
5,344
4,717
5,793
­
11.55%
5.02%
­
7.31%
13.84%
Lansing
City
of
6,097
3,667
4,545
3,986
33.30%
­
19.83%
­
0.63%
­
12.85%
LG&
E
Power
Services
626
1,981
2,469
3,055
­
69.22%
­
2.54%
21.47%
50.30%
Lon
C
Hill,
LP
120
1,900
3
32
­
76.64%
269.83%
­
99.42%
­
93.77%
Louisiana
Generating
LLC
14,925
16,475
21,089
12,777
­
8.53%
0.97%
29.25%
­
21.69%
Louisville
Gas
&
Electric
Co
21,833
21,617
26,396
32,919
­
15.02%
­
15.86%
2.74%
28.13%
Lower
Colorado
River
Authority
14,951
19,190
18,630
10,266
­
5.13%
21.77%
18.22%
­
34.86%
Madison
Gas
&
Electric
Co
382
906
920
1,023
­
52.71%
12.16%
13.90%
26.65%
Manitowoc
Public
Utilities
603
440
545
262
30.38%
­
4.86%
17.84%
­
43.35%
Marquette
City
of
176
461
572
277
­
52.62%
24.09%
53.97%
­
25.44%
Michigan
South
Central
Pwr
Agy
635
535
664
803
­
3.68%
­
18.85%
0.72%
21.81%
MidAmerican
Energy
Co
23,037
28,307
34,617
16,590
­
10.14%
10.41%
35.02%
­
35.29%
Midwest
Generations
EME
LLC
40,103
40,671
46,295
22,323
7.38%
8.90%
23.96%
­
40.23%
Minnesota
Power
Inc
8,106
11,793
14,164
6,841
­
20.73%
15.32%
38.51%
­
33.10%
Mirant
Chalk
Point
LLC
10,674
8,861
7,532
9,093
18.08%
­
1.98%
­
16.68%
0.59%
Mirant
Mid­
Atlantic
LLC
18,400
12,538
15,201
18,657
13.59%
­
22.60%
­
6.16%
15.17%
26
Table
2.
2015
Owner­
Level
Company
Allocations
Allocations
to
2015
Company
Owner/
Operators
Difference
from
Mean
Owner/
Operator
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Mirant
New
York
Inc
6,403
5,733
4,333
5,486
16.66%
4.45%
­
21.06%
­
0.05%
Mirant
Potomac
River
LLC
4,217
3,560
4,276
5,363
­
3.15%
­
18.24%
­
1.79%
23.17%
Mississippi
Power
Co
16,796
17,700
16,353
17,253
­
1.35%
3.96%
­
3.95%
1.34%
Monongahela
Power
Co
5,745
4,771
5,877
7,328
­
3.12%
­
19.55%
­
0.90%
23.57%
Morgantown
Energy
Associates
445
729
898
1,120
­
44.25%
­
8.64%
12.54%
40.36%
Muscatine
City
of
1,188
2,247
2,764
1,324
­
36.83%
19.47%
46.96%
­
29.60%
Northampton
Generating
Co
LP
422
1,007
1,282
617
­
49.23%
21.02%
54.06%
­
25.85%
Northeastern
Power
Co
390
891
1,134
546
­
47.33%
20.37%
53.20%
­
26.24%
Northern
Indiana
Pub
Serv
Co
17,746
23,627
28,708
26,146
­
26.23%
­
1.79%
19.33%
8.68%
Northern
States
Power
Co
24,655
33,907
41,010
19,999
­
17.52%
13.43%
37.19%
­
33.10%
NRG
Dunkirk
Operations
Inc
6,055
4,275
5,415
7,063
6.19%
­
25.03%
­
5.03%
23.87%
NRG
Huntley
Operations
Inc
7,593
4,544
5,757
7,509
19.56%
­
28.45%
­
9.35%
18.24%
Nueces
Bay
WLE,
LP
191
2,578
4
44
­
72.88%
266.06%
­
99.43%
­
93.75%
Ohio
Edison
Co
33,780
20,831
25,149
31,202
21.77%
­
24.91%
­
9.34%
12.48%
Ohio
Power
Co
60,464
44,724
55,259
68,869
5.47%
­
21.99%
­
3.61%
20.13%
Ohio
Valley
Electric
Corp
13,727
8,688
10,751
13,395
17.93%
­
25.36%
­
7.64%
15.07%
Orion
Power
Holdings
Inc
13,864
10,903
13,081
16,329
2.36%
­
19.50%
­
3.42%
20.56%
Orion
Power
Holdings­
Newcastle
3,952
2,340
2,980
3,727
21.61%
­
27.99%
­
8.30%
14.69%
Orion
Power
Midwest
LP
5,922
4,129
5,257
6,576
8.24%
­
24.53%
­
3.91%
20.20%
Orlando
Utilities
Comm
4,184
7,401
9,353
11,986
­
49.17%
­
10.08%
13.63%
45.62%
Otter
Tail
Power
Company
10,701
1,214
1,503
722
202.72%
­
65.66%
­
57.48%
­
79.58%
Owensboro
City
of
3,162
4,041
5,007
6,158
­
31.14%
­
12.00%
9.04%
34.10%
Panther
Creek
Partners
572
999
1,272
612
­
33.79%
15.66%
47.27%
­
29.14%
Pella
City
of
617
190
233
112
114.24%
­
34.03%
­
19.10%
­
61.11%
Pennsylvania
Power
Co
14,466
17,391
22,144
25,568
­
27.28%
­
12.57%
11.32%
28.53%
Power
Authority
of
State
of
NY
2,258
5,329
1,334
1,587
­
14.05%
102.85%
­
49.22%
­
39.59%
PPL
Brunner
Island
LLC
17,038
9,171
11,678
14,607
29.83%
­
30.12%
­
11.01%
11.30%
PPL
Martins
Creek
LLC
12,725
3,762
2,806
3,401
124.29%
­
33.69%
­
50.54%
­
40.05%
PPL
Montour
LLC
17,059
10,266
13,072
16,351
20.24%
­
27.64%
­
7.86%
15.25%
PSI
Energy
Inc
50,368
44,839
53,840
67,151
­
6.81%
­
17.04%
­
0.39%
24.24%
Public
Service
Co
of
Oklahoma
15,408
5,648
7,646
4,177
87.45%
­
31.29%
­
6.98%
­
49.18%
R
J
Reynolds
Tobacco
Co
2,031
988
1,231
1,523
40.73%
­
31.54%
­
14.71%
5.53%
Reliant
Energy
Mid­
Atlantic
PH
55,432
37,329
47,381
58,990
11.35%
­
25.02%
­
4.82%
18.49%
Richmond
City
of
3,131
923
1,142
1,424
89.18%
­
44.23%
­
31.00%
­
13.96%
Rochester
Gas
&
Electric
Corp
3,104
2,051
2,598
3,389
11.43%
­
26.37%
­
6.73%
21.67%
Rochester
Public
Utilities
1,098
283
338
422
105.14%
­
47.13%
­
36.85%
­
21.16%
San
Antonio
Public
Service
Bd
15,228
20,420
16,826
9,322
­
1.43%
32.18%
8.91%
­
39.66%
San
Miguel
Electric
Coop
Inc
5,828
4,104
5,556
3,035
25.85%
­
11.38%
19.98%
­
34.46%
Savannah
Electric
&
Power
Co
4,191
3,496
3,566
4,457
6.71%
­
10.99%
­
9.20%
13.48%
Schuylkill
Energy
Resource
Inc
1,258
1,178
1,500
722
8.03%
1.16%
28.81%
­
38.00%
Scrubgrass
Generating
Co
LP
575
1,034
1,317
1,647
­
49.69%
­
9.56%
15.19%
44.06%
Seminole
Electric
Coop
Inc
12,894
12,663
15,005
18,500
­
12.67%
­
14.24%
1.62%
25.29%
Sempra
Energy
Resources
1,972
2,822
3,821
2,087
­
26.29%
5.48%
42.81%
­
22.00%
Sikeston
City
of
2,381
2,411
2,997
1,445
3.14%
4.44%
29.82%
­
37.41%
South
Carolina
Electric&
Gas
Co
15,969
15,722
18,649
23,395
­
13.37%
­
14.71%
1.17%
26.91%
South
Carolina
Genertg
Co
Inc
5,547
5,337
6,758
8,474
­
15.04%
­
18.26%
3.51%
29.79%
South
Carolina
Pub
Serv
Auth
15,105
24,445
29,262
36,696
­
42.73%
­
7.32%
10.94%
39.12%
South
Mississippi
El
Pwr
Assn
3,574
3,541
3,556
4,848
­
7.88%
­
8.73%
­
8.34%
24.96%
Southern
Illinois
Power
Coop
2,912
2,158
2,705
3,384
4.38%
­
22.65%
­
3.04%
21.30%
Southern
Indiana
Gas
&
Elec
Co
7,164
8,012
9,700
12,097
­
22.49%
­
13.32%
4.94%
30.87%
27
Table
2.
2015
Owner­
Level
Company
Allocations
Allocations
to
2015
Company
Owner/
Operators
Difference
from
Mean
Owner/
Operator
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Southwestern
Electric
Power
Co
26,094
24,447
26,638
14,632
13.69%
6.51%
16.06%
­
36.25%
Southwestern
Public
Service
Co
18,677
25,066
26,834
14,744
­
12.44%
17.51%
25.80%
­
30.88%
Springfield
City
of
6,274
7,036
8,626
7,434
­
14.55%
­
4.17%
17.48%
1.25%
State
Line
Energy
LLC
3,320
3,707
4,589
2,201
­
3.89%
7.32%
32.85%
­
36.28%
Sunbury
Generation
LLC
5,804
2,838
3,613
3,276
49.48%
­
26.91%
­
6.95%
­
15.63%
Tallahassee
City
of
2,121
2,619
4
39
77.38%
119.03%
­
99.67%
­
96.74%
Tampa
Electric
Co
29,380
21,281
26,556
30,462
9.14%
­
20.95%
­
1.35%
13.16%
Tennessee
Valley
Authority
145,695
129,649
158,219
193,448
­
7.05%
­
17.29%
0.94%
23.41%
TES
Filer
City
Station
LP
177
672
834
1,049
­
74.07%
­
1.61%
22.10%
53.58%
Texas
Municipal
Power
Agency
4,866
3,653
4,945
2,701
20.41%
­
9.61%
22.36%
­
33.16%
TIFD
VIII­
W
Inc
1,750
3,422
1,143
1,429
­
9.60%
76.75%
­
40.96%
­
26.19%
Toledo
Edison
Co
8,441
4,570
5,388
2,757
59.60%
­
13.59%
1.87%
­
47.87%
Trigen­
Syracuse
Energy
Corp
305
744
943
473
­
50.53%
20.74%
53.03%
­
23.24%
TXU
Generation
Co
LP
86,685
87,160
71,906
39,836
21.41%
22.08%
0.71%
­
44.20%
UAE
Mecklenburg
Cogeneration
LP
327
1,052
1,264
1,586
­
69.10%
­
0.49%
19.56%
50.02%
UGI
Development
Co
791
459
535
361
47.44%
­
14.45%
­
0.28%
­
32.71%
Union
Electric
Co
43,393
39,896
49,319
27,499
8.41%
­
0.33%
23.22%
­
31.30%
US
Operating
Services
Co.­
Cedar
Bay
890
2,633
3,407
4,365
­
68.49%
­
6.75%
20.66%
54.59%

Victoria
WLE,
LP
118
1,176
2
20
­
64.13%
257.45%
­
99.39%
­
93.92%
Western
Kentucky
Energy
Corp
18,401
16,846
20,871
21,814
­
5.55%
­
13.53%
7.12%
11.96%
Wheelabrator
Environmental
Systems
446
564
718
345
­
13.93%
8.82%
38.54%
­
33.43%

Wisconsin
Electric
Power
Co
30,030
29,933
36,518
25,188
­
1.27%
­
1.59%
20.06%
­
17.19%
Wisconsin
Power
&
Light
Co
19,782
18,691
22,435
10,782
10.38%
4.29%
25.18%
­
39.84%
Wisconsin
Public
Service
Corp
7,003
8,996
10,574
5,085
­
11.52%
13.66%
33.60%
­
35.75%
Wyandotte
Municipal
Serv
Comm
383
492
569
276
­
10.93%
14.42%
32.33%
­
35.81%

Average
1.07%
4.57%
­
0.70%
­
4.94%
Percent
Positive
45.09%
32.37%
53.76%
53.76%
28
Table
3.
2010
Parent
Company
Allocations
Allocations
to
2010
Parent
Companies
Difference
from
Mean
Parent
Company
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
AE
108,654
83,426
102,488
127,896
2.88%
­
21.01%
­
2.96%
21.10%
AEP
393,878
310,508
362,178
377,306
9.12%
­
13.98%
0.34%
4.53%

AES
57,975
57,511
68,187
86,110
­
14.04%
­
14.73%
1.10%
27.67%
ALABAMA
ELECTRIC
COOPERATIVE
7,534
8,634
9,674
10,801
­
17.76%
­
5.75%
5.60%
17.91%
Alcoa
5,264
10,476
12,970
6,364
­
39.97%
19.47%
47.92%
­
27.42%
ALLETE
INC
11,580
16,846
20,234
9,772
­
20.73%
15.32%
38.51%
­
33.11%
Alliant
Energy
51,226
51,752
61,977
31,880
4.10%
5.17%
25.95%
­
35.21%
Ameren
123,596
110,291
135,513
94,354
6.60%
­
4.87%
16.88%
­
18.62%
AMERICAN
CONSUMER
INDUSTRIES
INC
264
537
684
855
­
54.91%
­
8.19%
16.94%
46.17%

AQUILA
INC
4,730
7,203
8,437
4,074
­
22.60%
17.87%
38.06%
­
33.33%
ASSOCIATED
ELECTRIC
COOPERATIVE
INC
28,196
30,442
36,295
17,518
0.30%
8.29%
29.11%
­
37.69%

Austin
City
of
(
MN)
528
313
388
484
23.29%
­
26.91%
­
9.40%
13.02%
Austin
Energy
258
5,244
7
90
­
81.57%
274.64%
­
99.50%
­
93.57%
Austin
Energy
and
Lower
Colorado
River
Authority
21,018
19,651
26,602
14,532
2.77%
­
3.91%
30.08%
­
28.94%

BLACK
RIVER
POWER
LLC
198
845
1,070
698
­
71.86%
20.25%
52.27%
­
0.67%
BOARD
OF
PUBLIC
UTILTIIES
JAMESTOWN
1,522
531
598
301
106.23%
­
28.05%
­
18.97%
­
59.21%

Brazos
Electric
Power
Coop
Inc
1,024
2,825
4
49
4.97%
189.60%
­
99.59%
­
94.98%
Calpine
0
11,703
16
195
Cedar
Falls
City
of
278
121
149
185
51.71%
­
33.97%
­
18.69%
0.95%
CenterPoint
53,249
86,097
67,645
37,543
­
12.90%
40.83%
10.65%
­
38.59%
CENTRAL
ELECTRIC
POWER
COOPERATIVE
2,733
702
873
1,052
103.96%
­
47.61%
­
34.85%
­
21.49%

CENTRAL
IOWA
POWER
COOPERATIVE
2,792
515
582
724
142.10%
­
55.34%
­
49.53%
­
37.22%

Cinergy
119,262
115,751
139,909
174,439
­
13.16%
­
15.72%
1.87%
27.01%
CITY
OF
AMES
1,120
981
1,207
578
15.29%
0.98%
24.24%
­
40.50%
CITY
OF
COLUMBIA,
MO
2,334
173
209
101
231.42%
­
75.43%
­
70.32%
­
85.66%
CITY
OF
GAINESVILLE
4,234
3,581
3,220
4,139
11.61%
­
5.60%
­
15.12%
9.11%
CITY
OF
INDEPENDENCE
2,339
294
365
458
170.72%
­
65.97%
­
57.75%
­
46.99%
CITY
OF
ROCHESTER,
MN
1,569
404
483
603
105.17%
­
47.17%
­
36.84%
­
21.15%
CITY
OF
SIKESTON
3,401
3,444
4,282
2,065
3.12%
4.43%
29.84%
­
37.39%
CLECO
CORPORATION
21,143
22,494
18,222
11,187
15.78%
23.18%
­
0.22%
­
38.74%
CMS
ENERGY
47,623
39,280
45,748
45,287
7.06%
­
11.70%
2.84%
1.80%
Cogentrix
5,533
16,694
20,843
24,637
­
67.31%
­
1.38%
23.14%
45.55%
Conectiv
8,251
72
9
11
295.59%
­
96.55%
­
99.57%
­
99.47%
CONSTELLATION
ENERGY
GROUP
28,319
33,713
35,030
41,573
­
18.29%
­
2.73%
1.07%
19.95%
Corn
Belt
Power
Coop
190
97
120
149
36.69%
­
30.22%
­
13.67%
7.19%
DAIRYLAND
POWER
COOPERATIVE
9,179
9,167
11,339
8,449
­
3.72%
­
3.84%
18.94%
­
11.38%
Delta
Power
Company
877
1,657
2,144
2,747
­
52.74%
­
10.74%
15.50%
47.98%
Dominion
91,334
98,717
109,174
123,833
­
13.64%
­
6.66%
3.22%
17.08%
DPL
INC
48,054
35,034
43,085
53,687
6.87%
­
22.09%
­
4.18%
19.40%
DTE
ENERGY
CO
105,695
79,349
94,568
72,628
20.03%
­
9.89%
7.39%
­
17.52%
Duke
83,314
76,989
90,977
112,646
­
8.43%
­
15.38%
0.00%
23.81%
Dynegy
64,596
44,575
49,213
60,551
18.02%
­
18.56%
­
10.09%
10.63%
EAST
KENTUCKY
POWER
COOPERATIVE
19,695
17,220
20,776
25,910
­
5.77%
­
17.61%
­
0.59%
23.97%
29
Table
3.
2010
Parent
Company
Allocations
Edison
International
88,459
80,550
94,659
67,559
6.83%
­
2.73%
14.31%
­
18.41%
EL
PASO
CORP
748
1,501
1,911
2,391
­
54.34%
­
8.35%
16.69%
46.00%
Empire
District
Electric
Company
4,897
4,405
2,858
1,713
41.20%
27.01%
­
17.60%
­
50.61%
ENERGY
EAST
CORPORATION
4,433
2,930
3,712
4,841
11.41%
­
26.36%
­
6.71%
21.66%
Entergy
20,548
88,813
11,960
10,205
­
37.51%
170.10%
­
63.63%
­
68.96%
Exelon
31,963
20,675
10,321
12,931
68.47%
8.97%
­
45.60%
­
31.84%
First
Energy
109,909
75,549
92,754
106,457
14.29%
­
21.44%
­
3.55%
10.70%
FPL
59,921
88,196
23,247
25,930
21.49%
78.81%
­
52.87%
­
47.43%
Garland
City
of
108
2,476
4
42
­
83.57%
276.58%
­
99.39%
­
93.61%
Grand
Haven
City
of
744
641
795
999
­
6.39%
­
19.35%
0.03%
25.70%
GREAT
PLAINS
ENERGY
34,564
20,670
24,464
11,865
51.00%
­
9.70%
6.87%
­
48.17%
Henderson
City
Utility
Comm
406
66
82
102
147.56%
­
59.76%
­
50.00%
­
37.80%
HOLLAND
BOARD
OF
PUBLIC
WORKS
824
482
444
561
42.62%
­
16.57%
­
23.15%
­
2.90%

HOOSIER
ENERGY
REC
INC
18,533
17,557
21,596
26,931
­
12.39%
­
17.00%
2.09%
27.31%
JEA
21,444
27,980
28,386
29,063
­
19.74%
4.72%
6.24%
8.78%
KeySpan
31,940
32,206
10,194
12,002
47.97%
49.20%
­
52.77%
­
44.40%
Kissimmee
Utility
Authority
0
2,093
3
31
LAKELAND
ELECTRIC
6,431
7,634
6,740
8,275
­
11.54%
5.01%
­
7.29%
13.82%
Lansing
City
of
8,710
5,237
6,493
5,694
33.31%
­
19.84%
­
0.62%
­
12.85%
LGE
97,141
96,610
113,259
133,986
­
11.89%
­
12.37%
2.73%
21.53%
Lower
Colorado
River
Authority
342
7,763
11
133
­
83.42%
276.43%
­
99.47%
­
93.55%
Madison
Gas
&
Electric
Co
546
1,296
1,315
1,462
­
52.72%
12.23%
13.88%
26.61%
MANITOWOC
PUBLIC
UTILITIES
862
628
778
374
30.51%
­
4.92%
17.79%
­
43.38%
Marquette
City
of
251
659
817
395
­
52.69%
24.22%
54.01%
­
25.54%
MCDERMOTT
INTERNATIONAL
562
968
1,233
1,542
­
47.76%
­
10.06%
14.56%
43.27%
Michigan
South
Central
Pwr
Agy
907
765
948
1,147
­
3.69%
­
18.77%
0.66%
21.79%
Mid­
America
Energy
32,911
40,437
49,452
23,701
­
10.14%
10.41%
35.02%
­
35.29%
Mirant
72,299
46,440
44,779
55,182
32.23%
­
15.06%
­
18.10%
0.93%
MORA­
SAN
MIGUEL
ELECTRIC
CO­
OP
8,326
5,863
7,937
4,336
25.86%
­
11.37%
19.98%
­
34.46%

MUSCATINE
POWER
&
WATER
1,697
3,209
3,948
1,892
­
36.83%
19.45%
46.96%
­
29.57%
Nisource
25,352
33,752
41,011
37,350
­
26.23%
­
1.79%
19.34%
8.68%
Northampton
Generating
Company
LP,
Cogentrix,
and
Foster
Wheeler
604
1,438
1,831
881
­
49.21%
21.00%
54.08%
­
25.87%

NRG
Energy
50,948
44,210
47,096
40,303
11.63%
­
3.13%
3.19%
­
11.69%
ORLANDO
UTILITIES
CO
5,977
10,573
13,362
17,123
­
49.17%
­
10.08%
13.63%
45.62%
Otter
Tail
Corp
15,285
1,734
2,147
1,031
202.72%
­
65.66%
­
57.48%
­
79.58%
OWENSBORO
MUNICIPAL
UTILITIES
4,517
5,774
7,153
8,797
­
31.15%
­
11.99%
9.04%
34.10%
Pella
City
of
882
272
333
160
114.21%
­
33.94%
­
19.13%
­
61.14%
PG&
E
CORP
8,235
1,477
1,881
2,353
136.19%
­
57.64%
­
46.05%
­
32.51%
Power
Authority
of
State
of
NY
3,225
7,613
1,906
2,266
­
14.06%
102.88%
­
49.21%
­
39.61%
PP&
L
81,781
33,733
39,924
49,359
59.73%
­
34.11%
­
22.02%
­
3.59%
Progress
Energy
124,143
106,938
106,277
132,581
5.67%
­
8.98%
­
9.54%
12.85%
Reliant
129,292
96,864
102,152
127,111
13.56%
­
14.92%
­
10.28%
11.64%
Reynolds
American
Inc.
2,901
1,411
1,758
2,176
40.74%
­
31.56%
­
14.73%
5.55%
RICHMOND
POWER
&
LIGHT
4,474
1,318
1,632
2,035
89.20%
­
44.26%
­
30.99%
­
13.94%
San
Antonio
Public
Service
Bd
21,754
29,172
24,038
13,317
­
1.43%
32.18%
8.92%
­
39.66%
SCANA
CORPORATION
30,737
30,084
36,294
45,526
­
13.81%
­
15.64%
1.78%
27.67%
SCHUYLKILL
ENERGY
RESOURCES
1,797
1,683
2,142
1,031
8.05%
1.18%
28.78%
­
38.01%
SEMINOLE
ELECTRIC
COOPERATIVE
INC
18,420
18,090
21,437
26,428
­
12.68%
­
14.24%
1.63%
25.29%

SEMPRA
ENERGY
3,535
13,127
5,470
3,137
­
44.04%
107.80%
­
13.41%
­
50.34%
SOUTH
CAROLINA
PUBLIC
SERVICE
AUTH.
21,577
34,920
41,801
52,423
­
42.74%
­
7.33%
10.94%
39.13%

SOUTH
MISSISSIPPI
ELECTRIC
POWER
ASSOC.
5,106
5,059
5,080
6,924
­
7.87%
­
8.72%
­
8.34%
24.93%
30
Table
3.
2010
Parent
Company
Allocations
Southern
364,955
291,167
341,733
368,281
6.86%
­
14.75%
0.06%
7.83%
Southern
Illinois
Power
Coop
4,160
3,082
3,864
4,834
4.39%
­
22.66%
­
3.04%
21.30%
Springfield
CWLP
8,965
10,052
12,324
10,621
­
14.54%
­
4.18%
17.48%
1.24%
SUEZ
ENERGY
INTERNATIONAL
557
4,989
6,454
3,308
­
85.45%
30.36%
68.64%
­
13.56%
Tallahassee
City
of
3,030
3,742
5
55
77.40%
119.09%
­
99.71%
­
96.78%
TECO
ENERGY
INC
41,972
30,401
37,936
43,517
9.14%
­
20.95%
­
1.35%
13.16%
TEXAS
MUNICIPAL
POWER
AGENCY
6,952
5,218
7,064
3,859
20.42%
­
9.62%
22.36%
­
33.16%
Tondu
Corporation
253
961
1,191
1,498
­
74.07%
­
1.51%
22.06%
53.52%
TRIGEN
ENERGY
CORP
435
1,063
1,347
676
­
50.54%
20.75%
53.00%
­
23.21%
TVA
208,137
185,217
226,027
276,356
­
7.05%
­
17.29%
0.93%
23.41%
TXU
123,836
124,513
102,722
56,908
21.41%
22.08%
0.71%
­
44.20%
UGI
CORPORATION
1,130
655
764
516
47.47%
­
14.52%
­
0.29%
­
32.66%
VECTREN
CORP
10,234
11,446
13,857
17,282
­
22.50%
­
13.32%
4.94%
30.88%
WE
Energies
42,903
42,759
52,168
35,984
­
1.27%
­
1.60%
20.05%
­
17.19%
Wheelabrator
Technologies
Inc.
637
805
1,025
493
­
13.89%
8.77%
38.50%
­
33.38%
WPS
18,496
18,649
21,774
12,690
3.32%
4.17%
21.63%
­
29.12%
WYANDOTTE
DEPARTMENT
OF
MUNICIPAL
Services
547
702
812
394
­
10.88%
14.38%
32.30%
­
35.80%

XCel
Energy
61,902
84,248
96,922
49,634
­
15.41%
15.13%
32.45%
­
32.17%

Average
11.08%
5.73%
­
3.54%
­
13.27%
Percent
Positive
51.82%
34.55%
56.36%
43.64%
31
Table
4.
2015
Parent
Company
Allocations
Allocations
to
2015
Parent
Companies
Difference
from
Mean
Parent
Company
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
AE
76,059
58,399
71,741
89,529
2.88%
­
21.01%
­
2.96%
21.10%

AEP
275,713
217,353
253,524
264,113
9.12%
­
13.98%
0.34%
4.53%

AES
40,583
40,256
47,731
60,276
­
14.04%
­
14.73%
1.10%
27.67%

ALABAMA
ELECTRIC
COOPERATIVE
5,274
6,044
6,772
7,561
­
17.76%
­
5.75%
5.60%
17.91%

Alcoa
3,684
7,333
9,079
4,455
­
39.98%
19.47%
47.92%
­
27.42%

ALLETE
INC
8,106
11,793
14,164
6,841
­
20.73%
15.32%
38.51%
­
33.10%

Alliant
Energy
35,855
36,226
43,383
22,317
4.09%
5.17%
25.95%
­
35.21%

Ameren
86,518
77,202
94,859
66,047
6.61%
­
4.87%
16.88%
­
18.62%

AQUILA
INC
3,310
5,043
5,906
2,852
­
22.62%
17.89%
38.06%
­
33.33%

ASSOCIATED
ELECTRIC
COOPERATIVE
INC
19,737
21,309
25,407
12,262
0.30%
8.28%
29.11%
­
37.69%

Austin
City
of
(
MN)
369
219
271
339
23.21%
­
26.88%
­
9.52%
13.19%

Austin
Energy
180
3,671
5
63
­
81.63%
274.69%
­
99.49%
­
93.57%

Austin
Energy
and
Lower
Colorado
River
Authority
14,712
13,756
18,622
10,173
2.77%
­
3.91%
30.08%
­
28.94%

BLACK
RIVER
POWER
LLC
138
591
749
489
­
71.86%
20.16%
52.28%
­
0.58%

BOARD
OF
PUBLIC
UTILITIES
JAMESTOWN
1,065
372
419
211
106.10%
­
28.01%
­
18.92%
­
59.17%

Brazos
Electric
Power
Coop
Inc
717
1,978
3
33
5.02%
189.71%
­
99.56%
­
95.17%

Cedar
Falls
City
of
194
84
104
129
51.86%
­
34.25%
­
18.59%
0.98%

CenterPoint
37,272
60,270
47,349
26,278
­
12.90%
40.84%
10.65%
­
38.59%

CENTRAL
ELECTRIC
POWER
COOPERATIVE
1,913
491
611
736
104.00%
­
47.64%
­
34.84%
­
21.51%

CENTRAL
IOWA
POWER
COOPERATIVE
1,955
361
407
506
142.18%
­
55.28%
­
49.58%
­
37.32%

CINERGY
83,483
81,023
97,936
122,107
­
13.16%
­
15.72%
1.87%
27.01%

CITY
OF
AMES
784
687
845
405
15.25%
0.99%
24.22%
­
40.46%

CITY
OF
COLUMBIA,
MO
1,634
121
146
71
231.44%
­
75.46%
­
70.39%
­
85.60%

CITY
OF
GAINESVILLE
2,963
2,507
2,253
2,897
11.60%
­
5.57%
­
15.14%
9.11%

CITY
OF
INDEPENDENCE
1,637
206
256
320
170.69%
­
65.94%
­
57.67%
­
47.09%

CITY
OF
ROCHESTER,
MN
1,098
283
338
422
105.14%
­
47.13%
­
36.85%
­
21.16%

CITY
OF
SIKESTON
2,381
2,411
2,997
1,445
3.14%
4.44%
29.82%
­
37.41%

CLECO
CORPORATION
14,799
15,746
12,756
7,830
15.77%
23.18%
­
0.21%
­
38.75%

CMS
ENERGY
33,336
27,495
32,024
31,701
7.06%
­
11.70%
2.84%
1.80%

Cogentrix
3,873
11,685
14,592
17,247
­
67.31%
­
1.39%
23.15%
45.55%

Conectiv
5,775
51
6
7
295.62%
­
96.51%
­
99.59%
­
99.52%
CONSTELLATION
ENERGY
GROUP
19,822
23,597
24,522
29,101
­
18.30%
­
2.73%
1.08%
19.95%

Corn
Belt
Power
Coop
133
68
84
104
36.76%
­
30.08%
­
13.62%
6.94%

DAIRYLAND
POWER
COOPERATIVE
6,425
6,417
7,937
5,915
­
3.72%
­
3.84%
18.93%
­
11.37%
32
Table
4.
2015
Parent
Company
Allocations
Allocations
to
2015
Parent
Companies
Difference
from
Mean
Parent
Company
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
Delta
Power
Company
614
1,160
1,501
1,923
­
52.74%
­
10.74%
15.50%
47.98%

Dominion
63,934
69,105
76,424
86,685
­
13.65%
­
6.66%
3.22%
17.08%

DPL
INC
33,637
24,523
30,159
37,580
6.87%
­
22.09%
­
4.18%
19.40%

DTE
ENERGY
CO
73,987
55,547
66,196
50,841
20.03%
­
9.89%
7.39%
­
17.52%

Duke
58,320
53,891
63,684
78,854
­
8.43%
­
15.38%
­
0.01%
23.81%

Dynegy
45,218
31,203
34,448
42,385
18.02%
­
18.56%
­
10.09%
10.63%

EAST
KENTUCKY
POWER
COOPERATIVE
13,787
12,054
14,542
18,137
­
5.76%
­
17.61%
­
0.60%
23.97%

Edison
International
61,922
56,384
66,260
47,292
6.83%
­
2.73%
14.31%
­
18.41%

EL
PASO
CORP
523
1,051
1,338
1,673
­
54.34%
­
8.32%
16.72%
45.94%

Empire
District
Electric
Company
3,427
3,084
2,001
1,199
41.16%
27.03%
­
17.58%
­
50.61%

ENERGY
EAST
CORPORATION
3,104
2,051
2,598
3,389
11.43%
­
26.37%
­
6.73%
21.67%

Entergy
14,383
62,169
8,371
7,145
­
37.51%
170.10%
­
63.63%
­
68.96%

Exelon
22,376
14,472
7,225
9,050
68.48%
8.97%
­
45.60%
­
31.86%

First
Energy
76,935
52,885
64,927
74,519
14.29%
­
21.44%
­
3.55%
10.70%

FPL
41,945
61,736
16,274
18,151
21.49%
78.81%
­
52.87%
­
47.43%

Grand
Haven
City
of
520
449
556
700
­
6.52%
­
19.28%
­
0.04%
25.84%

GREAT
PLAINS
ENERGY
24,195
14,469
17,125
8,306
50.99%
­
9.70%
6.87%
­
48.16%

Henderson
City
Utility
Comm
284
46
57
71
148.03%
­
59.83%
­
50.22%
­
37.99%

HOLLAND
BOARD
OF
PUBLIC
WORKS
577
338
311
392
42.65%
­
16.44%
­
23.11%
­
3.09%

HOOSIER
ENERGY
REC
INC
12,973
12,291
15,117
18,851
­
12.39%
­
17.00%
2.09%
27.30%

JEA
15,010
19,585
19,870
20,345
­
19.74%
4.72%
6.24%
8.78%

KeySpan
22,359
22,544
7,135
8,401
47.98%
49.20%
­
52.78%
­
44.40%

LAKELAND
ELECTRIC
4,501
5,344
4,717
5,793
­
11.55%
5.02%
­
7.31%
13.84%

Lansing
City
of
6,097
3,667
4,545
3,986
33.30%
­
19.83%
­
0.63%
­
12.85%

LGE
67,996
67,628
79,279
93,788
­
11.89%
­
12.37%
2.73%
21.53%

Lower
Colorado
River
Authority
239
5,434
8
93
­
83.44%
276.45%
­
99.45%
­
93.56%

Madison
Gas
&
Electric
Co
382
906
920
1,023
­
52.71%
12.16%
13.90%
26.65%

MANITOWOC
PUBLIC
UTILITIES
603
440
545
262
30.38%
­
4.86%
17.84%
­
43.35%

Marquette
City
of
176
461
572
277
­
52.62%
24.09%
53.97%
­
25.44%

MCDERMOTT
INTERNATIONAL
394
678
863
1,080
­
47.77%
­
10.04%
14.51%
43.30%

Michigan
South
Central
Pwr
Agy
635
535
664
803
­
3.68%
­
18.85%
0.72%
21.81%

Mid­
America
Energy
23,037
28,307
34,617
16,590
­
10.14%
10.41%
35.02%
­
35.29%

Mirant
50,609
32,507
31,345
38,628
32.23%
­
15.06%
­
18.10%
0.93%

MORA­
SAN
MIGUEL
ELECTRIC
CO­
OP
5,828
4,104
5,556
3,035
25.85%
­
11.38%
19.98%
­
34.46%

MUSCATINE
POWER
&
WATER
1,188
2,247
2,764
1,324
­
36.83%
19.47%
46.96%
­
29.60%

Nisource
17,746
23,627
28,708
26,146
­
26.23%
­
1.79%
19.33%
8.68%
Northampton
Generating
Company
LP,
Cogentrix,
and
Foster
Wheeler
422
1,007
1,282
617
­
49.23%
21.02%
54.06%
­
25.85%
33
Table
4.
2015
Parent
Company
Allocations
Allocations
to
2015
Parent
Companies
Difference
from
Mean
Parent
Company
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
NRG
Energy
35,664
30,946
32,967
28,213
11.63%
­
3.13%
3.19%
­
11.69%

ORLANDO
UTILITIES
CO
4,184
7,401
9,353
11,986
­
49.17%
­
10.08%
13.63%
45.62%

Otter
Tail
Corp
10,701
1,214
1,503
722
202.72%
­
65.66%
­
57.48%
­
79.58%

OWENSBORO
MUNICIPAL
UTILITIES
3,162
4,041
5,007
6,158
­
31.14%
­
12.00%
9.04%
34.10%

Pella
City
of
617
190
233
112
114.24%
­
34.03%
­
19.10%
­
61.11%

PG&
E
CORP
5,764
1,034
1,317
1,647
136.18%
­
57.63%
­
46.04%
­
32.51%

Power
Authority
of
State
of
NY
2,258
5,329
1,334
1,587
­
14.05%
102.85%
­
49.22%
­
39.59%

PP&
L
57,246
23,613
27,947
34,549
59.73%
­
34.11%
­
22.02%
­
3.60%

Progress
Energy
86,899
74,854
74,391
92,804
5.67%
­
8.98%
­
9.54%
12.85%

Reliant
90,507
67,805
71,504
88,976
13.56%
­
14.92%
­
10.28%
11.64%

Reynolds
American
Inc.
2,031
988
1,231
1,523
40.73%
­
31.54%
­
14.71%
5.53%

RICHMOND
POWER
&
LIGHT
3,131
923
1,142
1,424
89.18%
­
44.23%
­
31.00%
­
13.96%

San
Antonio
Public
Service
Bd
15,228
20,420
16,826
9,322
­
1.43%
32.18%
8.91%
­
39.66%

SCANA
CORPORATION
21,516
21,059
25,407
31,869
­
13.81%
­
15.64%
1.78%
27.67%

SCHUYLKILL
ENERGY
RESOURCES
1,258
1,178
1,500
722
8.03%
1.16%
28.81%
­
38.00%

SEMINOLE
ELECTRIC
COOPERATIVE
INC
12,894
12,663
15,005
18,500
­
12.67%
­
14.24%
1.62%
25.29%

SEMPRA
ENERGY
2,475
9,188
3,831
2,195
­
44.03%
107.77%
­
13.37%
­
50.36%

SOUTH
CAROLINA
PUBLIC
SERVICE
AUTH.
15,105
24,445
29,262
36,696
­
42.73%
­
7.32%
10.94%
39.12%

SOUTH
MISSISSIPPI
ELECTRIC
POWER
ASSOC.
3,574
3,541
3,556
4,848
­
7.88%
­
8.73%
­
8.34%
24.96%

Southern
255,467
203,816
239,213
257,795
6.86%
­
14.75%
0.06%
7.83%

Southern
Illinois
Power
Coop
2,912
2,158
2,705
3,384
4.38%
­
22.65%
­
3.04%
21.30%

Springfield
CWLP
6,274
7,036
8,626
7,434
­
14.55%
­
4.17%
17.48%
1.25%
SUEZ
ENERGY
INTERNATIONAL
390
3,493
4,518
2,316
­
85.45%
30.37%
68.63%
­
13.56%

Tallahassee
City
of
2,121
2,619
4
39
77.38%
119.03%
­
99.67%
­
96.74%

TECO
ENERGY
INC
29,380
21,281
26,556
30,462
9.14%
­
20.95%
­
1.35%
13.16%

TEXAS
MUNICIPAL
POWER
AGENCY
4,866
3,653
4,945
2,701
20.41%
­
9.61%
22.36%
­
33.16%

Tondu
Corporation
177
672
834
1,049
­
74.07%
­
1.61%
22.10%
53.58%

TRIGEN
ENERGY
CORP
305
744
943
473
­
50.53%
20.74%
53.03%
­
23.24%

TVA
145,695
129,649
158,219
193,448
­
7.05%
­
17.29%
0.94%
23.41%

TXU
86,685
87,160
71,906
39,836
21.41%
22.08%
0.71%
­
44.20%

UGI
CORPORATION
791
459
535
361
47.44%
­
14.45%
­
0.28%
­
32.71%

VECTREN
CORP
7,164
8,012
9,700
12,097
­
22.49%
­
13.32%
4.94%
30.87%

WE
Energies
30,030
29,933
36,518
25,188
­
1.27%
­
1.59%
20.06%
­
17.19%

Wheelabrator
Technologies
Inc.
446
564
718
345
­
13.93%
8.82%
38.54%
­
33.43%

WPS
12,947
13,054
15,241
8,883
3.32%
4.17%
21.62%
­
29.11%
34
Table
4.
2015
Parent
Company
Allocations
Allocations
to
2015
Parent
Companies
Difference
from
Mean
Parent
Company
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
EPA
Heat
Input
Heat
Input
&
Fuel
Factor
Heat
Input
&
Fuel
Factor,
Coal
Type
WYANDOTTE
DEPARTMENT
OF
MUNICIPAL
Services
383
492
569
276
­
10.93%
14.42%
32.33%
­
35.81%

XCel
Energy
43,332
58,973
67,844
34,743
­
15.41%
15.13%
32.45%
­
32.17%

Average
12.49%
3.10%
­
2.83%
­
12.76%

Percent
Positive
52.78%
34.26%
55.56%
43.52%
35
Table
5.
Percent
of
Region­
wide
Budget
for
24
CAIR
States
under
EPA's
CAIR
Approach
and
Alternatives
(
Data
Used
To
Generate
Cumulative
Distributions)

State
EPA
Title
IV
Average
(
Pure)
Heat
Input
Heat
Input
w/
Fuel
Factors
Heat
Input
w/
Fuel
Factors
&
Coal
Type
Average
Heat
Input
Coal
+
Oil
Average
Emissions
Average
Output
All
Average
Output
Fossil
Alabama
4.4%
4.7%
5.4%
5.9%
4.7%
5.0%
4.7%
4.2%
District
of
Columbia
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
Florida
7.0%
8.5%
6.3%
7.6%
7.3%
6.0%
7.2%
7.7%
Georgia
5.9%
4.5%
5.3%
6.0%
4.5%
5.2%
4.5%
4.2%
Iowa
1.8%
5.1%
6.1%
5.0%
2.3%
1.4%
1.5%
1.8%
Illinois
5.3%
7.2%
8.8%
9.0%
5.2%
4.7%
6.6%
4.4%
Indiana
7.0%
2.1%
2.7%
1.4%
7.5%
8.6%
4.6%
6.2%
Kentucky
5.2%
5.4%
6.7%
8.2%
5.8%
5.8%
3.5%
4.5%
Louisiana
1.7%
3.7%
1.8%
1.1%
1.5%
1.1%
3.4%
3.6%
Maryland
2.0%
1.9%
2.1%
2.6%
2.0%
2.7%
1.9%
1.7%
Michigan
4.9%
4.7%
5.0%
4.2%
4.3%
3.7%
4.1%
4.2%
Minnesota
1.4%
2.1%
2.5%
1.3%
2.2%
1.0%
1.9%
1.7%
Missouri
3.8%
1.5%
1.1%
1.2%
4.1%
2.4%
2.9%
3.4%
Mississippi
0.9%
4.0%
4.8%
2.6%
1.1%
1.2%
1.6%
1.6%
North
Carolina
3.8%
4.4%
2.4%
3.0%
4.3%
4.7%
4.5%
3.8%
New
York
3.7%
4.1%
5.0%
6.2%
3.4%
2.7%
5.3%
3.9%
Ohio
9.2%
7.1%
8.8%
10.9%
7.5%
12.2%
5.4%
6.5%
Pennsylvania
7.6%
6.6%
7.9%
9.5%
6.9%
9.5%
7.4%
6.1%
South
Carolina
1.6%
2.2%
2.6%
3.3%
2.2%
2.1%
3.4%
2.0%
Tennessee
3.8%
3.3%
4.1%
4.9%
3.5%
4.0%
3.5%
3.0%
Texas
8.9%
16.9%
10.5%
6.2%
9.0%
6.0%
13.9%
16.6%
Virginia
1.8%
2.5%
2.8%
3.5%
2.5%
2.3%
2.8%
2.3%
Wisconsin
2.4%
4.8%
6.0%
7.6%
2.8%
2.0%
2.2%
2.2%
West
Virginia
6.0%
2.7%
3.3%
2.0%
5.2%
5.8%
3.4%
4.5%
Source:
EPA,
2006
36
37
Appendix
C:
Commenter
Information
Summary
Table
Company
Preferred
Allocations
Approach
Best
Allocation
Approach
(
in
terms
of
coverage)
2010:
Emissions
 

Allowances
2010:
Cost
of
Allowances
(
million
2004$)
Revenues
(
million
2004$)
2010:
Allowance
Costs
as
Percent
of
Revenue
(%)
2010:
Coal
Capacity
(
GW)

AES
Updating
HI
w/
FF
&
Coal
Type
17,808
12
9,463
0.1
3.2
Minnesota
Power
HI
w/
FF
(
coal
&
oil
only)
HI
w/
FF
16,785
12
737
1.6
1.3
Duke
HI
w/
FF
HI
w/
FF
&
Coal
Type
80,328
55
16,746
0.3
8.3
FPL
Output
or
Simple
HI
Simple
HI
­
56,160
­
39
10,522
­
0.4
0.2
JEA
HI
w/
FF
HI
w/
FF
&
Coal
Type
­
6,177
­
4
1,013
­
0.4
3.5
NIPSCO
HI
w/
FF
HI
w/
FF
43,541
29
6,666
0.4
3.1
South
Carolina
Public
Service
Authority
HI
w/
FF
HI
w/
FF
&
Coal
Type
15,221
10
1,350
0.8
2.8
2010:
Total
Coal
Capacity
by
these
Companies:
22.4
/
Total
CAIR­
affected
Coal
Capacity:
243.8
GW
=
9.2%

Note:
(
Emission­
Allowances)
are
based
on
2010
CAIR
projected
emissions
and
CAIR
allocations.
Cost
of
allowances
are
based
on
IPM
modeling
run
CAIR_
CAMR_
CAVR
available
at
www.
epa.
gov/
airmarkets/
mp
adjusted
to
2004$.
Electric
power
revenues
and
capacity
are
based
on
company
information
given
to
EPA
or
available
at
company
websites.

Source:
EPA,
2006