Document ID: EPA-HQ-OAR-2002-0056-6209
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2005-03-15T05:00Z

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

Proposed
National
Emission
Standards
for
Hazardous
Air
Pollutants;
and,
in
the
Alternative,
Proposed
Standards
of
Performance
for
New
and
Existing
Stationary
Sources:
Electric
Utility
Steam
Generating
Units
(
69
FR
4652;
January
30,
2004)

Supplemental
Notice
for
the
Proposed
National
Emission
Standards
for
Hazardous
Air
Pollutants;
and,
in
the
Alternative,
Proposed
Standards
of
Performance
for
New
and
Existing
Stationary
Sources:
Electric
Utility
Steam
Generating
Units
(
69
FR
12398;
March
16,
2004)

Proposed
National
Emission
Standards
for
Hazardous
Air
Pollutants;
and,
in
the
Alternative,
Proposed
Standards
of
Performance
for
New
and
Existing
Stationary
Sources,
Electric
Utility
Steam
Generating
Units:
Notice
of
Data
Availability
(
69
FR
69864;
December
1,
2004)

Docket
Number
OAR­
2002­
0056
5.0
MERCURY
CAP­
AND­
TRADE
PROGRAM
US
Environmental
Protection
Agency
Emissions
Standards
Division
Office
of
Air
Quality
Planning
and
Standards
Research
Triangle
Park,
North
Carolina
27711
15
March
2005
i
General
Outline
1.0
INTRODUCTION
AND
BACKGROUND
2.0
APPLICABILITY
AND
SUBCATEGORIZATION
3.0
PERFORMANCE
STANDARDS
FOR
COAL­
FIRED
ELECTRIC
UTILITY
STEAM
GENERATING
UNITS
4.0
PERFORMANCE
STANDARDS
FOR
OIL­
FIRED
ELECTRIC
UTILITY
STEAM
GENERATING
UNITS
5.0
MERCURY
CAP­
AND­
TRADE
PROGRAM
6.0
MERCURY
EMISSIONS
MONITORING
7.0
IMPACT
ESTIMATES
8.0
COMPLIANCE
WITH
EXECUTIVE
ORDERS
AND
STATUTES
9.0
NODA
10.0
OTHER
Appendix
A
LIST
OF
COMMENTERS
5­
1
5.0
MERCURY
CAP­
AND­
TRADE
PROGRAM
5.1
GENERAL
5.1.1
Support
cap
and
trade
Comment:

Many
commenters
(
OAR­
2002­
0056­
1046,
­
1475,
­
1482,
­
1483,
­
1608,
­
1623,
­
1625,
­
1673,
­
1692,
­
1768,
­
1790,
­
1802
­
1826,
­
1834,
­
1859,
­
1889,
­
1900,
­
1955,
­
1961,
­
1969,
­
2042,
­
2115,
­
2117,
­
2119,
­
2123,
­
2135,
­
2162
­
2172,
­
2204,
­
2221,
­
2224,
­
2228,
­
2229,
­
2232,
­
2243,
­
2260,
­
2323,
­
2346,
­
2356,
­
2375,
­
2428,
­
2431,
­
2597,
­
2610,
­
2613,
­
2718,
­
2729,
­
2826,
­
2833,
­
2835,
­
2841,
­
2844,
­
2845,
­
2850,
­
2861,
­
2883,
­
2895,
­
2897,
­
2899,
­
2900,
­
2904,
­
2906,
­
2907,
­
2911,
­
2915,
­
2918,
­
2929,
­
2948,
­
3199,
­
3208,
­
3211,
­
3431,
­
3432,
­
3440,
­
3443,
­
3445,
­
3454,
­
3463,
­
3469,
­
3478,
­
3516,
­
3517,
­
3521,
­
3522,
­
3530,
­
3531,
­
3537,
­
3539,
­
3546,
­
3556,
­
3565,
­
4103,
­
4132,
­
4385,
­
4454)
supported
the
cap­
and­
trade
option
for
controlling
mercury
emissions
from
coal­
fired
power
plants.

One
commenter
(
OAR­
2002­
0056­
2906)
also
supported
the
cap­
and­
trade
approach
to
controlling
nickel
emissions
from
oil­
fired
power
plants.

Many
commenters
(
OAR­
2002­
0056­
1623,
­
1625,
­
1673,
­
1692,
­
1768,
­
1826,
­
1859,
­
1961,
­
1969,
­
2162,
­
2243,
­
2375,
­
2431,
­
2718,
­
2833,
­
2835,
­
2841,
­
2844,
­
2861,
­
2883,
­
2897,
­
2899,
­
2900,
­
2906,
­
2907,
­
2915,
­
2929,
­
3208,
­
3432,
­
3443,
­
3463,
­
3478,
­
3507,
­
3521,
­
3522,
­
3531,
­
3537,
­
3546,
­
3565)
supported
a
cap­
and­
trade
approach
as
being
the
most
cost
effective
way
of
achieving
substantial
emission
reductions
from
the
electric
power
sector.

Many
commenters
(
OAR­
2002­
0056­
1046,
­
1475,
­
1482,
­
1483,
­
1623,
­
1834,
­
1889,
­
1900,
­
1955,
­
2117,
­
2115,
­
2117,
­
2135,
­
2224,
­
2323,
­
2346,
­
2718,
­
2841,
­
2904,
­
2906,
­
2929,
­
3199,
­
3211,
­
3443,
­
3516,
­
3531,
­
3539,
­
3546)
cited
larger
emission
reductions
from
cap
and
trade
than
from
the
traditional
MACT
approach
as
a
reason
they
supported
cap
and
trade.

Several
of
these
commenters
(
OAR­
2002­
0056­
1955,
­
2718,
­
3546)
noted
that
greater
environmental
benefits
would
be
achieved
because
of
greater
compliance
within
the
regulated
community
and
commenter
1955
cited
the
compliance
rate
of
99.93
percent
with
the
Acid
Rain
Program
for
SO
2
in
2001.

Several
commenters
(
OAR­
2002­
0056­
4103,
­
4385,
­
2610,
­
2613,
­
2729,
­
2841)
submitted
that
emission
trading
helps
companies
avoid
potential
problems
that
could
reduce
power
reliability
while
improving
the
environment
by
providing
faster
and
efficient
emission
reductions.

One
of
these
commenters
(
OAR­
2002­
0056­
2841)
noted
cap
and
trade
would
not
result
in
increased
demand
for
or
pressure
on
natural
gas
prices
because
companies
will
be
able
to
over
control
units
that
are
most
economic
to
control
and
leave
smaller,
lower
emitting
units
on­
line.
5­
2
Several
commenters
(
OAR­
2002­
0056­
1834,
­
1889,
­
2117,
­
2123,
­
2323,
­
2907)
stated
that
a
nationwide
cap­
and­
trade
would
reduce
mercury
emissions
by
almost
70
percent
from
2001
levels,
achieving
the
MACT
goal
by
2010
and
capping
emissions
at
15
tons
in
2018.
The
commenters
noted
that
MACT
would
only
reduce
these
emissions
from
coal­
fired
power
plants
by
29
percent
from
2001
levels
by
2007.

Several
commenters
(
OAR­
2002­
0056­
1623,
­
1768,
­
1859,
­
2162,
­
2375,
­
2597,
­
2833,
­
2835,
­
2844,
­
2850,
­
2900,
­
2907,
­
3432,
­
3440,
­
3522,
­
3531,
­
3537)
believed
cap
and
trade
offers
a
flexible,
market­
based
approach.

One
commenter
(
OAR­
2002­
0056­
3432)
noted
that
compliance
flexibility
is
especially
important
to
small
generating
systems.

Several
commenters
(
OAR­
2002­
0056­
2597,
­
2845,
­
2897,
­
2906,
­
3431)
believed
that
cap
and
trade
will
have
less
impact
on
fuel
diversity
and
natural
gas
availability
than
the
MACT
approach.

One
of
these
commenters
(
OAR­
2002­
0056­
2845)
noted
fuel
switching
to
meet
the
acid
rain
requirements
resulted
in
the
loss
of
many
jobs.
Several
commenters
(
OAR­
2002­
0056­
2224,
­
2597,
­
2900,
­
2904,
­
3530,
­
3537)
submitted
that
cap
and
trade
will
spur
technological
innovations
by
electric
generators
seeking
to
create
emission
credits
that
can
be
sold
and
reducing
emissions
early
in
the
process.

Several
commenters
(
OAR­
2002­
0056­
2900,
­
3537)
added
that
cap
and
trade
would
result
in
a
certain,
fixed
cap
on
emissions
from
affected
sources
and
would
create
incentives
for
emissions
reductions
beyond
those
required
by
current
regulations.

One
commenter
(
OAR­
2002­
0056­
1608)
believed
that
a
regulatory
approach
can
work
if
it's
designed
around
the
following
principles:
1)
regulatory
certainty
that
will
allow
our
industry
to
make
financially
sound
compliance
and
planning
decisions
regarding
capital
investments
in
environmental
and
energy
technologies,
2)
that
EPA
should
set
reasonable
reduction
targets
and
time
lines,
and
provide
maximum
flexibility
to
minimize
costs
to
achieve
desired
air
quality
objectives
cost
effectively
through
the
use
of
flexible,
market­
based
mechanisms
such
as
emissions
trading,
and
finally
3)
to
protect
fuel
diversity
to
preserve
and
assure
the
continued
supply
of
reliable,
affordable
electricity
to
meet
our
nation's
growing
energy
needs.

One
commenter
(
OAR­
2002­
0056­
3516)
stated
that
criticism
of
the
cap­
and­
trade
option,
in
the
mercury
context,
was
inappropriate.
The
commenter
noted
a
recent
study
from
the
Brookhaven
National
Laboratory
(
BNL)
observed
that,
"
A
Cap
and
Trade
program
has
the
potential
to
be
protective
of
human
health
while
being
more
economically
efficient
than
limiting
releases
from
all
power
plants
to
a
fraction
of
their
current
release
rates."
[
Assessing
the
Mercury
Health
Risks
Associated
with
Coal­
Fired
Power
Plants:
Impacts
of
Local
Depositions
[
PDF­
866MB]
presented
by
Terry
Sullivan,
BNL
at
http://
www.
netl.
doe.
gov/
coalpower/
environment/
mercury/
.]
The
commenter
noted
further
the
BNL
researchers
challenged
the
alternative
of
a
plant­
by­
plant
approach
to
mercury
control
based
5­
3
upon
risk
considerations
as
follows:
"
The
prediction
that
risks
resulting
from
Hg
emissions
from
coal­
fired
power
plants
are
small
for
the
general
population
and
the
fact
that
the
risks
are
borne
by
a
small
fraction
of
the
population
suggests
that
placing
reduction
in
mercury
emission
goals
on
a
plant
by
plant
basis
will
do
little
to
improve
human
health.
Therefore,
a
cap
and
trade
approach
appears
to
be
acceptable
from
a
risk
standpoint."

Several
Texas
State
representatives
and
local
officials
(
OAR­
2002­
0056­
2119,
­
2204,
­
2221,
­
2228,
­
2232,
­
2356,
­
2428)
endorsed
the
cap
and
trade
approach.
They
noted
that
Texas
is
the
largest
coal
consumer
(
using
over
40
million
tons
of
lignite/
yr)
and
the
5th
largest
coal
producer;
coal
mining
is
an
important
part
of
the
economy
($
17
billion/
yr).
The
commenters
stated
that
mercury
is
difficult
to
remove
from
lignite
and
there
are
no
commercially
demonstrated
technologies
to
remove
the
elemental
mercury
emitted
from
lignite.
The
commenters
submitted
that
any
regulations
must
not
displace
lignite
coal
in
the
fuel
mix
in
favor
of
more
costly
natural
gas.

Concerning
the
regulatory
mechanism
used
for
a
mercury
control
program,
one
commenter
(
OAR­
2002­
0056­
3454)
recommended
including
flexible
mechanisms
in
the
regulation
that
would
encourage
innovation
while
providing
a
clear
goal
with
meaningful
reductions.
Examples
cited
by
the
commenter
of
these
types
of
mechanisms
included
early
reduction
incentives,
market
based
approaches,
capital
recovery
programs,
plant
wide
averaging,
safety
valves
or
other
approaches.
The
commenter
stated
these
types
of
incentives
combined
with
concrete
goals
would
encourage
technology
innovation
and
reduce
impacts
on
generation
mix.

Many
commenters
(
4,457
citizens,
3
public
interest
groups,
18
states,
1
tribe)
generally
supported
the
more
flexible
cap
and
trade
approach
because
it
would
result
in
lower
emissions
for
less
cost
than
fixed
emission
reductions.
The
commenters
stated
this
would
be
a
reasonable
approach
because
the
health
risk
is
unproven
(
claims
about
the
harmful
effects
of
mercury
on
women
and
children
are
exaggerated
and
misleading),
there
is
no
demonstrated
technology
to
meet
the
limits
(
particularly
if
additional
emission
reductions
were
required),
or
raise
electric
rates
as
much.
The
commenters
believed
emissions
trading
could
help
companies
avoid
potential
reliability
problems
while
improving
the
environment
by
encouraging
earlier
reductions
through
new
technology.

Many
commenters
(
OAR­
2002­
0056­
1673,
­
1955,
­
2224,
­
2833,
­
2844,
­
2861,
­
2883
­
2897,
­
2900,
­
2907,
­
2918,
­
3211,
­
3445,
­
3478,
­
3522,
­
3530,
­
3537,
­
3546,
­
4454,
­
4891)
cited
the
success
of
the
Acid
Rain
Program
as
illustrating
the
advantages
of
the
cap­
and­
trade
system.
One
commenter
(
OAR­
2002­
0056­
2897)
agreed
that
"[
t]
he
challenge
in
creating
an
environmental
market
is
often
to
design
the
predecessor
regulatory
system
that
will
create
proper
incentives
to
produce
the
technological
developments
that
are
preconditions
for
a
transition
to
a
market."
The
commenter
stated
that
the
Acid
Rain
Program
achieved
that
success
with
clear
emission
caps,
the
establishment
of
allowances
that
were
traded
as
financial
instruments,
a
national
market
program,
the
lack
of
any
restrictions
on
the
instruments,
and
a
program
design
that
rewarded
the
innovator
and
the
environmental
investor.
5­
4
Another
commenter
(
OAR­
2002­
0056­
2883)
stated
that
as
EPA's
acid
rain
program
has
shown,
a
well­
constructed
cap­
and­
trade
program
can
achieve
significant
emission
reductions
with
lower
cost
than
other
regulatory
approaches.
The
commenter
believed
a
cap­
and­
trade
program
provides
individual
units
maximum
flexibility
to
achieve
an
emissions
cap.

Several
commenters
(
OAR­
2002­
0056­
2883,
­
3530)
pointed
out
it
also
encourages
the
development
and
installation
of
individual
control
technologies
and
rewards
early
reductions
or
additional
reductions
through
the
use
of
a
banking
system.
For
these
reasons,
the
commenters
favored
a
cap­
and­
trade
approach
over
a
MACT
approach
for
regulating
mercury.

One
commenter
(
OAR­
2002­
0056­
2835)
contrasted
the
Acid
Rain
Program
and
NO
x
SIP
Call
to
command
and
control
type
of
regulations
that
would
limit
compliance
flexibility
and
might
impose
regulatory
constraints
that
not
only
unnecessarily
increase
compliance
costs,
but
also
pose
real
reliability
concerns.
The
commenter
believed
an
emissions
trading
framework
is
an
effective
regulatory
mechanism
to
ensure
that
reliable
power
can
be
delivered
to
customers
while
installing
the
requisite
emission
controls.

According
to
another
commenter
(
OAR­
2002­
0056­
3522),
especially
given
the
substantial
variability
in
emissions
of
mercury
from
plant
to
plant,
the
uncertainty
about
the
levels
of
existing
mercury
emissions
from
power
plants
and
the
lack
of
commercially
proven
technology
to
control
mercury
emissions
from
the
commenter's
sub­­
bituminous
and
western
bituminous
coal­
fired
generation,
a
cap
and
trade
program
would
be
the
best
option.

One
commenter
(
OAR­
2002­
0056­
4454)
submitted
the
following
policy
justifications
for
cap
and
trade,
in
addition
to
the
compliance
successes
and
operational
flexibilities
realized
through
the
Acid
Rain
Program:
(
a)
additional
time
needed
to
manufacture,
install
and
calibrate
emission
control
equipment;
and
(
b)
additional
time
needed
to
develop
accurate
continuous
monitoring
technology,
and
more
time
to
manufacture,
install
and
calibrate
it.

One
commenter
(
OAR­
2002­
0056­
2897)
believed
that
a
cap­
and­
trade
approach
would
be
far
more
effective
than
a
conventional
"
command
and
control"
regulatory
MACT
at
promoting
the
development
of
dedicated
maximum
achievable
control
technologies.
According
to
the
commenter,
as
the
existing
fleet
is
not
equipped
with
dedicated
mercury
control
technologies,
the
MACT
methodology,
which
is
based
on
the
performance
of
existing
units,
cannot
promote
the
development
of
dedicated
control
technologies.
The
commenter
stated
that,
however,
a
national
cap­
and­
trade
approach,
which
includes
limits
that
decrease
with
time,
would
provide
incentive
for
the
development
of
effective
and
affordable
technology.
Thus,
the
commenter
encouraged
a
design
feature
with
decreasing
allowances
over
time
to
increase
the
value
of
the
allowances
as
commodities.
The
commenter
believed
this
should
help
to
create
the
market
forces
to
commercialize
technology.

One
commenter
(
OAR­
2002­
0056­
2835)
believed
the
power
sector
is
well
suited
to
a
cap­
and­
trade
regulatory
framework.
Given
the
relatively
small
number
of
emissions
sources
to
be
regulated,
the
administrative
burdens
of
the
program
should
be
minimal.
The
commenter
also
believed
a
cap­
and­
trade
program
for
mercury
would
not
thwart
the
achievement
of
the
Act's
5­
5
goals
to
protect
human
health
and
the
environment.
One
important
reason
was
that
mercury
is
a
"
global"
pollutant
for
which
there
does
not
appear,
in
most
cases,
to
be
a
pressing
need
to
require
minimum
reductions
at
each
and
every
affected
EGU.

One
commenter
(
OAR­
2002­
0056­
3454)
stated
that
past
experience
with
technology
development
for
other
pollutants
(
SO
2,
NO
x,
and
PM)
as
well
as
other
source
categories
such
as
mobile
sources,
suggests
that
delaying
the
regulation
of
mercury
emissions
from
power
plants
would
serve
to
delay
the
development
of
innovative
control
technologies.
The
commenter
believed
that
research
and
development
efforts
would
be
unlikely
to
be
sustained
at
a
vigorous
level
in
the
absence
of
regulatory
or
other
drivers
capable
of
creating
a
viable
market
for
advanced
control
technologies.
The
commenter
submitted
that
larger
markets
provide
more
incentives
for
the
development
of
technologies
as
well
as
foster
competition
between
vendors
that
produces
more
innovative
and
cost
effective
solutions
for
affected
sources.

One
commenter
(
OAR­
2002­
0056­
2819)
stated
that
if
EPA
decides
to
pursue
trading
and
banking
despite
the
lack
of
legal
authority,
any
trading
and
banking
program
should
be
used
to
supplement
rather
than
supplant
other
CAA
requirements.
At
a
minimum,
EPA
must
adopt
an
initial
set
of
regulations
under
section
112.
The
commenter
suggested
that
any
additional
regulations
adopted
under
section
111
using
trading
and
banking
should
allow
only
for
achieving
compliance
with
a
cap
that
is
more
stringent
that
the
MACT
standards.

One
commenter
(
OAR­
2002­
0056­
2181)
stated
cap
and
trade
programs
work
best
when
a
clear,
enforceable
emissions
cap
is
established,
based
upon
the
appropriate
environmental
or
public
health
goal.
The
cap
is
then
accompanied
by
an
emissions
trading
system
that
allows
competitive
markets
 
not
regulators
 
to
determine
the
lowest
cost
method
to
elicit
the
reductions
necessary
to
accomplish
the
goal.
The
commenter
believed
trading
programs
are
distorted
when
they
are
skewed
to
favor
a
particular
fuel
source,
encourage
a
specific
technology
choice
or
protect
a
particular
vintage
or
business
segment.
The
commenter
concluded
that
such
market
distortions
are
merely
a
subtle
way
of
returning
to
more
traditional
command
and
control
regulatory
regimes
and
will
reduce
the
cost­
minimizing
function
of
the
trading
program,
hinder
progress
toward
air
quality
improvements,
or
both.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111
and
is
finalizing
caps
and
timing
that
are
integrated
with
the
Clean
Air
Interstate
Rule
(
CAIR).
See
final
rule
preamble
for
further
discussion.

5.1.2
Oppose
Cap
and
Trade
Comment:

Many
commenters
specifically
stated
that
EPA
should
abandon
the
cap­
and­
trade
approach.
The
commenters
believed
that
while
a
cap­
and­
trade
program
may
be
effective
and
appropriate
for
nontoxic
pollutants,
it
is
not
permitted
by
section
112(
d)
for
HAP.
Many
5­
6
commenters
submitted
that
cap­
and­
trade
approaches
fall
short
of
what
is
technologically
feasible
and
needed
to
protect
human
health
and
the
environment.
A
trading
scheme
would
allow
dirty
plants
to
continue
to
emit
high
levels
of
mercury
by
purchasing
credits
from
cleaner
plants
and
not
installing
controls,
which
would
further
endanger
the
health
of
surrounding
communities.
with
hot
spots.

One
commenter
(
OAR­
2002­
0056­
3449)
opposed
a
cap
and
trade
approach
for
mercury
except
as
a
supplement
to
more
stringent
MACT
standards.
The
commenter
stated
mercury
emissions
remaining
after
compliance
with
a
cap
and
trade
program
would
cause
unaccpetable
adverse
health
effects;
hot
spots
would
remain.

One
commenter
(
OAR­
2002­
0056­
2067)
stated
that
cap
and
trade
is
inappropriate
because
it
encourages
the
development
of
mercury
"
hot
spots,"
i.
e.,
the
commenter
claimed
that
some
individual
power
plant
units
might
continue
to
emit
mercury
under
a
cap
and
trade
approach,
causing
localized
mercury
deposition.
The
commenter
stated
that,
alternatively,
the
MACT
approach
would
require
the
installation
of
control
technology
on
all
power
plants
and
would
bring
the
balance
of
the
industry
to
the
same
emissions
level
as
those
utilities
that
have
been
industry
leaders
for
decades.
Similarly,
another
commenter
(
OAR­
2002­
0056­
2359)
noted
that
the
purpose
of
standards
under
section
112
is
to
raise
the
control
performance
of
all
sources
to
the
level
of
the
top
12
percent.
The
commenter
submitted
that
trading
would
be
in
direct
contrast
to
this
purpose
as
utilities
would
trade
for
credits
rather
than
install
controls.
The
commenter
believes
that
all
existing
units
must
be
required
to
meet
limits.
The
commenter
concluded
that
allowing
trading
would
invite
legal
challenges
that
would
further
delay
MACT
promulgation
and
implementation.

Many
Indian
tribes
and
organizations
strongly
opposed
cap
and
trade
due
to
the
deferral
of
mercury
controls,
the
inadequate
level
of
control,
and
lack
of
measures
to
prevent
hot
spots.
Waters
they
depend
on
for
fishing
are
contaminated
by
mercury
deposition
from
local,
regional,
and
international
deposition.
In
many
cases,
Indian
lands
are
largely
wetlands
which
are
more
susceptible
to
methylmercury
formation
or
otherwise
sensitive
to
mercury
contamination
due
to
site­
specific
factors.

Several
Indian
tribes
(
OAR­
2002­
0056­
1327,
­
2010,
­
2110,
­
2118,
­
2173,
­
3311,
­
3549,
­
3550,
­
3551)
opposed
cap
and
trade
because
unlike
the
Federal
government,
states
do
not
have
trust
responsibilities
for
tribes
and
tribes
have
no
formal
role
in
rulemakings.
The
commenters
believed
state­
run
programs
would
be
inefficient,
ineffective,
and
not
in
the
best
interest
of
health
and
the
environment.

One
commenter
(
OAR­
2002­
0056­
3469)
believed
the
best
method
for
the
EPA
to
reach
its
goals
for
SO
2,
NO
x
and
mercury
emissions
reductions
and
to
prevent
penalizing
Indian
country
coal
and
already
clean
plants,
would
be
to
require
all
power
plants
producing
more
than
50
MW
in
the
nation
that
are
not
scrubbed,
to
install
emission
control
equipment
that
meets
the
latest
standards.
The
commenter
stated
this
approach
was
preferred
to
cap
and
trade
programs.
5­
7
One
commenter
(
OAR­
2002­
0056­
2519)
noted
that
during
the
summer
of
2002
EPA
initiated
the
two­
year
process
under
the
Clean
Air
Act
Advisory
Committee's
Mercury
Working
Group,
seeking
stakeholder
input
to
develop
the
merury
emissions
control
program.
That
process
considered
various
technical,
policy
and
legal
issues
associated
with
setting
the
MACT
standard.
The
commenter
submitted
that
at
no
time
during
those
deliberations
was
there
any
suggestion
to
utilize
a
cap­
and­
trade
program
in
lieu
of
MACT
standards.
Accordingly,
there
was
no
opportunity
to
fully
assess
and
debate
various
issues
associated
with
such
a
mercury
emissions
control
approach.

One
commenter
(
OAR­
2002­
0056­
3449)
submitted
that
emission
trading
is
not
appropriate
for
HAP
and
that
the
current
Acid
Rain
and
NO
x
SIP
call
programs
are
not
good
models
for
advancing
trading
of
criteria
pollutants
or
mercury.
The
commenter
claimed
some
components
have
proven
problematic.
Unrestricted
banking
has
been
shown
to
be
inappropriate
in
the
SO
2
trading
program;
the
2000
cap
has
yet
to
be
met
because
of
banking.
The
commenter
stated
that
if
it
is
met
anytime
soon,
it
will
be
because
of
NSR
settlements.
The
commenter
believes
banking
would
also
prevent
achievement
of
the
15
tpy
mercury
cap
in
2018
for
at
least
a
decade.

Several
commenters
(
OAR­
2002­
0056­
2364,
­
3435)
claimed
the
mercury
emission
reductions
under
the
section
111
cap­
and­
trade
approach
would
be
too
little
too
late.
One
commenter
(
OAR­
2002­
0056­
2364)
found
this
proposal
inadequate
because:
the
cap
is
too
high
and
EPA
provided
no
justification
for
it
(
installation
of
MACT
controls
should
reduce
emissions
to
about
7.5
tpy),
the
2030
compliance
date
for
reaching
the
cap
is
too
long
and
ignored
attainment
dates
for
the
8­
hr
ozone
and
PM
2.5
rules
(
the
commenter
recommends
a
compliance
date
between
2012
to
2015),
and
would
not
protect
areas
from
localized
hot
spots.
The
second
commenter
(
OAR­
2002­
0056­
3435)
stated
it
is
inappropriate
and
a
dangerous
precedent
to
treat
a
listed
HAP
outside
the
112
framework.

Several
commenters
(
OAR­
2002­
0056­
2695,
­
2814,
­
4190)
submitted
questions
regarding
the
cap
and
trade
program:
(
1)
How
does
EPA
intend
to
provide
accountability
for
the
system?
(
2)
What
are
the
potential
risks
to
endangered
species
and
other
flora
and
fauna?
(
3)
How
will
the
risk
assessment
and
cost
benefit
analysis
include
tribal
values,
unique
exposure
pathways,
and
consumption
levels?
(
4)
Given
that
mercury
is
transported
over
large
areas
and
has
local
impacts,
is
it
environmentally
safe
to
trade
allowances?
(
5)
What
rule
provisions
will
prevent
plants
from
buying
allowances
to
increase
emissions
regardless
of
the
affects
on
surrounding
communities?
(
6)
How
will
EPA
(
or
how
could
tribes)
measure
the
reduction
of
human
and
environmental
exposure?
(
7)
What
is
the
potential
for
creating
hot
spots?
(
8)
How
will
the
program
protect
Indian
resources
used
in
traditional,
cultural,
and
subsistence
practices?

Several
commenters
(
OAR­
2002­
0056­
2871,
­
2889)
contended
that
comparisons
to
the
acid
rain
trading
program
are
inappropriate
because
of
the
nature
of
the
pollutants.
The
commenters
stated
that
the
acid
rain
program
focuses
on
pollutants
with
welfare
effects
while
mercury
is
a
neurotoxin
with
serious
health
effects.
Similarly,
one
commenter
(
OAR­
2002­
0056­
2243)
stated
that
although
NO
x
and
SO
2
trading
programs
are
a
success,
the
commenter
did
not
support
this
approach
with
mercury.
According
to
the
commenter,
trading
5­
8
ounces
of
mercury
did
not
appear
to
be
a
reasonable
approach.
The
commenter
was
concerned
with
the
ability
to
accurately
monitor
and
tabulate
emissions.
Also,
the
commenter
stated
that
a
trading
program
for
hazardous
air
pollutants
could
not
be
viewed
as
a
preferred
control
strategy.

One
commenter
(
OAR­
2002­
0056­
3561),
a
Maine
Congressman
attached
testimony
from
Maine
officials
and
residents
opposing
the
proposal
in
a
state
public
hearing.
[
Note:
attached
testimony
is
not
in
docket].

One
commenter
(
OAR­
2002­
0056­
2836)
consisting
of
US
Senators
and
Congressmen
contended
that
EPA's
weak
proposal
under
CAA
section
111
would
not
result
in
major
reductions
of
mercury
for
at
least
10
years
beyond
the
time
frame
required
for
MACT
standards.
The
commenter
claimed
this
would
result
in
more
pollution
and
health
risk
and
would
fail
to
encourage
new
technology.
The
commenter
noted
that
EPA's
own
modeling
showed
that
Clear
Skies
legislation,
which
calls
for
essentially
the
same
mercury
reduction
on
the
same
schedule
as
the
section
111
approach,
would
exempt
almost
200
of
the
oldest
and
dirtiest
coal­
fired
plants
from
installing
advanced
pollution
controls
for
decades.
It
also
showed
that
the
section
111
approach
would
achieve
at
best
a
58
percent
reduction
in
mercury
emissions
by
2020,
well
below
the
69
percent
goal
for
2018.
The
commenter
stated
that
in
addition,
the
Energy
Information
Administration
predicts
that
the
plants
would
reduce
mercury
emissions
by
only
40
percent
by
2025.
The
commenter
stated
in
addition,
the
section
111
cap
and
trade
approach
would
fail
to
protect
local
populations
from
hot
spots.
The
commenter
submitted
that
EPA
has
instead
committed
to
evaluate
the
health
risks
that
remain
without
committing
to
prevent
or
eliminate
those
risks.

One
commenter
(
OAR­
2002­
0056­
2951)
believed
in
the
recent
debate
over
the
desirability
of
a
"
Cap
and
Trade"
system
for
utility
mercury,
too
much
concentration
has
been
placed
on
the
desirability
of
the
Trading;
yet
the
key
to
maximizing
social
welfare
is
dramatically
reducing
and
accelerating
the
proposed
Cap.
The
commenter
stated
that
it
may
be
comforting
for
economists
to
recognize
that,
given
that
MACT
law
is
eventually
followed
and
the
utility
emission
limits
are
set
at
some
real
semblance
of
"
the
average
of
the
best­
performing
12
percent,"
the
loss
of
the
efficiencies
of
trading
will
not
be
that
great.
According
to
the
commenter,
the
primary
reason
for
this
is
simply
that
if
the
average
required
mercury
reduction
is
truly
in
the
neighborhood
of
80
percent
to
90
percent,
then
there
will
not
be
much
over
compliance
from
which
to
draw
tradable
allowances.
The
commenter
stated
that
mercury
is,
indeed,
an
air
toxic
and
common
sense
dictates
that
if
it
can
be
limited
cost­
effectively
to
a
high
degree
 
and
it
can
 
then
it
deserves
to
be.
The
commenter
believed
emission
allowance
trading
is
just
not
designed
for
accelerated
compliance
with
80+
percent
reduction
requirements.
The
commenter
added
that
further,
because
of
the
nature
of
the
likely
control
methods
to
be
predominately
used
in
complying
with
strict
emissions
limits
 
lower­
mercury
coals
and
sorbent
injection
into
existing
particulate
collectors
 
the
ability
to
trade
emission
allowances
would
yield
only
minimal
economic
gains.
The
commenter
stated
that
coal­
mercury
rationalization
and
sorbent
injection
are
not
capital­
intensive
control
methods:
their
costs
vary
directly
with
their
use.
The
commenter
noted
that
economic
benefits
of
trading
are
maximized
when
great
disparities
in
marginal
compliance
costs
among
units
exist.
The
commenter
believed
this
is
simply
not
turning
out
to
be
the
case
with
utility
mercury.
The
commenter
stated
that
even
in
the
high­
cost
compliance
cases,
like
units
with
hot­
side
ESPs
or
5­
9
those
that
sell
their
fly
ash
for
concrete,
technological
advances
are
reducing
the
compliance
costs
considerably.
(
See
the
Sorbent
Technologies'
presentations
on
the
e­
Docket
at
OAR­
2002­
0056­
1461
and
OAR­
2002­
0056­
1463.)
The
commenter
believed
that
efficiency
analogies
with
the
SO
2­
allowance­
trading
experience
are
simply
not
there.

One
commenter
(
OAR­
2002­
0056­
3398)
opposed
interstate
trading
of
mercury
emissions
because
of
the
potential
for
hot
spots.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111
and
is
finalizing
caps
and
timing
that
are
integrated
with
the
CAIR.
See
final
rule
preamble
for
further
discussion.

5.2
LEGAL
AUTHORITY
FOR
CAP
AND
TRADE
Commenter:

One
commenter
(
OAR­
2002­
0056­
3531)
stated
that
by
implementing
the
program
nationally
and
requiring
EPA's
CAMD
group
to
oversee
the
implementation,
the
rules
will
not
add
any
regulatory
or
cost
burden
to
the
states.

One
commenter
(
OAR­
2002­
0056­
3478)
stated
that
a
cap
and
trade
program
would
have
to
be
set
up
in
an
equitable
manner.
The
commenter
also
stated
that
it
would
be
imperative
that
the
allowance
allocation
system
be
transparent
and
provide
certainty
for
the
units
complying
with
the
cap
and
trade
program.
For
this
reason,
the
commenter
did
not
support
the
cap
and
trade
approach
under
section
111.
The
commenter
believed
that
this
method
would
allow
individual
states
to
determine
whether,
among
other
things,
to
1)
let
its
electric
generators
participate
in
a
national
cap
and
trade
program;
2)
allocate
all,
some,
or
none
of
its
budgeted
allowances
to
the
generators;
3)
auction
the
allowances
back
to
the
generators;
4)
withhold
allowances
from
a
given
generator
or
5)
let
its
generators
buy
and
sell
allowances
out
of
state.
According
to
the
commenter,
in
addition
to
being
a
major
enforcement
and
oversight
challenge
for
EPA,
the
resulting
patchwork
of
conflicting
programs
could
create
even
greater
challenges
to
electric
generators,
endanger
the
stability
of
the
grid,
increase
costs
to
consumers,
and
ultimately
delay
reductions
in
utility
mercury
emissions.

Several
commenters
(
OAR­
2002­
0056­
2046,
­
2247,
­
2871,
­
2887,
­
2889,
­
4139)
feared
a
cap­
and­
trade
program
under
section
111(
d)
would
require
states
to
develop
and
submit
a
SIP­
like
plan
for
approval
to
regulate
existing
facilities
which
would
result
in
a
patchwork
of
varying
regulations
and
limits.
The
commenters
claimed
the
section
111
approach
would
be
time­
consuming,
duplicative,
and
inconsistent.
One
commenter
(
OAR­
2002­
0056­
4139)
stated
also,
there
are
no
assurances
that
EPA
would
consider
depostion
from
an
upwind
state
when
reviewing
the
"
SIP­
like"
control
requirements.
Therefore,
the
section
111(
d)
approach
would
not
protect
the
commenter
from
upwind
states.
5­
10
Several
commenters
(
OAR­
2002­
0056­
1763,
­
4177)
asserted
EPA's
section
111
proposal
is
unworkable
because
EPA
can
only
promulgate
regulations
that
establish
a
procedure
for
states
to
follow
in
establishing
NSPS
for
existing
sources.
This
could
result
in
states
developing
their
own
mercury
plans
rather
than
following
a
consistent
approach.
This
does
not
comport
with
the
national
multi­
pollutant
framework.
One
commenter
(
OAR­
2002­
0056­
4177)
added
that
it
would
be
an
administrative
nightmare
and
many
states
would
opt
out
making
it
useless.
This
approach
would
prolong
implementation,
create
uncertainty,
and
make
an
uneven
playing
field.

Several
commenters
(
OAR­
2002­
0056­
2414,
­
3351)
stated
that
the
CAA
section
111
cap­
and­
trade
alternative
is
not
an
option
for
toxic
air
pollutants.
One
commenter
(
OAR­
2002­
0056­
2414)
submitted
that
section
111
is
designed
only
to
address
emissions
of
non­
hazardous
air
pollutants
from
new
sources.
In
addition,
the
original
intent
of
the
Act
demands
across
the
board
reductions.
By
definition,
a
trading
program
does
not
require
reductions
from
all
sources.
The
second
commenter
(
OAR­
2002­
0056­
3351)
stated
that
section
111
was
designed
to
address
criteria
pollutants
like
SO
2
and
NO
x.

One
commenter
(
OAR­
2002­
0056­
2521)
stated
that
many
stakeholders
have
charged,
and
the
Administration
has
itself
acknowledged,
that
there
are
substantial
questions
as
to
the
legality
of
the
EPA
regulatory
proposal
to
regulate
mercury
under
a
cap­
and­
trade
system,
whether
under
section
111
or
112
of
the
Clean
Air
Act.
According
to
the
commenter,
the
mere
fact
that
these
and
other
legal
questions
were
being
raised,
regardless
of
how
they
are
eventually
resolved,
meant
substantial
delay
and
uncertainty
in
terms
of
putting
stable
standards
in
place.
The
commenter
was
concerned
that
if
the
courts
resolve
the
legal
questions
contrary
to
EPA's
position,
the
Agency
would
have
to
propose
a
stricter
standard­
but
only
after
a
period
of
continued
uncertainty.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111
and
is
finalizing
caps
and
timing
that
are
integrated
with
the
CAIR.
See
final
rule
preamble
for
further
discussion.

Comment:

Several
commenters
(
OAR­
2002­
0056­
1673,
­
2172,
­
2224,
­
2899,
­
2922,
­
2929,
­
3537)
believed
that
EPA
has
the
legal
authority
under
CAA
section
111(
d)
to
establish
a
cap­
and­
trade
program
to
control
mercury
emissions
from
utility
units.

One
commenter
(
OAR­
2002­
0056­
3537)
submitted
that
EPA's
proposal
to
revise
its
"
necessary"
finding
made
in
December
2000
is
supportable
under
the
administrative
record.
The
commenter
believed
EPA's
justification
that
another
viable
statutory
mechanism
exists
to
adequately
address
mercury
(
and
nickel)
emissions
from
coal
(
and
oil­
fired)
Utility
Units
 
CAA
§
111
 
is
legally
justifiable.
The
commenter
also
believed
EPA's
interpretation
of
§
112(
n)(
1)(
A)
 
that
just
because
it
is
appropriate
to
regulate
Utility
Units,
EPA
is
not
compelled
to
regulate
them
under
§
112
if
other
authorities
in
the
CAA
exist
to
adequately
address
health
hazards
that
occur
as
a
result
of
HAP
emissions
 
is
a
reasonable
interpretation
of
the
term
"
necessary"
in
§
112(
n)(
1)(
A).
The
commenter
stated
that
if
EPA
withdraws
its
determination
5­
11
that
regulation
under
§
112
is
necessary,
then
EPA
should
not
be
required
to
go
through
a
formal
de­
listing
procedure
to
remove
Utility
Units
from
the
§
112(
c)
list.
The
commenter
submitted
EPA's
interpretation
of
the
phrase
best
system
of
control,
coupled
with
the
definition
of
standard
performance
in
§
111(
a)
to
allow
a
cap
and
trade
program
is
reasonable
in
the
context
of
establishing
NSPS
for
mercury
pursuant
to
CAA
§
111.
The
commenter
believed
EPA's
analysis
of
the
use
of
§
§
111(
b)
and
(
d)
to
establish
NSPS
for
new
and
existing
coal­
fired
Utility
Units
for
mercury
emissions
is
reasonable
in
the
context
of
establishing
a
cap
and
trade
program
pursuant
to
§
111.
The
commenter
stated
in
summary,
although
it
may
not
be
the
best
approach,
especially
from
an
efficiency
standpoint,
a
cap­
and­
trade
program
established
pursuant
to
§
111
is
a
viable
and
appropriate
statutory
mechanism
by
which
to
regulate
mercury
emissions
from
new
and
existing
coal­
fired
Utility
Units.
However,
should
EPA
proceed
forward
to
establish
a
cap
and
trade
program
pursuant
to
§
111,
the
commenter
believed
that
the
general
approach
outlined
by
the
commenter
in
section
3.24
(
in
OAR­
2002­
0056­
3537)
would
be
a
much
improved
version
of
EPA's
proposed
cap
and
trade
system
in
the
currently
proposed
Mercury
Rule.

Similarly,
another
commenter
(
OAR­
2002­
0056­
2899)
believed
that
CAA
section
112(
n)(
1)(
A)
provides
EPA
with
broad
authority
to
craft
regulations
to
address
any
public
health
concerns
it
identifies.
The
commenter
stated
that
section
112(
n)(
1)(
A)
does
not
require
EPA
to
regulate
under
§
112(
c)
and
(
d);
instead,
the
provision
provides
generally
that
EPA
shall
regulate
under
this
section
if
the
Administrator
finds
that
regulation
is
appropriate
and
necessary.
The
commenter
stated
the
most
consistent
reading
of
§
112(
n)(
1)(
A)
is
that
Congress
intended
EPA
to
consider
a
variety
of
control
options
to
address
whatever
heath
concerns
were
identified
in
the
Report
to
Congress
and
then
to
promulgate
rules
based
on
the
best
of
those
options.
The
commenter
added
that
the
limited
legislative
history
of
§
112(
n)(
1)(
A)
supports
a
broad
grant
of
authority.
The
commenter
stated
this
legislative
history
indicates
that
EPA
has
broad
discretion
to
establish
regulatory
standards,
should
it
find
such
standards
necessary
to
protect
public
health.

One
commenter
(
OAR­
2002­
0056­
2224)
stated
that
it
should
be
emphasized
that
CAA
section
111(
d)(
1)
itself
does
not
independently
mandate
that
standards
of
performance
for
existing
sources
impose
a
source­
specific
requirement
for
continuous
emission
reduction.
According
to
the
commenter,
thus,
a
state
plan
incorporating
a
standard
of
performance
that
employs
a
cap­
and­
trade
mechanism
would
not
conflict
with
the
statutory
requirements
of
section
111(
d)(
1).
Moreover,
the
commenter
believed
that
the
emissions
cap
and
allowance­
holding
requirement
in
EPA's
proposed
section
111(
d)
trading
program
arguably
would
have
the
effect
of
imposing
a
"
continuous
emissions
reduction"
requirement
on
affected
electric
generating
units
(
EGUs).
According
to
the
commenter,
specifically,
the
proposed
section
111(
d)(
1)
cap­
and­
trade
program
would
establish
a
permanent
cap
on
mercury
emissions
and
require
affected
sources
to
hold
allowances
that
correspond
to
the
level
of
mercury
emissions
from
those
sources
at
all
times.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111
and
is
finalizing
caps
and
timing
that
are
integrated
with
the
CAIR.
See
final
rule
preamble
for
further
discussion.

Comment:
5­
12
Many
commenters
(
OAR­
2002­
0056­
2108,
­
2219.
­
2695,
­
2823,
­
2871,
­
2887,
­
2889,
­
3205,
­
3457,
­
4117)
did
not
believe
that
mercury
emissions
trading
is
legal
under
either
section
111
or
112(
d)
of
the
Clean
Air
Act.

The
public
interest
group
comprehensive
comments
(
OAR­
2002­
0056­
3459)
stated
that
the
proposed
cap
and
trade
program
is
not
permitted
under
section
111.
The
commenter
claimed
judicial
decisions
limit
pollution
trading
under
the
CAA
and
do
not
authorize
EPA's
proposed
approach
as
follow:
(
1)
EPA's
attempt
to
permit
even
limited
emission
trading
under
CAA
section
111
has
been
rejected
by
the
U.
S.
Court
of
Appeals
(
ASARCO
v.
EPA,
578
F.
2d
319
(
DC
Cir.
1978).
For
new
and
modified
sources,
EPA
may
allow
some
form
of
intra­
source
trading
to
avoid
the
application
of
PSD
permit
requirements
but
the
offsetting
changes
must
be
within
the
same
source
(
Alabama
Power
Co.
v.
Costle,
636
F.
2d
323,
DC
Cir
1980).
And,
while
Congress
added
provisions
for
trading
programs
in
several
parts
of
the
CAA
as
part
of
the
1990
amendments,
it
did
not
do
so
for
section
111.
(
2)
The
legislative
history
of
CAA
section
111
indicates
a
Congressional
desire
for
uniform
national
standards,
not
a
tradeable
system
of
allowances.
Congress's
manifested
intent
that
every
individual
source
meet
the
same
standard
is
fundamentally
inconsistent
with
a
cap­
and­
trade
program
in
which
some
plants
would
be
able
to
emit
more
than
would
be
allowed
by
a
technology­
based
standard
because
they
have
traded
with
other
plants.
And,
nothing
in
the
legislative
history
suggests
that
the
"
best
system"
be
interpreted
so
broadly.
To
the
contrary,
the
best
system
is
consistently
understood
to
be
the
best
system
that
an
individual
plant
could
implement
and
the
legislative
history
of
the
1990
amendments
reaffirms
that
the
best
system
applies
to
individual
plants
and
not
to
a
novel
regulatory
system.
While
Congress
reverted
to
the
1970
definition
of
"
standard
of
performance"
to
provide
plants
more
flexibility,
this
clearly
was
intended
to
apply
within
the
constraint
of
a
command
and
control
system.

One
commenter
(
OAR­
2002­
0056­
2823)
comprised
of
eleven
State
Attorney
Generals
stated
that
mercury
emissions
trading
is
illegal
and
inappropriate
under
either
section
111
or
112(
d)
Act
because
mercury
emissions
may
be
deposited
in
close
proximity
to
power
plants
resulting
in
"
hot
spots."
The
commenter
submitted
the
following
supporting
information:
(
1)
EPA's
own
report
recognizes
that
buying
allowances
cannot
address
a
hot
spot
if
the
cap
does
not
require
sufficient
reductions
to
minimize
or
prevent
local
impacts.
EPA's
plan
to
evaluate
the
protectiveness
of
the
program
after
2018
provides
no
assurance
that
hot
spots
will
be
adequately
dealt
with.
(
2)
EPA's
proposed
trading
program
does
not
address
mercury
"
hot
spots."
It
is
well
documented
that
mercury
must
be
controlled
at
a
local
level
and
a
national
cap
and
trade
approach
by
itself
will
not
address
local
issues.
Recent
studies
show
considerable
hot
spots
and
that
up
to
95
percent
of
the
mecury
can
be
of
the
reactive
form
that
is
deposited
locally
(
Florida
Everglades,
New
Hampshire
data).
EPA
has
also
ignored
it's
own
policy
statements
that
trading
may
be
inappropriate
for
highly
toxic
pollutants
like
mercury.
(
3)
The
trading
program
as
proposed
does
not
include
adequate
restrictions,
such
as
temporal
restrictions
on
the
use
of
allowances.
EPA
has
ignored
its
own
policy
guidance
on
how
to
design
a
cap
and
trade
program
so
as
to
address
localized
hot
spots.
Also,
EPA's
provision
for
unlimited
flexibility,
such
as
the
proposed
safety
valve,
undermines
any
potential
for
a
trading
program
to
address
hot
spots.
(
4)
Other
regulatory
standards
and
level
of
required
reductions
are
inadequate
to
address
localized
impact.
EPA
fails
to
recognize
that
the
acid
rain
program
has
certain
"
backstops"
that
are
not
in
the
mercury
proposal.
(
See
pages
55­
61).
5­
13
One
commenter
(
OAR­
2002­
0056­
2108)
noted
that
CAA
sections
111(
b)
and
112(
d)
require
a
performance
standard
or
an
emissions
standard.
The
trading
program
does
not
require
a
source
to
achieve
any
particular
level
of
control.

Another
commenter
(
OAR­
2002­
0056­
2219)
pointed
out
that
according
to
EPA
guidance
(
Environmental
Incentive
Performance),
trading
programs
must
be
able
to
quantify
the
pollutant
reduction.
The
commenter
claimed
it
is
not
possible
to
quantify
mercury
emissions
because
baseline
levels
are
not
well
established.
Also,
some
ecosystems
are
more
sensitive
to
mercury
deposition
and
accumulation
than
others,
making
the
need
for
accurate
measurement
imperative.
The
commenter
believed
a
trading
program
should
not
be
allowed
because
it
conflicts
with
EPA
guidance.
One
commenter
(
OAR­
2002­
0056­
2887)
also
strongly
opposed
the
removal
of
coal
and
oil­
fired
units
from
the
list
of
source
categories
in
CAA
section
112(
c).
The
commenter
felt
this
action
would
be
entirely
inconsistent
with
the
air
toxics
program
since
these
units
comprise
one
of
the
largest
sources
of
HAP
in
the
country.
One
commenter
(
OAR­
2002­
0056­
3205)
stated
that
if
EPA
rescinds
its
December
2000
finding
that
it
is
necessary
and
appropriate
to
regulate
HAP
from
coal
fired
utility
units,
the
requirement
for
case­
by­
case
MACT
determinations
for
new
units
required
by
section
112(
g)
would
no
longer
apply.
The
commenter
would
be
adversely
affected
because
the
state
(
Montana)
would
likely
rescind
its
MACT
limit
for
the
proposed
new
Roundup
power
plant
.
The
commenter
concluded
that
although
EPA
has
proposed
a
cap­
and­
trade
program,
if
it
rescinds
the
December
2000
regulatory
finding,
the
commenter
agreed
with
Environmental
Defense
that
the
program
is
unlawful.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111
and
is
finalizing
caps
and
timing
that
are
integrated
with
the
CAIR.
See
final
rule
preamble
for
further
discussion.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2897,
­
3556,
­
3565)
believed
a
nationwide
cap­
and­
trade
program
under
CAA
section
112
would
create
a
more
efficient
regulatory
structure
than
a
similar
program
under
CAA
section
111.
One
commenter
(
OAR­
2002­
0056­
2897)
stated
the
111
approach
recognizes
the
inherent
cost­
effectiveness
of
emission
trading
compared
to
traditional
command­
and­
control
regulation;
however,
the
commenter
stated
the
practical
problems
with
section
111
are
evident.
In
the
commenter's
view,
the
111(
d)
approach,
while
well
intended
would
not
be
a
market­
based
approach
and
would
result
in
extended
delays
in
achieving
its
intended
purpose.
The
commenter
believed
the
111(
d)
program
inherently
withdraws
the
incentive
offered
to
the
early
innovator
and
the
early
investor.
The
commenter
added
that
under
111,
it
will
take
years
to
have
any
understanding
of
the
final
approved
plans,
and
the
careful
investor
will
withhold
investment
until
it
can
better
understand
which
states
are
in,
which
states
are
out,
and
which
states
will
reward
investment.
The
commenter
stated
this
would
only
result
in
delays
in
commercializing
of
remediation
technology.
The
commenter
added
that
lack
of
a
national
allowance
system
would
only
create
further
investment
delays.
According
to
the
commenter,
it
appeared
likely
the
111(
d)
approach
already
lacks
state
support.
For
example,
the
commenter
noted
the
Northeast
OTC
"
does
not
support
a
cap­
and­
trade
for
Mercury
(
Hg)
5­
14
beyond
a
facility's
borders.
The
OTC
supports
a
bubble
concept
for
mercury
at
a
given
facility."
The
commenter
also
noted
that
eleven
of
the
12
OTC
states
voted
to
oppose
any
cap­
and­
trade
program
for
mercury,
with
Virginia
abstaining.
The
commenter
concluded
that
if
the
purpose
of
this
rulemaking
is
to
get
the
international
ball
rolling
then
the
112(
n)(
1)(
a)
approach
offers
the
most
likely
manner
of
expediting
commercialized
remediation
technology.

A
second
commenter
(
OAR­
2002­
0056­
3556)
believed
that
the
Clean
Air
Act
provides
EPA
with
broad
discretion
as
to
how
it
chooses
to
regulate
EGUs
for
HAPs
emissions.
The
commenter's
preference
and
recommendation
was
that
the
Agency
do
so
under
the
provisions
of
CAA
section
112(
n)(
1)(
A).
The
commenter
believed
that
this
section
would
provide
EPA
with
the
discretion
it
requires,
yet
would
create
a
program
with
a
uniform
format
that
is
national
in
scope.
The
commenter
strongly
believed
that
a
Federally
operated,
national
emissions
trading
program
is
essential
if
this
effort
is
to
achieve
the
desired
emissions
reduction
in
the
quickest
and
most
economical
manner.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111
and
is
finalizing
caps
and
timing
that
are
integrated
with
the
CAIR.
See
final
rule
preamble
for
further
discussion.

5.3
NATIONWIDE
CAP
AND
COMPLIANCE
DATES
5.3.1
Timing
of
Compliance
Dates
Comment:

Several
commenters
(
OAR­
2002­
0056­
1625,
­
1673,
­
1768,
­
1814,
­
2117)
expressed
concern
over
the
proposed
mercury
rule
and
the
Interstate
Air
Quality
Rule
(
IAQR).
One
commenter
(
OAR­
2002­
0056­
1625)
stated
that
a
potential
timing
issue
would
be
the
possible
requirement
of
mercury
reductions
to
take
place
in
2008,
2
years
before
the
SO
x
and
NO
x
reductions
of
the
Interstate
Air
Quality
proposal.
The
commenter
submitted
that
EPA
must
harmonize
the
mercury
compliance
dates
with
the
deadlines
for
the
SO
x
and
NO
x
reductions.
For
an
effective
multi­
pollutant
control
strategy
that
best
mirrors
the
advantages
of
Clear
Skies,
another
commenter
(
OAR­
2002­
0056­
1673)
stated
that
EPA
must
coordinate
and
harmonize
the
mercury
rule
and
IAQR
as
much
as
possible.
In
setting
reduction
targets
and
compliance
deadlines
for
individual
pollutants,
several
commenters
(
OAR­
2002­
0056­
1673,
­
1768)
stated
that
EPA
should
fully
consider
the
co­
benefits
that
pollution
controls
such
as
SO
2
scrubbers
and
SCR
controls
will
have
for
reduction
of
other
pollutants.
The
commenters
believed
that
aligning
reduction
targets
and
compliance
deadlines
would
allow
companies
to
address
SO
2,
NO
x,
and
mercury
in
one
integrated
step,
rather
than
two.
The
commenters
submitted
this
would
promote
the
efficient
utilization
of
resources
and
better
ensure
timely
compliance.
The
commenters
added
therefore,
it
is
critical
for
the
Phase
I
compliance
dates
under
both
rules
to
be
set
for
2010.
The
commenters
believed
that,
as
in
Clear
Skies,
the
Phase
I
mercury
reduction
targets
should
be
set
at
the
co­
benefit
level
resulting
from
Phase
I
of
the
IAQR.
Failure
to
align
these
deadlines
and
5­
15
reduction
targets
would
not
only
increase
compliance
costs
substantially,
but
could
actually
impede
the
early
installation
of
the
most
effective
control
technologies.

Another
commenter
(
OAR­
2002­
0056­
1814)
stated
that
EPA
has
taken
the
innovative
approach
of
proposing
the
IAQR
rules
at
the
same
time
as
the
mercury
rules.
The
commenter
also
stated
that
this
is
important
because
controls
that
would
be
required
under
the
IAQR
will
achieve
significant
reductions
in
mercury
emissions,
through
co­
benefits
of
the
control
devices.
The
commenter
believed
setting
the
Phase
I
target
at
the
level
of
co­
benefits
of
SO
2
and
NO
x
control
is
appropriate
considering
the
low
concentrations
emitted
from
power
plants
and
the
difficulty
of
achieving
mercury
reductions.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111
and
is
finalizing
caps
and
timing
that
are
integrated
with
the
CAIR.
See
final
rule
preamble
for
further
discussion.

Comment:

One
commenter
(
OAR­
2002­
0056­
3431)
stated
that
the
small
and
medium­
sized
units
that
risk
shutdown
if
unit­
specific
controls
were
mandated
are
not
expendable;
they
provide
a
valuable
electric
service
reliability
benefit
to
the
national
grid.
The
commenter
added
that
specifically,
they
provide
operating
reserves,
load
balancing
capability,
regulation,
and
voltage
support.
The
commenter
believed
based
on
the
current
demands
on
the
grid,
it
is
critical
this
reliability
support
not
be
ignored,
particularly
when
EPA
can
achieve
the
same
or
better
aggregate
reduction
of
mercury
emissions
utilizing
a
mandated
cap
and
trade
program.
Similarly,
one
commenter
(
OAR­
2002­
0056­
2431)
argued
that
an
unreasonably
accelerated
compliance
schedule
for
a
MACT
standard
could
lead
to
reliability
problems
and
outages
for
equipment
installation
when
this
rule
and
the
IAQR
rule
are
considered.
The
commenter
also
noted
that
new
control
technologies
are
2­
3
years
from
completing
demonstration.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111
and
is
finalizing
caps
and
timing
that
are
integrated
with
the
CAIR.
See
final
rule
preamble
for
further
discussion.

Comment:

Many
commenters
(
OAR­
2002­
0056­
1768,
­
2042,
­
2123,
­
2224,
­
2833,
­
2844,
­
2906,
­
2907,
­
3443,
­
3537)
stated
that
the
cap­
and­
trade
approach
to
mercury
control
should
be
adopted
in
conjunction
with
the
proposed
interstate
air
quality
rules.
One
commenter
(
OAR­
2002­
0056­
2906)
supported
an
approach
of
imposing
mercury
emission
reductions
to
a
level
commensurate
with
co­
benefits
achieved
through
the
SO
2
and
NO
x
emissions
reductions
of
the
CAIR.
The
commenter
noted
however,
those
reductions
must
be
made
in
an
equitable
fashion
between
coal
ranks,
recognizing
the
inherent
difference
in
trace
metal
concentration,
and
the
differing
ability
of
SO
2
and
NO
x
emission
control
systems
to
remove
mercury
from
those
different
5­
16
coal
ranks,
with
consideration
of
chlorine
content
impact.
The
commenter
believed
this
approach
would
help
to
mitigate
the
costs
of
compliance,
which
would
be
borne
by
all
electricity
consumers.

Similarly,
one
commenter
(
OAR­
2002­
0056­
1768)
stated
that
the
final
rule
should,
to
the
greatest
extent
possible,
rely
on
SO
2
and
NO
x
control
technologies
to
meet
mercury
reduction
obligations.
One
commenter
(
OAR­
2002­
0056­
2224)
stated
EPA's
proposed
cap­
and­
trade
option
would
be
the
best
way
to
ensure
the
mercury
co­
benefits
reductions
can
be
realized
by
achieving
significant,
cost­
effective
reductions
for
all
three
pollutants
at
the
same
time.
The
commenter
stated
that
working
within
a
rigorous
MACT­
regulatory
context
instead
of
a
cap­
and­
trade
framework
would
afford
EPA
and
industry
much
less
flexibility
in
terms
of
timing
of
compliance.
The
commenter
noted
that
the
statute
allows,
at
most,
three
years
for
meeting
the
MACT
emissions
limits.
The
commenter
also
pointed
out
that
although
a
compliance
extension
would
be
possible,
CAA
section
112(
i)(
3)(
B)
provides
only
a
one­
year
extension
in
cases
where
"
such
addition
period
is
necessary."
The
commenter
added
that
furthermore,
the
CAA
only
authorizes
longer
extensions
in
time
through
a
"
Presidential
Exemption."
According
to
the
commenter,
this
statutory
provision
has
never
been
used
and
does
not
authorize
an
extension
of
the
compliance
deadline
unless
the
following
two
criteria
have
been
met:
1)
that
"`
the
technology
to
implement
such
standard
is
not
available,"
and
2)
that
a
compliance
extension
"
is
in
national
security
interests
of
the
United
States."
According
to
the
commenter,
it
was
far
from
clear
whether
both
criteria
could
ever
be
satisfied,
which
only
exacerbates
the
lack
of
regulatory
certainty
for
the
power
sector.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111
and
is
finalizing
caps
and
timing
that
are
integrated
with
the
CAIR.
See
final
rule
preamble
for
further
discussion.

Comment:
One
commenter
(
OAR­
2002­
0056­
1768)
supported
the
concept
of
multi­
emissions
regulation,
but
was
concerned
over
the
economic
and
technological
feasibility
of
the
basic
time
frames
and
levels
of
reductions
under
the
trading
options.
The
commenter
encouraged
the
EPA
to
incorporate
provisions
to
lengthen
the
time
frames
and
levels
should
achievement
not
be
possible
in
the
proposed
rules.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111and
is
finalizing
caps
and
timing
that
is
integrated
with
the
Clean
Air
Interstate
Rule.
See
final
rule
preamble
for
further
discussion.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2160,
­
2375,
­
2818,
­
2833,
­
2835,
­
2844,
­
2867,
­
2899,
­
3531)
stated
that
the
compliance
dates
for
emission
controls
for
mercury
should
be
coordinated
with
the
compliance
dates
for
controls
for
sulfur
dioxide
and
nitrogen
oxides
under
5­
17
the
proposed
Interstate
Air
Quality
Rule.
The
commenters
submitted
that
if
EPA
harmonizes
the
mercury
rule
deadline
with
the
IAQR
Phase
I
deadline,
sources
will
be
able
to
coordinate
their
planning
and
avoid
wasteful
investments
in
pollution
controls
and
maximize
the
mercury
removal
co­
benefits
from
SO
2
and
NO
x
controls.
One
commenter
(
OAR­
2002­
0056­
2818)
pointed
out
that
given
EPA's
determination
that
the
coordinated
regulation
of
mercury,
sulfur
dioxide
and
nitrogen
oxides
allows
mercury
reductions
to
be
achieved
in
a
cost
effective
manner
due
to
the
co­
benefit
of
mercury
removal
to
be
derived
form
controls
for
sulfur
dioxide
and
nitrogen
oxides,
it
would
be
reasonable
and
in
the
national
interest
to
have
the
mercury
compliance
deadlines
match
those
under
the
proposed
Interstate
Air
Quality
Rule.

Several
commenters
(
OAR­
2002­
0056­
2915,
­
4132)
expressed
concern
that
the
deadlines
for
having
emissions
controls
installed
and
operational
in
the
mercury
rule
and
in
the
CAIR
may
not
be
the
same.
One
commenter
(
OAR­
2002­
0056­
2915)
stated
that
after
EPA
lengthens
the
compliance
deadlines
in
the
mercury
rule
compared
to
the
proposed
compliance
deadlines,
EPA
would
need
to
establish
CAIR
compliance
deadlines
such
that
they
are
synchronized
with
such
lengthened
compliance
dates
in
the
mercury
rule
to
allow
electric
generators
to
develop
cost­
effective
planning
strategies
that
allow
them
to
take
advantage
of
co­
benefit
mercury
emissions
reductions
that
can
be
achieved
through
SO
2
and
NO
x
control
technologies.
The
commenters
claimed
that
failure
to
synchronize
these
deadlines
could
affect
electric
rates
and
reliability.

Several
commenters
(
OAR­
2002­
0056­
2830,
­
2850,
­
3443)
stated
that
the
first
phase
of
the
CAIR
and
the
first
phase
compliance
date
for
mercury
under
a
cap
and
trade
scheme
should
be
delayed.
Several
commenters
(
OAR­
2002­
0056­
2830,
­
2850)
noted
that
2010
was
established
as
the
date
for
first
phase
compliance
for
SO
2
and
NO
x
under
the
Clear
Skies
legislation.
Two
years
have
elapsed
since
Clear
Skies
was
proposed.
The
commenters
recommended
that
the
first
phase
of
the
CAIR
and
the
first
phase
compliance
date
for
mercury
under
a
cap
and
trade
scheme
should
be
delayed
2
years,
i.
e.,
from
2010
to
2012.
One
commenter
(
OAR­
2002­
0056­
3443)
stated
that
in
their
comments
on
the
CAIR,
they
noted
the
likely
scheduling
problems
associated
with
fabricating
the
control
equipment
and
obtaining
requisite
permits
for
waste
disposal.
For
these
reasons,
the
commenter
recommended
that
the
CAIR
schedules
be
adjusted
to
make
the
first
phase
effective
in
2011
and
the
second
phase
in
2016.
Consistent
with
these
earlier
comments,
the
commenter
would
expect
the
timing
of
Phase
I
under
both
rules
be
linked
such
that
if
the
CAIR
schedule
is
adjusted,
the
mercury
schedule
would
follow
suit.
The
commenter
stated
that
synergy
between
the
two
rules
will
facilitate
the
reduction
of
emissions
of
multiple
pollutants
(
SO
2,
NO
x,
and
Hg)
in
a
cost­
effective
manner.
If
Phase
I
of
the
CAIR
is
delayed,
the
commenter
believed
the
onset
of
the
mercury
program
should
also
be
delayed
and
sources
be
allowed
to
earn
early
reduction
credits
in
the
interim
prior
to
the
onset.
The
commenter
submitted
that
this
is
an
environmentally
preferable
approach
since
early
reductions
would
be
achieved
while
still
ensuring
that
the
two
rules
are
implemented
in
tandem.

One
commenter
(
OAR­
2002­
0056­
2521)
stated
that
the
Clean
Air
Planning
Act
proposes
a
24­
ton
cap
in
2009
on
mercury
emissions
from
the
industry
sector,
and
the
Northeast
States
for
Coordinated
Air
Use
Management
(
NESCAUM)
equates
the
commenter's
recommendation
to
the
Working
Group
with
a
13.1­
ton
cap
in
2008.
In
light
of
its
view
that
these
targets
are
5­
18
achievable,
the
commenter
anticipated
no
need
for
a
one­
year
extension
(
from
2008
to
2009)
for
the
implementation
of
the
34­
ton
cap
that
EPA
proposed.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111
and
is
finalizing
caps
and
timing
that
are
integrated
with
the
CAIR.
See
final
rule
preamble
for
further
discussion.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2833,
­
3440,
­
3530)
stated
that
in
the
final
rule,
EPA
must
not
tighten
the
standards
or
compliance
deadlines
set
forth
in
the
proposed
rule.
The
commenters
submitted
that
the
reduction
requirements
in
the
proposed
rule
are
extremely
aggressive
and
will
be
very
difficult
for
many
companies
to
meet.
One
commenter
(
OAR­
2002­
0056­
3440)
noted
the
first
phase
is
proposed
to
take
effect
in
2010,
leaving
companies
only
5
years
to
make
decisions
on
the
type
of
control
and
to
set
about
procuring
contracts
for
labor
and
materials.
The
commenter
stated
this
is
particularly
concerning
for
the
Texas
lignite
units,
the
majority
of
which
are
fitted
with
sulfur
dioxide
controls
already
and
have
no
demonstrated
control
technology
available
for
mercury
removal.
Given
that
national
applicability
of
this
rule,
Texas
utilities
will
not
be
the
only
ones
involved
in
this
process.
The
commenter
was
concerned
about
the
effect
on
labor
and
material
costs
to
the
electric
generators
as
a
result
of
such
a
shortened
timeframe.
All
of
the
commenters
believed
it
is
important
for
the
deadlines
and
emission
reduction
levels
to
be
tied
to
the
practicability
of
hundreds
of
units
to
acquire
labor,
materials
and
permits
and
control
technologies
(
many
at
the
same
time)
in
order
to
install
controls
without
sacrificing
reliable
and
low­
cost
electric
generation.
Several
commenters
(
2833,
3530)
believed
EPA
should
provide
for
time
extensions
for
companies
to
comply
with
the
standards
if
they
can
demonstrate
reasonable
concern
for
grid
reliability
or
security
problems,
technological
infeasibility
or
financial
hardship.
One
commenter
(
OAR­
2002­
0056­
2833)
stated
that
EPA
should
determine
whether
and
when
reliable,
cost­
effective
control
technologies
to
capture
mercury
emissions
will
be
fully
developed
and
tested
or
made
commercially
available
on
a
wide­
enough
scale
to
reduce
mercury
emissions.

Many
commenters
(
OAR­
2002­
0056­
2067,
­
2332,
­
2375,
­
2441,
­
2551,
­
2899,
­
2915,
­
2929,
­
3510,
­
3531)
expressed
concern
that
the
proposed
compliance
schedule
might
not
allow
sufficient
time
to
install
the
control
technologies
that
will
be
needed
to
meet
the
CAIR
and
mercury
program
mandates,
especially
for
reductions
required
by
2010.
Several
commenters
(
OAR­
2002­
0056­
2899,
­
2915)
observed
that
EPA
predicts,
based
on
the
CAIR
proposal,
that
almost
80
GW
of
capacity
would
install
either
flue
gas
desulfurization
or
selective
catalytic
reduction
to
reduce
SO
2
and
NO
x,
respectively,
between
2005
and
2010.
The
commenters
also
noted
that
EPA
assumes
that
companies
will
not
begin
construction
activities
until
2007
when
the
states
and
EPA
finalize
requirements,
leaving
just
parts
of
three
years
(
2007,
2008
and
2009)
to
install
control
technologies
on
hundreds
of
generating
units.

These
commenters
(
OAR­
2002­
0056­
2899,
­
2915)
stated
simultaneous
installations
of
controls
under
the
CAIR
and
mercury
programs
at
hundreds
of
units
would
stress
labor,
5­
19
materials,
and
state
and
local
permitting
agencies.
The
commenters
explained
that
the
process
for
a
single
installation
would
involve
a
complicated
engineering
review,
negotiation
of
contracts
with
vendors,
obtaining
permits
from
local
and
state
authorities,
and
engaging
contractors,
materials
and
machinery
at
the
site
for
construction.
The
commenters
added
that
all
this
would
be
done
in
an
environment
of
limited
availability
of
expert
labor,
especially
for
boilermakers;
in
addition
to
a
shortage
of
boilermakers,
there
could
be
a
shortage
of
electricians,
pipefitters
and
ironworkers.
The
commenters
also
stated
that
installations
take
the
plant
off­
line
for
weeks,
and
such
outages
must
be
coordinated
within
the
company
and
throughout
the
region
with
other
types
of
outages
in
order
to
avoid
stretching
the
generation
capacity
too
thin
and
exposing
the
grid
to
upset
and
potential
blackouts.

One
commenter
(
OAR­
2002­
0056­
2899)
noted
EPA
assumes
that
the
CAIR
installations
can
be
done
hundreds
of
times
concurrently,
in
less
time
than
electric
companies
believe
possible.
According
to
the
commenter,
installing
one
scrubber
requires
approximately
48­
54
months:
about
12
months
to
select
the
appropriate
technology
and
establish
design
criteria;
12­
18
months
for
engineering
and
design;
and
24­
30
months
(
depending
on
weather)
for
construction
and
startup.
The
commenter
added
that
the
permitting
process
can
take
years,
especially
for
a
new
landfill.
The
commenter
submitted
that
these
time
constraints
would
most
likely
be
longer
with
hundreds
of
affected
sources
installing
control
equipment
within
the
same
time
frame.
The
commenter
added
that
the
demand
for
labor
for
complying
with
the
industrial
boiler
MACT
program
will
further
strain
the
labor
supply.

The
commenter
(
OAR­
2002­
0056­
2899)
noted
that
the
Utility
Air
Regulatory
Group
(
UARG)
concluded
that
the
probability
is
high
that
the
boilermaker
labor
pool
will
not
be
sufficient
to
install
all
of
the
necessary
control
technology
by
2010;
that
is,
1)
EPA
has
optimistically
assumed
that
all
of
the
boilermakers
who
would
be
available
for
work
on
electric
utility
environmental
retrofit
projects
would
be
fully
utilized,
40
hours
a
week
for
50
weeks
a
year,
and
2)
alternative
electricity
demand
growth
projections
of
the
Energy
Information
Administration
(
EIA)
would
require
15
percent
greater
retrofits.

One
commenter
(
OAR­
2002­
0056­
2661)
stated
that
rural
electric
cooperatives
generally
have
systems
that
are
smaller
with
fewer
units
than
the
average
utility
and,
therefore,
would
have
an
even
more
difficult
time
competing
for
limited
resources
and
equipment.
Also,
the
commenter
noted
that
the
time
needed
by
cooperatives
to
obtain
financing
from
the
Department
of
Agriculture
Rural
Utility
Services
would
not
support
a
three
or
four­
year
compliance
schedule,
which
is
key
to
providing
safe,
affordable,
and
reliable
energy
needs
of
our
member­
owners.
The
commenter
believed
installation
of
any
mercury
control
requirements
must
coincide
and
be
integrated
with
existing
and
new
SO
2,
NO
x
and
particulate
control
measures
required
over
the
next
decade.

One
commenter
(
OAR­
2002­
0056­
2067)
stated
that
financing
arrangements
can
pose
significant
obstacles
to
a
relatively
short
compliance
period,
especially
for
public
power
entities.

One
commenter
(
OAR­
2002­
0056­
2441)
stated
mercury­
specific
controls
do
not
exist
yet
on
a
commercially
available
basis
and
new
regulations
must
provide
adequate
time
for
the
5­
20
commercial
development
of
control
technologies
capable
of
meeting
emission
reduction
targets.
Similarly
several
commenters
OAR­
2002­
0056­
2915,
­
3510)
submitted
that
demonstrated
control
technology
does
not
exist
to
reduce
mercury
emissions
from
Gulf
Coast
lignite­
fired
power
plants.
Commenter
OAR­
2002­
0056­
2915
noted
that
the
majority
of
Gulf
Coast
lignite­
fired
EGUs
are
fitted
with
SO
2
controls
already.

One
commenter
(
OAR­
2002­
0056­
2929)
stated
that
in
its
CAIR
comments,
the
commenter
suggested
that
EPA
take
into
consideration
the
difficulty
for
some
companies
to
meet
the
2010
targets
and
provide
a
regulatory
fix
to
this
almost
inevitable
problem.
The
commenter
submitted
the
same
regulatory
considerations
should
be
provided
for
a
mercury
cap­
and­
trade
program
that
relies
on
supposed
CAIR
co­
benefits.

One
commenter
(
OAR­
2002­
0056­
2422)
favored
the
longer
time
frames
for
compliance
that
are
available
under
cap­
and­
trade
alternatives.
The
commenter
believed
that
with
the
absence
of
commercially
demonstrated
technologies
for
controlling
mercury
emissions
from
coal­
fired
power
plants,
a
longer
compliance
timetable
such
as
2018
would
provide
needed
time
for
the
testing,
demonstration
and
commercialization
of
Activated
Carbon
Injection
and
similarly
promising
mercury
control
technologies.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111
and
is
finalizing
caps
and
timing
that
are
integrated
with
the
CAIR.
See
final
rule
preamble
for
further
discussion.
EPA
believes
its
timeframe
is
appropriately
addresses
the
time
needed
to
install
controls
and
the
concerns
about
financing
controls.
See
final
rule
preamble
for
further
discussion.

Comment:

Many
commenters
stated
that
the
compliance
time
frame
for
the
cap
and
trade
program
(
2018)
is
too
long.
The
commenters
noted
that
banking
provisions
extend
the
compliance
date
for
14
years
or
more.
This
would
be
counter
to
Clean
Air
Act
requirements
and
also
is
at
odds
with
settlement
agreement.
These
commenters
supported
an
earlier
time
frame
using
the
existing
provisions
of
the
Clean
Air
Act
for
extensions
under
section
112(
i)
to
allow
time
to
install
controls
or
longer,
using
the
Presidential
exemption
provision.
One
commenter
(
OAR­
2002­
0056­
2064)
added
that
DOE
is
expected
to
have
cost
effective
mercury
control
available
by
2010.
EPA's
mercury
rule
should
at
least
be
consistent
with
that
timing.
One
commenter,
OAR­
2002­
0056­
2094,
also
believed
reductions
should
occur
by
2010
and
the
Clean
Air
Act
has
provisions
to
accomodate
this
timeframe.
Several
commenters
(
OAR­
2002­
0056­
2094,
­
2108)
also
explained
that
compliance
is
needed
by
2010
for
states
to
have
TMDLs
in
place
by
2015
to
address
impaired
waters
as
required
under
the
CWA.
Another
commenter
suggested
that
mercury
controls
should
be
in
place
at
the
same
time
as
control
for
other
pollutants.

One
commenter
(
OAR­
2002­
0056­
2247)
asserted
the
final
mercury
cap
must
be
in
place
sooner
than
2018.
The
commenter
concluded
that
the
availability
of
labor
is
not
a
real
constraint
5­
21
as
suggested
by
EPA
in
its
rationale
for
the
proposed
effective
dates
of
the
caps.
The
commenter
noted
that
EPA's
own
analysis
shows
that
recent
power
plant
activity
due
to
the
NO
x
SIP
call
has
increased
the
labor
supply
and
other
EPA
analyses
show
that
there
is
sufficient
boilermaker
labor
to
meet
the
IAQR
needs.
This
analysis
did
not
take
into
account
any
increase
in
number
of
boilermakers
as
a
result
of
new
demand.
The
commenter
stated
that
the
effective
date
for
mercury
should
be
the
same
as
the
IAQR­
an
interim
cap
in
2010
and
a
final
cap
in
2015.
This
would
not
change
the
costs
for
a
significant
portion
of
the
units
and
would
force
control
technology
development
at
a
slightly
aggressive
date.
The
commenter
believed
an
earlier
date
would
not
seriously
compromise
a
plant's
ability
to
plan
and
execute
mercury
reduction
requirements.
An
earlier
deadline
would
also
help
to
make
technology
available
sooner
to
developing
countries
like
China.
The
commenter
submitted
this
would
better
address
concerns
about
mercury
from
global
sources
if
we
could
offer
cost
effective
methods
and
deploy
it
sooner.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111
and
is
finalizing
caps
and
timing
that
are
integrated
with
the
CAIR.
See
final
rule
preamble
for
further
discussion.
EPA
believes
its
timeframe
is
appropriately
addresses
the
time
needed
to
install
controls
and
the
concerns
about
financing
controls.
See
final
rule
preamble
for
further
discussion.

Comment:

Several
commenters
(
OAR­
2002­
0056­
1673,
­
2243,
­
2830,
­
2850,
­
2879,
­
2922,
­
3463,
­
3469,
­
3539,
­
3548)
supported
EPA's
efforts
to
coordinate
the
mercury
emissions
reduction
program
with
the
sulfur
dioxide
and
nitrogen
oxides
reductions
proposed
under
the
IAQR
rule.
One
commenter
(
OAR­
2002­
0056­
2850)
noted
that
keeping
the
timing
of
mercury
rule
control
requirements
compatible
with
the
IAQR
should
assure
that
cobenefits
from
SO
2
and
NO
x
cap
and
trade
methodology
are
not
sub­
optimized
due
to
accelerated
mercury
control
timing
requirements.
Another
commenter
stated
that
a
multi­
phased
and
balanced
national
cap
and
trade
program
would
take
advantage
of
the
co­
benefits
derived
from
implementation
of
the
IAQR
while
providing
time
for
the
full
development
and
installation
of
mercury­
specific
control
equipment.

Several
commenters
(
OAR­
2002­
0056­
2862,
­
3463)
stated
that
compliance
deadlines
for
UMRR
should
be
set
to
match
the
deadlines
that
are
established
for
compliance
with
the
phases
of
the
IAQR
cap­
and­
trade
program.
One
commenter
(
OAR­
2002­
0056­
2826)
noted
EPA's
proposed
IAQR
requires
compliance
with
Phase
I
SO
2
and
NO,
emission
reductions
by
2010
and
compliance
with
Phase
II
SO
2
and
NO,
emission
reductions
by
2015.
EPA's
MACT
option
specifies
a
2008
compliance
deadline,
while
EPA's
Cap
and
Trade
options
under
section
112
or
section
111
specify
a
2010
Phase
I
compliance
deadline.
The
section
111
and
112
Cap
and
Trade
Options
also
include
a
Phase
II
compliance
date
of
2018.
One
commenter
(
OAR­
2002­
0056­
3436)
noted
that
these
deadlines
should
be
adjusted
if
the
IAQR
timeline
is
adjusted.
However,
the
commenter
recommended
that,
if
anything,
the
deadlines
be
pushed
further
back
into
the
future
in
order
to
allow
time
for
the
development
of
mercury
control
and
monitoring
technologies
for
emissions
from
coal­
fired
power
plants.
Similarly
another
commenter
(
OAR­
2002­
0056­
3469)
recommended
that
the
compliance
time
frames
proposed
under
the
5­
22
UMRR
and
IAQR
be
consistent
and
adjusted
to
reflect
the
two
years
which
have
passed
since
Clear
Skies
was
first
proposed.
The
commenter
stated
that
this
would
set
the
first
phase
compliance
date
for
a
cap
and
trade
program
at
2012.
An
additional
commenter
(
OAR­
2002­
0056­
3548)
also
strongly
supported
EPA's
efforts
to
coordinate
the
schedules
of
the
proposed
IAQR
and
mercury
rules,
as
many
of
the
controls
expected
to
be
needed
for
the
IAQR
may
also
address
emissions
of
mercury.

One
commenter
(
OAR­
2002­
0056­
1673)
submitted
that
to
ensure
a
broad
range
of
compliance
options,
the
cap­
and­
trade
program
under
the
UMRR
and
IAQR
should
be
consistent
with
previous
trading
rules.

One
commenter
(
OAR­
2002­
0056­
2243)
stated
that
in
a
cap
and
trade
environment,
addressing
mercury,
NO
x,
and
SO
2
simultaneously
will
insure
that
adequate
allowances
will
be
available
for
either
existing
unit
expansion
and/
or
new
project
construction.

Several
commenters
(
OAR­
2002­
0056­
1889,
­
2323,
­
2346)
stated
that
the
cap­
and­
trade
program
can
be
coordinated
with
the
timing
of
SO
2
and
NO
x
controls
proposed
under
the
IAQR
and
should
be
a
nation­
wide
program.
The
commenters
also
stated
that
this
coordination
will
enable
power
generators
to
take
full
advantage
of
the
way
SCR
and
scrubber
systems
can
help
reduce
mercury
emissions
while
also
reducing
SO
2
and
NO
x.
Several
of
the
commenters
(
OAR­
2002­
0056­
1889,
­
2323)
believed
this
allowance
allocation
system
should
mirror
the
methodology
used
in
the
successful
acid
rain
control
program.

One
commenter
(
OAR­
2002­
0056­
2346)
supported
a
multi­
pollutant,
market­
based
approach
and
believed
that
with
some
enhancements,
the
IAQR
could
be
a
vital,
cost­
effective
air
regulatory
program
for
the
United
States.
The
commenter
stated
that
the
proposed
cap­
and­
trade
program
is
superior
to
the
MACT
program
because
1)
Cap­
and­
trade
would
reduce
mercury
emissions
by
almost
70
percent
from
2001
levels,
achieving
the
MACT
goal
by
2010
and
capping
emissions
at
15
tons
in
2018.
The
MACT
would
only
reduce
these
emissions
from
coal
fired
power
plants
by
29
percent
from
2001
levels
by
2007;
2)
There
is
no
commercially
available
mercury
control
technology
for
coal
fired
power
plants.
Therefore,
it
would
be
impossible
for
the
industry
to
comply
with
the
MACT
timetable
of
2007;
and
3)
The
cap­
and­
trade
program
can
be
coordinated
with
the
timing
of
SO
2
and
NO
x
controls
proposed
under
the
IAQR
and
should
be
a
nation­
wide
program.

One
commenter
(
OAR­
2002­
0056­
3830)
has
publicly
supported
the
Clear
Skies
Initiative
and
supports
a
coordinated
approach
to
utility
emission
reductions
that
would
provide
a
"
systems"
approach,
thus
reducing
uncertainty
and
cost.
The
commenter
believed
EPA's
intent
to
coordinate
the
development
of
the
proposed
Mercury
and
CAIR
rules
would
provide
a
more
cost­
effective
approach
to
developing
emission
control
systems.
The
commenter
supported,
in
concept,
the
cap
and
trade
as
it
would
allow
time
for
the
development
of
potentially
cost­
effective
control
technologies
and
would
offer
a
more
reasonable
implementation
schedule.

One
commenter
(
OAR­
2002­
0056­
2911)
has
been
an
advocate
for
a
multi­
pollutant
approach
to
address
the
need
for
the
electric
generation
industry
to
make
further
reductions
in
the
5­
23
emissions
of
SO
2,
NO
x
and
mercury.
The
commenter
believed
that
a
comprehensive
program
would
produce
those
reductions
faster
and
more
cost­
effectively
than
the
traditional
regulatory
approach.
The
commenter
stated
that
EPA
is
to
be
commended
for
its
efforts
to
craft
a
regulatory
framework
to
implement
such
a
program.
However,
the
commenter
believed
that
a
multi­
pollutant
approach
would
be
best
implemented
through
legislation.
The
commenter
stated
that
EPA
faces
many
obstacles
as
it
moves
to
implement
a
multi­
pollutant
program
for
EGUs,
within
the
existing
framework
of
the
Clean
Air
Act
 
particularly
with
respect
to
keeping
the
schedules
of
the
CAIR
and
the
proposed
mercury
rule
in
synch.

One
commenter
(
OAR­
2002­
0056­
2850)
stated
that
it
is
crucial
that
any
regulatory
requirements
result
in
a
level
playing
field
for
all
affected
sources.
The
commenter
added
that
compliance
timeframes
must
be
flexible
and
harmonized
with
the
Clean
Air
Interstate
Rule
(
CAIR)
to
ensure
continued
reliability,
to
feasibly
allow
capital
investment,
and
to
recognize
that
there
are
no
currently
available
commercial
technologies
designed
exclusively
for
mercury
control
from
electric
utilities.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111
and
is
finalizing
caps
and
timing
that
are
integrated
with
the
CAIR.
See
final
rule
preamble
for
further
discussion.

5.3.2
Level
of
Reduction
Required
by
Caps
Comment:

One
commenter
(
OAR­
2002­
0056­
1768)
stated
that
deeper
mercury
reductions
beyond
the
co­
benefits
associated
with
SO
2
and
NO
x
caps
should
be
based
on
the
progress
of
technology
development
and
a
clear
demonstration
of
a
health
benefit.
Also,
emerging
scientific
research
suggested
to
the
commenter
that
reducing
mercury
emissions
from
the
U.
S.
power
generating
sector
does
little
to
reduce
the
amount
of
mercury
deposition
in
the
United
States
or
the
levels
of
methyl­
mercury
in
fish.
The
commenter
submitted
that
forcing
all
power
plants
to
install
expensive
anti­
pollution
devices
would
not
necessarily
ensure
reductions
in
methylated
mercury
levels
in
local
environments.
The
commenter
asserted
that
the
final
rules
must
address
the
scientific
uncertainties
and
complexities
of
mercury
pollution
in
addition
to
providing
flexibility
and
weighing
known
costs
against
unknown
benefits
of
regulation.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
See
preamble
for
further
rationale
for
the
15
ton
cap.

Comment:
One
commenter
(
OAR­
2002­
0056­
1611)
submitted
that
the
NC
Clean
Smokestacks
Act
will
reduce
emissions
far
more
than
the
President's
proposal
and
should
be
used
as
the
national
model
rule.
5­
24
Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
See
preamble
for
further
discussion.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2660,
­
2838,
­
2871,
­
2887,
­
2889,
­
3437,
­
3449,
­
4117)
submitted
that
the
proposed
mercury
standards
under
the
cap
and
trade
options
are
too
weak
and
the
implementation
time
frame
is
too
long.

One
commenter
(
OAR­
2002­
0056­
3449)
stated
that
trading
only
makes
sense
if
the
caps
are
set
at
well
below
the
standards
that
otherwise
would
have
been
set.
Commenter
OAR­
2002­
0056­
3449
believed
a
defensible
MACT
standard
should
result
in
emissions
in
the
5­
10
tpy
range
by
a
set
deadline,
which
would
be
a
much
greater
reduction
than
the
15
tpy
actual
in
2018
that
EPA
proposed.

One
commenter
(
OAR­
2002­
0056­
3437)
was
concerned
that
EPA
is
using
projections
to
estimate
future
emissions
and
reductions.
The
proposed
Phase
II
cap
would
be
15
tons
in
2018
based
on
a
percentage
reduction
rather
than
an
estimate
of
possible
emissions
based
on
possibly
faulty
projections.
The
commenter
submitted
that
EPA
should
determine
a
reasonable
percentage
reduction
for
both
Phase
I
and
Phase
II
and
should
not
use
unknow
co­
benefits
for
establishing
a
budget.
Several
commenters
(
OAR­
2002­
0056­
2871,
­
2889,
­
2660,
­
2838,
­
2887,
­
4117)
also
pointed
out
that
the
Phase
I
cap
(
34
ton/
yr
cap
in
2010)
does
not
require
any
mercury
specific
controls
beyond
the
incidental
reductions
expected
from
the
IAQR.
The
commenters
added,
while
the
proposal
cites
a
15
ton/
yr
final
cap
in
2018,
the
impacts
analysis
shows
the
final
cap
would
not
be
achieved.
The
commenters
noted
that
EPA
acknowledged
that
emissions
could
be
as
high
as
22
tons
when
banking,
trading,
and
resultant
delays
are
considered.
One
Commenter
(
OAR­
2002­
0056­
2887)
also
pointed
out
that
the
section
111
proposal
is
totally
dependent
on
the
IAQR.
The
commenters
asked,
what
if
the
IAQR
is
not
finalized
or
promulgation
is
delayed?
The
commenters
believed
it
is
questionable
that
the
interim
cap
would
be
enforceable.
Another
commenter
(
OAR­
2002­
0056­
2660)
added
that
that
IAQR
does
not
extend
to
the
15
western
states
so
it
is
possible
there
would
be
no
mercury
reduction
ever
from
any
western
power
plants
and
that
the
limits
for
subbituminous
coal
are
so
lax
that
there
probably
will
not
be
any
mercury
reduction
within
the
state
either.
The
commenter
asserted
the
proposed
limits
would
not
achieve
the
needed
reductions.

One
commenter
(
OAR­
2002­
0056­
2887)
and
several
states
also
opposed
the
section
111
proposal
because
the
deadlines
are
extremely
protracted
given
the
seriousness
of
mercury
pollution
and
its
toxicity.
The
commenters
pointed
out
that
the
settlement
agreement
calls
for
final
HAP
standards
by
March
2005,
with
compliance
by
December
2007
(
with
extensions
if
justified).
The
proposal
postpones
compliance
until
2018
and
beyond
due
to
banking
and
trading
provisions.
The
commenters
submitted
this
delay
is
inappropriate,
irresponsible,
and
unacceptable.
It
is
also
counter
to
CAA
requirements
and
the
settlement
agreement.
The
5­
25
commenters
believed
feasible
controls
are
certainly
available
now.
The
commenters
pointed
out
that
for
example,
Massachusetts
rules
require
85
percent
control
by
2008
and
95
percent
in
2012.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
See
preamble
for
further
rationale.

Comment:

One
commenter
(
OAR­
2002­
0056­
4177)
opposed
the
cap
and
trade
approach
but
stated
that
if
EPA
proceeds
with
it,
the
cap
should
be
about
7
tons/
yr
(
same
as
an
appropriate
MACT
standard),
with
a
final
compliance
date
as
close
as
possible
to
the
2007
date
required
by
section
112
and
the
court
settlement
agreement.

Several
commenters
(
OAR­
2002­
0056­
0501,
­
2569)
specifically
stated
that
a
more
ambitious
cap
and
trade
program
might
be
effective
in
reducing
emissions
with
minimal
costs
to
industry.
One
commenter
(
OAR­
2002­
0056­
2569)
recommended
increasing
the
phase
I
reduction
to
20
tons
by
2009
and
the
phase
2
reduction
to
45
tons
by
2015.
The
commenter
believed
these
reductions
ccould
be
made
easily
on
those
plants
with
configurations
compatible
with
existing
control
technology.

One
commenter
(
OAR­
2002­
0056­
3444)
submitted
that
the
calculation
of
achievable
caps
in
2010
and
2018
would
require
operating
data
of
Utility
Units
during
the
baseline
period.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
See
preamble
for
further
rationale.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2519,
­
3543)
submitted
that
the
extent
of
co­
benefits
reductions
of
SO
2
and
NO
x
controls
is
unknown
under
the
cap
and
trade
program.
One
commenter
(
OAR­
2002­
0056­
2519)
noted
that
the
EPA
proposal
solicits
comments
on
what
level
should
be
selected
for
Phase
I
mercury
emissions
cap.
The
proposal
states
that
EPA
expects
mercury
emission
reductions
under
the
Phase
I
cap
would
result
via
"
co­
benefits"
(
resulting
from
actions
designed
to
achieve
SO
2
and
NO
x
emission
controls
by
retrofitting
SO
2
scrubbers
and
SCR)
in
areas
covered
by
the
proposed
Interstate
Air
Quality
Rule
(
IAQR
region)
of
29
Eastern
sates
and
D.
C.
EPA
suggested
setting
a
Phase
I
cap
of
around
34
tons,
the
level
anticipated
via
co­
benefits
from
sources
located
throughout
the
country.
The
commenter
stated
however,
similar
estimates
by
WEST
Associates
and
the
U.
S.
Department
of
Energy
range
from
36.5
tons
to
42
tons.
The
commenter
believed
that
with
the
1999
baseline
mercury
emissions
of
48
tons,
setting
a
Phase
I
cap
"
too
high"
will
create
a
credibility
problem
while
picking
a
cap
that
is
"
too
low"
may
not
be
achievable
with
co­
benefits
alone.
5­
26
The
commenter
submitted
it
is
not
possible
to
accurately
predict
how
much
mercury
emission
reductions
will
occur
via
co­
benefits
in
the
IAQR
region.
First,
because
the
proposed
mercury
cap­
and­
trade
program
does
not
impose
any
geographic
limitation
on
mercury
trading,
there
is
no
assurance
which
plants
will
reduce
emissions,
and
which
will
rely
on
buying
credits
from
the
market.
For
example,
some
of
the
reductions
would
occur
at
plants
located
outside
the
IAQR
region,
and
hence,
the
reductions
from
the
IAQR
region
would
be
less
than
estimated.
Second,
many,
if
not
most
sources
in
the
IAQR
region
could
shift
their
fuel
(
where
the
infrastructure
exists)
from
current
use
of
bituminous
coal
to
sub­
bituminous
coal
(
not
only
for
mercury
reduction
purposes
but
also
to
reduce
SO
2
emission
reductions
for
achieving
PM
2.5
standards).
The
commenter
added
it
is
well
known
that
mercury
reductions
expected
via
co­
benefits
from
sub­
bituminous
coal
are
much
lower
than
in
the
case
of
bituminous
coal.
Therefore,
not
knowing
which
plants
might
switch
fuel
or
which
plants
will
elect
to
buy
credits,
there
is
no
way
anyone
can
accurately
predict
what
level
of
mercury
emission
reductions
would
occur
via
co­
benefits.
The
commenter
stated
thus,
it
is
not
possible
to
set
a
Phase
I
mercury
emissions
cap
that
relies
exclusively
on
co­
benefits
in
the
IAQR
region.

The
commenter
also
stated
that
finally,
EPA
has
not
provided
state­
by­
state
mercury
budgets
for
Phase
I
starting
in
2010,
primarily
due
to
the
fact
that
EPA
has
not
specified
a
Phase
I
cap.
It
was
unclear
to
the
commenter
whether
EPA
expects
mercury
emission
reductions
during
Phase
I
(
via
co­
benefits)
from
sources
located
outside
the
IAQR
region.
The
commenter
noted
that
as
sources
outside
the
IAQR
region
are
not
expected
to
install
scrubbers
and
SCR
to
attain
PM
2.5
standards,
no
mercury
emission
reductions
via
co­
benefits
can
be
expected
to
occur
at
sources
outside
the
IAQR
region
in
the
near
term.
Accordingly,
if
the
Phase
I
cap
is
set
beyond
the
co­
benefits
level,
sources
outside
the
IAQR
region
will
have
to
either
install
scrubbers
and
SCR
or
other
mercury
specific
control
measures
sooner
than
their
counterparts
would
have
to
do
in
the
IAQR
region.
The
commenter
points
out
that
such
a
scenario
could
result
in
unfair
competitive
advantages
for
sources
in
the
IAQR
region.
Accordingly,
there
is
considerable
uncertainty
on
the
compliance
obligations
under
Phase
I
for
sources
located
in
regions
outside
the
IAQR
region.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
See
final
preamble
for
further
rationale.
EPA
is
establishing
a
firm
cap
for
the
first
phase
and
provided
State
and
Tribal
emissions
budgets.
For
further
discussion
of
state
emision
budgets
see
final
rule
preamble
(
section
IV.
C.
4)
and
Technical
Support
Document
for
CAMR
Notice
of
Final
Rulemaking,
State
and
Tribal
Emissions
Budgets,
EPA,
March
2005.

Comment:

Many
commenters
(
OAR­
2002­
0056­
1608,
­
1768,
­
1859,
­
1969,
­
2224,
­
2375,
­
2818,
­
2830,
­
2833,
­
2835,
­
2850,
­
2861,
­
2895,
­
2898,
­
2907,
­
2918,
­
3327,
­
3444,
­
3463,
­
3469,
­
3530,
­
3546,
­
4891)
supported
setting
the
phase
I
mercury
cap
at
a
level
that's
commensurate
5­
27
with
the
co­
benefit
reductions
anticipated
to
be
achieved
through
implementation
of
SO
2
and
NO
x
reductions
under
the
transport
rule.

Several
commenters
(
OAR­
2002­
0056­
1969,
­
2830,
­
3463,
­
3469)
asserted
that
tying
the
proposed
2010
mercury
reductions
to
co­
benefits
will
allow
reliable
data
on
the
mercury
content
of
lignite
and
mercury
emissions
to
be
collected,
co­
benefits
to
be
evaluated,
and
will
provide
additional
time
to
research
and
develop
effective
control
and
monitoring
technology.
Thus,
the
commenters
recommended
against
setting
a
hard
cap
and
recommended
that
the
cap
simply
be
the
level
which
co­
benefits
can
deliver.

Commenters
OAR­
2002­
0056­
3463
and
OAR­
2002­
0056­
3469
stated
that
if
a
soft
cap
approach
is
adopted,
banking
of
allowances
should
not
be
permitted
in
Phase
I.
One
commenter
(
OAR­
2002­
0056­
3463)
added
that
a
non­
numeric
cap
such
as
this
is
also
appropriate
because
mercury
removal
as
a
co­
benefit
of
SO
2
and
NO
x
control
technology
is
unproven.
According
to
the
commenter,
EPA
has
acknowledged
that
currently­
available
control
equipment
cannot
achieve
consistent
levels
of
mercury
removal
in
the
elemental
phase.
The
commenter
stated
that
since
current
control
equipment
cannot
effectively
remove
mercury
in
the
elemental
phase,
EPA
should
not
put
a
cap
on
emissions
levels
from
lignite­
fired
units.
According
to
the
commenter,
with
no
known
control
method
for
elemental
mercury,
a
specific
limit
on
lignite
emissions
levels
would
force
lignite
operations
to
buy
allowances
or
switch
fuel
 
either
of
which
would
effectively
put
the
Texas
Gulf
Coast
Lignite
industry
out
of
business.

One
commenter
(
OAR­
2002­
0056­
2224)
stated
that
EPA
does
not
propose
a
specific
level
of
mercury
control
for
Phase
I
of
the
cap­
and­
trade
program
under
either
option.
The
commenter
noted
that
rather,
EPA
proposes
to
set
the
mercury
emissions
cap
at
the
level
that
can
be
achieved
through
the
installation
of
controls
that
are
necessary
to
meet
the
Phase
I
emission
caps
in
the
proposed
IAQR.
The
commenter
asserted
that
setting
the
mercury
missions
cap
at
this
level
fully
realizes
the
mercury
"
co­
benefit"
reductions
associated
with
the
controls
required
under
the
IAQR.
According
to
the
commenter,
a
more
stringent
emissions
cap
 
that
is
one
that
does
not
correspond
to
the
controls
for
NO
x
and
SO
2
 
would
present
significant
compliance
and
reliability
concerns
to
the
power
industry
given
that
control
technologies
for
mercury
are
not
yet
commercially
available.
The
commenter
was
still
evaluating
the
appropriate
level
for
setting
a
"
co­
benefit"
emission
cap.
The
commenter
stated
that
EPA
should
be
guided
by
best
available
data
from
technical
analyses
developed
by
DOE
and
other
entities
that
suggest
that
a
34­
ton
cap
level
may
be
overly
optimistic.
The
commenter
noted
that
when
setting
the
Phase
I
mercury
cap,
EPA
should
consider
that
the
IAQR
only
covers
the
Eastern
United
States.

One
commenter
(
OAR­
2002­
0056­
2918)
stated
that
the
amount
of
mercury
emissions
reduction
that
will
be
achieved
as
co­
benefits
has
a
particularly
significant
impact
in
the
western
U.
S.
According
to
the
commenter,
two­
thirds
of
the
western
units
are
already
scrubbed
to
remove
SO
2.
The
commenter
added
however,
that
scrubber
technology
is
not
as
effective
in
mercury
capture
in
the
western
U.
S.
because
coals
burned
there
emit
a
relatively
higher
proportion
of
elemental
mercury
compared
to
oxidized
mercury
due
to
their
lower
chlorine
content.
5­
28
In
an
analysis
included
in
the
docket
(
OAR­
2002­
0056­
1912),
commenter
OAR­
2002­
0056­
2918
examined
EPA's
NATEMIS
files
and
the
applicable
data
sets
from
EPA's
1999
Information
Collection
Request
(
ICR)
supporting
this
rulemaking,
and
estimated
the
maximum
co­
benefits
achievable
by
the
application
of
pollution
controls
to
coal­
fired
units
to
meet
proposed
CSA
reduction
targets
for
SO
2
and
NO
x.
The
commenter
submitted
that
this
analysis
indicates
a
co­
benefits
cap
of
36.5
tons
under
the
best
of
circumstances.
The
commenter
believed
that
in
all
likelihood,
co­
benefit
mercury
emission
reductions
will
be
less,
and
the
Phase
I
cap
should
be
set
at
a
higher
level.
Consequently,
if
the
2010
cap
is
to
truly
reflect
co­
benefits,
then
it
was
the
commenter's
view
that
it
should
be
at
minimum
of
36.5
tons.
One
commenter
(
OAR­
2002­
0056­
3522)
proposed
that
the
Phase
I
cap
be
set
at
no
less
than
36.5
tons
as
commenter
OAR­
2002­
0056­
2918
recommended,
and
that
this
cap
be
accompanied
by
an
effective
safety
valve.
This
commenter
added
that
others,
such
as
the
Department
of
Energy,
estimated
even
higher
emissions,
depending,
for
example,
on
whether
one
assumes
that
the
use
of
SCR
reduces
emissions
of
mercury
along
with
emissions
of
NO
x.

One
commenter
(
OAR­
2002­
0056­
2900)
also
stated
that
EPA
has
suggested
that
the
appropriate
mercury
cap
for
Phase
I
is
34
tons
and
noted
that
Department
of
Energy
and
West
Associates
data
suggest
that
a
higher
level
likely
is
more
realistic.
First,
the
commenter
did
not
believe
that
EPA
had
taken
into
account
many
units
that
recently
have
switched
or
are
in
the
process
of
switching
to
sub­
bituminous,
low
sulfur
coal.
The
commenter
stated
that
as
a
result
of
such
fuel
switching,
the
reductions
EPA
has
anticipated
due
to
the
co­
benefits
of
SO
2
and
NO
x
controls
and
based
on
the
proposed
MACT
standards
would
not
be
as
great.
Second,
the
commenter
believed
EPA
needs
to
re­
evaluate
the
overall
expected
mercury
co­
benefits
of
compliance
with
Phase
I
of
the
CAIR.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
EPA
is
establishing
a
firm
cap
of
38
tons
based
on
EPA's
modeling
of
projected
CAIR
Hg
co­
benefits.
See
final
preamble
for
further
rationale.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2375,
­
2903)
suggested
to
avoid
basing
the
Phase
I
cap
on
as­
yet­
unknown
Interstate
Air
Quality
Rule
(
IAQR)
co­
benefits,
EPA
should
promulgate
a
final
rule
stating
that
the
Phase
I
cap
will
be
at
least
34
tpy
and
no
greater
than
38
tpy.
The
commenters
continued
that
based
on
emissions
data
that
will
be
available
to
EPA
in
2008,
EPA
should
determine
in
2009
what
the
Phase
I
cap
should
be
in
2010.
The
commenters
concluded
that
if
EPA
determines
that
co­
benefits
have
resulted
in
emissions
(
i)
below
34
tpy,
EPA
will
set
a
34
tpy
Phase
I
cap;
(
ii)
between
34
tpy
and
38
tpy,
EPA
will
set
the
cap
at
the
specific
level;
(
iii)
greater
than
38
tpy,
EPA
will
set
a
38
tpy
Phase
I
cap.

Response:
5­
29
EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
EPA
is
establishing
a
firm
cap
of
38
tons
based
on
EPA's
modeling
of
projected
CAIR
Hg
co­
benefits.
EPA
believes
it
is
important
to
establish
the
cap
level
in
the
final
rulemaking
to
provide
affected
sources
with
certainty
and
time
for
compliance
planning.
See
final
preamble
for
further
rationale.

Comment:

Similarly
one
commenter
(
OAR­
2002­
0056­
3443)
recommended
the
imposition
of
a
Phase
I
cap
of
34
tons
per
year
if
the
cap
and
trade
program
allows
for
early
reduction
credits
starting
in
2008.
The
commenter
noted
that
early
reduction
incentives
would
offer
facilities
the
opportunity
to
minimize
compliance
risks
and
the
ability
to
deliver
low­
cost,
reliable
electrical
power
by
accumulating
a
small
buffer
of
allowances
prior
to
the
Phase
I
start
date.
Equally
important,
early
reductions
would
be
environmentally
beneficial
since
they
would
help
reduce
mercury
emissions
prior
to
the
Phase
I
deadline.
Alternatively,
in
the
absence
of
early
reduction
incentives,
the
commenter
recommended
that
the
Phase
I
cap
be
established
at
the
higher
end
of
the
CAIR
emission
levels,
i.
e.,
at
38
tons,
to
account
for
variability
in
mercury
emissions
data.
The
commenter
noted
that
these
recommendations
for
a
Phase
I
cap
were
based
on
the
use
of
heat
input
adjustment
multipliers
proposed
by
EPA
(
1:
1.25:
3.0).
The
commenter
believed
any
further
adjustment
to
these
multipliers
should
be
accompanied
by
a
commensurate
adjustment
of
the
cap.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
EPA
is
establishing
a
firm
cap
of
38
tons
based
on
EPA's
modeling
of
projected
CAIR
Hg
co­
benefits.
See
final
preamble
for
further
rationale.
As
discussed
in
comment
responses
below,
section
5.8.3,
EPA
is
not
including
early
reduction
credits
for
Hg
in
the
final
rulemaking.

Comment:

Several
commenters
(
OAR­
2002­
0056­
1768,
­
2833,
­
3530)
stated
that
many
groups
are
calling
for
a
more
stringent
mercury
cap
than
the
level
of
reductions
achieved
through
"
co­
benefits"
of
SO
2
and
NO
x
reductions
on
a
faster
timetable,
under
which
many
plants
would
be
forced
to
invest
over
a
very
short
time
period
in
expensive
technologies
that
may
not
be
fully
proven
for
every
application
nor
achieve
desired
results.
The
commenters
believe
that
many
generators
may
choose
not
to
"
gamble"
with
their
ratepayers'
or
investors'
dollars
and
instead
choose
to
prematurely
retire
existing
coal­
fired
capacity,
thereby
exacerbating
utility
demand
for
natural
gas.

One
commenter
(
OAR­
2002­
0056­
2835)
agreed
with
EPA
that
it
is
unrealistic
to
establish
a
mercury
cap
based
on
the
reductions
possibly
achievable
through
activated
carbon
injection
(
ACI)
and
other
such
breakthrough
technologies
(
e.
g.,
chemical
systems
to
enhance
mercury
removal
efficiencies
for
wet
scrubbers).
The
commenter
believed
that
these
technologies
have
not
5­
30
been
adequately
demonstrated
on
full­
scale
power
plants
and
thus
do
not
currently
provide
a
reliable
means
to
achieve
mercury
reductions
below
the
levels
achievable
through
SO
2
scrubbers
and
selective
catalytic
reduction
(
SCR)
systems
for
NO
x.
For
these
reasons,
the
commenter
supported
EPA
setting
the
Phase
I
mercury
cap
at
levels
that
can
be
achieved
through
installation
of
such
conventional
SO
2
and
NO
x
control
technologies.
The
commenter
submitted
that
under
this
approach,
the
emissions
cap
would
match
actual
projected
mercury
emissions
instead
of
hypothetical
best
mercury
performance
through
unproven
mercury
control
technologies
that
are
not
yet
demonstrated.
The
commenter
believes
this
approach
is
consistent
with
the
requirement
in
CAA
section
111(
d)
that
the
standard
of
performance
be
based
on
the
best
system
of
emission
reduction
that
has
been
adequately
demonstrated.
The
commenter
also
noted
that
when
setting
the
Phase
I
mercury
cap,
EPA
needs
to
address
that
the
transport
rule
only
covers
the
eastern
states
and
the
very
minimal
co­
benefit
mercury
reductions
achievable
in
the
west,
even
if
the
transport
rule
is
expanded
to
the
entire
continental
United
States.
Moreover,
the
commenter
also
recommended
that
the
Phase
I
cap
for
mercury
reflect
the
use
of
banked
SO
2
and
NO
x
allowances
to
meet
Phase
I
of
the
transport
rule.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
EPA
is
establishing
a
firm
cap
of
38
tons
based
on
EPA's
modeling
of
projected
CAIR
Hg
co­
benefits.
See
final
preamble
for
further
rationale.

Commenter:

One
commenter
(
OAR­
2002­
0056­
2861)
believed
that
any
regulation
of
mercury
emissions
from
coal­
fired
power
plants
that
goes
beyond
the
level
of
co­
benefit
reductions
would
be
premature.
The
commenter
submitted
that
mercury­
specific
control
technologies
to
achieve
reliable
reductions
in
mercury
emissions
from
power
plants
are
not
commercially
available,
as
EPA
acknowledged
in
its
proposal.
The
commenter
noted
that
while
EPA's
response
to
that
problem
is
to
develop
a
cap
based
on
"
co­
benefits"
of
SO
2
and
NO
x
controls
beginning
in
2010,
the
problem
remains
that
establishing
any
hard
cap
in
2010
would
be
inconsistent
with
a
"
co­
benefits"
philosophy.
The
commenter
claimed
the
performance
of
SO
2
and
NO
x
controls
relative
to
their
ability
to
consistently
and
reliably
remove
mercury
is
still
largely
unknown.
The
commenter
asserted
therefore,
since
it
is
impossible
at
this
time
to
predict
with
reasonable
certainty
either
the
SO
2
and
NO
x
controls
that
will
be
installed
to
comply
with
EPA's
CAIR
or
their
effectiveness
at
removing
mercury,
any
attempt
by
EPA
to
set
a
hard
emissions
cap
in
2010
at
any
level
and
call
it
a
co­
benefit
is
nothing
more
than
a
guess,
with
the
utility
industry
and
its
customers
holding
the
risk.
If
EPA
guessed
on
the
low
side
and
set
a
cap
below
what
co­
benefits
would
actually
turn
out
to
be
as
a
result
of
CAIR
implementation
(
the
34
ton
number
that
has
surfaced
as
a
possible
level
that
EPA
may
be
considering
for
a
2010
co­
benefits
cap
by
all
accounts
is
well
below
even
the
most
aggressive
estimate
of
what
co­
benefits
might
turn
out
to
be
in
2010),
the
industry
would
be
faced
with
having
to
install
controls
specifically
to
remove
mercury,
controls
that
by
2010
EPA
acknowledges
will
not
be
ready
for
deployment
in
support
of
5­
31
a
regulatory
requirement.
The
commenter
stated
that
promulgating
such
a
regulatory
requirement
would
seem
an
archetype
of
arbitrary
and
capricious
agency
action.

Commenter
OAR­
2002­
0056­
2861
stated
that
utilities
and
others
are
investigating
ways
to
make
the
performance
of
SO
2
and
NO
x
controls
more
predictable
and
consistent,
but
at
this
time
there
is
no
way
to
know
with
any
certainty
how
much
reduction
can
be
reliably
achieved
at
a
particular
unit
over
an
extended
period
of
time.
The
commenter
asserted
not
only
would
this
uncertainty
create
problems
for
assuring
compliance
at
a
given
unit,
but
also
it
would
have
serious
impacts
on
the
ability
to
create
a
robust
and
effective
emissions
trading
market.
The
commenter
submitted
utilities
will
be
reluctant
to
sell
allowances
if
they
are
unsure
whether
they
can
actually
achieve
the
reductions
necessary
to
free
up
excess
allowances.

In
light
of
concerns
over
technology
availability
and
performance
and
the
likely
adverse
impacts
on
the
efficient
operation
of
a
cap
and
trade
program,
commenter
2861
recommended
that
no
hard
cap
on
mercury
emissions
be
set
for
either
2010
or
2018
at
this
time.
The
commenter
suggested
instead,
any
final
rule
should
specify
that
reductions
in
mercury
emissions
will
be
measured
to
quantify
the
co­
benefit
performance
of
controls
that
will
be
required
under
separate
federal
or
state
programs
including
the
CAIR,
Regional
Haze,
or
state
requirements
such
as
North
Carolina's
Clean
Smokestacks
Act.
The
commenter
stated
that
to
assure
that
co­
benefit
mercury
reductions
are
maximized,
EPA
could
specify
that
each
unit
equipped
with
a
wet
or
dry
SO
2
flue
gas
desulfurization
(
FGD)
system
would
develop
an
operational
plan
to
quantify
mercury
reductions
and
to
develop
operational
parameters
to
optimize
mercury
removal
performance
to
the
extent
practical,
without
adverse
impact
on
boiler
performance
or
SO
2
and
NO
x
removal.
The
commenter
added
the
rule
could
also
specify
that
the
question
of
whether
to
require
reductions
beyond
co­
benefits
would
be
revisited
by
2013
after
several
years
of
operating
data
are
collected
and
analyzed.
These
data
would
provide
better
information
about
the
actual
co­
benefit
level
of
reductions
that
can
be
achieved
and
will
inform
an
assessment
of
whether
further
reductions
beyond
co­
benefits
are
warranted.
The
commenter
believed
this
approach
would
provide
several
years
to
gather
data
on
mercury
speciation,
mercury
removal
associated
with
FGD
and
SCR
systems,
and
advances
in
mercury
control
technology
for
both
elemental
and
non­
elemental
mercury.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
EPA
is
establishing
a
firm
cap
of
38
tons
based
on
EPA's
modeling
of
projected
CAIR
Hg
co­
benefits.
EPA
believes
it
is
important
to
establish
the
cap
level
in
the
final
rulemaking
to
provide
affected
sources
with
certainty
and
time
for
compliance
planning.
See
final
preamble
for
further
rationale.

Comment:
One
commenter
(
OAR­
2002­
0056­
2895)
noted
that
the
exact
level
of
mercury
reduction
that
will
be
realized
as
a
result
of
the
IAQR
is
uncertain
and
hence
the
level
of
a
co­
benefit
cap
is
not
known.
The
commenter
submitted
that
estimates
of
a
co­
benefit
cap
range
from
34
to
42
tons.
The
commenter
suggested
that
one
possible
approach
to
establishing
a
co­
benefits
cap
would
be
to
implement
required
mercury
monitoring
(
source
testing
or
5­
32
monitoring)
in
the
beginning
of
2008.
By
mid
2009,
the
EPA
would
have
more
mercury
emission
data
that
could
be
used
to
estimate
a
more
informed
level
for
a
co­
benefit
cap.
The
commenter
stated
the
December
2004
final
rule
can
establish
a
co­
benefit
level
range
with
the
final
number
being
established
in
mid
2009.

One
commenter
(
OAR­
2002­
0056­
2907)
supported
a
Phase
I
program
based
on
a
true
co­
benefits
approach,
which
must
take
into
account
the
fact
that
it
is
more
difficult
to
remove
elemental
mercury
from
sub­
bituminous
and
lignite
coals
than
it
is
to
remove
oxidized
mercury
from
bituminous
coal.
The
commenter
noted
there
is
considerable
uncertainty
regarding
the
appropriate
co­
benefits
level.
Unless
EPA
can
establish
the
co­
benefits
cap
with
certainty,
the
commenter
encouraged
the
Agency
to
consider
alternatives
to
a
hard
2010
cap
on
mercury
emissions.
The
commenter's
alternatives
included
(
1)
deferring
a
2010
cap
as
proposed
by
EEl;
or
(
2)
creating
another
mechanism
to
provide
industry
with
adequate
relief
in
the
event
actual
mercury
emissions
exceed
the
projected
co­
benefits
emissions
level.

One
commenter
(
OAR­
2002­
0056­
3543)
stated
EPA's
rationale
for
setting
Phase
I
mercury
cap
at
a
level
that
can
be
achieved
through
FGD
and
SCR
was
inconsistent
with
the
preamble
rationale
which
stated
that
uncertainty
exists
in
the
level
of
reduction
that
may
be
achieved
through
FGD
and
SCR
on
different
boiler
types
burning
different
ranks
of
coal.

One
commenter
(
OAR­
2002­
0056­
2430)
stated
EPA's
proposal
discussed
mercury
reductions
in
2010
as
a
co­
benefit
of
the
controls
required
by
the
IAQR.
However,
no
method
for
quantifying
the
mercury
reduction
was
discussed,
making
it
impossible
to
evaluate
expected
2010
reductions
under
the
trading
program
with
2010
under
the
MACT
proposal.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
EPA
is
establishing
a
firm
cap
of
38
tons
based
on
EPA's
modeling
of
projected
CAIR
Hg
co­
benefits.
EPA
believes
it
is
important
to
establish
the
cap
level
in
the
final
rulemaking
to
provide
affected
sources
with
certainty
and
time
for
compliance
planning.
See
final
preamble
for
further
rationale.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2521,
­
2634,
­
3543)
recommended
setting
a
Phase
I
hard
cap.
One
commenter
(
OAR­
2002­
0056­
2521)
noted
that
EPA's
current
proposal
includes
the
following:
1)
depending
on
which
of
the
proposed
approaches
the
Agency
adopts,
a
34­
ton
limit
or
cap
on
mercury
emissions
in
2008
to
2010
(
a
29
percent
reduction
from
1999
levels),
and
a
15­
ton
cap
in
2018
(
a
69
percent
reduction),
and
2)
no
limit
on
trading.
The
commenter
then
noted
that
these
are
the
corresponding
provisions
of
the
Clean
Air
Planning
Act:
1)
a
24­
ton
cap
on
mercury
emissions
in
2009
(
a
50
percent
reduction
from
1999
levels)
and
a
10­
ton
cap
in
2013
(
a
79
percent
reduction),
and
2)
trading
of
mercury
allowances
after
imposition
of
a
reduction
requirement
on
each
facility
(
of
50
percent
in
2009,
and
70
percent
in
2013,
calculated
with
reference
to
the
quantity
of
mercury
in
the
coal).
5­
33
The
commenter
also
stated
that
during
the
course
of
the
Working
Group's
proceedings,
the
commenter
made
specific
recommendations
(
letter
to
Mr.
John
Paul,
co­
chair
of
the
Working
Group,
dated
March
28,
2003)
regarding
subcategories
of
coal­
fired
units
and
emission
rates
for
each
subcategory.
(
According
to
the
commenter,
they
noted
in
their
March
28
submission
that
they
supported
a
combined
standard
that
allows
the
opportunity
to
meet
either
a
specified
emission
rate
or
control
efficiency;
however,
they
included
only
emission
rate
recommendations
at
that
time
in
light
of
the
fact
that
the
IPM
model­
which
EPA
had
intended
to
use
to
model
the
stakeholder
recommendations
cannot
be
run
with
control
efficiencies.)

The
commenter
stated
that
although
their
recommendations
were
rate­
based
and
they
did
not
translate
those
recommendations
into
total
mass
emissions
from
the
industry
sector,
the
Northeast
States
for
Coordinated
Air
Use
Management
(
NESCAUM)
has
since
done
an
analysis
that
translates
the
recommendations
of
all
of
the
stakeholder
groups
that
participated
in
the
Working
Group
into
tons
of
emissions
from
the
industry.
According
to
NESCAUM,
the
commenter's
rate­
based
recommendations
equate
to
total
industry
emissions
of
13.1
tons
of
mercury
per
year,
with
an
implementation
date
of
2008.
Although
the
commenter
was
not
advocating
MACT
standards
that
equate
to
a
highly
specific
industry­
sector
tonnage
limit,
they
adopted
that
calculation
for
the
purposes
of
having
a
common
metric
with
which
to
compare
the
proposed
EPA,
Clean
Air
Planning
Act,
and
commenter's
approaches
to
limiting
mercury
emissions.

One
commenter
(
OAR­
2002­
0056­
3543)
recommended
strengthening
Phase
I
by
establishing
a
hard
cap
at
a
level
designed
to
eliminate
most
of
the
ionic
mercury
emissions
from
affected
units.

One
commenter
(
OAR­
2002­
0056­
2634)
stated
that
if
EPA
ultimately
decides
to
establish
a
numerical
cap
for
2010
as
well
as
2018,
the
commenter
supported
the
position
being
proposed
in
WEST's
comments,
whereas
the
2010
cap
would
be
set
at
36.5
tons
with
enhanced
safety
valves
available
in
2010
and
2018.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
EPA
is
establishing
a
firm
cap
of
38
tons
based
on
EPA's
modeling
of
projected
CAIR
Hg
co­
benefits.
EPA
believes
it
is
important
to
establish
the
cap
level
in
the
final
rulemaking
to
provide
affected
sources
with
certainty
and
time
for
compliance
planning.
See
final
preamble
for
further
rationale.

Comment:
One
commenter
(
OAR­
2002­
0056­
2835)
noted
that
questions
have
been
raised
regarding
the
timing
and
stringency
of
the
Phase
II
mercury
cap.
These
questions
appear
to
stem
from
the
concern
that
the
Phase
II
compliance
deadline
for
mercury
(
2018)
is
three
years
after
the
Phase
II
compliance
deadline
for
SO
2
and
NO
x
(
2015)
under
the
transport
rule.
The
commenter
acknowledged
that
this
mismatch
in
compliance
deadlines
may
enable
many
electric
utilities
to
bank
significant
amounts
of
mercury
allowances
between
2015
and
2018,
and
these
banked
allowances
may
delay
achievement
of
the
Phase
II
mercury
cap
for
many
years
after
2018.
5­
34
Furthermore,
the
commenter
acknowledged
these
concerns,
if
substantiated,
may
justify
the
need
for
adopting
an
interim
cap
in
2015
that
is
more
stringent
than
the
co­
benefit
cap
set
in
2010.
Under
this
approach,
EPA
might
defer
the
imposition
of
a
numeric
cap
in
2010,
preclude
banking
of
pre­
2015
allowances
in
most
cases,
and
require
electric
utilities
to
monitor
mercury
emissions
during
the
initial
phase
of
the
program
(
e.
g.,
2008
to
2014).
The
commenter
submitted
that
another
approach
might
be
to
maintain
the
co­
benefit
cap
in
Phase
I
(
2010­
2014),
but
set
it
at
a
slightly
higher
level
to
address
the
many
uncertainties
inherent
during
the
initial
compliance
period.
Generally
speaking,
these
uncertainties
relate
to
the
baseline
emissions
levels
for
all
affected
coal­
fired
utility
units
and
co­
benefit
mercury
levels
projected
in
2010
as
a
result
of
the
transport
rule.
The
program
would
then:

°
Establish
an
interim
cap
that
would
apply
during
the
2015­
2017
period.
The
control
level
of
the
interim
cap
would
be
set
to
reflect,
in
part,
the
additional
co­
benefit
mercury
reductions
achieved
under
Phase
II
of
the
transport
rule.

°
End
with
final
cap
of
15
tons
in
2018,
as
initially
proposed
by
EPA
under
both
cap­
and­
trade
options.

One
commenter
(
OAR­
2002­
0056­
2224)
was
still
evaluating
the
need
and
appropriateness
of
setting
an
interim
mercury
cap
that
would
be
slightly
more
stringent
than
the
Phase
I
cap
and
might
be
imposed
between
the
Phase
I
and
Phase
II
compliance
deadlines.
The
commenter
was
not
opposed
to
the
imposition
of
such
an
interim
cap
if
additional
mercury
reductions
are
appropriate
and
necessary
prior
to
2018
and
if
the
timing
and
reduction
levels
of
the
interim
cap
levels
are
done
correctly.

One
commenter
(
OAR­
2002­
0056­
2725)
noted
that
in
setting
an
interim
milestone,
EPA
should
remember
that
much
of
the
industry
will
spend
significant
dollars
and
resources
over
the
next
ten
years
reducing
emissions
of
SO
2
and
NO
x
under
the
Interstate
Air
Quality
Rule
(
IAQR)
or
other
programs,
and
these
efforts
should
result
in
significant
mercury
reductions.
The
commenter
believed
that
EPA
should
ensure
that
any
interim
milestone
is
consistent
with
the
co­
benefits
expected
from
other
control
systems
installed
pursuant
to
the
IAQR.
The
commenter
stated
that,
as
with
the
final
milestone,
EPA
should
recognize
the
mercury
emission
reductions
arising
in
the
West
under
other
regulatory
programs
such
as
Regional
Haze.

Several
commenters
(
OAR­
2002­
0056­
2850,
­
2883,
­
3443,
­
3478,
­
4891)
supported
the
establishment
of
an
interim
cap
of
24
tons
of
mercury
in
2015
when
IAQR
Phase
II
controls
are
in
place.
Commenter
OAR­
2002­
0056­
2850
stated
that
this
is
consistent
with
the
utility
industry's
commitment
to
ensuring
that
the
15­
ton
cap
is
met
in
2018.
Commenter
OAR­
2002­
0056­
3478
added
that
establishing
a
"
hard
cap"
in
2015
would
also
limit
the
amount
of
mercury
allowances
that
could
be
banked
by
2018
and,
therefore,
attain
the
final
goal
of
15
tons
earlier.
Commenter
OAR­
2002­
0056­
3443
stated
they
can
support
the
establishment
of
an
intermediate
cap
in
2015
if
early
reductions
can
be
banked
starting
in
2008.
The
commenter
believed
banking
encourages
earlier
or
greater
reductions
than
are
required
from
sources,
stimulates
the
market
and
provides
flexibility
in
achieving
emissions
reduction
goals.
The
commenter
submitted
that
these
advantages
notwithstanding,
banking
can
also
result
in
the
use
of
allowances
in
a
particular
year
that
exceed
5­
35
the
state's
trading
program
budget.
Thus,
an
excessive
accumulation
of
banked
allowances
could
result
in
a
situation
where
actual
emissions
in
2018
are
significantly
above
the
Phase
II
cap
of
15
tons
per
year.
To
prevent
the
accumulation
of
excess
allowances,
the
commenter
could
support
the
establishment
of
an
intermediate
mercury
cap
of
24
tons
in
2015
and
a
onetime
discounting
(
as
described
in
the
following
comment
)
in
2018.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
EPA
is
establishing
a
firm
cap
of
38
tons
based
on
EPA's
modeling
of
projected
CAIR
Hg
co­
benefits.
EPA
believes
it
is
important
to
establish
the
cap
level
in
the
final
rulemaking
to
provide
affected
sources
with
certainty
and
time
for
compliance
planning.
See
final
preamble
for
further
rationale.

Comment:

One
commenter
(
OAR­
2002­
0056­
2898)
stated
the
2018
cap
level
is
too
stringent
given
today's
state
of
development
of
mercury
control
technologies.
The
commenter
believed
it
is
speculative
that
controls
would
be
advanced
to
the
point
of
being
capable
of
controlling
mercury
emissions
nation­
wide
to
levels
proposed
for
2018.
The
commenter
noted
control
technology
for
mercury
removal
is
in
the
developmental
stage.
The
commenter
noted
further
that
the
proposed
2018
cap
of
15
tons
would
require
technologies
that
can
remove
elemental
mercury.
Since,
these
technologies
are
not
proven
at
this
time,
the
commenter
submitted
that
EPA
should
include
provisions
in
the
rule
to
revisit
the
long­
term
cap
if
technology
does
not
develop
that
will
allow
regulated
sources
to
meet
this
cap.
The
commenter
believed
the
U.
S.
economical
impact
must
be
weighed
against
any
human
health
and
environmental
benefit
that
would
result
in
the
additional
reductions.

One
commenter
(
OAR­
2002­
0056­
2907)
also
had
concerns
with
the
proposed
Phase
II
cap
of
15
tons.
This
commenter
also
believed
the
cap
will
require
significant
reductions
in
mercury
that
do
not
appear
to
be
attainable
with
current
technology.
The
commenter
acknowledged
there
is
considerable
ongoing
research
investigating
new
technologies
to
reduce
mercury
emissions
and
lower
the
costs
of
control,
the
commenter
believed
it
is
premature
to
set
a
cap
based
on
the
presumption
that
cost
effective
controls
will
be
available
by
2018.
For
this
reason,
the
commenter
supported
a
robust
"
safety
valve"
to
ensure
that
the
mercury
emissions
reductions
required
by
the
Phase
II
cap
are
achievable.
The
commenter
stated
WEST
Associates
is
filing
comments
containing
such
a
safety
valve.

Several
commenters
(
OAR­
2002­
0056­
3463,
­
3469)
challenged
the
legal
basis
for
EPA's
proposed
cap
of
15
tons
starting
in
2018.
The
commenters
claimed
the
proposal
is
based
on
unproven
mercury
control
technology
with
no
associated
cost
estimates.
One
commenter
(
OAR­
2002­
0056­
3463)
stated
that
lignite­
fired
facilities
cannot
meet
this
cap
limitation
with
currently
available
control
technology.
The
commenter
stated
that
EPA
cannot
use
untested
technologies
to
set
emissions
requirements.
The
commenter
believed
insufficient
data
exists
to
establish
reliable
and
attainable
mercury
emissions
limit
at
this
time.
The
commenter
urged
EPA
5­
36
to
postpone
setting
a
cap
for
Phase
II
until
reliable
data
is
collected,
IAQR­
related
co­
benefit
emission
reductions
are
evaluated,
and
control
technology
for
mercury
is
developed.
One
commenter
(
OAR­
2002­
0056­
3469)
stated
that
given
the
high
level
of
elemental
mercury
in
lignite
and
the
difficulty
of
capture
it
poses,
lignite
will
be
put
at
a
disadvantage
and
utilities
will
have
to
purchase
excessive
amounts
of
allowances,
if
available,
in
order
to
comply.
Both
commenters
recommended
that
EPA
should
establish
a
Phase
II
cap
based
upon
the
following:
data
resulting
from
Phase
I,
sound
science,
verifiable
public
health
benefits,
proven
mercury
control
technologies,
coal
type
differentiation,
amount
of
contribution
to
global
mercury
levels,
and
equitable
treatment
of
lignite
in
connection
with
the
cap­
and­
trade
program.

One
commenter
(
OAR­
2002­
0056­
2918)
stated
that
in
the
NPR,
EPA
proposed
a
Phase
2
cap
of
15
tons,
which
reflects
approximately
a
70
percent
reduction
from
current
emissions.
The
commenter
noted
the
NPR
indicates
that
this
cap
is
based
on
the
modeling
used
to
support
the
CSA.
The
NPR
specifically
states
that
this
modeling
"
suggests
that,
assuming
technologies
such
as
Activated
Carbon
Injection
(
ACI)
become
available,
such
a
cap
(
15
tons)
will
create
an
incentive
for
certain
plants
to
install
these
newer
technologies."
However,
the
commenter,
in
the
analysis
referred
to
in
the
discussion
concerning
the
Proposed
Phase
1
cap
(
OAR­
2002­
0056­
1912),
calculated
the
resulting
emissions
based
on
the
assumption
that
a
total
of
875
units
 
288,874
MW
or
~
88
pecent
of
total
generation
 
were
retrofitted
with
ACI.
The
commenter's
analysis
indicated
that
the
resulting
mercury
emissions
would
be
19
tons,
which
is
4
tons
higher
than
the
proposed
Phase
II
cap.
The
commenter
concluded
that
consequently,
given
the
Phase
2
cap
is
based
on
the
underlying
assumptions
about
the
availability
of
ACI
as
suggested
by
CSA
modeling,
the
Phase
2
(
2018)
cap
should
in
fact
be
19
tons.

Several
commenters
(
OAR­
2002­
0056­
2835,
­
3443,
­
4891)
accepted
a
final
15­
ton
cap
to
become
effective
in
2018.
One
commenter
(
OAR­
2002­
0056­
2835)
stated
that
although
ambitious,
the
level
of
control
may
be
achievable
based
on
the
incremental
co­
benefit
reductions
expected
from
Phase
II
of
the
transport
rule.
The
commenter
believed
that
in
addition,
it
is
reasonable
to
expect
that
additional
mercury
reductions
can
be
cost­
effectively
achieved
in
2018
through
the
application
of
ACI
and/
or
other
emerging
technologies
that
are
expected
to
become
commercially
available
for
deployment
after
2010.
To
address
the
issue
of
excessive
accumulation
of
banked
allowances,
one
commenter
(
OAR­
2002­
0056­
3443)
recommended
that
allowances
could
be
discounted
in
2018
by
a
preset
percentage
of
the
owner's
banked
allowances.
Reducing
the
banked
allowances
in
2018
would
ensure
that
actual
mercury
emissions
from
the
sector
as
a
whole
are
near
the
15
tons
per
year
level
during
subsequent
years.
The
commenter
emphasized
that
this
discounting
must
be
applied
one­
time
only.
No
further
discounting
should
be
applied
to
allowances
earned
after
2018
as
otherwise
the
incentives
to
create
banked
allowances
would
be
dampened.
The
commenter
believed,
therefore,
this
discounting
mechanism
should
not
discourage
the
overall
banking
program.

Several
commenters
(
OAR­
2002­
0056­
2364,
­
3446,
­
3455)
recommended
a
tighter
Phase
II
cap.
Modeling
by
ICF
conducted
for
one
commenter
(
OAR­
2002­
0056­
3446)
found
that
incremental
changes
in
the
timing
and
stringency
of
a
mercury
cap
have
modest
cost
implications.
The
added
costs
of
a
Phase
II
cap
at
10
tons
in
2015
(
instead
of
15
tons
in
2018)
would
be
about
the
same
as
the
cost
saving
for
moving
the
Phase
I
cap
from
26
to
34
tons.
The
commenter
5­
37
summarized
that
on
a
percentage
basis,
the
incremental
environmental
benefits
from
a
tighter
Phase
II
cap
would
exceed
the
incremental
costs.

One
commenter
(
OAR­
2002­
0056­
2364)
believed
that
the
emission
limits
which
reduce
emissions
to
34
tons
per
year
are
too
high
and
that
additional
reduction
is
needed.
The
commenter
recommended
reducing
emissions
to
5
tons/
yr
and
requested
an
IPM
run
to
determine
the
optimal
time
frame
for
reaching
this
lower
emission
level.

One
commenter
(
OAR­
2002­
0056­
3455)
believed
EPA
should
consider
enhancing
the
NO
x
and
SO
2
controls
to
achieve
more
mercury
reduction.
The
commenter
believed
more
stringent
limits
are
technologically
possible
and
recommends
limits
resulting
in
85­
90
percent.
The
commenter
submitted
that
even
considering
the
variability
in
coals,
a
national
mercury
emission
cap
of
5­
10
tons
per
year
is
achievable.
The
commenter
stated
this
is
consistent
with
STAPPA/
ALAPCO's
recommendation
to
the
working
group
of
a
standard
reducing
emissions
to
less
than
7.5
tons
per
year
and
with
EPA's
straw
proposal
for
a
24
ton
cap
in
2008
and
a
final
cap
of
7.5
tons
in
2012.
The
commenter
noted
that
based
on
control
technologies
currently
in
commercial
use
or
proposed
in
permit
applications,
states
such
as
Connecticut,
Massachusetts,
New
Jersey,
and
Wisconsin
have
or
will
adopt
limits
that
represent
control
efficiencies
of
80
to
90
percent
or
more.
The
commenter
stated
these
levels
can
be
achieved
using
the
controls
required
for
NO
x
and
SO
2
reductions
under
the
IAQR
if
the
equipment
maximizes
mercury
control.
Tuning
for
optimal
mercury
removal,
absorbent
improvements,
and
other
enhancements
for
multiple
emissions
control
would
be
effective
measures
to
improve
mercury
removal.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
See
preamble
for
further
rationale
for
the
15
ton
cap.

Comment:

Many
commenters
(
OAR­
2002­
0056­
2634,
­
2819,
­
2861,
­
2867,
­
2876
­
2911,
­
2922,
­
2929,
­
2945,
­
2948,
­
3521,
­
3556,
­
3565)
believed
that
EPA
should
modify
its
cap­
and­
trade
proposal.
One
commenter
(
OAR­
2002­
0056­
2819)
recommended
that
the
trading/
banking
program
be
based
on
recommendations
issued
by
STAPPA/
ALAPCO
and
OTC.
The
STAPPA/
ALAPCO
analysis
recommended
a
15­
20
ton
interim
cap
by
2008
and
a
5­
10
ton
cap
by
2013.
The
OTC
recommended
a
15
ton
interim
cap
by
2008,
a
10
tons
maximum
cap
for
2012,
and
a
5
ton
cap
for
2015.
The
commenter
noted
that
both
of
these
are
more
stringent
and
timely
than
EPA's
proposal
and
would
ensure
installation
of
the
best
controls
nationwide.

One
commenter
(
OAR­
2002­
0056­
2945)
specifically
supported
a
multi­
phase
approach
to
a
national
cap
and
trade
program
as
a
means
of
overcoming
the
multitude
of
problems
associated
with
the
EPA
data,
the
industry's
limited
experience
with
mercury
control
technology,
and
the
need
to
maintain
affordable
electricity
generation
while
developing
the
necessary
experience
to
reduce
mercury
emissions
in
the
most
cost
effective
manner.
The
commenter
stated
that
the
5­
38
Bituminous
Coal
Coalition's
proposed
multi­
phase
approach
and
timetable
is
superior
to
any
EPA
MACT
proposal
since
it
ultimately
results
in
a
much
lower
cap
(
15
tons)
than
does
the
MACT
proposal
One
commenter
(
OAR­
2002­
0056­
2922)
recommended
that
a
mercury
cap­
and­
trade
program
be
implemented
in
three
phases.
In
Phase
1,
there
should
not
be
a
numeric
cap
on
mercury
emissions.
Instead,
mercury
emission
reductions
would
be
those
resulting
from
coal­
fired
power
plants'
installing
new
control
equipment
to
comply
with
the
requirements
of
EPA's
proposed
Clean
Air
Interstate
Rule
(
CAIR),
assuming
that
EPA
promulgates
that
rule.
Mercury
trading
would
not
occur
during
Phase
1.
Mercury
allowances
would
not
be
issued
and
banking
of
mercury
allowances
would
not
occur.
Coal­
fired
units
would
install
and
certify
mercury
monitors
in
2008
and
begin
to
monitor
mercury
emissions
in
2009.
The
commenter
stated
that
the
main
reason
a
numeric
cap
should
not
be
established
in
Phase
1
is
because
there
is
no
way
to
predict
the
level
of
mercury
reductions
that
will
be
a
result
from
utilities'
efforts
to
meet
the
CAIR
requirements.
The
commenter
noted
that
not
setting
a
numeric
limit
would
avoid
excess
banking
of
allowances
if
the
cap
was
set
too
high,
and
conversely,
compliance
problems
if
the
cap
was
set
below
the
level
of
mercury
reductions
actually
achieved
from
complying
with
the
CAIR.
Phase
2
would
begin
in
2015
with
a
cap
of
24
tons
of
mercury
emissions
per
year.
In
Phase
2,
mercury
allowances
would
be
allocated
and
mercury
trading
could
occur.
Allowances
should
be
allocated
on
the
basis
of
heat
input.
The
commenter
suggested
heat
input
multipliers
of
1.0
for
bituminous
units,
1.5
for
sub­
bituminous
units
and
3.0
for
lignite
units.
Phase
3
would
begin
in
2018
with
a
cap
of
15
tons
per
year.

Several
commenters
(
OAR­
2002­
0056­
2634,
­
2861,
­
2867,
­
2911,
­
2929,
­
2948,
­
3521,
­
3556,
­
3565)
supported
and
recommended
the
three
phase
approach
recommended
by
commenter
OAR­
2002­
0056­
2922.
The
commenters
also
cited
advantages
to
this
approach.
Several
commenters
(
OAR­
2002­
0056­
2911,
­
3556)
stated
that
beginning
in
2008,
the
industry
would
begin
a
comprehensive
emissions
measurement
program
for
mercury
from
EGUs.
Similarly,
commenter
OAR­
2002­
0056­
3565
expressed
a
willingness
to
perform
continuous
monitoring
of
mercury
emissions
using
Method
324
beginning
in
2008.
This
measurement
program
would
provide
EPA,
the
states,
the
industry
and
the
public
with
detailed
information
regarding
the
mercury
emissions
from
each
coal­
fired
EGU.

Several
commenters
(
OAR­
2002­
0056­
2911,
­
3556)
submitted
that
the
primary
advantages
of
this
proposal
are
that
it
acknowledges
that
there
are
significant
unknowns
regarding
mercury
emissions
from
EGUs,
allows
the
opportunity
to
resolve
those
unknowns,
and
affords
the
opportunity
for
control
technology
to
catch
up
with
the
final
goals
proposed
by
EPA
 
primarily
through
advancements
in
reducing
the
emissions
of
elemental
mercury.

One
commenter
(
OAR­
2002­
0056­
3565)
stated
that,
as
a
practical
matter,
there
is
no
way
to
predict
what
equipment
the
utilities
will
install
to
meet
the
CAIR
requirements.
The
commenter
added
that
there
is
currently
much
uncertainty
as
to
the
amount
of
mercury
reduction
that
can
be
achieved
by
SCR
and
scrubbers.
The
commenter
stated
that
the
limited
data
from
testing
mercury
on
units
with
SCR
and/
or
scrubbers
has
been
very
varied
and
inconsistent.
The
commenter
further
added
that
there
is
also
some
evidence
that
some
ionic
mercury
reduces
to
5­
39
elemental
mercury
and
is
reemitted
in
some
scrubbers.
One
of
the
commenter's
1999
ICR
stack
test
sites
clearly
produced
data,
which
indicated
such
reemissions
were
occurring.
The
commenter
believed
estimating
the
amount
of
mercury
co­
benefits
which
will
occur
in
year
2010
is
just
a
guess,
therefore,
the
most
straightforward
approach
is
to
not
set
a
tons
limit
for
Phase
I.

One
commenter
(
OAR­
2002­
0056­
2634)
stated
that
the
three
phase
approach
provides
greater
certainty
to
the
utilities
as
it
accurately
addresses
the
true
level
of
"
co­
benefits"
and
it
provides
sufficient
time,
between
2008
(
when
monitoring
would
begin)
and
2015
for
utilities
to
plan
for
installation
of
mercury
specific
controls.
The
commenter
added
it
is
also
environmentally
beneficial
in
that
it
would
reduce
the
total
mercury
emissions
between
2010
and
2018,
and
would
result
in
actual
2018
emissions
being
very
close
to
15
tons
through
reduced
banking.

One
commenter
(
OAR­
2002­
0056­
2861)
stated
that
the
three
phase
approach
would
achieve
several
objectives:
First,
it
would
eliminate
the
guesswork
that
would
be
involved
in
setting
a
co­
benefit
cap
in
2010.
Second,
it
would
eliminate
the
potential
that
the
lack
of
demonstrated
mercury
specific
removal
technology,
combined
with
the
difficulty
in
installing
all
of
the
SO
2
and
NO
x
controls
that
would
be
required
under
CAIR
by
2010,
could
make
it
impossible
for
the
industry
either
to
meet
a
specific
mercury
emissions
cap
in
2010
or
to
have
an
effective
mercury
trading
program
in
2010.
The
commenter
submitted
that
while
concerns
remain
that
the
2015
and
2018
targets
are
still
ahead
of
technology
development,
the
approach
would
provide
more
time
for
the
technologies
that
will
be
needed
to
reduce
emissions
beyond
co­
benefits
to
be
developed,
demonstrated
and
deployed.
The
commenter
concluded
that
last,
the
proposal
to
move
the
first
cap
to
2015
would
address
concerns
that
have
been
expressed
that
too
much
banking
may
occur
if
utilities
are
allowed
to
start
banking
any
reductions
below
their
2010
allocations.
The
commenter
stated
a
2015
cap
that
sets
an
emissions
cap
below
co­
benefits
would
make
it
more
difficult
to
bank
reductions
for
the
period
from
2015
to
2018.
However,
the
commenter
recommended
that
limited
banking
be
allowed
prior
to
2015
if
the
utility
can
demonstrate
that
controls
have
been
installed
to
reduce
mercury
beyond
co­
benefits,
for
example,
if
a
company
installs
a
demonstration
technology
to
specifically
remove
mercury.
The
commenter
suggested
that
will
promote
early
reductions
and
help
development
of
technologies
needed
to
meet
both
the
2015
and
2018
caps.

One
commenter
(
OAR­
2002­
0056­
2867)
applauded
EPA's
recognition
that
mercury­
specific
control
technologies
will
not
be
commercially
ready
for
application
in
the
2010
time
frame.
The
commenter
noted
that
several
technologies
are
in
various
stages
of
pilot
testing,
but
none
have
been
demonstrated
on
a
commercial
scale
for
any
extended
periods
of
time.
The
commenter
stated
that
those
that
have
pilot­
tested
have
shown
a
substantial
degree
of
variability.
It
was
anticipated
by
the
commenter
that
in
the
post­
2010
period
and
by
the
2018
Phase
2
compliance
deadline,
the
performance
of
existing
technologies
would
be
well
demonstrated,
and
innovative
mercury­
specific
technologies
would
have
matured
and
be
ripe
for
commercial
use.
The
commenter
submitted
that
the
commitment
to
advance
mercury
control
technology
for
readiness
in
the
future
is
demonstrated
by
the
pace
of
industry
research
activities
and
demonstration
plans.
Active
commitment
of
funds
by
EPRI,
DOE,
and
several
utility
companies
including
AEP,
further
attest
to
the
commitment
of
the
industry
to
further
development
and
demonstration.
5­
40
Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
EPA
examined
a
three­
phase
approach
but
conclude
its
two­
phase
approach
was
appropriate.
See
preamble
for
further
rationale
and
Chapter
7
of
Final
CAMR
Regulatory
Impact
Analysis.

Comment:

Commenter
OAR­
2002­
0056­
2867
cited
the
following
advantages
of
the
recommended
three
phase
approach:

°
Would
provide
assurances
(
through
the
required
monitoring
programs)
that
emission
reductions
are
being
steadily
phased
in
toward
successful
achievement
of
the
ultimate
15­
ton
cap
°
Monitoring
capabilities
and
technologies
would
have
attained
the
needed
level
of
performance
improvement
to
provide
consistent
demonstrations
of
compliance
and
accurate
future
allowance
allocations
under
the
cap­
and­
trade
program.

°
Banking
would
be
limited
in
the
earlier
phase,
thus
ensuring
that
the
2018
emissions
would
closely
track
the
ultimate
15
Ton
cap.
The
3­
phase
plan
would
achieve
greater
mercury
reductions
in
the
2010­
2018
period
compared
to
EPA's
proposed
two­
phase
plan
(
a
cumulative
total
of
242
Tons
of
allowances
under
a
3­
phase
plan,
versus
a
cumulative
total
of
272
Tons
of
allowances
under
the
2­
phase
plan
as
proposed)

°
The
interim
compliance
date
would
more
closely
approximate
the
schedule
for
implementing
demonstrated
mercury
specific
newer
technologies
that
would
be
elemental
mercury
specific
(
the
predominant
form
of
mercury
expected
after
the
co­
benefits
based
reductions
that
principally
remove
the
ionic
form).

Consistent
with
the
3­
phased
approach
recommended
by
commenter
OAR­
2002­
0056­
2922
as
described
above,
one
commenter
(
OAR­
2002­
0056­
2876)
proposed
that
a
phased,
national
cap
and
trade
program
(
under
section
112
of
the
CM)
be
implemented
to
reduce
power
plant
mercury
emissions.
The
commenter
favored
a
phased
approach
because
it
would
not
be
possible
to
predict
with
adequate
confidence
the
co­
benefit
reductions
that
would
be
achieved
through
the
industry's
actions
to
meet
CAIR
requirements.
In
addition,
the
commenter
believed
a
phased
approach
would
allow
for
the
time
that
is
required
for
the
commercialization
of
mercury­
specific
control
technologies
that
will
be
needed
for
future
reductions.
However,
a
key
distinction
between
the
commenter's
proposed
alternatives
and
the
3­
phased
approach
described
above
is
that
the
commenter
did
not
believe
that
EPA
has
data
that
are
sufficient
to
support
setting
an
interim
(
2015)
cap,
or
emissions
allocation
factors
at
this
time.
As
noted
above,
EPA
should
determine
emissions
allocation
factors
by
coal
type
and
set
an
interim
cap
in
2012;
this
interim
cap
should
become
effective
in
2015.
The
commenter
stated
the
cap
and
associated
factors
should
be
based
on
a
co­
benefits
analysis
of
the
monitoring
data
collected
in
the
5­
41
2008­
2012
period,
and
an
assessment
of
commercial
availability
and
performance
characteristics
of
mercury
control
technologies
for
different
coal
types.
The
analysis
performed
during
this
period
would
allow
for
the
implementation
of
an
interim
cap
that
would
be
achievable
(
and
thus
would
not
promote
fuel
switching
­
to
natural
gas,
for
example),
and
avoid
emissions
allocations
among
coal
ranks
that
would
place
certain
coal
ranks
at
a
market
disadvantage.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
EPA
examined
a
three­
phase
approach
but
conclude
its
two­
phase
approach
was
appropriate.
EPA
believes
it
is
important
to
establish
the
cap
levels
in
the
final
rulemaking
to
provide
affected
sources
with
certainty
and
time
for
compliance
planning.
See
preamble
for
further
rationale
and
Chapter
7
of
Final
CAMR
Regulatory
Impact
Analysis.

Comment:

One
commenter
(
OAR­
2002­
0056­
4894)
provided
a
memo
that
summarized
the
results
of
an
EPMM
model
run
simulating
the
impacts
of
the
EEl's
proposed
alternative
Mercury
Cap
and
Trade
program
(
Alt
Hg
Option).
Under
this
option,
there
would
be
no
hard
mercury
cap
until
2015.
However,
early
reduction
credits
could
be
earned
and
banked
during
the
period
2010­
2014
if
mercury
emissions
were
to
be
consciously
reduced
through
early
application
of
control
technology.
Phase
I
of
the
mercury
cap
would
start
in
2015
and
be
set
to
24
tons.
Phase
II
would
start
in
2018
when
the
cap
is
lowered
to
15
tons.

The
commenter
attached
the
standard
summary
tables
for
this
case
as
an
Excel
file.
This
memo
highlighted
the
key
results,
primarily
though
comparison
with
results
from
EPA's
proposed
Mercury
Cap
and
Trade
Rule
(
Hg
Rule),
which
has
a
cap
of
34
tons
starting
in
2010,
reduced
to
15
tons
in
2018.
The
commenter
ran
both
scenarios
with
identical
assumptions
except
for
the
timing
and
level
of
the
mercury
caps.

The
Alt
Hg
Option
and
the
Hg
Rule
results
presented
by
the
commenter
both
were
simulated
with
an
assumption
that
there
would
be
gradual
improvement
in
activated
carbon
injection
(
ACI)
mercury
control
technology:
a
2.5
percent
annual
reduction
in
the
current
estimate
of
the
variable
costs
only
of
ACI­
based
technology.
The
summary
tables
for
this
specific
version
of
the
Hg
Rule
scenario
were
also
attached
to
the
memo.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
EPA
believes
it
is
important
to
establish
a
firm
cap
of
38
tons
in
2010
based
on
EPA's
modeling
of
projected
CAIR
Hg
co­
benefits.
See
final
preamble
for
further
rationale.
As
discussed
in
comment
responses
below,
section
5.8.3,
EPA
is
not
including
early
reduction
credits
for
Hg
in
the
final
rulemaking.
5­
42
Comment:

Several
commenters
(
OAR­
2002­
0056­
2880,
­
2889)
urged
EPA
to
adopt
the
mercury
cap
levels
and
reduction
timeframes
in
the
Multi­
Pollutant
Strategy
Position
of
the
Ozone
Transport
Commission
(
January
27,
2004)
and
STAPPA/
ALAPCO's
Principles
for
a
Multi­
pollutant
Strategy
for
Power
Plants
(
May
7,
2002
with
March
12,
2004
analysis
of
those
principles).
The
OTC
calls
for
stepwise
reductions
in
mercury
emissions:
15
tons/
yr
in
2008,
10
tons/
yr
in
2012,
5
tons/
yr
in
2015
and
performance
standards
for
individual
units
by
2012.
These
reductions
are
technically
and
economically
feasible
in
that
timeframe.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
See
final
preamble
for
further
rationale.

Comment:

One
commenter
(
OAR­
2002­
0056­
3546)
was
generally
supportive
of
the
proposed
targets
and
compliance
deadlines
for
reducing
mercury
proposed
under
the
cap­
and­
trade
options.
However,
the
commenter
urged
EPA
to
further
examine
these
targets
and
deadlines
 
which
are
very
ambitious
 
to
ensure
that
the
proposed
two­
phased
mercury
control
program
is
technically
and
economically
feasible
and
consistent
with
the
objectives
to
ensure
adequate
supplies
of
reasonably
priced
power.
Moreover,
the
commenter
submitted
that
given
the
stringency
of
the
proposed
reduction
requirements,
the
adoption
of
an
emissions
trading
program
is
essential
to
ensure
these
objectives
are
realized
and
that
mercury
reduction
obligations
can
be
achieved
at
the
lowest
possible
cost.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
See
final
preamble
for
further
rationale.

Comment:

One
commenter
(
OAR­
2002­
0056­
2359)
stated
EPA's
weak
proposals
do
not
provide
incentive
for
advancing
mercury
removal
technology
in
conjunction
with
SO
x,
NO
x,
and
PM.
The
commenter
pointed
out
that
DOE
is
expected
to
have
cost
effective
mercury
control
technology
available
by
2010;
EPA's
mercury
rules
should
at
least
be
consistent
with
that
timing.

Response:
5­
43
EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
EPA
believes
this
cap
levels
and
timing
encourage
technology
development.
See
final
preamble
for
further
rationale.

Comment:
One
commenter
(
OAR­
2002­
0056­
3210)
opposed
EPA's
rationale
in
the
supplemental
notice
for
6
years
to
adequately
conduct
a
commercial
demonstration
of
mercury
controls.
The
commenter
claimed
EPA
is
attempting
to
selectively
develop
time
lines
to
justify
cap
and
trade.
The
commenter
noted
the
6
year
time
line
includes
a
pre­
award
period
greater
than
12
months,
each
full­
scale
demonstration
taking
another
12
months
and
inflates
the
operating
and
reporting
timeline
by
including
the
time
to
prepare
a
report
on
the
project.
The
commenter
believes
a
realistic
time
line
is
3­
4
years,
especially
in
light
of
all
the
full
scale
demonstration
projects
already
completed
or
underway.
The
commenter
stated
the
goal
of
the
DOE/
NETL
Mercury
Control
Technology
Research
Program
is
for
technology
for
bituminous
coal
to
be
available
by
2005
and
lignite
and
sub­
bitumihnous
coal
by
2007
and
advanced
mercury
controls
for
all
coal
types
by
2010.
Widespread
commercial
deployment
could
begin
in
2008
for
bituminous
and
2011
for
lignite
and
sub­
bituminous
coal.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
EPA
believes
this
cap
levels
and
timing
are
consistent
with
its
understanding
of
technology
development.
See
final
preamble
for
further
rationale
and
see
Control
of
Emissions
from
Coal­
Fired
Electric
Utility
Boilers:
An
Update,
EPA/
Office
of
Research
and
Development,
March
2005,
in
docket.

Comment:
Several
commenters
(
OAR­
2002­
0056­
2054,
­
2422,
­
2718,
­
2922,
­
3198,
­
3469)
recommended
that
EPA
should
implement
a
phased­
in
approach
to
the
mercury
cap­
and­
trade
program
that
recognizes
the
differences
in
available
technology
solutions
between
the
various
fuel
subcategories.
Several
of
the
commenters
(
OAR­
2002­
0056­
2054,
­
2422,
­
3198)
claimed
adequate
technical
data
do
not
exist
at
this
time
to
provide
a
reasoned
basis
for
the
allocation
of
allowances
among
coal
types
for
purposes
of
an
initial
reduction
in
2010.

One
commenter
(
OAR­
2002­
0056­
2054)
believed
the
mercury
data
collected
as
part
of
EPA's
1999
Information
Collection
Request
(
ICR)
is
inadequate
and
inherently
flawed.
The
commenter
proposed
that
EPA
acknowledge
these
data
problems
and
implement
mercury
regulations
that
are
designed
to
rectify
the
situation,
while
maintaining
a
reasonable
level
of
environmental
control
over
mercury
emissions.
Several
commenters
(
OAR­
2002­
0056­
2054,
­
2422)
encouraged
initial
reliance
on
the
"
co­
benefit"
mercury
reductions
achieved
by
the
sulfur
and
nitrogen
oxides
reductions
required
by
EPA's
proposed
Interstate
Air
Quality
Rule
(
IAQR).
One
commenter
(
OAR­
2002­
0056­
2422)
noted
that
EPA's
mercury
co­
benefit
reduction
estimates
associated
with
the
IAQR
are
comparable
to
those
resulting
from
implementation
of
the
agency's
MACT
proposal.
The
commenter
noted
EPA
estimates
that
compliance
with
the
IAQR
will
result
in
an
overall
level
of
34
tons
of
mercury
emissions
from
the
electric
generating
sector
in
2010,
due
to
the
installation
of
49
Gigawatts
(
GW)
of
scrubbers
and
24
GW
of
SCR
capacity
by
2010.
5­
44
Several
commenters
(
OAR­
2002­
0056­
2054,
­
2422,
­
3198)
stated
EPA
should
implement
a
phased
approach
to
the
determination
of
mercury
emission
allowance
allocations
under
any
form
of
an
emissions
trading
rule.
The
commenters
submitted
a
phased
approach
should
be
designed
with
the
following
milestones:

°
2008­
Require
installation
and
initial
testing
and
operation
of
mercury
emission
monitoring
equipment
on
affected
units;

°
2009­
11­
Collect
and
analyze
monitor
data
to
determine
mercury
emissions
and
reductions
achieved
by
IAQR
emission
reductions
in
2010;

°
2012­
Determine
prospective
emission
allocations
by
coal
type
for
an
interim
2015
emissions
cap,
based
on
results
of
the
2009­
11
co­
benefits
analysis,
and
an
assessment
of
the
expected
future
commercial
availability
and
performance
characteristics
of
mercury
control
technologies
for
different
coal
types;

°
2015­
Affected
plants
meet
an
interim
emissions
cap
determined
by
EPA
in
2012;
banking
and
trading
of
allowances
commences;

°
2018­
Final
emissions
cap
of
15
tons
is
imposed.

Several
commenters
(
OAR­
2002­
0056­
2054,
­
2422)
recognized
that
the
development
of
mercury­
specific
control
technologies
may,
or
may
not,
reduce
the
need
for
specific
emission
allowance
allocations
by
coal
type
at
some
point
in
time.
The
commenters
stated
the
proposed
2009­
2011
analysis
of
the
efficacy
of
co­
benefit
control
reductions,
coupled
with
an
assessment
of
mercury­
specific
control
technologies,
would
facilitate
a
determination
of
the
appropriateness
of
coal­
specific
emission
allowance
allocations
to
meet
an
interim
2015
and
a
final
2018
cap.

Under
the
commenters'
(
OAR­
2002­
0056­
2054,
­
2422,
­
3198)
phased
approach,
no
mercury
allowances
would
be
assigned
until
2015,
for
purposes
of
meeting
an
interim
cap,
and
no
banking
or
trading
of
allowances
could
occur
prior
to
that
date.
One
commenter
(
OAR­
2002­
0056­
2244)
strongly
opposed
use
of
the
agency's
proposed
MACT
floor
values
for
any
allocation
of
mercury
emission
allowances.
The
commenter
asserted
these
floor
values
were
not
statistically
defensible,
and
were
inappropriate
for
any
regulatory
purpose.
One
commenter
(
OAR­
2002­
0056­
2054)
believed
that
with
this
proposal,
the
total
mercury
emissions
would
decrease
and
be
equal
to
or
less
than
the
emission
levels
under
the
currently
proposed
regulatory
alternatives.
The
commenter
stated
in
addition,
the
additional
data
collection
would
insure
a
just
and
verifiable
regulatory
program
based
on
sound
science.
The
commenter
also
stated
that
finally,
the
limited
time
for
banking
allowances
(
3
years)
would
insure
that
the
maximum
mercury
reductions
would
be
achieved
in
a
relatively
short
time.

Another
commenter
(
OAR­
2002­
0056­
2922)
also
recommended
that
a
mercury
cap­
and­
trade
program
be
implemented
in
three
phases.
This
commenter's
recommendation
as
described
in
the
following
paragraphs
was
identical
to
the
recommendation
of
the
above
commenters
(
OAR­
2002­
0056­
2054,
­
2422,
­
3198)
with
the
exception
of
the
Phase
2
(
interim)
5­
45
cap.
The
commenter
submitted
that
in
Phase
1,
there
should
not
be
a
numeric
cap
on
mercury
emissions.
Instead,
mercury
emission
reductions
would
be
those
resulting
from
coal­
fired
power
plants'
installing
new
control
equipment
to
comply
with
the
requirements
of
EPA's
proposed
Clean
Air
Interstate
Rule
(
CAIR),
assuming
that
EPA
promulgates
that
rule.
Mercury
trading
would
not
occur
during
Phase
1.
The
commenter
stated
mercury
allowances
would
not
be
issued
and
banking
of
mercury
allowances
would
not
occur.

Under
the
commenter's
(
OAR­
2002­
0056­
2922)
approach,
coal­
fired
units
would
install
and
certify
mercury
monitors
in
2008
and
begin
to
monitor
mercury
emissions
in
2009.
The
commenter
stated
the
main
reason
a
numeric
cap
should
not
be
established
in
Phase
1
is
because
there
is
no
way
to
predict
the
level
of
mercury
reductions
that
would
be
a
result
from
utilities'
efforts
to
meet
the
CAIR
requirements.
The
commenter
believed
not
setting
a
numeric
limit
would
avoid
excess
banking
of
allowances
if
the
cap
were
set
too
high,
and
conversely,
compliance
problems
if
the
cap
were
set
below
the
level
of
mercury
reductions
actually
achieved
from
complying
with
the
CAIR.
Phase
2
would
begin
in
2015
with
a
cap
of
24
tons
of
mercury
emissions
per
year.
The
commenter
submitted
that
in
Phase
2,
mercury
allowances
would
be
allocated
and
mercury
trading
could
occur.
According
to
the
commenter,
allowances
should
be
allocated
on
the
basis
of
heat
input.
The
commenter
suggested
heat
input
multipliers
of
1.0
for
bituminous
units,
1.5
for
sub­
bituminous
units
and
3.0
for
lignite
units.
Phase
3
would
begin
in
2018
with
a
cap
of
15
tons
per
year.
The
commenter
asserted
that
the
main
problems
with
EPA's
cap­
and­
trade
proposal
center
on
the
overly
stringent
limits
on
new
units
and
the
emissions
monitoring
and
compliance
requirements.

One
commenter
(
OAR­
2002­
0056­
2718)
supported
the
consensus
industry
position
that
EPA
implement
a
three­
Phase
trading
program
and
proposed
a
variation
of
the
approaches
described
above.
According
to
the
commenter,
EPA
should
initially
set
a
Phase
I
nationwide
cap
to
begin
in
2010
at
34
tpy
but,
based
on
monitoring
data
collected
in
2008,
reevaluate
whether
the
cap
appropriately
captures
the
Agency's
intent
to
require
co­
benefits
reductions
only
in
the
first
phase.
The
commenter
noted
that
several
different
studies
of
co­
benefits
have
indicated
a
Phase
I
range
of
removal
from
34
tpy
to
42
tpy
 
a
significant
range
of
uncertainty
that
could
be
addressed
through
a
monitoring
program
in
2008.
The
commenter
proposed
an
interim
Phase
II
cap
of
24
tpy
in
2015
and
a
Phase
III
cap
of
15
tpy
in
2018.
The
commenter
urged
EPA
to
implement
flexible
cap­
and­
trade
mechanisms
that
would
enable
affected
sources
to
achieve
the
proposed
reductions
as
cost­
effectively
as
possible.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
EPA
is
establishing
a
firm
cap
of
38
tons
based
on
EPA's
modeling
of
projected
CAIR
Hg
co­
benefits.
EPA
believes
it
is
important
to
establish
the
cap
levels
in
the
final
rulemaking
to
provide
affected
sources
with
certainty
and
time
for
compliance
planning.
EPA
examined
a
three­
phase
approach
but
conclude
its
two­
phase
approach
was
appropriate.
See
final
preamble
for
further
rationale
and
Chapter
7
of
Final
CAMR
Regulatory
Impact
Analysis.
For
discussion
of
coal
adjustment
factors
used
in
determining
allocations
see
responses
in
section
5.6.1
below.
5­
46
Comment:

One
commenter
(
OAR­
2002­
0056­
2243)
believed
that
in
general,
the
grandfathering
of
elevated
NO
x
and
SO
2
emissions
should
be
eliminated.
The
commenter
viewed
this
as
an
unfair
competitive
advantage
to
existing
generators
in
a
supposedly
competitive
electric
market.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
See
final
preamble
for
further
rationale.

Comment:

One
commenters
council
(
OAR­
2002­
0056­
2906)
reminded
EPA
that
it
is
much
more
cost
effective
to
reduce
emissions
from
large
utility
units
than
from
smaller
industrial
size
steam
boilers.
The
Council
supported
the
EPA
approach
of
focusing
on
the
more
cost
effective
larger
units
as
in
the
proposed
Clean
Air
Interstate
Rule
(
CAIR),
formerly
known
as
the
Interstate
Air
Quality
Rule
(
69
FR
4566,
January
30,
2004
and
69
FR
32684,
June
10,
2004)
to
achieve
the
required
emissions
reductions
rather
than
on
higher
cost
industrial
size
units.

Response:

The
final
CAMR
will
require
Hg
reductions
from
coal­
fired
power
plants.
See
final
preamble
for
further
rationale.

Comment:

One
commenter
(
OAR­
2002­
0056­
3469)
noted
that
EPA's
determination
of
the
necessity
to
regulate
Mercury
emissions
from
EGU's
is
based
in
part
on
a
report
by
the
National
Academy
of
Sciences
(
NAS).
However
this
report
stated
that
"
based
on
estimates
of
methylmercury
exposures
in
the
U.
S.
populations...
the
risk
of
adverse
effects
from
current
methylmercury
exposures
in
the
majority
of
the
population
is
low."
Methylmercury
is
typically
found
in
fish.
The
commenter
further
noted
that
EPA
itself
has
acknowledged
that
concentrations
of
methylmercury
in
fish
come
from
a
variety
of
sources
including
global
natural
and
manmade
sources.
According
to
the
Electric
Power
Research
Institute,
of
the
5,500
tons
of
mercury
emissions
estimated
to
occur
globally,
only
150
tons
originate
in
the
U.
S.
In
the
1997
Mercury
Study
Report
to
Congress,
the
EPA
estimated
that
U.
S.
EGU's
"
account
for
roughly
1
percent
of
total
global
emissions"
(
approximately
48
tons)
and
emissions
of
mercury
from
lignite­
fired
plants
is
less
than
10
percent
of
that
1
percent.
The
report
went
on
to
say
that
"
the
relationship
between
mercury
emissions
reductions
from
Utility
Units
and
methylmercury
concentrations
cannot
be
calculated
with
confidence."
The
commenter
submitted
that
computer
models
run
by
U.
S.
EPA
and
EPRI
predict
that
cutting
mercury
emissions
from
power
plants
by
50
percent
will
only
reduce
mercury
levels
in
U.
S.
waters
by
an
average
of
3
percent
and
this
level
of
reduction
will
translate
into
a
reduction
of
less
than
1
percent
in
exposure
to
mercury
via
fish
consumption.
5­
47
The
commenter
believed
the
EPA
is
faced
with
a
dilemma.
On
the
one
hand
the
science
does
not
yet
point
to
a
direct
link
between
U.
S.
EGU
mercury
emissions
and
methylmercury
concentrations
in
fish
nor
does
science
show
how
reductions
in
EGU
mercury
emissions
will
alter
these
concentrations
and
lower
health
risks.
On
the
other
hand,
the
public
has
been
led
to
believe
that
mothers
and
unborn
children
are
at
risk
to
exposure
of
damaging
levels
of
mercury
due
to
consuming
fish
and
that
this
mercury
emanates
from
U.
S.
power
plants.
It
is
asking
for
action
to
be
taken
to
control
mercury
emissions
from
power
plants.

The
commenter
stated
that
given
the
state
of
the
available
information,
it
would
thus
appear
prudent
on
the
part
of
EPA
to
proceed
slowly,
implementing
cost­
effective
regulations
that
do
not
destabilize
energy
markets,
such
as
forcing
fuel
switching
or
inhibiting
the
construction
of
new
coal­
fired
generation,
or
imposing
unintended
social
or
economic
costs,
such
as
raising
energy
prices
and
closing
mines
and
power
plants
in
rural
areas.
(
These
consequences
are
discussed
in
detail
in
the
comments
submitted
by
CEED
and
are
incorporated
in
the
commenter's
comments
by
reference).
The
commenter
submitted
that
a
measured
approach
will
allow
the
EPA
to
evaluate
the
effectiveness
of
the
regulations
in
reducing
health
risks
and
to
modify
future
regulations
in
light
of
these
results.
To
demonstrate
it
is
a
good
steward
of
the
public's
health
and
resources,
EPA
must
be
able
to
conclusively
demonstrate
that
the
regulations
have
resulted
in
lower
health
risks.
The
commenter
concluded
that
as
such
a
phased
approach
to
regulation
is
called
for.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111,
and
establishing
a
first
phase
cap
of
38
tons
and
a
second
phase
cap
of
15
tons.
See
final
preamble
for
further
rationale.

Comment:

One
commenter
(
OAR­
2002­
0056­
1842)
offered
the
following
"
mercury
escalating
payment
proposal."
According
to
the
commenter,
the
high
mercury
emitters
would
pay
the
low
mercury
emitters'
amounts
which
would
rise
each
year.
The
commenter
submitted
that
if
90
percent
of
the
mercury
could
be
removed
for
a
rate
increase
of
one
percent,
the
vast
majority
would
support
the
expenditure.
If
a
modest
rate
increase
would
achieve
80
percent
reduction
while
a
huge
increase
would
be
needed
for
90
percent
reduction
then
the
vast
majority
would
support
the
80
percent
removal.
So
there
would
be
relatively
little
controversy
over
how
much
should
be
spent.
The
commenter
believed
the
controversy
would
be
over
cost
vs.
performance.
The
commenter
noted
environmentalists
say
90
percent
of
the
mercury
can
be
eliminated
at
a
cost
of
a
few
thousand
dollars/
lb.
Utilities
say
that
even
at
$
35,000/
lb
you
may
not
be
able
to
remove
90
percent.

The
commenter
stated
that
at
the
end
of
the
year
each
utility
who
emits
mercury
at
greater
than
the
average
rate
pays
into
a
fund
and
each
utility
under
the
average
receives
those
payments.
The
amount
per
pound
would
rise
each
year.
The
commenter
submitted
it
would
likely
start
low,
5­
48
e.
g.,
$
5,000
lb
in
2007
and
rise
at
$
10,000/
lb
per
year
until
industry­
wide
emissions
are
reduced
to
5
tons/
yr.

The
commenter
submitted
that
if
the
environmentalists
are
right
and
most
mercury
can
be
removed
for
a
few
thousand
dollars/
lb,
then
utilities
would
soon
invest
in
removal
technology
rather
than
pay
into
the
fund.
To
ensure
that
this
does
happen
the
rule
could
contain
a
proviso
that
if
mercury
is
not
reduced
to
some
level
(
e.
g.
25
tons
in
2010
and
5
tons
in
2015)
then
a
tax
would
kick
in.
The
commenter
suggested
this
tax/
lb
would
be
greater
for
those
with
higher
than
average
emissions.
The
funds
from
this
tax
would
be
earmarked
for
mercury
development.

The
commenter
believed
setting
the
cost/
lb
would
be
critical.
The
commenter
noted
that
interestingly
both
sides
in
the
argument
would
have
to
contradict
themselves.
Environmentalists
would
say
that
instead
of
a
few
thousand
dollars/
lb
it
could
be
very
costly.
Utilities
would
say
that
the
payment
costs
should
be
set
lower
and
will
have
to
base
this
on
the
claim
that
mercury
can
be
removed
cheaply.

The
commenter
admitted
that
the
truth
of
the
matter
is
that
setting
the
costs
would
be
tricky.
At
$
19,000/
lb
average
cost
it
would
appear
that
a
$
25,000/
lb
top
payment
would
be
sufficient.
But
the
commenter
submits
that
given
the
incremental
cost
structure
above,
utilities
would
stop
at
75
percent
efficiency.
The
commenter
suggested
it
might
be
best
to
set
$
85,000/
lb
as
the
payment
in
2015.
According
to
the
commenter,
this
would
result
in
more
than
80
percent
removal.

The
commenter
explained
the
steep
escalation
for
the
final
percent
is
based
on
increasing
carbon
usage
from
2
Lbs/
MMacf
to
10
lbs/
MMacf
to
30
lbs/
MMacf.
The
commenter
did
not
believe
carbon
would
be
used
at
the
high
usage
rates.
The
commenter
believed
this
escalating
payment
system
will
stimulate
all
sorts
of
developments.
The
commenter
submitted
one
of
the
main
attractions
of
this
approach
would
be
the
accelerated
use
of
better
technology.
The
commenter
pointed
to
chloride
pre­
scrubbers,
biomass
gasification
including
PVC
for
injection
as
a
reburn
fuel,
additives
other
than
carbon,
acid
condensation,
etc.
The
commenter
stated
all
would
promise
to
remove
90
percent
of
the
mercury
at
less
than
$
10,000/
lb.

Escalating
Payment
Scenario
Would
Also
Solve
Monitoring
Problem.
The
commenter
submitted
the
EPA
proposal
to
ignore
particulate
mercury
was
not
a
good
idea.
The
commenter
noted
that
three
percent
error
is
maybe
acceptable
for
emission
reporting
but
if
you
are
trading
allowances
at
$
35,000
or
as
per
above
$
85,000/
lb
(
NOTE:
The
$
85,000/
lb
figure
is
based
on
an
example
application
of
the
mercury
escalating
payment
proposal
given
in
the
comment),
you
are
talking
about
a
variance
of
$
100
million
to
$
200
million.
Furthermore,
there
is
no
assurance
that
three
percent
is
the
right
number.
The
commenter
pointed
out
the
RJM
concept
is
to
condense
acid
mist
on
fine
particulate
in
order
to
create
acid
deposition
sites.
Under
the
EPA
scheme
all
the
mercury
could
then
be
discharged
and
not
counted.
The
commenter
also
pointed
out
there
is
a
10
times
differential
between
fine
particulate
emissions
from
old
precipitators
and
new
ones.

According
to
the
commenter,
no
trading
system
will
stand
for
this
amount
of
inaccuracy.
So
the
commenter
proposed
an
"
audit
system."
EPA
can
protect
against
abuses
but
put
the
5­
49
burden
on
the
utilities
to
report
accurately.
The
commenter
submitted
that
because
of
the
financial
consequences
utilities
will
demand
a
measurement
system
which
provides
the
highest
possible
accuracy.
EPA
has
already
proposed
allowing
better
QC/
QA
rather
than
mandating
specific
instrumentation.
The
commenter
believed
this
is
the
route
to
take.

Investors
Will
Supply
the
Capital
and
Take
the
Risks.
The
commenter
stated
most
experts
agree
that
mercury
technology
lacks
the
certainty
of
SO
2
removal.
But
they
would
also
agree
that
there
are
many
probable
routes
to
economic
mercury
removal.
The
commenter
submitted
the
problem
is
that
utilities
do
not
have
the
mind
set
of
traders.
So
why
not
pass
the
risk
to
the
investment
community.
The
commenter
pointed
out
the
maximum
cost
per
pound
in
any
future
year
is
now
known.
The
investor
would
agree
to
receive
some
percentage
of
this
amount.
In
return
he
would
finance
the
control
technology
used
to
make
the
reductions.

The
commenter
believes
there
is
a
big
upside
profit
potential
and
a
limit
on
downside
risk.
In
a
worst
case
scenario
the
investor
would
lose
his
investment
but
does
not
face
additional
penalties.
The
investor
says
that
if
the
system
works
he
wants
the
lion
share
of
the
cost
difference.
If
it
doesn't
work
the
utility
just
makes
the
payments
they
would
have
made
without
the
investment.

The
commenter
raised
the
question,
How
does
a
proposal
such
as
this
meet
the
criteria
of
individual
action
by
each
state?
One
way
would
be
to
add
a
clause
that
each
state
that
volunteers
to
enter
this
plan
would
have
the
option
to
drop
out
when
mercury
limits
reach
the
budgeted
amount
in
the
state.
The
commenter
believes
in
practice
no
state
would
do
so.

The
commenter
submitted
the
reason
would
be
if
the
state
reached
this
threshold,
utilities
in
the
state
would
be
net
recipients
rather
than
payers.
So
opting
out
would
increase
electricity
rates.

The
commenter
stated
another
reason
no
state
would
drop
out
is
that
this
plan
would
encourage
cost
effective
mercury
reductions
beyond
the
90
percent.
The
commenter
stated,
e.
g.,
the
national
average
drops
to
five
tons
in
2015.
At
that
time
the
payment
price
of
$
85,000/
lb
would
no
longer
escalate,
but
the
payment
would
continue
at
that
price.
The
commenter
submitted
that
in
future
years,
new
technology
that
costs
less
than
$
85,000/
lb
would
be
implemented.
The
commenter
believed
that
eventually
mercury
might
be
reduced
by
95
percent
instead
of
90
percent.
The
beauty
is
that
the
cost
would
be
a
maximum
of
$
85,000/
lb
for
the
last
increment
and
on
the
average
only
a
fraction
of
that.
The
commenter
stated
that
their
analysis
showed
that
the
cost
for
very
high
mercury
reduction
will
be
only
1
to
2
mils/
kWh.

The
commenter
(
OAR­
2002­
0056­
1842)
stated
that
the
Particulate
Inter­
Utility
escalating
payment
plan
would
provide
a
cost
effective
solution
to
the
particulate
and
toxic
metal
problems.
The
commenter
submitted
that
higher
emitting
utilities
would
pay
lower
emitting
utilities
an
amount
starting
at
$
400/
ton
in
2007
and
amounts
in
future
years
which
escalate
at
$
400/
ton
until
national
averages
drop
below
0.05
lbs/
MM/
btu.
According
to
the
commenter,
an
analysis
showed
that
within
a
few
years,
payments
would
be
more
than
the
annual
cost
of
efficient
particulate
5­
50
control
equipment.
The
analysis
also
showed
the
substantial
reduction
in
toxic
metals
which
would
accompany
the
particulate
reduction.

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111
that
it
believes
is
appropriate
and
cost­
effective.

5.4
HOT
SPOTS
Comment:

A
trading
scheme
would
allow
dirty
plants
to
continue
to
emit
high
levels
of
mercury
by
purchasing
credits
from
cleaner
plants
and
not
installing
controls,
which
would
further
endanger
the
health
of
surrounding
communities.
with
hot
spots.
For
example,
one
commenter
(
OAR­
2002­
0056­
2355)
stated
that
low
income
immigrant
populations
who
eat
fish
from
local
waters
are
at
risk
as
are
Boston
residents
who
suffer
from
asthma.
The
commenters
believed
this
approach
is
inappropriate
for
such
a
toxic
pollutant
and
is
inconsistent
with
EPA's
own
findings
as
well
as
other
Federal
agencies
such
as
FDA
and
NAS.
Another
commenter
(
OAR­
2002­
0056­
4139)
submitted
information
suggesting
that
localized
deposition
impacts
do
occur.
The
commenter
attached
a
copy
of
the
USGS
briefing.
The
commenter
stated
that
the
data
suggest
that
monitored
mercury
wet
deposition
is
directly
related
to
the
quantity
of
mercury
emissions
within
50
km.

One
commenter
(
OAR­
2002­
0056­
4177)
opposed
a
cap
and
trade
approach
under
section
111
or
112.
The
commenter
submitted
that
State
ambient
monitoring
shows
that
mercury
emissions
create
hot
spots
downwind
of
sources.
The
commenter
believed
a
national
trading
program
would
doom
certain
areas
of
the
country
to
unacceptably
high
concentrations.
Given
the
current
concentrations
in
the
Northeast,
the
commenter
felt
Maine
would
likely
continue
to
be
located
in
a
hot
spot.

The
commenter
(
OAR­
2002­
0056­
3449)
stated
mercury
emissions
remaining
after
compliance
with
a
cap
and
trade
program
would
cause
unacceptable
adverse
health
effects;
hot
spots
would
remain.
The
commenter
noted
that
EPA's
rationale
stressed
that
the
health
risks
associated
with
mercury
emissions
from
power
plants
are
uniquely
global,
rather
than
local
.
According
to
the
commenter,
this
dismisses
the
importance
of
local
impacts
from
heightened
deposition
near
power
plants
and
the
regional
impacts
from
overlapping
deposition
pattern.
The
commenter
submitted
that
in
general,
regions
with
the
highest
deposition
are
the
same
regions
where
local
and
regional
sources
make
significant
contributions
to
the
total
mercury
load.
It
was
clear
to
the
commenter
that
mercury
emitted
from
coal­
burning
power
plants
is
deposited
much
more
in
some
areas
than
other.
The
commenter
submitted
that
a
cap
and
trade
approach
would
exacerbate
the
regional
impacts.
The
commenter
noted
that
about
30
percent
of
generating
capacity
has
shorter
stacks
that
tend
to
result
in
more
local
deposition.
These
are
typically
smaller,
older
plants
that
would
not
likely
be
controlled
under
a
cap
and
trade
program.
The
commenter
believed
regional
and
local
impacts
could
increase
in
regions
where
these
plants
are
5­
51
prevalent.
The
commenter
stated
large
hot
spots
exist
now
across
areas
too
big
to
be
called
"
spots."
These
include
entire
regions,
especially
in
the
Northeast
and
Great
Lakes.
The
commenter
claimed
this
is
confirmed
by
deposition
monitoring
data
collected
by
states
and
the
by
widespread
fish
advisories.
The
commenter
concluded
that
marginal
regional
decreases
would
not
solve
the
regional
or
local
problems.
In
some
cases,
emissions
may
increase
if
plants
increase
coal
use.

One
commenter
(
OAR­
2002­
0056­
3435)
stated
EPA
should
abandon
cap
and
trade
because
of
its
weakness
in
control
of
a
HAP
and
concern
for
possible
hot
spot
problems.
The
commenter
submitted
that
recent
studies
(
New
Jersey
Mercury
Task
Force
Reports,
Mercury
Emissions
from
Coal­
fired
Power
Plants
by
NESCAUM,
and
Integrating
Atmospheric
Mercury
Deposition
with
Aquatic
Cycling
in
South
Florida
have
shown
that
mercury
is
deposited
much
closer
to
the
source
of
emissions
than
NO
x
or
SO
2
emissions
and
poses
a
much
greater
health
and
environmental
impact.
The
commenter
noted
that
Georgia
already
has
areas
of
high
mercury
concentrations
in
the
southern
part
of
the
state
where
physical
and
chemical
conditions
favor
metethylation
and
bioaccumulation
of
mercury.
The
commenter
believed
utility
units
within
these
airsheds
must
reduce
emissions
to
the
maximum
extent
possible.
The
commenter
asserted
that
any
aspect
of
a
program
that
would
allow
less
than
maximum
control
is
unacceptable.

Several
commenters
(
OAR­
2002­
0056­
2817,
­
2819)
supported
MACT
standards
under
CAA
section
112(
d)
to
address
mercury
hot
spots
associated
with
emissions
of
oxidized
mercury
from
coal­
fired
boilers.
One
of
the
commenters
(
OAR­
2002­
0056­
2817)
contended
that
while
science
may
not
be
conclusive
on
some
aspects,
EPA
should
err
on
the
side
of
public
health
and
adopt
more
stringent
limits.
The
commenter
cited
potential
legal
concerns,
the
hazardous
nature
of
mercury
and
the
potential
for
hot
spots
as
reasons
EPA
should
abandon
the
cap
and
trade
approach.
The
commenter
believed
cap
and
trade
may
be
appropriate
for
regional
pollutants
such
as
SO
2
and
NO
x,
but
not
for
HAP.

One
commenter
(
OAR­
2002­
0056­
3210)
stated
that
EPA's
conclusions
about
the
benefits
of
a
cap
and
trade
program
for
mercury
do
not
reflect
current
science,
environmental
considerations,
engineering,
or
economics.
The
commenter
noted
the
Utility
RTC
concluded
that
the
Great
Lakes,
Ohio
River
Valley,
the
Northeast,
and
scattered
areas
in
the
South
are
predicted
to
have
the
highest
annual
deposition
rates.
The
commenter
also
noted
that
recent
studies
show
that
US
sources
are
the
main
contributors.
The
commenter
believed
the
cap
and
trade
program
would
promote
hot
spots
and
allow
continuation
of
regional
concentrations.
The
commenter
stated
that
regional
concentrations
could
be
reduced
much
sooner
through
appropriate
MACT
standards.

One
commenter
(
OAR­
2002­
0056­
2878)
opposed
cap
and
trade
and
cited
several
scientific
and
policy
concerns
including
lack
of
safeguards
to
protect
the
public
health
and
secure
additional
needed
reductions,
toxicity
of
mercury
and
tendency
to
bioaccumulate
in
the
food
chain,
potential
for
hot
spots,
and
environmental
justice.
According
to
the
commenter,
an
initial
analysis
showed
that
the
top
33
percent
of
the
largest
plants
have
stack
heights
about
twice
as
tall
as
the
bottom
33
percent
lowest
emitters.
Short
stacks
could
contribute
to
more
local
deposition.
5­
52
The
commenter
submitted
that
to
the
extent
that
trading
shifts
emissions
from
larger
to
smaller
plants,
the
maximum
local
deposition
would
be
about
4
times
higher
for
each
pound
of
mercury.

Several
commenters
(
OAR­
2002­
0056­
2219,
­
3526)
opposed
the
cap
and
trade
approach
because
it
would
have
disproportionate
impacts
on
the
Great
Waters,
including
the
Great
Lakes
region
and
worsen
existing
hot
spots
and
may
cause
new
ones.
One
commenter
(
OAR­
2002­
0056­
2219)
stated
that
not
requiring
controls
on
all
facilities
would
further
contaminate
important
food
supplies
for
sensitive
populations
already
impacted
by
the
largest
concentration
of
coal­
fired
power
plants
in
the
U.
S.
According
to
the
commenter,
except
for
the
Everglades,
the
Great
Lakes
have
the
highest
mercury
deposition
rate
in
the
world.
According
to
an
EPA
mass
balance
study,
86
percent
of
mercury
deposited
to
Lake
Michigan
comes
from
atmospheric
sources
 
30
percent
of
these
emissions
are
from
local
sources
near
Chicago
and
the
number
of
potential
local
sources
of
mercury
is
increasing.
The
commenter
claimed
that
the
health
of
women,
children,
and
other
sensitive
populations
will
be
at
further
risk.
The
other
commenter
(
OAR­
2002­
0056­
3526)
stated
that
cap
and
trade
is
inconsistent
with
EPA's
prior
determination
that
it
would
protect
the
Great
Waters
through
faithful
enactment
of
section
112
without
a
cap­
and­
trade
approach
(
63
FR
14090,
March
24,
1998).
The
commenter
noted
that
a
cap
and
trade
approach
would
not
guarantee
that
units
responsible
for
mercury
and
other
HAP
pollution
to
the
Great
Waters
would
have
to
adopt
mercury
controls.
section
112(
m)
of
the
CAA
prohibits
EPA
from
adopting
a
program
to
control
HAP
that
does
not
assure
adequate
safeguards
for
the
Great
Waters.
The
commenter
asserted
the
cap
and
trade
program
can
not
address
the
adverse
impacts
that
units
currently
have
on
the
Great
Waters
and
could
result
in
even
more
harm.
The
commenter
stated
that
if
EPA
does
adopt
a
cap
and
trade
program,
it
must
explain
how
this
approach
fulfills
its
nondiscretionary
duties
to
protect
the
Great
Waters.

One
commenter
(
OAR­
2002­
0056­
2219)
opposed
the
cap
and
trade
approach
because
scientific
understanding
of
the
percentage
of
mercury
that
is
converted
to
methylmercury
(
the
form
that
most
readily
enters
the
food
chain)
is
limited.
The
commenter
noted
that
results
of
the
Florida
Everglades
study
showed
that
reducing
emissions
on
a
regional
basis,
facility
by
facility,
would
achieve
reductions
in
the
ecosystem,
but
it
is
not
a
one­
to­
one
correlation.
In
this
study,
a
99
percent
reduction
in
emissions
from
incinerators
yielded
a
60
percent
reduction
of
mercury
in
fish
tissues.
The
commenter
stated
it
is
not
clear
that
a
cap
and
trade
program
would
achieve
the
significant
local
reductions
needed
to
improve
the
ecosystem.
The
commenter
believed
if
all
facilities
reduced
emissions,
then
local
and
national
emissions
would
also
be
reduced.
The
commenter
also
stated
that
mercury
emissions
must
be
addressed
on
a
facility­
by­
facility
approach
since
the
most
toxic
form
of
mercury
(
reactive
gas
phase
mercury
or
RGM)
is
deposited
locally.
According
to
the
commenter,
trading
schemes
would
create
regional
areas
of
higher
mercury
releases
that
would
further
damage
food
sources
and
human
health
 
particularly
in
the
Great
Lakes
area
where
there
is
a
high
percentage
of
subsistence
fishing.

According
to
the
commenter
(
OAR­
2002­
0056­
3437),
The
2003
results
of
the
EPA
Office
of
Water
study,
"
Draft
Mercury
REMSAD
Deposition
Modeling
Results"
reinforced
their
concerns.
This
modeling
showed
that
at
mercury
hot
spots,
local
emission
sources
within
a
state
can
be
the
dominant
source
of
deposition,
commonly
accounting
for
50­
80
percent
of
the
mercury
deposition.
According
to
the
commenter,
in
state
sources
contributed
more
than
50
percent
of
5­
53
the
pollution
to
sites
in
the
top
8
worst
hot
spot
states
(
Michigan,
Maryland,
Florida,
Illinois,
South
Carolina,
North
Carolina,
Pennsylvania,
and
Texas).

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

Many
commenters
(
OAR­
2002­
0056­
1625,
­
1627,
­
1673,
­
1790,
­
1859,
­
1969,
­
2251,
­
2332,
­
2431,
­
2547,
­
2560,
­
2578,
­
2725,
­
2830,
­
2833,
­
2835,
­
2841,
­
2850,
­
2861,
­
2862,
­
2897,
­
2900,
­
2907,
­
2915,
­
2918,
­
2922,
­
2929,
­
2948,
­
3353,
­
3444,
­
3463,
­
3478,
­
3513,
­
3530,
­
3537,
­
3539,
­
3546,
­
4891)
believed
that
a
mercury
cap­
and­
trade
program
will
not
create
hot
spots.
Many
of
these
commenters
(
OAR­
2002­
0056­
1625,
­
1790,
­
2251,
­
2547,
­
2560,
­
2725,
­
2833,
­
2835,
­
2897,
­
2900,
­
2915,
­
2922,
­
2948,
­
3353,
­
3463,
­
3513,
­
3539)
cited
review
of
recent
studies
as
directly
refuting
that
claim.

Several
commenters
(
OAR­
2002­
0056­
1625,
­
2915)
stated
there
are
several
facts
that
suggest
that
localized
effects
will
not
occur
with
a
mercury
emissions
trading
program.
The
commenters
pointed
out
that
mercury
emissions
from
utilities
in
the
U.
S.
represent
only
a
portion
of
emissions
 
less
than
10
percent
of
total
North
American
emissions
and
about
one
percent
of
total
global
mercury
emissions.
Regulations
or
legislation
will
make
this
small
contribution
even
smaller.
According
to
the
commenters,
a
recent
study
by
EPRI
found
that
reducing
power
plant
generation
mercury
emissions
will
produce
minimal
benefits
 
a
47
percent
cut
would
yield
less
than
a
one
percent
drop
in
exposure.
The
commenters
submitted
that
even
drastic
reductions
in
utility
mercury
emissions
will
have
a
minimal
effect
on
state
fish
advisories.
Furthermore,
most
power
plant
mercury
emissions
are
of
the
elemental
form
soon
after
release
and
therefore
enter
the
global
pool
instead
of
depositing
nearby.
The
commenters
cited
a
recent
study
by
Brookhaven
National
Laboratory
that
found
only
4
to
7
percent
of
mercury
is
deposited
locally.
Another
fact
presented
by
the
commenters
is
that
regulations
to
control
SO
2
and
NO
x
will
require
the
installation
of
pollution
controls
that
will
also
capture
the
forms
of
mercury
that
tend
to
deposit
nearby.
This
is
because
the
species
of
mercury
that
are
deposited
locally­
oxidized
and
particulate
mercury­
are
controlled
by
the
same
equipment
that
controls
fine
particles,
SO
2
and
NO
x.

Another
commenter
(
OAR­
2002­
0056­
3478)
stated
that
current
research
indicates
that
North
American
anthropogenic
sources
were
calculated
to
contribute
only
from
25
to
32
percent
of
the
total
mercury
deposition
over
the
continental
U.
S.
The
commenter
stated
that
the
amount
of
local
deposition
of
mercury
is
in
part
a
function
of
the
speciation
of
the
mercury
emitted
from
the
source.
The
commenter
further
stated
that
mercury
is
typically
emitted
both
in
its
elemental
form
and
as
oxidized
mercury.
According
to
the
commenter,
elemental
mercury
tends
to
enter
the
global
mercury
cycle,
and
may
be
retained
in
the
atmosphere
for
up
to
one
year
before
deposition,
creating
the
possibility
that
it
will
travel
around
the
earth
several
times
before
deposition.
Similarly,
one
commenter
(
OAR­
2002­
0056­
1859)
agreed
that
no
hot
spots
should
occur,
5­
54
particularly
as
it
pertains
to
units
in
the
west
and
to
facilities
that
burn
sub­
bituminous
coals.
The
commenter
noted
that
sub­
bituminous
coals
are
typically
low
in
SO
2
and
mercury
and
when
combusted,
produce
primarily
elemental
mercury
which
tends
to
not
deposit
near
the
source.

One
commenter
(
OAR­
2002­
0056­
2431)
cited
modeling
by
EPA,
DOE,
the
Brookhaven
National
Laboratory,
and
EPRI
and
concluded
that
emissions
trading
would
not
create
hot
spots.
The
commenter
claimed
that
studies
of
the
acid
rain
program
trading
program
demonstrated
that
trading
did
not
significantly
change
where
emissions
actually
occurred
when
compared
to
a
command
and
control
approach.
The
commenter
stated
trading
would
not
cause
local
impacts
because
most
emissions
become
elemental
soon
after
release
and
enter
the
global
pool
instead
of
depositing
nearby.
Also
new
SO
2
and
NO
x
rules
will
require
controls
that
also
capture
the
forms
of
mercury
that
tend
to
deposit
nearby.
The
commenter
further
submitted
that
overall
emissions
would
still
decline
even
if
some
utilities
did
not
install
controls
because
of
the
cap.
The
commenter
stated
that
emissions
trading
also
creates
economic
incentives
which
bring
about
the
greatest
reduction
from
the
highest
emitting
sources.
The
commenter
concluded
thus,
hot
spots
would
not
occur.

One
commenter
(
OAR­
2002­
0056­
3513)
pointed
out
that
EPRI
modeling
has
indicated
that
mercury
should
be
studied
on
a
global
scale
 
not
a
local
or
even
national
one.
EPRI's
analysis
showed
that
the
majority
of
mercury
emitted
from
coal­
fired
units
is
in
the
elemental
form
which
does
not
deposit
locally,
but
enters
the
global
pool
and
circulates
in
the
atmosphere
for
six
months
to
a
year
on
average.
The
soluble
forms
of
mercury
are
more
likely
to
deposit
nearby.
The
commenter
submitted
however,
if
the
proposed
rule
is
enacted
along
the
same
timeline
as
the
Interstate
Air
Quality
Rule,
most
units
will
be
required
to
install
SCR's
and/
or
scrubbers
which
will
capture
most
soluble
forms
of
mercury.

One
commenter
(
OAR­
2002­
0056­
2835)
stated
that
the
acid
rain
program
has
cost
effectively
achieved
a
41
percent
reduction
in
SO
2
emissions
from
1980
through
2002
(
despite
a
significant
increase
in
electric
generation)
and
done
so
without
any
evidence
of
local
"
hot
spots"
occurring.
The
commenter
also
pointed
out
that
the
NO
x
SIP
Call
rule
has
adopted
an
interstate
cap­
and­
trade
program
that
has
achieved
significant
reductions
in
NO
x
emissions
from
the
power
sector.

Several
commenters
(
OAR­
2002­
0056­
2251,
­
2833,
­
2948,
­
3530)
submitted
that
as
"
proof"
of
the
"
hot
spot"
theory,
some
groups
have
cited
a
study
of
mercury
in
the
Florida
Everglades.
According
to
the
commenters,
many
claims
about
this
study
contain
erroneous,
unsubstantiated
assertions
that
it
"
proves"
controls
on
local
sources
would
result
in
a
fairly
rapid
decline
of
mercury
in
the
regional
environment.
The
commenters
asserted
the
study
does
not
prove
such
assertion
because:

°
The
mercury
reductions
in
south
Florida
were
from
municipal
and
medical
waste
incinerators,
not
from
power
plants.
The
mercury
emissions
from
these
incinerators
are
generally
in
a
water­
soluble
form.
5­
55
°
Many
studies
have
shown
that
the
characteristics
of
the
water
body,
not
the
amount
of
atmospheric
deposition,
dictate
the
eventual
levels
of
mercury
in
fish.
The
Everglades
is
a
unique
ecological
and
climatological
system,
strikingly
different
from
other
U.
S.
waterbodies;
it
should
not
be
considered
representative
of
water
bodies
in
other
states,
or
even
of
other
parts
of
Florida.
Before
states
decide
to
take
action
beyond
the
federal
mercury
rules,
they
should
assess
their
state's
actual
situation.

°
The
claim
that
changes
in
mercury
emissions
will
result
in
rapid
changes
in
the
amount
of
methylmercury
found
in
fish
is
not
supported
by
the
study's
data
or
findings.
Despite
decreases
in
mercury
emissions
from
incinerators,
data
measurements
and
long­
range
transport
modeling
indicate
that
the
amount
of
mercury
being
deposited
in
the
Everglades
overall
has
changed
little.
Modeling
of
mercury
transport
conducted
by
EPA
and
EPRI
has
led
to
the
conclusion
that
over
60
percent
of
mercury
deposited
in
Florida
originates
outside
the
state.

°
Extensive
measurements
around
power
plants
have
failed
to
show
local
increase
in
mercury
at
ground
level
or
in
nearby
waterways.
EPA
reached
this
conclusion
in
its
1997
Mercury
Study
Report
to
Congress,
and
this
finding
has
been
supported
by
recent
studies
at
a
large
power
plant
in
Maryland.

The
commenters
concluded
that
clearly,
the
Florida
Everglades
study
does
not
support
applying
the
"
hot
spot"
theory
to
other
states,
or
even
other
parts
of
Florida.

Regarding
the
South
Florida
Report,
another
commenter
(
OAR­
2002­
0056­
3444)
had
several
comments.
The
commenter
referenced
several
commenters
that
suggested
that
this
Report
demonstrated
the
existence
of
"
hot
spots"
and
further
demonstrated
that
limiting
mercury
releases
from
coal­
fired
power
plants
(
CFPPs)
would
cause
rapid
decreases
in
mercury
concentrations
in
the
local/
regional
environment.
The
commenter
submitted
that
neither
conclusion
followed
from
the
Florida
report.
While
the
commenter
acknowledged
an
extensive
and
valuable
body
of
research
has
been
conducted
in
south
Florida,
the
commenter
found
two
major
problems
with
how
the
results
have
been
interpreted
(
both
in
the
report
itself
and
by
others).
First,
to
what
degree
has
the
relationship
between
local
mercury
emissions
reductions
(
known
to
have
decreased
dramatically
between
the
late
1980s
and
the
early
1990s)
and
decreasing
levels
of
mercury
in
biota
(
documented
to
have
occurred
between
the
early
1990s
and
the
present,
but
not
to
the
same
degree
everywhere
in
south
Florida)
been
established,
or
put
another
way,
how
much
of
the
latter
was
caused
by
the
former?
Second,
to
the
extent
we
know
this
relationship,
to
what
degree
does
it
apply
to
CFPPs
in
other
parts
of
the
country?

The
commenter
stated
that
relative
to
the
first
issue,
while
there
is
an
evolving
weight
of
evidence
that
there
is
some
relationship
between
local
mercury
emissions
reductions
and
local
biotic
response,
the
degree
of
the
relationship
has
not
been,
nor
can
it
be,
definitively
quantified
for
the
time
period
addressed
by
the
Florida
study.
First,
the
commenter
noted
there
is
no
deposition
record
spanning
the
time
before
and
after
the
emission
reductions.
Inferences
from
sediment
cores
are,
at
best
suggestive,
and
at
worst
inconsistent.
Second,
the
commenter
submitted
that
while
aquatic
model
hindcasting
(
currently
being
conducted)
suggests
a
link
5­
56
between
deposition
and
response
in
aquatic
biota,
it
cannot
allocate
the
share
of
deposition
changes
coming
from
other
source
changes
and
the
share
of
the
biotic
response
coming
from
non­
depositional
ecosystem
changes
(
e.
g.,
hydrological,
sulfate,
phosphorous,
DOC,
etc.).
To
the
extent
that
U.
S.
emissions
reductions,
European
emissions
reductions,
and
other
worldwide
emissions
changes
were
affecting
the
changes
in
deposition
at
the
same
time
(
also
a
study
in
progress),
it
would
moderate
the
degree
that
local
emissions
changes
were
having
on
deposition
changes.
The
commenter
also
stated
that
similarly,
to
the
extent
hydrological
and
other
ecosystem
changes
were
also
affecting
biotic
mercury
levels,
it
would
moderate
the
role
of
deposition
changes.
Finally,
the
commenter
believed
atmospheric
modeling
conducted
as
part
of
the
Florida
Study
was
flawed
in
several
ways.
The
modeling
erroneously
assumed
that
mercury
deposition
in
waterways
comes
only
from
local
sources.
The
commenter
noted
that
modeling
by
EPA
and
EPRI
has
shown
that
more
than
90
percent
of
the
mercury
that
currently
deposits
in
south
Florida
originates
outside
the
United
States.
The
commenter
conceded
that
in
the
late
1980s
it
is
likely
that
the
local
contribution
was
somewhat
higher
than
today,
it
could
not
have
been
100
percent.
The
commenter
summarized,
the
magnitude
of
the
connection
between
local
mercury
emissions
reductions
in
south
Florida
and
local
biotic
response
is
tempered
by
the
contributions
from
other
mercury
emissions
changes
worldwide
and
other
ecosystem
changes
affecting
the
biotic
response.

Relative
to
the
issue
of
extrapolation,
the
commenter
stated
there
are
numerous
arguments
why
the
results
cannot
be
extrapolated
to
CFPPs
in
other
areas
of
the
country.
The
commenter
submitted
that
whatever
relationship
that
may
exist
is
unique
to
the
type
of
emissions,
the
climatology,
and
the
type
of
ecosystem
that
exists
in
south
Florida.
First,
as
demonstrated
above,
we
don't
know
the
magnitude
of
the
connection
between
local
mercury
emissions
and
local
biotic
responses.
Second,
municipal
and
medical
waste
incinerators
 
not
power
plants
 
are
the
source
of
industrial
mercury
emissions
in
south
Florida
that
are
referenced
in
the
Florida
report.
Incinerators
produce
far
higher
percentages
of
ionic
mercury
 
the
form
of
mercury
that
is
water­
soluble
and
more
readily
deposited
 
than
coal­
fired
power
plants
and
have
far
shorter
stack
heights
resulting
in
the
potential
for
higher
amounts
of
mercury
being
deposited
near
these
sources.
Third,
there
is
evidence
that
ionic
mercury
emissions
from
CFPPs
rapidly
converts
to
elemental
mercury
 
the
form
of
mercury
having
a
long
atmospheric
residence
time
 
a
phenomena
not
observed
in
incinerators,
which
suggest
that
the
link
between
emissions
and
local
deposition
would
be
even
less
for
CFPPs.
Fourth,
the
climatology
of
south
Florida
is
unique
to
the
U.
S.
with
daily,
deep
convective
thunderstorms
that
converge
over
the
Everglades
in
the
summer.
Fifth,
the
Everglades
are
not
representative
of
U.
S.
waterways
because
they
are
in
a
subtropical
zone
with
no
distinct
seasons
and
high
rainfall
in
the
summer,
contain
shallow
water
with
very
low
flow
rates,
and
with
bottom
sediments
that
differ
from
those
in
other
locations.
Other
waterbodies
also
have
different
levels
of
acidity,
biological
activity,
dissolved
oxygen,
and
turbidity.
The
commenter
asserted
that
all
of
these
differences
could
dramatically
affect
mercury
cycling
and
uptake
by
biological
organisms
and
make
extrapolation
of
the
Florida
results
to
other
areas
of
the
country
inappropriate.
The
commenter
pointed
out
that
in
Minnesota,
for
example,
mercury
emissions
also
have
declined
dramatically
from
1990
to
2000
(
about
68
percent
 
Minnesota
Pollution
Control
Agency,
March
2004),
yet
mercury
in
fish
of
that
area
has
not
changed
significantly
in
the
last
15
years.
The
commenter
summarized,
the
extrapolation
of
the
Florida
5­
57
mercury
emissions
to
deposition
or
deposition
to
biotic
response
relationships,
to
other
sources
and
areas
of
the
country
is
inappropriate.

The
commenter
stated,
accordingly,
the
Report
cannot
justify
a
conclusion
by
EPA
that
coal­
fired
power
plants
create
local
"
hot
spots"
nor
can
the
results
be
extrapolated
to
CFPPs
in
other
parts
of
the
country.
The
commenter
added
that
the
Report
itself
recognizes
its
limited
focus
and
is
replete
with
assumptions,
caveats,
cautions
and
recommendations
for
further
work,
none
of
which
is
mentioned
in
the
references
or
citations
above.
More
detailed
comments
regarding
the
Report
are
summarized
as
follows:

°
The
analysis
upon
which
the
Report
relies
is
a
work­
in­
progress,
and
therefore
the
conclusions
are
at
least
premature.
The
Report
expressly
recommends
that
further
information
be
obtained
and
provides
seven
specific
cautions
when
interpreting
the
results.

°
Any
claim
that
cost­
effective
control
strategies
have
substantially
reduced
mercury
concentrations
in
south
Florida's
fish
and
wading
birds
is
premature.
A
research
project
in
excess
of
$
300,000
has
been
designed
specifically
to
shed
light
on
this
assertion,
that
is,
to
elucidate
between
competing
hypotheses
for
explaining
the
observed
reduction
of
mercury
in
south
Florida's
biota.

°
Not
all
ecosystems
are
created
equal.
Mercury
may
be
accumulated
up
the
food
chain
differently
in
other
ecosystems
than
in
the
Everglades.
To
the
extent
decreases
in
local
reactive
mercury
emissions
result
in
local
declines
in
concentrations
in
fish
and
wildlife
might
be
true
in
the
area
of
study
(
central
Everglades),
there
are
substantial
differences
in
responses
even
across
the
Everglades
ecosystem.
There
is
also
evidence
of
a
general
decline
in
mercury
in
biota
in
areas
that
are
remote
from
local
sources.

°
While
it
may
be
true
that
total
quantities
of
mercury
emitted
from
CFPPs
are
substantially
larger
than
that
of
incinerators
on
a
world­
wide
basis,
the
form
of
mercury
emitted
from
coal
plants
is
more
in
a
form
(
non­
reactive)
not
readily
deposited
on
a
local
scale.
In
addition,
recent
research
indicates
that
any
reactive
mercury
that
is
emitted
from
coal­
fired
power
plants
is
largely
transformed
to
the
non­
reactive
form
before
deposition
can
occur.
Furthermore,
a
press
release
from
the
Resources
Committee,
US
Congress,
states
that
U.
S.
coal­
fired
power
plants
emit
only
1
percent
of
the
total
global
mercury
emissions,
citing
peer­
reviewed
research
published
in
Atmospheric
Environment,
2003.
In
addition,
emissions
measurements
analyses
show
that
the
data
quality
varies
widely
between
different
sources
and
geographically.

°
The
Report
describes
impressive
reductions
in
mercury
emissions
achieved
by
municipal
waste
incinerators
and
by
the
closing
of
numerous
small
medical
waste
incinerators.
These
reductions
and
the
implied
reductions
in
mercury
inputs
to
the
Everglades
ecosystem
must
be
considered
in
the
context
of
the
high
percentage
of
reactive
mercury
emitted
from
these
facilities,
75
percent
and
95
percent,
respectively.
5­
58
°
The
Report
does
not
support
the
idea
that
the
Lake
Annie
(
sediment
core)
data
shows
a
peak
in
deposition
coinciding
with
the
peak
in
emissions,
followed
by
a
rapid
decline
consistent
with
emission
reductions
from
the
Dade
and
Broward
County
incinerators
150
miles
away.
The
implication
that
emissions
from
the
Dade
and
Broward
County
incinerators
affected
mercury
accumulation
in
the
Lake
Annie
cores
is
not
supported.
Researchers
have
postulated
that
mercury
reduction
effects
can
be
seen
60
miles
from
an
emission
source.
However,
prevailing
winds
from
Dade
and
Broward
counties
are
unlikely
to
cause
consistent
depositional
impacts
in
an
area
northwest
of
Lake
Okeechobee.
In
addition,
the
magnitude
of
decrease
(
assuming
it
has
been
corrected
for
focusing
and
rainfall)
was
small
and
should
have
been
noted
as
evidence
for
local
sources
not
playing
much
of
a
role.

°
A
modern
and
retrospective
study
of
mercury
in
feathers
from
wading
birds
is
cited
as
following
the
pattern
of
mercury
emissions
from
1920
to
2002.
However,
a
modern
and
retrospective
study
of
mercury
content
in
hair
of
raccoons
(
Porcella
et
al.,
2004)
failed
to
demonstrate
a
significant
difference
over
the
last
50
years
in
south
Florida.
However,
a
large
difference
existed
between
sites
(
up
to
a
factor
of
20)
for
raccoon
hair
mercury
in
both
modern
and
historic
samples.
The
difference
between
the
wading
bird
data
and
the
raccoon
data
may
be
due
to
a
broader
sampling
area
for
raccoons
(
across
the
entire
south
Florida
peninsula),
compared
to
feather
collections
from
specific
rookeries.

°
The
idea
that
reductions
in
mercury
deposition
will
be
more
dramatic
closer
to
Broward
and
Dade
counties
where
the
majority
of
emissions
reductions
from
incinerators
occurred
is
also
not
supported.
Specifically,
the
Florida
Atmospheric
Mercury
Study
(
referred
to
in
comment
g)
results
do
not
bear
this
out.

°
Finally,
the
South
Florida
Report
characterizes
mercury
as
a
"
now
well­
understood
neurotoxin."
This
is
certainly
arguable
since
major
studies
of
neurological
effects
of
prenatal
mercury
exposure
in
children
are
not
in
agreement.
No
one
seriously
disputes
the
fact
that,
at
high
levels
of
exposure
and
in
laboratory
settings,
mercury
is
toxic
to
the
brain.
However,
setting
an
exposure
limit
for
regulatory
purposes
should
use
the
best
data
available
from
the
most
realistic
and
broadly
generalisable
studies.

One
commenter
(
OAR­
2002­
0056­
2251)
claimed
that
new
research
from
Michigan,
a
state
with
significant
coal­
based
electricity
generation,
further
discredits
the
"
hot
spot"
theory.
A
March
2004
study
conducted
for
the
EPRI
by
Atmospheric
and
Environmental
Research,
Inc.
found
that
"
Mercury
emissions
from
Michigan
coal­
fired
power
plants
are
calculated
to
contribute
between
0.5
and
1.5
percent
to
total
mercury
deposition
over
each
of
the
Great
Lakes
and
about
2
percent
statewide".
The
commenter
enclosed
a
copy
of
this
study,
Modeling
Deposition
of
Atmospheric
Mercury
in
Michigan
and
the
Great
Lakes
Region.

Several
commenters
(
OAR­
2002­
0056­
2251,
­
2833,
­
3530)
also
noted
that
according
to
the
rule's
preamble,
EPA
"
does
not
expect
any
local
or
regional
hot
spots"
if
it
selects
the
cap
and
trade
approach
and
will
consider
using
trading
ratios
to
address
regional
differences
if
they
occur.
The
preamble
also
made
it
clear
that
states
will
have
the
ability
to
address
any
remaining
local
5­
59
health­
based
concerns
if
the
EPA
selects
the
section
111
cap
and
trade
option.
The
commenters
pointed
out
that
indeed,
the
Clean
Air
Act
provides
states
with
discretion
to
enact
more
stringent
air
quality
regulations
than
required
by
the
Act,
with
the
exception
of
certain
limitations
for
automotive
emissions.
States
would
be
free
to
develop
specific
mercury
control
strategies
to
supplement
the
final
federal
rule,
regardless
of
its
form
or
level
of
stringency.

Several
commenters
(
OAR­
2002­
0056­
2830,
­
3463)
believed
that
mercury
allowance
trading
will
not
cause
adverse
local
environmental
or
health
impacts
because
most
power
plant
mercury
emissions
become
elemental
mercury
soon
after
release
and
enter
the
global
pool
instead
of
depositing
near
the
power
plant
from
which
it
originates.
Commenter
OAR­
2002­
0056­
3463
stated
that
elemental
mercury
is
not
as
likely
to
be
deposited
locally
as
is
particulate
and
oxidized
mercury.
According
to
the
commenter,
a
comparison
of
"
Wet
Deposition"
data
to
"
Total
Mercury
Concentration"
data
from
the
National
Atmospheric
Deposition
Program/
Mercury
Deposition
Network
documents
strongly
supports
the
conclusion
that
deposition
is
more
a
function
of
precipitation
than
proximity
to
emission
sources.
The
commenter
also
pointed
out
that
the
proposed
IAQR
rules
to
control
SO
2
and
NO
x
will
require
the
installation
of
pollution
controls
that
also
will
capture
the
forms
of
mercury
that
tend
to
deposit
nearby.

One
commenter
(
OAR­
2002­
0056­
3353)
stated
that
based
on
the
known
science
of
mercury
transport,
transformation,
and
health
effects,
the
Agency
proposal
to
control
mercury
by
a
cap
and
trade
program
is
appropriate
and
health
protective.
The
commenter
presented
extensive
information
on
the
science
of
mercury
(
see
section
6
of
e­
docket
item
OAR­
2002­
0056­
3353)
supporting
the
commenter's
belief
that
a
cap
and
trade
approach
will
not
endanger
public
health
or
result
in
hot
spots
of
mercury
health
risk.
The
commenter
stated
that
it
will,
on
the
other
hand,
encourage
the
continuing
development
of
low
cost
mercury
controls.
As
the
program
proceeds
and
experience
is
gained
with
various
control
options,
the
commenter
believed
the
cost
of
control
will
be
explicitly
identified.

One
commenter
(
OAR­
2002­
0056­
2431)
supported
the
cap
and
trade
approach
because
mercury
exposure
does
not
present
a
public
health
concern
warranting
stricter
regulation
under
a
MACT
standard.
According
to
the
commenter,
recent
research
by
the
CDC
indicated
that
people
are
not
being
exposed
to
unsafe
mercury
levels
and
the
recent
Seychelles
Child
Development
Study
assessments
at
9
years
of
age
show
no
detectable
adverse
effects.
The
commenter
also
pointed
out
that
in
the
December
2000
regulatory
finding,
EPA
was
unable
to
quantify
the
connection
between
utility
mercury
emissions
and
mercury
in
fish,
citing
only
a
"
plausible
link."

One
commenter
(
OAR­
2002­
0056­
2578)
claimed
to
have
performed
an
extensive
modeling
exercise
with
state­
of­
the­
art
tools
and
data
to
explore
projected
deposition
patterns
under
both
regulatory
proposals.
The
commenter's
analysis
showed
that:

°
The
highest
levels
of
mercury
deposition
anywhere
in
the
continental
United
States
are
brought
about
primarily
by
non­
utility
sources
(
even
after
accounting
for
MACT
rules
on
those
non­
utility
sources).
5­
60
°
The
Cap
&
Trade
proposal
would
produce
larger
and
more
widespread
reductions
in
mercury
deposition
compared
to
current
emissions
than
would
the
MACT
proposal,
particularly
in
regions
with
the
highest
deposition
currently.

The
commenter
also
cited
increasing
evidence
from
laboratory,
pilot­
scale,
and
full­
scale
measurements
that
the
divalent
form
of
mercury
may
convert
to
the
far
less
soluble
elemental
form
within
power
plant
plumes
and
that
this
apparently
rapid
and
complete
conversion
would
reduce
local
scale
deposition
from
power
plants
significantly,
if
it
is
found
to
hold
for
a
wide
range
of
such
sources.
To
verify
these
preliminary
results,
the
commenter
undertook
a
field
program
at
two
power
plants
using
a
combination
of
aircraft
measurements,
surface
observations,
in­
plant
measurements,
and
coal
sampling.
At
both
power
plants
from
the
stack
to
downwind
sampling
locations,
the
commenter
reported
a
significant
increase
in
the
elemental
mercury
concentration
and
a
corresponding
decrease
in
the
divalent
mercury
concentration.
According
to
the
commenter,
these
initial
demonstrations
of
the
significance
of
a
potential
reduction
reaction
may
imply
that
utility
power
plant
mercury
emissions
contribute
less
to
downwind
wet
deposition
than
has
been
assumed
previously.

One
commenter
(
OAR­
2002­
0056­
2862)
stated
that
while
there
is
evidence
in
the
literature
regarding
apparent
linkages
between
incinerator
mercury
emissions
and
enhanced
mercury
deposition
near
these
sources,
extensive
modeling
work,
as
well
as
detailed
flue
gas
chemistry
measurements,
did
not
support
a
similar
linkage
for
coal­
fired
power
plants.
Indeed,
preliminary
results
from
the
EPRI
I
U.
S.
DOE
­
funded
plume
chemistry
work
that
is
currently
underway
and
discussed
in
EPRI's
comments
on
these
proposed
rules,
strongly
reinforced
EPA's
assertion
that
the
cap
and
trade
program
is
unlikely
to
produce
so­
called
areas
of
enhanced
mercury
deposition
near
coal­
fired
power
plants.
Based
on
these
conclusions,
the
commenter
asserted
that
EPA
should
not
require
units
in
"
sensitive"
areas
to
surrender
more
allowances
than
units
in
other
areas
deemed
less
sensitive
(
e.
g.,
requiring
some
units
to
surrender
two
allowances
for
an
ounce
of
mercury
emissions
rather
than
the
standard
one
allowance).
Commenter
OAR­
2002­
0056­
2948
also
stated
that
EPA
should
not
require
units
in
"
sensitive"
areas
to
surrender
more
allowances
than
other
areas
deemed
less
sensitive
because
this
would
significantly
and
unnecessarily
complicate
the
trading
program
and
would
lower
the
cap.
The
commenter
added
that
EPA's
proposal
did
not
describe
how
such
"
sensitive"
areas
would
be
defined,
and
only
a
very
small
portion
of
mercury
emissions
from
coal­
fired
power
plants
deposit
within
50
kilometers
in
any
event.
The
commenter
stated
that
adoption
of
this
proposal
will
only
add
a
great
deal
of
complexity
to
the
program.

Similarly,
one
commenter
(
OAR­
2002­
0056­
2861)
stated
there
is
no
basis
for
any
provision
in
EPA's
mercury
rule
to
require
the
surrender
of
more
than
one
allowance
per
ounce
of
mercury
emissions
related
to
the
alleged
issue
of
mercury
sensitive
areas
or
"
hot
spots."
The
commenter
submitted
neither
EPA
nor
anyone
else
has
made
any
demonstration
of
a
linkage
between
power
plants
in
a
given
area
and
elevated
mercury
deposition
or
exposure
in
that
area.
The
commenter
added
that
by
nature
of
the
cap
and
trade
program
and
by
nature
of
how
power
plants
operate,
there
is
no
concern
that
the
mercury
cap
and
trade
program
would
create
such
"
hot
spots."
The
commenter
noted
the
cap
and
trade
program
at
the
proposed
levels
would
achieve
a
significant
overall
reduction
in
mercury
emissions
across
the
nation.
The
commenter
5­
61
believed
the
larger,
higher
emitting
sources
are
the
sources
that
will
be
controlled.
Requiring
the
surrender
of
more
than
one
allowance
in
certain
areas
would
greatly
complicate
and
confuse
the
trading
program
and
would
result
in
a
lowering
of
the
emissions
cap.
The
commenter
stated
this
also
would
affect
the
cost
of
compliance
that
was
used
to
establish
the
performance
standard
that
is
the
basis
of
EPA's
cap
and
trade
program.
The
commenter
believed
such
a
provision
should
not
be
allowed
without
a
clearly
demonstrated
need
and
that
demonstration
would
be
extremely
subjective
as
it
relates
to
the
definition
and
identification
of
"
sensitive"
areas
and
the
sources
whose
emissions
would
be
deemed
to
impact
those
areas
and
therefore
required
to
surrender
additional
allowances.
The
commenter
concluded
that
there
is
simply
no
credible
way
to
make
such
determinations,
and
in
fact
EPRI
studies
of
mercury
deposition
and
exposure
suggest
that
such
a
program
would
not
be
justified.

One
commenter
(
OAR­
2002­
0056­
3537)
submitted
that
a
mercury
cap
and
trade
program
would
not
increase
local
mercury
deposition
in
waterbodies
close
to
regulated
Utility
Units
and
create
hot
spots.
The
commenter
stated
in
fact,
EPA's
analysis
showed
that,
if
anything,
a
cap
and
trade
program
would
help
to
protect
against
potential
hot
spots
rather
than
aggravate
them.
The
commenter
noted
that
EPA's
modeling
suggested
that
large
coal­
fired
Utility
Units,
which
are
those
units
that
tend
to
have
relatively
high
mercury
emissions,
are
likely
to
have
larger
local
deposition
footprints
than
medium
and
smaller
sized
coal­
fired
Utility
Units.
However,
the
commenter
submitted
that
the
trading
of
allowances
will
probably
lead
to
the
over
control
of
mercury
emissions
at
the
larger
Utility
Units
and
the
selling
of
allowances
to
smaller
Utility
Units.
Why?
According
to
the
commenter
it
would
make
more
economic
sense
(
due
to
economies
of
scale)
for
a
utility
to
allocate
pollution
prevention
capital
expenditures
to
its
larger,
generally
more
efficient
facilities
than
to
smaller,
generally
less
efficient
plants.
Several
other
commenters
(
OAR­
2002­
0056­
1969,
­
2841,
­
2861)
stated
that
the
most
cost­
effective
reductions
will
be
made
first
at
the
larger,
higher
emitting
sources.

The
commenter
(
OAR­
2002­
0056­
3537)
submitted
second,
the
types
of
mercury
that
are
deposited
locally
 
ionic
and
particulate
mercury
 
are
controlled
somewhat
by
the
same
type
of
equipment
that
will
be
used
to
comply
with
the
CAIR
(
i.
e.,
FGD
and
SCR).
These
types
of
mercury
are
more
likely
to
be
deposited
locally
than
elemental
mercury,
which
is
emitted
in
a
gaseous
form,
is
not
soluble
in
water,
has
a
relatively
long
life
in
the
atmosphere
and
which
remains
uncontrolled
by
FGD
and
SCR.
The
commenter
stated
that
as
utilities
invest
in
equipment
to
comply
with
not
only
the
CAIR
but
also
with
new
national
ambient
air
quality
standards
for
PM
2.5
and
ozone,
a
co­
benefit
in
mercury
control
will
be
achieved.
Those
co­
benefits
will
be
the
increased
control
of
ionic
and
particulate
mercury,
decreasing
even
further
the
extremely
small
amount
of
mercury
now
deposited
locally
by
Utility
Units.
The
commenter
claimed,
therefore,
a
mercury
cap
and
trade
program
would
lead
to
increased
control
on
the
forms
of
mercury
most
likely
to
be
involved
in
potential
hot
spots.

The
commenter
pointed
out
that
modeling
conducted
by
the
Electric
Power
Research
Institute
(
EPRI)
has
demonstrated
that
mercury
must
be
studied
and
understood
on
a
global
scale
rather
than
a
national
one.
The
commenter
stated
that
U.
S.
utility
mercury
emissions
account
for
only
1
percent
of
total
yearly
mercury
emissions
worldwide.
A
recent
report
indicated
that
the
amount
of
mercury
released
to
the
air
from
the
earth's
surface
each
year
is
estimated
to
be
5­
62
between
2700­
6000
tons,
with
another
2,000­
3,000
tons
emitted
by
human
activities,
yielding
a
total
amount
of
mercury
that
enters
the
atmosphere
each
year
of
4700­
9000
tons.
The
non­
anthropogenic
fraction
is
due
to
volcanic
action,
natural
weathering
and
re­
entrainment
of
crustal
material
and
the
re­
emission
of
mercury
associated
with
past
man­
made
emissions
since
the
Industrial
Revolution.
The
commenter
noted
that
by
comparison,
a
number
of
sources
estimate
current
emissions
of
mercury
from
U.
S.
utilities
to
be
approximately
48
tons
per
year,
which
is
less
than
8
percent
of
the
mercury
deposited
in
the
U.
S.
The
commenter
stated
that
a
2003
study
by
EPRI
indicated
that
if
ionic
mercury
emissions
from
coal­
fired
power
plants
were
reduced
by
10
percent,
mercury
deposition
in
the
U.
S.
would
decrease
by
only
0.75
percent.
If
elemental
mercury
emissions
from
coal­
fired
power
plants
were
reduced
by
10
percent,
the
resultant
drop
in
mercury
deposition
in
the
U.
S.
would
only
be
0.03
percent.

Finally,
the
commenter
stated
EPA
noted
that
States
retain
the
power
under
the
CAA
to
adopt
stricter
regulations
to
address
any
local
hot
spots
or
other
problems.
Given
the
70
percent
emission
reduction
proposed
in
EPA's
cap
and
trade
systems,
the
Agency
noted
that
it
expects
no
local
regional
hot
spots.
The
commenter
noted
however,
it
also
stated
that
it
plans
to
continue
monitoring
mercury
emissions
and
the
operation
of
the
trading
system
through
its
administration
of
the
MATS,
to
ensure
that
localized
hot
spots
do
not
materialize.
Accordingly,
the
commenter
believed
it
is
clear
that
EPA
imposition
of
a
mercury
cap
and
trade
program,
would,
if
anything,
reduce
the
potential
for
localized
hot
spots
around
affected
Utility
Units.
EPRI
provides
an
extensive
discussion
on
the
hotspot
issue
in
their
comments
and
the
commenter
respectfully
referred
EPA
to
this
discussion
as
further
evidence
that
hot
spots
will
not
be
a
concern
under
a
mercury
cap
and
trade
program.

One
commenter
(
OAR­
2002­
0056­
3546)
submitted
that
EPRI's
most
recent
research
has
shown
that
the
highest
level
of
mercury
deposition
anywhere
in
the
continental
United
States
are
brought
about
by
non­
utility
sources.
According
to
the
commenter,
EPRI's
analysis
further
demonstrated
that
the
Cap­
and­
Trade
proposal
would
produce
larger
and
more
widespread
reduction
in
mercury
deposition
than
would
the
MACT
proposal.

The
commenter
stated
that
it
is
well
understood
that
mercury
is
a
global
pollutant.
According
to
the
commenter,
EPRI
model
results
showed
that
approximately
75
percent
of
the
mercury
that
deposits
in
the
United
States
originates
from
sources
outside
the
U.
S.
For
areas
in
the
west,
the
contribution
of
global
emissions
to
mercury
deposition
may
be
as
high
as
100
percent.
The
commenter
stated
that
mercury
emissions
from
coal­
fired
power
plants
mercury
deposition
will
not
increase
in
any
area
as
a
result
of
a
cap­
and­
trade
program.
The
commenter
noted
that
modeling
work
performed
by
the
Electric
Power
Research
Institute
predicts
that
reducing
total
mercury
emissions
from
coal­
fired
power
plants
from
present
day
levels
to
15
tons
annually
will
reduce
mercury
deposition
in
the
United
States
by
6.9
percent
 
from
165.4
tons
to
153.9
tons
per
year.
The
reduction
in
deposition
in
western
states
would
be
substantially
less
since
mercury
deposition
from
global
sources
can
be
as
high
as
100
percent.

The
commenter
claimed
that
cap­
and­
trade
programs
promote
economically
efficient
decisions
to
reduce
emissions
from
power
plants.
According
to
the
commenter,
Units
with
the
highest
mercury
emissions
would
be
among
the
first
to
be
controlled
since
the
cost
per
pound
of
5­
63
mercury
controlled
would
the
lowest
at
these
units.
The
commenter
noted
that
this
economic
behavior
has
previously
been
demonstrated
in
utilities
compliance
with
EPA's
Acid
Rain
requirements
and
the
NO
x
SIP
call.
On
a
source­
by­
source
basis,
the
opportunity
to
trade
has
led
many
of
the
largest
SO
2
and
NO
x
emitters
to
clean
up
the
most,
such
that
trading
has
had
an
effect
of
cooling
potential
hot­
spots,
not
creating
them.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2560,
­
2897)
stated
that
if
hot
spots
did
occur,
focused
local
investigations
and
some
simple
constraints
would
be
the
best
available
practice
for
the
accurate
identification
of
contributing
localized
mercury
deposition
sources.
Commenter
OAR­
2002­
0056­
2560
offered
as
an
example,
based
on
the
presentation
by
Opto­
Forensics
Technologies
at
the
2004
Electric
Utility
Environmental
Conference
in
Tucson,
Arizona
the
solution
to
fish
tissue
mercury
level
reductions
may
well
lie
in
the
monitoring
and
control
of
mercury
emission
from
municipal
landfill
vents
and
not
in
the
reduction
of
local
EGU
emissions.

Commenter
OAR­
2002­
0056­
2897
offered
as
another
example,
EGUs
in
the
immediate
vicinity
of
vulnerable
ecosystems
could
be
prohibited
from
trading,
or
minimal
levels
of
mercury
reductions
at
all
facilities
could
be
required.
The
commenter
stated
this
would
still
allow
trading
to
achieve
the
greatest
reductions
where
it
is
cheapest
and
to
incentivize
the
development
of
control
technology.
The
commenter
asserts
that
in
the
unlikely
event
that
hot
spots
are
a
serious
concern,
they
can
be
readily
addressed
and
should
not
be
a
basis
for
giving
up
the
significant
benefits
offered
by
a
cap­
and­
trade
approach
to
mercury
regulation
on
a
national
basis.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

One
commenter
(
OAR­
2002­
0056­
2922)
stated
that
EPA
should
not
require
units
in
"
sensitive"
areas
to
surrender
more
allowances
than
units
in
other
areas
deemed
less
"
sensitive"
(
e.
g.,
requiring
some
units
to
surrender
two
allowances
for
each
ounce
of
mercury
emissions
rather
than
the
standard
one
allowance
per
ounce).
The
commenter
submitted
that
hot
spots
have
not
resulted
in
the
Title
IV
Acid
Rain
Program,
and,
as
discussed
above,
no
reason
exists
to
believe
they
will
occur
in
this
program.
Moreover,
requiring
different
areas
to
surrender
different
numbers
of
allowances
would
complicate
the
trading
program
and
result
in
a
lowering
of
the
cap,
contrary
to
EPA's
regulatory
determinations.
5­
64
Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

Several
commenters
(
OAR­
2002­
0056­
1625,
­
1673,
­
2547,
­
2725,
­
2850,
­
2929,
­
3478)
pointed
out
that
under
a
cap­
and­
trade
program,
the
larger
emitters
will
be
the
first
to
be
controlled.
For
example,
several
commenters
(
OAR­
2002­
0056­
1625,
­
2929,
­
3478)
stated
that
the
economics
of
trading
will
help
to
minimize
local
deposition.
The
trading
of
allowances
almost
always
involves
large
coal­
based
power
plants
controlling
their
emissions
more
than
required
and
selling
allowances
to
smaller
plants.
Thus,
economies
of
scale
of
pollution
control
investment
will
favor
investment
at
the
larger
plants
and
will
produce
reductions
in
emissions
at
the
plants
of
greatest
interest.
One
commenter
(
OAR­
2002­
0056­
2725)
stated
that
this
is
doubly
true
with
mercury;
because
ionic
mercury,
the
form
of
mercury
that
is
most
likely
to
be
deposited
near
the
plant,
is
also
the
easiest
and
least
expensive
to
control,
a
mercury
trading
program
would
result
in
emissions
reductions
at
exactly
those
plants
most
likely
to
be
responsible
for
"
hot
spots.
One
commenter
(
2929)
noted
that
the
CAIR
proposal
and
other
pending
state
and
federal
regulations
would
require
the
installation
of
pollution
controls
that
also
would
capture
the
forms
of
mercury
that
tend
to
deposit
nearby.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

One
commenter
(
OAR­
2002­
0056­
1627)
stated
that
what
has
emerged
from
monitoring
actual
mercury
deposition
is
a
far
different
picture
than
predicted
by
many
of
the
early
computer
models
which
predicted
the
presence
of
hot
spots.
The
commenter
submitted
that
actual
data
demonstrates
that
power
plants
do
not
significantly
affect
deposition.
The
commenter
believed
hot
spots
should
now
be
seen
to
simply
be
artifacts
of
the
first
generation
of
computer
models
rather
than
real
occurrences.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

Many
commenters
(
OAR­
2002­
0056­
2173,
­
2227,
­
2380,
­
2415,
­
2575,
­
2660,
­
2817,
­
2838,
­
2871,
­
2880,
­
2887,
­
2889,
­
2878,
­
2924,
­
3202,
­
3413
­
3448,
­
3452,
­
4177)
believed
5­
65
mercury
trading
may
lead
to
hot
spots.
One
commenter
(
OAR­
2002­
0056­
2173)
noted
that
concerns
about
trading
are
recognized
in
the
regulatory
finding,
including
that
the
lakes
regions
of
the
Upper
Midwest
may
be
more
sensitive
to
mercury
deposition.
The
commenter
submitted
that
a
recent
New
Hampshire
study
suggested
that
local
deposition
is
very
much
a
concern.
However,
EPA
then
claims
in
the
preamble
that
it
does
not
expect
any
local
or
regional
hot
spots
and
provides
no
support
or
anecdotal
arguments
in
support.
The
commenter
states
that
hot
sports
are
a
real
concern
in
the
midwest
because
of
the
use
of
western
sub­
bituminous
coal.
It
is
more
difficult
and
costly
to
reduce
mercury
emissions
from
this
coal
type
than
from
eastern
bituminous
coal.
Thus,
the
commenter
believed
that
utilities
would
be
more
likely
to
purchase
emission
credits
from
utilities
burning
eastern
coal
that
have
installed
controls.
The
commenter
asserted
that
the
result
would
be
that
Tribal
lands
and
the
entire
lakes
area
of
the
upper
midwest
(
which
is
particularly
sensitive
to
mercury
deposition
and
most
needing
of
reductions)
may
experience
little
or
no
benefit.
Another
commenter
(
OAR­
2002­
0056­
2227)
also
noted
that
EPA's
own
data
show
that
mercury
hot
spots
exist
and
are
associated
with
local
sources
of
air
pollution.

An
alliance
of
many
commenters
(
OAR­
2002­
0056­
2575)
stated
that
data
collected
by
the
North
American
Commission
for
Environmental
Cooperation
show
that
there
are
244
locations
in
North
American
where
the
amount
of
mercury
contamination
is
greater
than
that
which
occurs
naturally
in
the
environment.
The
commenter
also
provided
several
examples
of
the
impact
of
local
sources
on
mercury
deposition.
and
the
resulting
effects
on
wildlilfe.
The
commenter
claimed
a
cap
and
trade
program
would
only
continue
and
exacerbate
mercury
deposition
and
increase
the
number
of
hot
spots.
The
result
would
be
concentration
of
pollution
in
certain
areas
and
merely
a
reallocation
of
pollution
rather
than
reduction
or
even
an
increase.

One
commenter
(
OAR­
2002­
0056­
2838)
submitted
that
in­
state
and
regional
sources
of
mercury
in
the
Southeast
contribute
to
high
levels
of
deposition;
four
of
the
top
10
most
severe
hot
spots
are
in
Southeastern
states.
The
commenter
believed
the
cap
and
trade
program
has
great
potential
to
exacerbate
mercury
contamination
at
many
sites
by
allowing
large
plants
to
continue
emitting;
studies
show
that
this
mercury
would
be
deposited
in­
state
or
within
the
Southeast
region.
The
commenter
stated
that
according
to
EPA's
Mercury
REMSAP
Deposition
Modeling
Results,
coastal
regions
along
the
Gulf
of
Mexico
and
southern
Atlantic
will
require
more
than
75
percent
reduction
in
air
deposition
rates
to
meet
EPA's
CWA
requirements
for
methyl
mercury.

Another
commenter
(
OAR­
2002­
0056­
2878)
stated
that
recent
modeling
suggests
that
at
mercury
hot
spots,
pollution
sources
within
a
state
can
account
for
large
portions
of
that
deposition.
The
commenter
claimed
that
at
hot
spots
across
the
US,
local
sources
often
account
for
50
to
80
percent
of
the
mercury
deposition.
The
commenter
also
submitted
that
in­
state
sources
contribute
more
than
50
percent
of
the
pollution
to
sites
in
the
top
8
worst
hot
spot
states
(
Draft
Mercury
Deposition
Modeling
Results,
EPA:
OW,
2003).
The
commenter
stated
that
data
from
the
Florida
Everglades
study
showed
that
local
reductions
of
mercury
yielded
reductions
in
mercury
pollution.
The
mercury
deposition
research
in
the
Florida
Everglades,
Wisconsin,
and
southern
Ontario
also
indicated
that
the
majority
of
mercury
converted
into
methylmercury
is
from
recent
deposition,
rather
than
cycling
from
the
sediment,
suggesting
that
reducing
mercury
5­
66
emissions
from
all
coal­
fired
plants
is
a
critical
need
for
reducing
exposure
and
improving
damaged
ecosystems.

One
commenter
(
OAR­
2002­
0056­
2380,
­
3413)
also
stated
that
earlier
modeling
showed
that
local
hot
spots
are
the
primary
sources
of
mercury
deposition
within
a
state,
contributing
more
than
50
percent
of
the
pollution
to
sites
in
the
top
8
worst
hot
spot
states.
The
commenter
submitted
that
EPA
should
include
provisions
in
the
rule
to
address
hot
spots
before
they
occur.

Many
of
the
commenters
(
OAR­
2002­
0056­
2660,
­
2817,
­
2871,
­
2880,
­
2887,
­
2889,
­
2924,
­
3202,
­
3448,
­
3452,
­
4177)
referred
to
the
recent
Florida
study
(
Integrating
Atmospheric
Mercury
Deposition
with
Aquatic
Cycling
in
South
Florida,
November
2003),
which
showed
that
sources
of
mercury
can
have
significant
local
impacts.
This
report
stated
that
the
drastic
reductions
in
mercury
concentrations
in
fish
and
birds
in
the
Everglades
were
directly
linked
to
installation
of
mercury
controls
by
industries
in
South
Flordia.
One
commenter
(
OAR­
2002­
0056­
2819)
noted
that
EPA
has
already
reported
that
deposition
of
oxidized
mercury
can
be
expected
to
occur
within
50
kilometers
of
the
source;
evidence
of
the
existence
of
hot
spots
has
already
been
documented
in
the
Evers
report
(
Assessing
the
Potential
Impacts
of
Methymercury
on
the
Common
Loon
in
Southern
New
Hampshire)
and
the
Florida
Everglades
report.
The
commenter
stated
that
additional
evidence
of
the
existence
of
mercury
hot
spots
can
be
found
on
the
University
of
Michigan
website
at
http://
www.
personal.
umich.
edu/~
kalwali/
mich+
ohio.
html
.
This
website
shows
color
coded
maps
that
distinguish
the
relative
hot
spots
associated
with
mercury
emissions
from
local
sources
from
mercury
emissions
due
to
longer
range
transport
(
regional
sources).
The
commenter
asserted
that
EPA
cannot
dismiss
these
concerns.

One
commenter
(
OAR­
2002­
0056­
2819)
submitted
recent
stack
test
data
showing
that
72­
94
percent
of
the
mercury
emitted
by
coal­
fired
boilers
is
emitted
as
oxidized
mercury.
These
tests
(
2003)
used
the
Ontario
Hydro
method
to
determine
the
amount
of
total
mercury
and
the
total
amount
by
species.
According
to
the
test
data,
2003
annual
emissions
of
oxidized
mercury
from
Merrimack
Station
units
1
and
2
were
32
pounds
and
77
pounds,
respectively.
Annual
emissions
of
oxidized
mercury
from
Schiller
Station
units
4,
5,
and
6
were
7
pounds.
The
commenter
believed
that
emissions
of
this
magnitude
have
the
potential
to
cause
local
hot
spots
which
can
not
be
remedied
solely
with
a
cap
and
trade
program.
The
commenter
submitted
that
stringent
plant­
specific
MACT
limits
are
needed
to
address
local
hot
spots.
Also,
the
commenter
pointed
out
that
EPA's
prediction
that
small
and
mid­
size
units
like
Schiller
and
Merrimack
Station
would
likely
purchase
credits
rather
than
install
controls
(
see
69
FR
4702)
confirmed
that
the
cap
and
trade
would
not
address
localized
deposition
in
their
state.
The
commenter
believed
that
the
only
sure
method
for
addressing
hot
spots
would
be
to
reduce
emissions
at
their
source
through
strict
MACT
standards.
The
commenter
concluded
that
it
was
also
a
good
reason
that
more
stringent
limits
should
apply
to
all
units
regardless
of
size.

One
commenter
(
OAR­
2002­
0056­
2887)
contended
that
EPA
has
not
considered
local
deposition
that
can
disproportionately
affect
sensitive
ecosystems.
The
commenter
claimed
sources
that
purchase
allowances
in
effect
emit
uncontrolled
levels
of
all
three
species
of
mercury
­
gaseous
elemental,
reactive
gaseous
(
RGM),
and
particulate.
The
commenter
stated
trading
can
5­
67
worsen
existing
hot
spots
and
may
create
new
ones
near
powerplants
because
the
RGM
(
which
can
be
as
high
as
70
percent
of
the
total
mercury
emitted
from
a
bituminuous
plant)
has
relatively
short
travel
distances
(
up
to
50­
100
kilometers)
and
short
residence
times
in
the
atmosphere
(
1­
2
days),
tending
to
deposit
locally
near
the
source.
The
commenter
also
noted
that
recent
field
studies
showed
that
mercury
newly
deposited
to
a
zone
of
methylation
in
a
waterbody
is
more
readily
converted
to
methylmercury.
The
commenter
claimed
that,
in
addition
to
local
impacts,
the
Northeast
is
affected
by
long­
range
transport
of
elemental
mercury
because
areas
with
high
ozone
levels
oxidize
elemental
mercury
and
therefore
increase
mercury
deposition
throughout
the
airshed.
Further,
the
commenter
cited
a
report
by
the
New
Jersey
Mercury
Task
force
which
examined
local
emissions,
models,
and
results,
and
stated
that
about
half
of
the
mercury
deposited
in
New
Jersey
comes
from
relatively
nearby
sources.
One
commenter
(
OAR­
2002­
0056­
4177)
cited
the
NESCAUM
Deposition
Study
which
concluded
that
47
percent
of
mercury
deposition
in
the
Northeast
came
from
sources
within
the
region,
30
percent
from
sources
outside
the
region,
and
23
percent
from
the
global
reservoir.
One
commenter
(
OAR­
2002­
0056­
3202)
asked
EPA
to
establish
more
rigorous
national
standards
so
downwind
states
can
meet
Clean
Water
Act
requirements.
One
commenter
(
OAR­
2002­
0056­
3452)
submitted
a
REMAP
assessment
of
mercury
in
sediments
of
selected
lakes
in
New
Hampshire
and
Vermont
which
showed
the
disproportionate
impact
of
airborne
mercury
from
a
power
plant
and
municipal
waste
combustor.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

Several
commenters
(
OAR­
2002­
0056­
1596,
­
2330,
­
2819,
­
2823,
­
2871,
­
2889,
­
3449,
­
3499)
noted
that
in
the
proposal,
EPA
indicated
that
hot
spots
could
be
addressed
through
the
adoption
of
more
stringent
state
or
local
standards.
The
commenters
disagreed
and
cited
their
recent
survey
that
showed
about
half
of
the
state
agencies
have
restrictions
on
their
ability
to
adopt
programs
more
stringent
that
those
of
the
federal
government.
In
addition,
hot
spots
can
be
created
across
state
lines,
so
that
a
downwind
state
is
dependent
on
stricter
controls
that
may
be
installed
by
utilities
in
an
upwind
state.
One
commenter
(
OAR­
2002­
0056­
2819)
added
that
their
state
relies
upon
adoption
of
a
strict
federal
standard
under
section
112
to
establish
state
limits
to
meet
an
annual
cap
and
relying
on
states
to
adopt
meaningful
controls
creates
an
economic
disadvantage
compared
to
lax
states.
One
commenter
(
OAR­
2002­
0056­
3449)
asked
what
these
related
Federal
and
State
programs
are
that
are
supposed
to
address
local
risks?

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:
5­
68
Many
U.
S.
Congressmen
(
OAR­
2002­
0056­
3293)
felt
that
the
rule
could
be
strengthened
by
addressing
hot
spots
now
rather
than
later.
The
commenters
suggested
that
adding
regional
emissions
trading
areas
for
States
with
high
mercury
or
setting
a
level
of
emissions
above
which
no
plant
could
emit
would
help
protect
the
public
health.

Many
state
legislators,
governors,
and
local
officials
called
on
EPA
to
strengthen
the
proposed
standards
as
they
are
not
protective
of
public
health
and
do
not
adequately
address
hot
spots.
The
commenters
pointed
out
that
available
technology
can
achieve
reductions
of
80
or
90
percent.
The
commenters
also
pointed
out
that
the
emission
reductions
fall
well
short
of
the
cuts
that
could
be
achieved
by
2007
under
section
112.
One
Texas
representative
stated
that
no
state
emits
more
mercury
pollution
from
its
power
plants
than
Texas
and
no
state
faces
a
greater
risk
from
cap
and
trade
than
Texas,
which
could
see
no
emission
reduction
at
all.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

One
commenter
(
OAR­
2002­
0056­
3543)
supported
the
cap
and
trade
program
but
pointed
out
that
data
on
hot
spots
appears
scant.
The
commenter
stated
that
while
EPA
states
it
intends
to
collect
data
and
study
the
effectiveness
of
the
rule
in
Phase
I
and
II
in
order
to
make
any
necessary
adjustments,
it
presented
no
clear
strategy
for
collecting
and
analyzing
information,
no
solid
data
on
which
to
formulate
a
baseline
for
this
analysis,
and
no
strategy
for
changing
the
regulatory
approach
if
it
aggravates
hot
spots.

Similarly,
one
commenter
(
OAR­
2002­
0056­
2219)
disagreed
with
EPA's
suggestion
to
evaluate
mercury
hot
spots
formed
as
a
result
of
the
cap
and
trade
program.
As
described
in
the
preamble,
EPA
would
evaluate
whether
emissions
remaining
after
compliance
with
the
cap
and
trade
program
cause
a
health
program.
The
commenter
believed
this
would
be
problematic
because
conducting
an
evaluation
in
2018
after
the
implementation
of
the
program
would
be
too
late;
the
mercury
accumulation
would
have
already
occurred
and
people
would
be
exposed
then
on.
In
addition,
EPA
does
not
have
a
good
"
on
time"
track
record.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

One
commenter
(
OAR­
2002­
0056­
3210)
disputed
EPA's
rationale
that
the
economics
of
a
cap
and
trade
program
would
lead
to
better
control
of
bituminous
coal
sources
since
these
sources
emit
more
oxidized
mercury
and
may
deposit
mercury
locally.
The
commenter
noted
that
5­
69
EPA
believes
reducing
oxidized
mercury
would
reduce
local
hot
spots.
The
commenter
asserted
that
this
rationale
ignores
current
science
on
the
atmospheric
chemistry
of
mercury
and
the
regional
concentration
component
of
the
mercury
deposition
problem.
The
commenter
submitted
that
uncontrolled
sources
of
elemental
mercury
will
continue
to
contribute
to
regional
mercury
deposition,
especially
in
the
summer
during
high
ozone
season.
The
commenter
cited
several
studies
and
reports
indicating
that
areas
with
elevated
ozone
levels
can
expect
increased
mercury
deposition.
The
commenter
concluded
that
mercury
deposition
is
a
year
round
local
hot
spot
issue
and
a
seasonal
widespread
regional
deposition
issue.

Similarly,
one
commenter
(
OAR­
2002­
0056­
3437)
submitted
information
confirming
that
mercury
deposition
of
local
waterbodies
will
continue
as
emissions
actually
increase
under
the
lenient
MACT
limits
or
a
cap
and
trade
approach.
While
the
commenter
was
generally
supportive
of
a
cap
and
trade
approach
,
the
commenter
believed
it
must
be
designed
to
assure
no
hot
spots.
The
commenter
provided
evidence
from
deposition
monitoring
that
showed
a
correspondence
between
mercury
deposition
values
and
mercury
emissions
from
sources
within
a
50
km
radius;
mercury
deposition
rates
were
highest
at
the
monitor
where
nearby
emissions
were
the
highest.
Given
the
concern
about
mercury
deposition
in
the
Great
Lakes
and
the
Grand
Calumet
watershed,
the
current
mercury
load
in
the
region,
and
the
potential
for
hot
spots,
the
commenter
was
very
concerned
about
any
approach
that
would
allow
emissions
to
increase
above
1999
levels.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

5.4.1
Trading
Constraints
to
Address
Hot
Spots
Comment:

Several
commenters
(
OAR­
2002­
0056­
2911,
­
3556)
stated
that
mercury
deposition
is
an
issue
that
is
global
in
scale
and
that
U.
S.
EGUs
represent
about
1
percent
of
the
global
emissions.
The
commenters
stated
that
EPA
acknowledges
that
it
cannot
determine
what
the
contribution
of
EGU
mercury
emissions
is
to
concentrations
in
fish.
The
commenters
further
stated
that
EPA
also
acknowledges
that
it
cannot
determine
how
much
the
concentrations
in
fish
will
decrease,
if
at
all,
once
EGU
mercury
emissions
are
reduced.
The
commenters
noted
that
the
concentration
of
mercury
in
fish
is
the
pathway
of
exposure
to
humans.
The
commenters
also
pointed
out
that
EPRI
has
submitted
detailed
comments
addressing
the
issue
of
mercury
"
hot
spots"
and
the
lack
of
relevance
to
EGU
mercury
emissions.
Consequently,
the
commenters
could
see
no
scientific
justification
to
regional
allocations
and
trading.
In
order
to
have
a
viable
and
robust
trading
program,
the
commenter
3556
believed
it
must
be
national
in
scope.

One
commenter
(
OAR­
2002­
0056­
4139)
stated
that
any
cap
and
trade
program
should
be
contained
to
a
geographic
area.
5­
70
Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

One
commenter
(
OAR­
2002­
0056­
2064)
opposed
trading
under
CAA
section
111
on
a
national
scale.
The
commenter
believes
if
trading
is
allowed
under
section
111,
it
should
be
limited
to
a
regional
or
contiguous
basis
because
of
interstate
deposition
problems
with
mercury.
Similarly,
one
commenter
(
OAR­
2002­
0056­
3437)
suggested
that
EPA
should
consider
if
geographic
or
other
constraints
on
trading
are
needed
to
prevent
hot
spots.
The
commenter
recommended
establishing
reduction
targests
to
assure
that
all
plants
reduce
emissions
to
some
degree.
The
commenter
submitted
a
cap
and
trade
program
must
contain
a
backstop
to
ensure
that
no
individual
plant
could
emit
more
mercury
than
in
1999.
The
commenter
believed
the
rule
also
must
assure
that
states
retain
the
ability
to
address
local
hot
spots.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

Several
commenters
(
OAR­
2002­
0056­
3437,
­
3443)
responded
to
EPA's
request
for
comments
on
whether
it
would
be
appropriate
to
adjust
the
geographic
scope
of
the
trading
program
by
introducing
trading
ratios
to
address
regional
differences.
(
See
Fed.
Reg.
4651,
4701.)
One
commenter
(
OAR­
2002­
0056­
3437)
understood
that
geographical
constraints
would
be
one
possible
approach
to
prevent
hot
spots.
But
the
commenter
believed
this
approach
could
add
much
complexity
to
the
trading
program
and
might
not
provide
the
desired
result.
The
commenter
stated
a
preferable
approach
would
be
a
stringent
limit
to
allocate
allowances
and
the
flexibility
to
impose
more
stringent
local
requirements.
The
commenter
cautioned
that
EPA
should
be
very
clear
about
trading
ratios
so
that
industry
will
have
clear
direction
to
plan
for
compliance
and
states
will
be
aware
of
any
responsibilities
that
will
be
imposed
on
them.

One
commenter
(
OAR­
2002­
0056­
3443)
did
not
support
such
adjustments
to
the
geographic
scope
because
they
would
hamper
the
effectiveness
of
the
trading
program
by
interfering
with
the
market.
More
importantly,
the
commenter
saw
no
need
for
such
adjustments
because
EPA's
analysis
in
the
preamble
leads
to
the
conclusion
that
"
hot
spots"
would
not
be
a
problem
under
a
cap
and
trade
program.
(
See
69
Fed.
Reg.
4,651,
4,702­
03.)

The
commenter
presumed
that
the
main
reason
for
making
such
geographic
adjustments
would
be
to
address
the
potential
for
localized
impacts.
In
regard
to
the
issue
of
localized
impacts,
the
commenter
has
been
monitoring
mercury
in
sediments
and
fish
in
the
reservoirs
on
the
Tennessee
River
and
its
tributaries
for
over
30
years.
The
commenter
stated
that
these
studies
5­
71
show
that
mercury
levels
in
the
sediment
for
both
mainstream
and
tributary
reservoirs
in
the
entire
Tennessee
Valley
region
have
declined
substantially
since
1973.
Likewise,
the
commenter
stated
that
although
mercury
levels
in
fish
tissue
in
the
reservoirs
along
the
Tennessee
River
have
varied,
these
levels
indicate
a
constant
or
declining
trend
despite
an
increase
in
coal­
fired
generation
on
the
commenter's
system
during
this
period.
(
The
commenter
attached
a
letter
dated
November
19,
2003,
from
the
commenter
to
EPA
on
Mercury
in
Sediment
and
Fish
in
the
TVA
Reservoirs.)
The
commenter
submitted
that
although
the
study
identified
areas
with
elevated
mercury,
none
of
these
elevated
levels
were
attributable
to
emissions
from
the
commenter's
coal­
fired
units.
Rather,
the
elevated
levels
were
the
result
of
industrial
activity,
such
as
waste
water
discharges
form
the
chlor­
alkoli
industry.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

One
commenter
(
OAR­
2002­
0056­
2247)
stated
that
while
they
viewed
a
cap
and
trade
program
as
the
preferred
policy
approach,
the
cap
must
be
lower
and
the
trading
properly
constrained.
The
commenter
suggested
an
additional
control
option.
To
insure
reductions
from
western
coal
users
and
to
prevent
drift
of
emissions
from
eastern
to
western
states,
the
commenter
submitted
that
EPA
should
combine
a
lower
cap
with
some
form
of
a
zonal
trading
plan
that
would
achieve
reductions
in
both
the
eastern
and
western
areas
of
the
U.
S.

The
commenter
claimed
that
up
to
90
percent
of
the
mercury
entering
their
waters
comes
from
atmospheric
sources
outside
the
state.
Their
TMDL
studies
showed
that
a
reduction
in
the
range
of
50
percent
in
atmospheric
deposition
would
be
needed
to
meet
their
projected
water
quality
standard.
EPA's
deposition
modeling
predicted
only
a
5
percent
reduction
in
certain
areas
of
the
state.
The
commenter
believed
the
proposed
cap
of
15
tons
is
so
loose
that
utility
boilers
in
the
commenter's
state
and
those
to
the
sourth
and
west
would
do
little
to
control
mercury
emissions.
The
IPM
modeling
showed
that
utility
boilers
in
the
commenter's
state
and
similar
boilers
west
of
the
Mississippi
burning
Powder
River
Basis
or
lignite
coal
would
reduce
emissions
by
only
35
percent
as
a
co­
benefit
of
controlling
SO
2
and
NO
x.
These
states,
including
utilities
in
the
commenter's
state,
are
predicted
to
purchase
credits
from
eastern
utilities
rather
than
control
releases.
Even
the
5
percent
reduction
EPA
predicted
for
the
commenter's
state
may
not
occur
because
modeling
did
not
account
for
banking
or
the
cost­
based
safety
valve.
The
commenter
believed
the
15
ton
final
cap
would
not
address
the
commenter's
problem
 
it
seemed
to
shift
the
cost
of
SO
2
and
NO
x
controls
at
eastern
boilers
to
western
states
burning
PRB
coal.
Their
analysis
showed
that
tighter
MACT
standards
or
a
lower
cap
are
justified.

The
commenter
submitted
that
the
drawback
of
a
cap
and
trade
program
is
that
it
reduces
mercury
where
it
is
most
cost
effective,
but
does
not
address
specific
geographic
needs.
The
commenter
needs
reductions
from
coal­
fired
plants
to
the
south
and
west
of
the
state.
The
commenter
suggested
trading
zones
with
separate
mercury
caps
and
limiting
trading
between
the
5­
72
zones.
The
commenter
believed
this
would
avoid
relying
on
bituminous
coal­
fired
boilers
for
nearly
all
the
reductions.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

One
commenter
(
OAR­
2002­
0056­
2860)
recommended
a
maximum
allowable
emission
rate
to
address
hot
spots.
The
commenter
asserted
that
EPA
should
provide
options
and
support
for
identifying
and
mitigating
potential
hot
spots.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

One
commenter
(
OAR­
2002­
0056­
1825)
objected
to
a
provision
in
the
cap
and
trade
program
that
would
allow
utilities
in
a
State
to
avoid
any
additional
mercury
reduction
even
if
studies
confirm
that
hot
spots
are
the
result
of
emissions
from
local
utilities.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

One
commenter
(
OAR­
2002­
0056­
3448)
stated
that
delaying
70
percent
of
the
emission
reduction
until
about
2030
in
the
proposed
CAA
section
111
rule
would
perpetuate
local
and
regional
hot
spots
for
25
years
and
forever
for
the
many
areas
affected
by
plants
that
will
not
install
controls
at
all
under
a
cap
and
trade
system.
The
commenter
believed
proposals
to
adjust
trading
to
attempt
to
address
hot
spots
are
likely
to
fail
based
on
perceptions
they
would
complicate
and
reduce
the
efficiency
of
a
cap
and
trade
program.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:
5­
73
One
commenter
(
OAR­
2002­
0056­
4139)
stated
that
budgets
need
to
be
lowered
to
protect
certain
areas.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

One
commenter
(
OAR­
2002­
0056­
2173)
stated
that
given
the
serious
concern
about
hot
spots,
if
EPA
adopts
a
cap
and
trade
approach,
it
must
take
all
appropriate
actions
to
ensure
they
do
not
result.
The
commenter
recommended
the
following
actions:
(
1)
require
excess
"
offsets"
(
the
offset
ratio
should
be
adjusted
based
on
the
ability
of
mercury
reductions
at
one
source
to
reduce
deposition
in
the
area
of
the
other
source
to
ensure
that
any
reductions
at
units
generating
credits
would
have
an
equivalent
environmental
effect
in
the
area
of
the
unit
purchasing
the
unit);
(
2)
limit
trades
to
a
regional
or
basin­
wide
area;
(
3)
limit
amount
of
credits
that
can
be
purchased
to
meet
limits;
and
(
4)
create
a
natural
resources
damage
fund
to
compensate
tribes,
states,
and
other
resource
trustees
for
damage
caused
by
hot
spots
by
assessing
a
surcharge
on
credits
that
are
traded.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

Several
commenters
(
OAR­
2002­
0056­
1671,
­
2108)
stated
that
if
EPA
retains
the
cap­
and­
trade
program,
credits
should
be
available
only
to
plants
that
demonstrate
through
modeling
that
deposition
is
not
occurring
in
local
watersheds
or
land
(
i.
e.,
hot
spots).

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

One
commenter
(
OAR­
2002­
0056­
2160)
suggested
that
maximum
emission
limits
should
be
established
for
individual
plants
to
avoid
hot
spots.
The
commenter
noted
that
capping
maximum
emissions
from
a
given
plant
has
ample
precedent
in
existing
SO
2
and
NO
x
rules.

Response:
5­
74
EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2835,
­
2878)
addressed
the
evaluation
of
control
requirements
after
implementation
of
the
cap­
and­
trade
program.
One
commenter
(
OAR­
2002­
0056­
2835)
agreed
with
the
EPA
proposal
to
evaluate
after
the
implementation
of
the
control
requirements
in
2010
and
2018
whether
the
mercury
cap
adequately
protects
public
health
and,
if
necessary,
take
further
regulatory
actions
to
address
any
health
risks
not
fully
addressed
by
the
cap­
and­
trade
regulatory
program.

The
second
commenter
(
OAR­
2002­
0056­
2878)
cited
several
scientific
and
policy
concerns
including
lack
of
safeguards
to
protect
the
public
health
and
secure
additional
needed
reductions,
toxicity
of
mercury
and
tendency
to
bioaccumulate
in
the
food
chain,
potential
for
hot
spots,
and
environmental
justice.
The
commenter
asserted
that
EPA's
response
to
these
concerns
(
reevaluate
effects
of
cap
and
trade
on
local
hot
spots
after
implementation
in
2018)
would
leave
communities
at
risk
for
another
14
years
or
longer.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

Comment:

If
EPA
pursues
regulation
under
CAA
section
111,
one
commenter
(
OAR­
2002­
0056­
2430)
recommended
that
it
include
some
type
of
risk
and
environmental
health
assessment
including
an
evaluation
of
the
effects
of
mercury
deposition.
The
commenter
noted
that
residual
risk
requirements
under
CAA
section
112
address
risk
to
public
health
and
the
environment,
while
CAA
section
111
does
not.
The
commenter
asserts
that
the
disassociation
of
CAA
regulations
from
public
health
and
the
environment
is
unacceptable
public
policy
and
sets
a
bad
precedent.

Response:

EPA
has
addressed
the
hot
spots
issue
in
the
revision
Federal
Register
notice
and
in
the
Effectiveness
TSD.

5.5
APPLICABILITY
5.5.1
Affected
Units
Comment:
5­
75
One
commenter
(
OAR­
2002­
0056­
2862)
stated
the
program
threshold
should
be
based
on
size
of
unit
(
m
25
MW).
The
commenter
noted
the
current
program
threshold
is
consistent
with
the
m
25
MW
level
set
for
EPA's
Acid
Rain
program.
The
commenter
believes
this
is
an
appropriate
threshold.
Including
units
based
a
size
definition
creates
a
fair
and
consistent
regulatory
program.

One
commenter
(
OAR­
2002­
0056­
2721)
supported
the
proposed
minimum
level
of
generation
of
a
fossil
fuel
fired
combustion
unit
that
serves
a
generator
of
25
MW
that
produces
electricity
for
sale
would
be
affected
by
the
proposed
mercury
regulations.

A
second
commenter
(
OAR­
2002­
0056­
2913)
stated
the
proposed
CAA
section
111
cap­
and­
trade
provisions
of
the
proposal
expand
upon
the
CAA
section
112
definition
of
electric
utility
steam
generating
unit
by
including
combustion
units
less
than
25
MW
if
they
serve
a
generator
greater
than
25
MW.
The
commenter
stated
that
CAA
section
112
defines
an
electric
utility
steam
generating
unit
as
a
25
MW
combustion
units,
but
the
proposed
CAA
section
111
cap­
and­
trade
rule
presumably
would
apply
to
combustion
units,
regardless
of
size,
serving
25
MW
generators
(
see
60.4104
(
a)).
It
appeared
to
the
commenter
as
though
the
Agency
is
attempting
to
expand
the
number
of
electric
utility
units
to
which
this
rule
would
apply
beyond
that
authorized
by
statute.
Furthermore,
the
potential
exists
for
some
electric
utility
units
to
be
regulated
by
two
different
and
conflicting
regulations
(
i.
e.
the
industrial/
commercial/
institutional
boilers
and
process
heater
MACT
standards
which
are
nearing
final
promulgation
and
these
electric
utility
steam
generating
unit
MACT
standards).
The
commenter
believed
this
is
contrary
to
both
statutory
intent
and
expressed
EPA
policy.
The
commenter
did
not
believe
that
this
is
the
Agency's
intent
and
this
"
inconsistency"
between
CAA
section
112
definition
and
CAA
section
111
applicability
is
merely
an
oversight
on
EPA's
part.

The
commenter
recommended
that,
if
the
Agency
ultimately
decides
that
the
best
way
to
adopt
a
cap­
and­
trade
rule
is
under
CAA
section
111,
then
this
situation
can
be
rectified
in
one
of
two
ways:
1)
Rewrite
40
CFR
60.4104(
a)
as
applying
to
"
Any
fossil
fuel
fired
combustion
unit
of
more
than
25
megawatts
that
serves
a
generator
that
produces
electricity
for
sale.";
or
2)
state,
in
the
applicability
section,
that
any
unit
covered
in
40
CFR
Part
63,
Subpart
DDDDD
(
i.
e.
the
industrial/
commercial/
institutional
boilers
and
process
heater
MACT
standards),
is
not
covered
under
this
subpart.

Response:

For
purposes
of
model
trading
rule,
an
affected
unit
is
defined
as
a
coal­
fire
boiler
or
IGCC
that
serves
a
generator
with
nameplate
capacity
of
more
than
25
MWe
producing
electricity
for
sale
(
see
regulatory
text
of
final
rule,
§
60.4104,
for
full
definition).
The
definition
also
provides
an
exception
for
cogeneration
units
serving
at
any
time
a
generator
with
nameplate
capacity
of
more
than
25
MWe
and
supplying
in
any
calendar
year
more
than
one­
third
of
the
unit's
potential
electric
output
capacity
or
219,000
MWh,
whichever
is
greater,
to
any
utility
power
distribution
system
for
sale
(
see
regulatory
text
of
final
rule,
§
60.4104,
for
full
definition).
5­
76
As
discussed
in
the
final
rule
preamble
(
section
IV.
D.
3),
the
approach
of
using
a
25
MWe
cut­
off
is
consistent
with
existing
SO
2
and
NO
x
cap­
and­
trade
programs
like
the
NO
x
SIP
call
and
the
Acid
Rain
Program
and
the
final
Clean
Air
Interstate
Rule.
In
addition,
the
Agency's
historical
interpretation
of
the
subpart
Da
definition
has
been
that
a
boiler
meeting
the
capacity
definition
(
i.
e.,
greater
than
250
million
Btu/
hr)
but
connected
to
an
electrical
generator
with
a
generation
capacity
of
25
MWe
or
less
would
still
be
classified
as
an
"
electric
utility
steam
generating
unit"
under
subpart
Da.
EPA
acknowledges
that
there
are
differences
in
definitions
between
the
NSPS
program
and
the
Acid
Rain
and
other
trading
programs
(
e.
g.,
CAIR)
that
result
from
the
underlying
statutory
mandates.
From
implementation
standpoint,
EPA
maintains
that
is
important
for
the
applicability
definition
under
the
Hg
modeling
trading
rule
to
be
consistent
with
other
cap­
and­
trade
rules,
especially
the
recently
finalized
CAIR.

Comment:

One
commenter
(
OAR­
2002­
0056­
2066)
stated
that
combined
heat
and
power
(
CHP)
units
currently
represent
only
about
3
percent
of
the
electric
generating
capacity
covered
by
Agency's
proposal.
According
to
the
commenter,
CHP
units
are
generally
twice
as
efficient
when
compared
to
their
utility
counterparts,
and
about
2/
3
of
all
CHP
units
burn
natural
gas
and
have
extremely
low
NO
x
emission
rates.
The
commenter
stated
that
while
individual
CHP
emission
rates
will
vary,
the
average
gas­
fired
CHP
emission
rates
are
only
15­
25
percent
of
that
emitted
by
a
typical
utility.
The
commenter
added
that
even
CHP
units
using
coal
or
oil
as
a
fuel
source
are
still
much
more
efficient
than
a
utility
using
the
same
fuels.
The
commenter
further
stated
that
CHP
units
are
usually
only
a
small
part
of
a
much
larger
industrial
facility
or
complex.
The
commenter
asserted
that
including
these
units
into
this
rulemaking
would
layer
another
set
of
regulations
on
the
entire
facility,
thus
further
complicating
on­
going
compliance
efforts.
For
these
reasons,
the
commenter
believed
that
CHP
units
should
be
exempted
from
inclusion
in
this
rulemaking.
According
to
the
commenter,
inclusion
of
traditional
CHP
facilities
would
provide
negligible
environment
benefit
while
discouraging
application
of
these
ultra­
efficient
power
and
steam
generators
both
now
and
in
the
future.

The
commenter
(
OAR­
2002­
0056­
2206)
noted
that
EPA
is
proposing
to
establish
a
cap
and
trade
program
for
regulated
utility
units
that
is
similar
to
the
current
cap
and
trade
for
this
sector
under
the
Title
IV
program
and
the
Agency's
proposed
rule
relating
to
interstate
air
quality
(
69
FR
4652).
The
commenter
further
noted
that
as
part
of
EPA's
proposal,
EPA
would
include
some
cogeneration
units
as
electric
utility
units
and
make
them
subject
to
the
rule.
The
commenter
did
not
support
this
approach
toward
cogeneration
units.
Instead,
the
commenter
suggested
that
EPA
should
exclude
all
cogeneration
units.
The
commenter
offered
that
EPA
could
include
them
in
its
planned
study
to
see
if
unregulated
units
are
causing
adverse
health
effects.

Response:

As
discussed
in
the
final
rule
preamble
(
section
IV.
D.
3),
EPA
believes
it
is
important
to
include
in
the
CAMR
program
all
units,
including
congeration
units,
that
are
substantially
in
the
business
of
selling
electricity.
As
discussed
above,
the
applicability
definition
under
the
Hg
5­
77
modeling
trading
rule
is
consistent
with
other
cap­
and­
trade
rules,
especially
the
recently
finalized
CAIR.

Comment:

For
CHP
units,
the
commenter
(
OAR­
2002­
0056­
3525)
believed
that
EPA
should
define
a
"
utility
unit"
as
only
those
units
that
meet
the
definition
on
a
net
annual
basis.
The
commenter
pointed
out
that
in
the
preamble,
EPA,
absent
rationale,
states
that
any
CHP
unit
that
meets
the
definition
of
a
utility
unit
during
any
portion
of
the
year
would
become
subject
to
the
rule.
The
commenter
stated
that
requiring
a
CHP
unit
to
stay
below
the
utility
unit
definition
on
an
instantaneous
basis
provides
a
disincentive
for
facilities
to
invest
in
new
CHP
capacity
or
to
maximize
the
output
and
efficiency
of
their
current
CHP
and
energy­
producing
network
of
units.

The
commenter
encouraged
EPA
to
confirm
that
for
purposes
of
its
proposed
definitions
of
"
EGU"
and
"
cogeneration
unit,"
all
sales
of
electricity
will
be
measured
on
a
"
net"
basis,
as
is
done
in
the
acid
rain
program.
The
commenter
stated
that
in
determining
that
"
net"
basis,
EPA's
accounting
should
take
account
of
the
specific
situation
of
major
facilities
with
a
number
of
cogeneration
units.
The
commenter
stated
that
at
such
plants,
some
units
may
be
over
the
size
threshold,
while
others
may
be
below
it.
Yet,
according
to
the
commenter,
the
electricity
from
all
those
units
will
be
pooled
before
it
is
either
used
in
the
plant
or
sold
to
the
grid.
In
that
case,
the
commenter
believed
EPA's
accounting
rules
should
provide
for
determining
when
the
threshold
conditions
have
been
met
by
looking
at
all
the
electricity
generated
by
all
the
cogeneration
units,
whether
they
were
subject
to
the
SIP
call
or
not.
The
commenter
asserted
that
no
other
approach
would
be
administratively
feasible.

The
commenter
stated
an
annual
average
should
be
used
to
determine
whether
cogeneration
units
sold
more
than
one
third
of
their
potential
electric
output
to
the
grid
and
more
than
25
MW
on
a
net
annual
average
basis
and
thus
were
defined
as
EGUs.
According
to
the
commenter,
a
shorter
averaging
time
could
often
result
in
classifying
units
as
EGUs
based
on
a
short
and
unrepresentative
operating
history­
for
example,
if
power
was
generally
used
exclusively
at
the
plant
at
which
it
was
generated,
but
was
sold
to
the
grid
when
the
production
facility
was
down
for
maintenance.

The
commenter
pointed
out
in
addition,
in
some
cases,
contractual
arrangements
may
exist
between
the
cogeneration
facility
and
the
local
electric
utility
wherein
all
generated
power
is
considered
sold
to
the
utility
and
all
electricity
used
on
the
site
is
purchased
from
the
utility.
According
to
the
commenter,
in
reality,
only
a
small
portion
of
the
generated
power
really
enters
the
grid
from
the
cogeneration
facility,
and
only
that
"
net"
sales
of
power
should
be
considered
when
determining
applicability
with
the
EGU
definition.

Subject
to
these
qualifications,
the
commenter
supported
the
cogeneration
unit
threshold
being
used
for
consideration
as
an
EGU,
specifically,
a
unit
serving
a
generator
with
a
nameplate
capacity
of
>
25
MW
and
supplying
more
than
1/
3
of
its
potential
electric
output
capacity
and
more
than
25
MW
to
any
utility
power
distribution
system
for
sale.
The
commenter
stated
however,
it
would
provide
additional
clarity
and
prevent
confusion
if
it
was
specifically
stated
that
5­
78
units
associated
with
generators
of
25
MWe
capacity
or
less
were
not
affected
sources
under
this
subpart;
and
any
cogeneration
units
not
supplying
both
more
than
one­
third
of
their
potential
electric
output
capacity
and
more
than
25
MWe
to
any
utility
power
distribution
system
for
sale
were
not
affected
sources
under
this
subpart.
The
commenter
recommended
that
EPA
include
this
additional
clarifying
language
in
the
final
rule.

Another
commenter
(
OAR­
2002­
0056­
2906)
stated
that
for
cogeneration
units,
EPA
should
define
as
an
electric
utility
steam
generating
unit
(
utility
unit)
only
those
units
that
meet
the
definition
of
a
utility
unit
on
a
net
annualized
basis.
The
commenter
noted
that
in
the
preamble,
EPA
states
that
any
cogeneration
unit
that
meets
the
definition
of
a
Utility
Unit
during
any
portion
of
the
year
would
become
subject
to
the
rule
(
69
FR
4657).
The
commenter
stated
that
EPA
provides
no
rationale
for
this
requirement.
The
commenter
further
stated
that
this
requirement
stands
in
contrast
to
EPA's
proposed
CAIR,
where
the
definition
for
a
Utility
Unit
is
based
on
a
historical
annual
average
(
69
FR
4610).

The
commenter
stated
that
requiring
a
cogeneration
unit
to
stay
below
the
Utility
Unit
definition
on
an
instantaneous
basis
would
create
a
large
disincentive
for
facilities
to
invest
in
new
CHP
capacity,
or
to
maximize
the
output
and
efficiency
of
their
current
cogeneration
and
energy­
producing
network
of
units.
According
to
the
commenter,
cogeneration
units
are
inherently
more
efficient
than
traditional
Utility
Units
(
in
many
cases
twice
as
efficient),
and
often
provide
distributed
key
power
to
the
grid
during
transient
or
short­
term
periods
of
peak
power
demand.
The
commenter
stated
that
in
order
to
prevent
being
included
within
the
Utility
Unit
definition,
many
cogeneration
units
will
likely
establish
tight
restrictions
on
exporting
excess
power
to
the
grid,
or
eliminate
export
all
together.
According
to
the
commenter,
this
would
have
the
perverse
effect
of
reduced
cogeneration
unit
power
output,
reduced
overall
grid
efficiency
and
reduced
industrial
steam
and
electricity
generation
efficiency.

The
commenter
stated
that
to
prevent
these
undesirable
consequences,
and
to
prevent
conflicts
and
confusion
with
the
definition
of
a
Utility
Unit
in
the
CAIR
under
which
some
of
these
units
may
choose
to
opt
into
the
CAIR
regulation,
EPA
should
base
the
Utility
Unit
definition
on
a
net
annualized
average
and
not
"
during
any
portion
of
the
year."

Response:

As
discussed
in
the
final
rule
preamble
(
section
IV.
D.
3),
EPA
confirms
that,
for
purposes
of
applying
the
one­
third
potential
electric
output
criteria
in
the
CAMR
program
and
the
model
cap­
and­
trade
rules,
the
only
electricity
that
counts
as
a
sale
is
electricity
produced
by
a
unit
that
actually
flows
to
a
utility
power
distribution
system
from
the
unit.
Electricity
that
is
produced
by
the
unit
and
used
on­
site
by
the
electricity­
consuming
component
of
the
facility
will
not
count,
including
cogenerated
electricity
that
is
simultaneously
purchased
by
the
utility
and
sold
back
to
such
facility
under
purchase
and
sale
agreements
under
the
Public
Utilities
Regulatory
Policy
Act
of
1978
(
PURPA).
However,
electric
purchases
and
sales
that
are
not
simultaneous
will
not
be
netted;
the
one­
third
potential
electric
output
criteria
will
be
applied
on
a
gross
basis,
except
for
simultaneous
purchase
and
sales.
This
is
consistent
with
the
approach
taken
in
the
Acid
Rain
Program.
5­
79
Comment:

One
commenter
(
OAR­
2002­
0056­
2906)
requested
that
EPA
confirm
that,
for
purposes
of
its
proposed
definitions
of
"
Utility
Unit"
and
"
cogeneration
unit,"
all
sales
of
electricity
will
be
measured
on
a
"
net"
basis,
as
is
done
in
the
acid
rain
program.
According
to
the
commenter,
in
determining
that
"
net"
basis,
EPA's
accounting
rules
should
take
into
account
the
specific
situation
of
major
facilities
with
a
number
of
cogeneration
units.
The
commenter
pointed
out
that
at
such
plants,
some
units
may
be
over
the
size
threshold
for
inclusion
in
the
rule,
while
others
may
be
below
it.
The
commenter
added
that,
yet,
the
electricity
from
all
those
units
will
be
pooled
together
before
it
is
either
used
in
the
plant,
or
sold
to
the
grid.
The
commenter
stated
that,
in
other
words,
there
will
be
no
way
to
determine
the
particular
use
of
the
electricity
generated
by
the
large
units
subject
to
the
rule.
The
commenter
believed
that
in
that
case,
EPA's
accounting
rules
should
provide
for
determining
when
the
threshold
conditions
have
been
met
by
looking
at
all
the
electricity
generated
by
all
the
cogeneration
units.
According
to
the
commenter,
no
other
approach
would
be
administratively
feasible.

The
commenter
pointed
out
that
in
many
cases
contractual
arrangements
may
exist
between
the
cogeneration
facility
and
the
local
electric
utility
wherein
all
generated
power
is
considered
sold
to
the
utility
and
all
electricity
used
on
the
site
is
purchased
from
the
utility.
According
to
the
commenter,
in
reality,
only
a
small
portion
of
generated
power
really
enters
the
grid
from
the
cogeneration
facility,
and
only
that
"
net"
sales
of
power
should
be
considered
when
determining
applicability
with
the
Utility
Unit
definition.

The
commenter
stated
that
an
annual
average
should
be
used
to
determine
whether
cogeneration
units
sold
more
than
one
third
of
their
potential
electric
output
to
the
grid
and
more
than
25
MWe
on
a
net
annual
average
basis
and
thus
were
defined
as
Utility
Units.
According
to
the
commenter,
a
shorter
averaging
time
could
often
result
in
classifying
units
as
Utility
Units
based
on
a
short
and
unrepresentative
operating
history
 
for
example,
if
power
was
generally
used
exclusively
at
the
plant
at
which
it
was
generated,
but
was
sold
to
the
grid
when
the
production
facility
was
down
for
maintenance.

Subject
to
these
qualifications,
the
commenter
supported
the
cogeneration
unit
threshold
being
used
for
consideration
as
an
Utility
Unit,
specifically,
a
unit
serving
a
generator
with
a
nameplate
capacity
of
greater
than
25
MWe
and
supplying
more
than
one­
third
of
its
potential
electric
output
capacity
and
more
than
25
MWe
to
any
utility
power
distribution
system
for
sale.
The
commenter
stated
that,
however,
it
would
provide
additional
clarity
and
prevent
confusion
if
it
was
specifically
stated
that
units
associated
with
generators
of
25
MWe
capacity
or
less
were
not
affected
sources
under
this
subpart;
and
any
cogeneration
units
not
supplying
both
more
than
one­
third
of
their
potential
electric
output
capacity
and
more
than
25
MWe
to
any
utility
power
distribution
system
for
sale
were
not
affected
sources
under
this
subpart.
The
commenter
recommended
that
EPA
include
this
additional
clarifying
language
in
the
final
rule.

Response:
5­
80
As
discussed
in
the
final
rule
preamble
(
section
IV.
D.
3),
EPA
is
finalizing
to
determine
whether
a
unit
is
affected
by
the
CAMR
on
an
individual­
unit
basis.
This
unit­
based
approach
is
consistent
with
both
the
Acid
Rain
Program
and
the
NOx
SIP
Call.
EPA
considers
this
approach
to
be
feasible
based
on
experience
from
these
existing
programs,
including
for
sources
with
multiple
cogeneration
units.
EPA
is
unaware
of
any
instances
of
cogeneration
unit
owners
being
unable
to
determine
how
to
apply
the
one­
third
potential
electric
output
capacity
criteria
where
there
are
multiple
cogeneration
units
at
a
source.

In
a
case
where
there
are
multiple
cogeneration
units
with
only
one
connection
to
a
utility
power
distribution
system,
the
electricity
supplied
to
the
utility
distribution
system
can
be
apportioned
among
the
units
in
order
to
apply
the
one­
third
potential
electric
output
capacity
criteria.
A
reasonable
basis
for
such
apportionment
must
be
developed
based
on
the
particular
circumstances.
The
most
accurate
way
of
apportioning
the
electricity
supplied
to
the
utility
power
distribution
system
seems
to
be
apportionment
based
on
the
amount
of
electricity
produced
by
each
unit
during
the
relevant
period
of
time.

The
commenters
concerns
about
"
net
sales"
are
addressed
in
the
previous
response.

Comment:

One
commenter
(
OAR­
2002­
0056­
3469)
stated
that
the
tribes
support
the
EPA
in
their
efforts
to
improve
air
quality.
However,
tribes
needed
protections
to
ensure
their
future
energy
projects
and
the
economic
benefits
derived
from
current
mining
operations
are
not
jeopardized.
The
tribes
supported
the
exemption
of
all
new
power
plants
developed
by
the
tribes
or
developed
on
tribal
land
from
being
required
to
hold
allowances
for
SO
2,
NO
x
or
mercury
emissions,
as
long
as
these
new
power
plants
meet
New
Source
Performance
Standards
(
NSPS)
and
all
other
relevant
permitting
requirements
at
the
date
of
initial
operation.
These
power
plants
would
adhere
to
the
monitoring
requirements
specified
in
the
rules
ensuring
that
these
NSPS
requirements
are
met
over
time.

Comment:
One
commenter
(
OAR­
2002­
0056­
2850)
supported
exemption
of
new
units
from
the
Hg
program
that
are
constructed
with
Best
Available
Control
Technology
for
Hg.
The
commenter
stated
that
if
a
new
unit
exemption
is
not
implemented,
credits
should
be
purchased
from
the
new
Hg
allowance
market
or
buyout
mechanism.

Response:

In
the
final
CAMR,
new
sources
will
be
covered
under
the
Hg
cap
of
the
trading
program,
and
will
be
required
to
hold
allowances
equal
to
their
emissions.
EPA
maintains
that
is
essential
to
include
new
sources
under
the
cap
to
ensure
that
environmental
goal
of
reducing
mercury
emission
is
achieved.
With
new
sources
under
the
cap,
the
environmental
goal
continues
to
be
achieved
despite
future
growth
in
the
electric
power
sector,
as
older
coal­
fired
generation
is
retired
and
replaced
new
coal­
fired
generation.

Comment:
5­
81
One
commenter
(
OAR­
2002­
0056­
2162)
stated
that
waste
coal­
fired
plants
should
not
be
subject
to
the
proposed
mercury
rules.

Response:

As
discussed
in
the
final
rule
preamble
(
section
IV.
D.
3),
EPA
points
out
that
coal
refuse
is
already
subject
to
other
Utility
Unit
programs,
such
as
the
Acid
Rain
program,
the
NSPS
program
(
40
CFR
part
60,
subpart
Da),
and
the
CAIR
program.
Consequently,
EPA
rejects
the
commenter's
request
to
not
be
included
in
the
CAMR
program.

5.5.2
25
lb
Exclusion
Comment:

Several
commenters
(
OAR­
2002­
0056­
2161,
­
2267,
­
2375,
­
2634,
­
2830,
­
2913,
­
2922,
­
2948)
supported
the
provision
excluding
units
that
emit
less
than
25
pounds
of
mercury
per
year
from
the
cap­
and­
trade
program.

One
commenter
(
OAR­
2002­
0056­
2161)
suggested
that
EPA
require
these
emitters
to
conduct
compliance
testing
annually
to
verify
the
level
of
their
emissions
and
report
the
results
to
EPA.
As
a
result
EPA
would
be
able
to
monitor
the
national
emissions
profile
of
this
group
of
sources
and
change
the
way
they
participate
in
the
mercury
cap
and
trade
program
if
their
emissions
profile
changes
significantly.

One
commenter
(
OAR­
2002­
0056­
2267)
requested
that
EPA
consider
extending
the
exemption
to
the
Phase
I
cap
as
well.
The
commenter
stated
that
controls
on
low
emitting
units
are
not
highly
cost­
effective.
EPA
has
acknowledged
that
expected
new
mercury­
specific
control
technologies
may
not
practically
apply
to
these
units.
Moreover,
emissions
from
such
units
do
not
contribute
significantly
to
over­
all
mercury
emissions.
The
commenter
noted
that
EPA's
data
indicates
that
these
units
(
numbered
at
396)
currently
account
for
less
than
5
percent
of
total
mercury
emissions.
The
commenter
believed
EPA
should
exclude
these
units
because
the
cost­
savings
would
be
substantial
for
such
units
without
affecting
the
ability
to
achieve
the
proposed
caps.
In
the
event
low
emitting
units
are
excluded
from
the
Phase
I
and/
or
II
cap,
the
commenter
would
support
provisions
that
would
allow
such
units
(
as
well
as
non­
affected
units)
to
opt­
in
to
the
cap­
and­
trade
program
at
their
discretion
as
in
the
NO
x
Budget
Trading
Program.

One
commenter
(
OAR­
2002­
0056­
2375)
stated
that
EPA
has
authority
to
promulgate
such
an
exemption
based
on
its
inherent
de
minimis
authority.
The
commenter
noted
sources
of
emissions
below
this
level
comprise
less
than
4
percent
of
current
U.
S.
power
plant
emissions.
The
commenter
believed
exempting
them
from
the
rule
would
not
jeopardize
the
caps.
The
commenter
stated
that
moreover,
the
exemption
is
warranted
because
pollution
controls
required
for
Phase
II
may
not
be
feasible
for
sources
with
low
emissions.

Several
commenters
(
OAR­
2002­
0056­
2634,
­
2922,
­
2948)
added
that
since
these
units
do
not
significantly
contribute
to
total
domestic
emissions,
the
2010
and
2018
caps
should
remain
5­
82
unchanged
and
be
applicable
to
the
units
remaining
in
the
program,
even
if
these
sources
are
excluded
from
the
program.

One
commenter
(
OAR­
2002­
0056­
2914)
stated
that
requiring
low
emitting
units
to
participate
in
the
proposed
cap­
and­
trade
program
would
provide
very
little
benefit
in
comparison
to
the
costs
needed
to
become
effective
trading
partners.
The
commenter
also
stated
that
low
emitting
units,
especially
those
already
equipped
with
MACT
standard
setting
technology
should
only
be
required
to
demonstrate
that
the
installed
pollution
controls
are
operating
properly,
monitor
operating
parameters
and
emissions,
keep
records
of
their
operating
parameters
and
emissions,
report
their
emissions,
and
nothing
more.
The
commenter
submitted
suggested
regulatory
language
to
implement
and
exemption
for
low
emitting
units.

One
commenter
(
OAR­
2002­
0056­
2560)
supported
the
exclusion
of
coal­
fired
electric
generating
units
(
EGUs)
that
emit
less
than
25
pounds
of
mercury
per
year.
According
to
the
commenter,
these
units
account
for
a
very
small
proportion
of
mercury
emissions.

One
commenter
(
OAR­
2002­
0056­
2883)
urged
the
EPA
to
consider
the
implications
of
both
proposed
rules
on
smaller
emitters
and
urges
the
EPA
to
provide
a
de
minimus
exemption
from
the
rule
for
de
minimus
emitters.

One
commenter
(
OAR­
2002­
0056­
3445)
noted
that
EPA
has
expressed
concern
about
units
with
low
mercury
emissions
rates
(
e.
g.,
less
than
25
pounds/
year)
and
has
asked
for
comment
on
excluding
these
units
(
69
FR
4999).
The
commenter
believed
EPA
should
exclude
these
units.
The
commenter
stated
that
excluding
them
will
provide
an
incentive
to
reduce
emissions
to
below
the
25­
pound/
year
level
through
pollution
prevention
or
innovative
technology.
The
commenter
believed
that
this
clearly
is
an
environmental
benefit.
The
commenter
further
suggested
that
if
the
agency
excludes
these
units
in
a
cap­
and­
trade
program,
the
overall
mercury
emissions
cap
should
not
be
reduced
by
the
amounts
that
these
sources
emit
(
i.
e.,
the
2018
cap
should
remain
15
tons
even
if
these
sources
are
excluded
from
the
program).

One
commenter
(
OAR­
2002­
0056­
2891)
stated
that
EPA
should
include
an
exclusion
 
or
at
a
minimum,
reduced
requirements
 
for
small
emitting
units
where
additional
emission
controls
cannot
be
economically
justified.
The
commenter
believed
equipping
smaller
units
with
state
of
the
art
emission
controls
is
not
economically
viable
and
equipping
larger
units
that
already
emit
relatively
small
amounts
of
mercury
is
not
cost
effective.
According
to
the
commenter,
excluding
these
units
from
any
additional
mercury
controls,
or
phasing
in
requirements
for
these
units
would
be
more
cost
effective
while
not
resulting
in
any
significant
detriment
to
mercury
reduction
goals.

One
commenter
(
OAR­
2002­
0056­
2867)
supported
exempting
units
with
mercury
emissions
less
than
25
pounds
per
year.
The
commenter
recommended,
however,
that
EPA
should
re­
allocate
the
allowances
to
controlled
units
in
proportion
to
their
annual
heat
input.
If
these
allowances
are
reallocated,
the
commenter
believed
it
would
be
incumbent
on
these
exempted,
low­
emitting
units
to
monitor
emissions
using
infrequent
measurement
methods.
5­
83
One
commenter
(
OAR­
2002­
0056­
3445)
noted
that
EPA
has
expressed
concern
about
units
with
low
mercury
emissions
rates
(
e.
g.,
less
than
25
pounds/
year)
and
has
asked
for
comment
on
excluding
these
units
(
69
FR
4999).
The
commenter
believed
EPA
should
exclude
these
units.
The
commenter
stated
that
excluding
them
will
provide
an
incentive
to
reduce
emissions
to
below
the
25­
pound/
year
level
through
pollution
prevention
or
innovative
technology.
The
commenter
believed
that
this
clearly
is
an
environmental
benefit.
The
commenter
further
suggested
that
if
the
agency
excludes
these
units
in
a
cap­
and­
trade
program,
the
overall
mercury
emissions
cap
should
not
be
reduced
by
the
amounts
that
these
sources
emit
(
i.
e.,
the
2018
cap
should
remain
15
tons
even
if
these
sources
are
excluded
from
the
program).

One
commenter
(
OAR­
2002­
0056­
2172)
strongly
supported
exempting
from
the
final
rule
those
units
that
emit
less
than
25
lbs.
of
mercury
per
year.
The
commenter
believed
that
EPA
has
ample
legal
authority
to
provide
such
an
exemption,
which
would
provide
important
regulatory
relief
for
small
units
that
may
not
be
able
to
comply,
particularly
with
the
Phase
II
cap.

One
commenter
(
OAR­
2002­
0056­
2850)
supported
a
proposal
to
exempt
units
whose
mercury
emissions
are
under
25
pounds
per
year.
The
commenter
added
that
would
involve
less
than
a
10
percent
shift
in
the
tonnage
cap
but
would
exclude
coal
units
for
which
mercury
control
retrofit
would
be
the
least
cost
effective.

Response:

As
discussed
in
the
final
rule
preamble
(
section
IV.
D.
3.
iv),
the
low­
emitter
exclusion
was
proposed
to
address
small
business
entities.
Small
business
entities,
however,
are
not
necessarily
small
emission
emitters.
Of
the
396
units
with
estimated
Hg
emissions
under
25
lb
in
1999,
most
(
about
95
percent)
are
not
owned
by
small
entities
and
a
significant
amount
(
about
10
percent)
are
large­
capacity
units
(
greater
than
250
MW).
In
addition,
removing
low­
emitters
from
the
trading
program
could
increase
costs,
because
a
significant
amount
of
the
396
units
are
large­
capacity
units
that
might
be
expected
to
be
net
seller
of
allowances
because
they
are
already
achieving
emission
reductions.
Therefore,
EPA
maintains
that
the
low­
emitter
exclusion
may
not
be
the
best
way
to
address
small
entity
burden.
For
today's
final
CAMR,
EPA
is
not
finalizing
a
low­
emitter
exclusion
and
EPA
recommends
States
address
small
business
entities
through
the
allocation
process.
For
example,
States
could
provide
a
minimum
Phase
II
allocation
for
small
entities
(
e.
g.,
allocation
based
on
projected
2010
unit
emissions).
EPA
also
maintains
that
the
cap­
and­
trade
program
and
other
program
aspects
minimize
the
burden
for
small
business
entities.
These
program
aspects
include
the
25
MWe
size
cut­
off.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2260,
­
2365,
­
2661,
­
2891)
believed
EPA
should
include
an
exclusion
 
or
at
a
minimum,
reduced
requirements
 
for
small
emitting
units
where
additional
emission
controls
cannot
be
economically
justified.
The
commenters
stated
equipping
smaller
units
with
state
of
the
art
emission
controls
is
not
economically
viable
and
equipping
larger
units
that
already
emit
relatively
small
amounts
of
mercury
is
not
cost
effective.
The
commenters
added
that
excluding
these
units
from
any
additional
mercury
controls,
or
phasing
5­
84
requirements
for
these
units
would
be
more
cost
effective
and
not
detrimental
to
mercury
reduction
goals.

One
commenter
(
OAR­
2002­
0056­
2267)
believed
that
EPA
must
limit
the
disproportionate
impact
of
the
proposed
rules
on
low
emitting
units.
The
commenter
noted
the
low
emitting
units
emit
relatively
smaller
amounts
of
emissions
and
controls
on
such
units
are
less
cost­
effective
than
for
larger
units.
The
commenter
stated
imposing
controls
on
the
low
emitting
units
will
not
significantly
contribute
to
reductions
required
to
meet
the
proposed
caps
or
to
the
overall
reductions
achieved
under
the
MACT
approach
if
it
is
adopted.
The
commenter
stated
that
for
these
reasons,
EPA
should
provide
appropriate
relief
for
the
low
emitting
units
under
the
proposed
cap­
and
trade
or
MACT
programs.

One
commenter
(
OAR­
2002­
0056­
3514)
supported
EPA's
conclusion
that
the
control
technologies
currently
being
researched
will
not
be
practical
at
units
emitting
less
than
25
tons
per
year,
and
suggested
that
exemption
apply
regardless
of
which
implementation
option
EPA
selects
for
the
final
rule.

One
commenter
(
OAR­
2002­
0056­
1969)
stated
that
EPA
is
correct
in
its
concern
that
new,
mercury
specific
control
technologies
that
are
expected
to
be
developed
prior
to
the
Phase
II
cap
deadline
may
not
practicably
apply
to
units
with
low
annual
mercury
emissions.
The
commenter
suggested
that
electric
generating
units
emitting
less
than
25
pounds
per
year
be
excluded
from
the
Phase
II
cap.

Response:

As
discussed
above
and
in
the
final
rule
preamble
(
section
IV.
D.
3.
iv),
EPA
is
not
finalizing
a
low­
emitter
exclusion
and
EPA
recommends
States
address
small
business
entities
through
the
allocation
process.

Comment:

One
commenter
(
OAR­
2002­
0056­
3437)
stated
that
the
25
lb/
yr
exemption
should
not
be
included.
The
commenter
noted
that
in
the
SNPR,
the
applicability
is
limited
to
EGU
greater
than
25
MW
with
no
low­
emitting
exception.
The
only
exception
is
for
retired
units.

One
commenter
(
OAR­
2002­
0056­
3459)
stated
in
public
interest
group
comprehensive
comments
that
if
EPA
proceeds
with
its
illegal
trading
program,
it
must
reject
program
elements
that
permit
increased
pollution.
In
response
to
EPA's
request
for
comments,
the
commenter
stated
utility
units
emitting
less
than
25
pounds
of
mercury
should
not
be
exempted
from
the
2018
cap.
The
commenter
asserted
that
the
record
documents
the
origin
of
this
provision
and
shows
that
EPA
did
no
analysis
of
impacts
or
costs.
The
commenter
stated
that
the
language
comes
directly
from
the
Small
Business
Administration
(
SBA),
which
is
concerned
about
small
units
having
difficulty
making
the
reductions,
but
EPA
offers
no
evidence
that
this
is
true.
The
commenter
stated
that
EPA's
memo
identifying
such
units
indicates
that
only
about
60
(
of
396)
are
standalone
units;
all
others
are
boilers
part
of
a
multi­
boiler
facility
where
boilers
are
likely
tied
5­
85
into
a
common
ductwork
for
pollution
control.
The
commenter
added
that
because
EPA
is
proposing
to
allow
facilities
to
bubble
their
emissions,
units
other
than
the
one
or
two
small
units
can
be
controlled
to
a
greater
extent
to
compensate
for
the
lower
emitting
small
units.
The
commenter
stated
that
his
would
help
mitigate
any
concerns
about
control
costs
for
small
units.
Thus,
the
commenter
asserted
that
the
proposal
to
exempt
them
is
arbitrary
and
capricious.

Response:

As
discussed
above
and
in
the
final
rule
preamble
(
section
IV.
D.
3.
iv),
EPA
is
not
finalizing
a
low­
emitter
exclusion
and
EPA
recommends
States
address
small
business
entities
through
the
allocation
process.

Comment:

One
commenter
(
OAR­
2002­
0056­
2911)
recommended
that
EPA
follow
its
concerns
about
the
ability
of
smaller
units
to
implement
mercury­
specific
control
technologies.
The
commenter
recommended
that
units
emitting
less
than
50
pounds
of
mercury
per
year
be
exempt
from
mercury­
specific
control
requirements.

One
commenter
(
OAR­
2002­
0056­
3556)
recommended
that
EPA
follow
its
concerns
about
the
ability
of
smaller
units
to
implement
mercury­
specific
control
technologies.
The
commenter
recommended
that
units
emitting
less
than
50
pounds
of
mercury
per
year
be
exempt
from
mercury­
specific
control
requirements.

One
commenter
(
OAR­
2002­
0056­
3556)
recommended
that
EPA
follow
its
concerns
about
the
ability
of
smaller
units
to
implement
mercury­
specific
control
technologies.
The
commenter
recommended
that
units
emitting
less
than
50
pounds
of
mercury
per
year
be
exempt
from
mercury­
specific
control
requirements.

One
commenter
(
OAR­
2002­
0056­
3556)
recommended
that
EPA
follow
its
concerns
about
the
ability
of
smaller
units
to
implement
mercury­
specific
control
technologies.
The
commenter
recommended
that
units
emitting
less
than
50
pounds
of
mercury
per
year
be
exempt
from
mercury­
specific
control
requirements.

One
commenter
(
OAR­
2002­
0056­
3432)
stated
that
like
other
small
rural
electric
generating
and
transmission
(
G
&
T)
cooperatives,
they
have
a
number
of
small
coal­
fired
boilers.
The
commenter
stated
that
installing
and
operating
emission
controls
on
small
units
is
not
economically
viable,
and
the
amount
of
mercury
emissions
attributable
to
these
small
units
is
not
significant.
The
commenter
supported
exempting
units
with
mercury
emissions
less
than
50
pounds/
year
from
the
control
program
and
re­
allocating
the
exempt
unit
allowances
to
units
in
the
program
in
proportion
to
their
annual
heat
input.
The
commenter
acknowledged
that
exempted
units
would
need
to
demonstrate
that
their
emissions
do
not
rise
above
the
exempted
level,
however,
less
sophisticated
and
cost­
effective
monitoring
methods
should
be
allowed.
5­
86
One
commenter
(
OAR­
2002­
0056­
2422)
noted
that
EPA
has
requested
comment
on
the
basis
for
excluding
certain
small
coal­
fired
units
from
emission
controls
in
the
context
of
an
emission
trading
program.
The
commenter
encouraged
EPA
to
exclude
at
least
these
396
small
units
emitting
less
than
25
pounds
of
mercury
annually
due
to
the
lack
of
cost­
effective
mercury
controls
available
for
retrofit
installations,
and
the
likelihood
that
emissions
from
these
units
are
not
contributing
measurably
to
any
domestic
public
health
problems.
According
to
the
commenter,
indeed,
a
higher
cutoff
limit
for
a
small
unit
exclusion
could
be
justified
for
the
reasons
that
EPA
has
identified
regarding
the
prospective
retrofit
of
mercury
control
technologies
in
a
Phase
II
trading
program.
For
these
reasons,
the
commenter
urged
EPA
to
establish
a
minimum
emission
threshold
for
exclusion
that
will
avoid
the
need
to
control
emissions
at
small
electric
generating
units
whose
emissions
do
not
measurably
impact
global
mercury
budgets.
According
to
the
commenter,
if
confronted
with
plant­
or
unit­
specific
emission
limits,
such
units
likely
would
be
retired
rather
than
retrofitted
with
costly
control
technologies.

Response:

As
discussed
above
and
in
the
final
rule
preamble
(
section
IV.
D.
3.
iv),
EPA
is
not
finalizing
a
low­
emitter
exclusion
and
EPA
recommends
States
address
small
business
entities
through
the
allocation
process.

Comment:

One
commenter
(
OAR­
2002­
0056­
2861)
stated
that
EPA
has
asked
for
comment
on
excluding
units
that
emit
less
than
25
pounds
of
mercury
per
year
from
the
Phase
II
mercury
cap.
According
to
the
commenter,
as
noted,
these
units
make
up
a
small
percentage
of
the
total
mercury
emissions
from
U.
S.
coal­
fired
power
plants
(
5
percent
by
EPA's
estimate).
The
commenter
believed
an
exclusion
for
low
emitting
units
is
appropriate,
both
for
all
phases
of
a
cap
and
trade
program
and
for
a
MACT
program.
However,
rather
than
exclude
units
based
on
their
mercury
emissions
as
EPA
has
proposed,
the
commenter
recommended
the
exclusion
be
based
on
a
unit's
size,
with
a
cutoff
in
the
range
of
100
to
140
MW.
The
commenter
believed
a
MW
size
cutoff
would
provide
a
more
definite
exclusion
than
use
of
mercury
emissions.
The
commenter
stated
that
currently,
there
is
great
uncertainty
and
variability
in
estimations
of
mercury
emissions
from
power
plants.
The
commenter
submitted
that
specifying
unit
size
as
the
parameter
for
determining
the
exclusion
will
provide
greater
regulatory
certainty
and
will
meet
similar
objectives
as
EPA
identified
for
considering
a
25­
pound
exclusion.

The
commenter
has
reviewed
the
estimated
mercury
emissions
from
the
commenter's
coal­
fired
power
plants
for
2002
based
on
information
provided
in
their
annual
TRI
report.
The
commenter
operates
31
coal­
fired
boilers
burning
Eastern
bituminous
coal.
These
boilers
range
in
size
from
38
to
1120
MW.
For
2002,
the
13
boilers
of
100
MW
or
less
in
size
accounted
for
only
5
percent
of
the
commenter's
estimated
coal­
fired
boiler
mercury
emissions,
and
each
of
those
boilers
had
calculated
emissions
less
than
25
pounds.
The
commenter
suggested
a
broader
analysis
of
all
power
plants
in
the
nation
may
show
that
a
unit
rating
as
high
as
140
MW
would
account
for
5
percent
or
less
of
total
mercury
emissions.
According
to
the
commenter,
as
suggested
in
EPA's
proposal,
the
cost
of
emissions
monitoring
and
administration
for
these
units
5­
87
with
low
emissions
is
excessive
and
would
result
in
very
little
actual
reduction
in
emissions.
The
commenter
added
that
requiring
sources
to
incur
the
cost
of
monitoring
simply
to
demonstrate
that
they
qualify
for
the
exclusion
when
there
is
a
surrogate
metric,
megawatts,
which
will
yield
very
similar
results
is
not
cost
effective
and
is
not
good
public
policy.

The
commenter
stated
that
if
EPA
does
exclude
low
emitting
units
under
a
cap
and
trade
program,
the
cap
for
the
remaining,
non­
excluded
units
should
not
be
reduced
to
offset
the
emissions
from
the
excluded
units.
The
commenter
noted
that
the
proposed
15
ton
cap
on
mercury
has
no
specific
regulatory
or
scientific
basis
and
therefore
EPA
is
not
required
to
offset
the
insignificant
amount
of
emissions
from
small
sources
as
if
there
were
a
"
hard
cap"
on
the
allowable
mercury
emissions.
The
commenter
submitted
that
reducing
the
15
ton
cap
would
simply
shift
an
additional
burden
onto
the
regulated
units,
and
would
tend
to
drive
up
the
cost
of
allowances
by
locking
up
5
percent
of
the
total
allowances
that
would
otherwise
be
available
for
trading.

The
commenter
noted
that
in
its
MACT
proposal,
EPA
proposed
that
low­
emitting
units
be
excluded
only
from
monitoring
requirements
for
low­
emitting
units.
Consistent
with
their
position
on
the
cap
and
trade
program,
the
commenter
believed
these
low­
emitting
units
(
units
rated
below
a
specified
MW
rating
as
they
have
proposed,
or
units
below
25
pounds
of
mercury
as
EPA
has
proposed)
should
be
excluded
from
all
MACT
requirements.

Response:

As
discussed
above
and
in
the
final
rule
preamble
(
section
IV.
D.
3.
iv),
EPA
is
not
finalizing
a
low­
emitter
exclusion
and
EPA
recommends
States
address
small
business
entities
through
the
allocation
process.
The
CAMR
cap­
and­
trade
program
includes
a
25
MWe
size
cut­
off
which
EPA
believes
is
appropriate.

Comment:

One
commenter
(
OAR­
2002­
0056­
2661)
proposed
that
smaller
emitting
units
be
allowed
to
be
bubble
with
other
larger
sources
within
the
larger
system­
wide
average
for
a
utility
or
group
of
utilities.
The
commenter
believed
that
greater
emission
controls
would
be
realized
at
large
emitting
units
and
make
control
schemes
more
cost
effective
to
implement.

Response:

As
discussed
above
and
in
the
final
rule
preamble
(
section
IV.
D.
3.
iv),
EPA
is
not
finalizing
a
low­
emitter
exclusion
and
EPA
recommends
States
address
small
business
entities
through
the
allocation
process.
EPA
also
notes
that
the
cap­
and­
trae
program
allows
for
the
commenter's
proposal.

Comment:
5­
88
One
commenter
(
OAR­
2002­
0056­
3509)
stated
that
to
the
extent
that
the
final
Utility
Mercury
Rule
does
require
controls
of
small
municipal
generators
via
allowance
trading
or
other
requirements,
EPA
should
provide
these
units
with
other
compliance
flexibility
options
to
reduce
the
cost
of
such
compliance.

One
commenter
(
OAR­
2002­
0056­
3509)
strongly
urged
the
EPA
to
exclude
the
smallest
emitting
units
(
units
with
less
than
25
pounds
annual
emissions)
from
mercury
controls
under
either
the
MACT
or
the
cap­
and­
trade
approach,
because
these
small
units
emit
a
relatively
insignificant
level
of
mercury;
because
these
units
will
suffer
drastic,
disproportionate
and
costly
impacts
from
the
rule;
because
the
technology
to
comply
is
unproven
for
these
small
units;
and
because
the
continued
operation
of
these
units
is
critical
to
the
basic
energy
needs
of
local
communities
in
Michigan.
The
commenter
urged
EPA
to
adopt
this
exclusion
for
small
emitters
for
both
existing
affected
units
and
new
affected
units,
including
those
that
blend
coal
and
non­
coal
fuels
in
their
generation
mix
(
and
who
measure
emissions
using
EPA's
suggested
mass
balancing
approach).

One
commenter
(
OAR­
2002­
0056­
3509)
stated
that
the
rule's
requirements
for
utility
unit
mercury
controls,
under
either
the
MACT
or
trading
approach,
will
disproportionately
impact
the
smallest
units
and
systems.
Based
on
information
derived
from
EPA's
Mercury
Information
Collection
Request,
Toxic
Release
Inventory
reporting,
and
stack
testing
for
mercury
emissions,
the
commenter
estimated
that
the
units
they
own
and
operate
are
emitting
less
than
25
pounds
of
mercury
annually
each.
The
commenter
stated
this
places
them
in
the
category
of
units
that
EPA
refers
to
as
"
small
emitters."
The
commenter
pointed
out
that
it
is
important
that
the
Utility
Mercury
Rule
considers
and
helps
mitigate
small
entity
impacts
for
several
economic
and
environmental
reasons,
including:

°
Diseconomies
of
Scale
 
The
capital
costs
for
emissions
control
at
small­
sized
utility
units
is
disproportionately
high
due
to
inefficiencies
in
mercury
removal,
space
constraints
for
control
technology
retrofits,
and
the
fact
that
small
units
have
fewer
rate
base
customers
upon
which
to
spread
these
costs.

°
Less
Bang
for
the
Buck
 
The
commenter
stated
that
as
EPA
has
acknowledged,
smaller
utility
units
contribute
a
relatively
insignificant
level
of
mercury
in
the
context
of
the
industry­
wide
contribution
of
mercury
emissions.

°
Unproven
Technologies
 
The
commenter
was
not
able
to
provide
any
technical
information
on
whether
these
small
units
could
reduce
mercury
emissions
to
the
low
levels
proposed
by
the
EPA
either
under
the
MACT
approach
or
the
cap­
and­
trade
approach
 
because
mercury
control
technologies
are
generally
untested
and
unproven
for
these
sizes
and
types
of
units.
The
commenter
emphasized
EPA's
own
recognition
that
"
the
new,
mercury­
specific
control
technologies
that
we
expect
to
be
developed
prior
to
the
[
2018]
Phase
II
cap
deadline
may
not
practicably
apply
to
such
units
period."
Proposed
Rule
at
4699.
The
commenter
also
noted
that
the
current
DOE/
EPRI/
EPA
effort
to
test
the
availability
and
effectiveness
of
mercury
control
technologies
for
coal­
fired
utility
units
involves
primarily
larger­
sized
units
(
See
5­
89
http://
www.
netl.
doe.
gov/
coalpower/
environment/
).
The
commenter
added
that
nor
do
these
DOE
demonstration
studies,
or
other
available
studies,
show
whether
mercury
control
technologies
are
effective,
let
alone
cost­
effective,
at
the
smallest
sized
coal­
fired
units.
To
the
commenter's
knowledge,
no
large
scale
field
testing
for
activated
carbon
technology
have
been
conducted
for
units
<
80
MW.
The
commenter
added
that
these
technologies
are
untested
for
the
smallest
utility
units.

°
More
Limited
Access
to
Capital
 
Smaller
utility
systems
generally
have
less
capital
to
invest
in
pollution
control
than
larger,
investor­
owned
systems,
due
to
statutory
inability
to
borrow
from
the
private
capital
markets,
statutory
debt
ceilings,
limited
bonding
capacity,
borrowing
limitations
related
to
fiscal
strain
posed
by
other,
non­
environmental
factors,
and
other
limitations.

°
Limited
Ability
to
Average
Emissions
 
Public
power
systems
have
much
less
flexibility
in
trading
under
the
proposed
Utility
Mercury
Rule
because
municipalities
typically
do
not
own
multiple
utility
units
that
can
utilize
system­
wide
averaging
of
emissions
for
cap­
and­
trade
compliance
purposes.
Likewise,
the
commenter
did
not
own
units
that
are
large
enough
to
enable
the
application
of
control
technology
that
could
likely
produce
mercury
trading
credits.

°
Important
Role
of
Public
Power
to
Communities
 
Michigan
public
power
communities
play
an
important
role
in
the
competitive
utility
industry,
and
provide
valuable
services
to
local
citizens.
Pollution
controls
should
not
disproportionately
impact
smaller
entities
and
thereby
impose
a
competitive
disadvantage
on
municipalities.

The
commenter
stated
that
for
all
these
reasons,
EPA
should
take
into
account
the
disproportionate
adverse
impacts
of
the
Utility
Mercury
Rule
on
small
systems
and
units.
Moreover,
the
commenter
emphasized
that
the
ability
of
these
small
electric
systems
to
purchase
mercury
allowances
on
the
market
is
not
a
sufficient
solution,
by
itself,
to
the
major
economic
challenges
that
will
face
these
communities
under
the
Utility
Mercury
Rule.
The
commenter
stated
that
there
are
substantial
transaction
costs
to
allowance
trading,
as
recognized
by
the
D.
C.
Circuit
Court
of
Appeals.
See
Michigan
v.
EPA,
213
F.
3d
663,
676
and
n.
3
(
D.
C.
Cir.
2000)
("
A
glance
at
EPA's
regulations
for
allowance
trading
will
convince
any
doubter
that
transaction
costs
can
safely
be
expected
to
be
substantial.")
The
commenter
further
stated
that
in
addition,
the
Utility
Mercury
Rule's
trading
market
may
never
generate
sufficient
excess
allowances
to
alleviate
any
of
this
burden
on
small
electric
systems
and
units.
The
commenter
believed
that
without
consideration
of
the
particular
challenges
and
needs
of
small
electric
units,
the
long­
term
economic
viability
of
these
systems
will
be
subject
to
the
vagaries
of
an
uncertain
and
potentially
scarce
allowance
market.

One
commenter
(
OAR­
2002­
0056­
3509)
encouraged
EPA
to
consider
allowing
small
municipal
generators
(
with
capacities
of
less
than
25
megawatts)
that
are
located
at
a
common
facility
with
larger
units
(>
25MW),
to
have
the
voluntary
option
to
"
opt­
in"
the
smaller,
less
than
25
MW
units,
to
the
Utility
Mercury
Rule.
The
commenter
added
that
most
importantly,
EPA
should
provide
options
for
mercury
compliance
optimization
at
electric
generating
facilities
where
5­
90
there
are
units
that
are
considered
Industrial
Boiler
MACT
units
that
are
operated
in
common
with
proposed
Utility
Mercury
Rule
units.
The
commenter
added
that
the
current
situation
is
particularly
difficult
for
those
public
power
systems,
like
some
of
those
commenting
here,
who
have
both
>
25MW
and
<
25MW
electric
generating
units
located
in
a
common
facility.
The
commenter
noted
that
in
one
case,
these
different
sized
units
are
located
on
a
common
steam
header.
The
commenter
stated
that
however,
under
EPA's
Industrial
Boiler
MACT
and
proposed
Utility
Mercury
Rule,
these
systems
will
be
unable
to
average
emissions
facility­
wide,
or
enjoy
the
compliance
optimization
and
flexibility
necessary
to
be
able
to
comply
cost­
effectively.

The
commenter
noted
that
EPA
specifically
requests
comments
in
the
Proposed
Rule
(
4657)
on
how
to
consider
units
subject
to
different
EPA
mercury
rules
at
the
same
facility.
The
commenter
emphasized
that
this
is
a
problem,
and
encourages
EPA
to
allow
small,
<
25MW
EGUs
located
at
a
common,
contiguous
facility
with
other
EGUs
subject
to
the
Utility
Mercury
Rule,
to
be
able
to
opt­
in
to
the
Utility
Mercury
Rule,
either
to
claim
the
"
small
emitter"
exclusion,
or
to
be
able
to
average
and
trade
allowances
among
their
common
units.

Response:

As
discussed
above
and
in
the
final
rule
preamble
(
section
IV.
D.
3.
iv),
EPA
is
not
finalizing
a
low­
emitter
exclusion
and
EPA
recommends
States
address
small
business
entities
through
the
allocation
process.

Comment:
One
commenter
(
OAR­
2002­
0056­
4456)
supported
a
small
emitter
exemption
that
would
apply
to
either
a
cap/
trade­
based
or
MACT
­
based
Hg
emissions
regulatory
system.
However,
the
commenters
suggested
that
EPA
can
best
achieve
its
objectives
by
crafting
an
exemption
that
is
facility
or
source
based,
as
opposed
to
one
that
is
solely
unit
based.

The
commenters
stated
that
EPA's
notice
styles
the
proposed
small
emitter
exemption
as
one
applying
on
a
unit
basis.
The
commenters
stated
that,
however,
EPA's
data
shows
that
creating
a
unit­
based
Hg
exemption
does
not
isolate
a
class
of
small
utility
emitters.
The
commenters
noted
that
many
units
covered
by
EPA's
suggested
unit­
based
exemption
are
smaller
units
at
very
large
multiple­
unit
electric
generating
facilities.
The
commenters
stated
that,
conversely,
EPA's
data
shows
that
many
units
that
may
emit
more
than
25
pounds
of
Hg
per
year
are
single
units
at
small
electric
generating
facilities.
According
to
the
commenters,
thus,
a
unit­
based
proposal
does
not
correctly
identify
the
universe
of
small
utility
Hg
emitters.

The
commenters
proposed
that
EPA
adopt
a
final
rule
that
exempts
from
Hg
regulation
all
utility
units
at
common­
source
plant
facilities
that
emit,
on
a
facility­
wide
basis,
less
than
a
threshold
amount
of
Hg
per
year.
For
the
threshold
amount,
the
commenters
suggested
that
EPA
convert
the
Clear
Skies
unit­
based
exemption
(
50
pounds
or
less
per
unit)
to
a
facility­
based
exemption
so
that
the
total
projected
exempt
emissions
(
6.9
percent
of
the
total)
remains
the
same.
The
commenters
stated
that
EPA's
1999
ICR
plant
emission
data
base
shows
this
cut­
off,
on
a
facility
basis,
is
approximately
95
pounds
(
or
less)
of
Hg
facility
emissions
per
year.
5­
91
According
to
the
commenters,
alternatively,
EPA
could
convert
the
25
pound
unit­
based
exemption
referenced
in
EPA's
Notice
to
a
facility­
based
exemption
so
that
the
total
exempt
emissions
(
3.9
percent
of
the
total)
remains
the
same.
The
commenters
stated
that
EPA's
1999
ICR
plant
emission
data
base
shows
this
cut­
off,
on
a
facility
basis,
is
approximately
62
pounds
(
or
less)
of
Hg
facility
emissions
per
year.

The
commenters
suggested
EPA
adopt
the
following
procedures
to
implement
a
facility­
based
small
emitter
exemption:

°
Initial
Identification
of
Exempt
Facilities.
EPA
would
identify
potentially
qualifying
facilities
(
i.
e.,
all
utility
units
at
facilities
emitting
less
than
the
annual
utility
facility
Hg
threshold)
from
its
1999
ICR
plant
data
base.

°
Utility
Election.
Owners
of
qualifying
facilities
identified
by
EPA
could,
at
their
election,
have
units
at
their
facilities
designated
as
exempt
or,
in
the
alternative,
designated
as
non­
exempt
covered
utility
units.

°
Post­
Election
Actions.
Under
cap
and
trade,
qualifying
units
that
a
facility
owner
elects
for
exempt
status
would
receive
no
allowance
allocations.
Consistent
with
the
approach
taken
in
the
Chairman's
Mark
bill,
remaining
affected
units
would
be
allocated
allowances
(
e.
g.,
if
a
15
ton
Phase
II
Hg
cap
is
in
place,
allowances
equal
to
15
Hg
tons
would
be
allocated
to
non­
exempt
affected
units).
(
See,
S.
1844,
§
§
471,473).
Under
MACT,
qualifying
units
that
a
utility
elects
for
exempt
status
would
initially
be
exempt
from
MACT
Hg
regulations.

°
Monitoring.
Facility
owners
electing
exempt
status
would
be
required
to
monitor
their
facility
Hg
emissions
in
a
cost­
effective
manner.
Hastings
and
Grand
Island
suggest
that
exempt
facilities
utilize
EPA­
approved
ASTM
Hg
sampling
and
Hg
emission
testing
procedures
at
frequencies
selected
by
facility
owners,
but
no
less
than
quarterly.
Annual
Hg
emissions
would
be
calculated
from
this
data,
using
the
same
procedures
EPA
utilized
to
estimate
the
unit­
specific
1999
Hg
emissions
referenced
in
its
Notice
(
49
F.
R.
at
4699).
°
Excess
Emissions.
If
an
exempt
facility
exceeded
the
exemption
Hg
emission
threshold
in
any
year,
the
facility
owner,
under
the
cap­
and­
trade
proposal,
would
have
to
obtain
Hg
allowances
equal
to
its
excess
emissions
(
Hg
emitted
(
pounds)
threshold
Hg
amount
(
pounds)
=
excess
Hg
emissions).
Under
MACT,
the
facility
owners
could
pay
an
appropriate
fine,
or
if
the
problem
became
a
persistent
one,
the
facility
would
lose
its
exempt
status
and
become
subject
to
the
applicable
governing
MACT
standards
for
non­
exempt
units.

°
New
Units.
Any
new
utility
units
built
at
exempt
facilities
would
be
subject
to
otherwise
applicable
Hg
emission
regulations,
but
pre­
existing
facility
units
would
remain
exempt
if
the
exemption
threshold
is
not
exceeded
for
the
pre­
existing
facility
units.

Both
EPA
and
Congress
have
expressed
concerns
about
small
Hg
emitters.
These
concerns
are
driven
by
the
huge
costs
that
Hg
controls
will
impose
on
impacted
utilities
and
the
5­
92
cost/
benefit
considerations
of
imposing
these
huge
costs
on
very
small
Hg
emitters.
The
commenters
suggested
that
the
correct
cost/
benefit
calculus
results
in
exempting
facilities,
many
of
which
are
publicly­
owned
or
co­
ops,
where
overall
facility
emissions
are
low.
According
to
the
commenters,
EPA
can
achieve
its
national
Hg
reduction
objectives
without
subjecting
facilities
that
contribute
only
a
tiny
fraction
of
national
Hg
emissions
to
extraordinarily
expensive
regulations.

Response:

As
discussed
above
and
in
the
final
rule
preamble
(
section
IV.
D.
3.
iv),
EPA
is
not
finalizing
a
low­
emitter
exclusion
and
EPA
recommends
States
address
small
business
entities
through
the
allocation
process.

Comment:

One
commenter
(
OAR­
2002­
0056­
2162)
supported
the
promulgation
of
an
exemption
from
the
proposed
mercury
rules
for
electric
utility
steam
generating
units
emitting
less
than
25
pounds
of
mercury
per
year.

The
commenter
noted
that
in
its
preambles
to
the
Proposed
Mercury
Rules,
the
Agency
solicits
comment
on
a
proposed
exemption
from
the
Phase
II
requirements
of
the
proposed
mercury
cap­
and­
trade
rule
for
units
emitting
less
than
25
pounds
of
mercury
per
year.
The
commenter
noted
that
the
Agency's
basis
for
the
proposed
exemption
from
the
requirements
is
that
low
emitting
sources
would
be
disproportionately
impacted
by
the
costs
of
complying
with
requirements
under
the
proposed
MACT
standard.
The
commenter
stated
that
the
available
information
clearly
justifies
this
concern.
According
to
the
commenter,
while
the
Agency
estimates
that
396
of
the
1,124
units
operational
in
1999
(
35.4
percent
of
total
operating
units)
would
meet
the
25
pound
exemption,
these
units
in
the
aggregate
would
contribute
less
than
5
percent
of
total
mercury
emissions.
The
commenter
added
that,
further,
according
to
the
Agency's
data,
exemption
of
these
units
from
the
Phase
II
cap
would
not
interfere
with
the
overall
ability
of
affected
sources
to
comply
with
the
15
ton
cap.
The
commenter
stated
that,
accordingly,
proposed
25
lb/
year
exemption,
a
substantial
number
of
sources
would
be
forced
to
absorb
significant
expense
without
achieving
any
appreciable
environmental
benefit.

The
commenter
stated
that,
likewise,
the
Agency
expressed
concern
that
the
mercury
specific
control
technologies
currently
under
development
may
not
apply
to
low­
emitting
units,
and
therefore
those
units
would
be
unable
to
further
reduce
mercury
emissions
in
accordance
with
cap­
and­
trade
requirements.
The
commenter
stated
that
with
respect
to
their
facilities,
the
units
already
are
subjected
to
the
best
commercially
available
mercury
control
technology.
According
to
the
commenter,
these
low
emitting
sources
could
not
reasonably
further
reduce
mercury
emissions
in
response
to
any
cap­
and­
trade
or
other
mercury
control
regulation.

In
addition
to
its
position
that
waste
coal­
fired
sources
should
be
exempt
from
the
Proposed
Mercury
Rules,
the
commenter
also
supported
the
proposed
exemption
of
sources
emitting
less
than
25
pounds
of
mercury
per
year
from
the
Proposed
Mercury
Rules,
for
the
5­
93
reasons
articulated
by
the
Agency
in
its
preamble.
The
commenter
believed
that
the
de
minimis
nature
of
these
sources
supports
the
implementation
of
a
wholesale
exemption
from
the
proposed
MACT­
based
emission
limitations
or
the
proposed
cap­
and­
trade
program,
whichever
is
finally
promulgated
by
the
Agency.
The
commenter
stated
that,
specifically,
the
Agency's
rationale
for
exempting
such
sources
from
the
Phase
II
mercury
cap­
and­
trade
program
also
would
support
an
exemption
from
MACT
requirements.
According
to
the
commenter,
to
the
extent
that
low
emitting
sources
would
be
unable
to
further
control
mercury
emissions
as
required
under
the
Phase
II
cap
due
to
the
unavailability
of
effective
add­
on
mercury
controls,
such
sources
likewise
would
be
unable
to
meet
the
proposed
MACT
standards.
The
commenter
further
stated
that
the
regulation
of
such
low
emitting
sources
would
be
inconsistent
with
the
Agency's
mandate
to
consider
the
necessity
and
benefit
of
regulation
for
specific
affected
sources.

According
to
the
commenter,
to
the
extent
that
the
Agency
does
promulgate
an
exemption
for
sources
emitting
less
than
25
pounds
per
year
of
mercury,
the
exemption
should
be
absolute,
and
should
not
result
in
the
imposition
of
monitoring,
testing
or
record
keeping
requirements
upon
these
de
minimis
sources.
The
commenter
stated
that
such
an
approach
would
be
consistent
with
other
MACT
standards
developed
by
the
Agency,
pursuant
to
which
certain
de
minimis
sources
within
a
regulated
source
category
may
be
completely
exempted
from
all
requirements
of
the
relevant
MACT
regulation.

Response:

As
discussed
above
and
in
the
final
rule
preamble
(
section
IV.
D.
3.
iv),
EPA
is
not
finalizing
a
low­
emitter
exclusion
and
EPA
recommends
States
address
small
business
entities
through
the
allocation
process.

5.5.3
Opt­
ins
Comment:

Several
commenters
(
OAR­
2002­
0056­
2900,
­
3432,
­
2105)
supported
allowing
facilities
with
both
industrial
boiler
units
and
coal­
fired
utility
units
to
opt
the
industrial
boiler
units
into
the
electric
utility
rule
for
purposes
of
meeting
the
emissions
standard.
The
commenter
believes
a
final
rule
should
allow
affected
facilities
with
both
industrial
boilers
and
coal­
fired
utility
units
the
compliance
flexibility
to
meet
one
Hg
emission
limit
through
facility­
wide
emissions
averaging.

One
commenter
(
OAR­
2002­
0056­
2105)
recommended
that
any
emission­
trading
program
for
Utility
Steam
Generating
Units
be
promulgated
with
an
"
opt­
in"
provision
so
that
other
sources
and
industries
with
verifiable
and
surplus
mercury
emission
reductions
could
generate
and
trade
them
as
viable
emission
reduction
credits
under
this
rulemaking.
The
commenter
was
aware
of
the
many
obstacles
and
potential
legal
challenges,
however
in
this
instance,
the
commenter
felt
it
was
imperative
that
more,
faster,
and
cost­
effective
reductions
are
made
as
soon
as
practicable.
The
commenter
believed
that
providing
an
"
opt­
in"
provision
for
any
and
all
sources
would
encourage
the
maximum
reduction
in
emissions
in
the
shortest
amount
of
time,
in
the
most
cost
effective
manner
and
with
the
least
amount
of
social
cost
in
the
form
of
5­
94
elevated
energy
costs
to
the
public.
A
second
commenter
(
OAR­
2002­
0056­
1756)
asked
if
the
rule
will
allow
other
types
of
sources
(
non­
utility
combustion
or
non­
combustion
mercury)
to
participate
in
trading
or
offsets
in
cap
and
trade
program?

One
commenter
(
OAR­
2002­
0056­
3432)
believed
that
if,
in
the
final
rule,
the
EPA
does
not
allow
sources
to
opt­
in
industrial
boiler
(
IB)
unit(
s)
into
the
Utility
Mercury
MACT,
or
if
the
final
rule
does
allow
the
flexibility
of
opt­
in
and
sources
choose
not
to
opt­
in
IB
unit(
s)
due
to
their
own
unique
situations,
these
sources
should
not
be
faced
with
expensive
additional
monitoring
or
apportionment
methods
for
the
determination
of
the
contribution
of
mercury
emissions
from
IB
unit(
s).
For
those
sources
with
the
"
common
stack"
situation,
the
commenter
stated
that
the
EPA
should
allow
the
source
the
flexibility
to
monitor
the
mercury
concentration
in
the
common
stack
and
to
apply
this
concentration
to
the
IB(
s)
flue
gas
duct.
According
to
the
commenter,
utilizing
the
EPA
approved
volumetric
flow
measurements
for
the
common
stack
and
for
the
IB(
s)
flue
gas
duct,
the
source
would
then
be
able
to
calculate
mercury
mass
emissions
for
the
common
stack
and
for
the
IB(
s)
duct.
With
these
parameters,
electric
utility
steam
generating
units
(
EUSGU)
and
IB(
s)
mercury
mass
emissions
can
be
determined
by
simple
subtraction.

Response:

Under
the
final
CAMR,
EPA
is
requiring
States
and
Tribes
to
meet
emissions
budgets
and
to
achieve
those
emissions
reductions
from
coal­
fired
power
generation
sources.
EPA
is
not
allowing
States
or
Tribes
to
opt­
in
other
sources
into
the
cap­
and­
trade
program
to
meet
its
emission
budget.
EPA
feels
strongly
that
any
cap
and
trade
program
needs
to
have
strong
monitoring
and
reporting
requirements,
which
are
difficult
to
enforce
and
implement
for
other
source
categories.
Given
that
other
stationary
sources
(
e.
g.,
boilers)
are
already
complying
with
MACT
Hg
standards,
cost­
effective
reductions
from
other
source
categories
are
not
likely.

To
address
the
issues
associated
with
monitoring
units
at
a
common
stack
where
one
is
affected
and
the
other
not
EPA
provides
alternative
monitoring
methodology.
This
alternatives
can
possibly
include:
measuring
Hg
for
the
affected
unit
in
the
duct;
doing
a
proportional
distribution
based
on
fuel;
using
a
conservative
mass
balance
to
determine
the
proportion
of
Hg
in
the
flue
gas
that
each
unit
is
contributing.

Comment:

Commenter
(
OAR­
2002­
0056­
3530,
­
2833)
stated
that
the
utility
mercury
reductions
rule
(
UMRR)
should
not
extend
its
mandates
to
either
current
or
future
combined­
heat­
and­
power
systems
(
CHP).
The
commenter
stated
that
in
virtually
all
cases,
CHP
units
are
a
source
of
highly
efficient
power
with
correspondingly
low
emissions.
The
commenter
added
that
hundreds
of
industrial
facilities
depend
on
the
economic
efficiencies
of
CHP.
The
commenter
stated
that
in
fact,
the
President's
National
Energy
Policy
recommends
the
increased
use
of
CHP
systems
to
improve
energy
efficiency
and
decrease
air
emissions.
The
commenter
also
stated
that
however,
industrial
units
should
be
given
the
opportunity
to
voluntarily
opt­
in
to
the
benefits
of
the
cap­
and­
trade
program.
The
commenter
stated
that
any
opt­
in
provision
should
be
drafted
to
5­
95
encourage
participation
and
recognize
cost­
effective
emission
reductions
tailored
to
the
unique
attributes
of
manufacturing
facilities.

Response:

As
already
discussed
in
responses
above,
EPA
maintains
that
certain
cogeneration
units
should
be
included
in
the
CAMR
program
and
that
opt­
in
will
not
be
allowed.

5.6
STATE
EMISSION
BUDGETS
5.6.1
Coal
Adjustment
Factors
Comment:

Many
commenters
(
OAR­
2002­
0056­
1803,
­
2721,
­
2830,
­
2915,
­
3440,
­
3463,
­
3469,
­
3478,
­
3515,
­
3565,
­
4191,
­
4891)
supported
the
proposed
allocation
ratios
of
1,
1.25
and
3
for
bituminous,
sub­
bituminous
and
lignite
coals.
One
commenter
(
4891)
stated
that
the
proposed
ratios
should
be
adopted
to
apply
to
both
the
interim
and
Phase
II
caps.
Several
commenters
(
OAR­
2002­
0056­
2915,
­
3440,
­
3463,
­
3478)
noted
that
lignite
units
receive
a
3:
1
heat
input
based
allocation
of
allowances
with
respect
to
bituminous
units.
This
ratio
is
to
account
for
the
higher
mercury
content
and
lower
energy
content
in
lignite
versus
other
coal
types.
The
commenters
stated
that
such
an
allocation
is
critical
to
the
continued
use
of
lignite
given
its
higher
mercury
content
with
a
higher
elemental
content
that
is
harder
to
control,
its
lower
heat
content
and
the
current
lack
of
demonstrated
mercury
control
technology
for
lignite
coals.
One
commenter
(
OAR­
2002­
0056­
3478)
also
stated
that
these
baseline
adjustment
ratios
were
agreed
upon
by
the
industry
in
the
Clear
Skies
Initiative
negotiations.

One
commenter
(
OAR­
2002­
0056­
3478)
added
that
not
only
does
the
higher
mercury
content,
mercury
speciation,
lower
heat
content
and
lack
of
demonstrated
mercury
control
technology
for
lignite
support
at
least
an
adjustment
factor
of
3
(
with
sub­
bituminous
held
at
1.25),
but
the
variability
in
the
existing
data
supports
this
as
well.
According
to
the
commenter,
in
the
preamble
to
this
proposed
rule,
EPA
stated:
"
Variability
is
inherent
whenever
measurements
are
made
or
whenever
mechanical
processes
operate.
Variability
in
emission
test
data
may
arise
from
one
or
more
of
the
following
areas:
(
1)
The
emission
test
method(
s);
(
2)
the
analytical
method(
s);
(
3)
the
design
of
the
unit
and
control
device(
s);
(
4)
the
operation
of
the
unit
and
control
device(
s);
(
5)
the
amount
of
the
constituent
being
tested
in
the
fuel;
and,
(
6)
composition
of
the
constituents
in
the
fuel
and/
or
stack
gases."
The
commenter
also
stated
that
these
baseline
adjustment
ratios
were
agreed
upon
by
the
industry
in
the
Clear
Skies
Initiative
negotiations.

The
commenter
believed
that
although
the
EPA
made
these
comments
in
regards
to
setting
the
Maximum
Achievable
Control
Technology
(
MACT)
standard,
it
also
would
apply
to
setting
an
appropriate
cap
for
mercury
in
a
cap
and
trade
system.
The
commenter
has
noticed
in
reviewing
the
1999
Information
Collection
Request
(
ICR)
data,
considerable
variability
in
all
these
parameters,
especially
with
lignite.
According
to
the
commenter,
ICR
Part
III
test
runs
across
the
scrubber
on
Monticello
Unit
3
indicated
that
mercury
increased
on
one
run
and
was
5­
96
reduced
by
48
percent
on
another
run.
The
commenter
also
stated
that
the
tests
on
both
Big
Brown
Unit
1
and
Monticello
Unit
1
both
indicated
that
mercury
was
increasing
across
the
baghouse.
The
commenter
stated
that,
therefore,
there
was
a
great
deal
of
variability
in
the
stack
test
method
at
their
plants.
The
commenter
has
seen
variability
not
only
in
the
mercury
content
of
the
coal
from
mine
to
mine,
but
also
seam
to
seam
and
even
noticed
seasonal
variability.
The
commenter
could
not
explain
whether
the
seasonal
variability
was
an
actual
phenomenon
or
some
type
of
laboratory
analysis
difference.
According
to
the
commenter,
the
lignite
mercury
analysis
performed
for
Part
II
of
EPA's
1999
Information
Collection
Request
showed
the
same
seasonal
trend
for
the
samples
from
all
four
plants.

Several
Texas
State
representatives
and
local
officials
(
OAR­
2002­
0056­
2119,
­
2204,
­
2221,
­
2228,
­
2232,
­
2356,
­
2428)
endorsed
the
cap
and
trade
approach
and
supported
the
allocations
for
lignite.

Several
of
the
commenters
(
OAR­
2002­
0056­
2830,
­
3469)
requested
that
any
adjustment
to
the
proposed
factors
which
might
occur
during
the
rulemaking
process
not
reduce
the
allocations
to
lignite
and
thus
disadvantage
it
in
the
market.

One
commenter
(
OAR­
2002­
0056­
2331)
opposed
EPA's
proposal
to
use
the
maximum
achievable
control
technology
(
MACT)
emission
rate
criteria
for
different
grades
of
coal
as
the
basis
for
allocating
Mercury
allowances.
The
commenter
recommended
that
the
EPA
adopt
the
CAA
section
111
approach
and
maintain
the
compromise
criteria
of
the
December
15,
2003
proposal
that
were
based
on
baseline
heat
input
and
adjustment
factors
for
different
grades
of
coal.
The
commenter
believed
this
would
not
only
be
a
more
equitable
interregional
solution
for
allocating
mercury
allowances
but
would
also
not
result
in
excessive
fuel
switching
from
coal
to
natural
gas.

One
commenter
(
OAR­
2002­
0056­
2634)
would
support
and
prefer
a
well
designed
Cap
and
Trade
program
if
the
allocation
methodology
were
modified
to
achieve
a
more
fair
and
equitable
allowance
distribution
and
thus
reduce
the
number
of
large
winners
and
losers.
In
an
effort
to
achieve
a
more
equitable
mercury
allowance
distribution,
however,
the
commenter
proposed
three
(
3)
allocation
methodology
options.

OPTION
1:
The
commenter
Mercury
Allocation
Methodology
using
unit
specific
1999
Elemental
Mercury
Emissions.

The
commenter
submitted
that
this
methodology
would
achieve
the
major
goals
of:

°
Being
coal
neutral.
Does
not
utilize
any
coal
category
adjustment
factors.

°
Reducing
the
number
of
large
winners
and
losers.

The
commenter
felt
that
the
methodology
proposed
above
utilizing
the
individual
elemental
mercury
emissions
would
be
the
most
equitable
way
of
allocating
mercury
allowances.
5­
97
However,
the
commenter
recognized
that
the
methodology
proposed
in
the
NPR
may
not
be
substantially
modified
without
seeking
additional
comments
from
interested
stakeholders.

Therefore,
the
commenter
proposed
two
alternate
allocation
methodologies
that
would
apply
to
those
units
having
high
(
90
percent
plus)
elemental
mercury
emissions.

OPTION
2:
The
commenter
Mercury
Allocation
Methodology
using
adjusted
HI
factors
for
units
that
have
1999
elemental
mercury
emissions
above
90
percent.

OPTION
3:
The
commenter
Mercury
Allocation
Methodology
using
a
set
aside
of
10
percent
of
the
2010
and
2018
allowances.

The
commenter
stated
that
at
a
minimum,
the
modified
allocation
under
Options
1,
2,
or
3,
or
under
some
other
similar
method,
would
need
to
be
applied
to
units
that
presently
have
Spray
Dryer
Absorbers
(
SDA)
for
SO
2
control
and
Fabric
Filters
for
particulate
control
and
have
mercury
emissions
that
are
above
90
percent
elemental.
The
commenter
believed
that
this
adjustment
for
these
units
would
be
necessary
and
justifiable
because
the
SO
2
control
(
SDA)
is
located
upstream
of
the
Fabric
Filter.
The
commenter
stated
SDA
tends
to
remove
most
of
the
gases
that
would
potentially
oxidize
some
of
the
mercury
to
a
form
to
be
removed
in
the
Fabric
Filter.
The
commenter
stated
further
that
units
whose
emissions
are
above
90
percent
elemental
have
already
achieved
the
maximum
removal
that
these
units
are
capable
of
achieving
without
the
addition
of
advanced
mercury
control
technology.
This
technology
is
envisioned
as
necessary
for
past
2018
compliance,
but
it
is
not
intended
for
the
2010­
2018
period
when
co­
benefits
are
envisioned.

One
commenter
(
OAR­
2002­
0056­
2879)
believed
EPA's
data
are
inadequate
both
quantitatively
and
qualitatively
to
produce
supportable
unit
MACT
emissions
rates
or,
under
a
trading
regime,
supportable
or
equitable
allowance
allocations,
and
has
detailed
those
deficiencies
in
Attachment
A
(
See
docket
item
OAR­
2002­
0056­
2879).

If
EPA
proceeds
with
a
cap
and
trade
option,
one
commenter
(
OAR­
2002­
0056­
2264)
recognized
and
supported
the
need
for
adjustments
in
the
allocations
to
recognize
differences
between
bituminous
and
sub­
bituminous
coals.
The
commenter
believed
that
EPA
should
develop
better
data
and
information
on
which
to
quantify
the
mercury
adjustment
factors.

One
commenter
(
OAR­
2002­
0056­
2944)
believed
the
currently­
proposed
mercury
emission
limits,
along
with
the
similarly­
weighted
allowance
distribution
systems
that
were
proposed,
clearly
look
politically­
derived
to
particularly
favor
some
business
interests
at
the
expense
of
others.
The
commenter
stated
that
the
Environmental
Protection
Agency
should
adamantly
reject
regulatory
schemes
which
so
blatantly
appear
to
sacrifice
the
nation's
health
to
special
interests.

One
commenter
(
OAR­
2002­
0056­
3522)
stated
that
allowances
should
be
allocated
to
sources
in
accordance
with
the
emission
factors
developed
as
a
result
of
WEST
Associates'
analysis
and
described
more
fully
in
the
WEST
Associates'
comments.
However,
the
commenter
5­
98
could
accept
the
allowance
allocation
factors
endorsed
in
the
comments
of
the
Edison
Electric
Institute.

One
commenter
(
OAR­
2002­
0056­
2835)
submitted
that
while
commenter
members
have
varying
viewpoints
on
the
different
possible
methodologies,
all
of
the
commenter's
members
agreed
that
allowances
should
be
allocated
in
a
manner
that
reflects
coal
chemistry,
mercury
variability
in
the
combustion
fuel,
and
mercury
removal
efficiencies
of
available
pollution
control
technologies.

One
of
the
commenters
(
OAR­
2002­
0056­
2725)
stated
that
many
questions
remain
regarding
both
the
impacts
of
various
coal
types
and
the
controls
effective
in
mitigating
each
type's
specific
impacts.
The
commenter
noted
that
the
National
Mining
Association,
recognizing
that
more
data
is
needed
to
fully
answer
these
questions,
is
recommending
that
the
EPA
hold
off
on
assigning
allocations
among
coal
types
until
more
complete
information
can
be
gathered
and
assessed.
The
commenter
believed
this
suggestion
has
real
merit
and
would
be
supportive
of
such
a
measured
approach.

The
commenter
stated
that
should
EPA
determine
that
it
must
go
forward
with
setting
allocations
on
the
front
end
through
its
proposed
mercury
trading
program,
the
commenter
urged
the
Agency
to
assure
that
those
allocations
are
as
equitable
as
possible.
The
commenter
noted
EPA
has
proposed
a
range
of
allocation
options
for
mercury
allowances,
ranging
from
the
allocation
scheme
proposed
in
the
Clear
Skies
Act
(
i.
e.
allocate
in
the
proportion
of
1:
1.25:
3
for
bituminous,
sub­
bituminous
coal
and
lignite)
to
a
scheme
based
on
the
mercury
MACT
proposal.
In
light
of
the
problems
with
controlling
mercury
from
sub­
bituminous
coal,
the
commenter
believed
that
the
Clear
Skies
approach
provides
too
few
allowances
for
Western
sub­
bituminous
coal
and
suggested
that
EPA
find
compromise
allowance
allocation
ratios
that
are
more
consistent
with
the
science
of
mercury
control.

One
commenter
(
OAR­
2002­
0056­
3463)
stated
that
the
EPA
should
allocate
emission
allowances
for
mercury
to
each
affected
unit
directly
in
keeping
with
the
Acid
Rain
Program.
Similarly
one
commenter
(
OAR­
2002­
0056­
2826)
advocated
that
the
cap­
and­
trade
program's
allowance
allotment
be
based
upon
"
heat
input"
 
as
with
the
Subpart
H,
NO
x
credit
program­
and
not
on
rank
of
coal.

One
commenter
(
OAR­
2002­
0056­
2160)
stated
that
a
cap
and
trade
program
should
not
include
fuel
adjustment
factors.

One
commenter
(
OAR­
2002­
0056­
2452)
submitted
that
within
a
section
112
or
section
111
cap­
and­
trade
context,
they
did
not
believe
that
it
is
appropriate
for
EPA
to
adjust
allocations
to
the
states
or
generating
units
based
on
coal­
type
adjustment
factor
(
the
commenter
noted
that
EPA's
currently
proposed
methodology
applies
adjustment
factors
to
coal
unit
baseline
heat
input
data
with
an
adjustment
of
1.0
for
bituminous
coal,
1.25
for
sub­
bituminous
and
3.0
for
lignite).
The
commenter
believed
that
rather,
a
single
allocation
emission
rate
standard,
applied
to
baseline
generating
unit
heat
input
(
without
adjustment
for
coal­
type)
should
be
the
basis
for
state
and
unit
level
allocations.
The
commenter
asserted
that
under
a
cap­
and­
trade
regime,
there
would
be
no
5­
99
need
for
EPA
to
address
differences
in
coal­
types
as
part
of
its
allocation
system.
Units
that
were
harder
to
control
would
have
the
option
to
go
to
the
market
to
support
their
compliance
needs.
The
commenter
submitted
that
a
single
allocation
standard
has
worked
well
for
the
NO
x
SIP
Call
(
e.
g.
0.15
Ib
NO
x/
mmBtu)
and
companies
have
had
the
flexibility
to
choose
the
optimum
mix
of
controls
and
allowance
purchases
for
compliance
at
their
generating
units.
The
commenter
believed
a
single
allocation
standard
would
also
be
more
competitively
neutral
versus
EPA's
proposed
allocation
system
that
effectively
"
subsidizes"
states
and
units
with
lower
rank
coals,
particularly
lignite.
The
commenter
stated
that
it
is
quite
possible
that
as
mercury
control
technology
evolves,
that
cost
effective,
high
removal
efficiency
control
technologies
for
lower
rank
coals
will
be
developed.
The
commenter
pointed
out
that
in
this
case,
EPA's
proposal
to
provide
lower
rank
coals
with
larger
emission
allocations
would
provide
these
units
with
a
windfall
relative
to
higher
rank
coals.
Also,
by
lowering
the
compliance
burden
on
lower
rank
coals,
EPA
would
be
potentially
creating
a
self­
fulfilling
prophecy
where
highly
effective
control
technology
for
lower
rank
coals
would
be
under­
developed
versus
what
would
be
the
case
if
all
units
received
emission
allocations
based
on
the
same
standard.

One
commenter
(
OAR­
2002­
0056­
3431)
stated
that
regulations
for
the
control
of
mercury
from
utilities
must
not
favor
one
coal
type
over
another.
The
commenter
believed
the
cap­
and­
trade
proposal
with
adjustment
factors
for
different
coal
ranks
(
i.
e.,
types)
affecting
allocations
and
the
MACT
proposal
with
different
emissions
standards
for
different
coal
types,
both
inappropriately
favor
particular
coal
types.
The
commenter
stated
that
these
regulations
should
not
unduly
disadvantage
generators
based
upon
their
coal
type
(
i.
e.
bituminous,
sub­
bituminous
and
lignite).
The
commenter
believed
a
regulatory
approach
that
does
not
favor
one
coal
type
over
another
would
be
more
efficient,
cost­
effective
and
equitable.
According
to
the
commenter,
under
the
successful
Acid
Rain
program,
the
allocation
methodology
did
not
favor
one
type
of
coal
over
another
for
sulfur
content,
but
let
the
market
set
demand
for
a
particular
coal.

The
commenter
noted
that
EPA
solicited
comment
on
whether
it
should
use
the
proposed
MACT
emission
rates
proposed
in
the
Notice
of
Proposed
Rulemaking
as
the
basis
for
allocations.
The
commenter
specifically
opposed
this
approach
since
it
would
penalize
plants
that
burn
bituminous
coal
even
more
than
the
allocation
approach
proposed
in
the
rule.
The
commenter
also
stated
that
the
MACT
proposal
would
disadvantage
both
producers
and
users
of
bituminous
coal
and
would
force
the
use
of
non­
bituminous
coal
through
blending.
The
commenter
believed
such
blending
would
favor
Western
coals
over
Eastern
coals
and,
at
a
minimum,
increase
transportation
and
coal
costs
for
those
who
blend.
The
commenter
added
that
blending
of
coals
also
would
result
in
higher
emissions
rates
as
the
proposal
requires
a
monthly
unit­
specific
weighted
mercury
emissions
limit
based
on
the
proportion
of
energy
output
(
in
Btu)
contributed
by
each
coal
type
burned
during
the
compliance
period
and
each
coal
type's
applicable
emissions
limit.
According
to
the
commenter,
as
sub­
bituminous
coal
has
a
higher
emission
rate
under
the
MACT
proposal
than
bituminous
coal,
any
blending
of
sub­
bituminous
coal
with
bituminous
coal
would
result
in
a
higher
emission
rate.

One
commenter
(
OAR­
2002­
0056­
3443)
did
not
support
the
use
of
heat
input
adjustment
multipliers
and
was
against
any
further
tinkering
of
the
multipliers
proposed
by
EPA.
See
69
FR
5­
100
12397
and
12406
(
1.0:
1.25:
3.00).
The
commenter
submitted
that
heat
input
adjustment
factors
would
favor
non­
bituminous
coals
by
allowing
higher
mercury
emissions
per
TBTU.
The
commenter
believed
this
approach
was
not
equitable
nor
environmentally
sound
since
it
would
allow
units
to
have
higher
emissions
based
entirely
on
fuel
choice.
The
commenter
noted
that
previous
EPA
cap
and
trade
programs
did
not
make
such
skewing
adjustments
favoring
one
coal
rank
over
another.
In
fact,
EPA's
Acid
Rain
program
was
designed
to
prevent
the
market
from
bestowing
preferential
treatment
on
a
particular
coal
rank.
The
commenter
believed
EPA's
proposed
factors
were
already
generous
to
non­
bituminous
units
in
accounting
for
the
higher
emissions
of
non­
elemental
mercury
from
bituminous
units.
Pertinently,
the
intermediate
and
final
cap
of
24
and
15
tons
per
year
respectively,
would
require
reductions
from
bituminous
units
not
only
of
most
non­
elemental
mercury
but
also
of
the
elemental
kind.
The
commenter
asserted
that
accordingly,
further
skewing
of
the
ratios
in
favor
of
the
non­
bituminous
units
would
essentially
absolve
these
units
of
any
control
of
elemental
mercury.

One
commenter
(
OAR­
2002­
0056­
3437)
questioned
the
allocation
methodology.
The
commenter
noted
the
baseline
heat
input
would
be
the
average
of
the
3
highest
heat
inputs
during
1998­
2002.
The
was
consistent
with
the
NO
x
trading
program.
The
commenter
also
noted
however,
EPA
proposed
to
adjust
the
heat
input
based
on
the
coal
rank.
This
would
not
be
consistent
with
the
NO
x
or
Acid
Rain
programs.
The
commenter
noted
further
that
EPA
claimed
this
would
level
the
playing
field
based
on
the
different
mercury
removal
efficiencies
with
the
control
used
to
control
PM,
SO
2
and
NO
x.
It
was
not
clear
to
the
commenter
how
this
would
affect
fuel
switching,
control
options,
or
actual
emissions.
The
commenter
submitted
that
EPA
must
provide
information
on
how
allocations
would
be
distributed
using
different
methodologies
so
that
more
detailed
comments
can
be
filed.
Absent
any
comparisons,
the
commenter
believed
emission
rates
should
be
used
to
determine
allocations
and
budgets
that
would
address
any
differences
in
coal
types.

One
commenter
(
OAR­
2002­
0056­
3437)
disagreed
with
the
method
for
calculating
state
and
unit
budgets.
The
commenter
believed
the
rule
should
not
be
structured
to
provide
an
advantage
to
one
type
fuel
over
another.
The
commenter
suggested
EPA
should
do
like
in
the
NO
x
SIP
Call;
use
an
emission
rate
to
determine
allocations
and
budgets.
This
would
avoid
the
need
to
adjust
the
heat
input
.
The
commenter
stated
the
emission
rates
would
address
the
differences
in
the
ability
to
control
mercury
from
different
types
of
coal.

Many
commenters
(
OAR­
2002­
0056­
1854,
­
1969,
­
2067,
­
2160,
­
2180,
­
2375,
­
2519,
­
2535,
­
2560,
­
2597,
­
2634,
­
2661,
­
2718,
­
2725,
­
2835,
­
2850,
­
2861,
­
2862,
­
2867,
­
2879,
­
2895,
­
2897,
­
2900,
­
2903,
­
2918,
­
3406,
­
3521,
­
3537,
­
3546,
­
4132)
requested
changes
in
the
mercury
allocation
adjustment
factors.
Many
of
these
commenters
(
OAR­
2002­
0056­
1969,
­
2375,
­
2519,
­
2560,
­
2597,
­
2661,
­
2718,
­
2725,
­
2850,
­
2862,
­
2867,
­
2897,
­
2903,
­
3198,
­
3521,
­
3546)
supported
a
change
in
EPA's
proposed
mercury
allocation
adjustment
factors
to
1.0
for
bituminous
units,
1.5
for
sub­
bituminous
units
and
3.0
for
lignite
units.
One
of
these
commenters
(
OAR­
2002­
0056­
3546)
submitted
that
allowances
should
be
allocated
in
a
manner
that
reflects
coal
chemistry
and
mercury
variability
between
coals.
The
commenter
noted
that
chlorine
in
coal
plays
a
major
role
in
the
type
of
mercury
that
is
emitted.
Higher
chlorine
levels
result
in
a
greater
percentage
of
oxidized
mercury
and
lower
amounts
of
chlorine
in
coal
result
in
5­
101
more
elemental
mercury.
The
commenter
stated
that
sub­
bituminous
and
western
bituminous
coals
tend
to
be
very
low
in
both
mercury
and
chlorine
content
compared
with
the
concentrations
found
in
eastern
bituminous
coals.
Data
from
the
1999
Information
Collection
Rule
showed
that
western
plants
emit
lower
concentrations
of
total
mercury
than
eastern
plants
and
that
elemental
mercury
is
the
form
of
mercury
primarily
emitted.
The
commenter
noted
that
elemental
mercury
is
the
form
of
mercury
that
is
the
most
difficult
to
control.
Ionic
mercury
can
be
readily
captured
in
existing
particulate
controls
and
flue
gas
desulfurization
systems.
The
commenter
stated
that
EPA's
proposed
mercury
MACT
floor
limit
for
sub­
bituminous
coal
recognizes
the
technical
challenge
of
controlling
elemental
mercury.
However,
according
to
the
commenter,
the
proposed
allocation
adjustment
factors
for
the
various
coal
ranks
did
not
adequately
reflect
the
differences
in
coal
chemistry
and
mercury
variability
between
sub­
bituminous
and
eastern
bituminous
coals.
The
commenter
believed
that
the
proposed
1.25
allocation
adjustment
factor
for
sub­
bituminous
and
western
bituminous
coals
needed
to
be
increased
to
at
least
1.5.

The
commenter
(
OAR­
2002­
0056­
3546)
stated
that
the
proposed
allocation
adjustment
factors
also
do
not
differentiate
between
western
bituminous
coal
and
eastern
bituminous
coal;
both
coal
types
receive
the
same
adjustment
factor.
The
commenter
claimed
that
this
would
treat
EGU's
that
burn
western
bituminous
coal
unfairly
because
the
physical,
chemical
and
emission
characteristics
of
western
bituminous
coals
are
substantially
more
similar
to
western
bituminous
coal
than
eastern
bituminous
coal.
The
commenter
submitted
there
are
often
times
subtle
differences
between
the
physical
properties
of
western
bituminous
and
sub­
bituminous
coals.
While
these
physical
tests
determine
whether
a
coal
is
bituminous
or
sub­
bituminous,
it
does
not
reflect
that
both
ranks
of
western
coal
have
low
mercury
and
chlorine
concentrations,
and
thus
similar
mercury
emission
characteristics.
The
commenter
supported
an
adjustment
to
the
coal
rank
multiplies
that
would
combine
western
bituminous
coal
with
sub­
bituminous
coal.

Another
of
the
commenters
(
OAR­
2002­
0056­
2850)
noted
EPA
is
suggesting
a
1.0,
1.25
and
3.0
relative
allocation
of
mercury
allowances
to
bituminous,
sub­
bituminous
and
lignite
coals
respectively,
based
on
heat
input.
The
commenter
stated
that,
in
effect,
sub­
bituminous
coal
units
incur
a
relatively
more
aggressive
control
requirement
than
would
be
applied
under
the
EPA
proposed
MACT
levels
and
it
would
be
expected
that
utilities
burning
sub­
bituminous
coals
would
find
it
most
economic
to
buy
credits
from
bituminous
coal
units
that
face
lower
mercury
compliance
costs.
According
to
the
commenter,
a
ratio
for
allocation
of
1,
1.5
and
3
would
be
more
equitable
and
should
be
considered
by
EPA
as
an
alternative.

One
of
the
commenters
(
OAR­
2002­
0056­
3537)
stated
that
although
there
are
no
commercially
available
control
technologies
specifically
designed
today
for
reducing
mercury
emissions
and
monitoring
data
from
Utility
Units
of
mercury
emissions
is
sparse,
there
is
some
available
data.
The
commenter
noted
that
such
data
indicates
that
the
three
types
of
mercury
emitted
in
flue
gas
 
particulate,
ionic
and
elemental
 
vary
according
to
the
three
most
common
ranks
of
coal
 
bituminous,
sub­
bituminous
and
lignite
being
combusted
in
the
Utility
Unit.
The
commenter
also
noted
that
generally
speaking,
the
lower
the
coal
rank,
from
bituminous
to
sub­
bituminous
to
lignite
coals,
the
more
difficult
it
is
to
control
mercury.
The
commenter
stated
that
differences
in
elemental
constituents
in
coal
is
just
one
variable
affecting
the
ability
to
control
mercury
emissions,
since
mercury
speciation
dictates
the
level
of
control
that
can
be
achieved
5­
102
using
existing
air
pollution
control
equipment.
The
relationship
between
coal
chemistry
and
mercury
speciation
is
not
totally
understood.
The
commenter
pointed
out
it
is
known,
however,
that
chloride
content,
sulfur
content
and
ash
characteristics
can
all
affect
mercury
speciation.
In
conclusion,
the
commenter
stated
that
conventional
pollution
control
technologies
will
be
least
effective
on
units
combusting
lignite
and
most
effective
on
those
that
burn
bituminous
coals,
with
sub­
bituminous
units
falling
somewhere
between
the
other
two
coal
ranks.

The
commenter
(
OAR­
2002­
0056­
3537)
stated
therefore,
any
cap
and
trade
program
which
uses
heat
input
as
the
basis
for
allocation
must,
to
be
equitable,
contain
adjustment
factors
to
account
for
the
varying
coal
ranks
that
will
be
combusted
across
the
industry,
and
the
associated
differences
between
coal
ranks
related
to
the
difficulty
in
controlling
mercury
emissions.
The
commenter
noted
that
EPA
proposed
heat
input
adjustment
factors
of
1.0
for
bituminous
units,
1.25
for
sub­
bituminous
units
and
3.0
for
lignite
Utility
Units.
The
commenter
believed
that
the
heat
input
factor
for
sub­
bituminous
coal
is
too
low
relative
to
the
other
coal
ranks
and
should
be
increased
to
1.50,
which,
based
on
the
available
data,
would
better
represent
the
relative
difficulties
of
controlling
mercury
emissions
from
the
three
coal
ranks.

One
of
the
commenters
(
OAR­
2002­
0056­
2375)
stated
that
the
method
of
allocating
mercury
trading
credits
among
affected
sources
can
be
established
in
a
manner
that
would
provide
protections
against
potential
fuel­
switching
or
creating
an
unequal
playing
field
between
subcategories
of
coal
users.
Studies
by
WEST
Associates
(
WEST)
and
the
commenter
showed
that
the
multiplier
for
sub­
bituminous
units
should
be
at
least
1.5
to
account
for
the
difficulty
of
controlling
mercury
emissions
from
western
coal.
The
commenter
submitted
that
the
vast
majority
of
coal­
fired
generators
in
the
U.
S.
have
agreed
to
compromise
multipliers
of
1.0,
1.5,
and
3.0
for
bituminous,
sub­
bituminous,
and
lignite,
respectively.
The
commenter
supported
these
multipliers
both
as
representing
a
reasonable
compromise
and
as
having
a
sound
technical
basis,
although
a
higher
multiplier
for
sub­
bituminous
could
be
justified
based
on
the
available
data.

One
of
the
commenters
(
OAR­
2002­
0056­
2519)
noted
that
WEST
Associates,
of
which
the
commenter
is
a
member,
was
submitting
detailed
comments
on
several
issues
associated
with
the
C
&
T
program,
and
the
commenter
endorsed
those
comments
by
reference.
Specifically,
those
issues
relate
to
the
multipliers
used
for
different
coal
types
in
calculating
the
allowance
allocations.

Another
of
the
commenters
(
OAR­
2002­
0056­
1969)
expressed
concern
that
EPA's
proposed
coal
heat
input
adjustment
factors
of
1.0
for
bituminous
coal,
1.25
for
sub­
bituminous
coal,
and
3.0
for
lignite
are
not
equitable
for
the
purpose
of
allocating
future
mercury
allowances.
According
to
the
commenter,
EPA
has
not
adequately
considered
the
fuel­
specific
impacts
of
the
co­
benefit
level
mercury
emissions
reductions.
The
commenter
believed
that
as
a
result,
allowances
would
not
be
equitably
allocated
among
the
coal
ranks.
The
commenter
stated
that
specifically,
the
optimum
level
of
co­
benefits
would
occur
when
all
particulate
and
oxidized
mercury
have
been
removed
from
the
flue
gas
with
only
elemental
mercury
remaining.
According
to
the
commenter,
Table
1
(
see
docket)
estimated
the
elemental
portion
of
each
coal
rank
based
on
the
1999
ICR
data.
Table
2
(
see
docket)
projected
the
annual
emissions
in
tons
per
year
on
5­
103
the
basis
of
EPA's
proposed
1:
1.25:
3
coal
heat
input
adjustment
factors.
The
commenter
noted
that
the
relative
margin
between
the
ICR
­
based
1999
mercury
emission
and
the
EPA
proposal
was
considerably
smaller
for
sub­
bituminous
coal
as
compared
to
the
other
fuels.
The
commenter
asserted
that
more
equitable
heat
input
adjustment
factors
would
be
1.0
for
bituminous,
1.5
for
sub­
bituminous
and
3.0
for
lignite
(
See
Table
3
in
docket).

One
of
the
commenters
(
OAR­
2002­
0056­
2661)
stated
there
is
an
understood
industry­
wide
and
regulatory
concern
that
sub­
bituminous
coal
users
are
at
a
disadvantage
to
meet
mercury
reduction
requirements
because
of
the
unique
coal
chemistry
involved
in
burning
this
fuel
type.
The
commenter
submitted
this
inherent
difference
should
be
reflected
in
the
heat
input
adjustment
factor
or
multiplier
for
subbituminous
coal
ranks.
As
proposed,
the
commenter
supported
a
1.5
or
higher
adjustment
factor
for
users
of
the
differing
coal
types,
specifically
for
sub­
bituminous
coals.
The
commenter
agreed
with
EPA's
assertion
that
the
same
percentage
of
non­
elemental
mercury
first
be
reduced
at
a
proportional
rate
across
the
board
between
the
variety
of
coal
ranks.

Another
of
the
commenters
(
OAR­
2002­
0056­
2718)
supported
The
Allocation
Of
Mercury
Allowances
Based
On
Reasonable
Multipliers.
The
commenter
agreed
with
industry
consensus,
with
some
refinements
given
the
commenter's
unique
situation,
that
for
Phases
I
and
II,
the
multipliers
that
most
appropriately
reflect
the
mercury
reductions
that
would
be
achieved
as
co­
benefits
of
CAIR
NO
x
and
SO
2
reductions
are
1.0,
1.5
and
3.0
for
bituminous,
sub­
bituminous
and
lignite,
respectively.
For
Phase
III,
no
multipliers
 
or,
put
differently,
multipliers
of
1.0,
1.0,
and
1.0
 
would
be
appropriate.
Given
that
mercury
reductions
are
a
nationwide,
rather
than
regional,
concern,
the
commenter
believed
that
EPA's
final
rule
should
equitably
distribute
the
burden
of
mercury
reductions
among
regulated
utilities
and
coal
producers
nationwide.

Another
of
the
commenters
(
OAR­
2002­
0056­
2560)
stated
that
at
an
absolute
minimum
the
commenter
supported
a
1.5
or
higher
heat
input
adjustment
factor
for
boilers
burning
sub­
bituminous
coals
as
compared
to
bituminous
coals.
The
commenter
added
that
where
sub­
bituminous
and
bituminous
coals
are
blended
for
firing,
the
heat
input
adjustment
factor
should
reflect
the
percent
of
blend.

Another
of
the
commenters
(
OAR­
2002­
0056­
2903)
stated
that
mercury
trading
credits
should
be
allocated
among
affected
sources
in
a
manner
that
recognizes
the
differences
in
control
opportunities
and
costs
among
coal
types
and
preserves
fuel
diversity,
yet
avoids
unintended
fuel
switching
and,
when
all
factors
are
considered,
still
preserves
a
balance
among
subcategories
of
coal
users.
The
commenter
believed
that
the
appropriate
multipliers,
taking
such
considerations
into
account,
should
be
1.0
for
bituminous,
1.5
for
sub­
bituminous
and
3.0
for
lignite.
The
commenter
noted
that
the
majority
of
coal­
fired
generators
in
the
U.
S.
have
now
agreed
to
support
such
multipliers.

One
of
the
commenters
(
OAR­
2002­
0056­
2597)
noted
that
a
major
issue
embedded
in
the
model
cap­
and­
trade
program
concerns
how
mercury
allowances
would
be
allocated
among
the
different
subcategories
of
coal
types.
The
commenter
stated
that
in
order
for
the
model
program
to
work
most
efficiently
and
cost­
effectively,
it
is
critical
that
no
coal
type
is
unduly
disadvantaged
5­
104
based
on
the
allowance
allocation
scheme
adopted
by
EPA.
The
commenter
believed
the
most
equitable
allocation
method
uses
adjustment
factors
of
1.0
for
bituminous,
1.5
for
sub­
bituminous
and
3.0
for
lignite.

One
commenter
(
OAR­
2002­
0056­
2895)
stated
that
while
the
proposed
allowance
allocation
factors
do
reflect
the
difficulty
in
controlling
for
mercury
amongst
the
different
coal
ranks,
the
commenter
believed
that
the
proposed
factors
of
1.0
for
bituminous
coal,
1.25
for
sub­
bituminous
coal,
and
3.0
for
lignite
need
to
be
revised.
The
commenter
believed
that
the
multipliers
developed
by
WEST
Associates
based
on
its
technical
analysis
of
coal
chemistry
and
mercury
variability
between
coals
are
more
reflective
of
the
difficulty
in
controlling
for
mercury
amongst
the
different
coal
ranks.
These
multipliers
are
1.0
for
bituminous
coal,
1.8
for
sub­
bituminous
coal,
and
3.6
for
lignite.
The
commenter
was
also
aware
that
a
large
number
of
companies
in
the
industry
were
supporting
adjustment
factors
of
1.0
for
bituminous
coal,
1.5
for
sub­
bituminous
coal,
and
3.0
for
lignite.
If
the
WEST
Associate
numbers
are
not
selected
as
the
multipliers
in
the
final
rule,
the
commenter
recommended
the
use
of
the
aforementioned
multipliers
(
1.0,
1.5,
3.0)
supported
by
much
of
the
industry.

One
commenter
(
OAR­
2002­
0056­
2835)
supported
minor
adjustments
to
allocation
methodology
for
mercury
allowances
based
on
type
of
fuel
burned.
The
commenter
agreed
with
EPA's
decision
to
allocate
mercury
allowances
based
on
the
ability
to
control
mercury
from
the
three
major
types
of
coal:
bituminous,
sub
bituminous,
and
lignite.
Furthermore,
the
commenter
believed
that
the
adjustment
factors
selected
for
the
mercury
allocations
should
represent
an
equitable
sharing
of
the
burden
among
coal
types
to
achieve
the
required
mercury
reductions.
The
specific
mercury
allocation
position
outlined
below
reflected
a
compromise
position
among
the
commenter
members,
which
collectively
have
burned
a
diverse
mix
of
coal
types
including
eastern
and
western
bituminous
and
sub­
bituminous
coals
and
lignite.

The
commenter
stated
that
initial
mercury
reductions
would
be
achieved
through
the
imposition
of
the
SO
2
and
NO
x
controls
required
by
the
CAIR.
These
reductions
are
referred
to
as
mercury
co­
benefit
reductions.
The
commenter
also
stated
however,
additional
reductions
would
be
required
beyond
projected
mercury
co­
benefit
levels,
particularly
during
the
later
years
of
the
mercury
control
program.
The
commenter
submitted
this
additional
mercury
reduction
burden
for
each
coal
type
could
be
measured
in
several
ways.
These
included
percent
reduction
(
pounds
reduced
divided
by
current
pounds
emitted
for
each
coal
type),
equal
reduction
on
a
Btu
basis
(
pounds
reduced
divided
by
total
coal
type
Btu),
or
cost
of
required
reductions
on
a
Btu
basis
(
dollar
cost
of
reductions
divided
by
total
coal
type
Btu).

The
commenter
believed
costs
on
a
Btu­
basis
may
be
the
best
measure
of
the
"
fairness"
of
a
given
set
of
allocation
factors.
The
commenter
has
examined
the
range
of
removal
costs
for
the
various
coal
types.
The
commenter's
analysis
indicated
that
existing
pollution
control
technologies
can,
on
average,
achieve
the
following
$/
pound
removal
rates:
$
20,000/
pound
for
lignite,
$
25­$
30,000/
pound
for
bituminous,
and
$
30­$
40,000/
pound
for
sub­
bituminous.
Another
relevant
factor
examined
by
the
commenter
was
the
incremental
mercury
reductions
estimated
to
be
necessary
after
mercury
co­
benefit
reductions
have
been
achieved
through
implementation
of
5­
105
the
CAIR
controls.
Finally,
the
commenter
considered
variations
in
the
form
of
mercury
and
level
within
each
coal
type
as
well
as
the
National
Energy
Technology
Lab's
data
on
coal
use
by
type.

The
commenter
noted
that
the
considerations
noted
above
indicated
that
the
proposed
allocation
factors
of
1.0
(
bituminous),
1.25
(
sub­
bituminous),
and
3.0
(
lignite),
although
directionally
sound,
fall
far
short
of
equitably
allocating
the
mercury
control
obligation
among
coal
types.
Among
other
things,
EPA's
proposed
factors
failed
to
reflect
adequately
the
difficulty
in
removing
elemental
mercury
from
those
units
burning
sub­
bituminous
coal
and
over­
allocate
mercury
allowances
to
those
units
burning
lignite.
The
commenter
submitted
furthermore,
these
considerations
noted
above
weighed
in
favor
of
EPA
making
the
following
changes
in
the
proposed
mercury
adjustment
factors.
The
commenter
believed
that
adjustment
factors
should
represent
an
equitable
sharing
of
the
burden
among
coal
types
for
necessary
mercury
reductions
when
the
cost
of
required
reductions
on
a
Btu­
basis
is
evaluated
for
each
coal
type.
The
commenter
stated
that
these
factors
would
not
achieve
equality
among
the
coal
types
with
respect
to
cost
per
Btu,
but
would
be
much
more
equitable
than
the
proposed
factors.
The
commenter
believed
that
these
allocation
factors
should
be
used
for
each
phase
of
a
cap­
and­
trade
program:

Coal
Type
Proposed
Adjustment
Factor
Revised
Adjustment
Factor
Bituminous
1
1
Sub­
Bituminous
1.25
1.5
Lignite
3
2.5
Several
commenters
(
OAR­
2002­
0056­
2898,
­
2907)
supported
allowance
adjustment
factors
as
proposed
by
WEST
Associates
in
Table
2
of
WEST's
multivariable
analysis.
The
commenters
stated
these
allocation
factors
are:
Bituminous
1.0;
Sub­
bituminous
1.8;
and
Lignite
3.6.
One
of
the
commenters
(
OAR­
2002­
0056­
2907)
stated
they
supported
these
allocation
factors
in
light
of
the
difficulty
associated
with
controlling
sub­
bituminous
coal.
The
commenter
believed
these
allocation
factors
would
be
more
consistent
with
the
science
of
mercury
and
control
technology.

One
commentor
(
OAR­
2002­
0056­
2180)
noted
that
the
proposed
allowance
adjustment
factors
for
determining
allowance
allocations
to
units
are
1.0
for
bituminous
coal,
1.25
for
sub­
bituminous
coal,
and
3.0
for
lignite,
and
that
these
factors
appeared
to
originate
from
the
proposed
Clear
Skies
legislation.
The
commenter
stated
that,
however,
the
adjustment
factors
in
the
proposed
legislation
have
not
been
scrutinized
for
scientific
accuracy.
The
commenter
noted
that
the
proposed
rule's
preamble
states
that
the
proposed
adjustment
factors
"
are
considered
to
be
directionally
correct
based
on
test
data
currently
available"
and
the
factors
"
are
intended
to
equitably
distribute
allowances
to
the
affected
industry."
The
commenter
stated
that,
however,
there
is
no
information
in
either
the
rule's
preamble
or
in
the
mercury
rulemaking
docket
that
scientifically
justifies
the
proposed
adjustment
factors.
The
commenter
noted
that
the
preamble
indicates
that
EPA
may
apportion
allowances
based
on
proposed
MACT
emission
limits.
According
to
the
commenter,
the
proposed
MACT
emission
limits
suggested
that
the
5­
106
sub­
bituminous
allowance
adjustment
factor
is
set
too
low.
The
commenter
stated
that
the
ratio
of
the
sub­
bituminous
proposed
MACT
limit
to
the
bituminous
proposed
MACT
limit
was
2.9,
while
the
ratio
of
the
sub­
bituminous
to
the
bituminous
proposed
adjustment
factors
was
only
1.25.
According
to
the
commenter,
the
apportionment
process
based
on
MACT
limits
could
be
a
step
in
the
right
direction,
as
MACT
limits
in
the
proposal
are
based
on
coal
subcategories
reflecting
coal
rank,
and
the
proposed
MACT
limits
are
based
on
EPA's
analysis
of
data.
The
commenter
stated
that,
however,
without
knowing
what
the
final
MACT
limits
would
be,
how
the
limits
were
scientifically
justified,
and
how
the
limits
would
be
translated
into
the
equivalent
adjustment
factors
for
allocating
allowances,
it
would
not
be
possible
to
specifically
support
the
proposed
alternate
apportionment
approach
at
this
time.
The
commenter's
coal
capacity
consisted
of
about
two­
thirds
sub­
bituminous
and
one­
third
bituminous
coal.
Therefore,
the
commenter
had
a
direct
interest
in
having
appropriate
and
scientifically
justified
adjustment
factors
reflecting
the
various
coal
ranks.
The
commenter
asserted
that
the
final
mercury
trading
rule
should
include
a
complete
scientific
analysis
and
explanation
of
the
final
adjustment
factors
that
are
adopted.
The
commenter
offered
that
one
alternative
to
consider
would
be
to
set
adjustment
factors
based
on
the
ratio
of
remaining
emission
levels
for
each
coal
type
after
application
of
co­
benefit
controls.
According
to
the
commenter,
remaining
emission
levels
for
this
purpose
would
consist
of
elemental
mercury
emissions
(
assuming
minimal
emission
reduction
with
co­
benefit
controls)
plus
non­
elemental
mercury
emissions
(
representing
the
percentage
of
non­
elemental
mercury
not
captured
by
co­
benefit
controls).

One
commenter
(
OAR­
2002­
0056­
4132)
cautioned
that
EPA
should
be
careful
not
to
manipulate
mercury
allowances
to
simulate
a
technology­
based
standard.
The
commenter
noted
that
EPA
has
garnered
significant
praise
over
the
economic
successes
of
cap
and
trade
programs
implemented
relative
to
SO
2
and
NO
x.
Critical
to
the
success
of
these
programs
was
the
fact
that
there
were
strong
economic
incentives
for
all
affected
emitters
to
develop
a
low­
cost
solution
to
reducing
their
emissions.

The
commenter
noted
that
in
these
proposals
EPA
is
considering
an
unusual
allocation
of
mercury
allowances
at
paragraph
60.4142.
Sub­
bituminous
coal
users
may
receive
25
percent
more
mercury
allowances
per
mmBtu
than
bituminous
coal
users.
Lignite
coal
users
may
receive
200
percent
more
mercury
allowances
per
mmBtu
than
bituminous
users.
(
The
mechanism
for
this
unusual
allocation
are
coal­
specific
annual
heat
input
multipliers
1.0,
1.25,
and
3.0).
The
commenter
believed
this
artificial
manipulation
of
a
cap
and
trade
program
had
the
potential
to
create
several
adverse
outcomes:

°
It
appeared
to
provide
special
subsidies
to
the
coals
that
emit
the
highest
amount
of
mercury
per
mmBtu.

°
It
allocated
large
lignite
and
sub­
bituminous
coal
users
mercury
allowances
equal
to
or
exceeding
their
current
mercury
emissions.
As
a
result
they
would
have
little
incentive
to
make
capital
improvements
to
reduce
mercury
emissions.
Theoretically,
they
may
backslide
and
emit
more
mercury
in
the
future
than
in
the
base
year.
5­
107
°
Bituminous
coal
users
were
essentially
shorted
in
their
allocations
of
mercury
allowances.
This
would
cause
higher
levels
of
mercury
control
with
higher
incremental
control
costs
than
would
possibly
be
experienced
in
the
traditional,
unmanipulated
allocation
program.

°
The
allocation
of
mercury
allowances
to
the
sub­
bituminous
and
lignite
coal
users
would
have
the
potential
to
incentives
use
of
these
types
of
coal.
This
would
not
be
a
desirable
outcome,
since
mercury
emissions
from
these
coal
types
do
not
respond
well
to
existing
air
pollution
controls.

The
commenter
stated
that
the
remedy
for
the
above
outcomes
would
be
to
do
away
with
the
use
of
any
"
annual
heat
input
multipliers."
The
commenter
suggested
that
alternatively
the
annual
heat
input
multipliers
should
be
reduced
in
magnitude
and
at
the
very
least,
they
should
not
be
made
larger.

One
commenter
(
OAR­
2002­
0056­
2897)
stated
that
any
cap­
and­
trade
approach
must
include
allocation
factors
that
address
the
need
for
subcategorization.
The
commenter
believed
the
factors
proposed
by
the
EPA
(
1.0
for
bituminous,
1.25
for
subbituminous
and
3.0
for
lignite)
did
not
adequately
address
this
issue.
The
commenter
stated
that
these
factors
were
based
on
EPA's
analysis
of
the
ICR
data,
which
has
been
shown
to
be
inappropriate
for
any
regulatory
purpose.
According
to
the
commenter,
even
the
EPA
states
that
these
factors
are
only
"
directionally
correct",
this
was
a
completely
inadequate
basis
for
setting
a
regulatory
standard.
The
commenter
urged
the
EPA
to
thoroughly
reassess
the
proposed
allocation
factors.

The
commenter
pointed
out
as
the
first
phase
reduction
targets
were
based
on
EPA's
estimates
of
actual
reductions
achieved
through
co­
benefits
and
as
it
was
widely
acknowledged
that
sub­
bituminous
coals
obtain
lower
co­
benefit
reductions
than
bituminous
coals
it
would
be
essential
that
the
EPA
adopt
appropriate
allocation
factors.
The
commenter
stated
that
without
appropriate
allocation
factors
sub­
bituminous
users
who
could
not
achieve
significant
co­
benefit
reductions
would
be
forced
to
buy
allowances
from
bituminous
users
who
can.
According
to
the
commenter,
this
would
obviously
result
in
wealth
transfer
from
users
of
sub­
bituminous
to
users
of
bituminous
coals
and
promote
fuel
switching.
The
commenter
asserted
that
claims
that
the
incorporation
of
any
allocation
factors
will
result
in
wealth
transfer
from
bituminous
users
to
sub­
bituminous
users
were
clearly
false
and
ignored
the
reality
of
lower
co­
benefit
reductions
for
sub­
bituminous
coals.

The
commenter
noted
that
other
industry
commentators
are
proposing
factors
of
1.0
for
bituminous,
1.5
for
sub­
bituminous
and
3.0
for
lignite
based
upon
the
relative
proportions
of
elemental
mercury
produced
by
the
three
different
coal
ranks.
The
commenter
believed
given
the
limitations
in
the
ICR
database,
basing
the
factors
on
the
relative
proportions
of
elemental
mercury
would
likely
be
a
more
robust
approach.
According
to
the
commenter,
because
the
amount
of
elemental
mercury
produced
effectively
reflects
the
difficulty
of
control,
these
factors
are,
in
the
long
term,
more
likely
to
result
in
an
even
distribution
of
the
compliance
burden
between
coal
ranks.
The
commenter
stated
that,
however,
because
plant
configuration
also
affects
mercury
capture
and
as
sub­
bituminous
coal
is
typically
burned
in
plant
configurations
that
produce
little
co­
benefit
capture,
e.
g.
plants
with
dry
scrubbers,
a
sub­
bituminous
factor
based
5­
108
purely
on
elemental
mercury
content
will
be
inadequate
to
avoid
fuel
switching.
The
commenter
asserted
that
in
order
to
account
for
differences
in
plant
configuration
allocation
factors
of
1.0
for
bituminous,
1.9
for
sub­
bituminous
and
2.95
for
lignite,
as
proposed
by
the
industry
majority
during
the
CAAAC
process,
appear
to
be
the
most
appropriate.
The
commenter
stated
that
these
factors
have
been
calculated
from
the
floors
developed
by
industry
majority
consensus
position,
which
included
representatives
from
the
unions,
all
major
coal
producing
regions
and
a
large
proportion
of
the
electric
utility
industry.

One
commenter
(
OAR­
2002­
0056­
2634)
noted
that
the
adjustment
factors
are
supposed
to
account
for
the
difference
in
coal
chemistry
among
the
different
types
of
coal
ranks.
The
commenter
pointed
out
that
some
of
the
major
differences
among
coals
is
the
amount
of
elemental
mercury
and
the
chlorine
content.

According
to
the
commenter,
bituminous
coals
are
generally
high
in
chlorine
content
which
tends
to
oxidize
the
elemental
mercury
and
thus
facilitate
its
removal
with
add
on
SO
2/
NO
x/
PM
emission
control
equipment.
Sub­
bituminous
coals,
however,
have
little
or
no
chlorine
content
and
thus
mercury
oxidation
is
correspondingly
less.
The
commenter
stated
it
is
much
more
difficult
to
remove
the
elemental
portion
of
the
mercury
in
flue
gas
for
sub­
bituminous
coals
regardless
of
control
technology,
including
the
addition
of
activated
carbon
which
is
the
most
promising
technology
but
is
yet
unproven.
The
commenter
submitted
that
because
sub­
bituminous
coals
typically
have
a
much
higher
percentage
of
elemental
mercury,
the
adjustment
factors
should
proportionally
provide
sub­
bituminous
coal
users
with
a
higher
allocation.

The
commenter
stated
that
given
this
fact,
it
follows
that
the
adjustment
factor
for
sub­
bituminous
coal
should
be
considerably
higher
than
what
is
proposed
in
the
NPR.
The
commenter
believed
the
ratio
that
would
result
from
the
proposed
MACT
floor
contained
in
the
section
112
MACT
portion
of
the
NPR
appeared
to
be
the
most
reasonable.
These
factors
would
be
1.0
for
bituminous,
2.9
for
subbituminous,
and
4.6
for
lignite.
The
commenter
noted
ICR
III
speciation
data
showed
that
the
average
ratio
of
elemental
mercury
between
sub­
bituminous
and
bituminous
coals
is
2.3.
The
commenter
stated
that
this
analysis
supported
the
2.9
adjustment
factor
for
sub­
bituminous
coals
because
it
demonstrated
and
considered
the
inherent
difficulties
of
controlling
elemental
mercury;
however,
a
multiplier
of
2.3
for
sub­
bituminous
could
be
justifiable
and
defensible.

One
commenter
(
OAR­
2002­
0056­
3406)
noted
that
EPA
proposed
to
allocate
allowances
to
bituminous
coal­
burning
units
on
the
basis
of
1.0
times
their
overall
heat
input,
and
to
sub­
bituminous
units
on
the
basis
of
1.25
times
their
heat
input.
The
commenter
recommended
against
distinguishing
between
bituminous
and
sub­
bituminous
units
for
these
purposes.
In
view
of
the
efforts
underway
to
develop
mercury
control
technologies
for
sub­
bituminous
coal,
and
the
role
of
stringent
standards
in
driving
technology
development,
the
commenter
believed
that
bituminous
and
sub­
bituminous
units
should
be
treated
the
same
for
allocation
purposes.
Similarly,
the
commenter
believed
that
constraint
should
be
exercised
in
applying
adjustment
factors
to
lignite.
5­
109
One
commenter
(
OAR­
2002­
0056­
1854)
believed
that
a
properly
implemented
cap
and
trade
program
could
reduce
the
overall
cost
of
mercury
control
for
coal­
fired
electric
generating
units.
The
commenter
supported
the
cap
and
trade
baseline
heat
input
adjustment
factors
that
are
listed
in
this
proposed
rule
on
page
12445,
i.
e.,
1
for
bituminous,
1.25
for
sub­
bituminous
and
3
for
lignite
coals.
The
commenter
noted
that
these
factors
resulted
from
a
carefully
crafted
agreement
reached
in
the
Clear
Skies
Initiative.
However,
the
commenter
stated
that
with
their
increasing
knowledge
of
the
mercury
content
of
lignite
and
the
inability
to
control
it
with
proven
technology,
they
did
have
concerns
that
a
factor
of
3
for
lignite
may
still
be
very
restrictive.

One
commenter
(
OAR­
2002­
0056­
2067)
stated
that
it
is
dependent
on
Wyoming
Powder
River
Basin
(
PRB)
subbituminous
coal
to
fuel
its
primary
generating
resource.
According
to
the
commenter,
PRB
coal
accounts
for
nearly
40
percent
of
the
coal
used
for
generating
electricity
in
the
United
States.
The
commenter
supported
the
use
of
multipliers
for
the
coal
ranks
based
on
sound
scientific
data
and
noted
that
the
EPA
ICR
data
is
a
starting
point
but
should
not
be
the
exclusive
source
of
such
data.
According
to
the
commenter
data
collected
by
the
Subbituminous
Energy
Coalition
(
SEC),
through
the
Western
Research
Institute
in
Laramie,
Wyoming,
provided
a
more
recent
set
of
test
data
that
should
be
considered.
The
commenter
recommended
that
at
a
minimum,
the
appropriate
multiplier
for
sub­
bituminous
coal
should
be
1.5.

One
commenter
(
OAR­
2002­
0056­
2861)
noted
that
EPA
has
proposed
to
apply
an
adjustment
factor
to
the
baseline
heat
input
used
to
allocate
allowances
depending
on
the
coal
rank
consumed
during
the
baseline
period.
The
commenter
stated
that
the
proposed
factors
of
1.25
for
sub­
bituminous
and
3.0
for
lignite
would
provide
additional
allowances
to
those
coal
ranks,
leaving
fewer
allowances
for
bituminous
coal
users.
The
commenter
submited
that
EPA
has
proposed
those
factors
for
distributing
the
allocations
for
2018
and
presumably
for
2010
as
well.
The
stated
basis
for
the
factors
was
that
boilers
that
burn
sub­
bituminous
or
lignite
coals
presumably
emit
more
mercury
in
the
elemental
form
which
is
more
difficult
to
capture
with
SO
2
and
NO
x
technologies.
The
commenter
believed
that
the
use
of
adjustment
factors
provides
a
significant
advantage
to
sub­
bituminous
and
lignite
coals.
The
commenter
asked
that
EPA
re­
evaluate
the
technical
basis
for
adjustment
factors
and
at
a
minimum
to
reject
any
request
to
make
those
factors
higher
than
what
the
Agency
has
proposed.

The
commenter
did
not
support
the
1.5
adjustment
factor
for
sub­
bituminous
coal
being
proposed
by
UARG
and
the
Edison
Electric
Institute
(
EEI).
The
commenter
claimed
that
neither
UARG
nor
EEI
have
provided
a
sufficient
technical
justification
for
the
higher
factor.
The
commenter
noted
that
those
arguing
for
the
higher
allocation
adjustment
factor
are
assuming
that
sub­
bituminous
coals
will
achieve
no
control
of
elemental
mercury.
The
commenter
believed
that
while
that
assumption
may
be
somewhat
appropriate
if
considering
the
level
of
reduction
associated
with
the
co­
benefits
of
SO
2
and
NO
x
control,
the
analysis
is
entirely
inappropriate
when
considering
allocations
of
mercury
at
either
a
24
ton
or
a
15
ton
cap
level.

The
commenter
submitted
that
in
order
for
the
industry
to
meet
either
a
24
ton
or
15
ton
emissions
cap,
it
would
be
necessary
for
utilities
across
the
nation
to
take
broad
actions
to
install
technologies
that
are
under
development
to
control
both
elemental
and
non­
elemental
mercury,
with
an
overall
80
percent
reduction
requirement
from
the
total
mercury
in
coal.
The
commenter
5­
110
stated
that
the
advanced
technologies
that
are
under
development
are
intended
to
be
applicable
to
a
wide
range
of
coals,
including
bituminous,
sub­
bituminous,
and
lignite.
The
commenter
believed
factors
other
than
coal
rank
may
be
more
important
to
the
ability
to
reduce
mercury
emissions.
For
example,
a
facility
that
is
equipped
with
a
baghouse
may
be
able
to
achieve
substantial
elemental
mercury
reduction
through
use
of
carbon
injection.

The
commenter
claimed
that
even
using
heat
input
alone
to
distribute
either
a
24
ton
or
15
ton
cap
would
provide
a
significant
advantage
to
sub­
bituminous
coal
users.
The
commenter
noted
that
sub­
bituminous
coal
has
the
lowest
average
mercury
content
of
the
coal
ranks,
as
documented
by
EPA
data
from
the
mercury
ICR.
The
commenter
stated
that
using
an
adjustment
factor
of
1.0
(
using
unadjusted
heat
inputs
to
allocate
allowances)
would
actually
provide
nearly
a
50
percent
bonus
to
sub­
bituminous
coals
compared
to
the
allocations
if
all
coal
ranks
were
expected
to
achieve
the
same
percent
reduction.
The
commenter
claimed
that
EPA's
proposed
adjustment
factor
of
1.25
for
sub­
bituminous
coal
amounts
to
an
allocation
windfall
bonus
of
nearly
90
percent.
The
commenter
also
claimed
that
for
lignite
coal,
the
proposed
adjustment
factor
of
3.0
would
be
equivalent
to
an
allocation
windfall
bonus
of
nearly
150
percent.

The
commenter
asserted
that
additional
allocations
for
sub­
bituminous
and
lignite
coal
would
mean
that
bituminous
coal
users
would
be
required
to
make
proportionally
greater
reductions,
or
purchase
more
allowances
than
would
otherwise
be
required.
The
commenter
submitted
that
EPA
has
not
provided
a
technical
basis
to
justify
this
subsidization
of
sub­
bituminous
and
lignite
users
by
bituminous
users,
but
has
simply
declared
that
the
factors
are
"
directionally
correct."
The
commenter
submited
moreover,
EPA
has
not
indicated
why
it
is
necessary
to
give
this
advantage
to
sub­
bituminous
and
lignite
coal
producers
and
to
punish
bituminous
coal
producers.
The
commenter
stated
EPA
must
provide
a
compelling
justification
for
such
economic
policy
choices
and
impacts.
The
commenter
believed
the
fact
that
the
Clear
Skies
legislation
included
adjustment
factors
for
sub­
bituminous
and
lignite
coal
was
not
a
justification
for
EPA
to
include
them
in
a
mercury
rule.
The
commenter
submitted
that
unlike
Congress,
EPA
must
provide
adequate
technical
justification
for
its
rule,
which
in
the
case
of
its
proposed
adjustment
factors
it
has
failed
to
provide.
Without
a
reasonable
technical
basis,
the
commenter
believed
the
adjustment
factors
were
arbitrary
and
should
not
be
used
for
establishing
a
regulatory
control
program.
The
commenter
submitted
that
providing
these
bonus
allocations
would
be
an
energy
and
economic
policy
decision
that
would
provide
an
advantage
for
states
that
have
historically
produced
and/
or
used
certain
coal
supplies.
The
commenter
also
submitted
it
is
not
a
decision
based
on
future
environmental
control
requirements
and
effectiveness.
The
commenter
predicted
the
consequences
for
states
that
have
used
bituminous
coal
exclusively,
and
those
states
engaged
in
the
mining
of
bituminous
coals,
are
millions
of
dollars
for
additional
controls
or
allowance
purchases,
limited
ability
for
development
of
new
coal
facilities
due
to
a
shortage
of
allowances
for
bituminous
users,
and
lost
jobs
and
income
for
industry
and
coal
miners.

While
the
commenter
believed
that
the
use
of
adjustment
factors
would
not
be
warranted,
if
EPA
finalizes
a
cap
and
trade
program
beginning
in
2010
which
includes
adjustment
factors
for
sub
bituminous
and
lignite
coals,
the
commenter
recommended
that
both
adjustment
factors
be
gradually
eliminated
on
a
sliding
scale
through
2018
to
reflect
the
fact
that
advanced
technologies
5­
111
and
the
stringent
cap
will
require
control
of
all
species
of
mercury.
Under
the
alternate
proposal
that
the
commenter
and
UARG
are
recommending
(
co­
benefits
with
no
cap
in
2010,
followed
by
a
two­
phase
cap
and
trade
program
beginning
in
2015),
the
commenter
recommended
no
adjustment
factors
be
included.
In
any
case,
the
commenter
was
not
aware
of
any
credible
analysis
that
would
support
the
adjustment
factors
higher
than
those
that
EPA
has
proposed
as
some
groups
are
advocating,
and
EPA
should
reject
those
suggestions.

One
commenter
(
OAR­
2002­
0056­
2879)
stated
that
allowance
allocations
under
a
trading
program
must
be
done
equitably.
The
commenter
believed
that
an
allowance
allocation
using
the
proposed
MACT
emissions
rates
would
simply
convert
the
form
of
the
advantage
conferred
on
sub­
bituminous
coal
from
coal
switching
to
a
transfer
of
allowances,
with
hundreds
of
millions
of
dollars
flowing
each
year
from
bituminous
coal
users
to
sub­
bituminous
coal
users
in
the
form
of
excess
allowances.
The
EPA
should
propose
a
supportable
and
equitable
allowance
allocation
scheme
that
does
not
overtly
favor
one
coal
rank
over
another.
(
Note
See
detailed
explanation
in
docket
item.)

One
commenter
(
OAR­
2002­
0056­
2535)
believed
that
if
EPA's
proposed
mercury
adjustment
factors
(
1.0;
1.25;
3.0)
were
used
in
conjunction
with
EPA's
assumed
34­
ton
co­
benefit
level
in
2010,
a
corresponding
mercury
emission
limit
could
be
calculated.
Using
the
assumptions
described,
the
corresponding
mercury
emission
limit
would
be
in
the
ballpark
of
2.6
lb
Hg/
TBtu
(
bituminous
coal),
3.2
lb
Hg/
TBtu
(
sub­
bituminous
coal),
and
7.8
lb
Hg/
TBtu
(
lignite
coal).
This
calculation
showed
that
EPA's
proposed
mercury
adjustment
factors
represent
a
dramatically
different
regulatory
scheme
than
that
proposed
under
the
MACT
program
(
2
lb
Hg/
TBtu
(
bituminous
coal),
5.8
lb
Hg/
TBtu
(
sub­
bituminous
coal),
and
9.2
lb
Hg/
TBtu
(
lignite
coal)),
as
there
was
relatively
little
"
subcategorization"
in
the
proposed
adjustment
factors
between
bituminous
and
sub­
bituminous
coal.
The
commenter
pointed
out
there
are
dramatic
differences
between
Wyoming
sub­
bituminous
coal
and
other
sub­
bituminous
coals.
These
differences
include
higher
mercury
content
than
the
EPA's
"
average"
sub­
bituminous
coal
mercury
content
of
5.74
lb
Hg/
TBtu,
and
lower
capture
rates
than
some
other
sub­
bituminous
coals
largely
based
on
the
high
elemental
to
total
mercury
ratio
in
the
coal
(
evidenced
by
the
lack
of
Wyoming
PRB
plants
among
the
top
performing
units).
EPA
stated
in
the
allocation
memorandum
cited
above
that
"
These
adjustment
factors
are
considered
to
be
directionally
correct
based
on
the
test
data
currently
available."
The
commenter
asserted
the
allocation
process
is
critically
important
to
the
coal
industry,
regardless
of
coal
rank.
"
Directionally
correct"
would
not
be
a
sufficient
basis
on
which
to
set
adjustment
factors
that
are
so
crucial
to
understanding
market
implications.
For
this
reason,
the
commenter
would
support
EPA
taking
the
necessary
time
to
determine
the
accuracy
and
validity
of
the
data
prior
to
setting
the
adjustment
factors.
This
approach
would
allow
EPA
to
better
understand
the
current
state
of
control
technology,
and
how
different
coal
ranks
behave
with
that
technology.
If
EPA
opts
not
to
go
this
direction,
then
the
commenter
would
be
forced
to
support
the
mercury
adjustment
factors
based
upon
EPA's
proposed
MACT
emission
floor
numbers
 
those
being
1.0
for
bituminous;
2.9
for
sub­
bituminous;
and
4.6
for
lignite.

One
commenter
(
OAR­
2002­
0056­
3198)
stated
that
any
allocation
factors
must
address
the
need
for
sub­
categorization,
and
the
factors
currently
proposed
by
the
EPA
(
1.0,
1.25
and
5­
112
3.0)
did
not
adequately
address
this
issue.
The
commenter
stated
that
these
factors
were
based
on
EPA's
analysis
of
the
ICR
data
and
would
be
inappropriate
for
any
regulatory
purpose.
The
commenter
pointed
out
that
EPA
stated
that
their
analysis
is
only
"
directionally
correct,"
which
is
an
insufficient
basis
for
setting
a
standard
of
this
significant
importance.
The
commenter
urged
the
EPA
to
thoroughly
reassess
the
proposed
allocation
factors.
The
commenter
asserted
that
there
is
no
rush
to
judgment
in
setting
these
factors,
and
EPA
can
take
the
appropriate
time
to
obtain
and
analyze
the
proper
factors.
Absent
this
process
and
EPA
moves
forward
to
set
the
factors
at
this
time,
the
commenter
believed
that
factors
should
be
set
somewhere
in
the
range
of
the
proposed
EPA
MACT
emission
limits
for
mercury.

One
commenter
(
OAR­
2002­
0056­
2918)
asserted
the
rulemaking
must
take
into
consideration
both
coal
chemistry
(
primarily
the
chlorine
content)
and
mercury
variability
between
coals
both
as
a
total
concentration
and
elemental
fraction.
The
commenter
submitted
that
doing
so
would
result
in
a
regulatory
approach
that
addresses
both
the
environmental
impacts
of
near­
field
deposition
of
oxidized
mercury
and
the
long­
range
atmospheric
transport
of
elemental
mercury.

The
commenter
noted
that
the
NPR
recognized
distinctions
in
coal
chemistry
by
proposing
to
use
allocation
adjustment
factors
for
each
coal
rank.
These
allocation
factors
are
intended
to
compensate
for
differences
in
the
efficacy
of
mercury
control
based
on
coal
type.

The
commenter
stated
that
they
undertook
extensive
technical
work
to
determine
the
most
appropriate
manner
to
address
mercury
variability
in
developing
a
mercury
MACT
floor.
The
commenter
suggested
using
this
work
as
the
basis
to
develop
mercury
allocation
factors
under
a
cap
and
trade
program
that
would
reflect
actual
mercury
variability.
The
commenter
believed
that
the
relative
difference
between
the
proposed
mercury
MACT
floor
levels
for
each
coal
rank
would
be
a
good
surrogate
for
weighting
the
allocations
of
future
mercury
emission
credits
between
units
burning
these
coal
types,
i.
e.,
the
cap
and
trade
multipliers
should
reflect
coal
chemistry
to
the
same
extent
as
the
proposed
MACT
limits.

The
commenter
noted
that
the
proposed
MACT
floors
contained
in
the
section
112
MACT
portion
of
the
NPR
would
produce
the
following
allocation
factors
for
various
coal
ranks:
bituminous
 
1.0;
sub­
bituminous
and
western
bituminous
 
2.9;
and
lignite
 
4.6.
While
the
commenter
supported
these
allocation
adjustment
factors,
the
commenter
was
concerned
that
there
may
be
inadequate
basis
for
these
derived
factors.
Alternatively,
the
commenter
suggested,
based
on
its
technical
analysis,
using
the
following
allowance
multipliers:
bituminous
 
1.0;
sub­
bituminous
and
western
bituminous
 
1.8;
and
lignite
 
3.6.

One
commenter
(
OAR­
2002­
0056­
2918)
wanted
to
bring
to
EPA's
attention
that
there
are
member
facilities
(
the
commenter
is
a
coalition
of
utilities)
that,
because
of
the
high
percentage
of
elemental
mercury
emitted
by
their
coal
(
90­
99
percent),
would
not
receive
adequate
allowance
allocations
under
any
set
of
multipliers.
According
to
the
commenter,
some
of
these
facilities
already
have
SO
2/
NO
x/
PM
controls,
but
they
would
receive
considerably
fewer
allowances
than
needed
to
operate
based
on
ICR
data
for
their
1999
emissions.
This
would
be
true
even
in
2010
with
a
cap
set
at
the
level
of
co­
benefits
achieved
through
installation
of
control
5­
113
technology
at
sources
covered
under
the
CAIR.
The
commenter
claimed
that
these
member
sources
would
therefore
be
forced
to
purchase
allowances
in
Phase
I.
For
the
facilities
that
would
have
to
purchase
allowances,
the
commenter
recommended
that
an
additional
allocation
adjustment
factor
be
applied
that
promotes
equitable
allowance
distribution,
particularly
in
Phase
I
of
the
cap
and
trade
program.

One
commenter
(
OAR­
2002­
0056­
2900)
believed
that
EPA's
proposed
adjustment
factors
are
directionally
correct
but
requested
that
the
Agency
re­
evaluate
the
appropriate
levels
for
the
adjustment
factors
in
light
of
the
data
submitted
by
other
groups
that
have
analyzed
this
issue.

One
commenter
(
OAR­
2002­
0056­
3437)
noted
that
in
the
SNPR,
EPA
continued
the
methodology
for
basing
allocations
on
the
unit's
proportionate
share
of
the
baseline
heat
input
to
total
heat
input.
The
commenter
pointed
out
that
this
way
would
not
use
an
emissions
rate,
but
would
simply
divide
the
toal
cap
among
individual
units
based
on
heat
input.
The
commenter
questioned
how
this
would
affect
actual
reductions?
The
commenter
also
questioned
whether
this
could
lead
to
some
units
being
uncontrolled
and
allowing
allowances
to
be
transferred
to
other
units
so
that
even
more
units
would
be
uncontrolled?
The
commenter
stated
that
EPA
proposed
an
alternative
method
that
would
use
the
proposed
MACT
limit
and
the
proportionate
share
of
heat
input
to
establish
unit
allowances.
In
both
cases
the
state
budget
would
be
the
sum
of
the
unit's
allowances.
The
commenter
supported
using
an
emission
rate
that
would
reflect
cost
effective
control
and
would
more
effectively
limit
individual
units
and
result
in
more
units
having
to
control
emissions.
The
commenter
believed
the
allocation
budgets
should
be
based
on
an
emisson
rate
that
reflected
adequate
and
reasonable
reductions
of
mercury
similar
to
that
in
the
NO
x
SIP
call.
The
commenter
submitted
that
EPA
needs
to
provide
comparisons
of
the
final
allocations
based
on
the
proposed
methods.

One
commenter
(
OAR­
2002­
0056­
2181)
believed
the
Rule's
proposed
allocation
method
for
determining
individual
State
budgets
was
flawed
because
it
would
adopt
two
market­
distorting
foundations.
First,
it
would
base
the
allocation
on
historic
heat
input;
thus
rewarding
those
States
with
the
most
inefficient
fleet
of
electric
generating
capacity.
Second,
by
subcategorizing
the
allocation
formula
based
upon
fuel
sources
and
granting
more
allowances
to
higher
cost­
of
control
coal
types,
the
proposed
rule
also
would
reward
some
sources
at
the
expense
of
other
sources.
The
commenter
claimed
that
these
proposed
subcategorizations
were
based
on
expectations
of
mercury
control
costs
that
are
not
well
documented
and
would
defeat
the
cost­
minimization
function
of
the
trading
program.
Neither
of
these
two
foundations
would
establish
the
fundamental
signals
that
will
lead
to
a
dynamic
trading
program
that
would
allow
markets
to
work
in
the
most
cost
effective
manner.
The
commenter
pointed
out
that
the
negative
response
from
States
to
this
skewing
of
the
allocation
system
highlighted
the
problem
of
trying
to
prejudge
the
compliance
response.
The
commenter
submitted
that
the
most
equitable
and
effective
choice
would
be
to
treat
all
sources
equally
in
the
allocation
program
and
allow
the
market
to
determine
the
least­
cost
approach
to
reducing
emissions.
As
an
alternative,
the
commenter
recommended
that
EPA
should
structure
the
State
budgets
on
an
output
basis
(
lb/
MWhr)
without
regard
to
subcategories
of
fuel.
This
method
would
be
the
best
approach
for
establishing
a
trading
program
that
provides
the
broadest
flexibility
and
insures
neutrality
among
5­
114
vintage
or
technology
choices.
Indeed,
output­
based
allocation
would
put
into
practice
many
of
the
goals
set
forth
by
the
enlibra
principles
promoted
by
Administrator
Leavitt.
The
commenter
noted
that
specifically,
these
principles
stated
that,
"
A
clean
and
safe
environment
will
best
be
achieved
when
government
actions
are
focused
on
outcomes,
not
programs
and
processes,
and
when
innovative
approaches
to
achieving
desired
outcomes
are
rewarded."
An
output­
based
allocation
method
that
rewards
efficiency
and
lower
emissions
would
be
one
such
innovative
approach.
The
commenter
strongly
urged
the
EPA
to
follow
this
approach
in
determination
of
the
State
budgets
as
the
most
equitable,
and
to
signal
support
for
this
approach
with
the
States
in
determination
of
the
generator
allocations.

One
commenter
(
OAR­
2002­
0056­
2843)
believed
that
an
allowance
allocation
budget
established
at
this
time
would
almost
certainly
unfairly
discriminate
among
coal
types
and
among
installed
APCD
technologies.
The
commenter
submitted
that
postponement
of
an
equitable
allocation
determination
until
near
the
implementation
of
Phase
2
could
eliminate
most
of
the
uncertainty
and
inequities
associated
with
pre­
mature
determination.

Response:

EPA
is
finalizing
coal
adjustment
factors
for
the
purpose
of
establishing
state
emission
budgets
of
1.0
for
bituminous
coals,
1.25
for
subbituminous
coals,
and
3.0
for
lignite
coals.
To
develop
allocation
ratios,
EPA
balanced
a
number
of
factors,
including:
(
1)
data
on
mercury
capture
by
control
figuration
and
coal
type,
(
2)
data
on
coal
characteristics
impacting
Hg
capture,
and
(
3)
Hg
emissions
by
capacity.
EPA
believes
the
allocation
adjustment
ratios
recognize
that
subbituminous
and
lignite
coals
have
the
lowest
mercury
capture
with
existing
technologies,
represent
more
emissions
per
capacity,
and
in
the
case
of
lignite
also
have
higher
mercury
coal
content.
These
adjustment
factors
are
considered
to
be
appropriate
numbers
based
on
the
test
data
currently
available.
For
further
discussion
see
final
rule
preamble
(
section
IV.
C.
4)
and
Technical
Support
Document
for
the
Clean
Air
Mercury
Rule
Notice
of
Final
Rulemaking,
State
and
Tribal
Emissions
Budgets,
EPA,
March
2005.

5.6.2
Methodology
for
Determining
Budgets
Comment:

One
commenter
(
OAR­
2002­
0056­
3449)
stated
that
estimating
national
mercury
emissions
based
on
sampling
of
coal
from
all
coal­
fired
units
and
testing
about
80
units
is
appropriate.
However,
these
tests
were
too
limited
for
allocations
to
specific
states
or
plants.
The
commenter
submitted
that
testing
at
more
than
80
units
would
be
needed
to
allocation
of
allowances.

Response:

EPA
is
finalizing
a
formula
to
be
used
to
develop
budgets
for
each
state
and
Tribes
for
2010
and
2018.
That
formula
is,
in
essence,
the
sum
of
the
hypothetical
allocations
to
each
affected
Utility
Unit
in
the
State
or
Tribe,
and
that
allocation,
in
turn,
is
based
on
the
5­
115
proportionate
share
of
their
baseline
heat
input
to
total
heat
input
of
all
affected
units.
For
purposes
of
this
hypothetical
allocation
of
the
allowances,
each
unit's
baseline
heat
input
is
adjusted
to
reflect
the
ranks
of
coal
combusted
by
the
unit
during
the
baseline
period.
The
commenter
is
incorrect
in
the
assumption
that
emissions
data
was
used
to
develop
the
budget
allocations.
Rather,
reported
heat
input
from
affected
units
was
used
to
develop
the
allocation.
For
further
discussion
see
final
rule
preamble
(
section
IV.
C.
4)
and
Technical
Support
Document
for
the
Clean
Air
Mercury
Rule
Notice
of
Final
Rulemaking,
State
and
Tribal
Emissions
Budgets,
EPA,
March
2005.

Comment:

One
commenter
(
OAR­
2002­
0056­
4139)
stated
that
the
proposed
budget
is
too
high
and
would
not
provide
for
adequate
reductions
in
Phase
I.
The
commenter
claimed
EPA
has
exaggerated
the
Phase
2
reduction
as
well
;
it
would
not
occur
by
2018.
The
commenter
submitted
the
budget
allocation
for
Michigan
would
not
reach
the
national
average
reduction
even
in
2018
 
only
63
percent
of
it.
The
budgets
were
established
by
fuel
types
burned.
However,
the
commenter
believed
the
focus
must
be
on
needed
mercury
reductions.
The
commenter
asserted
the
method
for
budget
allocations
must
be
changed
to
ensure
public
health
protection.

One
commenter
(
OAR­
2002­
0056­
3976)
submitted
that
the
2018
mecury
allowances
cause
7
of
the
top
10
plants
and
all
of
the
top
5
to
be
in
Texas.
The
commenter
stated
this
placed
an
undue
mercury
allocation
on
Texas
of
59,391
ounces
per
year
compared
to
5077
for
New
York
and
0
for
California.

Response:

EPA
maintains
that
it
is
appropriate
to
base
emission
budgets
on
baseline
heat
input
that
is
adjusted
to
reflect
the
ranks
of
coal
combusted
by
the
unit
during
the
baseline
period.
It
should
also
be
noted
that
these
allocation
adjustment
factors
should
not
impact
the
achievement
of
the
specific
environmental
goal
or
impact
the
overall
efficiency
of
the
cap­
and­
trade
program.
Allowance
allocation
decisions
in
a
cap­
and­
trade
program
raise
essentially
distributional
issues,
as
economic
forces
are
expected
to
result
in
economically
least
cost
and
environmentally
similar
outcomes
regardless
of
the
manner
in
which
allowances
are
initially
distributed.

Comment:

One
commenter
(
OAR­
2002­
0056­
2452)
noted
that
EPA
has
requested
public
comment
on
an
appropriate
mercury
cap
level
for
2010­
2017.
The
commenter
requested
that
before
EPA
goes
final
with
its
proposed
cap
level
for
this
time
period,
that
the
proposed
cap
level,
state
budgets,
and
unit­
level
allocations
be
published
for
public
comment
in
a
supplemental
notice
of
proposed
rulemaking
(
SNPR)
in
the
Federal
Register.
As
per
the
commenter's
recommendation
on
state
mercury
budgets
and
unit
allocations,
all
unit
level
allocations
and
state
budgets
could
be
published
for
comment
based
on
the
commenter's
recommendation
of
a
single
mercury
emission
standard
for
all
coal­
fired
units
applied
to
baseline
heat
input
(
without
adjustment
for
fuel
type).
5­
116
Another
commenter
(
OAR­
2002­
0056­
2108)
noted
that
the
proposal
did
not
contain
any
State
budgets
for
2010,
nor
did
it
indicate
when
such
budgets
would
be
promulgated.
According
to
the
commenter,
this
is
a
critical
piece
of
the
program.

Response:

As
discussed
above,
EPA
maintains
that
it
is
appropriate
to
use
coal
adjustment
factors
for
the
purpose
of
establishing
state
emission
budgets.
EPA
also
maintains
that
the
commenter
has
been
supplied
with
appropriate
notice
and
comment
for
the
2010­
2017
emission
budgets
because
EPA
has
noticed
the
unit
allocations
used
to
derive
those
budgets
in
the
supplemental
notice
of
proposed
rulemaking.
The
final
rulemaking
includes
State
and
Tribal
emissions
budgets
for
2010­
2017
and
2018
and
after.

Comment:

One
commenter
(
OAR­
2002­
0056­
4891)
noted
that
EPA
has
proposed
a
budget
allowance
for
Texas
of
1.837
tons
per
year
for
2018
and
thereafter.
The
commenter
supported
a
proposed
mercury
emissions
budget
allowance
for
Texas
of
no
less
than
EPA's
proposal.

Response:

EPA
has
used
the
same
methodology
to
determine
state
emission
budgets
as
the
proposed
rulemaking.
EPA
has
made
some
adjustments
to
the
unit­
level
allocation
data
for
the
final
rulemaking
which
as
resulted
in
some
state
budgets
changing
for
the
final
rulemaking.
For
discussion
of
final
rule
State
and
Tribal
Budgets
see
Technical
Support
Document
for
the
Clean
Air
Mercury
Rule
Notice
of
Final
Rulemaking,
State
and
Tribal
Emissions
Budgets,
EPA,
March
2005.

Comment:

One
commenter
(
OAR­
2002­
0056­
3432)
observed
that
industrial
boilers
are
already
subject
to
a
MACT
rule
which
the
EPA
issued
as
final
on
February
26,
2004.
The
commenter
noted
with
considerable
interest
that
in
the
March
16,
2004
SNPR,
in
th
units
allocation
table
(
69
FR
12435),
the
EPA
includes
Alma
Bl,
B2,
and
B3
in
the
listing
of
units
with
"
Phase
II
Hg
allocation(
ounces)."
The
commenter
stated
that
these
are
the
same
units
that
the
EPA
has
otherwise
identified
as
industrial
boilers
(
or
IBs)
since
they
serve
generators
less
than
25
MWe.
The
commenter
found
the
inclusion
of
these
units
in
the
units
allocation
table
confusing
since
the
commenter
found
no
explanation
in
the
SNPR
for
a
deviation
from
the
prescribed
definition
of
these
combustion
units.
The
commenter
stated
that
EPA
needs
to
clarify
the
listing
of
their
Alma
IB
units.

Response:

The
commenter
did
provide
EPA
with
specific
nameplate
capacity
data
to
determine
whether
they
are
not
affected
units
under
this
program.
Therefore,
EPA
has
included
they
in
the
5­
117
unit­
level
allocations
used
to
determine
state
emission
budgets
for
the
final
rule.
EPA
notes
that
these
hypothetical
unit
allocations
to
not
determine
applicability
to
the
program.
Rather,
applicability
is
determined
by
whether
a
unit
meets
the
definition
of
affected
unit
(
see
regulatory
text
of
final
rule,
§
60.4104,
for
full
definition).
If
the
commenter's
units
are
determined
to
be
unaffected
units,
EPA
maintains
that
removal
from
the
list
of
hypothetical
unit
allocations
will
not
significant
impact
the
state
emission
budget
for
Wisconsin.

Comment:

According
to
one
commenter
(
OAR­
2002­
0056­
3443),
state
budgets
should
be
in
perpetuity.
A
shifting
state
budget
would
make
long­
term
planning
difficult
for
utilities
and
would
add
significantly
to
the
administrative
burden
of
the
rule.
The
commenter
stated
it
would
also
discourage
repowering
or
retirement
of
uncontrolled
units.

Response:

EPA
has
established
permanent
state
Hg
emission
budgets
for
the
first
(
2010­
2017)
and
second
(
2018
and
after)
phase
of
the
program.

5.6.3
Baseline
Data
Used
in
Emission
Budgets
Comment:

One
commenter
(
OAR­
2002­
0056­
2922)
suggests
that,
in
reference
to
the
calculation
of
the
baseline
heat
input,
EPA
must
take
steps
to
ensure
that
the
heat
input
data
for
non­
Title
IV
units
are
accurate.
The
commenter
noted
that
in
its
proposal,
some
of
the
heat
input
data
that
EPA
provided
for
non­
Title
IV
units
were
incorrect.

Several
commenters
(
OAR­
2002­
0056­
2162,
­
3565)
believed
EPA
must
take
steps
to
ensure
that
the
heat­
input
data
are
correct
so
that
accurate
baselines
can
be
established.
One
commenter
(
OAR­
2002­
0056­
3565)
stated
that
EPA
should
publish
all
heat
input
data
and
any
other
data
it
intends
to
use
and
clearly
describe
the
methodology
by
which
it
intends
to
calculate
both
a
unit's
baseline
and
the
allowances
to
be
allocated
to
the
unit.
The
commenter
cannot
exactly
duplicate
and
match
the
proposed
allowance
allocation
for
its
units
with
the
allowances
listed
in
the
proposed
rule.
The
commenter
stated
that
enough
data
and
information
should
be
clearly
provided
to
allow
all
affected
sources
the
ability
to
calculate
and
check
their
individual
allocations.

One
commenter
(
OAR­
2002­
0056­
2891)
stated
that
EPA
must
address
errors
and
omissions
in
its
ICR
database
and
provide
a
mechanism
for
correction
of
mercury
unit
allocations.
According
to
the
commenter,
for
a
number
of
reasons,
information
reported
to
EPA
and
reflected
in
its
ICR
database
regarding
gulf
coast
lignite
was
seriously
flawed.
The
commenter
added
that
appropriate
information
regarding
waste
coal
and
its
use
in
Southern
Illinois
was
not
reflected
in
the
database.
The
commenter
further
stated
that
in
addition,
changes
in
generating
unit
5­
118
operational
circumstances
have
occurred
since
1999.
For
these
and
other
reasons,
the
commenter
recommended
that
a
petition
process
be
put
in
place
to
facilitate
needed
unit
allocation
changes.

One
commenter
(
OAR­
2002­
0056­
2162)
noted
that
in
its
preamble
to
the
Proposed
Mercury
Rules,
the
Agency
specified
that
baseline
heat
input
would
be
determined
for
each
affected
unit
by
determining
the
average
of
the
three
annual
highest
heat
input
values
for
the
period
from
1998
to
2002.
However,
based
upon
a
review
of
the
Agency's
revised
unit
allocations,
it
appeared
to
the
commenter
that
the
Agency
has
established
allocations
for
many
of
the
commenter
facilities
based
upon
only
one
year
of
heat
input
data.

The
commenter
believed
that
the
Agency's
methodology
for
establishing
unit
allocations
under
the
proposed
cap­
and­
trade
approach
may
rely
exclusively
on
data
collected
in
accordance
with
40
CFR
Part
75
monitoring
standards.
Although
Acid
Rain
Program
data
may
be
the
best
available
data
for
many
electric
utility
steam
generating
units,
the
majority
of
the
commenter's
facilities
have
been
exempted
from
the
program,
including
its
monitoring
provisions,
since
the
program's
inception.
The
commenter's
facilities
generally
began
to
monitor
emissions
in
accordance
with
Part
75
requirements
during
2002,
pursuant
to
implementation
of
the
NO
x
SIP
Call
Rule.
In
fact,
EPA
has
accepted
monitoring
data
collected
by
the
commenter's
facilities
under
40
CFR
Part
60
for
purposes
of
all
other
federal
allocation
programs,
including
even
the
initial
allocation
under
the
NO
x
SIP
Call
Rule.

Notwithstanding
the
availability
of
more
complete
historic
heat
input
data
for
the
commenter's
facilities
(
which
the
Agency
utilized
in
the
context
of
the
NO
x
SIP
Call),
the
Agency
utilized
only
one
year
of
heat
input
in
establishing
a
baseline
value
for
the
commenter's
facilities.
In
fact,
while
the
Agency
identified
both
2002
and
1999
heat
input
data
for
most
the
commenter's
facilities,
the
Agency
only
utilized
the
1999
data,
even
where
the
2002
data
demonstrated
a
higher
heat
input.
This
would
pose
a
significant
disadvantage
to
the
commenter's
facilities,
which
do
not
have
the
benefit
of
averaging
the
three
highest
years
of
heat
input,
and
inexplicably
have
been
limited
to
1999
heat
input
data.
The
commenter
submitted
further,
to
the
extent
that
the
Agency
has
relied
on
heat
input
data
that
reflected
an
aberrational
operating
condition,
the
baseline
heat
input
value
may
be
inappropriately
low.

For
these
reasons,
the
commenter
requested
an
opportunity
to
submit
complete
and
accurate
heat
input
data
for
the
years
1998
through
2002,
from
which
the
Agency
could
determine
appropriate
baseline
heat
input
values,
and
mercury
allocations,
for
the
commenter's
facilities.

Response:

EPA
is
finalizing
a
formula
to
be
used
to
develop
budgets
for
each
state
and
Tribes
for
2010
and
2018.
That
formula
is,
in
essence,
the
sum
of
the
hypothetical
allocations
to
each
affected
Utility
Unit
in
the
State
or
Tribe,
and
that
allocation,
in
turn,
is
based
on
the
proportionate
share
of
their
baseline
heat
input
to
total
heat
input
of
all
affected
units.
For
purposes
of
this
hypothetical
allocation
of
the
allowances,
each
unit's
baseline
heat
input
is
adjusted
to
reflect
the
ranks
of
coal
combusted
by
the
unit
during
the
baseline
period.
5­
119
Commenters
indicated
inaccurate
data
in
the
hypothetical
unit
allocations
used
to
determine
the
emission
budgets,
but
have
not
pointed
to
specific
errors
or
provided
corrected
data.
Thus,
EPA
is
unable
to
address
the
commenters
claim's.
EPA
believes
that
its
methodology
for
determining
the
state
emission
budgets
is
accurately
described
in
its
emission
budget
technical
support
document
and
in
the
companion
spreadsheet
file,
both
in
the
rulemaking
docket
(
see
Technical
Support
Document
for
the
Clean
Air
Mercury
Rule
Notice
of
Final
Rulemaking,
State
and
Tribal
Emissions
Budgets,
EPA,
March
2005
and
electronic
spreadsheet
file:
Final
CAMR
Unit
Hg
Allocations.
xls,
which
contains
the
unit
level
allocations).

The
use
of
one
years
worth
of
data
was
done
for
non­
Acid
Rain
units,
because
this
was
the
only
available
data.
Non­
Acid
Rain
units
in
the
Hg
ICR
inventory
do
not
uniformly
report
annual
heat
input
to
EPA's
Clean
Air
Market
Division
(
some
OTC
NO
x
Budget
Program
units
may
have
reported
ozone
season
heat
input
for
1999­
2002).
Baseline
heat
input
information
was
collected
by
the
Hg
ICR
for
1999.
The
fuel
use
and
heat
content
data
from
the
ICR
were
used
to
calculate
1999
annual
heat
input,
and
this
single
year
was
used
as
the
baseline
heat
input
(
see
Budget
TSD
for
more
discussion).

With
regard
to
commenter's
request
to
submit
more
appropriate
data
for
1998­
2002,
EPA
notes
that
it
requested
at
proposal
for
commenters
to
submit
such
data.
For
commenters
who
submitted
such
data,
EPA
adjusted
hypothetical
unit
allocations
accordingly.
In
most
instances,
corrections
to
baseline
heat
input
data
at
the
unit
level
allocation
are
not
likely
to
result
in
significant
changes
to
the
overall
State
or
Tribal
emissions
budgets.
Under
the
model
trading
rule,
EPA
notes
that
States
and
Tribes
have
the
authority
to
allocate
at
the
unit
level
and
commenters
can
submit
corrected
baseline
heat
input
to
the
State
or
Tribe
prior
to
the
allocation
process.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2915,
­
3478,
­
4191)
supported
the
1999
coal
type
use
as
the
basis
for
the
adjustment
of
the
baseline
for
establishing
plant
mercury
allocations.
Commenter
OAR­
2002­
0056­
3478
stated
that
this
is
the
year
upon
which
the
48­
ton
electric
utility
mercury
emissions
were
based.
Several
of
the
commenters
(
OAR­
2002­
0056­
2915,
­
4191)
believed
using
1999
as
the
fuel
baseline
is
needed
to
provide
certainty.
The
commenters
added,
1999
is
the
only
year
for
which
EPA
already
has
data
for
all
the
coal­
fired
EGUs
throughout
the
country.

Several
commenters
(
OAR­
2002­
0056­
2180,
­
2816,
­
2900,
­
2948,
­
3537,
­
3546,
­
3556,
­
3565)
stated
that
basing
plant
mercury
allocations
on
the
coal
rank
used
in
1999
would
not
reflect
coal
type
switches
that
have
occurred
since
the
coal
rank
year.
One
commenter
(
OAR­
2002­
0056­
2180)
pointed
out
that,
therefore,
units
that
have
switched
coal
type
since
1999
would
not
receive
an
appropriate
or
relevant
allocation
of
allowances
for
future
operation,
as
the
allowance
adjustment
factor
would
be
based
on
historical
coal
type,
not
the
current
coal
type.
The
commenter
was
a
joint
owner
of
two
coal
units
that
have
switched
coal
rank
since
1999
and
stated
that
they
would
be
adversely
affected
by
the
proposed
method
for
determining
the
allowance
adjustment
factor
and
mercury
allowances.
The
units
represented
about
two­
thirds
of
5­
120
the
commenter's
total
coal
capacity.
These
units
switched
coal
rank
from
bituminous
coal
to
sub­
bituminous
coal
to
comply
with
the
NO
x
SIP
Call.
According
to
the
commenter,
using
sub­
bituminous
coal
in
these
units
reduced
the
NO
x
emission
rate
by
about
50
percent.
The
commenter
stated
that
switching
coal
type
was
not
simply
a
matter
of
ordering
a
different
type
of
coal.
The
commenter
emphasized
that
to
use
sub­
bituminous
coal
at
its
units,
they
made
significant
and
necessary
investments
to
the
units'
systems
for
coal
transportation,
coal
handling,
dust
suppression,
fire
protection,
particulate
emissions
control,
and
ash
handling.
The
commenter
stated
that
the
coal
switch
qualified
as
a
pollution
control
project
under
New
Source
Review
regulations,
and
the
decision
to
switch
coal
type
came
about
long
before
the
mercury
cap
and
trade
rule
was
proposed.
The
commenter
asserted
that
the
mercury
trading
rule's
application
of
allowance
adjustment
factors
should
be
revised
to
reflect
coal
type
switches
that
have
occurred
since
the
baseline
coal
rank
year,
and
especially
for
coal
type
switches
that
were
done
towards
complying
with
Clean
Air
Act
requirements
and
where
the
decision
to
switch
coal
type
occurred
prior
to
the
proposed
mercury
rule.
The
commenter
stated
that
for
such
situations,
the
final
rule
should
enable
the
use
of
the
adjustment
factor
for
currently
used
coal.
According
to
the
commenter,
this
recommended
revision
would
not
affect
the
total
number
of
national
mercury
allowances,
only
the
allocation
of
the
allowances
among
affected
units,
and
would
only
have
a
very
minor
change
in
allowances
allocated
to
other
affected
units.
Another
commenter
(
OAR­
2002­
0056­
2948)
suggested
that
EPA
should
permit
units
that
had
a
significant
change
in
their
coal­
type
usage
since
1999
to
provide
EPA
with
that
information
before
allocations
are
finalized.

A
third
commenter
(
OAR­
2002­
0056­
3537)
stated
that
in
anticipation
of
new
regulatory
requirements,
two
Utility
Units
co­
owned
by
the
commenter
switched
from
eastern
bituminous
to
western
sub­
bituminous
coal
to
lower
NO
x
emissions.
In
2001,
the
decision
was
made
by
the
Corporation
(
and
the
other
co­
owners)
to
switch
to
sub­
bituminous
coal,
in
anticipation
of
imminent
new
regulatory
requirements
for
Georgia.
According
to
the
commenter
even
though
the
units
in
question
were
originally
designed
to
burn
this
type
of
coal,
some
engineering
and
design
work
was
needed
to
facilitate
the
switch.
This
was
started
in
late
2001
and
construction
began
in
early
2002,
in
order
to
fully
implement
the
switch
in
2004.
The
commenter
stated
the
units
began
to
operate
fully
on
sub­
bituminous
coal
at
the
beginning
of
2004.
The
commenter
noted
if
EPA
uses
the
coal
type
used
by
each
unit
in
1999,
however,
to
determine
the
adjustment
factor,
then
no
adjustment
to
these
units'
baseline
will
be
made.
Further,
when
Georgia
(
under
CAA
section
111)
or
EPA
(
under
CAA
section112)
allocates
back
to
these
units
from
Georgia's
mercury
trading
program
budget,
likely
that
same
multiplier
(
i.
e.,
1.0)
instead
of
the
higher
ratio
for
subbituminous
coal
would
be
used.
The
commenter
submitted
that
the
result
would
be
a
lower
allocation
of
mercury
allowances
to
such
units
than
would
otherwise
occur
had
those
units
been
given
credit
for
the
fuel
that
is
actually
being
burned.
The
commenter
believed
that
such
units
will
be
"
short­
changed,"
since
they
would
not
receive
the
amount
of
mercury
allowances
needed
for
the
coal
they
are
now
burning
 
coal
whose
mercury
emissions
are
by
their
very
nature
harder
to
control
than
the
type
combusted
in
1999.
The
commenter
claimed
that
such
units
would
automatically
be
at
a
distinct
competitive
disadvantage
vis­
a­
vis
other
units,
who
were
fortunate
enough
not
to
have
switched
to
a
lower
ranked
coal
since
1999.
The
commenter
asserted
that
the
result
would
be
patently
inequitable,
in
essence
punishing
the
affected
units
for
taking
steps
to
comply
with
an
important
State
and
federal
program
for
the
control
of
a
criteria
pollutant,
by
5­
121
failing
to
allocate
to
them
the
allowances
that
correspond
to
actual
coal
usage.
The
commenter
believed
EPA
should
not
allow
these
units
to
be
so
unfairly
prejudiced.
EPA
should
correct
this
inequity
for
those
Utility
Units
that
switched
fuels
for
environmentally
beneficial
reasons,
by
allowing
a
unit
that
switched
to
a
lower
ranked
coal
for
reasons
other
than
the
Mercury
Rule
to
use
the
year
the
Mercury
Rule
is
finalized
as
the
year
to
determine
the
adjustment
ratio
to
be
used,
both
when
computing
State
budgets
and
when
allocating
mercury
allowances
to
units
within
the
State.
The
commenter
suggested
alternatively,
EPA
could
allow
owners
of
those
few
units
in
this
position
to
petition
it
(
or
the
relevant
State)
for
use
of
a
different
adjustment
ratio
that
matches
the
real­
world
coal
use
at
such
units.

Several
other
commenters
(
OAR­
2002­
0056­
2911,
­
3546,
­
3556)
cited
circumstances
leading
to
fuel
switches
that
would
be
inequitable
to
the
Utility
Unit.
One
of
these
commenters
(
OAR­
2002­
0056­
3546)
believed
EPA
should
permit
units
that
had
a
significant
change
in
their
coal­
type
usage
in
connection
with
mine
closures
or
environmental
purposes
to
provide
EPA
with
that
information
before
allocations
are
finalized
so
that
EPA
could
use
the
adjustment
factors
that
more
accurately
reflect
the
coal
actually
being
used
at
a
unit.

The
other
commenters
(
OAR­
2002­
0056­
2911,
­
3556)
stated
that
allocations
of
allowances
based
on
the
1999
fuel
blend
would
be
detrimental
to
those
units
that
have
increased
the
percentage
of
western
fuel
burned,
as
mercury
from
western
coal
is
harder
to
remove,
therefore
a
larger
allocation
is
necessary
to
prevent
fuel
bias.
The
commenter
recommended
that
more
recent
and
representative
data
be
used
to
allocate
allowances.
The
commenter
believed
this
would
ensure
that
allocations
to
the
states,
with
units
that
have
switched
to
western
coal,
would
be
done
in
a
manner
that
would
not
to
create
a
competitive
disadvantage
due
to
an
inappropriate
allocation
of
allowances.

One
of
these
commenters
(
OAR­
2002­
0056­
2911)
included
a
graph
showing
the
substantial
changes
to
fuel
blends
that
have
occurred
since
1999
due
to
the
lower
cost
and
compliance
with
the
Acid
Rain
provisions
of
the
Clean
Air
Act.

One
commenter
(
OAR­
2002­
0056­
3565)
had
seven
units
located
at
three
different
plants,
which
burned
bituminous
coal
in
1999
but
switched
to
sub­
bituminous
coal
in
2000,
which
they
continue
to
burn
today.
The
commenter
stated
that
these
seven
units
should
receive
the
higher
heat
input
allocation
factor
1.25
for
sub­
bituminous
units
and
not
the
1.0
factor
for
bituminous
units.
The
commenter
strongly
urged
EPA
to
use
the
year
2003,
or
even
2004,
to
determine
coal­
type
usage.

One
commenter
(
OAR­
2002­
0056­
2816)
noted
that
EPA
proposed
to
use
1999
Information
Collection
Request
(
ICR)
data
to
determine
the
coal­
type
usage
patterns
of
units
subject
to
regulation.
The
commenter
stated
that
these
data
are
important
because
they
determine
the
factors
that
will
be
used
to
adjust
heat
input
based
on
coal
type.
The
commenter
submitted
that
using
1999
data
to
determine
coal
usage
patterns
would
result
in
incorrect
information
regarding
coal
use
by
a
majority
of
the
commenter's
units,
as
well
as
the
units
of
other
companies
that
switched
from
high
sulfur
bituminous
coals
to
low
sulfur
sub­
bituminous
coal
during
and
after
1999
in
order
to
comply
with
requirements
for
reducing
SO
2
emissions
for
Phase
II
of
the
Title
IV
5­
122
Acid
Rain
Program.
The
commenter
submitted
that
incorrect
identification
of
the
coals
actually
being
used
by
these
units
would
result
in
significant
penalty
in
allocating
allowances
to
any
such
unit.
The
commenter
submitted
that
to
more
fairly
and
accurately
represent
the
coal­
type
usage
pattern
for
such
units,
EPA
should
implement
one
of
the
following
proposals:

°
EPA
should
permit
companies
with
units
that
had
a
significant
change
in
their
coal­
type
usage
during
or
after
1999
to
provide
that
information
to
EPA
before
allocations
are
finalized.
EPA
should
revise
its
coal
type
usage
data
for
those
units
and
use
the
adjustment
factors
that
accurately
reflect
the
coal
actually
being
used
at
such
units.
EPA
could
limit
manipulation
of
the
factors
by
restricting
coal­
type
usage
data
to
an
annual
period
before
December
31,
2004;
or
°
Rather
than
using
the
ICR
data
to
set
allowance
allocations,
EPA
should
use
the
most
recent
publicly
available
fuel
data
(
2004)
such
as
that
provided
to
the
Department
of
Energy
on
Forms
423
or
906.
These
data
specify
the
type
of
fuel
used
at
each
coal­
fired
power
generating
facility
on
a
current
basis.

One
commenter
(
OAR­
2002­
0056­
2900)
noted
the
proposed
2018
allowance
allocations
are
based
on
the
coal
burned
at
the
affected
units
during
the
baseline
period,
which
is
the
average
of
the
three
years
of
highest
heat
input
from
1998­
2002.
EPA
proposed
it
would
use
this
same
methodology
to
set
2010
allowance
allocations.
The
commenter
stated
that
subsequent
to
the
proposed
baseline
period
of
1998­
2002,
many
coal­
fired
EUSGUs
have
switched
or
are
in
the
process
of
switching
from
the
use
of
bituminous
coal
to
sub­
bituminous
coal
to
meet
the
requirements
of
other
programs.
The
commenter
believed
EPA
must
allow
such
units
the
option
of
establishing
a
different
baseline
for
allowance
allocations.
According
to
the
commenter,
failure
to
do
so
would
result
in
a
highly
inequitable
system
that
severely
penalizes
units
that
recently
have
switched
to
lower
sulfur
coal.

For
units
that
switched
or
partially
switched
from
bituminous
to
sub­
bituminous
coal
following
the
proposed
baseline
period
of
1998­
2002,
the
commenter
urged
EPA
to
consider
an
adjustment
when
establishing
the
2010
cap
and
to
revise
the
proposed
2018
allocations.
The
commenter
suggested
this
could
be
accomplished
by
allowing
units
to
choose
an
alternative
three­
year
baseline
that
encompasses
the
switch.
For
units
that
only
partially
switched
to
sub­
bituminous
coals,
the
heat
input
could
be
proportioned
to
reflect
the
amount
of
sub­
bituminous
and
bituminous
coal
burned
during
the
revised
baseline
period
when
any
blending
occurred,
similar
to
the
MACT
provision
allowing
mercury
emissions
to
be
weighted
proportionally
by
fuel
type
when
blending.

The
commenter
understood
that,
if
EPA
establishes
a
cap
in
2010,
then
the
Phase
I
allowance
allocations
would
be
included
in
the
final
rule.
The
commenter
noted
that
this
would
not
allow
units
that
have
switched
to
sub­
bituminous
coal
to
select
an
alternative
baseline
period.
Therefore,
for
Phase
I,
the
commenter
proposed
that
EPA
deal
with
any
additional
allowance
allocations
to
alternative
baseline
units
through
the
establishment
of
an
allowance
set­
aside.
For
Phase
II,
the
commenter
proposed
that
EPA
revise
the
allowance
allocations
once
units
have
submitted
their
alternative
baseline
to
EPA.
The
commenter
further
recommended
that
alternative
5­
123
baseline
units
be
required
to
use
the
lower
heat
input
from
the
1998­
2002
time
period
or
the
alternative
baseline
period.
Specifically,
units
would
demonstrate
an
alternative
baseline
for
purposes
of
determining
the
coal
type
on
which
their
Phase
II
allowance
allocations
should
be
based
and
their
eligibility
for
the
Phase
I
alternative
baseline
allowance
set­
aside.
However,
for
determining
heat
input,
the
commenter
recommended
the
unit
would
be
required
to
use
the
lower
of
the
baseline
selected
by
EPA
from
the
1998­
2002
time
frame
(
EPA
used
the
average
of
the
highest
three
years
of
heat
input
from
the
1998­
2002
time
frame
in
determining
the
proposed
Phase
II
allowance
allocations
for
the
SNPR)
or
the
alternative
baseline.
The
commenter
believed
this
requirement
would
prevent
units
from
gaming
the
system.

The
commenter
did
not
have
a
specific
recommendation
as
to
the
size
of
the
alternative
baseline
allowance
set­
aside
that
would
be
appropriate
for
Phase
I
but
believed
that
EPA
could
readily
determine
this
information
by
sending
out
a
request
and
reopening
the
comment
period
on
this
narrow
issue
to
determine
which
units
have
switched
to
sub­
bituminous
coal
or
are
in
the
process
of
switching.
The
commenter
submitted
the
responses
would
provide
EPA
with
a
reasonable
estimate
of
the
amount
of
allowances
needed
for
the
set­
aside.

Response:

EPA
agrees
with
commenters
that
1999
coal
type
is
appropriate
for
the
use
as
the
basis
for
the
adjustment
of
the
baseline
for
establishing
plant
mercury
allocations.
1999
is
the
only
year
for
which
EPA
already
has
data
for
all
the
coal­
fired
power
plants
throughout
the
country,
is
the
year
upon
which
the
48­
ton
electric
utility
mercury
emissions
estimate
was
based,
and
the
emissions
EPA
examine
in
developing
its
coal
adjustment
factors.

EPA
is
finalizing
a
formula
to
be
used
to
develop
budgets
for
each
state
and
Tribes
for
2010
and
2018.
That
formula
is,
in
essence,
the
sum
of
the
hypothetical
allocations
to
each
affected
Utility
Unit
in
the
State
or
Tribe,
and
that
allocation,
in
turn,
is
based
on
the
proportionate
share
of
their
baseline
heat
input
to
total
heat
input
of
all
affected
units.
For
purposes
of
this
hypothetical
allocation
of
the
allowances,
each
unit's
baseline
heat
input
is
adjusted
to
reflect
the
ranks
of
coal
combusted
by
the
unit
during
the
baseline
period.
Commenters
did
not
provide
data
that
indicated
how
coal
switching
since
1999
would
impact,
if
at
all,
the
state
emissions
budgets.

Under
the
model
trading
rule,
EPA
notes
that
States
and
Tribes
have
the
authority
to
allocate
at
the
unit
level
and
they
can
use
a
different
baseline
year
for
coal
type
used
to
determine
unit
level
allocations.

Comment:

One
commenter
(
OAR­
2002­
0056­
3431,
­
3400)
stated
that
upon
review
of
Appendix
B
to
the
Preamble
(
Unit
Allocations)
and
EPA's
April
5,
2004
memorandum
to
the
Docket
titled
"
Revisions
to
Unit
Level
Allocations
and
State
Emissions
Budgets
for
the
Proposed
Mercury
Trading
Rulemaking"
it
appeared
that
the
commenter's
Warrior
Run
allocation
(
21
ounces)
was
incorrect
and
should
be
greater.
(
The
commenter
noted
that
Warrior
Run
was
a
180
MW
5­
124
coal­
fired
power
plant
located
in
Maryland.)
The
commenter
noted
that
in
the
April
5,
2004
memo,
EPA
stated
that
the
figures
in
the
spreadsheet
that
accompanied
the
memo
would
replace
the
hypothetical
unit
allocations
in
Appendix
B
and
the
state
emission
budgets
in
the
regulatory
text
of
the
Supplemental
Rulemaking.
The
commenter
stated
that
if
they
are
interpreting
the
spreadsheet
correctly,
EPA's
spreadsheet
showed
zero
(
0)
heat
input
for
the
plant
trom
1998
to
2001
and
15,587,456
mmBtu
in
2002.
The
correct
heat
input
(
mmBtu)
at
Warrior
Run
trom
coal
was
as
follows:

1999
2000
2001
2002
2003
1,128,625
14,890,200
15,495,345
15,222,786
15,579,265
The
commenter
stated
that
start­
up
operations
commenced
in
1999,
explaining
the
low
heat
input
for
that
year.
The
commenter
believed
that
because
EPA
did
not
record
any
heat
input
for
1999
to
2001,
the
baseline
data
that
EPA
used
to
calculate
the
commenter's
allocation
was
probably
incorrect.
The
commenter
requested
that
EPA
verify
its
heat
input
information
for
Warrior
Run
and
update
the
information
and
calculations
used
to
calculate
Warrior
Run's
allocations
and
Maryland's
state
emissions
budgets.

The
commenter
observed
that
as
provided
for
in
the
Supplemental
Notice
of
Proposed
Rulemaking,
the
other
plants'
allowance
allocations
were
based
on
their
proportion
of
the
total
state's
heat
input.
The
commenter
stated
for
example,
the
combined
heat
input
for
the
three
units
at
Dickerson
Station
was
approximately
11
percent
of
the
total
Maryland
heat
input,
and
the
station
was
allocated
647
allowances
which
was
11
percent
of
the
total
Maryland
2018
mercury
allocation.
Based
on
the
commenter's
heat
input
figures
above,
Warrior
Run's
heat
input
was
approximately
5
percent
of
the
total
Maryland
heat
input
and
therefore
the
commenter
should
receive
roughly
5percent
of
the
total
Maryland
budget,
or
approximately
296
allowances.
The
commenter
stated
that
however,
the
allocation
for
Warrior
Run
in
the
April
2004
memo
was
only
21
allowances
 
0.35
percent
of
the
total
Maryland
budget
instead
of
the
5percent
that
should
have
been
provided.

The
allocation
issue
was
of
great
concern
to
independent
power
producers
(
IPPs)
such
as
the
commenter.
The
commenter
stated
that
passing
through
increased
costs
to
comply
with
new
environmental
regulation
in
rates
could
rectify
shortfalls
in
allowance
allocations
for
power
plants
owned
by
traditional
utilities;
however,
IPPs
would
not
have
this
luxury
and
must
absorb
such
increased
costs
against
the
plant's
bottom
line.

Response:

EPA
updated
the
heat
input
data
for
1
plant
based
on
commenter
input.
EPA
data
was
missing
heat
input
for
the
AES
Warrior
Run
plant
in
Maryland
for
the
years
1998­
2001.
The
data
submitted
by
the
commenter
is
highlighted
in
the
heat
input
data
spreadsheet
available
in
the
docket
(
see
electronic
spreadsheet
file:
Final
CAMR
Unit
Hg
Allocations.
xls,
which
contains
the
unit
level
allocations).
5­
125
5.6.4
Tribal
Emission
Budgets
Comment:

Several
commenters
(
OAR­
2002­
0056­
2010,
­
2118,
­
2380,
­
3413,
­
3469,
­
3549,
­
3550,
­
3551)
opposed
cap
and
trade,
but
stated
that
if
EPA
adopts
this
approach
the
rule
must
make
provisions
for
tribal
allowances.

One
commenter
(
OAR­
2002­
0056­
3469)
stated
that
in
the
event
a
cap­
and­
trade
program
is
implemented
by
the
EPA
to
reduce
SO
2,
NO
x
or
mercury,
future
tribal
energy
development
projects
and
existing
power
plants
burning
Indian
country
coal
that
has
a
higher
sulfur
content
than
SPRB
coal,
i.
e.,
more
than
1.2lb
SO
2/
mmBtu,
will
be
allocated
allowances
(
a)
as
ultimately
determined
by
EPA
for
NO
x
and
mercury
and
(
b)
as
currently
scheduled
under
Title
IV
for
SO
2
or
otherwise
under
a
separate
CAIR
program,
depending
on
its
structure.
These
new
projects
and
plants
would
be
permitted
to
use
these
allowances
according
to
the
following
formula:

°
1
allowance
for
2
tons
of
SO
2­
effective
immediately
through
12/
31/
05
°
1
allowance
for
3
tons
of
SO
2­
effective
1/
1/
06
forward
°
1
allowance
for
2
tons
of
NO
x­
effective
with
CAIR
implementation
°
1
allowance
for
2
ounces
of
Mercury­
effective
with
CAIR
and
Mercury
Rule
implementation
The
commenter
noted
that
the
SO
2
formula
above
would
only
apply
to
noncompliance
coal
(
i.
e.
greater
than
1.21b
SO
2/
mmBtu).
The
commenter
believed
the
accelerated
schedules
for
the
SO
2
formulae
above
are
justified
given
that
the
mere
announcement
of
the
CAIR
proposal
is
having
real
and
immediate
impacts
on
the
Title
IV
SO
2
allowance
market
with
real
and
current
impacts
on
Indian
country
coal.
(
Allowance
prices
have
already
increased
by
80
percent
largely
due
to
announcement
of
the
proposal).
The
commenter
submitted
that
granting
these
preferential
allowance
ratios
will
have
no
negative
impact
on
national
emissions.
SO
2
emissions
at
plants
using
Indian
country
coal
will
not
increase
emissions
nationally
as
these
plants
are
already
scrubbed
and
compliant
with
NSPS.
The
commenter
also
noted
the
SO
2
ratio
is
based
upon
the
greater
amount
of
sulfur
content
in
Montana
Indian
country
coal
when
compared
to
SPRB
coal.
EPA
intends
to
increase
the
market
price
of
Title
IV
allowances
by
reducing
available
supply,
thus
providing
economic
justification
for
power
plants
to
retrofit
emission
control
technology.
The
commenter
stated
that
by
intertwining
the
CAIR
with
Title
IV,
the
proposal
would
increase
SO
2
costs
for
all
plants
across
the
country,
not
just
in
the
29
states
and
D.
C.
The
commenter
believed
that
volatility
in
the
SO
2
allowance
market
could
drive
changes
in
fuel
choices
at
clean
plants
using
Indian
coal,
or
could
even
cause
plants
to
shut
down,
depriving
the
tribes
of
coal
sales
royalty
and
tax
revenues,
employment,
and
other
economic
benefits
they
currently
rely
on
to
sustain
their
nations.

Response:
5­
126
EPA
has
provided
budgets
to
tribes
in
the
final
rule
that
have
existing
sources
on
their
land.
Requirements
for
new
tribal
sources
under
CAMR
are
discussed
in
the
preamble.

EPA
understands
and
is
sympathetic
to
the
economic
situation
of
the
specific
tribe's
comments.
EPA
staff
and
officials
have
met
with
one
of
the
commenters
regarding
their
concerns
regarding
the
CAIR
rulemaking,
and
considered
the
comments
and
proposals
put
forth
by
the
commenters.
EPA's
analysis
of
the
Crow
tribe's
economic
situation,
and
discussions
with
the
commenters,
suggest
that
the
Tribe
should
not
experience
adverse
economic
impacts
as
a
result
of
the
NO
x
caps
under
CAIR.
Rising
SO
2
prices,
however,
may
lead
to
the
erosion
of
the
competitive
advantage
currently
held
by
coal
from
Absaloka
mine,
and
could
potentially
force
the
mine
to
shut
down.
However,
the
erosion
of
this
competitive
advantage
is
not
a
direct
effect
of
CAIR,
as
the
price
advantage
held
by
Absaloka
coal
is
likely
to
disappear
under
title
IV
alone.

The
EPA
has
determined
that
we
can
not
implement
the
commenters
recommendation
for
the
following
reasons:
The
proposed
Hg
allowance
retirement
ratios
would
undermine
both
the
environmental
certainty
and
economic
stability
of
the
cap­
and­
trade
program.
If
EPA
were
to
allow
power
plants
burning
Indian
country
coal,
and
future
tribal
energy
development
projects
to
retire
allowances
at
a
less
than
one
to
one
ratio,
the
certainty
of
the
cap
level,
and
the
resulting
knowledge
of
the
value
of
an
allowance
would
be
jeopardized.
This
lack
of
certainty
about
the
cap
is
unacceptable
for
a
cap
and
trade
program,
which
function
most
successfully
when
environmental
and
economic
certainty
have
been
established.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2380,
­
3413,
­
3457)
noted
that
Tribal
organizations
opposed
cap
and
trade,
but
asked
EPA
to
include
these
provisions.
Commenter
OAR­
2002­
0056­
2380
suggested:
(
1)
Tribes
should
be
included
where
they
are
omitted.
(
2)
Restrict
trading.
EPA
should
set
an
appropriate
ceiling
for
the
number
of
credits
any
source
may
hold
and
use
at
a
given
time.
(
3)
Require
a
higher
trading
ratio
for
facilities
with
high
emissions
to
encourage
sooner
installation
of
controls.
It
should
cost
more
to
buy
credits
than
to
not
install
controls.
Commenter
OAR­
2002­
0056­
3457
recommended
that
any
allowance
system
forbid
trading
and
require
allowances
to
expire
or
be
discounted
over
time.

Response:

In
the
final
rule,
EPA
has
established
Hg
emission
budgets
for
tribes
with
existing
sources.
Requirements
for
new
tribal
sources
under
CAMR
are
discussed
in
the
preamble.
EPA
believes
that
a
cap­
and­
trade
program
for
Hg
will
provide
for
an
efficient
means
of
achieving
the
necessary
level
of
emissions
reductions.
Allowing
for
trading
maximizes
the
cost­
effectiveness
of
emissions
reductions.
Sources
that
can
reduce
emissions
most
cheaply
will
do
so,
and
sell
any
remaining
allowances
to
sources
that
cannot.
Sources
have
an
incentive
to
endeavor
to
reduce
their
emissions
below
their
allowance
allocation;
if
they
can
do
so
cost­
effectively,
they
may
then
sell
their
excess
allowances
on
the
market.
In
practice,
the
sources
that
can
reduce
emissions
cost­
effectively
under
a
cap­
and­
trade
program
are
the
largest
(
and
frequently
high
emitting)
sources.
5­
127
Comment:

Several
commenters
(
OAR­
2002­
0056­
2380,
­
3413)
noted
that
the
tribal
authority
rule
allows
tribes
to
adopt
parts
of
air
programs
without
being
subject
to
deadlines
or
other
requirements
imposed
on
states.
The
commenters
submitted
the
proposed
rule
should
include
a
mechanism
for
tribes
to
enter
the
cap­
and­
trade
program
if
and
when
they
want.
At
minimum,
tribes
need
allocations
for
plants
already
located
on
Indian
land
or
planning
to
do
so.
The
commenters
also
submitted
that
in
absence
of
adequate
resources
for
a
tribe
to
enter
the
program
(
i.
e.,
inability
to
develop
and
implement
a
tribal
implementation
plan),
EPA
should
develop
a
Federal
Implementation
Plan
for
them.

Response:

EPA
has
provided
budgets
to
tribes
in
the
final
rule
that
have
existing
sources
on
their
land.
The
requirements
of
tribes
under
CAMR
are
discussed
in
the
preamble.

Comment:

One
commenter
(
OAR­
2002­
0056­
3469)
stated
that
if
CAA
provisions
do
not
permit
an
exemption
for
new
plants
in
Indian
country,
the
EPA
should
make
available
to
developers
or
new
consumers
of
Indian
country
energy
a
pool
of
SO
2,
NO
x
and
mercury
allowances
equal
to
5
percent
of
all
allocations
at
set
prices.
The
commenter
suggested
that
these
prices
would
be
established
as
follows:

°
50
percent
of
the
mercury
price
modeled
by
EPA;

°
Average
SO
2
allowance
price
2000­
2003;
and
°
50
percent
of
the
NO
x
price
modeled
by
EPA.

Response:

EPA
has
allocated
allowances
to
States
and
tribes
on
the
basis
of
heat
input
and
coal
type.
States
have
the
authority
to
determine
how
to
allocate
allowances
to
sources
within
the
State.
Allocations
to
States
and
tribes
are
discussed
in
section
IV
of
the
preamble.

Comment:

Several
commenters
(
OAR­
2002­
0056­
1961,
­
3469)
recommended
that
new
Tribal
plants
be
exempted
from
the
requirement
to
purchase
allowances
as
long
as
they
have
NSPS
Subpart
Da
technology
operational
when
they
initiate
operations
and
they
adhere
to
monitoring
and
reporting
requirements,
demonstrating
continuous
compliance.
One
commenter
(
OAR­
2002­
0056­
3469)
submitted
given
that
lignite
units
and
the
small
number
of
new
plants
that
could
be
built
by
the
Tribes
will
contribute
a
minute
amount
of
mercury
to
the
global
pool,
exempting
new
plants
will
not
materially
affect
any
caps
adopted
by
the
EPA.
One
commenter
(
OAR­
2002­
0056­
1961)
5­
128
added
that
if
EPA
does
not
exempt
them,
EPA
should
make
an
energy
pool
available
for
mercury
allowances
equal
to
5
percent
of
all
allocations
at
set
prices
(
50
percent
of
mercury
prices
modeled
by
EPA).
This
will
help
tribes
who
have
developed
their
coal
reserves.

Response:

In
the
final
CAMR,
new
sources
will
be
covered
under
the
Hg
cap
of
the
trading
program,
and
will
be
required
to
hold
allowances
equal
to
their
emissions.
EPA
maintains
that
is
essential
to
include
new
sources
under
the
cap
to
ensure
that
environmental
goal
of
reducing
mercury
emission
is
achieved.
With
new
sources
under
the
cap,
the
environmental
goal
continues
to
be
achieved
despite
future
growth
in
the
electric
power
sector,
as
older
coal­
fired
generation
is
retired
and
replaced
new
coal­
fired
generation.
Requirements
of
new
tribal
sources
under
CAMR
are
discussed
in
the
preamble.

5.7
ALLOCATION
METHODOLOGY
5.7.1
Allocation
Mechanisms
Comment:

One
commenter
(
OAR­
2002­
0056­
2860)
recommended
that
a
parallel
allowance
allocation
methodology
similar
to
that
used
under
the
IAQR
should
be
used.
The
commenter
believed
this
would
promote
consistency
among
programs.

Response:

EPA
agrees
with
commenter
and
has
provided
an
example
unit
allocation
methodology
for
the
Hg
model
trading
rule
as
consistent
as
possible
to
the
CAIR
NO
x
allocation
methodology.

Comment:

One
commenter
(
OAR­
2002­
0056­
1608)
believed
that
in
order
to
establish
consistency
across
the
country,
the
EPA
should
develop
the
model
trading
rules
in
a
way
that
maximizes
appeal
to
all
of
the
states
affected.
The
commenter
however
urged
the
EPA
to
assure
that
any
allocation
methodology
developed
for
mercury
allowances
under
a
trading
program
does
not
penalize
sources
that
are
already
achieving
co­
benefit
reductions
through
the
operations
of
existing
control
equipment.

Response:

EPA
believes
its
example
allocation
methodology
should
appeal
to
all
states.
EPA
also
maintains
that
coal
adjustment
factors
for
existing
units
address
commenters
concerns
with
regard
to
co­
benefit
reductions.

Comment:
5­
129
Several
commenters
(
OAR­
2002­
0056­
2830,
­
2835,
­
2915,
­
3440,
­
3469,
­
3478,
­
3546,
­
4191,
­
4891)
stated
that
allowances
should
be
allocated
only
to
affected
EGUs.
Four
of
the
commenters
(
OAR­
2002­
0056­
2915,
­
3440,
­
3478,
­
4191)
explicitly
stated
that
mercury
allowances
under
the
mercury
rule
should
be
allocated
to
coal­
fired
EGUs
only.

Response:

The
final
CAMR
requires
reductions
from
coal­
fired
power
plants
and
as
such
States
can
only
allocate
to
these
affected
units.

Comment:

One
commenter
(
OAR­
2002­
0056­
2180)
stated
that
allowance
allocations
should
be
periodically
updated
to
reflect
changes
in
capacity
utilization
(
capacity
factor),
unit
retirements,
commencement
of
operation
of
new
units,
and
changes
in
coal
rank.
The
commenter
suggested
that
an
appropriate
first
update
might
be
when
Phase
II
of
the
cap
comes
into
effect,
with
at
least
a
three­
year
lead
time
for
beginning
the
updated
allocation.
Thereafter,
allowances
could
be
allocated
only
for
specific
future
periods,
e.
g.
5
to10
years.

Response:

Under
its
example
allocation
methodology,
EPA
has
finalized
for
the
model
rule
a
"
modified
output"
approach.
This
example
method
involves
input­
based
allocations
for
existing
coal
units
(
with
different
ratios
based
on
coal
type),
with
updating
to
take
into
account
new
generation
on
a
modified­
output
basis.
It
also
utilizes
a
new
source
set­
aside
for
new
units
that
have
not
yet
established
baseline
data
to
be
used
for
updating.

Under
the
EPA
example
method,
existing
units
as
a
group
will
not
update
their
heat
input.
This
will
eliminate
the
potential
for
a
generation
subsidy
(
and
efficiency
loss)
as
well
as
any
potential
incentive
for
less
efficient
existing
units
to
generate
more.
This
methodology
will
also
be
easier
to
implement
because
it
will
not
require
the
updating
of
existing
units'
baseline
data.
Retired
units
will
continue
to
receive
allowances
indefinitely,
thereby
creating
an
incentive
to
retire
less
efficient
units
instead
of
continuing
to
operate
them
in
order
to
maintain
the
allowance
allocations.
Moreover,
new
units
as
a
group
will
only
update
their
heat
input
numbers
once
 
for
the
initial
5­
year
baseline
period
after
they
start
operating.
This
will
reduce
any
potential
generation
subsidy
and
be
easier
to
implement,
because
it
will
not
require
the
collection
and
processing
of
data
needed
for
regular
updating.
See
preamble
for
further
discussion
of
example
methodology.

This
methodology
is
offered
simply
as
an
example,
and
individual
States
retain
full
latitude
to
make
their
own
choices
regarding
what
type
of
allocation
method
to
adopt
for
Hg
allowances
and
are
not
bound
in
any
way
to
adopt
the
EPA's
example.

Comment:
5­
130
Several
commenters
(
OAR­
2002­
0056­
2862,
­
2911,
­
2922,
­
2948,
­
3546,
­
3556,
­
3565)
supported
permanent
mercury
allowance
allocations.
One
commenter
(
OAR­
2002­
0056­
2948)
believed
permanent
allocations
of
mercury
allowances
would
provide
units
with
the
greatest
amount
of
certainty,
would
provide
units
with
an
incentive
to
improve
energy
efficiency,
and
would
require
fewer
resources
to
administer
than
an
updated
allocation
system.
Several
commenters
(
OAR­
2002­
0056­
2911,
­
3556)
believed
that
such
a
system
would
provide
units
with
certainty
regarding
their
allowances,
facilitating
planning
for
the
implementation
of
controls
and
turnover
of
the
generating
fleet
­
all
of
which
would
work
towards
the
reduction
of
mercury
emissions
while
maintaining
the
reliability
of
the
power
supply
and
the
integrity
of
the
grid.

One
commenter
(
OAR­
2002­
0056­
2862)
stated
that
a
permanent
allowance
allocation
would
provide
certainty
and
aid
in
planning.
The
commenter
added
that
a
necessary
part
of
a
permanent
allocation
scheme
would
be
to
include
a
new
source
set
aside.
The
commenter
believed
a
permanent
allocation
approach
coupled
with
a
new
source
set
aside
would
be
less
complicated
than
EPA's
proposed
updating
approach
and
would
provide
units
with
the
greatest
amount
of
certainty
while
providing
a
mechanism
for
new
sources
to
receive
allowances.

The
commenter
(
OAR­
2002­
0056­
2721)
supported
free
distribution
of
allowances
that
are
permanently
assigned
to
the
affected
unit.
The
commenter
stated
that
allowing
a
periodically
(
5
years
in
EPA
example)
allocation
methodology
that
would
incorporate
new
units
would
cause
uncertainty
in
planning
for
environmental
compliance
strategies.
The
commenter
believed
that
allowances
should
be
issued
on
a
heat­
input
basis
using
the
established
baseline.

Response:

As
discussed
in
the
final
rule
preamble,
under
its
example
allocation
methodology,
EPA
has
finalized
for
the
model
rule
a
"
modified
output"
approach.
This
example
method
involves
input­
based
allocations
for
existing
coal
units
(
with
different
ratios
based
on
coal
type),
with
updating
to
take
into
account
new
generation
on
a
modified­
output
basis.
It
also
utilizes
a
new
source
set­
aside
for
new
units
that
have
not
yet
established
baseline
data
to
be
used
for
updating.
EPA
is
offering
States
flexibility
regarding
allocation
of
allowances
to
sources.
This
includes
the
flexibility
to
create
new
source
set­
asides
and/
or
to
issue
allowances
on
a
permanent
basis.
As
discussed
in
the
preamble,
EPA
does
not
believe
these
flexibilities
impact
the
total
cost
or
environmental
benefits
of
the
overall
rule.

The
commenter
is
also
inconsistent
in
supporting
a
new
source
set­
aside
while
condemning
programs
that
adjust
allowance
allocations
periodically.
A
new
source
set­
aside
(
where
unused
allowances
are
returned
to
existing
sources)
effectively
adjusts
allocations
periodically.

Comment:

One
commenter
(
OAR­
2002­
0056­
2721)
recommended
that
the
allocations
of
allowances
are
based
on
the
baseline
heat
input.
5­
131
Response:

As
discussed
in
the
final
rule
preamble,
under
its
example
allocation
methodology,
EPA
has
finalized
for
the
model
rule
a
"
modified
output"
approach.
This
example
method
involves
heat
input­
based
allocations
for
existing
coal
units
(
with
different
ratios
based
on
coal
type),
with
updating
to
take
into
account
new
generation
on
a
modified­
output
basis.
It
also
utilizes
a
new
source
set­
aside
for
new
units
that
have
not
yet
established
baseline
data
to
be
used
for
updating.
EPA
is
offering
States
flexibility
regarding
allocation
of
allowances
to
sources.

Comment:

One
commenter
(
OAR­
2002­
0056­
2181)
agreed
with
EPA
that
there
are
significant
benefits
associated
with
an
allocation
method
that
allows
for
updating
and
felt
that
the
rolling
annual
updating
system,
determining
allocation
for
a
single
control
period
six
years
in
advance,
would
be
a
reasonable
time
period
(
given
the
approximate
amount
of
time
required
to
permit
and
construct
a
coal­
fired
power
plant)
and
one
that
the
commenter
would
encourage
States
to
adopt.
The
commenter
submitted
however,
that
the
updating
approach
has
one
major
flaw
in
that
the
initial
allocation
baseline
does
not
change
over
time.
This
means
that
existing
plants
would
continue
to
receive
allowances
in
future
years,
even
if
they
are
shut
down.
On
the
other
hand,
new
plants
would
receive
allocations
forever
based
on
their
initial
years
of
operation,
which
could
be
significantly
less
than
their
ultimate
operating
levels
due
to
operation
and
competitive
limitations.
The
commenter
believed
strongly
that
an
updating
mechanism
with
responsive
adjustments
that
would
reflect
the
actual
operation
both
in
the
near
term
and
future
years
is
the
appropriate
method
that
EPA
should
adopt.

Response:

Under
the
EPA
example
method,
existing
units
as
a
group
will
not
update
their
heat
input.
This
will
eliminate
the
potential
for
a
generation
subsidy
(
and
efficiency
loss)
as
well
as
any
potential
incentive
for
less
efficient
existing
units
to
generate
more.
This
methodology
will
also
be
easier
to
implement
because
it
will
not
require
the
updating
of
existing
units'
baseline
data.
Retired
units
will
continue
to
receive
allowances
indefinitely,
thereby
creating
an
incentive
to
retire
less
efficient
units
instead
of
continuing
to
operate
them
in
order
to
maintain
the
allowance
allocations.
Moreover,
new
units
as
a
group
will
only
update
their
heat
input
numbers
once
 
for
the
initial
5­
year
baseline
period
after
they
start
operating.
This
will
reduce
any
potential
generation
subsidy
and
be
easier
to
implement,
because
it
will
not
require
the
collection
and
processing
of
data
needed
for
regular
updating.
See
preamble
for
further
discussion
of
example
methodology.

Comment:

One
commenter
(
OAR­
2002­
0056­
2547)
supported
EPA's
requirement
that
all
states
adopt
the
"
hypothetical"
hybrid
allowance
allocation
approach
it
describes
in
the
preamble
of
the
Supplemental
Rule.
The
commenter
submitted
that
since
many
facilities
are
exploring
the
use
of
Powder
River
Basin
coals
to
meet
reduced
SO
2
emission
requirements
of
the
proposed
CAIR
5­
132
rule,
the
mercury
allocation
method
should
be
structured
so
as
not
to
disadvantage
units
that
switch
to
this
higher
mercury
content
fuel
after
promulgation
of
the
mercury
rule.
The
commenter
believed
options
to
consider
would
be
not
using
adjustment
factors
at
all,
or
if
a
facility
switches
fuels
between
the
three
listed
fuel
types
 
bituminous,
sub­
bituminous,
and
lignite,
that
the
facility
notify
the
state
agency
requesting
additional
allowances
be
allocated
(
or
forfeiting
allowances
where
appropriate)
based
upon
the
difference
between
the
average
heat
inputs
calculated
in
60.4142(
a)(
1)(
i)(
A­
C)
for
the
fuel
type
for
which
the
allocations
were
initially
determined
and
for
the
new
fuel
type.
The
commenter
stated
this
should
be
done
in
the
spirit
of
promoting
multi­
pollutant
emission
reduction,
and
to
aid
in
achieving
the
goals
of
the
CAIR.

Response:

As
discussed
in
the
final
rule
preamble
under
EPA's
example
allocation
methodology,
EPA
is
finalizing
that
if
states
want
to
have
allocations
reflect
the
difficulty
of
controlling
Hg,
they
might
consider
multiplying
the
baseline
heat
input
data
by
ratios
based
on
coal
type,
similar
to
the
methodology
used
to
establish
the
State
Hg
budgets
in
today's
final
rulemaking.
In
today's
rulemaking
for
the
purposes
of
establishing
State
budgets,
EPA
is
using
the
coal
adjustment
factors
of
1.0
for
bituminous
coals,
1.25
for
subbituminous
coals
and
3.0
for
lignite
coals.
In
this
example
allocation
methodology
for
States,
EPA
is
also
using
these
adjustment
factors.
EPA
is
offering
States
flexibility
regarding
allocation
of
allowances
to
sources.
This
includes
the
flexibility
to
not
use
coal
adjustment
factors.

Commenter:

The
commenter
(
OAR­
2002­
0056­
2181)
believed
that
in
its
discussions
of
allowance
allocation
methodology,
the
EPA
argued,
"
allowance
allocation
decisions
in
a
cap
and
trade
program
largely
reflect
distributional
issues,
as
economic
forces
would
be
expected
to
result
in
economically
efficient
and
environmentally
similar
outcomes."
The
commenter
disagreed
with
this
conclusion,
and
believed
that
allocation
choices
could
have
a
significant
impact
on
economic
and
environmental
outcomes.
The
commenter
claimed
that
several
studies
supported
this
position
and
discussed
the
potential
economic
"
co­
benefits"
of
an
output
allocation
standard.
For
example,
a
study
by
the
Northeast­
Midwest
Institute
concluded
that
an
output­
based
allocation
standard
could
"
advance
an
array
of
innovative
technologies
that
would
offer
enormous
potential
to
improve
efficiency
and
enhance
the
environment."
Likewise,
a
policy
report
by
the
Pew
Center
for
Climate
Change
concluded
that
an
output­
based
allocation
standard
"
could
significantly
affect
the
ability
of
new,
highly
efficient
generation
technologies
to
enter
the
market."
Conversely,
the
Report
also
concluded
that
input
allocation
would
"
put
new
investments
in
clean
technologies
at
a
competitive
disadvantage."

The
commenter
noted
that
the
allocation
approach
recommended
by
the
EPA
would
be
a
hybrid
approach
that
would
include
some
of
the
desirable
components
but
would
be
lacking
in
other
areas.
EPA
first
recommended
that
existing
sources
follow
an
input­
based
system
with
different
allocation
ratios
based
on
coal­
type.
Next,
it
recommended
accommodating
new
sources
through
updates
to
the
allocation
on
a
modified
output
basis,
without
differentiating
between
coal
types.
The
commenter
welcomed
the
second
approach
that
EPA
selected
for
new
sources
as
a
5­
133
step
towards
a
full
output­
based
allocation
system.
The
commenter
believed
that
output­
based
allocation
would
be
the
appropriate
method
for
all
sources,
new
and
existing.
While
the
commenter
appreciated
that
the
hybrid
is
an
attempt
to
introduce
a
compromise
approach,
the
commenter
believed
the
result
would
perpetuate
a
disturbing
trend
toward
developing
two
sets
of
environmental
rules
within
the
nation's
power
sector
­
one
for
existing
power
sources
and
one
for
new
sources.
Such
a
two
tiered
system
not
only
would
create
inequities
among
competitors,
it
would
send
market
signals
that
may,
in
the
long
run,
lead
to
unintended
consequences
to
market
structures
within
the
power
sector
such
as
favoring
existing
generators
over
new
entrants
and
regulated
utilities
over
independent
producers.

Several
commenters
(
OAR­
2002­
0056­
3437,
­
4139)
recommended
that
allowances
be
set
based
on
energy
output.
Commenter
OAR­
2002­
0056­
3437
stated
that
would
reward
and
encourage
efficiency.
Similarly,
Commenter
OAR­
2002­
0056­
4139
submitted
an
energy
output
model
would
reward
conservation
and
renewable
energy
sources
and
encourage
cleaner
technology
development.

Response:

As
discussed
in
the
final
rule
preamble,
under
its
example
allocation
methodology,
EPA
has
finalized
for
the
model
rule
a
"
modified
output"
approach.
This
example
method
involves
heat
input­
based
allocations
for
existing
coal
units
(
with
different
ratios
based
on
coal
type),
with
updating
to
take
into
account
new
generation
on
a
modified­
output
basis.
It
also
utilizes
a
new
source
set­
aside
for
new
units
that
have
not
yet
established
baseline
data
to
be
used
for
updating.

The
EPA
believes
that
allocating
to
existing
units
based
on
a
baseline
of
historic
heat
input
data
(
rather
than
output
data)
is
desirable,
because
accurate
protocols
currently
exist
for
monitoring
this
data
and
reporting
it
to
EPA,
and
several
years
of
certified
data
are
available
for
most
of
the
affected
sources.
EPA
expects
that
any
problems
with
standardizing
and
collecting
output
data,
to
the
extent
that
they
exist,
can
be
resolved
in
time
for
their
use
for
new
unit
calculations.
Given
that
units
keep
track
of
electricity
output
for
commercial
purposes,
this
is
not
likely
to
be
a
significant
problem.

EPA
is
giving
States
flexibility
with
regards
to
the
allocations
of
the
its
Hg
budgets
to
sources.
EPA
notes
that
its
example
"
modified
output"
allocations
approach
incorporates
key
aspects
of
an
output
based
updating
system
and
provides
incentives
for
efficient
new
units.
Additionally,
EPA
reiterates
that
use
of
output
based
allocation
methodologies,
if
not
updated,
do
not
provide
incentives
for
behavior
or
for
new
generation.
They
only
provide
a
one­
time
transfer
amongst
existing
sources.

Comment:

One
commenter
(
OAR­
2002­
0056­
3443)
stated
that
the
model
rule
lays
out
a
rational
program
for
periodic
redistribution
to
individual
sources.
The
commenter
suggested
that
the
initial
allocation
period
be
extended
from
5
to
8
years
since
that
would
align
with
the
2018
Phase
5­
134
II
compliance
date.
This
would
avoid
an
unnecessary
reallocation
prior
to
the
2018
Phase
II
compliance
date.
The
commenter
noted
that
the
model
rule
proposed
that
allocations
after
the
initial
allocation
period
be
on
an
annual
basis
using
the
original
baseline
heat
inputs
for
existing
units.
For
new
units,
these
allocations
would
be
based
on
the
average
of
the
high
three
year
heat
inputs
(
calculated
from
generation
and
an
8000
Btu/
kwh
heat
rate).
The
commenter
believed
that
a
proposal
with
an
8­
year
initial
allocation
would
provide
a
sufficient
planning
horizon
for
responding
to
changes
in
allocations.
In
the
same
vein,
the
commenter
supported
EPA's
proposal
to
make
allocations
in
perpetuity
to
retired
units
as
it
would
provide
owners
an
incentive
to
retire
higher­
emitting
sources,
creating
a
multi­
pollutant
(
SO
2,
NO
x
and
Hg)
reduction
benefit.

Another
commenter
(
OAR­
2002­
0056­
3444)
stated
to
ensure
that
companies
are
able
to
recover
investments
made
in
control
equipment
and
use
of
clean
technologies,
the
commenter
believed
the
initial
allocation
of
allowances
should
be
fixed
for
the
existing
sources
for
the
period
from
2010
until
2020.
The
commenter
stated
that
the
certainty
associated
with
control
equipment
and
construction
investment
decisions
rely
on
a
source's
ability
to
realize
anticipated
allowance
excesses
to
generate
revenue
required
for
those
investments.
The
commenter
maintained
that
by
allocating
on
a
10­
year
basis
EPA
will
maintain
a
minimal
level
of
certainty
in
Utility
Unit
investments
and
also
provide
a
mechanism
for
mercury
allowances
to
encourage
new
coal
fired
Utility
Unit
entrants.
The
commenter
believed
that
maintaining
fuel
flexibility
is
key
to
the
security
and
reliability
of
the
electrical
grid
and
national
energy
supply.

One
commenter
(
OAR­
2002­
0056­
4132)
stated
that
EPA
must
provide
allocations,
which
align
with
the
long­
term
nature
of
the
emission
control
system
investments.
The
commenter
submitted
the
strategic
and
financial
planning
process
involved
with
the
industry
installing
billions
of
dollars
of
new
pollution
control
equipment
would
be
very
complex.
The
commenter
added
that
forecasting
the
value
of
emission
allowances
(
sale
or
purchase)
would
be
difficult.
The
commenter
believed
that
if
there
is
no
certainty
in
the
number
of
allowances
provided
in
later
years,
the
economic
analysis
for
such
projects
becomes
speculative.

The
commenter
strongly
encouraged
that
EPA
allocate
mercury
emission
allowances
for
a
time
period
that
would
align
with
the
economic
considerations
of
the
air
pollution
control
equipment
required
for
this
air
quality
improvement.
The
commenter
submitted
a
perpetual
allocation
consistent
with
the
current
Clean
Air
Act
SO
2
allocation
would
be
appropriate
and
necessary
for
utilities
to
determine
the
proper
investment
strategy.
The
commenter
also
submitted
that
early
reduction
credits
should
be
awarded
and
could
be
allocated
for
a
lesser
time
period.
The
commenter
also
believed
the
cap
and
trade
system
should
not
be
subject
to
flow
control.
The
commenter
stated
flow
control
would
greatly
reduce
incentives
for
early
reductions
and
hinder
economic
analysis.

Response:

As
discussed
in
the
final
rule
preamble,
under
its
example
allocation
methodology,
EPA
has
finalized
for
the
model
rule
a
"
modified
output"
approach.
Under
the
example
method,
allocations
are
made
from
the
State's
Hg
budget
for
the
first
five
control
periods
(
2010
through
2014)
of
the
model
cap­
and­
trade
program
for
existing
sources
on
the
basis
of
historic
baseline
5­
135
heat
input.
The
allowances
for
2015
and
later
will
be
allocated
from
the
State's
Hg
budget
annually,
six
years
in
advance,
taking
into
account
output
data
from
new
units
with
established
baselines
(
modified
by
the
heat
input
conversion
factor
to
yield
heat
input
numbers).
EPA
believes
this
5
year
period
provides
enough
certainty
and
planning
time
horizon.

Comment:

One
commenter
(
OAR­
2002­
0056­
2267)
noted
that
EPA
discussed
whether
allocations
should
be
based
on
baseline
heat
input
or
baseline
generating
output
under
the
cap­
and­
trade
approach.
69
FR
12408.
The
commenter
objected
to
a
strict
output­
based
allocation
method.
The
commenter
submitted
that
the
smaller
boilers
and
generators
owned
and
operated
by
municipalities
generally
are
less
efficient
in
terms
of
energy
output
per
heat
input
than
the
large
boilers
and
generators
operated
by
the
large
utilities.
The
commenter
believed
municipal
power
generators
would
be
placed
at
an
additional
competitive
disadvantage
by
the
budgets
being
set
on
this
basis.
Adding
this
to
the
disadvantage
of
a
smaller
customer
base
over
which
to
spread
the
emission
control
costs,
municipal
power
generators
would
face
multiple
competitive
disadvantages
relative
to
large
electric
utilities.

Ensuring
that
new
units
have
fair
access
to
allowances
was
a
concern
for
the
commenter
(
OAR­
2002­
0056­
2068).
In
concert
with
the
EPA's
"
example
methodology,"
the
commenter
suggested
allocations
be
determined
according
to
the
baseline
heat
input
of
affected
units.
As
outlined
in
the
Supplemental
Notice,
initial
allocations
for
existing
sources
should
be
made
for
the
first
five
control
periods
at
the
start
of
the
program
on
the
basis
of
heat
input
and
take
into
consideration
coal
type.
After
the
first
five
years,
the
budget
should
be
distributed
on
an
annual
basis,
taking
into
account
data
from
new
units.
The
baseline
heat
input
for
units
should
be
determined
by
averaging
the
three
highest
heat
input
years
out
of
a
five­
year
period,
and
allowances
should
be
reallocated
after
each
subsequent
five­
year
period.

Response:

As
discussed
in
the
final
rule
preamble,
under
its
example
allocation
methodology,
EPA
has
finalized
for
the
model
rule
a
"
modified
output"
approach.
This
example
method
involves
heat
input­
based
allocations
for
existing
coal
units
(
with
different
ratios
based
on
coal
type),
with
updating
to
take
into
account
new
generation
on
a
modified­
output
basis.
It
also
utilizes
a
new
source
set­
aside
for
new
units
that
have
not
yet
established
baseline
data
to
be
used
for
updating.

Comment:

One
commenter
(
OAR­
2002­
0056­
2862)
stated
that
allocations
to
retired
units
should
be
permanent.
The
commenter
noted
that
EPA's
definition
of
the
baseline
for
calculating
cap
and
trade
emission
allowances
does
not
address
the
issue
of
how
to
treat
units
retired
since
the
1998­
2002
proposed
baseline
period
(
69
FR
4703
and
proposed
40
CFR
60.4105
of
the
SNPR).
The
commenter
submitted
that
treatment
of
retired
units
is,
however,
very
important.
The
commenter's
position
was
that
units
retired
since
the
baseline
period
should
receive
budget
5­
136
allowances.
The
commenter
believed
if
allocations
were
not
made
to
retired
units,
the
rule
effectively
would
discourage
utility
system
modernization
and
penalize
environmental
improvement
efforts.

The
commenter
stated
ideally,
EPA's
rules
should
provide
incentives
for
utilities
to
retire
existing
coal­
fired
generating
plants
and
replace
them
with
plants
that
are
more
efficient
and
equipped
with
state­
of­
the­
art
environmental
controls.
At
a
minimum,
utilities
that
retire
units
that
were
operating
during
the
baseline
period
should
not
be
penalized.
The
commenter
explained
this
means
that
owners
should
be
allowed
to
hold
allowances
for
retired
units
that
were
operating
during
the
baseline
period,
and
be
able
to
apply
those
allowances
as
eligible
emission
currency
in
the
cap­
and­
trade
program.
The
commenter
concluded
that
a
permanent
allocation
system
would
ensure
that
retired
units
retain
their
allowances.

One
commenter
(
OAR­
2002­
0056­
4139)
stated
that
future
allocations
should
be
set
at
less
than
the
shutdown
facility
if
that
facility
is
replaced.
The
replacement
facility
should
meet
a
new
source
limit
to
emit
less
mercury
than
the
shutdown
plant
it
replaced.
The
commenter
submitted
that
if
permitting
and
construction
is
not
begun
in
a
specified
reasonable
time,
there
should
be
a
decrease
over
time
in
the
allocation
for
the
shut
down
declining
to
zero.
The
commenter
added
the
overall
state
budget
should
also
be
decreased
as
described.

Response:

As
discussed
in
the
final
rule
preamble,
under
its
example
allocation
methodology,
EPA
is
finalizing
January
1,
2001
as
the
cut­
off
on­
line
date
for
considering
units
as
existing
units.
Under
the
EPA
example
method,
existing
units
as
a
group
will
not
update
their
heat
input.
This
will
eliminate
the
potential
for
a
generation
subsidy
(
and
efficiency
loss)
as
well
as
any
potential
incentive
for
less
efficient
existing
units
to
generate
more.
This
methodology
will
also
be
easier
to
implement
because
it
will
not
require
the
updating
of
existing
units'
baseline
data.
Retired
units
will
continue
to
receive
allowances
indefinitely,
thereby
creating
an
incentive
to
retire
less
efficient
units
instead
of
continuing
to
operate
them
in
order
to
maintain
the
allowance
allocations.

Comment:

One
commenter
(
OAR­
2002­
0056­
2519)
encouraged
EPA
to
incorporate
a
provision
to
update
allowance
allocations
to
reflect
changes
in
electricity
generation.
The
commenter
offered
for
example,
the
West
is
one
of
the
fastest
growing
regions
of
the
country,
and
the
increasing
population
growth
will
mean
increased
electricity
demand.
In
order
to
keep
coal
as
a
viable
option
for
such
new
generation,
the
allowance
allocation
should
be
updated
periodically
to
match
increases
and
shifts
in
power
generation
at
existing
sources
and
new
sources.
Toward
that
end
the
commenter
recommended
that
the
allowance
allocation
should
be
updated
every
five
years.

Response:
5­
137
As
discussed
in
the
final
rule
preamble,
under
its
example
allocation
methodology,
EPA
has
finalized
for
the
model
rule
a
"
modified
output"
approach.
This
example
method
involves
heat
input­
based
allocations
for
existing
coal
units
(
with
different
ratios
based
on
coal
type),
with
updating
to
take
into
account
new
generation
on
a
modified­
output
basis.
It
also
utilizes
a
new
source
set­
aside
for
new
units
that
have
not
yet
established
baseline
data
to
be
used
for
updating.

Comment:

One
commenter
(
OAR­
2002­
0056­
2267)
requested
that
EPA
make
a
change
to
the
rule
to
allocate
additional
allowances
to
the
entities
in
recognition
of
the
their
foresight
and
progressive
in
investment
in
hydroelectric
power
(
or
other
green
power)
when
cheaper
energy
choices
could
have
been
made.
As
it
stood,
the
commenter's
municipality
ultimately
would
be
penalized,
rather
than
rewarded,
for
its
early
focus
on
reducing
emissions
from
its
power
generation
system.
To
address
this
situation,
the
commenter
requested
that
the
budget
allocation
be
based
on
potential
or
projected
heat
input
rate
for
entities
such
as
the
commenters.
By
granting
this
request,
EPA
would
ensure
that
the
commenter's
and
other
similar
entities
have
enough
allowances
to
provide
reliable
power
generation
at
an
affordable
price.
As
an
alternative
solution,
the
commenter
requested
that
EPA
provide
in
its
model
trading
program
rules
for
the
use
of
a
different
time
period
to
calculate
baseline
heat
input
for
situations
described
above.
The
commenter
cited
precedence
under
the
Clean
Air
Act
for
substitution
of
baseline
data
when
a
baseline
period
is
not
representative
of
normal
source
operation.
See
40
CFR
52.21(
21)(
ii)
(
NSR
rules).
The
commenter
stated
EPA
has
recognized
that
it
should
have
discretion
to
allow
the
use
of
a
different
time
period
upon
a
determination
that
it
is
more
representative
of
normal
source
operation.
The
commenter
recommended
that
EPA
should
exercise
similar
discretion
in
this
case.

Response:

State
are
required
to
achieve
the
mercury
reduction
requirements
by
reducing
Hg
emissions
from
coal­
fired
power
plants.
States
are
welcome
to
use
set­
asides
(
size
determined
by
the
State)
for
new
units
and
any
special
policy
objectives
­
such
as
promoting
energy
efficiency
or
renewables.
The
States,
rather
than
this
regulation
can
decide
the
best
way
to
incorporate
renewable
incentives.

5.7.2
Baseline
Period
for
Allocations
Comment:

One
commenter
(
OAR­
2002­
0056­
3478)
supported
the
use
of
the
average
of
the
highest
three­
year
heat
inputs
achieved
during
the
five­
year
period
of
1998
to
2002
as
the
baseline
for
establishing
plant
mercury
allocations.

Several
commenters
(
OAR­
2002­
0056­
2867,
­
2922,
­
2948,
­
3437,
­
3565)
noted
the
proposed
calculation
of
the
baseline
heat
input
by
"
using
the
average
of
the
three
highest
heat
inputs
of
the
period
1998
to
2002"
and
suggested
using
a
more
current
period.
Two
of
the
5­
138
commenters
(
OAR­
2002­
0056­
2922,
­
2948)
suggested
using
the
average
of
the
three
highest
heat
inputs
of
the
period
1999
to
2003.
These
commenters
believed
this
approach
would
use
a
period
that
would
be
closer
in
time
to
the
commencement
of
the
trading
program
under
EPA's
proposal
and
still
would
avoid
opportunities
to
affect
the
baseline
through
prospective
actions.
One
of
the
commenters
(
OAR­
2002­
0056­
3565)
strongly
urged
EPA
to
use
the
average
of
the
three
highest
heat
inputs
of
the
period
1998
to
2002.

One
commenter
(
OAR­
2002­
0056­
2867)
recommended
that
EPA
consider
using
the
average
heat­
input
of
the
highest
of
three
years
from
the
period
which
begins
six
years
prior
to
the
implementation
of
the
cap
(
2004
if
the
cap
takes
effect
in
2010
as
proposed
or
2009
if
the
cap
takes
effect
in
2015
under
the
commenter's
recommended
program)
to
account
for
growth
in
electricity
demand,
changes
in
the
generation
fleet,
the
inherent
variability
in
heat
input
levels
for
individual
units,
and
for
weather
and
demand
induced
variability.

One
commenter
(
OAR­
2002­
0056­
3437)
noted
that
EPA
did
not
mention
updating
the
baseline
heat
input
based
on
more
recent
years
of
operation.
The
commenter
stated
that
the
rule
would
use
the
same
baseline
throughout
time.
The
commenter
believed
this
would
help
in
having
to
track
annual
operating
data,
but
it
was
not
clear
to
the
commenter
if
this
would
increase
or
decrease
a
unit's
allowances
if
the
heat
input
data
was
update.
The
commenter
noted
EPA
says
this
is
preferable
because
it
would
eliminate
a
potential
generation
subsidy
and
an
incentive
for
less
efficient
generation.
The
commenter
stated
that
EPA
should
use
an
output
based
emission
rate
to
address
efficient
generation
and
a
system
that
would
use
updated
heat
input
to
more
accurately
reflect
industry
changes.

Response:

For
existing
units
under
the
model
trading
rule,
EPA
is
using
the
average
of
the
highest
three­
year
heat
inputs
achieved
during
the
five­
year
period
of
2000
to
2004
as
the
baseline
for
establishing
plant
mercury
allocations.
EPA
proposed
January
1,
2001,
cut­
off
on­
line
date
for
considering
units
as
existing
units.
The
cut­
off
on­
line
date
was
selected
so
that
any
unit
meeting
the
cut­
off
date
would
have
at
least
five
years
of
operating
data,
i.
e.,
data
for
2000
through
2004.
EPA
is
concerned
with
ensuring
that
particular
units
are
not
disadvantaged
in
their
allocations
by
having
insufficient
operating
data
on
which
to
base
the
allocations.
EPA
believes
that
a
5­
year
window,
starting
from
commencement
of
operation,
gives
units
adequate
time
to
collect
sufficient
data
to
provide
a
fair
assessment
of
their
operations.

As
discussed
in
the
final
rule
preamble,
under
its
example
allocation
methodology,
EPA
has
finalized
for
the
model
rule
a
"
modified
output"
approach.
This
example
method
involves
heat
input­
based
allocations
for
existing
coal
units
(
with
different
ratios
based
on
coal
type),
with
updating
to
take
into
account
new
generation
on
a
modified­
output
basis.
It
also
utilizes
a
new
source
set­
aside
for
new
units
that
have
not
yet
established
baseline
data
to
be
used
for
updating.

The
EPA
believes
that
allocating
to
existing
units
based
on
a
baseline
of
historic
heat
input
data
(
rather
than
output
data)
is
desirable,
because
accurate
protocols
currently
exist
for
5­
139
monitoring
this
data
and
reporting
it
to
EPA,
and
several
years
of
certified
data
are
available
for
most
of
the
affected
sources.
Under
the
EPA
example
method,
existing
units
as
a
group
will
not
update
their
heat
input.
This
will
eliminate
the
potential
for
a
generation
subsidy
(
and
efficiency
loss)
as
well
as
any
potential
incentive
for
less
efficient
existing
units
to
generate
more.
This
methodology
will
also
be
easier
to
implement
because
it
will
not
require
the
updating
of
existing
units'
baseline
data.
Retired
units
will
continue
to
receive
allowances
indefinitely,
thereby
creating
an
incentive
to
retire
less
efficient
units
instead
of
continuing
to
operate
them
in
order
to
maintain
the
allowance
allocations.

Comment:

One
commenter
(
OAR­
2002­
0056­
2267)
requested
that
EPA
provide
in
its
model
trading
program
rules
for
the
use
of
a
different
time
period
to
calculate
baseline
heat
input
for
situations
where
to
allocate
additional
allowances
to
the
entities
in
recognition
of
their
foresight
and
progressive
investment
in
hydroelectric
power
(
or
other
green
power)
such
as
Boiler
#
9.
The
commenter
stated
there
is
precedence
under
the
Clean
Air
Act
for
substitution
of
baseline
data
when
a
baseline
period
is
not
representative
of
normal
source
operation.
See
40
CFR
2.21(
21)(
ii)
(
NSR
rules).
The
commenter
noted
that
EPA
has
recognized
that
it
should
have
discretion
to
allow
the
use
of
a
different
time
period
upon
a
determination
that
it
is
more
representative
of
normal
source
operation.
The
commenter
urged
that
EPA
should
exercise
similar
discretion
in
this
case.

Response:

For
existing
units
under
the
model
trading
rule,
EPA
is
using
the
average
of
the
highest
three­
year
heat
inputs
achieved
during
the
five­
year
period
of
2000
to
2004
as
the
baseline
for
establishing
plant
mercury
allocations.
EPA
proposed
January
1,
2001,
cut­
off
on­
line
date
for
considering
units
as
existing
units.
The
cut­
off
on­
line
date
was
selected
so
that
any
unit
meeting
the
cut­
off
date
would
have
at
least
five
years
of
operating
data,
i.
e.,
data
for
2000
through
2004.
EPA
is
concerned
with
ensuring
that
particular
units
are
not
disadvantaged
in
their
allocations
by
having
insufficient
operating
data
on
which
to
base
the
allocations.
EPA
believes
that
a
5­
year
window,
starting
from
commencement
of
operation,
gives
units
adequate
time
to
collect
sufficient
data
to
provide
a
fair
assessment
of
their
operations.

States
are
required
to
achieve
the
mercury
reduction
requirements
by
reducing
Hg
emissions
from
coal­
fired
power
plants.
States
are
welcome
to
use
set­
asides
(
size
determined
by
the
State)
for
new
units
and
any
special
policy
objectives
 
such
as
promoting
energy
efficiency
or
renewables.
The
States,
rather
than
this
regulation
can
decide
the
best
way
to
incorporate
renewable
incentives.

Comment:

One
commenter
(
OAR­
2002­
0056­
2918)
understood
that
in
the
event
that
EGUs,
burning
a
mixture
of
coal
ranks,
the
MACT
compliance
limit
will
be
adjusted
based
on
pro­
rata
heat
input
calculation
of
each
of
the
coal
ranks
in
the
mix
of
coal
burned.
Consistent
with
such
an
5­
140
adjustment,
the
commenter
recommended
that
EPA
adopt
a
provision
making
each
EGU
responsible
for
obtaining
periodic
ASTM
laboratory
test
data
on
coal
burned
by
the
EGU
for
each
compliance
period.

Similarly,
if
EPA
adopts
a
cap
and
trade
program,
the
commenter
recommended
that
EGU
owners
be
provided
an
opportunity
to
submit
more
recent
coal
rank
data
obtained
by
ASTM
laboratory
test
methods
for
the
coal
burned
during
a
time
period
that
reflects
more
contemporary
usage.
The
commenter
stated
that
such
coal
rank
data
should
be
used
by
EPA
in
allocating
Hg
emission
trading
credits
for
the
future
year
period(
s)
designated
in
the
proposed
cap
and
trade
rule.

Whether
EPA
adopts
Hg
MACT
emissions
limits,
or
alternatively
a
Hg
cap
and
trade
program,
the
commenter
stated
that
their
recommendation
will
provide
EGU
owners
the
opportunity
to
adjust
their
Hg
compliance
requirements
based
on
current
coals
burned.
The
commenter
noted
that
coal
fired
EGUs
do
change
coal
suppliers
and
coal
ranks
over
time
because
of
changing
market
conditions
and
regulatory
requirements.
As
such
the
commenter
believed
their
proposal
would
add
additional
equity
to
EPA's
Hg
compliance
requirements
for
EGUs.

Response:

As
discussed
in
the
final
rule
preamble,
under
its
example
allocation
methodology,
EPA
has
finalized
for
the
model
rule
a
"
modified
output"
approach.
This
example
method
involves
heat
input­
based
allocations
for
existing
coal
units
(
with
different
ratios
based
on
coal
type),
with
updating
to
take
into
account
new
generation
on
a
modified­
output
basis.
It
also
utilizes
a
new
source
set­
aside
for
new
units
that
have
not
yet
established
baseline
data
to
be
used
for
updating.

For
existing
units
under
the
model
trading
rule,
EPA
is
using
the
average
of
the
highest
three­
year
heat
inputs
achieved
during
the
five­
year
period
of
2000
to
2004
as
the
baseline
for
establishing
plant
mercury
allocations.
EPA
proposed
January
1,
2001,
cut­
off
on­
line
date
for
considering
units
as
existing
units.
The
cut­
off
on­
line
date
was
selected
so
that
any
unit
meeting
the
cut­
off
date
would
have
at
least
five
years
of
operating
data,
i.
e.,
data
for
2000
through
2004.
EPA
is
concerned
with
ensuring
that
particular
units
are
not
disadvantaged
in
their
allocations
by
having
insufficient
operating
data
on
which
to
base
the
allocations.
EPA
believes
that
a
5­
year
window,
starting
from
commencement
of
operation,
gives
units
adequate
time
to
collect
sufficient
data
to
provide
a
fair
assessment
of
their
operations.

The
EPA
believes
that
allocating
to
existing
units
based
on
a
baseline
of
historic
heat
input
data
(
rather
than
output
data)
is
desirable,
because
accurate
protocols
currently
exist
for
monitoring
this
data
and
reporting
it
to
EPA,
and
several
years
of
certified
data
are
available
for
most
of
the
affected
sources.
Under
the
EPA
example
method,
existing
units
as
a
group
will
not
update
their
heat
input.
This
will
eliminate
the
potential
for
a
generation
subsidy
(
and
efficiency
loss)
as
well
as
any
potential
incentive
for
less
efficient
existing
units
to
generate
more.
This
methodology
will
also
be
easier
to
implement
because
it
will
not
require
the
updating
of
existing
units'
baseline
data.
5­
141
5.7.3
New
Units
Comment:

One
commenter
(
OAR­
2002­
0056­
3437)
did
not
support
EPA's
proposed
alternative
of
using
the
lower
of
the
NSPS
for
the
different
coal
types
or
a
rate
based
on
the
proposed
2018
cap
rather
than
using
a
single
emission
rate
for
new
units.
The
commenter
stated
that
while
this
approach
may
address
the
differences
between
coal
types
and
new
and
existing
units,
the
commenter
would
still
be
concerned
that
using
different
information
based
on
coal
type
could
lead
to
fuel
switching
and
the
possibility
of
not
achieving
the
desired
reductions.

One
commenter
(
OAR­
2002­
0056­
3543)
understood
that
new
sources
would
be
required
to
hold
allowances
equivalent
to
the
product
of
their
NSPS
and
baseline
heat
input.
The
commenter
stated
however,
EPA
is
unclear
what
will
be
proposed
as
the
baseline
for
new
sources.

One
commenter
(
OAR­
2002­
0056­
3543)
found
the
proposal
unclear
regarding
how
new
sources
would
be
treated
under
a
cap
and
trade
approach.
The
commenter
noted
new
sources
would
be
required
to
comply
with
the
NSPS
for
mercury
and
be
required
to
hold
allowances.
The
commenter
asked
would
new
sources
be
given
an
allocation
or
is
this
up
to
the
discretion
of
the
states?

Response:

As
discussed
in
the
final
rule
preamble,
under
its
example
allocation
methodology,
EPA
is
finalizing
the
approach
that
new
units
will
begin
receiving
allowances
from
the
set­
aside
for
the
control
period
immediately
following
the
control
period
in
which
the
new
unit
commences
commercial
operation,
based
on
the
unit's
emissions
for
the
preceding
control
period.
Thus,
a
source
will
be
required
to
hold
allowances
during
its
start­
up
year,
but
will
not
receive
an
allocation
for
that
year.
States
will
allocate
allowances
from
the
set­
aside
to
all
new
units
in
any
given
year
as
a
group.
If
there
are
more
allowances
requested
than
in
the
set­
aside,
allowances
will
be
distributed
on
a
pro­
rata
basis.
Allowance
allocations
for
a
given
new
unit
in
following
years
will
continue
to
be
based
on
the
prior
year's
emissions
until
the
new
unit
establishes
a
baseline,
is
treated
as
an
existing
unit,
and
is
allocated
allowances
through
the
State's
updating
process.
This
will
enable
new
units
to
have
a
good
sense
of
the
amount
of
allowances
they
will
likely
receive
­
in
proportion
to
their
emissions
for
the
previous
year.
This
methodology
will
not
provide
allowances
to
a
unit
in
its
first
year
of
operation;
however
it
is
a
methodology
that
is
straightforward,
reasonable
to
implement,
and
predictable.

Although
EPA
is
offering
an
example
allocation
method
with
accompanying
regulatory
language,
EPA
reiterates
that
it
recognizes
States'
flexibility
in
choosing
their
Hg
allocations
method.

Comment:
5­
142
Many
commenters
(
OAR­
2002­
0056­
2067,
­
2422,
­
2818,
­
2911,
­
2915,
­
2922,
­
3198,
­
3443,
­
3444,
­
3514,
­
3519)
believed
that
the
cap­
and­
trade
program
should
have
a
set
aside
for
new
sources.
Several
of
these
commenters
(
OAR­
2002­
0056­
2818,
­
2911,
­
2915,
­
3198)
noted
that
a
modest
set
aside
would
be
consistent
with
the
Acid
Rain
Program.

Several
commenters
(
OAR­
2002­
0056­
2818,
­
3198)
submitted
that
this
will
ensure
that
new
units
operating
in
compliance
with
the
NSPS
will
have
legitimate
access
to
allowances.
One
commenter
(
OAR­
2002­
0056­
2915)
stated
that
new
unit
development
is
critical
to
the
continued
use
and
development
of
Gulf
Coast
lignite
for
electric
generation
in
Texas.

Commenter
OAR­
2002­
0056­
2911
suggested
that
once
the
size
of
the
permanent
allocation
pool
is
determined,
a
small
percentage
of
those
allocations,
2
percent
for
example,
can
be
set
aside
for
new
units
each
year.
The
commenter
further
suggested
that
any
unused
allocations
would
be
returned
to
the
pool
for
the
other
affected
units.
According
to
the
commenter,
similar
concepts
have
been
successfully
incorporated
into
the
trading
program
used
for
the
NO
x
SIP
Call.

Several
commenters
(
OAR­
2002­
0056­
3443,
­
3519)
submitted
that
the
model
rule
proposal
for
a
two
percent
new
source
set­
aside
was
reasonable.
One
commenter
(
OAR­
2002­
0056­
3443)
believed
this
would
be
sufficient
to
prevent
any
inhibition
to
entry
of
new
units
in
the
market.
The
commenter
asserted
that
redistribution
of
unused
allowances
from
the
set­
aside
to
existing
units
is
a
critical
piece
of
this
proposal.
The
commenter
believed
the
model
rule
should
require
that
this
redistribution
be
completed
in
time
for
existing
sources
to
use
them
in
the
same
budget
year.

One
commenter
(
OAR­
2002­
0056­
3519)
believed
that
new
units
should
be
defined
as
EGUs
starting
operation
after
the
date
of
final
rule
adoption.
One
commenter
(
OAR­
2002­
0056­
2922)
stated
that
if
EPA
chooses
a
"
cap­
and­
trade"
program,
it
must
ensure
that
new
facilities
have
reasonable
access
to
mercury
emission
allowances.

Similarly,
one
commenter
(
OAR­
2002­
0056­
2067)
stated
that
the
proposed
Cap
and
Trade
alternative
must
give
economic
access
to
allocations
to
new
power
plants
to
allow
for
effective
planning
for
construction
of
new
units
to
meet
growth
and
to
replace
retiring
units.
The
commenter
asserted
that
the
Cap
and
Trade
mechanism
should
not
create
obstacles
to
retiring
older
units
or
to
adding
new
generation
to
ensure
adequate
security
and
reliability.

One
commenter
(
OAR­
2002­
0056­
3444)
stated
the
cap
and
trade
program
should
provide
new
unit
set
asides
for
new
units
operating
prior
to
2010.

One
commenter
(
OAR­
2002­
0056­
2725)
stated
that
the
West
is
one
of
the
fastest
growing
regions
in
the
country,
and
new
coal
plants
are
vital
to
affordable
energy
prices
in
the
future
and
will
be
essential
to
continued
growth
in
the
economy.
The
commenter
noted
the
DOE's
Energy
Information
Administration
projects
a
significant
increase
in
construction
of
new
coal­
based
power
plants;
the
DOE/
EIA
Annual
Energy
Outlook
2004
with
projections
to
2025
forecasts
the
addition
of
112
Gigawatts
of
new
coal
generating
capacity.
According
to
the
5­
143
commenter,
if
these
new
plants
were
to
be
prevented
from
being
constructed
because
of
new
mercury
regulations,
the
only
alternative
for
this
needed
capacity
would
be
natural
gas.
The
commenter
stated
that
due
to
physical
and
regulatory
constraints,
the
supply
of
natural
gas
is
not
able
to
affordably
meet
its
demand.

Over
the
next
several
years,
the
commenter
expected
several
new,
clean
coal
units
to
come
on
line
in
the
West,
and
submitted
that
EPA
should
not
burden
these
new
units
with
overly
stringent
emission
control
requirements.
Thus,
the
commenter
supported
adopting
the
allocation
of
mercury
allowances
for
new
units
under
the
trading
approach
consistent
with
Senator
Inhofe's
approach
to
Clear
Skies.

Many
commenters
(
OAR­
2002­
0056­
2042,
­
2375,
­
2422,
­
2519,
­
2862,
­
2907,
­
2815,
­
2922,
­
3440,
­
3478,
­
3556,
­
3565,
­
4191,
­
4891)
stated
there
should
be
a
modest
mercury
allowance
set­
aside
for
new
units.
Many
of
the
commenters
(
OAR­
2002­
0056­
2375,
­
2422,
­
2519,
­
2915,
­
3440,
­
3478,
­
3556,
­
3565,
­
4191,
­
4891)
suggested
the
new
unit
set
aside
should
be
consistent
with
the
2
percent
set
aside
for
new
facilities
in
Title
IV
Acid
Rain
Program.
Several
commenters
(
OAR­
2002­
0056­
2915,
­
3440,
­
3478,
­
4191)
believed
new
unit
development
would
be
critical
to
the
continued
use
and
development
of
lignite
for
electric
generation
in
Texas.
One
commenter
(
OAR­
2002­
0056­
3556)
stated
that
any
unused
allocations
would
be
returned
to
the
pool
for
the
other
affected
units.
The
commenter
also
stated
that
similar
concepts
have
been
successfully
incorporated
into
the
trading
program
used
for
the
NO
x
SIP
Call.
Similarly,
a
second
commenter
(
OAR­
2002­
0056­
2375)
suggested
the
unused
portion
of
the
set
aside
should
be
returned
to
existing
sources
on
a
pro
rata
basis.
One
commenter
(
OAR­
2002­
0056­
2907)
stated
that
as
we
enter
a
new
era
where
demand
is
beginning
to
exceed
supply,
new
generation
becomes
essential.
The
commenter
added,
new
coal
generation
is
cleaner
and
more
efficient
than
existing
plants.
The
commenter
believed
that
EPA
should
use
an
approach
similar
to
that
used
in
the
Clear
Skies
Act
to
allocate
mercury
allowances
to
new
units
under
a
mercury
cap
and
trade
program.
One
commenter
(
OAR­
2002­
0056­
3565)
believed
that
new
units
should
also
be
able
to
acquire
mercury
allowances
from
the
allowance
market.

One
commenter
(
OAR­
2002­
0056­
2422)
noted
that
under
a
cap­
and­
trade
approach,
EPA
has
proposed
NSPS
emission
limits
equivalent
to
the
NSPS
proposed
under
the
112(
d)
regulations.
The
commenter
believed
the
limit
was
set
at
a
level
that
could
not
be
achieved
by
the
best
performing
units,
and
should
be
adjusted
upward.
The
commenter
was
concerned
that
a
cap­
and­
trade
program
would
add
another
significant
burden
to
new
units
if
they
are
not
allocated
emission
allowances.
New
units
would
be
left
to
pursue
allowances
on
the
open
market,
with
no
guarantee
of
access.
The
commenter
stated
that
EPA
should
reconsider
how
it
will
ensure
that
new
units
operating
in
compliance
with
the
NSPS
will
have
legitimate
access
to
allowances.
The
commenter
suggested
that
this
could
be
achieved,
for
example,
by
requiring
a
modest
set­
aside
of
allowances
from
existing
units,
similar
to
the
approach
taken
in
the
Title
IV
acid
rain
program.

One
commenter
(
OAR­
2002­
0056­
4891)
stated
that
as
proposed,
the
mercury
rule
would
discourage
the
development
of
new
power
plants
given
that
it
would
require
new
sources
to
procure
allowances
from
the
same
pool
of
allowances
applicable
to
existing
sources.
The
commenter
submitted
that
jeopardizing
the
ability
to
develop
new
power
plants
would
ultimately
5­
144
put
an
untenable
strain
on
the
ability
to
meet
the
ever­
increasing
demand
for
affordable
electricity
in
Texas
and
throughout
the
U.
S.
The
commenter
believed
that
to
avoid
this
clearly
undesirable
result
and
ensure
the
continued
development
of
new
plants,
new
power
plants
should
either
be
exempted
from
the
requirement
to
obtain
allowances,
or
be
provided
an
allowance
set­
aside
specifically
for
new
units
comparable
to
the
2
percent
set­
aside
for
new
facilities
in
the
Title
IV,
Acid
Rain
Program.

One
commenter
(
OAR­
2002­
0056­
4891)
submitted
that
only
existing
facilities
subject
to
the
mercury
rule
should
receive
allowances.
The
commenter
noted
that
as
proposed,
the
mercury
rule
would
discourage
the
development
of
new
power
plants
given
that
it
would
require
new
sources
to
procure
allowances.
Jeopardizing
the
ability
to
develop
new
power
plants
would
ultimately
put
an
untenable
strain
on
the
ability
to
meet
the
ever­
increasing
demand
for
affordable
electricity
in
Texas
and
throughout
the
U.
S.
To
avoid
this
clearly
undesirable
result
and
ensure
the
continued
development
of
new
plants,
the
commenter
stated
new
power
plants
should
be
exempted
from
the
requirement
to
obtain
allowances.

One
commenter
(
OAR­
2002­
0056­
2243)
was
concerned
with
how
allowance
programs
are
being
developed.
According
to
the
commenter,
when
new
projects
were
primarily
gas­
fired,
the
availability
of
an
adequate
allowance
pool
for
new
sources
was
not
as
important
as
it
is
today.
The
commenter
pointed
out
that
as
coal­
fired
projects
are
conceived,
the
availability
of
access
into
the
allowance
market
is
critical.
The
commenter
added
that
encouraging
new
project
development
is
vital
from
both
an
economic
and
environmental
point
of
view.

Response:

As
discussed
in
the
final
rule
preamble,
the
example
allocation
methodology
includes
a
new
source
set­
aside
equal
to
5
percent
of
the
State's
emission
budget
for
the
years
2010
to
2014
and
3
percent
of
the
State's
emission
budget
for
the
subsequent
years.
This
is
a
change
from
the
SNPR
were
EPA
proposed
a
level
2
percent
set
aside
for
all
years.

One
commenter
pointed
to
EIA
forecasts
for
coal
to
grow
by
112
gigawatts
(
GW)
by
2025
and
EPA
economic
modeling
projects
growth
in
coal
by
2020.
In
order
to
estimate
the
need
for
allocations
for
new
units,
EPA
considered
projected
growth
in
coal
generation
and
the
resulting
Hg
emissions
portion
of
the
Hg
national
cap.
EPA
believes
the
final
new
source
set­
aside
provides
for
that
growth.

Because
States
have
flexibility
in
choosing
their
Hg
allocations
method,
individual
States
using
a
version
of
the
example
method
may
want
to
adjust
this
initial
five
year
set­
aside
amount
to
a
number
higher
or
lower
than
5
percent
to
the
extent
that
they
expect
to
have
more
or
less
new
generation
going
on­
line
during
the
2001
to
2013
period.
They
may
also
want
to
adjust
the
subsequent
set­
aside
amount
to
a
number
higher
or
lower
than
2
percent
to
the
extent
that
they
expect
more
or
less
new
generation
going
on­
line
after
2004.
States
may
also
want
to
set
this
percentage
a
little
higher
than
the
expected
need,
because,
in
the
event
that
the
amount
of
the
set­
aside
exceeds
the
need
for
new
unit
allowances,
the
State
may
want
to
provide
that
any
5­
145
unused
set­
aside
allowances
will
be
redistributed
to
existing
units
in
proportion
to
their
existing
allocations.

Comment:

One
commenter
(
OAR­
2002­
0056­
2830)
believed
the
heat
rate
conversion
factor
of
8,000
Btu/
kWh
was
too
low
for
Fort
Union
lignite
fired
EGUs.
The
commenter
stated
that
heat
rates
for
units
utilizing
Fort
Union
lignite
have
improved
over
time.
According
to
the
commenter,
the
recent
historical
heat
rate
for
existing
Fort
Union
lignite­
fired
boilers
is
just
under
11,000
Btu/
gross
kWhr.
The
commenter
recommended
that
a
heat
rate
conversion
factor
of
9,700
Btu/
gross
MWhr
be
employed
for
new
lignite­
fired
units
(
69
FR
12409).

One
commenter
(
OAR­
2002­
0056­
2841)
stated
that
the
rule
should
not
discourage
new
coal
units.
The
commenter
noted
that
new
units
undergoing
permitting
and/
or
under
construction
would
not
have
the
ability
to
establish
a
baseline
heat
input
until
going
into
commercial
operation.
The
commenter
also
noted
EPA
has
proposed
an
alternative
to
address
the
issue
of
no
baseline
by
suggesting
that
the
updated
allocation
for
such
units
be
adjusted
by
calculating
the
heat
input
for
such
units
by
multiplying
the
unit's
output
by
a
heat
rate
conversion
factor
of
8000
btu/
kWh.
EPA
suggested
that
the
8000
btu/
kWh
rate
represents
a
midpoint
between
expected
heat
rates
for
new
pulverized
coal
plants
and
new
integrated
gasification
combined
cycle
(
IGCC)
coal
plants.
The
stated
purpose
for
such
an
approach
is
to
create
level
benefits
for
new
units
based
on
their
output
and
encouraging
efficiency.
In
principle,
the
commenter
agreed
with
the
approach
selected
by
EPA
to
address
units
that
will
not
have
an
established
baseline.
However,
the
commenter
believed
the
selected
conversion
rate
of
8000
btu/
kWh
rate
cannot
be
supported
and
would
unduly
penalize
new
units.

The
commenter
stated
the
range
of
heat
rates
for
IGCC
units
can
be
anywhere
from
8400
btu/
kWh
to
9500
btu/
kWh.
Accordingly,
the
commenter
did
not
believe
the
midpoint
between
IGCC
and
supercritical
was
appropriately
established
at
8000
btu/
kWh.
Given
the
current
state
of
IGCC
technology
and
the
range
of
heat
rates,
the
commenter
did
not
believe
that
EPA
should
try
to
establish
any
presumed
incentive
for
IGCC.
Instead,
EPA
should
only
utilize
a
rate
that
provides
incentive
to
proven
technology
such
as
construction
of
a
supercritical
pulverized
coal
boiler
that
can
be
supported
by
Public
Utility
Commissions.
The
commenter
recommended
a
conversion
factor
of
8900
btu/
kWh
that
would
provide
the
incentive
to
build
supercritical
units,
while
not
penalizing
companies
through
the
utilization
of
an
unrealistic
and
unsupportable
conversion
factor.
Similarly,
the
commenter
believed
the
conversion
factor
should
not
have
the
unintended
consequence
of
encouraging
the
further
utilization
of
natural
gas
for
the
production
of
electricity.

Similarly,
one
commenter
submitted
that
the
model
rule's
use
of
an
8000
Btu/
kWh
assumed
heat
rate
for
calculating
allowance
allocations
appeared
to
be
a
mistake.
The
cmmenter
noted
that
the
model
rule
states
that
8000
Btu/
kWh
represents
the
"
mid­
point"
between
the
heat
rate
expected
of
new
conventional
coal
and
IGCC
units.
However,
in
the
supplemental
CAIR
the
same
8000
Btu/
kWh
is
used
as
the
"
mid­
point
between
gas
fired
combined
cycle
units
and
conventional
coal
units.
The
commenter
agreed
the
8000
Btu/
kWh
mid­
point
is
reasonable
for
5­
146
CAIR.
However,
the
commenter
pointed
out
that
existing
IGCC
units
have
heat
rates
in
the
mid
8000s
and
conventional
coal
units
have
heat
rates
in
the
mid
to
lower
9000s.
Consequently,
the
commenter
believed
9000
Btu/
kWh
is
the
more
appropriate
mid­
point
for
the
mercury
model
rule.

The
commenter
also
had
concerns
about
using
the
midpoint
approach
at
all
since
it
would
clearly
favor
IGCC
technology
over
conventional
coal
technology.
The
commenter
encouraged
EPA
to
consider
a
separate
heat
rate
for
IGCC
and
conventional
coal
units.
The
commenter
pointed
out
that
the
DOE
clean
coal
roadmap
goals
for
2010
indicate
that
9000
Btu/
kWh
for
conventional
coal
and
8000
Btu/
kWh
for
IGCC
would
be
reasonable
heat
rates.

The
commenter
(
OAR­
2002­
0056­
2721)
submitted
that
the
new
unit
mercury
allocation
utilizing
the
modified
heat
output
basis
again
places
low
rank
fuels
at
a
distinct
disadvantage.
The
commenter
noted
that
the
modified
heat
output
based
procedure
would
take
the
three
highest
of
the
first
five
years
of
gross
output
and
multiply
it
by
a
conversion
factor
of
8,000
btu/
kWH.
The
commenter
stated
that
this
would
place
a
plant
efficiency
incentive
on
new
units
so
that
the
low
rank
coals
would
be
unfairly
punished.
The
commenter
noted
that
EPA
is
requesting
comment
on
the
appropriateness
of
8,000
btu/
kWH.
The
commenter
strongly
encouraged
EPA
to
establish
a
subcategory
for
heat
rate
conversion
factor
for
low
rank
coals
nearer
9,700
btu/
kWH.

One
commenter
(
OAR­
2002­
0056­
2834)
believed
the
proposed
heat
rate
conversion
factor
of
8,000
Btu/
kWh
is
to
low
for
Fort
Union
lignite­
fired
EGUs.
The
commenter
stated
that
heat
rates
for
units
utilizing
Fort
Union
lignite
have
improved
over
time.
According
to
the
commenter
the
recent
historical
heat
rate
for
existing
Fort
Union
lignite­
fired
boilers
is
just
under
11,000
Btu/
gross
kWh.

Response:

As
discussed
in
the
final
rule
preamble,
under
the
example
allocation
methodology,
allowances
will
be
allocated
to
new
units
with
an
appropriate
baseline
on
a
"
modified
output"
basis.
The
new
unit's
modified
output
will
be
calculated
by
multiplying
its
gross
output
by
a
heat
rate
conversion
factor
of
8,000
Btu
per
kilowatt­
hour
(
Btu/
kWh).
The
8,000
Btu/
kWh
value
for
the
conversion
factor
is
an
average
of
heat­
rates
for
new
pulverized
coal
plants
and
new
IGCC
coal
plants
(
based
upon
assumptions
in
EPA's
economic
modeling
analysis).
See
documentation
for
the
Integrated
Planning
Model
(
IPM)
at
http://
www.
epa.
gov/
airmarkets/
epa­
ipm).
A
single
conversion
rate
will
create
consistent
and
level
incentives
for
efficient
generation,
rather
than
favoring
new
units
with
higher
heat
rates.

EPA
maintains
that
providing
each
new
source
an
equal
amount
of
allowances
per
MWh
of
output
is
an
equitable
approach.
Because
electricity
output
is
the
ultimate
product
being
produced
by
electric
generating
unit,
a
single
conversion
factor
based
on
output
ensures
that
all
sources
will
be
treated
equally.
Higher
conversion
factors
for
less
efficient
technologies
will
effectively
provide
greater
amounts
of
allowances
(
and
thus
a
greater
subsidy)
to
such
less
efficient
units
for
each
MWh
they
generate.
This
will
serve
to
provide
greater
relative
incentives
to
build
new
less
efficient
technologies
rather
than
efficient
technology.
It
should
also
be
noted
5­
147
that,
since
all
allocations
are
proportionally
reduced
after
a
new
source
is
integrated
into
the
market,
higher
conversion
factors
also
lower
allocations
to
existing
sources.

Comment:

One
commenter
(
OAR­
2002­
0056­
3437)
submitted
that
if
EPA
decides
to
include
a
new
source
set
aside,
states
should
be
in
charge
of
managing
it
and
should
be
able
to
use
some
of
it
to
encourage
energy
efficiency.
The
commenter
felt
it
would
be
more
equitable
to
use
a
methodology
that
allows
all
new
units
to
receive
some
allowances
to
reduce
the
amount
that
may
need
to
be
purchased.
The
commenter
believed
this
is
especially
important
if
sources
are
allowed
to
request
up
to
5
years
of
allowances.
The
commenter
suggested
that
one
option
would
be
to
increase
the
discount
factor
(
0.90)
to
0.80
or
0.75
or
more.
The
commenter
noted
it
is
difficult
to
estimate
the
actual
number
of
new
units
and
the
amount
of
allowances
needed,
but
this
is
somewhat
resolved
by
redistributing
unallocated
allowances
back
to
existing
units.

Regarding
the
allocation
methodology,
one
commenter
(
OAR­
2002­
0056­
3437)
noted
that
EPA
did
not
provide
any
basis
for
a
discount
factor
of
0.90
to
arrive
at
a
final
allocation.

One
commenter
(
OAR­
2002­
0056­
3437)
commented
on
EPA's
proposed
alternative
where
new
units
would
simply
apply
at
the
end
of
the
year
for
allowances
based
on
actual
emissions.
The
commenter
submitted
that
this
is
not
a
good
alternative
because
sources
would
be
uncertain
about
the
actual
amount
of
emissions
and
available
allowances.
The
commenter
believed
that
this
could
lead
to
a
flurry
of
activity
to
try
and
buy
allowances
in
a
short
time
or
risk
noncompliance.

Response:

The
example
allocation
methodology
for
the
final
rule
does
include
these
discount
factors.
As
discussed
in
the
final
rule
preamble,
under
its
example
allocation
methodology,
EPA
is
finalizing
the
approach
that
new
units
will
begin
receiving
allowances
from
the
set­
aside
for
the
control
period
immediately
following
the
control
period
in
which
the
new
unit
commences
commercial
operation,
based
on
the
unit's
emissions
for
the
preceding
control
period.
Thus,
a
source
will
be
required
to
hold
allowances
during
its
start­
up
year,
but
will
not
receive
an
allocation
for
that
year.
States
will
allocate
allowances
from
the
set­
aside
to
all
new
units
in
any
given
year
as
a
group.
If
there
are
more
allowances
requested
than
in
the
set­
aside,
allowances
will
be
distributed
on
a
pro­
rata
basis.
Allowance
allocations
for
a
given
new
unit
in
following
years
will
continue
to
be
based
on
the
prior
year's
emissions
until
the
new
unit
establishes
a
baseline,
is
treated
as
an
existing
unit,
and
is
allocated
allowances
through
the
State's
updating
process.
This
will
enable
new
units
to
have
a
good
sense
of
the
amount
of
allowances
they
will
likely
receive
 
in
proportion
to
their
emissions
for
the
previous
year.
This
methodology
will
not
provide
allowances
to
a
unit
in
its
first
year
of
operation;
however,
it
is
a
methodology
that
is
straightforward,
reasonable
to
implement,
and
predictable.

Although
EPA
is
offering
an
example
allocation
method
with
accompanying
regulatory
language,
EPA
reiterates
that
it
recognizes
States'
flexibility
in
choosing
their
Hg
allocations
method.
5­
148
Comment:

One
commenter
(
OAR­
2002­
0056­
2181)
stated
that
the
proposal
provides
credit
for
the
thermal
output
of
new
CHP
facilities.
The
commenter
believed
this
is
a
very
important
and
beneficial
provision
that
will
help
encourage
the
application
of
CHP.
The
commenter
believed,
however,
the
same
credit
should
apply
to
existing
CHP
facilities.
The
commenter
stated
that
the
program
should
provide
the
maximum
encouragement
to
CHP
as
a
means
of
reducing
energy
consumption
and
emissions
from
the
power
and
steam
generation
sectors.
The
commenter
submitted
that
continued
and
increasing
use
of
CHP
can
help
reduce
the
cost
of
the
program
as
well
as
producing
significant
coincident
benefits
for
regulated
and
non­
regulated
pollutant
reductions.

Response:

As
discussed
in
the
final
rule
preamble,
under
the
example
allocation
methodology,
existing
units
as
a
group
will
not
update
their
heat
input.
This
will
eliminate
the
potential
for
a
generation
subsidy
(
and
efficiency
loss)
as
well
as
any
potential
incentive
for
less
efficient
existing
units
to
generate
more.
This
methodology
will
also
be
easier
to
implement
because
it
will
not
require
the
updating
of
existing
units'
baseline
data.
Retired
units
will
continue
to
receive
allowances
indefinitely,
thereby
creating
an
incentive
to
retire
less
efficient
units
instead
of
continuing
to
operate
them
in
order
to
maintain
the
allowance
allocations.

Comment:

One
commenter
(
OAR­
2002­
0056­
2913)
stated
that
their
newest,
cleanest
and
most
efficient
electric
utility
steam
generating
unit
was
currently
under
construction,
which
because
the
unit
commenced
construction
prior
to
January
30,
2004,
it
was
classified
as
an
existing
unit
as
provided
for
in
rule
§
63.9982(
b).
The
commenter
submitted
however,
if
a
cap­
and­
trade
program
were
promulgated
as
proposed
this
unit's
mercury
allowances
would
be
allocated
according
to
new
unit
criteria
(
i.
e.
a
design
output
basis
in
lb/
GWh)
and
only
after
it
operated
for
five
years.

According
to
the
commenter,
its
newest
unit
would
be
allocated
mercury
allowances
based
on
the
unit's
heat
input
which,
for
the
first
five
years
of
operation,
would
be
converted
to
gross
electrical
output
using
a
predetermined
conversion
factor
of
8,000
Btu/
kWh.
The
commenter
stated
that
8,000
Btu/
kWh
is
not
applicable
under
any
cogenerating
circumstances
and
is
extremely
aggressive
under
best
case
conditions
and
leaves
no
allowance
for
equipment
degradation
due
to
low
load
conditions,
equipment
degradation
or
non­
optimal
process
operations.
The
commenter
further
stated
that
any
heat
input
used
for
co­
generation
purposes
would
only
be
converted
at
one­
half
of
the
actual
rate
and
that
mercury
allowances
would
then
be
allocated
based
on
these
artificially
low
heat
input
conversion
rates;
these
allowances
would
be
reduced
further
by
an
additional
10
percent
before
being
allocated
for
use.
Beyond
the
penalties
already
imposed
on
this
unit
(
i.
e.
no
allowance
for
mercury
content
in
the
limestone
used
for
SO
2
control
purposes
as
discussed
above)
the
commenter
claimed
they
will
be
further
penalized
by
this
allocation
process
and
questions
the
appropriateness
of
applying
what
is
in
essence
a
new
source
limit/
allocation
process
to
an
existing
unit.
5­
149
While
the
commenter
believed
the
set­
aside
allocation
process
as
currently
proposed
was
flawed,
they
expressed
a
much
larger
concern.
According
to
the
commenter,
under
the
allocation
process
proposed
in
§
60.4142(
c)(
4)(
iii)
and
(
iv),
there
was
a
distinct
possibility
that
they
would
not
be
allocated
enough
mercury
allowances
to
operate
its
newest
unit
regardless
of
the
amount
of
the
proposed
set­
aside,
due
to
the
fact
that
a
large
new
electric
utility
steam
generating
unit
could
potentially
require
and
be
granted
the
entire
amount
of
allowances
set­
aside.
The
commenter
stated
that
they
would
then
be
faced
with
the
possibility
of
not
being
able
to
achieve
" 
the
maximum
degree
of
reductions
 "
on
its
own
even
though
it
would
use
the
very
technology
EPA
relied
upon
in
setting
the
EGU
MACT
standard
in
the
first
place.
The
commenter
did
not
believe
this
is
what
Congress
envisioned
when
it
passed
CAA
section
112
into
law.
While
the
list
of
compliance
measures,
processes,
methods,
systems
or
techniques
delineated
in
CAA
section
112(
d)(
2)(
A)­(
E)
is,
admittedly,
not
all
inclusive,
the
commenter
argued
they
would
essentially
be
prevented
from
using
any
of
them
to
achieve
compliance
with
the
MACT
standard
under
a
cap­
and­
trade
program
not
"
funded"
with
sufficient
set­
aside
allowances.

As
a
remedy,
the
commenter
offered
that
one
way
to
treat
all
existing
units
equitably
would
be
to
allocate
mercury
allowances
to
all
existing
units
whether
or
not
they
operated
during
the
initial
baseline
period
and
whether
or
not
they
operated
for
five
years
or
more.
The
commenter
stated
that
one
could
look
to
§
60.4142(
c)(
3)
for
guidance
on
what
EPA
believed
was
appropriate
for
initial
mercury
allowance
allocations
for
units
that
have
not
operated
for
five
years
or
more.
To
implement
the
stated
policy
consistent
with
the
approach
outlined
in
§
60.4142(
c)(
3),
the
commenter
offered
suggested
modifications
to
§
60.4142.

Response:

The
example
allocation
methodology
for
the
final
rule
addresses
the
commenter's
concerns
about
new
units.
As
discussed
in
responses
above,
the
example
allocation
methodology
includes:
a
new
sources
set­
aside,
allowance
allocations
for
a
given
new
unit
based
on
the
prior
year's
emissions
until
the
new
unit
establishes
a
baseline,
and
no
inclusion
of
discount
factors.

Comment:

The
commenter
(
OAR­
2002­
0056­
4891)
added
that
with
the
exemption
option,
new
power
plants
should
be
exempted
from
the
requirement
to
purchase
allowances
as
long
as
they
have
NSPS
Subpart
Da
technology
operational
when
they
initiate
operations,
and
they
adhere
to
monitoring
and
reporting
requirements
to
demonstrate
continuous
compliance.
By
the
same
token,
facilities
that
are
not
subject
to
the
UMRR
should
not
be
able
to
receive
credits
and
thereby
receive
windfall
gains
on
the
allowance
trading
markets.

Response:

In
the
final
CAMR,
new
sources
will
be
covered
under
the
Hg
cap
of
the
trading
program,
and
will
be
required
to
hold
allowances
equal
to
their
emissions.
EPA
maintains
that
is
essential
to
include
new
sources
under
the
cap
to
ensure
that
environmental
goal
of
reducing
mercury
emission
is
achieved.
With
new
sources
under
the
cap,
the
environmental
goal
5­
150
continues
to
be
achieved
despite
future
growth
in
the
electric
power
sector,
as
older
coal­
fired
generation
is
retired
and
replaced
new
coal­
fired
generation
Comment:

Several
commenters
(
OAR­
2002­
0056­
2834,
­
2898)
submitted
that
Springerville
Units
3
and
4
should
receive
allocations
in
the
same
manner
as
other
"
existing
units."
The
commenters
stated
that
the
Springerville
Generating
Station
was
recently
permitted
for
the
addition
of
two
new
400
MW
net
coal­
fired
units.
The
permit
for
the
addition
of
Springerville
Units
3
and
4
was
received
on
April
29,
2002,
and
construction
of
the
phased
project
began
on
October
22,
2003,
with
Unit
3
scheduled
for
completion
in
2006
and
Unit
4
at
a
later
date.
Two
other
Units
already
exist
at
the
site,
Springerville
Units
1
and
2.

The
commenters
stated
that
units
such
as
Springerville
3
and
4
should
receive
allocations
in
the
same
manner
as
other
"
existing
units"
since
construction
commenced
on
or
before
January
30,
2004.
The
Springerville
units
3
and
4
are
"
existing
units"
for
the
purpose
of
determining
the
applicability
of
the
proposed
rule.
The
commenters
noted
that
under
either
section
111
or
112,
an
"
existing
unit"
is
one
for
which
construction,
modification,
or
reconstruction
commenced
on
or
before
January
30,
2004
(
69
FR
4662
and
69
FR
4690).
The
commenters
stated
that
Units
3
and
4,
however,
are
not
listed
as
part
of
those
existing
units
receiving
mercury
allowances
under
a
Cap
and
Trade
program.
Under
the
proposed
rule
(
69
FR
12446),
units
that
"
commence
operation
on
or
after
January
1,
2000"
receive
allocations
according
to
a
different
approach,
regardless
of
whether
they
are
"
new"
or
"
existing
units."
The
commenters
felt
that,
since
construction
of
Springerville
Units
3
and
4
commenced
on
or
before
January
30,
2004,
these
units
should
receive
allocations
in
the
same
manner
as
other
"
existing
units."
Commenter
2898
added
that
due
to
the
fact
that
there
is
no
historical
heat
input
for
these
units,
the
"
baseline
heat
input"
(
prior
to
multiplying
by
the
adjustment
factors)
should
be
calculated
using
the
maximum
potential
heat
input
for
the
units
and
a
capacity
factor
of
90
percent.
The
commenter
noted
that
units
of
this
nature
are
invariably
intended
to
provide
base
load
power,
and
the
allocation
methodology
must
recognize
this
fact.

Response:

Under
the
example
allocation
methodology,
a
new
unit
is
defined
as
a
unit
commencing
operation
after
January
1,
2001.
For
purposes
of
allocating
emissions,
EPA
believes
that
existing
units
need
five
years
of
heat
input
data
to
establishes
it
baseline
heat
input.
This
is
consistent
with
the
overall
allocation
approach,
under
which
new
unit
establishes
a
baseline
after
5
years
of
operation,
is
treated
as
an
existing
unit,
and
is
allocated
allowances
through
the
State's
updating
process.

5.7.4
Auctions
Comment:
5­
151
Many
commenters
(
OAR­
2002­
0056­
1834,
­
1969,
­
2117,
­
2161,
­
2180,
­
2267,
­
2375,
­
2721,
­
2830,
­
2835,
­
2850,
­
2867,
­
2891,
­
2898,
­
2911,
­
2922,
­
2948,
­
3443,
­
3445,
­
3543,
­
3546
­
3556,
­
3565)
opposed
the
auctioning
of
mercury
allowances.
One
commenter
(
OAR­
2002­
0056­
3565)
believed
states
do
not
have
that
authority
and
allowances
should
be
allocated
free.
A
second
commenter
(
OAR­
2002­
0056­
2891)
stated
that
EPA
had
no
regulatory
"
taxing"
authority
under
section
112
or
section
111
to
mandate
the
auctioning
of
mercury
allowances,
and
the
auctioning
of
allowances
would
be
poor
public
policy
because
it
would
increase
the
cost
of
an
already
expensive
proposal.
The
commenter
further
stated
that
a
mercury
cap­
and­
trade
program
could
be
constructed
in
many
ways
to
help
ensure
an
equitable
and
cost­
effective
program.
The
commenter
noted
that
EPA
requested
comment
on
whether
it
could
and
should
impose
an
auction
program
under
either
a
section
112(
n)
or
section
111(
d)
Federal
Implementation
Program
cap­
and­
trade
program,
at
12408.
The
commenter
stated
that
in
short,
it
is
neither
legal
nor
appropriate
for
EPA
to
implement
any
auction
program
of
mercury
allowances.

Commenter
OAR­
2002­
0056­
2891
stated
that
first,
EPA
had
no
legal
authority
under
the
CAA
to
auction
or
require
the
auctioning
of
mercury
allowances
under
either
proposed
cap­
and­
trade
programs
and
conspicuously
cited
no
legal
authority
in
the
proposal.
According
to
the
commenter,
the
only
auctioning
of
allowances
the
EPA
has
authority
to
conduct
is
specifically
delineated
by
an
act
of
Congress
in
the
1990
CAA
Amendments,
section
416,
under
"
acid
rain"
control.
The
commenter
stated
that
even
under
section
416,
the
auction
proceeds
are
redistributed
to
the
original
allowance
holders.
The
commenter
further
stated
that
auction
proceeds
would
be
effectively
a
tax
on
those
required
to
purchase
mercury
allowances.
The
commenter
believed
that
EPA's
contention,
at
12408
col.
2,
that
it
might
have
regulatory
authority
to
collect
taxes
and
deposit
the
proceeds
in
"
general
revenues"
under
the
Miscellaneous
Receipts
Act
was
unfounded.

The
commenter
added
that
the
policy
goals
EPA
claimed
an
auction
would
achieve
can
be
accomplished
by
less
draconian
and
more
legal
means.
The
commenter
stated
that
for
example,
a
"
new
source
set
aside"
provision
alternatively
suggested
by
EPA,
at
12408­
12409,
could
be
constructed
to
accomplish
the
same
objectives
without
unnecessarily
driving
up
the
costs
of
what
will
be
an
already
expensive
program.

One
commenter
(
OAR­
2002­
0056­
2922)
opposed
auctions
or
any
other
method
of
forced
sale
of
allowances.

Several
commenters
(
OAR­
2002­
0056­
2161,
­
2948)
opposed
auctions,
but
stated
that
if
EPA
decided
to
permit
auctions,
auctions
should
not
be
for
the
initial
allocations
of
allowances,
but
only
for
a
very
small
percentage
of
allowances
each
year
as
in
the
Title
IV
program.
One
commenter
(
OAR­
2002­
0056­
2161)
noted
that
the
infrastructure
for
an
allowance
program
is
already
in
place
as
a
result
of
the
Acid
Rain
Amendments,
and
it
should
be
relatively
simple
to
add
mercury
allowances
to
the
program
already
in
existence.

Several
commenters
(
OAR­
2002­
0056­
2180,
­
2267,
­
2835,
­
2898,
­
3445)
supported
an
allocation
system
and
opposed
an
auction.
One
commenter
(
OAR­
2002­
0056­
2898)
5­
152
recommended
that
mercury
allowances
be
allocated
to
sources
by
EPA.
Several
commenters
(
OAR­
2002­
0056­
2267,
­
2835,
­
3443,
­
3445)
stated
that
mercury
emissions
would
be
controlled
at
substantial
cost,
and
to
pay
for
allowances
in
addition
to
the
mercury
controls
would
add
substantial
cost
with
no
added
environmental
benefit.
One
of
these
commenters
(
OAR­
2002­
0056­
3445)
did
not
believe
that
additional
reductions
would
occur
from
sources
seeking
to
reduce
the
cost
of
allowances;
it
was
not
anticipated
that
additional
reductions
will
be
possible,
based
on
the
available
and
developing
control
technologies.

Commenter
OAR­
2002­
0056­
2267
submitted
that
allocating
allowances
for
free
would
provide
assistance
to
the
entities
incurring
most
of
the
costs
of
complying
with
the
necessary
mercury
reductions,
lessening
the
financial
impact
of
the
program
on
these
sources.
One
commenter
(
OAR­
2002­
0056­
2180)
submitted
that
affected
units
will
pay
twice,
once
to
reduce
emissions
and
second
to
pay
for
allowances
they
need
to
operate.
Commenter
OAR­
2002­
0056­
2835
suggested
that
if
any
allowances
are
withheld
from
affected
EGUs
for
auction,
proceeds
from
auction
sales
should
be
remitted
to
the
original
holders
from
which
the
allowances
were
withheld.
Commenter
OAR­
2002­
0056­
3443
submitted
that
auctioning
allowances
would
increase
the
price
of
electricity
due
to
the
increased
stringency
of
the
emission
standard
resulting
from
the
requirement
to
purchase
allowances
and
invest
in
control
equipment.
The
commenter
stated
that
well­
documented
studies
show
clearly
that
affordable
electricity
is
a
key
element
in
public
health
policy.
The
commenter
felt
that
placing
a
tax
on
electricity
could
undermine
the
health­
benefits
sought
to
be
gained
by
this
rulemaking.

Several
commenters
(
OAR­
2002­
0056­
2991,
­
3556)
believed
that
if
states
were
allowed
to
sell
allowances
at
auction
(
or
otherwise)
rather
than
allocate
them
without
charge,
it
would
substantially
change
the
cost
analyses
for
the
standard
of
performance
that
EPA
has
conducted.
The
commenters
added
that
it
would
add
to
the
variability
of
the
implementation
of
the
trading
program,
hindering
the
development
of
a
robust
program.

One
commenter
(
OAR­
2002­
0056­
3543)
believed
auctions
would
not
be
necessary
under
an
open
market
free
trade
system.
The
commenter
submitted
that
the
use
of
a
safety
valve
mechanism,
or
capping
allowance
prices,
may
dictate
decisions
to
install
controls
instead
of
the
market
price
for
an
allowance.
This
would
be
counter
to
the
idea
that
decisions
to
control
emissions
are
driven
by
the
cost
effectiveness
of
controls
compared
to
purchase
of
allowances.
The
commenter
believed
the
safety
valve
mechanism
also
may
hamper
EPA's
ability
to
assess
penalties
for
noncompliance.

One
commenter
(
OAR­
2002­
0056­
3546)
stated
that
requiring
controlled
sources
to
both
reduce
emissions
and
pay
for
allowances
to
cover
their
remaining
emissions
would
impose
significant
costs
on
emitting
sources.
These
additional
allowance
costs
would
be
unnecessarily
burdensome
and
costly
to
fossil
fuel­
fired
generation.
In
contrast,
the
commenter
believed
allocating
allowances
to
regulated
sources
would
lessen
the
financial
impact
of
this
very
costly
control
program.

Several
commenters
(
OAR­
2002­
0056­
1969,
­
2830,
­
2850)
disagreed
with
EPA's
proposal
to
have
an
annual
auction
for
mercury
allocations
under
a
cap­
and­
trade
approach.
5­
153
According
to
the
commenters,
considering
the
uncertainty
of
the
availability
of
mercury
controls
and
monitors,
the
risk
to
the
existing
coal­
fired
electric
generating
units
would
be
high.
The
commenters
believed
that,
to
alleviate
some
of
the
risk,
the
mercury
caps
should
be
fully
and
permanently
allocated
to
the
existing
electric
generating
units
as
is
done
under
the
Title
IV
sulfur
dioxide
program.
The
commenters
stated
that
new
units
would
be
better
able
to
minimize
risks
since
they
would
be
able
to
design
systems
and
select
fuels
to
minimize
mercury
emissions,
which
is
something
that
many
existing
units
cannot
do.
The
commenters
asserted
that
if
EPA
decides
to
allocate
allowances
to
new
units,
it
should
not
be
done
at
the
expense
of
existing
units.
The
commenters
suggested
that
if
EPA
decides
to
implement
an
auction,
EPA
should
manage
that
auction
program
at
the
national
level
rather
than
having
it
managed
by
the
individual
states.

One
commenter
(
OAR­
2002­
0056­
2721)
noted
that
allowance
auctions
would
be
the
responsibility
of
the
individual
state.
The
permanent
allowance
system
would
not
take
into
account
new
units,
unless
there
was
a
new
unit
set
aside.
The
commenter
would
be
concerned
with
the
quantity
of
the
set­
aside
as
it
is
difficult
to
anticipate
the
rate
of
new
units
coming
on­
line.
An
additional
concern
would
be
that
the
set
aside
would
not
be
available
for
existing
sources.

One
commenter
(
OAR­
2002­
0056­
2861)
opposed
giving
states
the
option
of
distributing
allocations
through
an
auction.
The
commenter
submitted
this
is
not
a
necessary
element
of
an
environmental
control
program.
The
commenter
added
that
auctioning
allowances
would
not
produce
any
additional
reduction
in
emissions.
It
would
simply
increase
the
cost
of
the
regulatory
program
to
companies
and
ultimately
to
consumers
by
requiring
regulated
entities
to
pay
for
every
ton
emitted.
The
commenter
stated
that
auctioning
of
mercury
allowances
would
simply
not
be
an
economically
efficient
policy.
The
commenter
added,
as
UARG
has
argued
in
its
comments,
a
state
does
not
have
the
authority
to
auction
allowances
because
to
do
so
would
fundamentally
change
the
cost
analysis
that
EPA
used
to
establish
the
mercury
performance
standard.

One
commenter
(
OAR­
2002­
0056­
3437)
stated
that,
although
EPA
proposes
it,
the
auction
allowance
work
would
fall
to
the
states.
While
it
may
be
beneficial
to
have
a
pool
of
revenue
available,
there
could
be
resource
issues
with
establishing
and
implementing
an
auction
program.
The
commenter
asserted
that
if
EPA
includes
auctions,
this
must
be
voluntary
and
not
a
requirement.

Response:

For
States
participating
in
the
EPA­
administered
CAMR
cap­
and­
trade
program,
States
have
the
flexibility
to
determine
their
own
methods
for
allocating
Hg
allowances
to
their
sources.
Specifically,
such
States
will
have
flexibility
concerning
the
cost
of
the
allowance
distribution,
the
frequency
of
allocations,
the
basis
for
distributing
the
allowances,
and
the
use
and
size
of
allowance
set­
asides.

As
discussed
in
the
final
preamble,
although
there
are
some
clear
potential
benefits
to
using
auctions
for
allocating
allowances,
EPA
believes
the
decision
regarding
utilizing
auctions
rightly
belongs
to
the
States
and
Tribes.
EPA
is
not
requiring,
restricting,
or
barring
State
use
5­
154
of
auctions
for
allocating
allowances.
An
example
of
an
approach
where
CAMR
allowances
could
be
distributed
to
sources
through
a
combination
of
an
auction
and
a
free
allocation
is
provided
in
the
preamble.

5.8
OTHER
TRADING
MECHANISMS
5.8.1
Banking
Comment:

Several
commenters
(
OAR­
2002­
0056­
1673,
­
1859,
­
2375,
­
2547,
­
2718,
­
2862,
­
2867,
­
2883,
­
2900,
­
2922,
­
2948,
­
3509,
­
3565)
stated
there
should
be
no
restrictions
on
banking
of
emission
allowances.
Several
commenters
(
OAR­
2002­
0056­
2547,
­
2718)
supported
a
provision
for
unrestricted
banking
as
a
way
to
encourage
early
emissions
reductions,
stimulate
the
trading
market,
encourage
efficient
pollution
control,
and
provide
flexibility
to
affected
sources
in
meeting
environmental
objectives.
One
commenter
(
OAR­
2002­
0056­
2900)
noted
that,
like
the
Acid
Rain
Program,
the
Mercury
Budget
Trading
Program
proposed
unlimited
banking
without
the
flow
control
provisions
of
the
NO
x
Budget
Trading
Program.
The
commenter
supported
unlimited
banking
of
allowances
allocated
to
sources
under
each
phase
of
the
Program
and
did
not
see
any
advantage
to
a
flow
control
provision.
Commenter
OAR­
2002­
0056­
2862
also
believed
there
should
not
be
any
restrictions
such
as
flow
control.
This
commenter
stated
that
because
mercury
is
a
chemical
that
bio­
accumulates
in
the
environment,
and
because
the
behavior
of
mercury
emissions
are
not
exacerbated
by
seasonal
weather
conditions
(
such
as
the
proclivity
for
ozone
formation
development
during
hot,
humid
summer
months),
any
reduction
in
mercury
in
advance
of
a
compliance
date
would
result
in
a
net
environmental
gain.

Response:

EPA
has
finalized
that
banking
will
be
allowed
without
restriction
after
the
start
of
the
Hg
cap­
and­
trade
program
in
2010.

Commenter
(
OAR­
2002­
0056­
2375)
submitted
that
a
mercury
cap­
and­
trade
program
should
include
provisions
for
early
reduction
credits
(
ERC)
and
banking
of
mercury
credits.
The
commenter
supported
unrestricted
banking
of
all
ERCs
and
Phase
I
and
II
excess
credits
without
discount,
except
the
banking
of
Phase
I
credits
should
be
restricted
if
EPA
determines
in
2009
that
IAQR
reduction
co­
benefits
result
in
emissions
less
than
34
tpy
and
EPA
sets
the
cap
at
34
tpy.
Sources
would
be
permitted
to
use
vintage
Phase
I
credits
during
Phase
I
without
discount
and
vintage
Phase
II
credits
during
Phase
II
without
discount.

Response:

EPA
has
finalized
that
banking
will
be
allowed
without
restriction
after
the
start
of
the
Hg
cap­
and­
trade
program
in
2010.
Given
that
the
2010
cap
is
set
at
a
level
that
represents
Hg
co­
benefit
reductions
under
CAIR,
EPA
did
not
propose,
and
is
not
finalizing,
an
early
reduction
credit
provision,
because
the
cap­
level
does
not
require
the
installation
of
Hg
specific
controls.
5­
155
Under
CAIR,
Acid
Rain
Program
sources
will
be
able
to
bank
SO
2
allowances
from
additional
reductions
before
2010
that
may
also
result
in
ancillary
Hg
emission
reductions.

One
commenter
(
OAR­
2002­
0056­
3443)
recommended
in
view
of
the
environmental
benefits
fostered
by
a
program
that
allows
allowances
to
be
banked
in
advance
of
the
deadline
for
a
cap,
that
early
reduction
credits
should
be
allowed
for
calendar
years
2008
and
2009.
The
commenter
has
long
held
that
early
reduction
programs
be
made
part
of
all
cap
and
trade
programs.
The
commenter
believed
that
early
reduction
programs
work
to
promote
clean
air
sooner
by
encouraging
the
early
installation
of
new
technologies.
The
commenter
installed
state­
of­
the­
art
scrubbers
in
advance
of
the
statutory
deadlines
under
the
successful
Title
IV
program.
Likewise,
the
commenter
installed
the
nation's
first
SCRs
burning
high
sulfur
coal
in
advance
of
the
NO
x
SIP
Call.
For
a
mercury
cap
and
trade
program,
the
commenter
asserted
that
the
utility
industry
needs
banking
of
early
reduction
credits
because
of
the
uncertainty
in
its
ability
to
control
mercury
emissions
over
the
long
term.
The
commenter
noted
that
as
the
preamble
acknowledges,
a
banked
allowance
is
one
less
ounce
of
mercury
emitted
in
a
given
year.
Thus,
an
early
emissions
banking
program
has
the
advantage
of
achieving
reductions
in
advance
of
the
2010
compliance
date
for
a
Phase
I
cap.

The
commenter
recommended
an
early
emission
banking
program
would
be
based
on
the
mass
of
reductions
produced
from
the
installation
of
an
emissions
control
device
on
an
individual
unit
basis,
as
was
done
in
the
NO
x
SIP
Call.
In
addition
to
providing
environmental
improvements,
the
commenter
believed
this
program
also
provides
an
opportunity
to
address
important
monitoring
issues
since
utilities
choosing
to
participate
in
the
program
would
have
to
start
monitoring
for
mercury
in
2008
for
units
in
this
early
reduction
program.
The
commenter
stated
credit
would
be
earned
on
an
individual
unit
basis
at
levels
below
their
Phase
I
allocation.
The
commenter
estimated
that
on
a
yearly
basis,
they
might
earn
three
to
six
percent
of
their
Phase
I
allocation
level.
The
commenter
noted
this
is
a
small
amount,
given
that
the
current
best
mercury
emission
monitoring
method
(
the
Ontario
Hydro
Method)
has
a
10
percent
accuracy
level.

Given
the
limited
experience
industry
has
had
with
mercury
CEMs
or
equivalent
methods,
the
commenter
believed
several
monitoring
issues
would
have
to
be
resolved
prior
to
the
onset
of
monitoring.
For
example,
substitution
of
missing
data
is
just
one
of
the
many
issues
that
the
commenter
felt
need
to
be
addressed.
The
commenter
submitted
an
early
banking
program,
starting
in
2008,
would
allow
EPA
to
address
these
issues
prior
to
the
imposition
of
the
first
cap
in
2010.

The
commenter
submitted
that
excessive
bank
accumulations
could
be
minimized
by
discounting
the
banked
allowances
in
2018
by
a
certain
pre­
set
percentage.
The
commenter
believed
the
interim
cap
and
the
discounting
of
allowances
would
ensure
that
actual
emissions
in
2018
are
close
to
the
Phase
II
cap
of
15
tons
per
year.
The
commenter
stated
that
this
approach
provides
the
flexibility
of
building
some
allowances
prior
to
program
initiation
in
2010
to
hedge
against
the
uncertainty
in
the
estimate
of
achievable
mercury
reductions.
This
approach
would
also
be
environmentally
preferable
because
it
would
encourage
earlier
reductions
and
then
in
2018
permanently
retire
allowances.
5­
156
Response:

Given
that
the
2010
cap
is
set
at
a
level
that
represents
Hg
co­
benefit
reductions
under
CAIR,
EPA
did
not
propose,
and
is
not
finalizing,
an
early
reduction
credit
provision,
because
the
2010
cap­
level
for
CAMR
does
not
require
the
installation
of
Hg
specific
controls.
Under
CAIR,
Acid
Rain
Program
sources
will
be
able
to
bank
SO
2
allowances
from
additional
reductions
before
2010
that
may
also
result
in
ancillary
Hg
emission
reductions.
EPA
has
finalized
that
banking
will
be
allowed
without
restriction
after
the
start
of
the
Hg
cap­
and­
trade
program
in
2010.
The
ability
of
affected
sources
to
bank
Hg
allowances
starting
in
2010
will
promote
earlier
reductions
than
would
otherwise
be
achieved
in
the
program,
and
help
to
stimulate
the
Hg
allowance
market.

Comment:

One
commenter
OAR­
2002­
0056­
3445
stated
that
they
are
already
installing
equipment
to
make
significant
reductions
in
NO
x
and
SO
2
emissions.
The
commenter
added
that
they
and
their
customers
have
made
a
substantial
investment
in
the
NO
x
and
SO
2
control
technologies,
one
that
the
commenter
believed
will
have
a
substantial
level
of
mercury
reduction
co­
benefits.
The
commenter
added
that
this
equipment
will
be
operational
as
much
as
five
years
before
EPA's
proposed
initial
compliance
deadline,
resulting
in
less
overall
mercury
emissions
to
the
environment.

The
commenter
believed
that
banking
should
be
allowed,
so
the
credits
that
the
commenter
earns
by
acting
early
may
be
used
to
offset
later
emissions
or
as
a
reserve
in
the
event
of
equipment
failure.
A
significant
amount
of
the
commenter's
generation
comes
from
nuclear
power,
which
emits
no
mercury.
The
commenter
pointed
out
that
if
any
of
those
nuclear
units
experienced
an
unexpected
outage,
generation
must
be
made
up
from
the
fossil
plants,
which
could
result
in
unanticipated
mercury
emissions.
With
limits
as
tight
as
the
proposed
15­
ton
cap
in
2018,
the
commenter
believed
that
banked
emissions
credits
should
be
available
to
offset
the
unexpected
mercury
emissions
from
such
an
event.

The
commenter
stated
that
banking
would
encourage
companies
to
install
and
operate
pollution
control
equipment
early,
at
significant
operating
cost,
so
that
the
banked
allowances
could
be
used
when
additional
equipment
could
not
be
installed
in
the
limited
time
available.
The
commenter
added
that
banking
also
encourages
companies
to
operate
pollution
control
equipment
to
achieve
maximum
emissions
reductions,
accumulating
a
pool
of
allowances
that
can
be
used
as
a
reserve
in
case
of
the
unforeseen
loss
of
a
non­
emitting
or
controlled
unit,
during
periods
of
necessary
but
unexpected
maintenance,
and
in
the
event
that
some
controls
do
not
perform
as
designed.

The
commenter
stated
that
utilities
like
them
that
have
a
significant
number
of
non­
mercury
emitting
generation
units
(
e.
g.,
nuclear
and
gas)
must
plan
for
fluctuations
in
their
operations,
based
on
long­
term
maintenance
and
refueling
cycles.
The
commenter
added
that
these
plans
impact
the
plants'
year­
to­
year
operations
and
the
commenter's
overall
emissions.
The
commenter
further
added
that
weather
is
also
a
factor
in
plant
operations.
According
to
the
5­
157
commenter,
an
extremely
hot
summer
or
cold
winter
could
result
in
a
significant
emissions
increase
relative
to
the
original
plan,
which
would
be
based
on
"
normal
weather
assumptions"
for
that
period.
The
commenter
stated
that
banking
would
provide
a
cost­
effective
mechanism
for
dealing
with
the
expected
year­
to­
year
emissions
fluctuations
while
ensuring
long­
term
compliance.

Response:

EPA
has
finalized
that
banking
will
be
allowed
without
restriction
after
the
start
of
the
Hg
cap­
and­
trade
program
in
2010.

Several
commenters
(
OAR­
2002­
0056­
1596,
­
2071,
­
2064,
­
2094,
­
2359,
­
3398,
­
4139)
stated
that
banking
should
not
be
allowed
or
should
be
restricted.
One
commenter
(
OAR­
2002­
0056­
2359)
opposed
EPA's
proposal
to
allow
units
to
bank
early
emission
credits
with
no
restrictions
to
be
used
in
meeting
reductions
under
CAA
section
111.
If
banking
and
trading
were
allowed,
the
proposed
15­
ton
final
cap
in
2018
would
increase
to
22
tons
or
only
a
54
percent
reduction.
The
commenter
believed
that
the
banking
of
emission
credits
should
be
restricted
and
that
at
a
minimum,
credits
should
expire
by
a
final
compliance
date.
Commenter
OAR­
2002­
0056­
3398
rejected
banking
prior
to
the
2018
compliance
date
because
it
would
extend
the
timeframe
for
meaningful
reductions
and
may
further
contribute
to
hot
spots.
One
commenter
(
OAR­
2002­
0056­
4139)
did
not
support
banking
of
allowances
without
restrictions.
The
commenter
believed
the
availability
of
banked
allowances
should
be
decreased
either
through
time­
generated
reductions
(
i.
e.,
allowances
expire
after
a
definite
time
period)
or
by
requiring
the
use
of
older
banked
allowances
on
an
increasing
ratio
based
on
age
(
i.
e.,
1
to
1.5
or
1
to
2).
One
commenter
(
OAR­
2002­
0056­
1596)
stated
that
any
banking
of
allowances
must
include
an
extra
reduction
for
each
transaction
for
environmental
improvement.
For
example,
when
100
units
are
retired,
an
additional
5
units
should
be
retired.

Response:

Banking
would
achieve
greater
cumulative
reductions
early
in
the
program
than
would
be
required
by
the
final
cap,
and
will
not
increase
cumulative
emissions
over
the
entire
length
of
the
program.
Banking
has
several
additional
advantages,
including
the
potential
to
encourage
earlier
or
greater
reductions
from
sources,
stimulate
the
market
and
encourage
efficiency,
and
provide
flexibility
in
achieving
emissions
reduction
goals
(
e.
g.,
by
allowing
for
periodic
increased
generation
activity
that
may
occur
in
response
to
interruptions
of
power
supply
from
non­
Hg
emitting
sources).

5.8.2
Safety
Valve
Provision
Comment:

Many
State
Attorney
Generals
(
OAR­
2002­
0056­
2823)
stated
there
is
no
legal
or
policy
basis
for
establishing
a
"
safety
valve,"
which
would
set
a
maximum
cost
for
mercury
emission
allowances.
The
commenters
asserted
EPA
lacks
both
authority
and
a
policy
basis
for
adopting
a
5­
158
safety
valve.
The
commenters
believed
the
safety
valve
would
provide
incentive
to
deter
emission
reductions
and
should
be
withdrawn.
The
commenters
noted
that
even
if
authority
existed,
EPA
presented
no
legal
or
technical
basis
for
the
proposed
price
of
$
2,187.50.
The
commenters
stated
the
provision
is
also
unnecessary
for
a
market­
based
program
and
would
undermine
its
purpose
 
to
use
market
incentives
to
achieve
timely
reductions.

Response:

EPA
is
not
finalizing
a
safety
valve
provision
in
CAMR.
EPA
maintains
that
the
safety
valve
mechanism
is
not
necessary
to
address
market
volatility
associated
with
the
Hg
reduction
requirements.
This
issue
is
discussed
in
detail
in
section
IV
of
today's
preamble.

Comment:

Similarly,
several
states
(
OAR­
2002­
0056­
3437,
­
3449,
­
4139)
did
not
support
the
safety
valve
provision.
One
commenter
(
OAR­
2002­
0056­
3437)
stated
safety
valves
have
not
been
needed
in
the
Acid
Rain
or
NO
x
programs,
and
they
would
require
EPA
to
speculate
about
too
many
uncertainties,
such
as
the
allowance
price.
One
commenter
(
OAR­
2002­
0056­
3449)
submitted
the
safety
valve
provision
to
avoid
controls
if
the
cost
is
greater
than
$
35,000/
lb
is
inappropriate
and
arbitrary.
The
commenter
noted
the
dollar
value
was
not
linked
to
the
environmental
cost
which
result
from
excess
mercury
emissions.
The
commenter
believed
that
it
appeared
to
be
linked
to
EPA's
arbitrary
notion
of
what
level
of
cap
is
supported
by
the
proposed
rule.
The
commenter
also
believed
costs
of
control
over
$
100,000/
lb
were
justified
based
on
the
economic
loss
of
fish,
sports
fishing
industry,
and
the
lifetime
economic
loss
of
brain
damaged
people
due
to
in
utero
exposure.

Response:

EPA
is
not
finalizing
a
safety
valve
provision
in
CAMR.
EPA
maintains
that
the
safety
valve
mechanism
is
not
necessary
to
address
market
volatility
associated
with
the
Hg
reduction
requirements.
This
issue
is
discussed
in
detail
in
section
IV
of
today's
preamble.

One
commenter
(
OAR­
2002­
0056­
4139)
submitted
that
allowing
sources
to
purchase
allowances
under
a
safety
valve
price
guarantee
may
discourage
companies
from
seeking
more
cost
effective
means
to
control
mercury.
The
commenter
pointed
out
this
could
inhibit
advancement
of
new
technologies
because
sources
would
control
only
to
a
set
dollar
amount
regardless
of
advances
in
control
technology.

Response:

EPA
is
not
finalizing
a
safety
valve
provision
in
CAMR.
EPA
maintains
that
the
safety
valve
mechanism
is
not
necessary
to
address
market
volatility
associated
with
the
Hg
reduction
requirements.
This
issue
is
discussed
in
detail
in
section
IV
of
today's
preamble.

Comment:
5­
159
Public
interest
group
comprehensive
comments
(
OAR­
2002­
0056­
3459)
stated
that
the
safety
valve
provision
should
be
discarded
because
it
would
permit
pollution
levels
to
remain
artificially
high
and
because
EPA
expects
it
to
be
used
to
avoid
pollution
controls.
Even
though
purchased
safety
valve
allowances
would
be
deducted
from
the
next
year's
allocation,
there
does
not
seem
to
be
any
limit
on
using
the
provision
to
borrow
again
year
after
year
and
avoiding
controls
indefinitely.
The
commenters
noted
that
EPA's
own
IPM
modeling
showed
it
is
bad
environmental
policy
that
would
increase
emissions
in
the
years
2023­
2030
beyond
the
cap
of
15
tpy
(
to
22
tpy).
It
also
would
have
the
potential
to
delay
controls
if
the
price
were
cheaper
than
controls.
The
commenters
observed
that
EPA
did
not
even
address
the
possibility
of
local
problems
resulting
from
the
safety
valve
provision.
It
also
would
create
a
huge
paradox
associated
with
the
continual
borrowing
of
future
allowances
without
ever
reconciling
the
borrowed
allowances
from
future
compliance
periods.
As
written,
the
commenters
submitted
the
proposed
provision
would
allow
a
plant
to
comply
by
purchasing
allowances
into
the
future.

Response:

EPA
is
not
finalizing
a
safety
valve
provision
in
CAMR.
EPA
maintains
that
the
safety
valve
mechanism
is
not
necessary
to
address
market
volatility
associated
with
the
Hg
reduction
requirements.
This
issue
is
discussed
in
detail
in
section
IV
of
today's
preamble.

Comment:

One
commenter
(
OAR­
2002­
0056­
2897)
expressed
concern
about
the
proposed
safety
valve
mechanism
and
suggested
that
this
concept
be
revisited,
as
it
seemed
to
undermine
the
market
value
concept
of
Title
IV.
The
commenter
noted
that
the
concept
suggests
that
there
would
be
unlimited
allowances
available
at
a
fixed
and
arbitrary
price
unrelated
to
market
conditions
and
that
these
allowances
could
be
borrowed
against
ad
finitum
into
the
future.
The
commenter
questioned
whether
this
truly
incentivizes
commercialization
of
technology.

Response:

EPA
is
not
finalizing
a
safety
valve
provision
in
CAMR.
EPA
maintains
that
the
safety
valve
mechanism
is
not
necessary
to
address
market
volatility
associated
with
the
Hg
reduction
requirements.
This
issue
is
discussed
in
detail
in
section
IV
of
today's
preamble.

Comment:

The
commenter
(
OAR­
2002­
0056­
2897)
stated
that
borrowing
of
future
allowances
may
be
acceptable
if
there
will
be
only
minor
noncompliance
issues
in
the
years
immediately
following
initial
implementation.
The
commenter
asserted
that,
however,
this
could
not
be
guaranteed
and
continued
borrowing
of
out
year
allowances
would
be
extremely
problematic.
The
commenter
stated
that
an
alternative
approach
may
be
to
allow
utilities
to
purchase
off­
system
reductions
from
outside
the
electricity­
generating
sector,
if
their
control
costs
exceed
the
safety
valve
value.
According
to
the
commenter,
this
would
eliminate
the
risk
that
utilities
face
from
excessive
control
costs
while
continuing
to
reduce
the
mercury
emitted
to
the
environment.
The
commenter
5­
160
believed
over
time,
the
depletion
of
these
off­
system
reductions
would
help
incentivize
mercury
control
technology.

Response:

EPA
is
not
finalizing
a
safety
valve
provision
in
CAMR.
EPA
maintains
that
the
safety
valve
mechanism
is
not
necessary
to
address
market
volatility
associated
with
the
Hg
reduction
requirements.
This
issue
is
discussed
in
detail
in
section
IV
of
today's
preamble.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2180,
­
2375,
­
2519,
­
2547,
­
2718,
­
2721,
­
2830,
­
2835,
­
2850,
­
2861,
­
2922,
­
2948,
­
3509,
­
3522,
­
3565,
­
4891)
supported
the
establishing
of
a
safety
valve.
Several
commenters
(
OAR­
2002­
0056­
2375,
­
2718,
­
2903,
­
3522)
supported
an
enhanced,
appropriately
designed
safety
valve
provision
because
it
could
solve
critical
problems
of
implementing
the
trading
program
while
ensuring
compliance
with
and
the
integrity
of
the
Phase
I
and
II
caps.
Specifically,
the
commenters
supported
a
Phase
I
safety
valve
set
at
$
15,000/
lb.
and
a
Phase
II
safety
valve
set
at
$
35,000/
lb.
However,
the
commenters
objected
to
EPA's
proposal
to
deposit
safety
valve
funds
into
the
general
treasury
and
to
deduct
safety
valve
allowances
from
future
years.
The
commenters
proposed
that
safety
valve
funds
should
go
into
a
Mercury
Reduction
Fund
(
MRF)
and
be
used
to
fund
the
development
of
innovative
technologies
and/
or
purchase
additional
off­
utility
system
mercury
reductions.
The
commenters
proposed
that
because
the
MRF
could
yield
net
mercury
reduction
benefits,
there
would
be
no
need
to
confiscate
safety
valve
credits
from
future
years.

Response:

EPA
is
not
finalizing
a
safety
valve
provision
in
CAMR.
EPA
maintains
that
the
safety
valve
mechanism
is
not
necessary
to
address
market
volatility
associated
with
the
Hg
reduction
requirements.
This
issue
is
discussed
in
detail
in
section
IV
of
today's
preamble.
Further,
it
should
be
noted
that
under
section
111
where
state
plans
have
been
approved,
funds
from
the
sale
of
safety
valve
allowances
would
have
been
collected
by
the
States,
not
EPA.

Comment:

One
commenter
(
OAR­
2002­
0056­
4891)
stated
the
safety
valve
provision
is
intended
to
and
would,
in
fact,
minimize
some
of
the
uncertainty
and
unanticipated
market
volatility
that
may
be
associated
with
the
cost
of
mercury
rule
compliance.
The
price
of
allowances
would
be
capped
such
that,
if
the
allowance
price
exceeds
the
"
safety­
valve"
amount,
sources
would
be
authorized
to
borrow
allowances
from
following
years
to
have
access
to
more
allowances
available
at
that
price.
The
commenter
submitted
that
perhaps
the
primary
benefit
of
this
provision
is
that
it
would
render
the
cost
of
complying
with
the
mercury
rule
requirements
somewhat
predictable
and
limited,
though
extremely
costly.

Response:
5­
161
EPA
is
not
finalizing
a
safety
valve
provision
in
CAMR.
EPA
maintains
that
the
safety
valve
mechanism
is
not
necessary
to
address
market
volatility
associated
with
the
Hg
reduction
requirements.
This
issue
is
discussed
in
detail
in
section
IV
of
today's
preamble.

Comment:

One
commenter
(
OAR­
2002­
0056­
2835)
emphasized
that
the
success
of
a
safety
valve
mechanism
would
depend
on
the
design
of
the
state
allocation
system
 
i.
e.,
the
availability
of
undistributed
allowances
from
which
the
sources
could
borrow
 
and
highlighted
the
need
for
consistent
allocation
methods
across
the
various
state
programs.

Response:

EPA
is
not
finalizing
a
safety
valve
provision
in
CAMR.
EPA
maintains
that
the
safety
valve
mechanism
is
not
necessary
to
address
market
volatility
associated
with
the
Hg
reduction
requirements.
This
issue
is
discussed
in
detail
in
section
IV
of
today's
preamble.

Comment:

One
commenter
(
OAR­
2002­
0056­
3431)
noted
that
EPA
has
proposed
a
safety
valve
provision
that
sets
the
maximum
cost
purchasers
must
pay
for
mercury
emission
allowances.
The
commenter
observed
that
EPA
proposed
a
price
of
$
2,187.50
for
a
mercury
allowance
(
one
ounce);
this
price
would
be
adjusted
annually
for
inflation.
The
commenter
stated
that
safety
valve
allowances
could
be
used
to
cover
any
shortfall
between
reported
emissions
and
the
allowances
needed
to
cover
those
emissions.
The
commenter
observed
that
as
proposed,
allowances
purchased
by
a
power
plant
through
the
safety
valve
mechanism
would
come
out
of
the
budget
for
future
years
from
the
state
within
which
the
power
plant
is
located
and,
in
EPA's
example,
would
be
taken
out
of
the
pool
of
allowances
available
for
units
that
have
been
generating
for
at
least
five
years.
The
commenter
stated
that
this
would
result
in
reduced
future
allocations
for
all
plants
in
that
state.
According
to
the
commenter,
it
would
be
unwarranted
and
inequitable
for
other
plants
in
the
state
to
be
penalized
as
a
consequence
of
another
plant
taking
advantage
of
the
safety
valve
mechanism.
The
commenter
stated
that
this
potentially
is
an
especially
problematic
issue
for
plants
in
states
that
have
a
small
number
of
coal­
fired
power
plants.
To
address
this
problem,
the
commenter
suggested
that
the
mechanism
be
revised
to
have
the
"
borrowed"
safety
valve
allowances
come
out
of
the
overall
nationwide
budget,
not
individual
state
budgets.
The
commenter
also
suggested
that
alternatively,
the
mechanism
could
be
changed
to
allow
plants
to
use
future
year
allowances
for
compliance
in
an
earlier
compliance
year,
at
no
charge,
but
on
a
discounted
basis.
According
to
the
commenter,
this
would
eliminate
the
problem
of
penalizing
plants
for
the
use
of
the
safety
valve
mechanism
by
other
plants
in
its
state,
while
making
sure
there
isn't
excess
"
borrowing"
of
future
years'
allowances
through
the
discount
provision.

Response:
5­
162
EPA
is
not
finalizing
a
safety
valve
provision
in
CAMR.
EPA
maintains
that
the
safety
valve
mechanism
is
not
necessary
to
address
market
volatility
associated
with
the
Hg
reduction
requirements.
This
issue
is
discussed
in
detail
in
section
IV
of
today's
preamble.

Comment:

One
commenter
(
OAR­
2002­
0056­
2634)
believed
that
the
EPA's
safety
valve
provision
is
not
a
true
safety
valve
in
that
it
requires
the
confiscation
of
future
years'
allowances.
The
commenter
stated
that
the
purpose
of
the
safety
valve
is
to
ensure
reliability
in
the
electrical
system
by
providing
units
a
means
of
compliance
even
if
technology
does
not
develop
at
the
rate
currently
anticipated.
The
commenter
believed
confiscation
of
future
years
allowances
would
only
exacerbate
the
problem.
The
commenter
suggested
that
if
EPA
ultimately
decides
that
the
safety
valve
provision
will
include
borrowing
of
future
years
allowances,
allowances
should
be
borrowed
from
the
general
pool
and
not
against
an
individual
units
account.
If
the
safety
valve
were
triggered,
it
would
not
be
the
result
of
any
business
decisions
made
at
a
unit
level,
rather
it
would
be
a
reflection
of
the
state
of
technology
across
the
industry.
Therefore,
the
cost
burden
should
also
be
spread
across
the
industry.

Response:

EPA
is
not
finalizing
a
safety
valve
provision
in
CAMR.
EPA
maintains
that
the
safety
valve
mechanism
is
not
necessary
to
address
market
volatility
associated
with
the
Hg
reduction
requirements.
This
issue
is
discussed
in
detail
in
section
IV
of
today's
preamble.

Comment:

One
commenter
(
OAR­
2002­
0056­
1969)
was
unclear
how
a
safety
valve
will
be
an
effective
tool
to
minimize
unanticipated
market
volatility
if
the
future
year
cap
is
reduced
by
the
borrowed
amount.
The
commenter
stated
that
it
certainly
could
alleviate
compliance
concerns
at
the
point
in
time
when
the
safety
valve
is
triggered,
but
also
noted
that,
on
the
other
hand,
triggering
the
safety
valve
in
multiple
years
could
compound
future
compliance
requirements
unless
industry
were
able
to
effectively
reduce
future
mercury
emissions
within
a
reasonable
time
frame.

Similarly,
one
commenter
(
OAR­
2002­
0056­
2850)
supported
the
safety
valve
if
it
does
not
involve
replacement
of
credits
from
future
allocations.
The
commenter
believed
an
interim
phase
buyout
price
of
$
10,000
per
pound
mercury
should
be
considered,
shifting
to
EPA's
proposed
$
35,000
per
pound
value
at
the
final
phase
of
the
program
(
2018).
The
commenter
stated
that
the
price
cap
is
critical
considering
that
there
is
no
commercially
demonstrated
control
technology.
The
commenter
suggested
that
the
pay
back
component
be
eliminated,
since
that
only
serves
to
make
future
year
compliance
all
the
more
difficult
while
emerging
technology
is
commercialized.
5­
163
One
commenter
(
OAR­
2002­
0056­
2861)
suggested
that
some
restriction
is
needed
on
the
use
of
the
safety
valve
to
assure
that
borrowed
allowances
do
not
affect
the
future
allocations
of
sources
that
met
compliance
without
the
need
to
borrow.

One
commenter
(
OAR­
2002­
0056­
2180)
suggested
that
proceeds
from
the
safety
valve
should
be
returned
to
other
allowance
holders
or
held
in
escrow
until
the
user
of
the
safety
valve
can
return
the
borrowed
allowances.

Several
commenters
(
OAR­
2002­
0056­
2948,
­
3565)
requested
EPA
to
modify
their
proposal
to
enable
a
unit
to
borrow
from
its
own
future­
year
allowance
account
(
resulting
in
fewer
allowances
available
to
that
unit
in
future
years).
Commenter
OAR­
2002­
0056­
2948
stated
this
would
avoid
a
situation
where
units
that
did
not
borrow
allowances
are
forced
to
bear
part
of
the
burden
of
a
reduced
number
of
available
allowances
in
future
years.
Commenter
OAR­
2002­
0056­
3565
recommended
that
the
unit
borrowing
from
its
own
future­
year
allowance
still
pay
EPA
the
$
2,187.50
per
allowance
for
the
privilege
to
borrow
against
future
years.
The
commenter
believed
the
unit
should
not
be
borrowing
from
the
general
pool
of
allowances
available
to
all
units
within
the
state
as
EPA
has
proposed.
The
commenter
stated
that
this
would
result
in
fewer
allowances
available
for
allocation
in
future
years,
not
just
to
the
units
that
borrowed
allowances,
but
to
all
units.
The
commenter
noted
that
EPA
also
proposes
that
funds
received
from
the
purchase
of
safety
valve
allowances
be
deposited
in
the
United
States
Treasury.
The
commenter
requested
that
these
funds
instead
be
provided
to
the
United
States
Department
of
Energy
to
assist
in
the
development
of
innovative
mercury
emissions
control
projects,
such
as
Powerspan's
Electro
Catalytic
Oxidation
technology.

Response:

EPA
is
not
finalizing
a
safety
valve
provision
in
CAMR.
EPA
maintains
that
the
safety
valve
mechanism
is
not
necessary
to
address
market
volatility
associated
with
the
Hg
reduction
requirements.
This
issue
is
discussed
in
detail
in
section
IV
of
today's
preamble.

Comment:

One
commenter
(
OAR­
2002­
0056­
3443)
stated
that
EPA
has
asked
for
comments
on
the
need
for
a
safety
valve
mechanism
under
which
the
price
of
allowances
is
effectively
capped.
See
69
FR
12397
and
12410.
The
commenter
can
support
the
inclusion
of
such
a
mechanism
in
the
trading
rule
but
contended
that
an
early
reduction
credit
program
would
be
a
more
effective
tool
for
dampening
the
market
volatility
that
could
result
from
implementation
of
a
cap
and
trade
program.
The
commenter
believed
an
early
reduction
program
would
be
a
better
policy
and
market
tool
since
it
would
grant
credit
for
reductions
made
early
rather
than
grant
credit
for
the
promise
of
greater
future
reductions.
The
commenter
noted
early
reduction
allowance
programs
have
been
part
of
previous
cap
and
trade
programs,
and
are
better
suited
to
dampen
market
volatility
by
making
emission
credits
available
ahead
of
compliance
deadlines.
The
commenter
pointed
out
that
the
safety
valve
mechanism,
by
contrast,
would
attempt
to
artificially
restrain
the
market
price
of
allowances.
The
market
price
of
an
emission
allowance
obtained
via
a
safety
valve
provision
could
vary
greatly
depending
on
the
final
source
of
that
emission
allowance,
5­
164
creating
situations
in
which
the
safety
valve
would
have
little
effect
on
dampening
market
volatility
or
facilitating
compliance
decisions.

Response:

EPA
is
not
finalizing
a
safety
valve
provision
in
CAMR.
EPA
maintains
that
the
safety
valve
mechanism
is
not
necessary
to
address
market
volatility
associated
with
the
Hg
reduction
requirements.
This
issue
is
discussed
in
detail
in
section
IV
of
today's
preamble.
See
the
discussion
of
early
reduction
credits
in
following
section.

Comment:

One
commenter
(
OAR­
2002­
0056­
1842)
offered
the
following
"
variable
mercury
safety
valve
plan,"
based
on
the
mercury
cap
and
trade
proposal.

Proposition:
Variable
mercury
safety
valve
allowance
pricing
should
be
included
in
the
proposed
mercury
and
cap
and
trade
rule.

Purpose:
To
eliminate
the
impasse
over
feasability.
This
impasse
is
largely
based
on
the
question
of
mercury
technology
performance.
Variable
pricing
eliminates
the
need
to
address
this
question.

Proposition
Specifics:
Present
proposals
call
for
absolute
diminishing
caps
with
a
fixed
safety
valve
price
approach.
This
should
be
changed
to
single
cap
target
(
5
to
10
tpy)
with
safety
valve
allowance
prices
which
start
low
but
increase
yearly.
The
result
is
that
the
achievement
of
the
target
is
probable
but
the
maximum
cost
is
predictable.

Background:
Much
of
the
debate
centers
on
the
amount
of
mercury
removal
which
should
be
achieved
in
various
years.
The
differences
are
not
about
the
goal
but
about
the
cost
of
obtaining
the
goal.
Power
plants
in
the
U.
S.
presently
emit
48
tons
(
96,000
lb)
of
mercury/
yr.
Environmentalists
contend
that
90
percent
of
the
mercury
can
be
removed
with
known
technology
and
are
calling
for
a
five
ton
mercury
cap
in
2007.
Power
plant
owners
believe
there
is
no
reliable
technology
available
and
are
questioning
whether
a
26
ton
cap
in
2010
is
too
onerous.
However,
both
agree
that
by
2018
it
is
necessary
to
remove
between
70­
90
percent
of
the
mercury.

Mercury
is
bio­
accumulative.
Therefore
mercury
removed
in
earlier
years
will
benefit
those
living
in
2018.
Since
there
is
broad
agreement
to
reduce
mercury
exposure
in
2018,
there
must
be
agreement
that
cost
effective
earlier
reduction
of
mercury
is
also
desirable.
The
problem
is
that
there
is
great
disagreement
on
what
will
be
cost
effective
when.

The
proposed
rule
attempts
to
allay
power
plant
concerns
about
cost
through
a
"
safety
valve"
provision.
A
34
ton
cap
is
proposed
for
2010.
68,000
pounds
of
5­
165
mercury
allowances
would
be
allocated
to
the
300,000
MW
of
generating
capacity.
The
average
300
MW
plant
would
have
an
allowance
of
68
pounds.
Should
he
emit
more
than
68
lbs
in
2010
he
can
buy
allowances
on
the
open
market.
If
he
cannot
buy
allowances
on
the
open
market
for
less
he
can
buy
them
from
EPA
for
$
35,000/
lb.
The
average
300
MW
plant
emits
96
lbs/
yr
of
mercury.
Therefore
the
worst
case
scenario
is
a
2010
cost
of
28
lbs
x
$
35,000
=
$
980,000.
Impasse
Analysis:
There
is
no
supplier
with
deep
pockets
guaranteeing
to
remove
90
percent
of
the
mercury
at
$
5,000/
lb
of
mercury
in
2007.
So
while
environmentalists
claim
that
this
can
be
done
utilities
can
justifiably
ask:
what
if
we
install
lots
of
equipment
which
does
not
work
and
then
still
end
up
not
meeting
the
limits?
They
argue
that
by
2018
solutions
will
be
available
at
a
reasonable
cost.
So
let's
wait.

Argument
over
an
unknown
is
fatal
to
any
progress.
Since
the
cost
of
removal
at
any
point
in
time
is
not
certain,
progress
can
only
be
made
by
eliminating
the
relevance
of
this
"
unknown."
Variable
safety
valve
allowance
pricing
does
precisely
this.

Proposition
Details:
The
safety
valve
concept
is
undeniably
a
positive
addition.
Environmentalists
who
anticipate
allowances
selling
for
$
5,000/
lb
will
not
object
to
a
$
35,000
safety
valve
price.
Utilities
which
anticipate
much
higher
costs
are
relieved
that
there
is
a
cost
ceiling.
But
this
high
priced
safety
valve
which
is
only
applicable
at
a
34
ton
cap
in
2010
does
little
to
break
the
impasse.
However,
the
basic
idea
can
be
exploited
to
completely
eliminate
the
Impasse.

The
plan
entails
a
fixed
cap
with
variable
price
allowances.
Under
this
proposal
the
ultimate
cap,
whether
it
is
5
tons
or
10
tons,
would
be
utilized
from
the
first
date
of
promulgation.
This
means
that
the
average
300
MW
utility
would
have
an
allowance
of
10
to
20
pounds
from
some
date
starting
in
2006
through
2010.
The
plant
would
buy
allowances
for
yearly
emissions
above
this
figure.
However,
if
the
allowances
exceeded
some
price,
e.
g.
$
1,000­
5,000
in
the
first
year,
they
could
be
purchased
for
that
amount
from
EPA.
This
price
would
rise
each
year.
So
for
example
the
price
could
start
at
$
1,000/
lb
in
2007
and
rise
to
$
7,000/
lb
in
2010.
A
2018
price
of
$
25,000/
lb
instead
of
the
proposal
of
$
35,000
could
be
set.

This
mechanism
favors
all
parties.
Environmentalists
who
are
confident
that
90
percent
removal
will
be
achieved
at
$
5,000
lb
would
back
a
variable
price
at
this
amount
at
the
earliest
time
they
can
negotiate.
Utilities
who
are
already
anticipating
spending
up
to
$
35,000/
lb
in
2018
will
see
themselves
much
better
off
under
this
provision.
Suppliers
will
be
spurred
to
massive
R
and
D
programs
because
they
can
target
specific
years
when
they
are
confident
their
technology
will
be
more
cost
effective
than
the
safety
valve
price.
The
public
will
be
better
off
because
the
private
sector
will
shoulder
the
development
costs.
EPA
and
DOE
will
be
relieved
that
the
burdens
are
transferred
elsewhere.
5­
166
Summary:
The
fixed
cap/
variable
safety
valve
allowance
prices
for
mercury
would
eliminate
the
impasse
in
Clear
Skies
passage
and
would
result
in
a
very
cost
effective
solution
to
the
mercury
removal
problem.
Since
many
suppliers
believe
they
have
solutions
which
will
remove
mercury
at
low
cost,
but
who
do
not
see
any
market
until
2018,
this
provision
would
trigger
immediate
development
of
technology.
In
the
past,
government
funded
development
of
air
pollution
control
technology
has
proven
to
be
expensive
and
not
as
productive
as
private
funding.
Revenues
generated
by
the
safety
valve
option
could
be
funneled
directly
to
mercury
technology
development.
So
this
provision
will
be
an
important
addition
to
the
proposed
legislation.

The
commenter
then
offered
an
example
of
how
the
variable
mercury
safety
valve
plan
would
work
for
a
300
MW
plant.

Response:

EPA
is
not
finalizing
a
safety
valve
provision
in
CAMR.
EPA
maintains
that
the
safety
valve
mechanism
is
not
necessary
to
address
market
volatility
associated
with
the
Hg
reduction
requirements.
This
issue
is
discussed
in
detail
in
section
IV
of
today's
preamble.

Comment:

One
commenter
(
OAR­
2002­
0056­
2918)
believed
that
an
enhanced,
appropriately
designed
"
Safety
Valve"
provision
could
resolve
several
critical
problems
related
to
implementation
of
a
mercury
cap
and
trade
program
for
the
coal­
fired
power
plant
industry.
The
commenter
stated
a
properly
designed
safety
valve
mechanism
could
ensure
compliance
with,
and
the
integrity
of,
the
Phase
I
(
2010)
and
Phase
II
(
2018)
mercury
emission
caps
while
providing
the
flexibility
to
address
the
current
uncertainty
about
mercury
emissions
and
their
control.

The
commenter
proposed
that
EPA
enhance
the
safety
valve
provision
and
design
it
to
address
the
following
critical
cap
and
trade
implementation
issues:

°
Significant
uncertainty
exists
over
the
accuracy
of
EPA's
ICR
and
NATEMIS
national
emissions
database
inventories,
as
well
as
the
accuracy
of
EPA's
34­
ton
co­
benefits­
based
Phase
I
mercury
emissions
cap.
Therefore,
the
coal­
fired
power
plant
industry
sees
significant
uncertainty
whether
sufficient
mercury
allowances
will
be
available
for
compliance
after
the
co­
benefit
controls
are
installed
under
EPA's
proposed
CAIR.

°
In
addition
to
the
potential
Phase
I
shortfall
of
mercury
allowances,
the
compliance
issue
is
exacerbated
for
one
or
more
coal
ranks
if
EPA's
allowance
multipliers
are
not
set
appropriately.

°
EPA's
proposed
confiscation
of
future
year
"
borrowed"
mercury
allowances
in
its
safety
valve
proposal
presents
serious
potential
system
reliability
and
future
compliance
problems.
As
currently
understood
by
industry,
if
significant
advancements
in
mercury
5­
167
control
technology
do
not
develop
at
a
commercial
level
by
Phase
II
(
2018),
the
confiscation
of
future
year
allowances
will
simply
"
dig
the
hole
deeper."

°
Finally,
the
safety
valve
needs
to
materially
contribute
to
actual
achievement
of
the
Phase
II
15
ton/
yr
mercury
emissions
cap.
The
commenter
prepared
a
"
Hg
Co­
Benefits
and
CSA
Phase
I
and
II
Analysis"
that
demonstrated
(
based
on
EPA's
ICR
II
and
NATEMIS
national
emissions
inventory
data)
that
after
application
of
co­
benefit
control
technology
required
to
meet
the
CSA
requirements,
and
with
the
application
of
all
feasible
ACI
mercury
control
(
assuming
it
becomes
commercially
available),
national
mercury
emissions
from
power
plants
would
remain
at
about
19
tons/
year
by
Phase
II.

The
commenter
believed
that
a
safety
valve
must
be
properly
designed
to
maximize
mercury
emission
reductions,
while
enabling
the
operators
of
coal­
fired
power
plants
to
comply
with
the
Phase
I
and
Phase
II
caps
at
an
acceptable
cost.
The
commenter
submitted
that
a
properly
designed
safety
valve
could
also
accelerate
the
development
of
commercially
available
mercury
control
technologies
necessary
to
achieve
the
proposed
Phase
II
15
ton/
year
cap.
The
commenter
stated
that
the
aforementioned
co­
benefits
analysis
was
performed
principally
with
the
use
of
EPA's
IPM
modeling
assumptions
about
the
effectiveness
of
mercury
control
technologies,
including
ACI.

The
commenter
recommended
that
EPA
revise
its
proposed
safety
valve
provision
to
include
the
following
design
elements
for
both
Phase
I
and
Phase
II
of
the
mercury
cap
and
trade
program:

°
Allow
a
lower
$/
lb
mercury
safety
valve
fee
for
compliance
during
Phase
I
(
2010­
2017).
The
safety
valve
fee
during
Phase
I
could
be
set
at
$
15,000
per
pound.
Covered
facilities
would
pay
the
fee
in
lieu
of
using
mercury
allowances
for
compliance
in
the
event
that
the
mercury
allowance
price
exceeds
$
15,000
per
pound.

°
Allow
payment
of
EPA's
currently
proposed
$
35,000/
lb
fee
during
Phase
II,
in
lieu
of
using
mercury
allowances
for
compliance
in
the
event
that
the
allowance
market
price
exceeds
$
35,000
per
pound.

°
Do
not
confiscate
future
year
mercury
allowances
under
either
the
Phase
I
cap,
or
under
the
Phase
II
cap.
Facilities
paying
the
fee
would
not
be
allowed
to
use
any
Phase
I
or
Phase
II
"
banked"
emission
credits.
This
feature
would
ensure
that
banked
emissions
must
be
used,
or
placed
on
the
market
(
likely
at
a
price
lower
than
the
fee),
before
compliance
is
allowed
by
payment
of
the
safety
valve
fee,
to
preserve
the
integrity
of
the
mercury
caps
to
the
maximum
extent
possible.

°
Establish
a
Mercurv
Reduction
Fund
from
the
safety
valve
fees
collected,
and
disburse
the
funds
(
with
no
more
than
a
5percent
administrative
cost)
to
achieve
mercury
reductions
and
advancing
mercury
control
technologies,
by
contracting
for
and
funding:
(
1)
Project
proposals
to
make
mercury
reductions
from
other
mercury
emissions
sources
"
off
the
utility
system";
and,
(
2)
Project
proposals
that
demonstrate
advanced
mercury
control
5­
168
technologies,
including
commercial
level
generating
unit
demonstrations
(
i.
e.,
units
at
25MW
to
750MW
capacity).

°
Conduct
a
mercury
cap
and
trade
program
"
reasonable
progress"
review
at
years
2015,
2018,
and
2021
to
assess
the
actual
mercury
emissions
reduction
progress
occurring
from
electric
generating
units
(
EGUs)
under
the
cap
and
trade
program,
compared
with
the
Phase
I
and
Phase
II
mercury
caps.
The
purpose
of
a
"
reasonable
progress"
review
would
be
to
determine
whether
any
program
adjustments
need
to
be
promulgated
by
rule
revision,
to
ensure
that
the
mercury
reduction
caps
are
achieved
 
given
the
state
of
development
of
mercury
emission
reduction
technologies,
and
the
reliability
of
the
national
electric
supply
grid
system.

The
commenter
stated
that
the
safety
valve
proposal
would
guarantee
a
maximum
price
at
which
regulated
sources
would
be
able
to
purchase
mercury
allowances
for
Phase
I
and
Phase
II,
market
pressures
notwithstanding.
The
safety
valve
also
would
minimize
unanticipated
allowance
market
volatility
by
ensuring
that
the
price
for
allowances
would
not
exceed
a
fixed
ceiling.
According
to
the
commenter,
EPA
thereby
would
provide
industry
with
reliable
market
information
for
strategic
compliance
planning.
Even
more
importantly,
in
the
event
that
it
proved
more
costly
and
difficult
to
achieve
the
Phase
I
and
Phase
II
mercury
emissions
reduction
targets
than
is
now
projected,
the
marginal
cost
of
the
mercury
control
program
could
not
exceed
$
15,000
per
pound
in
Phase
I
and
$
35,000
per
pound
in
Phase
II.
The
commenter
stated
that
this
would
protect
consumers
from
unanticipated
and
unjustifiable
costs.
For
these
reasons,
the
commenter
supported
the
creation
of
a
safety
valve
mechanism
for
both
Phase
I
and
Phase
II
of
the
proposed
mercury
cap
and
trade
program
to
ensure
that
emissions
reductions
will
be
achieved,
but
that
control
costs
would
not
exceed
a
predetermined
level.

The
commenter
further
supported
the
creation
of
a
Mercury
Reduction
Fund
as
an
effective
means
for
maximizing
the
economic
efficiency
of
achieving
the
Phase
I
and
Phase
II
mercury
reduction
caps.
First,
safety
valve
funds
could
be
used
to
stimulate
the
development
of
innovative
control
technologies,
by
providing
capital
to
potential
innovators
that
is
otherwise
unavailable
due
to
the
scale
of
the
required
investment,
the
delay
in
return,
or
the
degree
of
risk
involved.
Second,
the
fund
could
act
as
a
safety
net
or
relief
valve
by
making
it
easy
for
sources
with
limited
or
no
emissions
control
capability
to
obtain
needed
reductions
from
off­
line
sources
that
can
reduce
emissions
more
efficiently.

The
commenter
pointed
out
that
a
safety
valve
fund
could
enhance
compliance
with
emissions
standards
in
several
ways.
The
commenter
continued
that
the
fund
also
would
promote
regulatory
certainty
by
guaranteeing
a
cap
on
removal
costs.
This
would
help
owners
and
operators
of
regulated
sources
better
plan
for
the
future.
The
commenter
submitted
that
the
fund
also
would
enable
EPA
to
target
sources
for
cost­
effective
emissions
reductions
that
EPA
otherwise
would
lack
the
statutory
authority
to
regulate.
Armed
with
safety
valve
funds,
the
commenter
believed
EPA
could
act
as
a
market
participant
and
procure
additional
reductions
from
any
entity
willing
to
be
paid
in
return.
5­
169
The
commenter
added
that
a
safety
valve
fund
could
also
significantly
benefit
the
environment.
For
example,
if
the
safety
valve
were
set
at
an
appropriate
marginal
control
cost
level
as
described
above,
regulated
sources
would
be
discouraged
from
paying
into
the
fund
to
cover
emissions.
Rather,
sources
would
be
encouraged
to
develop
innovative
ways
to
reduce
emissions
more
efficiently.
Further,
the
commenter
stated
a
safety
valve
fund
would
encourage
the
aggregation
of
capital
for
larger,
strategic
investments
by
reducing
associated
transaction
costs.
The
commenter
suggested
EPA
could
then
use
the
capital
at
its
disposal
to
invest
in
a
variety
of
technological
innovations,
including
low­
risk,
low­
return
investments
as
well
as
higher­
risk
and
potentially
higher­
return
investments.

In
conclusion,
the
commenter
urged
EPA
to
establish
Phase
I
and
Phase
II
safety
valve
fees
at
appropriate
marginal
cost
level
(
as
proposed
above)
that
would
be
high
enough
to
discourage
sources
from
choosing
payment
into
the
fund
as
their
means
of
control,
but
low
enough
so
sources
that
could
not
obtain
controls
for
a
reasonable
cost
would
not
be
penalized.
The
commenter
further
recommended
that
EPA
use
safety
valve
proceeds
to
purchase
additional
cost­
effective
off­
utility
(
EGU)
sector
reductions,
not
to
purchase
or
confiscate
mercury
allowances
from
future
years.
By
implementing
the
recommended
safety
valve
provision,
the
commenter
believed
EPA
could
prevent
delay
in
important
air
quality
achievements.
Moreover,
the
commenter
supported
the
use
of
any
excess
safety
valve
funds
to
provide
capital
for
the
development
of
better,
more
efficient
mercury
controls.

Response:

EPA
is
not
finalizing
a
safety
valve
provision
in
CAMR.
EPA
maintains
that
the
safety
valve
mechanism
is
not
necessary
to
address
market
volatility
associated
with
the
Hg
reduction
requirements.
This
issue
is
discussed
in
detail
in
section
IV
of
today's
preamble.

Comment:

One
commenter
supported
the
proposed
safety
valve
price
level
as
a
means
of
capping
the
overall
economic
impact
of
controlling
mercury
emissions.
The
commenter
submitted
the
price
cap
would
be
critical
considering
that
there
is
no
commercially
demonstrated
control
technology.
The
commenter
agreed
that
EPA's
cap­
and­
trade
program
would
effectively
address
alleged
mercury
hot
spots
and
concluded
that
most
cost­
effective
reductions
will
be
made
at
the
larger,
higher
emitting
sources.
The
commenter
also
agreed
the
remaining
uncontrolled
emissions
would
be
largely
elemental
mercury
that
is
not
as
likely
to
be
deposited
locally
as
is
the
particulate
and
oxidized
mercury.
(
69
FR
4703.)

However,
the
commenter
was
unclear
how
a
safety
valve
would
be
an
effective
tool
to
minimize
unanticipated
market
volatility
if
the
future
year
cap
were
reduced
by
the
borrowed
amount.
The
commenter
believed
that
while
it
may
alleviate
compliance
concerns,
at
some
point
in
time
triggering
the
safety
valve
in
multiple
years
could
compound
future
compliance
requirements
unless
industry
were
able
to
effectively
reduce
future
mercury
emissions
within
a
reasonable
time
frame.
5­
170
The
commenter
recommended
that
if
the
safety
valve
is
triggered,
the
annual
allocations
to
the
plant
withdrawing
from
the
safety
valve
pool
should
be
decreased
at
a
rate
of
0.5
ounces
for
every
ounce
of
mercury
it
purchased
under
the
safety
valve.
(
69
FR
4704.)

Response:

EPA
is
not
finalizing
a
safety
valve
provision
in
CAMR.
EPA
maintains
that
the
safety
valve
mechanism
is
not
necessary
to
address
market
volatility
associated
with
the
Hg
reduction
requirements.
This
issue
is
discussed
in
detail
in
section
IV
of
today's
preamble.

5.8.3
Early
Reduction
Credits
and
Incentive
Pools
Comment:

One
commenter
(
OAR­
2002­
0056­
3531)
further
suggested,
if
the
EPA
were
to
create
an
early
reduction
credit
program,
significant
reductions
prior
to
2010
would
still
be
achieved
by
units
coming
on
line
early
to
earn
the
ERCs.
The
commenter
concluded
that
as
a
result,
early
mercury
reductions
will
be
achieved
while
still
allowing
for
a
reasonable
cost
effective
installation
schedule.

Response:

The
first
phase
Hg
cap
is
set
at
a
level
that
requires
no
additional
installation
of
controls
relative
to
CAIR,
because
it
is
set
at
a
level
that
represents
projected
cobenefit
mercury
reductions
that
will
occur
as
a
result
of
NO
x
and
SO
2
control
technologies
installed
under
CAIR.
Acid
Rain
Program
units
and
SIP
call
units
can
bank
excess
NO
x
and
SO
2
reductions
achieved
prior
to
2010
for
use
under
CAIR.
Further,
EPA
is
finalizing
that
banking
be
allowed
without
restriction
from
the
start
of
the
Hg
cap­
and­
trade
program.
Banking
of
allowances
will
provide
flexibility
to
sources,
encourage
earlier
or
greater
reductions
than
required,
stimulate
the
market,
and
encourage
efficiency.

Comment:

One
commenter
(
OAR­
2002­
0056­
3444)
stated
that
the
proposed
initial
compliance
date
of
2010
creates
a
large
uncertainty
in
the
ability
of
the
Electric
Generating
Industry
to
achieve
the
reductions
required
by
the
initial
mercury
cap.
To
assist
the
industry
and
the
EPA
in
achieving
these
target
reductions
the
commenter
believed
it
would
be
necessary
to
implement
an
Early
Reduction
Credit
(
ERC)
program
to
create
incentives
for
coal
fired
Utility
Units
to
install
controls
well
before
the
2010
target
date.
The
commenter
submitted
that
to
effectively
achieve
early
mercury
reductions
the
following
elements
should
be
part
of
the
proposed
ERC
program:
1)
Installation
of
controls
must
be
accomplished
prior
to
2009;
2)
Continuous
Mercury
Emissions
Monitoring
Systems
must
be
installed
with
a
minimum
demonstrated
data
availability
of
90
percent;
3)
Installed
control
efficiency
must
meet
or
exceed
the
co­
benefit
removal
efficiency
target
for
the
type
of
coal
being
combusted;
4)
ERC's
allocated
to
sources
must
be
used
prior
to
the
2018
final
budget
compliance
date.
5­
171
Response:

The
first
phase
Hg
cap
is
set
at
a
level
that
requires
no
additional
installation
of
controls
relative
to
CAIR,
because
it
is
set
at
a
level
that
represents
projected
cobenefit
mercury
reductions
that
will
occur
as
a
result
of
NO
x
and
SO
2
control
technologies
installed
under
CAIR.
Acid
Rain
Program
units
and
SIP
call
units
can
bank
excess
NO
x
and
SO
2
reductions
achieved
prior
to
2010
for
use
under
CAIR,
and
sources
will
be
allowed
to
bank
starting
at
beginning
of
the
first
phase
of
the
Hg
cap­
and­
trade
program.

Comment:

One
commenter
(
OAR­
2002­
0056­
4891)
added
emissions
reductions
credits
should
be
provided
to
facilities
subject
to
the
rule
for
commissioning
projects
that
achieve
mercury
emissions
reductions
from
other
mercury
emission
sources.

Response:

The
ability
to
accurately
measure
emissions
reductions,
and
thus
guarantee
the
value
of
an
allowance,
is
essential
to
a
successful
cap­
and­
trade
program.
Allowing
credit
to
be
used
in
the
Hg
cap­
and­
trade
program
for
utilities
from
off­
sector
reductions
that
may
not
have
adequate
Hg
emissions
monitoring,
would
jeopardize
the
certainty
behind
the
value
of
an
allowance,
and
thus
the
functioning
of
the
trading
program.

Comment:

One
commenter
(
OAR­
2002­
0056­
3446)
recommended
that
EPA
develop
a
technology
incentive
pool,
a
mechanism
in
which
allowances
from
the
first
compliance
period
would
be
distributed
early
to
plants
that
deploy
advanced
mercury
control
technology.
This
would
spread
the
risks
of
technology
development
and
help
build
confidence
in
the
performance
and
cost
of
advanced
control
technologies.
The
commenter
stated
that
an
IPM
modeling
run
found
a
2.6
ton/
yr
incentive
pool
(
with
a
26­
ton
Phase
I
cap
and
a
15­
ton
Phase
II
cap)
would
achieve
a
total
penetration
of
31
GW
of
ACI
in
2010
and
48
GW
of
ACI
in
2015
 
11
and
5
GW
of
ACI
penetration
more
than
a
program
with
no
technology
incentive
pool.
The
commenter
added
that
this
added
technology
penetration
would
be
achieved
at
an
incremental
net
present
value
cost
of
$
400
million
or
0.6
percent
of
total
3­
pollutant
compliance
costs.

Response:

While
the
proposed
technology
incentive
pool
has
merit
for
the
potential
to
stimulate
earlier
adoption
of
Hg
control
technology,
EPA
believes
that
the
market
forces
at
work
under
the
Hg
cap­
and­
trade
program
will
act
to
promote
the
development
of
Hg
control
technology,
and
the
technology
incentive
pool
is
not
necessary.

Comment:
Several
commenters
(
OAR­
2002­
0056­
2181,
2519)
noted
the
EPA
has
indicated
that
it
is
examining
a
possible
incentive
within
the
cap
and
trade
program
that
would
5­
172
provide
and
set
aside
allowances
that
would
be
used
to
develop
so
called
"
technology
incentive
pools."
EPA
appears
particularly
concerned
with
providing
a
technology
assist
for
the
development
and
deployment
of
activated
carbon
injection
(
ACI)
systems.
The
commenters
had
serious
concerns
about
applying
such
a
system
in
the
context
of
a
cap
and
trade
program
because
it
would
conflict
with
the
goal
of
a
system
that
allows
market
forces
to
set
the
cost
of
compliance.
The
commenters
stated
that
in
a
trading
program,
an
appropriately
set
cap
should
be
the
signal
that
will
drive
the
appropriate
economic
response,
which
may
include
any
number
of
market
driven
reactions,
such
as
new
technology
investments,
fuel
choices
or
efficiency
standards.
One
of
the
primary
advantages
of
the
cap
and
trade
approach
is
the
ability
to
drive
the
development
of
new
technology
solutions
that
are
not
foreseen
in
the
program
design.
The
commenters
believed
that
any
technology
set­
aside
within
the
context
of
a
trading
program
would
tend
to
predetermine
an
economic
outcome,
generally
at
the
expense
of
alternative
choices
that
may
provide
consumers
with
lower
cost
solutions,
a
more
aggressive
environmental
benefit,
or
both.
The
commenters
submitted
that
this
has
been
well
documented
in
earlier
cap
and
trade
programs
in
which
new
and
lower
cost
solutions
that
were
not
expected
or
predicted
during
the
program
design
period
successfully
evolved
and
were
deployed.
The
future
success
of
the
program
should
not
be
constrained
by
trying
to
anticipate
future
technology
or
market
solutions.
The
commenters
stated
the
program
will
find
the
right
answers
if
it
is
designed
to
treat
all
sources
equally
and
reward
efficiency
and
low
emissions.

Response:

While
the
proposed
technology
incentive
pool
has
merit
for
the
potential
to
stimulate
earlier
adoption
of
Hg
control
technology,
EPA
believes
that
the
market
forces
at
work
under
the
Hg
cap­
and­
trade
program
will
act
to
promote
the
development
of
Hg
control
technology,
and
the
technology
incentive
pool
is
not
necessary.

Comment:

Many
commenters
(
OAR­
2002­
0056­
1608,
­
1673,
­
1814,
­
2163,
­
2180,
­
2224,
­
2375,
­
2718,
­
2725,
­
2835,
­
2843,
­
2845,
­
2850,
­
2861,
­
2862,
­
2900,
­
2907,
­
2922,
­
2948,
­
2951,
­
3431,
­
3444,
­
3521,
­
4132)
suggested
that
EPA
should
provide
for
early
reduction
credits.
One
commenter
(
OAR­
2002­
0056­
2180)
stated
that
to
encourage
development
and
implementation
of
technologies
that
reduce
mercury
emissions,
and
to
help
insure
a
workable
cap
and
trade
program,
there
should
be
a
crediting
program
for
early
mercury
reductions.
One
commenter
(
OAR­
2002­
0056­
2725)
believed
that
early
reductions
reduce
the
overall
mercury
loading
in
the
environment
and,
to
the
extent
power
plant
reductions
will
have
a
positive
impact
on
public
health,
achieve
those
benefits
earlier.
In
particular,
for
the
proposed
trading
program,
the
commenter
supported
setting
the
"
baseline"
from
which
reductions
will
be
measured
at
an
earlier
date
and
protecting
the
ability
to
bank
allowances
throughout
the
program.

Response:

EPA
is
not
finalizing
an
early
reduction
program.
The
first
phase
Hg
cap
is
set
at
a
level
that
requires
no
additional
installation
of
controls
relative
to
CAIR,
because
it
is
set
at
a
level
5­
173
that
represents
projected
cobenefit
mercury
reductions
that
will
occur
as
a
result
of
NO
x
and
SO
2
control
technologies
installed
under
CAIR.
Acid
Rain
Program
units
and
SIP
call
units
can
bank
excess
NO
x
and
SO
2
reductions
achieved
prior
to
2010
for
use
under
CAIR,
and
sources
will
be
allowed
to
bank
starting
at
beginning
of
the
first
phase
of
the
Hg
cap­
and­
trade
program.
EPA
believes
that
the
cap­
and­
trade
program,
by
relying
on
market
forces,
will
provide
incentives
for
the
development
of
mercury
control
technologies.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2862,
­
2922)
supported
the
creation
of
an
early
reduction
credit
feature
as
part
of
the
mercury
trading
program
to
aid
in
the
development
of
mercury
emissions
control
technologies.
One
commenter
(
OAR­
2002­
0056­
2922)
stated
that
EPA
should
create
a
small
reserve
of
early
reduction
credits
for
units
that
install
mercury­
specific
control
technology
by
2014.
The
commenters
(
OAR­
2002­
0056­
2862,
­
2922)
submitted
that
EPA
should
limit
the
program
to
mercury­
specific
controls;
no
credits
should
be
given
for
the
installation
of
scrubbers,
SCRs,
or
other
controls
designed
primarily
to
reduce
emissions
of
NO
x,
SO
2,
or
other
non­
mercury
emissions.
The
commenters
believed
EPA
should
award
credits
only
for
reductions
of
mercury
emissions
that
result
from
mercury­
specific
controls
that
go
beyond
the
reductions
achieved
as
co­
benefits
from
NO
x
or
SO
2
controls.

Response:

EPA
is
not
finalizing
an
early
reduction
program.
EPA
believes
that
the
cap­
and­
trade
program,
by
relying
on
market
forces,
will
provide
incentives
for
the
development
of
mercury
control
technologies.
Additionally,
the
ability
of
sources
to
bank
allowances
starting
at
the
beginning
of
the
Hg
cap­
and­
trade
program,
will
provide
flexibility
to
sources,
encourage
earlier
or
greater
reductions
than
required,
stimulate
the
market,
and
encourage
efficiency.

Comment:

Commenter
OAR­
2002­
0056­
2861
stated
that
under
the
recommended
alternate
cap
and
trade
proposal
(
first
cap
and
allocations
begin
in
2015),
the
commenter
recommended
an
early
reduction
credit
program
that
provides
credit
only
for
reductions
attributed
to
technologies
designed
specifically
to
capture
mercury.
The
utility
would
provide
a
demonstration
of
the
removal
efficiency
and
would
be
provided
credit
for
the
difference
between
actual
mercury
emissions
and
emissions
that
would
have
occurred
without
the
use
of
the
technology.
The
commenter
suggested
the
operating
permit
would
specify
conditions
to
verify
control
technology
performance.

If
EPA
establishes
a
cap
and
trade
program
that
begins
in
2010,
then
commenter
OAR­
2002­
0056­
2861
believed
an
early
reduction
credit
program
would
be
even
more
important
and
should
include
credit
for
reductions
achieved
as
a
co­
benefit
of
SO
2
and
NO
x
controls.
The
commenter
suggested
that
in
order
to
earn
early
reduction
credits,
EPA
would
need
to
require
only
that
the
facility
install
appropriate
monitoring
technology
to
quantify
emissions
and
the
level
of
mercury
removal
resulting
from
the
installation
of
emission
controls
for
SO
2
and
NO
x
or
5­
174
demonstration
technologies
specifically
aimed
at
removing
mercury.
The
commenter
noted
that
the
level
of
"
co­
benefits"
associated
with
SO
2
and
NO
x
controls
is
uncertain
and
variable,
and
utilities
will
need
to
work
with
the
technologies
to
develop
ways
to
enhance
their
removal
efficiencies.
The
commenter
submitted
that
compliance
by
2010
will
also
be
very
difficult,
and
providing
an
early
reduction
credit
program
will
help
facilitate
compliance
while
preserving
the
nation's
fuel
diversity.
Early
reduction
credits
would
provide
an
incentive
for
companies
to
install
and
operate
emissions
controls
and
achieve
reductions
sooner
than
they
otherwise
would.
The
commenter
suggested
that
if
EPA
has
concerns
that
too
many
early
reduction
credits
would
be
banked,
it
can
create
a
"
Compliance
Supplement
Pool"
similar
to
the
program
used
in
the
NO
x
SIP
Call,
thus
limiting
the
number
of
allowances
that
could
be
earned
through
early
reductions.

Response:

EPA
is
not
finalizing
an
early
reduction
program.
The
first
phase
Hg
cap
is
set
at
a
level
that
requires
no
additional
installation
of
controls
relative
to
CAIR,
because
it
is
set
at
a
level
that
represents
projected
cobenefit
mercury
reductions
that
will
occur
as
a
result
of
NO
x
and
SO
2
control
technologies
installed
under
CAIR.
Acid
Rain
Program
units
and
SIP
call
units
can
bank
excess
NO
x
and
SO
2
reductions
achieved
prior
to
2010
for
use
under
CAIR,
and
sources
will
be
allowed
to
bank
starting
at
beginning
of
the
first
phase
of
the
Hg
cap­
and­
trade
program.

Comment:

Several
other
commenters
(
OAR­
2002­
0056­
1608,
­
2850,
­
3521)
also
stated
that
EPA
should
provide
early
reduction
credits
for
mercury­
specific
add­
on
controls.
Several
of
these
commenters
(
OAR­
2002­
0056­
2907,
­
3521)
stated
early
reduction
credits
should
be
awarded
units
that
implement
mercury­
specific
controls
prior
to
2015.
Several
of
these
commenters
(
OAR­
2002­
0056­
2907,
­
2850)
also
supported
early
reduction
credits
for
coal
plant
closures.
Similarly,
one
commenter
(
OAR­
2002­
0056­
4132)
stated
that
EPA
must
provide
early
reduction
credits
for
plants
shutting
down.
The
commenter
noted
that
the
economic
burden
of
this
mercury
initiative
may
force
the
shutdown
of
some
of
the
oldest
EGUS.
If
these
units
shutdown,
yielding
early
reductions
in
mercury
emissions,
it
is
important
that
early
reduction
credits
be
provided.
The
commenter
emphasized
that
the
final
regulations
should
expressly
and
properly
acknowledge
this
approach
to
early
reductions.

Response:

EPA
is
not
finalizing
an
early
reduction
program.
EPA
believes
that
the
cap­
and­
trade
program,
by
relying
on
market
forces,
will
provide
incentives
for
the
development
of
mercury
control
technologies.
Additionally,
the
ability
of
sources
to
bank
allowances
starting
at
the
beginning
of
the
Hg
cap­
and­
trade
program,
will
provide
flexibility
to
sources,
encourage
earlier
or
greater
reductions
than
required,
stimulate
the
market,
and
encourage
efficiency.
Further,
EPA
is
not
projecting
that
any
additional
coal­
fired
capacity
will
be
uneconomic
to
maintain
relative
to
CAIR
under
the
combination
of
CAIR
and
CAMR.

Comment:
5­
175
One
commenter
(
OAR­
2002­
0056­
1673)
stated
that
the
IAQR
and
mercury
rules
should
provide
utilities
with
the
incentive
to
undertake
early
reduction
measures,
such
as
year
round
operation
of
SCRs
currently
operated
during
the
ozone
season.
This
would
provide
immediate
NO
x
and
mercury
reduction
benefits.
Another
commenter
(
OAR­
2002­
0056­
1814)
submitted
that
early
reduction
credits
would
provide
an
incentive
for
companies
to
install
and
operate
emissions
controls
and
achieve
these
co­
benefits
earlier.
The
commenter
believes
these
credits
are
also
important
in
aiding
companies
in
meeting
very
aggressive
schedules
for
installation
of
equipment.
A
third
commenter
(
OAR­
2002­
0056­
2845)
stated
that
credits
for
early
reductions
could
be
coupled
with
additional
early
SO
2
reductions
in
the
CAIR
proposal.
The
commenter
believed
the
proposed
rule
should
provide
credit
for
reductions
achieved
from
the
installation
and/
or
modification
of
emission
or
combustion
control
technologies
like
early
installation
and
operation
of
scrubbers,
SCR,
and
ACI.
The
commenter
stated
that
credit
should
not
be
available
for
reductions
required
under
federal
regulations.

Response:

EPA
is
not
finalizing
an
early
reduction
program.
The
first
phase
Hg
cap
is
set
at
a
level
that
requires
no
additional
installation
of
controls
relative
to
CAIR,
because
it
is
set
at
a
level
that
represents
projected
cobenefit
mercury
reductions
that
will
occur
as
a
result
of
NO
x
and
SO
2
control
technologies
installed
under
CAIR.
Acid
Rain
Program
units
and
SIP
call
units
can
bank
excess
NO
x
and
SO
2
reductions
achieved
prior
to
2010
for
use
under
CAIR,
and
sources
will
be
allowed
to
bank
starting
at
beginning
of
the
first
phase
of
the
Hg
cap­
and­
trade
program.
See
the
CAIR
preamble
for
discussion
of
early
reduction
credits
under
that
rule.

Comment:

Several
commenters
(
OAR­
2002­
0056­
2224,
­
2835)
noted
that
an
early
reduction
credit
system
is
consistent
with
the
concept
of
"
banking"
surplus
reductions
under
a
market­
based,
cap­
and­
trade
regulatory
approach.
Commenter
OAR­
2002­
0056­
2224
noted
that
in
order
to
facilitate
this
action,
details
pertaining
to
the
baseline,
measurement,
deadline
and
time
line
mechanisms
would
need
to
be
sorted
out
in
the
final
rule.
Commenter
OAR­
2002­
0056­
2835
believed
that
an
early
reduction
credit
would
not
compromise
the
environmental
integrity
of
the
trading
program
because
only
a
small
number
of
sources
would
be
able
to
take
advantage
of
this
feature.
According
to
the
commenters,
from
a
policy
perspective,
early
mercury
reductions
should
be
encouraged
because
they
deliver
an
important
environment
benefit
in
advance
of
the
regulatory
control
program.
The
commenters
further
added
that
credit
should
only
be
granted
where
a
facility
can
demonstrate
that
the
reductions
are
real
and
quantifiable.
The
commenter
also
added
that
any
early
reduction
credit
scheme
should
not
penalize
a
facility
for
such
reductions
by
reducing
the
allocations
the
facility
would
receive
under
the
trading
program.

Response:

EPA
is
not
finalizing
an
early
reduction
program.
The
first
phase
Hg
cap
is
set
at
a
level
that
requires
no
additional
installation
of
controls
relative
to
CAIR,
because
it
is
set
at
a
level
5­
176
that
represents
projected
cobenefit
mercury
reductions
that
will
occur
as
a
result
of
NO
x
and
SO
2
control
technologies
installed
under
CAIR.

Comment:

One
commenter
(
OAR­
2002­
0056­
2163)
noted
that
cost­
effective
implementation
of
any
new
technology
requires
experience
with
full­
scale
installations
over
extended
periods
of
operation.
The
commenter
stated
there
are
always
forward­
thinking
utilities
who
are
interested
in
early
adoption
of
new
pollution
control
strategies.
The
commenter
believed
these
utilities
should
be
offered
incentives
to
promote
this
early
adoption
strategy
and
to
encourage
the
refinement
and
deployment
of
control
technology
options.
Such
incentives
could
include
bankable
and/
or
salable
emissions
credits.
The
commenter
strongly
encouraged
EPA
to
work
with
these
early
adopters
to
creatively
develop
a
strategy
that
offers
broad
incentives
for
early
implementation.

Response:

EPA
believes
that
the
market
forces
at
work
under
the
Hg
cap­
and­
trade
program
will
provide
incentives
for
the
development
of
Hg
control
technology.
This
incentive
will
be
further
strengthened
by
the
ability
of
sources
to
bank
allowances
from
excess
mercury
reductions
starting
at
the
beginning
of
the
Hg
cap­
and­
trade
program.

Several
commenters
(
OAR­
2002­
0056­
2375,
­
2718)
proposed
that
sources
be
able
to
earn
ERCs
before
the
Phase
I
deadline
in
2010.
To
address
concerns
that
such
a
provision
may
jeopardize
the
integrity
of
the
Phase
I
and
Phase
II
caps,
commenter
OAR­
2002­
0056­
2375
submitted
that
ERCs
should
be
discounted
at
a
2­
to­
1
ratio
upon
registration
into
the
mercury
bank.
Sources
would
be
permitted
to
use
ERCs
without
discount
during
Phase
I
and
Phase
II.
The
commenter
(
OAR­
2002­
0056­
2375)
asserted
that
an
ERC
program
is
supportable
on
public
policy
grounds.
The
commenter
believed
an
ERC
provision
in
the
final
rule
would
encourage
sources
not
yet
equipped
with
mercury
controls
to
install
and
operate
them
before
the
January
2010
deadline,
where
feasible,
so
that
greater
reductions
would
be
achieved
earlier.
The
commenter's
proposal
that
ERCs
be
discounted
at
a
2­
to­
1
rate
upon
registration
in
the
mercury
bank
would
achieve
added
benefits
by
ensuring
that
sources
would
be
permitted
to
emit
only
one
ounce
of
mercury
after
Phase
I
takes
effect
for
every
two
ounces
of
mercury
reduced
prior
to
January
2010.
The
commenter
believed
in
addition,
an
ERC
provision
would
provide
sources
with
much­
needed
compliance
flexibility
for
meeting
the
Phase
I
deadline.
Similarly,
commenter
2718
proposed
that
affected
sources
that
implement
mercury
CEMs
monitoring
be
permitted
to
earn
ERCs
at
a
2­
to­
1
ratio
such
that
one
credit
would
issue
for
every
two
ounces
of
mercury
emissions
reduced
from
the
source's
baseline.
Sources
using
other
methods,
such
as
stack
testing
or
look­
up
tables,
would
be
subject
to
a
3­
to­
1
issuance
ratio.

Response:

EPA
is
not
finalizing
an
early
reduction
program.
EPA
believes
that
the
cap­
and­
trade
program,
by
relying
on
market
forces,
will
provide
incentives
for
the
development
of
mercury
control
technologies.
Additionally,
the
ability
of
sources
to
bank
allowances
starting
at
the
5­
177
beginning
of
the
Hg
cap­
and­
trade
program,
will
provide
flexibility
to
sources,
encourage
earlier
or
greater
reductions
than
required,
stimulate
the
market,
and
encourage
efficiency.

One
commenter
(
OAR­
2002­
0056­
2907)
participated
in
programs
to
voluntarily
reduce
emissions
from
its
facilities
prior
to
adoption
of
mandatory
programs.
The
commenter
believed
EPA
should
not
penalize
the
commenter's
efforts
and
the
efforts
of
similar
proactive
companies
by
reducing
mercury
allowance
allocations
to
companies
that
make
emission
reductions
prior
to
the
compliance
dates
required
by
this
rule.
Instead,
EPA
should
encourage
and
support
early
reductions
by
not
restricting
the
banking
of
allowances
created
by
early
reduction
programs.
The
commenter
believed
all
reductions
completed
prior
to
the
compliance
date
should
be
credited
toward
meeting
the
proposed
cap.

Response:

EPA
is
not
finalizing
an
early
reduction
program.
The
first
phase
Hg
cap
is
set
at
a
level
that
requires
no
additional
installation
of
controls
relative
to
CAIR,
because
it
is
set
at
a
level
that
represents
projected
cobenefit
mercury
reductions
that
will
occur
as
a
result
of
NO
x
and
SO
2
control
technologies
installed
under
CAIR.
Acid
Rain
Program
units
and
SIP
call
units
can
bank
excess
NO
x
and
SO
2
reductions
achieved
prior
to
2010
for
use
under
CAIR,
and
sources
will
be
allowed
to
bank
starting
at
beginning
of
the
first
phase
of
the
Hg
cap­
and­
trade
program.
See
the
CAIR
preamble
for
discussion
of
early
reduction
credits
under
that
rule.

Comment:

One
commenter
(
OAR­
2002­
0056­
2900)
noted
that
Phase
I
of
the
Program
is
scheduled
to
begin
in
2010,
to
coincide
with
the
first
phase
of
the
CAIR.
In
addition,
EPA
proposes
to
set
the
Phase
I
mercury
cap
according
to
the
co­
benefits
achieved
from
the
SO
2
and
NO
x
reductions
mandated
by
the
CAIR.
However,
it
is
not
clear
to
the
commenter
what
that
level
should
be
and,
if
EPA
is
mistaken
in
the
level
of
the
Phase
I
mercury
cap,
it
is
possible
that
coal­
fired
EGUs
will
not
meet
the
cap
even
with
the
installation
of
stringent
SO
2
and
NO
x
controls
on
each
affected
unit.
To
alleviate
this
potential
problem,
the
commenter
recommended
that
EPA
allow
coal­
fired
EGUs
to
generate
early
reduction
credits
that
could
be
used
during
Phase
1.
Specifically,
the
commenter
recommended
that
EPA
grant
mercury
early
reduction
credits
to
sources
that
demonstrate
that
their
mercury
emissions
are
below
the
amount
they
are
allocated
under
Phase
1.
The
commenter
also
recommended
sources
should
be
allowed
to
generate
early
reduction
credits
beginning
with
adoption
of
the
Program
until
the
start
of
Phase
I,
unless
the
units
are
retired
or
repowered.
They
would
not
be
eligible
for
early
reduction
credits
until
they
have
met
the
Program's
initial
certification
procedures
for
mercury
monitoring.

Response:

EPA
is
not
finalizing
an
early
reduction
program.
The
first
phase
Hg
cap
is
set
at
a
level
that
requires
no
additional
installation
of
controls
relative
to
CAIR,
because
it
is
set
at
a
level
that
represents
projected
cobenefit
mercury
reductions
that
will
occur
as
a
result
of
NO
x
and
SO
2
control
technologies
installed
under
CAIR.
Acid
Rain
Program
units
and
SIP
call
units
can
5­
178
bank
excess
NO
x
and
SO
2
reductions
achieved
prior
to
2010
for
use
under
CAIR,
and
sources
will
be
allowed
to
bank
starting
at
beginning
of
the
first
phase
of
the
Hg
cap­
and­
trade
program.
See
the
CAIR
preamble
for
discussion
of
early
reduction
credits
under
that
rule.

Comment:

To
ensure
that
such
early
reduction
credits
would
not
simply
expand
the
Phase
I
cap
and
indefinitely
put
off
achievement
of
the
Phase
II
cap,
the
commenter
(
OAR­
2002­
0056­
2900)
suggested
that
such
early
reduction
credits
expire
in
2014,
although
the
commenter
advocated
unlimited
banking
for
mercury
allowances
that
are
allocated
to
affected
sources
under
each
phase
of
the
program.
The
commenter
believed
that
early
reduction
credits
would
help
sources
make
the
transition
to
the
Program.
They
also
would
improve
the
robustness
of
the
market
and
would
offer
EUSGUs
an
incentive
to
achieve
reductions
earlier
than
otherwise
required.
Finally,
the
commenter
believed
early
reduction
credits
will
help
avoid
the
need
for
sources
to
use
the
safety
valve
that
the
Agency
is
proposing.

Response:

EPA
is
not
finalizing
an
early
reduction
program.
The
first
phase
Hg
cap
is
set
at
a
level
that
requires
no
additional
installation
of
controls
relative
to
CAIR,
because
it
is
set
at
a
level
that
represents
projected
cobenefit
mercury
reductions
that
will
occur
as
a
result
of
NO
x
and
SO
2
control
technologies
installed
under
CAIR.
Additionally,
the
ability
of
sources
to
bank
allowances
starting
at
the
beginning
of
the
Hg
cap­
and­
trade
program,
will
provide
flexibility
to
sources,
encourage
earlier
or
greater
reductions
than
required,
stimulate
the
market,
and
encourage
efficiency.

Comment:

One
commenter
(
OAR­
2002­
0056­
2951)
stated
that
to
maximize
the
social
benefits
from
utility
mercury
emission
limitations,
the
regulatory
scheme
needs
the
earliest
possible
compliance
date.
The
commenter
called
this
the
"
Average
Control
Date."
The
commenter
added
that
just
as
important,
to
minimize
social
costs
we
need
the
earliest
possible
date
that
utilities
can
get
credit
for
making
technology­
based
mercury
reductions.
The
commenter
called
this
the
"
Mercury
Credit
Date."

The
commenter
stated
that
on
their
own,
utilities
have
no
incentives
to
reduce
any
mercury
emissions
one
minute
before
they
have
to.
The
commenter
added
that
indeed,
top
utility
executives
could
be
sued
by
their
shareholders
if
they
spent
any
money
on
mercury
reductions
any
earlier
than
required;
that
money
should
theoretically
go
to
the
shareholders.

The
commenter
stated
that
nationally,
it
is
obviously
advantageous
to
have
orderly
mercury
technology
implementation,
rather
than
the
inefficiencies
resulting
from
all
of
the
utilities
and
their
subcontractors
competing
to
have
controls
in
place
on
all
1,100
boilers
at
the
same
date.
The
commenter
believed,
however,
that
social
benefits
are
lost
with
any
delay.
The
commenter
stated
that,
consequently,
utilities
should
be
able
to
make
mercury
reductions
at
some
of
their
5­
179
units
early,
ahead
of
the
Average
Control
Date,
and
get
credit
that
they
can
trade
off
by
beginning
reductions
at
an
equivalent
amount
of
their
units
late.
According
to
the
commenter,
as
net
mercury
emissions
would
be
the
same,
society
should
be
largely
indifferent
to
such
"
banking."
The
commenter
believed
if
the
tougher,
more­
costly
sites
come
last,
society
even
gains
a
bit.

The
commenter
suggested
that
to
maximize
the
benefits
of
such
flexibility,
the
temporal
trade­
off
period
should
be
designed
to
be
as
wide
as
possible
(
and
it
need
not
necessarily
be
symmetrical).
The
commenter
stated
that
in
particular,
it
should
begin
at
the
earliest
conceivable
"
Mercury
Credit
Date"
because
any
early
technology­
adopters
benefit
everyone
else
by
leading
the
industry
down
the
learning
curve,
resulting
in
lower
total
costs
for
everyone.
The
commenter
added
that
unfortunately,
however,
any
early
adopters
would
inevitably
see
higher
costs
and
greater
risks
than
those
who
wait
until
the
last
minute,
and
they
would
be
unable
to
capture
the
social
benefits
of
their
pioneering,
thus
creating
a
classical
market
failure.

The
commenter
stated
that
consequently,
there
should
be
special
incentives
for
early
technology­
based
mercury­
reductions.
The
commenter
added
that
for
example,
early
technology­
driven
mercury
reductions
could
receive
extra
credit,
perhaps
at
2X,
for
banking
purposes.
The
commenter
stressed
that
the
positive
social
externalities
of
early
technology
adopters
are
very
real
and
very
significant
and
efforts
should
be
made
to
encourage
them
in
constructing
any
utility
mercury
regulatory
framework.

The
commenter
further
stated
that
there
are
no
positive
externalities
with
early
switches
to
lower­
Hg­
coal
or
for
scrubbing
co­
benefit­
based­
reductions
or
other
non­
innovative­
technology­
based
Hg
reductions.
According
to
the
commenter,
while
these
types
of
reductions
could
conceivably
be
banked,
they
might
be
difficult
to
substantiate
or
result
in
zero­
sum
losses
in
unobserved
parts
of
the
system.
The
commenter
believed
they
should
not
be
advantaged.

Response:

EPA
believes
that
the
cap­
and­
trade
program,
by
relying
on
market
forces,
will
provide
incentives
for
the
development
of
mercury
control
technologies.
Additionally,
the
ability
of
sources
to
bank
allowances
starting
at
the
beginning
of
the
Hg
cap­
and­
trade
program,
will
provide
flexibility
to
sources,
encourage
earlier
or
greater
reductions
than
required,
stimulate
the
market,
and
encourage
efficiency.
Therefore,
EPA
does
not
believe
it
is
necessary
to
add
any
additional
provisions
to
the
rule
to
promote
technology
adoption.

One
commenter
(
OAR­
2002­
0056­
2843)
stated
that
if
a
cap­
and­
trade
program
is
promulgated,
two
essential
elements
must
be
preserved
if
new
coal­
fired
units
are
to
remain
viable
resources
for
the
future.
First,
because
compliance
with
either
emission
rates
or
reductions
necessary
under
a
"
cap­
and­
trade"
environment
are
uncertain
at
best,
there
must
be
a
reliable
and
readily
available
source
of
allowances
available
for
purchase
at
a
pre­
determined
price.
The
commenter
suggested
that
early
reduction
credits
might
be
an
available
resource
for
these
allowances.
Second,
the
commenter
believed
there
should
be
a
reservation
of
allowances
for
5­
180
allocation
to
new
units.
These
should
be
available
on
a
first­
come,
first­
served
basis
until
exhausted.

Response:

EPA
is
not
finalizing
an
early
reduction
program.
The
first
phase
Hg
cap
is
set
at
a
level
that
requires
no
additional
installation
of
controls
relative
to
CAIR,
because
it
is
set
at
a
level
that
represents
projected
cobenefit
mercury
reductions
that
will
occur
as
a
result
of
NO
x
and
SO
2
control
technologies
installed
under
CAIR.
Additionally,
the
ability
of
sources
to
bank
allowances
starting
at
the
beginning
of
the
Hg
cap­
and­
trade
program,
will
provide
flexibility
to
sources,
encourage
earlier
or
greater
reductions
than
required,
stimulate
the
market,
and
encourage
efficiency.

Under
the
Hg
cap­
and­
trade
program,
States
determine
how
to
allocate
allowances
to
sources.
EPA
provides
an
example
allocation
methodology
in
the
model
rule,
which
provides
for
a
new
source
set­
aside.

Comment:

One
commenter
(
OAR­
2002­
0056­
2850)
achieved
about
17
percent
reduction
in
mercury
stack
emissions
in
2000
compared
to
1990
levels
through
optimizing
fuel
sourcing
and
plant
operation.
The
commenter's
coal
units
are
also
over
70
percent
wet
scrubbed
for
particulate
and
sulfur
dioxide
removal,
which
combined
with
other
voluntary
mercury
reduction
activities
has
reduced
base
line
emissions
relative
to
1990
and
compared
to
other
utility
units.
Consequently,
the
commenter
stated
that
an
equitable
allocation
of
mercury
reduction
requirement
stringency,
either
through
unit
specific
requirements
or
cap
and
trade
program
allowance
allocation
methodology
would
be
important
for
assuring
reasonable
credit
for
early
action.
The
commenter
supported
an
equitable
cap­
and­
trade
approach
as
the
preferred
option
for
regulating
electric
power
sector
mercury
emissions,
as
that
provides
the
most
flexibility
for
achieving
compliance
using
new
and
often
unproven
technology.

Response:

EPA
agrees
with
the
commenter
about
the
advantages
of
using
cap­
and­
trade
for
achieving
mercury
emissions
reductions
from
the
power
sector.
Under
the
Hg
cap­
and­
trade
program,
States
have
the
authority
to
allocate
allowances
to
sources.
EPA's
example
allocation
methodology
is
outlined
in
the
preamble.
EPA
is
not
finalizing
an
early
reduction
credit
provisions.
See
the
comments
above
regarding
this
issue.

Comment:

One
commenter
(
OAR­
2002­
0056­
3431)
believed
the
market
will
send
the
proper
signals
to
influence
early
reductions
that
will
drop
mercury
emissions
at
a
sharp
and
steady
rate
as
the
first
phase
compliance
deadline
approaches.
The
commenter
stated
that
credit
for
such
early
reductions
can
be
patterned
after
the
provisions
of
the
NO
x
SIP
Call
and
NO
x
budget
rules
and
5­
181
could
be
granted
for
reductions
in
total
mercury
in
coal
from
as­
fired
analyses
and
consumption
information.
The
commenter
added
that
such
information
could
be
verified
with
annual
stack
testing
prior
to
installation
of
Hg
Continuous
Emission
Monitoring
Systems
(
CEMS).
According
to
the
commenter
ERCs
are
a
"
win­
win"
for
EPA,
industry,
and
the
environment;
the
opportunity
to
receive
ERCs
improves
environmental
performance,
reduces
cumulative
compliance
costs
and
provides
flexibility
to
deal
with
uncertainty
in
the
trading
market.

Response:

EPA
is
not
finalizing
an
early
reduction
program.
The
first
phase
Hg
cap
is
set
at
a
level
that
requires
no
additional
installation
of
controls
relative
to
CAIR,
because
it
is
set
at
a
level
that
represents
projected
cobenefit
mercury
reductions
that
will
occur
as
a
result
of
NO
x
and
SO
2
control
technologies
installed
under
CAIR.
Additionally,
the
ability
of
sources
to
bank
allowances
starting
at
the
beginning
of
the
Hg
cap­
and­
trade
program,
will
provide
flexibility
to
sources,
encourage
earlier
or
greater
reductions
than
required,
stimulate
the
market,
and
encourage
efficiency.

Comment:

One
commenter
(
OAR­
2002­
0056­
2067)
stated
that
the
proposed
alternative
Cap­
and­
Trade
approach
would
rely
heavily
on
achieving
mercury
reductions
through
the
co­
benefits
of
future
installation
of
scrubbers
to
meet
SO
2
and
NO
x.
The
commenter
added
that
however,
the
Cap­
and­
Trade
proposal
failed
to
take
into
account
that
there
are
existing
Utility
Units
that
have
already
achieved
this
Phase
I
reduction,
and
are
currently
operating
with
significantly
lower
mercury
emissions
than
the
industry
as
a
whole.
The
commenter
asserted
that
instead,
Cap
and
Trade
would
subject
these
plants,
such
as
the
commenter's
primary
generating
resource
(
which
has
been
controlling
mercury
emissions
for
nearly
25
years),
to
the
same
cap
as
the
majority
of
Utility
Units
and
provide
allocations
based
on
the
assumption
that
existing
scrubbers
do
not
exist,
creating
an
unrealistically
low
emissions
level.
The
commenter
stated
that
Cap
and
Trade
would
fail
to
give
appropriate
credit
to
power
plants
that
already
are
reducing
mercury
emissions,
and
that
indeed,
it
would
create
a
greater
burden
on
scrubbed
plants
because
it
would
effectively
require
scrubbed
plants
to
achieve
the
same
level
of
reductions
as
unscrubbed
plants.
The
commenter
stated
that
this
is
a
significant
issue
in
the
western
United
States
where
it
has
been
estimated
that
up
to
two­
thirds
of
Utility
Units
are
presently
scrubbed.
According
to
the
commenter,
this
approach
imposes
a
disproportionately
high
burden
on
power
plants
that
are
already
scrubbed,
such
as
the
commenter's
primary
generating
resource,
and
is
a
fundamental
flaw
of
Cap
and
Trade
that
is
avoided
under
MACT.

The
commenter
stated
that,
in
the
event
EPA
selects
the
Cap­
and­
Trade
approach
to
regulating
mercury,
key
modifications
would
be
necessary
to
make
Cap
and
Trade
workable.
According
to
the
commenter,
the
net
effect
is
that
while
Cap
and
Trade
is
designed
to
achieve
a
total
reduction
of
70
percent
from
current
levels,
units
that
have
existing
scrubbers
will
be
required
to
achieve
this
70
percent
reduction
on
top
of
existing
reductions
of
nearly
70
percent.
The
commenter
stated
that
it
is
fundamentally
unfair
for
the
EPA
to
give
credit
for
mercury
reductions
to
utilities
that
install
scrubbers
for
SO
2
and
NO
x
in
the
future,
while
not
providing
the
5­
182
same
credit
to
those
who
installed
the
technology
and
have
been
reducing
emissions
for
25
years.
The
commenter
asserted
that
in
the
event
EPA
adopts
a
Cap
and
Trade
approach,
EPA
should
address
this
fundamental
unfairness
that
would
penalize
utilities
that
have
taken
early
steps
to
reduce
emissions.
The
commenter
recommended
that,
at
a
minimum,
Utility
Units
that
have
existing
scrubbers
should
be
exempt
from
mercury
reduction
requirements
through
Phase
I,
and
should
only
be
subjected
to
additional
requirements
in
Phase
II
when
the
future
co­
benefits
have
been
recognized,
and
the
next
level
of
control
is
required.

Response:

EPA
is
not
finalizing
an
early
reduction
program.
The
first
phase
Hg
cap
is
set
at
a
level
that
requires
no
additional
installation
of
controls
relative
to
CAIR,
because
it
is
set
at
a
level
that
represents
projected
cobenefit
mercury
reductions
that
will
occur
as
a
result
of
NO
x
and
SO
2
control
technologies
installed
under
CAIR.
Acid
Rain
Program
units
can
bank
excess
SO
2
reductions
achieved
prior
to
2010
for
use
under
CAIR,
and
sources
will
be
allowed
to
bank
starting
at
beginning
of
the
first
phase
of
the
Hg
cap­
and­
trade
program.
See
the
CAIR
preamble
for
discussion
of
early
reduction
credits
under
that
rule.

Comment:

One
commenter
(
OAR­
2002­
0056­
3469)
recommended
that
EPA
should
implement
a
vigorous
research
and
development
program
to
develop
economically
viable
technology
solutions
 
and
allow
work
on
existing
programs
to
be
concluded
 
for
all
fuel
sub­
categories.

Response:

EPA's
Office
of
Research
and
Development
currently
participates
in
a
program
with
Department
of
Energy
and
industry
representatives
to
assess
mercury
control
technology
options.
See
the
revised
ORD
White
Paper
on
Hg
control
technology,
available
in
the
docket.

Comment:

One
commenter
(
OAR­
2002­
0056­
4891)
recommended
that
EPA
provide
an
option
that
allows
entities
subject
to
the
cap­
and­
trade
program
to
"
earn"
emissions
reduction
credits
for
commissioning
or
funding
projects
that
result
in
the
reduction
of
mercury
emissions
from
other
mercury
emissions
point
sources
(
e.
g.,
fuel
combustion;
waste
incineration;
industrial
processes;
and
metal
ore
roasting,
refining,
and
processing).

Response:

The
ability
to
accurately
measure
emissions
reductions,
and
thus
guarantee
the
value
of
an
allowance,
is
essential
to
a
successful
cap­
and­
trade
program.
Allowing
credit
to
be
used
in
the
Hg
cap­
and­
trade
program
for
utilities
from
off­
sector
reductions
that
may
not
have
adequate
Hg
emissions
monitoring,
would
jeopardize
the
certainty
behind
the
value
of
an
allowance,
and
thus
the
functioning
of
the
trading
program.
5­
183
5.8.4
Other
Model
Trading
Rule
Requirements
Comment:

One
commenter
(
OAR­
2002­
0056­
4139)
supported
the
need
for
two
primary
types
of
accounts­
compliance
accounts
and
general
accounts.
Compliance
accounts
would
be
created
for
each
Mercury
Budget
source
with
one
or
more
Mercury
Budget
units
upon
receipt
of
the
account
certificate
of
representation
form.
General
accounts
would
be
created
for
any
organization
or
individual
upon
receipt
of
a
general
account
information
form.

Response:

Today's
final
rule
contains
provisions
for
the
establishment
of
compliance
accounts
and
general
accounts.

Comment:

One
commenter
(
OAR­
2002­
0056­
2287)
suggested
that
the
cap
and
trade
system
be
open
to
all
interested
parties,
including
communities
and
environmental
groups
so
that
they
could
also
bid
for
credits
to
use
as
they
please.

Response:

Under
the
final
rule,
States
are
given
the
authority
to
allocate
Hg
allowances
as
they
see
fit.
However,
individuals
and
groups
that
are
not
affected
sources
are
allowed
to
hold
Hg
allowances
by
establishing
a
general
account.

Comment:

One
commenter
(
OAR­
2002­
0056­
3509)
stated
that
to
the
extent
that
the
final
Utility
Mercury
Rule
does
require
controls
of
small
municipal
generators
via
allowance
trading
or
other
requirements,
EPA
should
provide
these
units
with
other
compliance
flexibility
options
to
reduce
the
cost
of
such
compliance.
Specifically,
the
commenter
supported
several
of
the
proposals
made
by
EPA,
including
for
facility­
wide
emissions
averaging,
measurement
of
emissions
using
12­
month
rolling
averages,
the
ability
to
bank
mercury
allowances
without
restriction,
and
the
ability
to
use
"
safety
valve"
allowances
when
the
price
of
allowances
exceed
a
reasonable
cost
threshold.

Response:

EPA
is
finalizing
a
number
of
provisions
as
part
of
the
cap­
and­
trade
program
in
order
to
provide
flexibility
to
sources.
Under
the
final
rule,
compliance
will
be
assessed
at
the
facility
level,
and
on
a
12­
month
rolling
average
basis.
Additionally,
EPA
is
finalizing
that
banking
be
allowed
without
restriction,
beginning
at
the
start
of
the
first
phase
of
the
program.
EPA
is
not
5­
184
finalizing
a
safety
valve
provision,
for
reasons
discussed
in
the
preamble,
and
section
5.8.2
of
this
document.

Comment:

One
commenter
(
OAR­
2002­
0056­
2181)
believed
there
were
several
key
components
of
the
proposed
rules
that
could
set
broad
precedents
within
the
electric
power
sector
beyond
just
the
control
of
mercury,
specifically
in
regard
to
the
design
of
trading
programs
and
allowance
allocation
systems.

Response:

EPA
believes
that
the
final
design
of
the
Hg
Budget
Trading
Program
will
result
in
an
efficient
and
effective
program.

Comment:

One
commenter
(
OAR­
2002­
0056­
2067)
expressed
significant
concern
regarding
what
entity
actually
receives
the
allocations
in
the
Cap
and
Trade
approach.
The
commenter
stated
that
if
a
Cap
and
Trade
alternative
is
selected,
it
is
important
that
emission
allowances
be
awarded
to
the
owners
of
Utility
Units,
not
the
operators
of
such
units.
As
a
relatively
small
wholesale
power
producer,
the
commenter
is
not
able
to
economically
construct,
own
and
operate
its
own
baseload
facilities.
Rather,
the
commenter
is
a
joint
owner
with
other
utilities
in
its
primary
generating
resource
and
would
expect
to
utilize
the
same
type
of
arrangement
for
any
future
baseload
coal
additions
to
its
resource
portfolio.
The
commenter
asserted
that
allowances
should
be
allotted
to
the
unit
owners
on
the
basis
of
their
ownership
interest
and
should
not
be
awarded
to
the
operators
of
the
unit(
s).

Response:

Hg
allowances
will
be
allocated
by
States
to
Hg
Budget
sources.
Each
Hg
Budget
source
affected
under
the
Hg
cap­
and­
trade
program
is
required
to
have
1
Hg
designated
representative,
with
regard
to
all
matters
under
the
trading
program
concerning
the
source
or
any
Hg
Budget
unit
at
the
source.
This
representative
shall
be
selected
by
an
agreement
binding
on
the
owners
and
operators
of
the
source
and
all
Hg
Budget
units
at
the
source.

Comment:

One
commenter
(
OAR­
2002­
0056­
3537)
stated
that
CAA
§
408(
i)
sets
out
an
approach
regarding
the
holding
and
distribution
of
Title
IV
SO
2
allowances
and
the
proceeds
of
transactions
involving
allowances,
where
there
are
multiple
holders
of
a
legal
or
equitable
title
to
or
a
leasehold
interest
in
an
affected
unit.
That
provision
in
pertinent
part
provides
that:
"
No
permit
shall
be
issued
under
this
section
to
an
affected
unit
until
the
designated
representative
of
the
owners
or
operators
has
filed
a
Certificate
of
Representation
with
regard
to
matters
under
this
subchapter,
including
the
holding
and
distribution
of
allowances
and
the
proceeds
of
transactions
5­
185
involving
allowances.
Where
there
are
multiple
holders
of
a
legal
or
equitable
title
to,
or
a
leasehold
interest
in
such
unit,
or
where
a
utility
or
industrial
customer
purchases
power
from
an
affected
unit
(
or
units)
under
life­
of­
the­
unit,
firm
power
contractual
arrangements,
the
certificate
shall
state
(
1)
that
allowances,
and
the
proceeds
of
transactions
involving
allowances
will
be
deemed
to
be
held
or
distributed
in
proportion
to
each
holder's
legal,
equitable,
leasehold
or
contractual
reservation
or
entitlement,
or
(
2)
if
such
multiple
holders
have
expressly
provided
for
a
different
distribution
of
allowances
by
contract,
that
allowances
and
the
proceeds
of
transactions
involving
allowances,
will
be
deemed
to
be
held
or
distributed
in
accordance
with
the
contract.
A
passive
lessor,
or
a
person
who
has
an
equitable
interest
through
such
lessor,
whose
rental
payments
are
not
based,
either
directly
or
indirectly,
upon
the
revenues
or
income
from
the
affected
unit
shall
not
be
deemed
to
be
a
holder
of
a
legal,
equitable,
leasehold,
or
contractual
interest
for
the
purpose
of
holding
or
distributing
allowances
as
provided
in
this
subsection,
during
either
the
term
of
such
leasehold
or
thereafter,
unless
expressly
provided
for
in
the
leasehold
agreement."
CAA
§
408(
I).

The
commenter
submitted
that
clearly,
when
enacting
Title
IV
of
the
CAAA,
Congress
considered
how
allowances
should
be
distributed
to
multiple
owners
of
an
affected
unit.
It
concluded
that
allowance
allocations
(
or
the
proceeds
from
auctions)
should
track
the
ownership
interest
in
affected
units,
absent
an
agreement
between
the
parties
to
the
contrary.
The
commenter
believed
there
is
nothing
in
the
proposed
mercury
rule
that
would
justify
following
a
different
approach
to
the
ultimate
distribution
of
mercury
allowances
under
EPA's
current
proposal.
The
commenter
suggested,
therefore,
when
proposing
and
promulgating
regulatory
language
to
implement
the
requirements
of
the
mercury
cap
and
trade
rule,
EPA
should
encourage
States
that
promulgate
cap
and
trade
rules
pursuant
to
CAA
section
111
to
use
the
approach
followed
in
CAA
§
408(
i)
as
the
method
for
allocating
allowances
among
multiple
owners
of
a
Utility
Unit.
The
commenter
also
suggested
that
should
EPA
promulgate
a
cap
and
trade
program
under
CAA
§
112,
then
EPA
should,
as
part
of
its
method
for
allocating
allowances,
follow
the
approach
set
forth
in
CAA
§
408(
I).

Response:

Regarding
the
commenter's
concerns
about
rules
and
guidance
on
allocations,
the
model
trading
rules
already
include
provisions
analogous
to
section
408(
i)
of
the
Clean
Air
Act.

Comment:

One
commenter
(
OAR­
2002­
0056­
2898)
opposed
EPA's
proposal
to
confiscate
future
year
allowances
in
the
event
a
source
does
not
have
enough
allowances
to
offset
emissions.
Rather,
the
commenter
proposed
that
a
fee
be
assessed
for
each
pound
of
mercury
that
a
source
exceeds
its
available
allowances.
The
commenter
suggested
this
source
of
revenue
would
fund
mercury
control
technology
research
and
demonstration
projects.
The
commenter
added
also,
these
monies
could
be
used
to
achieve
off­
utility
system
mercury
reductions.

Response:
5­
186
EPA
is
finalizing
that
three
Hg
allowances
for
each
ounce
of
emissions
would
be
deducted
from
a
source's
compliance
account
for
the
following
control
period,
in
the
event
that
an
affected
source
does
not
hold
sufficient
Hg
allowances
to
offset
emissions
for
the
season.
EPA
believes
that
it
is
important
to
set
up
this
automatic
offset
deduction
because
it
is
ensures
that
non­
compliance
with
the
Hg
emission
limitations
of
this
rule
is
a
more
expensive
option
than
controlling
emissions.
EPA
required
the
same
offset
deduction
of
three
to
one
in
the
NO
x
SIP
call.
The
automatic
offset
provisions
do
not
limit
the
ability
of
the
permitting
authority
or
EPA
to
take
enforcement
action
under
State
law
or
the
CAA.

Comment:

One
commenter
(
OAR­
2002­
0056­
3478)
did
not
see
the
benefit
to
having
a
3­
to­
l
offset
for
allowance
shortages.
The
commenter
believed
the
1­
to­
1
offset
penalty
and
deduction
from
the
next
year's
subaccount
in
Acid
Rain
provides
adequate
control
for
shortages.

Response:

EPA
is
finalizing
that
three
Hg
allowances
for
each
ounce
of
emissions
would
be
deducted
from
a
source's
compliance
account
for
the
following
control
period,
in
the
event
that
an
affected
source
does
not
hold
sufficient
Hg
allowances
to
offset
emissions
for
the
season.
EPA
believes
that
it
is
important
to
set
up
this
automatic
offset
deduction
because
it
is
ensures
that
non­
compliance
with
the
Hg
emission
limitations
of
this
rule
is
a
more
expensive
option
than
controlling
emissions.
EPA
required
the
same
offset
deduction
of
three
to
one
in
the
NO
x
SIP
call.
The
automatic
offset
provisions
do
not
limit
the
ability
of
the
permitting
authority
or
EPA
to
take
enforcement
action
under
State
law
or
the
CAA.

Comment:

One
commenter
(
OAR­
2002­
0056­
4132)
noted
that
EPA
has
proposed
that
the
Mercury
Budget
Trading
Program
utilize
source­
wide
compliance
rather
than
unit­
by­
unit
compliance.
The
commenter
noted
in
particular,
EPA
proposed
that
sources
would
be
allocated
allowances
rather
than
individual
units
and,
accordingly
compliance
would
be
source­
wide
rather
than
unit­
by­
unit.
The
commenter
strongly
supported
this
concept.
This
would
simplify
the
administrative
activities
associated
with
ensuring
that
each
unit
account
has
sufficient
allowances
by
the
end
of
the
allowance
transfer
deadline.

Response:

EPA
is
finalizing
that
compliance
with
CAMR
be
assessed
at
the
facility
level.

Comment:

One
commenter
noted
that
EPA
proposes
to
require
compliance
on
a
facility­
wide
basis
rather
than
on
a
unit­
by­
unit
basis.
Each
facility
would
have
a
"
compliance"
account,
which
would
need
to
hold
enough
allowances
to
cover
mercury
emissions
for
an
entire
facility.
The
commenter
5­
187
believed
this
makes
practical
sense
from
a
technology
perspective,
and
simplifies
program
accounting
requirements.

Response:

EPA
concurs,
and
is
finalizing
that
compliance
with
CAMR
be
assessed
at
the
facility
level.

Comment:

One
commenter
(
OAR­
2002­
0056­
4239)
recommended
using
serial
numbers
of
some
mechanism
for
tracking
and
reporting
mercury
emissions.
The
commenter
stated
the
program
must
be
transparent
to
all
entities.
The
commenter
believed
serial
numbers
encourage
transparency
and
benefits
derived
for
tax
and
accounting
purposes.

Response:

Under
CAMR,
each
Hg
allowance
will
be
assigned
a
serial
number
for
the
purpose
of
tracking
allowances.

Comment:
Several
commenters
(
OAR­
2002­
0056­
2634,
­
2830,
­
2835)
requested
that
the
EPA
include
facility­
wide
averaging
in
the
section
111
Emission
Guidelines
for
existing
sources
as
an
additional
compliance
alternative.
States
should
be
encouraged
to
allow
such
flexible
compliance
alternatives
if
states
decline
to
adopt
a
section
111
trading
program,
if
that
option
is
selected
by
the
EPA.
By
including
this
type
of
flexibility
mechanism,
the
EPA
will
ensure
that
those
facilities
located
in
States
opting
out
of
the
trading
program
will
retain
some
degree
of
flexibility
when
complying
with
the
requirements
of
the
Emission
Guidelines.
Similarly,
facility­
wide
emissions
averaging
provides
a
flexible
compliance
alternative
to
a
cap­
and­
trade
program
in
the
event
that
neither
cap­
and­
trade
option
can
be
authorized
under
the
statute.
Varying
operational
modes
or
combination
of
systems,
e.
g.,
wet/
dry
scrubber,
ESP
or
fabric
filter,
could
be
employed
to
provide
the
greatest
potential
to
economically
reduce
Hg
emissions
to
meet
compliance
requirements.

Response:

As
discussed
in
the
final
preamble,
States
must
submit
a
demonstration
that
it
will
meet
ist
assigned
emissions
budget
through
reductions
from
coal­
fired
power
plants.
There
are
no
restrictions
on
states
using
facility­
wide
averaging.

5.8.5
Title
V
Permits
Comment:

One
commenter
(
OAR­
2002­
0056­
4139)
stated
that
a
Title
V
permit
incorporates
applicable
requirements
that
are
created
under
other
authorities,
but
does
not
directly
establish
5­
188
specific
standards
unless
explicitly
provided
by
the
CAA
(
such
as
periodic
monitoring).
In
the
case
of
mercury
budget
program
requirements,
the
proposed
rule
appeared
to
require
permitting
authorities
to
directly
create
mercury
permit
requirements
in
Title
V
permits.
The
commenter
questioned
what
authority
under
the
CAA
allows
the
mercury
budget
rule
to
change
Title
V
program
requirements
and
allow
Title
V
to
directly
create
mercury
program
permitting
requirements?

One
commenter
(
OAR­
2002­
0056­
4139)
submitted
the
proposed
general
permit
requirement
in
40
CFR
60.4120
specified
that
the
Mercury
Budget
portion
of
the
Title
V
permit
is
to
be
administered
according
to
the
permit
authority's
Title
V
operating
permits
regulations.
However,
the
proposed
rule
did
not
comport
with
existing
permit
content
requirements
particularly
for
monitoring
requirements.
The
commenter
stated
that
the
Title
V
permit
must
directly
identify
the
applicable
limits
or
operational
restrictions
and
what
monitoring,
recordkeeping,
and
reporting
requirements
will
be
used
to
demonstrate
compliance.
The
commenter
pointed
out
the
proposed
Mercury
Budget
permit
portion
does
not
include
that
same
level
of
detail.

One
commenter
(
OAR­
2002­
0056­
4139)
noted
the
proposed
general
permit
requirement
in
40
CFR
60.4120
specifies
that
the
Mercury
Budget
portion
of
the
Title
V
permit
is
to
be
administered
according
to
the
permit
authority's
Title
V
operating
permits
regulations.
The
commenter
submitted,
however,
the
proposed
rule
did
not
comport
with
the
Title
V
schedule
requirements
for
revising
a
permit
to
include
new
requirements.
The
proposed
general
permit
requirement
in
40
CFR
60.4121
specified
that
the
Mercury
Budget
permit
application
must
be
submitted
18
months
before
January
1,
2010,
(
or
the
date
the
Mercury
Budget
unit
commences
operation
for
new
units).
The
commenter
stated,
however,
40
CFR
70.6(
f)
of
the
Title
V
operating
permits
rules
does
not
require
that
the
source
submit
an
application
to
revise
a
Title
V
permit
for
new
promulgated
requirements.
The
permitting
authority
must
reopen
the
permit
for
cause
if
there
are
3
or
more
years
remaining
before
the
current
Title
V
permit
expires.

One
commenter
(
OAR­
2002­
0056­
4139)
noted
the
proposed
rule
did
not
comport
with
the
Title
V
permit
renewal
schedule.
The
proposed
general
permit
requirement
in
40
CFR
60.4121
(
c)
specified
that
the
Mercury
Budget
authorized
account
representative
must
submit
a
complete
mercury
budget
permit
application
according
to
the
permitting
authority's
Title
V
operating
permit
regulations
for
permit
renew.
However,
most
of
the
commenter's
Title
V
permits
for
the
listed
Mercury
Budget
sources
will
not
be
due
for
renewal
during
the
specified
Mercury
Budget
time
frame.
The
commenter
asked
how
does
the
Mercury
Budget
permit
renewal
synchronize
with
the
Title
V
renewal
schedule?
The
commenter
found
the
proposed
wording
far
too
vague
to
adequately
address
the
nuances
of
the
renewal
process.

One
commenter
(
OAR­
2002­
0056­
4139)
stated
that
the
proposed
general
permit
requirement
in
40
CFR
60.4120
specified
that
the
Mercury
Budget
portion
of
the
Title
V
permit
is
to
be
administered
according
to
the
permit
authority's
Title
V
operating
permits
regulations.
All
submittals
pursuant
to
the
Title
V
permit
program
must
be
certified
by
a
responsible
official,
with
specific
compliance
certification
requirements
for
annual
and
semiannual
reports.
The
commenter
submitted,
however,
40
CFR
60.4130
of
the
proposed
rule
would
require
data
report
and
5­
189
compliance
certification
submittals
by
the
authorized
account
representative
for
different
information
and
based
on
schedules
that
do
not
mesh
with
the
Title
V
time
frame.

Response:

Under
the
Hg
Budget
model
trading
rule,
a
Hg
Budget
source
that
is
already
required
to
have
a
title
V
operating
permit
is
required
to
submit
an
application
to
the
permitting
authority
for
a
Hg
Budget
permit,
which
will
become
a
complete
and
separable
part
of
the
title
V
permit.
Sources
not
required
to
have
title
V
permits
do
not
have
to
apply
for
Hg
Budget
permits.
For
a
source
required
to
have
title
V
permit,
the
requirements
of
the
model
trading
rule
are
applicable
requirements
that,
under
title
V
,
must
be
incorporated
into
the
source's
title
V
permit
because
the
requirements
of
the
model
trading
rule
are
requirements
under
section
111
of
the
CAA.
See
40
C.
F.
R.
70.2
(
definition
of
"
applicable
requirement").
In
short,
contrary
to
the
commenter's
statements,
the
title
V
permit
is
incorporating
the
requirements
established
by
the
Hg
model
trading
rule,
which
incorporation
is
analogous
to
the
way
the
title
V
permit
incorporates
the
requirements
established
by
other
programs
(
e.
g.,
the
NOx
SIP
Call
model
trading
rule)
under
CAA.

Comment:

One
commenter
(
OAR­
2002­
0056­
2922)
suggested,
as
a
general
matter,
that
EPA
pattern
the
mercury
cap­
and­
trade
program
on
the
Title
IV
Acid
Rain
Program.
In
that
regard,
EPA,
as
it
does
in
the
Title
IV
program,
should
not
require
Title
V
operating
permits
to
be
reopened
or
revised
for
allocation,
transfer,
or
deduction
of
allowances.
The
commenter
recommended
in
addition,
EPA
should
assign
serial
numbers
to
mercury
allowances.
The
commenter
believed
that
although
tracking
and
reporting
serial
numbers
would
result
in
some
administrative
burden,
that
burden
would
be
significantly
outweighed
by
the
benefits
that
serial
numbers
would
provide
for
tax
and
accounting
purposes
for
regulated
companies
and
other
market
participants.

Response:

EPA
agrees
that
requiring
title
IV
operating
permits
to
be
reopened
or
revised
for
allocation,
transfer,
or
deduction
of
allowances
would
create
an
unnecessary
administrative
burden,
and
is
finalizing
that
these
be
automatically
incorporated
in
the
Hg
budget
permit.
Also,
EPA
is
assigning
serial
numbers
to
Hg
allowances
for
the
purpose
of
tracking.

5.9
IMPLEMENTATION
5.9.1
State
Plan
Requirements
Comment:

One
commenter
(
OAR­
2002­
0056­
2247)
noted
the
proposed
trading
program
would
require
a
state
to
submit
its
first
plan
by
2006
for
distributing
allocations
for
2010­
2014.
The
commenter's
state
cannot
meet
this
deadline.
The
commenter
stated
that
mercury
control
rules
5­
190
and
allowance
distribution
will
be
controversial;
implementation
will
require
having
the
legal
framework
in
place,
sufficient
administrative
resources,
and
time
for
input
from
the
industry
and
the
public.
The
commenter
believed
that
at
least
2
years
would
be
needed
after
emission
guideline
promulgation
to
complete
a
rule
with
more
time
needed
to
actually
distribute
allowances.
The
commenter
stated
submittal
of
plans
should
be
required
at
least
24
months
after
federal
rule
promulgation.

Response:

EPA
is
requiring
a
state
to
submit
its
plan
for
distributing
allocations
for
2010­
2014
by
October
21,
2006.
As
discussed
in
the
final
rule
preamble,
EPA
believes
this
lead
time
is
necessary
ensures
that
an
affected
source,
regardless
of
the
State
in
which
the
unit
is
located,
will
have
sufficient
time
to
plan
for
compliance
and
implement
their
compliance
planning.

Comment:

One
commenter
(
OAR­
2002­
0056­
3543)
noted
states
would
be
required
to
submit
a
SIP­
type
plan
to
regulate
existing
mercury
sources;
the
plan
would
include
unit­
specific
standards
for
new
units
under
section
111(
b).
It
was
unclear
to
the
commenter
what
type
of
plan
EPA
is
requesting
and
if
it
will
become
part
of
a
an
air
quality
SIP.

Response:

EPA
is
requiring
the
submission
of
a
State
plan
under
section
111
of
the
CAA.
Detailed
language
describing
the
requirements
of
the
State
plan
has
been
added
to
the
regulatory
text.

Comment:

One
commenter
(
OAR­
2002­
0056­
1678)
submitted
that
relying
on
SIP
to
establish
mercury
reduction
levels
would
be
administratively
cumbersome
and
time
consuming
and
likely
to
result
in
disparate
regulation.

Response:

EPA
is
requiring
the
submission
of
a
State
plan
under
section
111
of
the
CAA.
Detailed
language
describing
the
requirements
of
the
State
plan
has
been
added
to
the
regulatory
text.
EPA
has
provided
a
model
rule
that
States
can
adopt
in
order
to
limit
the
administrative
burden
on
States
and
to
create
a
uniform
program
among
participating
States.

Comment:

One
commenter
(
OAR­
2002­
0056­
2841)
believed
that
if
EPA
establishes
a
cap­
and­
trade
program
under
the
authority
of
section
112(
n)(
1)(
A)
and/
or
112(
d),
EPA
should
amend
the
definition
of
"
emission
standard"
in
40
CFR
63.2
to
read
"
pursuant
to
sections
112(
d),
112(
h),
112(
f)
or
112(
n)
of
the
Act."
Additionally,
the
commenter
believed
EPA
should
amend
40
CFR
5­
191
63.1(
e)
to
read
"
If
the
Administrator
promulgates
an
emission
standard
under
section
112(
d),
(
h),
or
(
n)
of
the
Act.
.
."

Response:

EPA
is
finalizing
a
cap­
and­
trade
program
under
section
111.
See
preamble
for
more
detail.

5.9.2
Approvability
of
Trading
Rule
Comment:

Several
commenters
(
OAR­
2002­
0056­
2219,
­
2519,
­
3431)
opposed
allowing
states
to
decide
the
allocation
of
trading
units
and
the
time
line
for
updating
the
allocations.
One
commenter
(
OAR­
2002­
0056­
2519)
noted
that
states
will
have
the
right
allocate
mercury
emission
allowances
to
individual
sources
or
to
choose
any
other
allocation
scheme
a
state
deems
appropriate.
In
the
event
a
state
fails
to
submit
its
SIP,
the
model
rule
would
become
the
SIP
for
that
state.
The
commenter
believed
the
SIP
process
could
result
in
some
sources
in
one
state
getting
allowances
much
less
than
what
was
envisioned
under
the
EPA's
state
budgets
while
a
source
in
an
adjoining
state
could
receive
more
allowances
than
under
the
proposal.
Under
such
a
situation,
the
first
source
would
have
to
purchase
allowances
from
the
second
or
apply
emission
controls.
The
commenter
points
out
that
such
a
scenario
could
result
in
an
inefficient
trading
program
or
unfair
competitive
issues
among
sources.
Furthermore,
preparation
and
submittal
of
SIP
must
follow
certain
processes
mandated
by
state
Constitution,
and
that
could
result
in
some
delay
in
adopting
the
rule
governing
the
trading
program.
The
commenter
stated
that
additional
time
would
consume
part
of
the
time
allowed
for
compliance
planning
to
achieve
the
emission
caps.
The
commenter
submitted
therefore,
it
is
critical
that
EPA
adopt
a
uniform
program
throughout
the
country,
much
like
the
existing
Acid
Rain
Control
Program,
rather
than
a
patchwork
of
differing
requirements
among
various
states.
Accordingly,
if
EPA
decides
on
a
cap­
and­
trade
program
rather
than
a
MACT
program,
the
commenter
prefers
the
CAA
section
112
approach
over
the
CAA
section
111
approach.

Another
commenter
(
OAR­
2002­
0056­
3431)
believed
a
major
problem
with
utilizing
a
CAA
section
111
standard
of
performance
approach
to
cap­
and­
trade
would
be
that
it
requires
further
decision­
making
at
the
state
level
regarding
allowance
allocation.
According
to
the
commenter,
the
experience
of
the
Northeast
states
with
the
NO
x
budget
rule,
which
similarly
left
the
intrastate
allocations
to
the
affected
states,
was
that
the
allocation
process
was
extremely
contentious
and
subject
to
political
influence.
The
commenter
stated
that
for
example,
if
the
prevailing
view
within
a
state
was
to
rid
the
state
of
coal­
fired
utilities,
the
allocation
scheme
would
provide
a
powerful
tool
for
making
coal­
fired
units
prohibitively
expensive
to
run,
to
the
detriment
of
important
national
objectives
of
maintaining
fuel
diversity.
Consequently,
the
commenter
favored
a
uniform
allocation
scheme
imposed
at
the
national
level,
based
on
the
heat
input
criteria
expressed
by
EPA,
but
determined
in
a
way
that
does
not
favor
one
coal
type
over
another.
5­
192
Several
commenters
(
OAR­
2002­
0056­
0730,
­
1682,
­
2064,
­
2108,
­
4139)
supported
the
CAA
section
111(
d)
approach
because
it
would
allow
more
state
and
local
input.
Several
commenters
(
OAR­
2002­
0056­
0730,
­
1682,
­
2064)
submitted
states
are
in
the
best
position
to
make
allocations
that
protect
the
environment
and
address
hot
spots.
One
commenter
(
OAR­
2002­
0056­
2108)
preferred
to
develop
its
own
system
for
allowance
allocation,
flow
control,
banking,
and
other
trading
issues.
Another
commenter
(
OAR­
2002­
0056­
4139)
supported
the
proposed
flexibility
to
choose
what
allowance
allocation
methodology
states
will
use
to
determine
their
mercury
budgets:
auction
or
free
distribution
of
allowances,
permanent
or
updated
allowances,
and
allowances
based
on
input,
output,
or
emission
reductions.
The
commenter
stated
that
for
interstate
trade,
however,
the
rule
should
specify
that
the
trade
is
allowable
only
if
the
section
111(
d)
limits
for
existing
sources
are
as
stringent
or
more
stringent
in
the
selling
state
as
for
the
facility
in
the
purchasing
state.
The
commenter
believed
that
while
this
is
more
complicated
because
of
the
different
subcategories,
a
matrix
to
represent
appropriate
exchanges
could
be
developed.

One
commenter
(
OAR­
2002­
0056­
3437)
stated
that
in
the
NPR
and
SNPR
states
are
allowed
to
establish
their
own
allocation
methodology.
The
commenter
assumed
this
would
include
existing
and
new
sources
and
any
set
asides.
EPA
then
requested
comment
on
whether
an
allocation
methodology
should
be
mandated
depending
on
whether
a
state
participates
in
an
interstate
trading
program,
an
intrastate
trading
program,
or
no
trading
program.
The
commenter
believed
states
should
have
the
flexibility
in
addressing
the
allocations
under
the
cap
irrespective
of
participation
in
a
particular
program.

One
commenter
(
OAR­
2002­
0056­
3552)
commented
on
whether
to
require
the
State
to
allocate
allowances
to
each
unit
in
accordance
with
the
model
cap
and
trade
rule.
According
to
the
proposal,
a
state
may
allocate
allowances
using
its
own
method.
The
commenter
requested
the
flexibility
not
to
follow
EPA's
methodology
if
the
state
determines
it
is
not
stringent
enough
to
protect
the
public
health.
The
commenter
submitted
that
many
states
are
limited
in
their
rulemaking
authority
to
be
no
stricter
than
federal
standards.

One
commenter
(
OAR­
2002­
0056­
2181)
noted
that
while
EPA
uses
a
heat
input
rate
adjusted
by
subcategories
by
fuel
source
for
determining
State
budgets,
States
may
choose
how
they
will
allocate
allowances
to
each
affected
Utility
Unit.
The
commenter
agreed
that
States
should
not
be
mandated
to
use
the
proposed
hypothetical
allocation
method
when
budgeting
to
specific
units.
Among
the
choices
the
EPA
recognized,
States
may
consider
a
baseline
heat
input
or
baseline
power
output,
updating
or
permanent
allocation,
and
auction
programs.
The
commenter
believed
that
while
on
the
one
hand,
EPA
is
careful
to
encourage
States
to
utilize
an
approach
that
is
best
suited
for
specific
State
circumstances,
on
the
other,
it
notes
that
those
who
adopt
its
method
can
count
on
a
quick
approval
by
the
Agency.
The
commenter
submitted
this
could
bias
certain
States
toward
adopting
the
EPA
approach
without
offering
thorough
consideration
of
the
benefits
of
alternative
allocation
strategies.
The
commenter
recommended
that
EPA
eliminate
this
inherent
bias.
5­
193
Several
commenters
(
OAR­
2002­
0056­
1671,
­
2064)
submitted
that
the
rule
should
allow
states
to
permanently
retire
mercury
credits.
The
commenters
added
that
credits
should
expire
by
a
final
compliance
date.

One
commenter
(
OAR­
2002­
0056­
2898)
suggested
that
EPA
could
provide
a
mechanism
for
units
to
petition
EPA
to
provide
fair
and
accurate
allocations
to
existing
units.
The
commenter
supported
the
comments
submitted
to
EPA
on
this
issue
by
the
National
Rural
Electric
Cooperative
Association.

One
commenter
(
OAR­
2002­
0056­
2721)
noted
that
EPA
is
leaving
the
options
to
the
individual
states
to
determine
if
the
allowances
would
be
permanently
issued:
1)
year
by
year,
2)
5­
10
year
allocations
where
mercury
allowance
allocations
would
be
periodically
placed
into
the
Mercury
allowance
Trading
system
for
5­
10
consecutive
control
periods,
or
3)
a
single
permanent
allocation
where
the
mercury
allowance
allocation
would
be
set
only
once
in
the
beginning
of
the
trading
program.
The
commenter
supported
the
permanent
issuance
of
allowances.
The
commenter
stated
this
would
allow
utilities
to
be
better
prepared
for
planning
for
the
future.
This
planning
would
allow
them
to
put
in­
place
the
appropriate
removal
technologies
without
jeopardizing
electrical
generation
and
other
balance
of
plant
issues.
The
commenter
stated
that
new
units
after
initial
allocation
would
be
required
to
go
to
the
marketplace
to
gain
allowances
under
option
3.
Under
options
1
and
2
the
new
unit
would
be
allocated
allowances
only
with
a
corresponding
reduction
from
an
existing
unit.
The
commenter
submitted
that
the
uncertainty
is
in
what
allocation
plan
each
state
chooses.
The
commenter
believed
that
leaving
the
choice
up
to
the
states
would
weaken
the
overall
trading
program
and
place
an
unfair
financial
burden
on
these
facilities,
especially
for
units
in
a
state
with
few
allowances.

Response:

State
adoption
of
the
model
rule
will
ensure
consistency
in
certain
key
operational
elements
of
the
program
among
participating
States,
while
allowing
each
State
flexibility
in
other
important
program
elements.
Uniformity
of
the
key
operational
elements
is
necessary
to
ensure
a
viable
and
efficient
trading
program
with
low
transaction
costs
and
minimum
administrative
costs
for
sources,
States,
and
EPA.
Consistency
in
areas
such
as
allowance
management,
compliance,
penalties,
banking,
emissions
monitoring
and
reporting
and
accountability
are
essential.

The
EPA's
intent
in
issuing
a
model
rule
for
the
Hg
Budget
Trading
Program
is
to
provide
States
with
a
model
program
that
serves
as
an
approvable
strategy
for
achieving
the
required
reductions.
States
choosing
to
participate
in
the
program
will
be
responsible
for
adopting
State
regulations
to
support
the
Hg
Budget
Trading
Program,
and
submitting
those
rules
as
part
of
the
State
Plan.
There
are
two
alternatives
for
a
State
to
use
in
joining
the
Hg
Budget
Trading
Program:
incorporate
40
CFR
part
60,
subpart
HHHH
by
reference
into
the
State's
regulations
or
adopt
State
regulations
that
mirror
40
CFR
part
60,
subpart
HHHH,
but
for
the
potential
variations
described
below.
5­
194
Some
variations
and
omissions
from
the
model
rule
are
acceptable
in
a
State
rule.
This
approach
provides
States
flexibility
while
still
ensuring
the
environmental
results
and
administrative
feasibility
of
the
program.
EPA
finalizes
that
in
order
for
a
State
Plan
to
be
approved
for
State
participation
in
the
Hg
Budget
Trading
Program,
the
State
rule
should
not
deviate
from
the
model
rule
except
in
the
area
of
allowance
allocation
methodology.
Allowances
allocation
methodology
includes
any
updating
system
and
any
methodology
for
allocating
to
new
units.
Additionally,
States
may
incorporate
a
mechanism
for
implementing
more
stringent
controls
at
the
State
level
within
their
allowance
allocation
methodology.

State
plans
incorporating
a
trading
program
that
is
not
approved
for
inclusion
in
the
Hg
Budget
Trading
Program
may
still
be
acceptable
for
purposes
of
achieving
some
or
all
of
a
State's
obligations
provided
the
general
criteria.
However,
only
States
participating
in
the
Hg
Budget
Trading
Program
would
be
included
in
EPA's
tracking
systems
for
Hg
emissions
and
allowances
used
to
administer
the
multi­
state
trading
program.

In
terms
of
allocations,
States
must
include
an
allocation
section
in
their
rule,
conform
to
the
timing
requirements
for
submission
of
allocations
to
EPA
that
are
described
in
this
preamble,
and
allocate
an
amount
of
allowances
that
does
not
exceed
their
State
trading
program
budget.
However,
States
may
allocate
allowances
to
budget
sources
according
to
whatever
methodology
they
choose.
EPA
has
included
an
optional
allocation
methodology
but
States
are
free
to
allocate
as
they
see
fit
within
the
bounds
specified
above,
and
still
receive
State
Plan
approval
for
purposes
of
the
Hg
Budget
Trading
Program.

5.9.3
State
Authority
under
111
Comment:

Several
commenters
(
OAR­
2002­
0056­
1692,
­
1802,
­
2911,
­
2915,
­
3432,
­
3445,
­
3454,
­
3463,
­
3543,
­
3556,
­
4191,
­
4891)
stated
a
preference
for
a
national
trading
program.
One
commenter
(
OAR­
2002­
0056­
1692)
stated
that
the
flexibility
inherent
in
well­
designed
emission
trading
programs,
such
as
the
Title
IV
acid
rain
program,
is
preferable
to
the
rigidities
of
unit­
or
source­
specific
controls.
The
commenter
believed
however,
in
order
to
secure
the
benefits
of
this
flexibility,
either
of
the
alternative
regulatory
vehicles
EPA
proposed
under
sections
111(
d)
or
112(
n)(
1)
must
lend
itself
to
a
truly
national
emissions
trading
program,
with
certainty
in
the
assignment
of
emission
allowances
 
essential
for
planning
and
executing
cost­
effective
emission
control
strategies.
The
commenter
stated
that
the
"
opt­
in"
nature
of
state
participation
in
the
111(
d)
proposal,
which
provides
too
much
leeway
to
individual
state
SIP
determination
processes,
and
the
open­
ended
potential
for
risk­
based
assessment
of
mercury
reduction
requirements
under
the
112(
n)(
1)
alternative,
jeopardizes
the
benefits
associated
with
a
well­
designed
emissions
trading
regime.
(
Many
commenters
expressed
concerns
with
the
opt­
in
nature
of
state
participation
in
the
CAA
111(
d)
proposal;
see
comment
below
in
this
section.)

One
commenter
(
OAR­
2002­
0056­
3543)
stated
that
a
national
program
is
needed
to
control
mercury
emissions
to
help
restore
Texas
water
bodies
since
evidence
exists
that
some
significant
portion
of
the
mercury
originates
beyond
Texas
borders.
Several
commenters
5­
195
(
OAR­
2002­
0056­
2915,
­
4191)
submitted
that
mercury
allowances
trading
should
be
allowed
to
occur
throughout
the
nation
to
make
the
cap
and
trade
program
as
viable
as
possible.
The
commenters
believe
a
nation­
wide
trading
market
would
reduce
mercury
emissions
faster
and
more
cost
effectively
because
there
would
be
increased
opportunities
and
demand
for
early
mercury
reductions
that
could
be
"
banked"
for
later
use.
Several
commenters
(
OAR­
2002­
0056­
3432,
­
3445)
stated
that
EPA
must
not
allow
individual
states
to
interfere
with
an
emission
trading
compliance
option.
Commenter
(
OAR­
2002­
0056­
3445)
added
that
in
order
for
a
mercury
trading
program
to
be
successful,
a
robust
marketplace
is
necessary.
The
commenter
believed
that
if
trading
is
restricted,
the
efficiencies
of
a
cap­
and­
trade
system
would
be
lost.

Several
commenters
(
OAR­
2002­
0056­
1673,
­
2929)
submitted
that
trading
should
be
allowed
over
the
broadest
interstate
region
or
largest
area
possible.
One
commenter
(
OAR­
2002­
0056­
2929)
stated
that
this
would
capitalize
on
all
efficiencies.
The
commenter
believed
EPA
should
make
every
attempt
to
promote
unfettered
emissions
trading
in
the
final
mercury
rule.

One
commenter
(
OAR­
2002­
0056­
2160)
submitted
that
if
EPA
chooses
a
cap
and
trade
approach,
allowances
should
be
tradable
across
state
boundaries.

One
commenter
(
OAR­
2002­
0056­
2161)
stated
both
the
MACT
and
Cap­
and­
Trade
approaches
have
attributes
and
problems.
Whichever
approach
EPA
chooses,
the
commenter
felt
it
would
be
imperative
that
EPA
continue
to
recognize
in
any
regulation
the
inherent
problems
with
controlling
mercury
for
plants
burning
subbituminous
coal.
The
commenter
believed
the
proposed
MACT
level
of
control
for
subbituminous
plants
is
appropriate;
if
EPA
deemed
it
necessary
to
appreciably
change
this
level,
the
commenter
strongly
urged
EPA
to
re­
propose
this
regulation.
The
commenter
submitted
that
if
EPA
chose
a
Cap
and
Trade
program,
it
should
be
patterned
after
the
highly
successful
Title
IV
SO
2
program.
The
commenter
urged
EPA
to
ensure
that
this
program
is
applied
in
a
consistent
manner
across
the
states.
Differences
in
program
design
or
implementation
by
individual
states
must
be
minimized.
The
commenter
agreed
that
as
EPA
discussed
in
their
proposal
for
an
NSPS
cap
and
trade
program,
the
Title
IV
program
has
demonstrated
that
it
is
an
effective
program
and
has
substantially
reduced
emissions
of
acid
rain
precursors.

Many
commenters
(
OAR­
2002­
0056­
1802,
­
1859,
­
2224,
­
2264,
­
2422,
­
2452,
­
2560,
­
2835,
­
2850,
­
2897,
­
2911,
­
2948,
­
3452,
­
3463,
­
3514,
­
4891)
expressed
concern
that
the
"
opt­
in"
nature
of
state
participation
in
the
CAA
section
111(
d)
program
would
provide
too
much
uncertainty
associated
with
individual
SIP
determination
processes.
Specific
concerns
stated
by
the
commenters
included
the
following:
states
may
not
participate
in
a
national
trading
program;
arbitrary
confiscation
or
other
limitations
on
the
use
of
emission
allowances;
reallocation
of
emission
allowances
among
non­
emitting
source
sectors,
e.
g.,
non­
coal
fired
EGUs;
patchwork
of
programs
varying
from
state
to
state;
states
promoting
premature
emission
allowance
retirement;
time
required
for
review
and
approval
of
separate
SIP
by
state
approval
authorities,
including
the
necessary
notice
and
public
hearings,
followed
by
the
necessary
review
by
the
EPA
will
likely
extend
to
a
number
of
years;
and
a
fragmented
trading
system
would
not
allow
sufficient
trading
5­
196
to
be
economical
for
smaller
facilities.
The
commenters
felt
that
for
trading
programs
to
be
efficient,
equitable,
and
effective,
they
must
by
uniformly
applied
over
broad
geographic
regions.

Several
commenters
(
OAR­
2002­
0056­
2251,
­
2332,
­
2560,
­
2818,
­
2835,
­
2862,
­
2915,
­
2948,
­
3431,
­
3469,
­
3514,
­
4191)
believed
that
state
participation
in
a
mercury
cap­
and­
trade
program
should
be
mandatory
or
that
states
should
be
prohibited
from
interfering
with
the
cap­
and­
trade
program.
One
commenter
(
OAR­
2002­
0056­
3431)
stated
EPA
should
require
participation
by
all
states
in
a
mercury
cap­
and­
trade
program
to
create
a
robust
and
efficient
market
system.
The
commenter
stated
that
a
national
cap­
and­
trade
program
offers
the
most
certainty,
flexibility
and
cost
effectiveness
for
the
industry
as
a
whole.
According
to
the
commenter,
past
experience
with
the
Acid
Rain
program
demonstrated
that
for
a
cap­
and­
trade
program
to
be
successful,
it
must
have
broad­
based
participation
by
the
states.
The
commenter
stated
that
even
the
NO
x
Budget
Rule
in
the
Northeast,
which
allowed
for
some
state
variation
from
a
model
rule,
was
slow
to
develop
into
a
robust
market
with
readily
available
interstate
trades.
According
to
the
commenter,
only
when
is
there
a
robust
market
is
the
development
of
cost
effective
control
technologies
incentivized.
The
commenter
believed
if
states
are
given
the
option
not
to
participate
in
a
cap
and
trade
program
or
to
create
significant
variation
in
their
rule
pursuant
to
a
CAA
§
111
SIP
approach,
the
overall
target
mercury
reduction
may
not
be
achieved
and
non­
participating
states
would
disadvantage
generation
in
their
state
by
increasing
generation
costs
and
reducing
system
reliability.
One
other
commenter
(
OAR­
2002­
0056­
2560)
cited
success
of
the
Title
IV
Acid
Rain
SO
2
program
being
attributed
to
mandatory
participation.
One
commenter
(
OAR­
2002­
0056­
3514)
stated
they
would
only
support
regulation
under
CAA
section
111
if
states
are
required
to
fully
participate
in
the
section
111
interstate
cap­
and­
trade
program.

One
commenter
(
OAR­
2002­
0056­
2862)
believed
a
federal
mercury
emission
program
would
be
most
appropriate
for
an
emission
that
is
national
and
global
in
scope.
The
commenter
submitted
that
if
EPA
decides
to
proceed
to
regulate
mercury
under
a
section
111
Cap
and
Trade
alternative,
states
must
be
required
to
participate
in
the
interstate
cap­
and­
trade
program.
With
this
alternative,
the
federal
performance
standard
would
be
implemented
as
a
state­
specific
emissions
cap.

One
commenter
(
OAR­
2002­
0056­
2948)
stated
that
in
order
for
the
trading
program
to
be
successful,
EPA
would
need
to
prohibit
states
from
interfering
with
any
mercury
cap­
and­
trade
program.
The
commenter
added
that
although
states
are
permitted
under
the
Act
to
impose
more
stringent
emissions
limitations
on
sources
within
their
borders,
states
must
be
expressly
prohibited
from
restricting
the
ability
of
sources
to
sell
or
trade
mercury
allowances.
The
commenter
also
stated
that
similarly,
EPA
needs
to
prohibit
states
from
interfering
with
the
EPA­
established
cap
on
mercury
emissions.
According
to
the
commenter,
in
the
final
rule,
EPA
needs
to
make
clear
that
states
cannot
require
sources
within
their
borders
to
surrender
more
allowances
than
federally
required
and
cannot
place
restrictions
on
the
sale
of
mercury
allowances
by
sources
within
their
borders.
Another
commenter
(
OAR­
2002­
0056­
2835)
recommended
that
EPA
reduce
the
opportunity
for
widely
diverging
state
plans
by
prescribing
the
manner
in
which
states
allocate
allowances
to
sources
participating
in
the
trading
program.
Similarly,
several
commenters
(
OAR­
2002­
0056­
2252,
­
2332)
stated
that
a
mercury
trade
program
that
is
state
run
will
lead
to
5­
197
state­
to­
state
differences
in
implementation.
These
commenters
asserted
that
it
is
not
clear
that
this
method
is
consistent
with
the
goal
of
allowances
that
are
"
readily
transferable
between
all
regulated
utilities"
(
69
FR
4652
Summary
dated,
January
30,
2004).
One
commenter
(
OAR­
2002­
0056­
2818)
suggested
that,
if
EPA
determines
that
a
cap
and
trade
program
is
the
best
way
to
reduce
mercury
emissions,
then
EPA
should
administer
the
program
so
it
is
available
to
all
utility
units.

Several
commenters
(
OAR­
2002­
0056­
2862,
­
2948)
disagreed
with
the
amount
of
flexibility
states
will
have
under
the
CAA
section
111
cap­
and­
trade
program.
One
commenter
(
OAR­
2002­
0056­
2862)
noted
that
EPA's
section
111
cap­
and­
trade
proposal
would
allow
states
the
flexibility
to
determine
how
to
allocate
the
capped
mercury
allowances
to
in­
state
sources.
State
implementation
plans
must,
however,
allocate
the
full
emissions
cap,
and
all
of
the
EPA­
issued
allowances
must
be
issued
to
in­
state
sources.
The
commenter
submits
that
because
the
state
cap
is
essentially
the
CAA
section
111
performance
standard,
states
choosing
not
to
allocate
all
of
their
allowances
would
essentially
be
"
opting
out"
of
the
section
111
program,
and
modifying
the
underlying
federal
standard
of
performance.
The
Clean
Air
Act
does
not
permit
this.

The
second
commenter
(
OAR­
2002­
0056­
2948)
disagreed
with
EPA's
proposal
to
allow
states
to
opt
out
of
a
CAA
section
111
trading
program.
According
to
the
commenter,
because
promulgation
of
a
section
111
trading
program
would
necessitate
a
determination
by
EPA
that
the
program
is
the
"
best
system"
for
reducing
mercury
emissions
from
coal­
fired
power
plants,
states
cannot
interfere
with
that
determination.
The
commenter
believed
that
although
states
do
have
some
authority
under
section
111,
they
lack
authority
to
change
the
standard
of
performance
set
by
EPA.
According
to
the
commenter,
if
EPA
permits
states
to
opt
out
of
a
section
111
trading
program,
this
will
in
essence
allow
states
to
change
the
standard
of
performance,
which
the
CAA
does
not
authorize.
The
commenter
added
that
similarly,
states
cannot
issue
only
a
portion
of
the
allowances
available
within
the
state
because
this
would
also
permit
that
state
to
modify
the
federally
determined
standard
of
performance.

Several
commenters
(
OAR­
2002­
0056­
0598,
­
3449,
­
3543)
believed
states
should
be
allowed
to
opt
out
of
the
CAA
section
111
cap­
and­
trade
program.
One
commenter
(
OAR­
2002­
0056­
3449)
submitted
that
states
should
have
authority
not
to
participate
in
emission
trading
programs
and
to
require
emission
reductions
beyond
those
specified
in
state
budgets.

One
commenter
(
OAR­
2002­
0056­
2721)
believed
that
States
should
be
required
to
participate
in
the
inter­
State
trading
program.
The
commenter
submitted
that
in
instances
where
there
are
few
or
only
one
utility
in
a
State
(
i.
e.,
South
Dakota),
the
utility
would
be
at
an
extreme
economic
disadvantage
relative
to
a
utility
in
a
neighboring
state
that
has
multiple
affected
units
when
allowing
each
state
to
determine
independently
the
amount
of
new
source
set
aside
or
allocations
of
allowances
to
other
industry
sources.

One
commenter
(
OAR­
2002­
0056­
2922)
stated
that
EPA
must
make
clear
that
states
cannot
interfere
with
the
cap­
and­
trade
program.
The
commenter
offered
as
example,
states
should
be
expressly
prohibited
from
requiring
units
to
surrender
more
allowances
than
required
by
5­
198
EPA's
one­
allowance­
per­
ounce
rule
or
from
placing
restrictions
on
the
intrastate
or
interstate
transfer
of
allowances.
The
commenter
urged
EPA
to
include
provisions
in
its
rules
that
expressly
prohibit
states
from
interfering
with
the
cap­
and­
trade
program
in
the
ways
described
above
or
in
any
other
way.

One
commenter
(
OAR­
2002­
0056­
2224)
had
concerns
about
potential
adverse
impacts
that
might
occur
through
an
inflexible,
unit­
specific
regulatory
control
program.
Specifically,
the
commenter
was
concerned
that
the
benefits
and
flexibility
of
a
market­
based
program
could
be
entirely
lost
if
it
were
determined
that
a
national
cap­
and­
trade
program
is
not
legally
authorized
or,
if
states
declined
to
implement
the
cap­
and­
trade
option
under
section
111
alternative.
According
to
the
commenter,
to
anticipate
these
concerns,
EPA
should
allow
states
to
establish
flexible
procedures
for
implementing
the
mercury
reduction
requirements
under
the
"
section
111"
option.
The
commenter
stated
that
in
addition
to
the
cap­
and­
trade
program
proposed
in
the
supplement
notice,
these
procedures
should
allow
states
to
implement
the
reductions
through
emissions
averaging
or
trading
on
at
least
a
facility­
wide
basis.
The
commenter
noted
that
one
alternate
control
program,
which
was
specifically
provided
for
in
the
nationwide
MACT
alternative,
would
be
the
emissions
averaging
program
modeled
after
the
NO
x
acid
rain
program.
The
commenter
asserted
that
the
rule
should
clarify
that
this
provision
should
also
specifically
be
provided
for
under
the
section
111
implementation
approach
for
states
that
may
elect
not
to
participate
in
the
nationwide
cap­
and­
trade
program.
Another
alternative
that
the
commenter
strongly
urged
EPA
to
adopt
was
a
state­
wide,
mass
emissions
(
i.
e.,
ounces/
year)
approach
that
would
involve
mass
emissions
caps
set
for
each
facility
(
calculated
based
on
the
rule's
emission
rates).
The
commenter
asserted
that
providing
at
least
this
much
flexibility
would
be
essential
to
enable
electric
generators
to
develop
least­
cost
strategies
for
controlling
mercury.
According
to
the
commenter,
among
other
things,
it
would
provide
significant
additional
compliance
flexibility
for
multi­
unit
stations
while
meeting
the
overall
reduction
goals
of
the
program.
The
commenter
stated
that
section
111(
d)
provides
states
with
broad
latitude
in
designing
the
mercury
control
program,
and
emissions
averaging
would
thus
be
an
appropriate
implementation
mechanism
that
should
be
available
to
states
so
long
as
the
state
program
achieves
the
mercury
reductions
required
under
the
final
EPA
rule.

Response:

As
discussed
in
the
final
preamble,
each
State
must
impose
control
requirements
that
the
State
demonstrates
will
limit
Statewide
emissions
from
affected
new
and
existing
sources
to
the
amount
of
the
budget.
Consistent
with
CAIR,
EPA
is
finalizing
that
States
may
meet
their
Statewide
emission
budget
by
allowing
their
sources
to
participate
in
a
national
cap­
and­
trade
program.
That
is,
a
State
may
authorize
its
affected
sources
to
buy
and
sell
allowances
out
of
State,
so
that
any
difference
between
the
State's
budget
and
the
total
amount
of
Statewide
emissions
will
be
offset
in
another
State
(
or
States).
Regardless
of
State
participation
in
the
national
cap­
and­
trade
program,
EPA
believes
that
the
best
way
to
assure
this
emission
limitation
is
for
the
State
to
assign
to
each
affected
source,
new
and
existing,
an
amount
of
allowances
that
sum
to
the
State
budget.
Therefore,
EPA
is
finalizing
that
all
regulatory
requirements
be
in
the
form
of
a
maximum
level
of
emissions
(
i.
e.,
a
cap)
for
the
sources.
5­
199
As
proposed
in
the
SNPR,
EPA
is
finalizing
that
each
State
must
submit
a
demonstration
that
it
will
meet
its
assigned
Statewide
emission
budget,
but
that
regardless
of
whether
the
State
participates
in
a
trading
program,
the
State
may
allocate
its
allowances
by
its
own
methodology
rather
than
following
the
method
used
by
EPA
to
derive
the
state
emissions
budgets.
This
alternative
approach
is
consistent
with
the
approach
in
the
CAIR.

States
remain
authorized
to
require
emissions
reductions
beyond
those
required
by
the
State
budget,
and
nothing
in
today's
final
rule
will
preclude
the
States
from
requiring
such
stricter
controls
and
still
being
eligible
to
participate
in
the
Hg
Budget
Trading
Program.

Comment:

Several
commenters
(
OAR­
2002­
0056­
1611,
­
3909)
stated
that
the
proposed
rules
should
not
override
more
stringent
State
requirements.
One
commenter
(
OAR­
2002­
0056­
2835)
stated
that
States
are
always
free
to
adopt
mercury
control
requirements
more
stringent
than
the
federal
requirements
to
address
any
adverse
local
impacts
from
EGU
emissions.

One
commenter
(
OAR­
2002­
0056­
3199)
asked
EPA
to
consider
provisions
that
would
allow
states
to
control
individual
plants
in
the
event
there
is
a
demonstrated
mercury
hot
spot.
Similarly,
another
commenter
(
OAR­
2002­
0056­
2909)
stated
that
EPA
rules
must
provide
the
explicit
right
and
authority
for
States
to
deal
with
residual
local
issues.

Response:

Moreover,
States
remain
authorized
to
require
emissions
reductions
beyond
those
required
by
the
State
budget,
and
nothing
in
today's
final
rule
will
preclude
the
States
from
requiring
such
stricter
controls
and
still
being
eligible
to
participate
in
the
Hg
Budget
Trading
Program.

Comment:

One
commenter
(
OAR­
2002­
0056­
2430)
stated
that
EPA
must
clearly
define
its
role
in
overseeing
a
cap­
and­
trade
program
if
a
state
elects
to
participate.
The
commenter
submitted
that
States
are
unable
to
evaluate
the
cost
associated
with
implementation
of
the
rule
without
clearly
stated
commitments.

Response:

States
may
elect
to
participate
in
an
EPA­
managed
cap­
and­
trade
program
for
coal­
fired
Utility
Units
greater
than
25
MW.
To
participate,
a
State
must
adopt
the
model
cap­
and­
trade
rules
finalized
in
this
section
of
today's
rule
with
flexibility
to
modify
sections
regarding
source
Hg
allocations.
For
States
that
elect
not
to
participate
in
an
EPA­
managed
cap­
and­
trade
program,
their
respective
State
Hg
budgets
will
serve
as
a
firm
cap.
5­
200
In
a
system
run
by
EPA,
source
information
management,
emissions
data
reporting,
and
allowance
trading
is
done
through
on­
line
systems
similar
to
those
currently
used
for
the
Acid
Rain
SO2
and
NOx
SIP
Call
programs
Comment:

Several
commenters
(
OAR­
2002­
0056­
2264,
­
2422)
claimed
that
CAA
section
111(
d)
cap­
and­
trade
program
would
place
an
unfair
burden
on
many
States
that
are
already
required
to
develop
and
approve
controversial
ozone
and
PM
2.5
SIPs.
Moreover,
the
inclusion
of
mercury
emission
programs
within
often
time
consuming
State
SIP
submission
and
approval
processes
would
effectively
reduce
the
time
available
for
source
compliance
planning
and
control
strategy
implementation.
In
this
regard,
the
commenters
noted
that
the
proposed
section
111(
d)
SIP­
based
trading
program
has
been
rejected
in
principle
by
11
of
the
12
northeastern
states
of
the
Ozone
Transport
Commission
(
OTC).
Eleven
of
the
12
OTC
states
voted
to
oppose
any
cap­
and­
trade
program
for
mercury,
with
Virginia
abstaining.
The
commenters
pointed
out
that
other
states
have
voiced
similar
concerns
about
emissions
trading
for
mercury.
The
commenters
believed
these
developments
underscore
the
potential
difficulties
associated
with
an
emission
trading
plan
implemented
through
section
111(
d).

Response:

EPA
is
committed
to
assist
states
in
the
implementation
of
the
program.
States
may
elect
to
participate
in
an
EPA­
managed
cap­
and­
trade
program
for
coal­
fired
Utility
Units
greater
than
25
MW.
To
participate,
a
State
must
adopt
the
model
cap­
and­
trade
rules
finalized
in
this
section
of
today's
rule
with
flexibility
to
modify
sections
regarding
source
Hg
allocations.
For
States
that
elect
not
to
participate
in
an
EPA­
managed
cap­
and­
trade
program,
their
respective
State
Hg
budgets
will
serve
as
a
firm
cap.

In
a
system
run
by
EPA,
source
information
management,
emissions
data
reporting,
and
allowance
trading
is
done
through
on­
line
systems
similar
to
those
currently
used
for
the
Acid
Rain
SO2
and
NOx
SIP
Call
programs.

5.9.4
State
Resources
Comment:

Several
commenters
(
OAR­
2002­
0056­
2120,
­
2219,
­
2247,
­
2430,
­
2871,
­
2887,
­
2889,
­
2897)
stated
that
the
cap­
and­
trade
program
under
CAA
section
111
would
place
an
additional
burden
on
states.
One
commenter
submitted
that
section
111(
d)
would
place
an
unfair
burden
on
many
States
that
are
already
required
to
develop
and
approve
controversial
ozone
and
PM
2.5
SIPs.
Several
commenters
(
OAR­
2002­
0056­
2120,
­
2430)
asserted
noted
that
the
cap­
and­
trade
program
proposed
in
the
supplemental
rule
would
appear
to
require
significant
resources
for
state
and
local
agencies,
the
source
of
which
is
not
accounted
for
in
EPA's
proposal.
The
commenters
state
the
same
is
true
for
the
enforcement
and
compliance
scheme.
The
commenters
believed
that
adding
additional
burden
to
overextended
states
is
a
recipe
for
failure.
5­
201
One
commenter
(
OAR­
2002­
0056­
2219)
stated
that
because
of
the
additional
burden
of
the
budget
permitting
system
it
is
likely
that
the
permitting
time
line
would
be
delayed
and
create
unacceptable
delays
in
emission
reductions.
One
commenter
added
that
the
resources
needed
to
implement
a
cap
and
trade
program
under
section
111
would
be
much
higher
than
the
resources
needed
for
MACT
standards
because
the
state
must
conduct
a
rulemaking
to
obtain
authority
to
administer
section
111(
d)
emission
guidelines
and
they
currently
have
no
trading
system
that
could
be
used
as
a
model
to
allocate
credits.
The
commenter
also
questioned
EPA's
concerns
about
states
being
overwhelmed
by
requests
for
Title
V
permit
modifications
for
1
year
compliance
extensions
under
a
MACT
standard.
The
commenter
stated
that
amending
permits
to
extend
a
compliance
date
would
be
far
less
resource
intensive
than
implementing
and
administering
the
allowance
distribution
process
in
the
mercury
trading
program.

Response:

States
may
elect
to
participate
in
an
EPA­
managed
cap­
and­
trade
program
for
coal­
fired
Utility
Units
greater
than
25
MW.
To
participate,
a
State
must
adopt
the
model
cap­
and­
trade
rules
finalized
in
this
section
of
today's
rule
with
flexibility
to
modify
sections
regarding
source
Hg
allocations.
For
States
that
elect
not
to
participate
in
an
EPA­
managed
cap­
and­
trade
program,
their
respective
State
Hg
budgets
will
serve
as
a
firm
cap.

In
a
system
run
by
EPA,
source
information
management,
emissions
data
reporting,
and
allowance
trading
is
done
through
on­
line
systems
similar
to
those
currently
used
for
the
Acid
Rain
SO2
and
NOx
SIP
Call
programs.

Comment:

One
commenter
(
OAR­
2002­
0056­
1596)
stated
that
enforcement
personnel
have
little
training
about
how
to
determine
compliance
with
a
cap­
and­
trade
program.
The
commenter
believed
that
this
approach
would
allow
companies
to
hide
pollution
with
numbers
that
are
hard
to
verify.

Response:

As
discussed
in
the
final
preamble,
EPA
will
jointly
administer
the
cap­
and­
trade
program
with
States.
EPA
is
requiring
monitoring
under
Part
75
and
EPA
is
running
the
system
to
collect
emissions
data
and
track
allowances.

Comment:

One
commenter
(
OAR­
2002­
0056­
3448)
asserted
that
EPA's
lack
of
an
effective
national
strategy
has
driven
states
to
do
their
own
rules.
The
commenter
submitted
that
Massachusetts,
Connecticut,
New
Jersey,
and
Wisconsin
have
either
legislation
or
rules
and
others
are
sure
to
follow.
The
commenter
believed
states
should
not
have
to
expend
resources
on
a
problem
that
is
best
addressed
on
a
nationwide
basis.
The
commenter
stated
that
EPA
has
created
this
situation.
5­
202
Response:

Under
the
final
rule
EPA
is
establishing
a
national
program
to
reduce
Hg
emissions
by
allowing
states
to
participate
in
a
cap­
and­
trade
program.

Comment:

One
commenter
(
OAR­
2002­
0056­
2883)
believed
that
the
EPA
should
hold
regional
workshops
to
assist
municipal
and
state­
owned
utility
generation
facilities
with
compliance
with
these
final
rules
to
reduce
mercury
and
nickel.

Response:

EPA
is
committed
to
assist
states
in
the
implementation
of
the
program.