JLI
TITLE
35:
ENVIRONMENTAL
PROTECTION
SUBTITLE
B:
AIR
POLLUTION
CHAPTER
I:
POLLUTION
CONTROL
BOARD
SUBCHAPTER
C:
EMISSION
STANDARDS
AND
LIMITATIONS
FOR
STATIONARY
SOURCES
PART
225
CONTROL
OF
EMISSIONS
FROM
LARGE
COMBUSTION
SOURCES
SUBPART
A:
GENERAL
PROVISIONS
Section
225.100
Severability
225.120
Abbreviations
and
Acronyms
225.130
Definitions
225.140
Incorporations
by
Reference
225.150
Commence
Commercial
Operation
SUBPART
B:
CONTROL
OF
MERCURY
EMISSIONS
FROM
COAL-FIRED
ELECTRIC
GENERATING
UNITS
Section
225.200
Purpose
225.202
Measurement
Methods
225.205
Applicability
225.210
Compliance
Requirements
225.220
Clean
Air
Act Permit
Program
(CAAPP)
Permit
Requirements
225
.230
Emission
Standards
for EGUs
at
Existing
Sources
225.232
Averaging
Demonstrations
for Existing
Sources
225.233
Multi-Pollutant
Standard
(MPS)
225.234
Temporary
Technology-Based
Standard
for
EGUs
at
Existing
Sources
225.23
5
Units
Scheduled
for
Permanent
Shut
Down
225.237
Emission
Standards
for
New
Sources
with
EGUs
225.23
8
Temporary
Technology-Based
Standard
for
New
Sources
with
EGUs
225.239
Periodic
Emissions
Testing
Alternative
Requirements
225 .240
General
Monitoring
and
Reporting
Requirements
225.250
Initial
Certification
and
Recertification
Procedures
for
Emissions
Monitoring
225.260
Out of
Control
Periods
for
Emission
Monitors
225
.261
Additional
Requirements
to Provide
Heat
Input
Data
225 .263
Monitoring
of Gross
Electrical
Output
225
.265
Coal
Analysis
for
Input
Mercury
Levels
225.270
Notifications
225
.290
Recordkeeping
and
Reporting
225 .295
Treatment
of
Mercury
Allowances
1
225.291
Combined
Pollutant
Standard:
Purpose
225
.292
Applicability
of
the
Combined
Pollutant
Standard
225.293
Combined
Pollutant
Standard:
Notice
of
Intent
225
.294
Combined
Pollutant
Standard:
Control
Technology Requirements
and
Emissions
Standards
for
Mercury
225 .295
Combined
Pollutant
Standard:
Emissions
Standards for
NO
and
SO
2
225
.296
Combined
Pollutant
Standard:
Control
Technology Requirements
for
SO
and
PM
Emissions
225.297
Combined
Pollutant
Standard:
Permanent
Shut-Downs
225.298
Combined
Pollutant
Standard:
Requirements
for
NQ
and
SO
2
Allowances
225.299
Combined
Pollutant
Standard:
Clean
Air
Act
Requirements
SUBPART
C: CLEAN
AIR
ACT
INTERSTATE
RULE
(CAIR)
SO
2
TRADING
PROGRAM
Section
225
.300
Purpose
225
.305
Applicability
225.3
10
Compliance
Requirements
225.3
15
Appeal
Procedures
225.320
Permit
Requirements
225
.325
Trading
Program
SUBPART
D:
CAIR
NO
ANNUAL
TRADING
PROGRAM
Section
225
.400
Purpose
225
.405
Applicability
225
.410
Compliance
Requirements
225.415
Appeal
Procedures
225.420
Permit
Requirements
225.425
Annual
Trading
Budget
225
.430
Timing
for Annual Allocations
-
225
.435
Methodology
for
Calculating
Annual
Allocations
225
.440
Annual
Allocations
225.445
New
Unit
Set-Aside (NUSA)
225
.450
Monitoring,
Recordkeeping
and
Reporting
Requirements
for
Gross
Electrical
Output
and
Useful
Thermal Energy
225
.455
Clean
Air
Set-Aside
(CASA)
225.460
Energy
Efficiency
and
Conservation,
Renewable
Energy,
and
Clean
Technology
Projects
225.465
Clean
Air
Set-Aside
(CASA)
Allowances
225.470
Clean
Air Set-Aside
(CASA)
Applications
225.475
Agency
Action
on
Clean
Air
Set-Aside
(CASA)
Applications
225
.480
Compliance
Supplement
Pool
SUBPART
E:
CAIR
NO
OZONE
SEASON
TRADiNG
PROGRAM
2
Section
225.500
Purpose
225.505
Applicability
225.510
Compliance
Requirements
225.515
Appeal
Procedures
225
.520
Permit
Requirements
225.525
Ozone
Season
Trading
Budget
225.530
Timing
for
Ozone
Season
Allocations
225.535
Methodology
for
Calculating
Ozone
Season
Allocations
225.540
Ozone
Season
Allocations
225.545
New
Unit
Set-Aside
(NUSA)
225.550
Monitoring,
Recordkeeping
and
Reporting
Requirements
for
Gross
Electrical
Output
and
Useful
Thermal
Energy
225.555
Clean
Air
Set-Aside
(CASA)
225.560
Energy
Efficiency
and
Conservation,
Renewable
Energy,
and
Clean
Technology
Projects
225.565
Clean Air
Set-Aside
(CASA)
Allowances
225.570
Clean
Air
Set-Aside
(CASA)
Applications
225
.575
Agency
Action
on
Clean
Air
Set-Aside
(CASA)
Applications
SUEPAPT
F
CO4TTNFfl
POT
TTTTANT
TANTAPTh
225.600
Purpose
‘‘C
ff
A_.1
LU
.UUJ
n.ppuCablflty
‘9S
61fl
Nctir
nfTntAl,t
225.615
Control Technology
Requirements
and
Emissions
Standards
for
Mercury
225.620
Emissions
Standards
for
NO
and
SO
2
225
.625
Control Technology
Requirements
for
NO-SO
2
,
and
PM
Emissions
225.630
Permanent
Shut
Downs
for
CA
SO
2
,
C
NO,
and
C
NO%
Onn
nnn
Allowances
225.640
Clean Air
Act
Requirements
225.APPENDIX
A
Specified
EGUs
for
Purposes
of
the
CPSSubpart
F (Midwest
Generation’s
Coal-Fired
Boilers
as
of
July
1,
2006)
225
.APPENDIX
B
Continuous
Emission
Monitoring
Systems
for
Mercury
AUTHORITY:
Implementing
and
authorized
by
Section
27
of
the
Environmental
Protection
Act
[415
ILCS
5/27].
SOURCE:
Adopted
in
R06-25
at
31111.
Reg.
129,
effective
December
21,
2006;
amended
in
R06-26
at
31111. Reg.
12864,
effective
August
31,
2007.
3
SUBPART
A: GENERAL
PROVISIONS
Section
225.100
Severability
If any
Section,
subsection
or
clause
of this
Part
is found
invalid,
such
finding
must
not
affect
the
validity
of
this
Part as
a whole
or
any Section,
subsection
or
clause
not found
invalid.
Section
225.120
Abbreviations
and
Acronyms
Unless
otherwise
specified
within
this
Part,
the
abbreviations
used
in
this Part
must
be the
same
as
those
found
in 35
Iii.
Adm.
Code
211.
The
following
abbreviations
and
acronyms
are
used
in
this Part:
Act
Environmental
Protection
Act
[415
ILCS 5]
ACI
activated
carbon
injection
AETB
Air
Emission
Testing
Body
Agency
Illinois
Environmental
Protection
Agency
Btu
British
thermal
unit
CAA
Clean
Air
Act [42
USC
7401
et seq.]
CAAPP
Clean
Air
Act
Permit
Program
CAR
Clean
Air Interstate
Rule
CASA
Clean
Air Set-Aside
CEMS
continuous
emission
monitoring
system
CO
2
carbon
dioxide
CPS
Combined
Pollutant
Standard
-
CGO
converted
gross
electrical
output
CRM
certified
reference
materials
CUTE
converted
useful
thermal
energy
DAHS
data acquisition
and
handling
system
dscm
dry
standard
cubic
meters
EGU
electric
generating
unit
ESP
electrostatic
precipitator
FGD
flue gas
desulfurization
1l,m
feet
per
minute
GO
gross electrical
output
GWh
gigawatt
hour
HI
heat
input
Hg
mercury
hr
hour
ISO
International
Organization
for
Standardization
kg
kilogram
lb
pound
MPS
Multi-Pollutant
Standard
MSDS
Material
Safety
Data Sheet
4
MW
megawatt
Mwe
megawatt
electrical
MWh
megawatt
hour
NAAQS
National
Ambient
Air
Quality
Standards
NIST
National
Institute
of
Standards
and
Technology
N0
nitrogen
oxides
NTRM
NIST
Traceable
Reference
Material
NUSA
New
Unit
Set-Aside
ORIS
Office
of
Regulatory
Information
Systems
02
oxygen
PM
2
.
5
particles
less
than
2.5
micrometers
in
diameter
QA
quality
assurance
OC
quality
certification
RATA
relative
accuracy
test
audit
RGFM
reference
gas
flow
meter
SO
2
sulfur
dioxide
SNCR’
selective
noncatalytic
reduction
TTBS
Temporary
Technology
Based
Standard
TCGO
total
converted
useful
thermal
energy
UTE
useful
thermal
energy
USEPA
United
States
Environmental
Protection
Agency
yr
year
(Source:
Amended
at
effective
Section
225.130
Definitions
The
following
definitions
apply
for
the
purposes
of
this
Part.
Unless
otherwise
defined
in
this
Section
or
a
different
meaning
for
a
term
is
clear
from
its
context,
the
terms
used
in
this
Part
have
the
meanings
specified
in
35
Iii.
Adm.
Code 211.
-
“Agency”
means
the
Illinois
Environmental
Protection
Agency.
[415
ILCS
5/3.105]
“Averaging
demonstration”
means,
with
regard
to Subpart
B
of
this
Part,
a demonstration
of
compliance
that
is
based
on
the
combined
performance
of
EGUs
at
two
or
more
sources.
“Base
Emission
Rate”
means,
for
a
group
of
EGUs
subject
to
emission
standards
for
NOx
and
SO
2
pursuant
to
Section
225.233,
the
average
emission
rate
of
N0
or
SO
2
from
the
EGUs,
in
pounds
per
million
Btu
heat input,
for
calendar
years
2003
through
2005
(or,
for
seasonal
N0,
the
2003
through
2005
ozone
seasons),
as
determined
from
the
data
collected
and
quality
assured
by
the
USEPA,
pursuant
to
the
40
CFR
72
and
96
federal
Acid Rain
and
N0
Budget
Trading
Programs,
for
the
emissions
and
heat
input
of
that
group
of
EGUs.
5
“Board”
means
the
Illinois
Pollution
Control
Board.
[415
ILCS
5/3.1301
“Boiler”
means
an
enclosed
fossil
or
other
fuel-fired
combustion
device
used
to
produce
heat
and
to
transfer
heat
to
recirculating
water,
steam,
or
other
medium.
“Bottoming-cycle
cogeneration
unit”
means
a
cogeneration
unit
in
which
the
energy
input
to
the
unit
is
first
used
to produce
useful
thermal
energy
and
at
least
some
of
the
reject
heat
from
the
useful
thermal
energy
application
or
process
is
then
used
for
electricity
production.
“CA]E. authorized
account
representative”
means,
for
the
purpose
of
general
accounts,
a
responsible
natural person
who
is
authorized,
in
accordance
with
40
CFR
96,
subparts
BB,
FF,
BBB,
FFF,
BBBB,
and
FFFF
to transfer
and
otherwise
dispose
of
CAIR
NON,
SO
2
,
and
NO
Ozone
Season
allowances,
as
applicable,
held
in
the
CAR
NON,
SO
2
,
and
NO
Ozone
Season
general
account,
and
for
the
purpose
of
a
CAIR
NO
compliance
account,
a
CAR
SO
2
compliance
account,
or a
CAIR
NO
Ozone
Season
compliance
account,
the
CAR
designated
representative
of
the
source.
“CAR
designated
representative”
means,
for
a
CAR
NO
source,
a CAR
SO
2
source,
and
a
CAR
NO
Ozone
Season
source
and
each
CAR
NO
unit,
CAR
SO
2
unit
and
CAR
NO
Ozone
Season
unit
at
the
source,
the
natural
person
who
is
authorized
by
the
owners
and
operators
of
the
source
and
all
such
units
at
the
source,
in
accordance
with
40
CFR
96,
subparts
BB,
FF,
BBB,
FFF,
BBBB,
and
FFFF
as
applicable,
to
represent
and
legally
bind
each
owner
and
operator
in
matters
pertaining
to
the
CAR
NO
Annual
Trading
Program,
CAR
SO
2
Trading
Program,
and
CAR
NO
Ozone
Season
Trading
Program, as
applicable.
For
any
unit
that
is
subject
to
one
or
more
of
the
following
programs:
CAR
NO
Annual
Trading
Program,
CAR
SO
2
Trading
Program,
CAR
NO
Ozone
Season
Trading
Program,
or
the
federal
Acid
Rain
Program,
the
designated
representative
for
the
unit
must
be
the
same
natural
person
for
all programs
applicable
to
the
unit.
“Coal”
means
any
solid
fuel
classified
as
anthracite,
bituminous,
subbituminous,
or
lignite
by
the
American
Society for
Testing
and
Materials
(ASTM)
Standard
Specification
for
Classification
of Coals
by
Rank
D388-77,
90,
91,
95,
98a,
or
99
(Reapproved
2004).
“Coal-derived fuel”
means
any
fuel
(whether
in
a solid,
liquid
or
gaseous
state)
produced
by
the
mechanical,
thermal,
or
chemical
processing
of
coal.
“Coal-fired”
means:
•
For
purposes
of Subpart&
B
and
F,
or
for
purposes
of
allocating
allowances
under
Sections
225.435,
225.445, 225.535,
and
225.545,
combusting
any
amount
of
coal
or
coal-derived
fuel,
alone
or
in
combination
with
any
amount
of
any
other
fuel,
during
a
specified
year;
6
Except
as provided
above,
combusting
any
amount
of
coal
or
coal-derived
fuel,
alone
or
in
combination
with
any
amount
of any
other
fuel.
“Cogeneration
unit”
means,
for
the
purposes
of
Subparts
C,
D,
and
E,
a stationary,
fossil
fuel-fired
boiler
or
a stationary,
fossil
fuel-fired
combustion
turbine
of
which
both
of
the
following
conditions
are
true:
It uses
equipment
to
produce
electricity
and
useful
thermal
energy
for
industrial,
commercial,
heating,
or
cooling
purposes
through the
sequential
use of
energy;
and
It produces
either
of
the
following
during
the 12-month
period
beginning
on
the
date
the
unit
first
produces
electricity
and
during
any
subsequent
calendar
year
after
that
in
which
the
unit
first
produces
electricity:
For
a topping-cycle
cogeneration
unit,
both
of
the
following:
Useful
thermal
energy
not
less
than
five
percent
of total
energy
output;
and
Useful
power
that,
when
added
to
one-half
of
useful
thermal
energy
produced,
is
not
less
than
42.5
percent
of
total
energy
input,
if
useful
thermal
energy
produced
is
15
percent
or
more
of
total
energy
output,
or
not
less
than
45 percent
of
total
energy
input
if
useful
thermal
energy
produced
is
less
than
15
percent
of total
energy
output;
or
For
a
bottoming-cycle
cogeneration
unit,
useful
power
not
less
than
45
percent
of
total
energy
input.
“Combined
cycle
system”
means
a system
comprised
of
one.
or
more
combustion
turbines,
heat
recovery
steam
generators,
and
steam
turbines
configured
to improve
overall
efficiency of
electricity
generation
or steam
production.
“Combustion
turbine”
means:
An
enclosed
device
comprising
a compressor,
a
combustor, and
a
turbine
and
in
which
the
flue
gas
resulting
from
the
combustion
of
fuel
in
the
combustor
passes
through
the turbine,
rotating
the
turbine; and
If
the
enclosed
device
described
in
the
above
paragraph
of
this
definition
is
combined cycle,
any
associated
duct
burner,
heat
recovery
steam
generator
and
steam
turbine.
“Commence
commercial
operation”
means,
for
the
purposes
of Subparts
B and
F of
this
Part,
with
regard
to an
EGU
that
serves
a
generator,
to
have
begun
to
produce
steam,
gas,
7
or
other
heated
medium
used
to generate
electricity
for
sale
or
use,
including
test
generation.
Such
date
must
remain
the
unit’s
date
of
commencement
of
operation
even
if
the
EGU
is
subsequently
modified,
reconstructed
or
repowered.
For
the
purposes
of
Subparts
C, D
and
E,
“commence
commercial operation”
is
as
defined
in
Section
225.150.
“Commence
construction”
means,
for
the
purposes
of
Section 225.460(f),
225.470,
225.560(f),
and
225.570,
that
the
owner
or owner’s
designee has
obtained
all
necessary
preconstruction
approvals
(e.g.,
zoning)
orpermits
and
either
has:
Begun,
or
caused
to
begin,
a
continuous
program
of
actual
on-site
construction
of
the
source,
to
be completed
within
a reasonable
time;
or
Entered into
binding
agreements
or
contractual
obligations,
which cannot
be
cancelled
or
modified
without
substantial
loss,
to
the
owner
or
operator,
to
undertake
a program
of actual
construction
of
the
source
to be
completed
within
a
reasonable
time.
For
purposes
of this
definition:
“Construction”
shall
be
determined
as
any
physical
change
or
change
in
the
method
of
operation,
including
but
not
limited
to
fabrication,
erection,
installation,
demolition,
or
modification
of projects
eligible for
CASA
allowances,
as
set
forth
in
Sections
225
.460
and
225.560.
“A
reasonable
time”
shall
be
determined
considering
but
not
limited
to the
following
factors:
the
nature
and
size
of
the
project,
the
extent
of design
engineering,
the
amount
of
off-site
preparation,
whether
equipment
can
be
fabricated
or
can
be
purchased,
when
the
project
begins
(considering
both
the
seasonal
nature
of
the
construction
activity
and
the
existence
of
other
projects
competing
for
construction
labor
at the
same
time,
the
place
of
the
environmental
permit
in
the
sequence
of corporate
and
overall
governmental
approval),
and
the
nature
of
the
project
sponsor
(e.g.,
private, public,
regulated).
“Commence
operation”,
for
purposes
of
Subparts
C,
D
and
B,
means:
To
have
begun
any
mechanical,
chemical,
or electronic
process,
including,
for
the
purpose of a
unit,
start-up of
a
unit’s
combustion
chamber,
except
as
provided
in
40
CFR
96.105,
96.205,
or
96.305, as
incorporated
by
reference
in
Section
225.140.
For
a unit
that
undergoes
a
physical
change
(other
than
replacement
of
the
unit
by
a
unit
at
the
same
source) after
the
date
the
unit
commences
operation
as
set
forth
in
the
first
paragraph
of this
definition,
such
date
will
remain
the
date
of
commencement
of
operation
of
the
unit,
which
will
continue
to
be
treated
as
the
same
unit.
8
For
a
unit
that
is
replaced
by
a
unit
at
the
same
source
(e.g.,
repowered),
after
the
date
the
unit
commences
operation
as
set
forth
in
the
first
paragraph
of
this
definition,
such
date
will
remain
the
replaced
unit’s
date
of
commencement
of
operation,
and
the
replacement
unit
will
be
treated
as a
separate
unit
with
a
separate
date
for
commencement
of
operation
as
set
forth
in
this
definition
as
appropriate.
“Common
stack”
means
a
single
flue
through
which
emissions
from
two
or
more
units
are
exhausted.
“Compliance
account”
means:
For
the
purposes
of
Subparts
D
and
E,
a CAR
NO
Allowance
Tracking
System
account,
established
by
USEPA
for
a CAR
NO
source
or CAR
NO
Ozone
Season source
pursuant
to 40
CFR
96,
subparts
FF
and
FFFF
in
which
any
CAR
NO
allowance
or
CAR
NO
Ozone
Season
allowance
allocations
for
the
CAR
NO
units
or
CAR
NO
Ozone
Season
units
at the
source
are
initially
recorded
and
in
which
are
held
any
CAR
NO
or
CAR
NO
Ozone
Season
allowances
available
for
use
for
a control
period
in
order
to
meet
the
source’s
CAR
NO
or
CAR
NO
Ozone
Season
emissions
limitations
in
accordance
with
Sections
225.410 and
225.510,
and
40
CFR
96.154
and
96.354,
as
incorporated
by
reference
in
Section
225.140.
CAR
NO
allowances
may
not
be
used for
compliance
with
the
CAR
NO
Ozone
Season
Trading
Program
and
CAIR
NO
Ozone
Season
allowances
may
not
be
used
for
compliance
with
the
CAR
NO
Annual Trading
Program; or
For
the
purposes
of
Subpart
C, a
“compliance
account”
means a
CAR
SO
2
compliance
account,
established
by
the
USEPA
for
a
CAR
SO
2
source
pursuant
to
40
CFR
96,
subpart
FFF,
in
which
any
SO
2
units
at
the
source
are
initially
recorded
and
in
which
are
held
any
SO
2
allowances
available
for
use
for
a
control
period in order
to
meet
the
source’s
CAR
SO
2
emissions
limitations
in
accordance
with
Section
225.3
10
and
40
CFR
96.254,
as
incorporated
by
reference in
Section
225.140.
“Control period”
means:
For
the
CAR
SO
2
and
NO
Annual
Trading
Programs
in Subparts
C
and
D,
the
period
beginning
January
1
of
a
calendar
year,
except
as
provided
in
Sections
225.3
10(d)(3)
and
225.4
10(d)(3),
and
ending
on
December31
of
the
same
year,
inclusive;
or
For
the
CAR
NO
Ozone
Season
Trading
Program
in
Subpart
E,
the
period
beginning
May
1
of a
calendar
year,
except
as
provided
in
Section
225.5
10(d)(3),
and
ending on
September
30
of the
same
year,
inclusive.
9
“Designated
representative”
means,
for
the
purposes
of
Subpart
B of
this
Part,
the
natural
person
as
defmed
in
40
CFR
60.4
102,
and
is
the
same
natural
person
as
the
person
who
is
the
designated
representative
for
the
CAR
trading
and
Acid
Rain
programs.
“Electric
generating
unit”
or
“EGU”
means
a
fossil
fuel-fired
stationary
boiler,
combustion
turbine
or
combined
cycle
system
that
serves
a
generator
that
has
a
nameplate
capacity
greater
than
25
MWe
and
produces
electricity
for
sale.
“Flue”
means
a
conduit
or
duct
through
which
gases
or
other
matter
is exhausted
to
the
atmosphere.
“Fossil
fuel”
means
natural
gas,
petroleum,
coal,
or
any
form
of solid,
liquid,
or
gaseous
fuel
derived
from
such
material.
“Fossil
fuel-fired”
means
the
combusting
of
any
amount
of
fossil
fuel,
alone
or
in
combination
with
any
other
fuel
in
any
calendar
year.
“Generator”
means
a
device
that
produces
electricity.
“Gross
electrical
output”
means
the
total
electrical
output
from
an
EGU
before
making
any
deductions
for
energy
output
used
in
any
way
related
to
the
production
of
energy.
For
an
EGU
generating
only
electricity,
the
gross
electrical output
is
the
output
from
the
turbine/generator
set.
“Heat
input” means,
for
the
purposes
of
Subparts
C,
D,
and
E,
a
specified
period
of time,
the
product
(in
mrnBtu!hr)
of
the
gross
calorific
value
of
the
fuel
(in
Btu/lb)
divided
by
1,000,000
Btu/mrnBtu
and
multiplied
by
the
fuel
feed
rate
into
a
combustion
device
(in
lb
of
fuelltime),
as
measured,
recorded
and
reported
to
USEPA
by
the
CAR
designated
representative
and
determined
by
USEPA
in
accordance
with
40
CFR
96,
subpart
HH,
HHH,
or
HHHH, if
applicable,
and
excluding
the
heat
derived
from
preheated
combustion
air,
recirculated
flue
gases,
or
exhaust
from
other
sources.
“Higher
heating
value”
or
“HHV”
means
the
total
heat
liberated
per
mass
of
fuel
burned
(BtuJlb),
when
fuel
and
dry
air
at
standard
conditions
undergo
complete
combustion
and
all
resultant
products are
brought
to
their
standard
states
at
standard
conditions.
“Input
mercury”
means
the
mass
of
mercury that
is
contained
in
the
coal
combusted
within
an
EGU.
“Integrated
gasification
combined
cycle”
or
“IGCC”
means
a
coal-fired
electric
utility
steam
generating
unit
that
bums
a
synthetic
gas
derived
from
coal
in a
combined-cycle
gas
turbine.
No
coal
is
directly
burned
in the
unit
during
operation.
“Long-term
cold
storage”
means
the
complete
shutdown
of
a
unit
intended
to
last
for
an
extended
period
of
time
(at
least
two
calendar
years)
where
notice
for
long-term
cold
10
storage
is
provided
under
40
CFR
75.6
1(a)(7).
“Nameplate
capacity”
means,
starting
from
the
initial installation
of
a
generator,
the
maximum
electrical
generating
output
(in
MWe)
that
the
generator
is
capable
of
producing
on
a
steady-state
basis
and
during
continuous
operation
(when
not
restricted
by
seasonal
or
other
deratings)
as
of such
installation
as
specified
by
the
manufacturer
of
the
generator
or,
starting
from
the
completion
of
any
subsequent
physical
change
in
the
generator
resulting
in
an
increase
in
the
maximum
electrical
generating
output
(in
MWe)
that
the
generator
is
capable
of
producing
on
a
steady-state
basis
and
during
continuous
operation
(when
not
restricted
by
seasonal
or
other
deratings),
such
increased
maximum
amount
as
of
completion
as
specified
by
the
person conducting
the
physical
change.
“MST traceable
elemental
mercury
standards”
means either:
(1)
Compressed
gas
cylinders having
known
concentrations
of
elemental
mercury,
which
have
been
prepared
according
to the
“EPA
Traceability
Protocol
for
Assay
and
Certification
of
Gaseous
Calibration
Standards”
or
(2)
Calibration
gases having
known
concentrations
of
elemental
mercury,
produced
by
a
generator
that
fully
meets
the
performance
requirements
of
the
“EPA
Traceability
Protocol
for
Qualification
and
Certification
of Elemental
Mercury
Gas
Generators.”
“NIST
traceable
source
of
oxidized
mercury”
means
a
generator
that
is
capable
of
providing
known
concentrations
of vapor
phase
mercuric
chloride
(HgCI
2
),
and
that
fully
meets
the
performance
requirements
of
the
“EPA Traceability
Protocol
for
Qualification
and
Certification
of
Oxidized
Mercury
Gas
Generators.”
“Oil-fired
unit” means
a
unit
combusting
fuel
oil
for
more
than
15.0
percent
of
the
annual
heat
input
in
a
specified year
and
not
qualifying
as
coal-fired.
“Output-based
emission
standard”
means,
for
the
purposes
of
Subpart
B
of this
Part,
a
maximum
allowable
rate
of
emissions
of
mercury
per
unit
of
gross
electrical
output
from
an
EGU.
“Potential
electrical
output
capacity”
means
33
percent
of
a
unit’s
maximum
design
heat
input,
expressed
in
mniBtu/hr
divided
by
3.4
13
mmBtu/MWh,
and
multiplied
by
8,760
hr/yr.
“Project sponsor”
means
a person
or
an
entity,
including
but
not
limited
to
the
owner
or
operator
of
an
EGU
or
a
not-for-profit
group,
that
provides
the
majority
of
funding
for
an
energy
efficiency
and
conservation,
renewable
energy,
or
clean
technology
project
as
listed
in
Sections
225.460
and
225.560,
unless
another
person
or entity
is designated
by
a
written
agreement
as
the
project
sponsor
for
the
purpose
of
applying
for
NO allowances
or
NO
Ozone
Season
allowances
from
the
CASA.
11
“Rated-energy
efficiency”
means
the
percentage
of
thermal
energy
input
that
is
recovered
as
useable
energy
in the
form
of gross
electrical
output,
useful
thermal
energy,
or
both
that
is
used
for
heating,
cooling,
industrial
processes,
or
other
beneficial
uses
as
follows:
For
electric
generators,
rated-energy
efficiency
is
calculated
as one
kilowatt
hour
(3,413
Btu)
of electricity
divided
by
the
unit’s
design
heat
rate
using
the
higher
heating
value
of the
fuel,
and
expressed
as
a
percentage.
For
combined
heat
and
power
projects,
rated-energy
efficiency
is
calculated
using
the
following
formula:
REE
=
((GO
+
UTE)fHI)
x
100
Where:
REE
=
Rated-energy
efficiency,
expressed
as percentage.
GO
Gross
electrical
output
of the
system
expressed
in BtuJhr.
UTE
=
Useful
thermal
output
from
the
system
that
is used
for
heating,
cooling,
industrial
processes
or other
beneficial
uses,
expressed
in
BtuThr.
HI
=
Heat
input,
based
upon
the
higher
heating
value
of
fuel,
in
Btu/hr.
“Repowered”
means,
for
the
purposes
of
an EGU,
replacement
of
a coal-fired
boiler
with
one
of
the following
coal-fired
technologies
at
the
same
source
as
the
coal-fired
boiler:
Atmospheric
or
pressurized
fluidized
bed
combustion;
Integrated gasification
combined
cycle;
Magnetohydroclynamics;
Direct
and
indirect
coal-fired
turbines;
Integrated gasification
fuel
cells;
or
As
determined
by
the
USEPA
in
consultation
with
the
United
States
Department
of Energy, a
derivative
of one
or
more
of
the
technologies
under
this
definition
and
any
other
coal-fired
technology
capable
of
controlling
multiple
combustion
emissions
simultaneously
with
improved
boiler
or
generation
efficiency
and
with
significantly
greater
waste
reduction
relative
to
the
performance
of
technology
in
widespread
commercial
use
as of
January
1, 2005.
“Rolling
12-month
basis”
means,
for the
purposes
of
Subparts
B
and
F
of
this
Part,
a
determination made
on
a
monthly
basis
from
the
relevant
data
for
a
particular
calendar
month
and
the
preceding
11
calendar
months
(total
of
12
months
of
data),
with
two
12
exceptions.
For
determinations
involving
one
EGU,
calendar
months
in
which
the
EGU
does
not
operate
(zero
EGU
operating
hours)
must
not
be
included
in
the
determination,
and
must
be
replaced
by
a preceding
month
or
months
in
which
the
EGU
does
operate,
so
that
the
determination
is
still
based
on
12
months
of
data.
For
determinations
involving
two
or
more
EGUs,
calendar
months
in
which
none
of
the
EGUs
covered
by
the
determination
operates
(zero
EGU
operating
hours)
must
not
be
included
in
the
determination,
and
must
be
replaced
by
preceding
months
in
which
at
least
one
of
the
EGUs
covered
by
the
determination
does
operate,
so that
the
determination
is still
based
on
12 months
of
data.
“Total
energy
output”
means,
with
respect
to a
cogeneration
unit,
the
sum
of
useful
power
and
useful
thermal
energy
produced
by
the
cogeneration
unit.
“Useful
thermal
energy”
means,
for
the
purpose
of
a
cogeneration
unit,
the
thermal
energy
that
is made
available
to
an
industrial
or
commercial
process,
excluding
any
heat
contained
in condensate
return
or makeup
water:
Used
in
a
heating
application
(e.g.,
space
heating
or
domestic
hot
water
heating);
or
Used
in
a space
cooling
application
(e.g.,
thermal
energy
used
by
an
absorption
chiller).
(Source:
Amended
at
effective
Section
225.140
Incorporations
by
Reference
The
following
materials
are
incorporated
by
reference.
These
incorporations
do not
include
any
later
amendments
or editions.
a)
Appendix
A,
Subpart
A, and
Performance
Specifications
2
and
3
of Appendix
B
of
40
CFR
60,
60.17,
60.45a,
60.49a(k)(1)
and
(p),
60.50a(h), and
60.4170
through
60.4176
(2005).
b)
40
CFR
72.2
(2005).
cb)
40
CFR
75.4,
75.11 through
75.14,
75.16
through
75.19,
75.30,
75.34
through
75.37,
75.40 through
75.48,
75.53(e),
75.57(c)(2)(i)
through
75.57(c)(2)(yj)
1
75.60
through
75.67.
75.71,
75.74(c),
Sections
2.1.1.5,
2.1.1.2,
7.7,
and
7.8
of
Appendix
A
to
40
CFR
75,
Appendix
C to
40
CFR
75,
Section
3.3.5
of
Appendix
F
to
40
CFR
75
(2006).40
CFR
75
(2006).
de)
40
CFR
78
(2006).
e4)
40
CFR
96,
CAIR
SO
2
Trading
Program,
subparts
AAA
(excluding
40
CFR
96.204
and
96.206),
BBB,
FFF,
GGG,
and
HHH
(2006).
13
fe)
40
CFR
96,
CAIR
NO
Annual
Trading
Program,
subparts
AA
(excluding
40
CFR
96.104,
96.105(b)(2),
and
96.106),
BB,
FF,
GG,
and
HH
(2006).
gf)
40
CFR
96,
CAIR
NO
Ozone
Season
Trading
Program,
subparts
AAAA
(excluding
40
CFR
96.304,
96.305(b)(2),
and
96.306), BBBB,
FFFF,
GGGG,
and
RHHH
(2006).
hg)
ASTM.
The
following
methods
from
the
American
Society
for
Testing
and
Materials,
100
Barr
Harbor
Drive,
P.O.
Box
C700,
West
Conshohocken
PA
19428-2959,
(610)
832-9585:
1)
ASTM D388-77
(approved
February
25,
1977), D388-90
(approved
March
30,
1990),
D388-91a
(approved
April
15,
1991),
D388-95
(approved
January
15,
1995),
D388-98a
(approved
September
10,
1998),
or
D388-99
(approved
September
10,
1999,
reapproved
in
2004),
Classification
of
Coals
by
Rank.
2)
ASTM
D3173-03,
Standard
Test
Method
for
Moisture
in
the
Analysis
Sample
of
Coal
and
Coke
(Approved
April
10,
2003).
3)
ASTM
D3684-01,
Standard
Test
Method
for
Total
Mercury
in
Coal
by
the
Oxygen
Bomb
Combustion/Atomic
Absorption
Method
(Approved
October
10,
2001).
4)
ASTM D4840-99,
Standard
Guide
for
Sampling
Chain-of-Custody
Procedures
(Reapproved
2004).
54)
ASTM
D5865-04,
Standard
Test
Method
for
Gross
Calorific
Value
of
Coal
and
Coke
(Approved
April
1, 2004).
6)
ASTM D6414-01,
Standard
Test
Method
for
Total
Mercury
in
Coal
and
Coal
Combustion
Residues
by
Acid
Extraction
or
Wet
Oxidation/Cold
Vapor
Atomic
Absorption
(Approved
October
10,
2001).
7)
ASTM
D6784-02,
Standard
Test
Method
for
Elemental,
Oxidized,
Particle-Bound
and
Total
Mercury
in Flue
Gas
Generated
from
Coal-Fired
Stationary
Sources
(Ontario
Hydro
Method)
(Approved
April
10,
2002).
8)
ASTM
D691
1-03,
Standard
Guide
for
Packaging
and
Shipping
Environmental
Samples
for
Laboratory
Analysis.
9)
ASTM
D7036-04,
Standard
Practice
for
Competence
of
Air
Emission
Testing
Bodies.
14
ih)
Federal
Energy
Management
Program,
M&V
Guidelines:
Measurement
and
Verification
for
Federal
Energy
Projects,
US
Department
of
Energy,
Office
of
Energy
Efficiency
and
Renewable
Energy,
Version
2.2,
DOE/GO-102000-0960
(September
2000).
(Source:
Amended
at
effective
Section
225.150
Commence
Commercial
Operation
Commence
commercial
operation
means,
for
the
purposes
of
Subparts
C,
D
and
E,
with
regard
to
a
unit:
a)
To
have
begun
to
produce
steam,
gas,
or
other
heated
medium
used
to
generate
electricity
for
sale or
use, including
test
generation,
except
as
provided
in
40
CFR
96.105,
96.205,
or
96.305,
as
incorporated
by
reference
in
Section.
225.140.
1)
For
a
unit
that
is a
CAR
SO
2
unit,
CAR
NO
unit,
or
a
CAR
NO
Ozone
Season
unit
pursuant
to
Sections
225.305,
225.405,
and
225.505,
respectively,
on
the
date
the
unit
commences
commercial
operation
on
the
later
of
November
15,
1990
or
the
date
the
unit
commences
commercial
operation
as
defined
in
subsection
(a)
of
this
Section
and
that
subsequently
undergoes
a
physical
change
(other
than
replacement
of
the
unit
by
a
unit
at
the
same
source),
such date
will
remain
the
unit’s
date
of
commencement
of
commercial
operation,
which
will
continue
to
be
treated
as
the
same
unit.
2)
For
a
unit
that
is
a
CAR
SO
2
unit,
CAIR
NO
unit,
or
a
CAR
NO
Ozone
Season
unit
pursuant
to
Sections
225.305,
225
.405,
and
225.505,
respectively,
on
the
later
of
November
15
1990
or
the
date
the
unit
commences
commercial
operation
as
defined
in
subsection
(a)
of
this Section
and
that
is
subsequently
replaced
by
a
unit
at
the
same
source
(e.g.,
repowered),
such
date
will
remain
the
replaced
unit’s
date
of
commencement
of
commercial
operation,
and
the replacement
unit
will
be
treated
as
a
separate
unit
with
a
separate
date for
commencement
of
commercial
operation
as
defined
in
subsection
(a)
or
(b)
of
this
Section
as
appropriate.
b)
Notwithstanding
subsection
(a)
of
this
Section
and
except
as
provided
in
40
CFR 96.105,
96.205,
or
96.305
for a
unit
that
is
not
aCAIR
SO
2
unit,
CAR
NO
unit,
or
a
CAR
NO
Ozone
Season
unit
pursuant
to
Section
225.305,
225.405,
or
225.505,
respectively,
on
the
later
of
November
15,
1990
or
the date
the
unit
commences
commercial
operation
as
defined
in
subsection
(a)
of
this
Section,
the
unit’s
date
for
commencement
of
15
commercial
operation
will
be the
date
on
which
the
unit
becomes
a
CAR
SO
2
unit,
CAR
NO
unit,
or CAR
NO
Ozone
Season
unit
pursuant
to
Section
225.305,
225.405,
or
225.505,
respectively.
1)
For
a
unit
with
a
date
for
commencement
of commercial
operation
as defined
in
subsection
(b)
of
this
Section
and
that
subsequently
undergoes
a
physical
change
(other
than
replacement
of
the
unit
by
a
unit
at
the
same
source),
such
date
will
remain
the
unit’s
date
of
commencement
of
commercial
operation,
which
shall
continue
to
be
treated
as
the
same
unit.
.2)
For
a
unit
with
a
date
for
commencement
of
commercial
operation
as defined
in
subsection
(b)
of
this
Section
and
that
is
subsequently
replaced
by
a
unit
at
the
same
source
(e.g.,
repowered),
such
date
will
remain
the
replaced
unit’s
date
of
commencement
of
commercial
operation,
and
the
replacement
unit
will
be
treated
as
a
separate
unit
with
a
separate
date
for
commencement
of
commercial
operation
as
defined
in subsection
(a)
or
(b)
of
this
Section
as
appropriate.
(Source:
Added
at
31111.
Reg.
12864,
effective
August
31,
2007)
SUBPART
B:
CONTROL
OF
MERCURY
EMISSIONS
FROM
COAL-FIRED
ELECTRIC
GENERATING
UNITS
Section
225.200
Purpose
The
purpose of
this
Subpart
B is
to
control
the
emissions
of
mercury
from
coal-fired
EGU
operating
in
Illinois.
Section
225.202
Measurement
Methods
Measurement
of
mercury
must
be
according
to
the
following:
a)
Continuous
emission
monitoring
pursuant
to
Appendix
B
to
this
Part
or
an
alternative
emissions
monitoring
system,
alternative
reference
method
for
measuring emissions,
or
other
alternative
to
the
emissions
monitoring
and
measurement
requirements
of Sections
225.240
through
225
.290,
if
such
alternative
is
submitted
to
the
Agency
in
writing
and
approved
in
writing
by
the
Manager
of
the
Bureau
of
Air’s
Compliance
Section.
40
CFR
75 (2005).
16
b)
ASTM
D3173-03,
Standard
Test
Method
for
Moisture
in the
Analysis
Sample
of
Coal
and
Coke
(Approved
April
10,
2003),
incorporated
by
reference
in
Section
225.140.
c)
ASTM
D3684-0l,
Standard
Test
Method
for
Total
Mercury
in
Coal
by
the
Oxygen
Bomb
Combustion/Atomic
Absorption
Method
(Approved
October
10,
2001),
incorporated
by
reference
in
Section
225.140.
d)
ASTM
D5865-04,
Standard
Test
Method
for
Gross Calorific
Value
of
Coal
and
Coke
(Approved
April 1, 2004),
incorporated
by
reference
in
Section
225.140.
e)
ASTM
D6414-01,
Standard
Test
Method
for
Total
Mercury
in
Coal
and
Coal
Combustion
Residues
by
Acid
Extraction
or
Wet
Oxidation/Cold
Vapor
Atomic
Absorption
(Approved
October
10,
2001),
incorporated
by
reference
in
Section
225.140.
f)
ASTM
D6784-02,
Standard
Test
Method
for
Elemental,
Oxidized,
Partible-Bound
and
Total
Mercury
in
Flue
Gas
Generated
from
Coal-Fired
Stationary
Sources
(Ontario
Hydro
Method)
(Approved
April
10,
2002),
incorporated
by
reference
in
Section 225.140.
g)
Emissions
testing
pursuant
to
Appendix
A
of
40
CFR
60.
(Source:
Amended
at
effective
Section
225.205
Applicability
The
following
stationary
coal-fired
boilers
and
stationary
coal-fired
combustion
turbines
are
EGUs
and
are
subject
to this
Subpart
B:
a)
Except
as provided
in
subsection
(b)
of
this
Section,
a unit
serving,
at
any
time
since
the
start-up
of
the
unit’s
combustion
chamber,
a generator
with
nameplate
capacity
of
more
than
25
MWe
producing
electricity
for
sale.
b)
For
a unit
that
qualifies
as
a
cogeneration
unit
during
the
12-month
period
starting
on
the
date
the
unit
first
produces
electricity
and
continues
to
qualify
as
a
co generation
unit,
a
co
generation
unit
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.
If
a
unit
qualifies
as
a
cogeneration
unit
during
the
12-month
period
starting
on
the
date
the
unit
first
produces
electricity
but
subsequently
no
longer
qualifies
as
a
cogeneration
unit,
the
unit
must
be
subject
to
subsection
(a)
of
this
Section
starting
on
the
day
on
which the
unit
first
no
longer
qualifies
as
a cogeneration
unit.
17
Section
225.210
Compliance
Requirements
a)
Permit
Requirements.
The
owner
or
operator
of
each
source
with
one
or
more
EGUs
subject
to this
Subpart
B at
the
source
must
apply
for
a
CAAPP
permit
that
addresses
the
applicable
requirements
of
this
Subpart
B.
b)
Monitoring
and
Testing
Requirements.
1)
The
owner
or
operator
of
each
source
and
each
EGU
at
the
source
must
comply
with
either
the monitoring
requirements
of Sections
225.240
through
225.290
of
this
Subpart
B, the
periodic
emissions
testing
requirements
of
Section
225.239
of this
Subpart
B. or
an alternative
emissions
monitoring
system,
alternative
reference
method
for
measuring
emissions,
or
other
alternative
to
the
emissions
monitoring
and
measurement
requirements
of Sections
225.240
through
225.290,
if
such
alternative
is submitted
to the
Agency
in
writing
and
approved
in
writing
by
the Manager
of
the
Bureau
of
Air’s
Compliance
Section.
2)
The
compliance
of
each
EGU
with
the
mercury
requirements
of
Sections
225.230
and
225.237
of
this
Subpart
B
must
be
determined
by the
emissions
measurements
recorded
and
reported
in
accordance
with
either
Sections
225.240
through
225.290
of this
Subpart
B, Section
225.239
of
this
Subpart
B,
or
an
alternative
emissions
monitoring
system,
alternative
reference
method
for
measuring
emissions,
or
other
alternative
to
the
emissions
monitoring
and
measurement
requirements
of
Sections
225.240
through
225.290,
if
such
alternative
is submitted
to the
Agency
in
writing
and
approved
in
writing
by the
Manager
of the
Bureau
of
Air’s
Compliance
Section.
c)
Mercury
Emission
Reduction
Requirements
-
The
owner
or operator
of
any
EGU
subject
to
this
Subpart
B
must
comply
with
applicable
requirements
for
control
ofmercury
emissions
of
Section
225.230
or
Section
225
.237
of
this
Subpart
B.
d)
Recordkeeping
and
Reporting
Requirements
Unless
otherwise
provided,
the
owner
or
operator
of
a
source
with
one
or
more
EGUs
at the
source
must
keep
on
site
at
the
source
each
of the
documents
listed
in
subsections
(d)(1)
through
(d)(3)
of
this
Section
for
a
period
of
five
years
from
the
date
the
document
is
created.
This
period
may
be
extended,
in
writing
by
the
Agency,
for
cause,
at
any
time
prior
to
the
end
of
five
years.
18
1)
All
emissions
monitoring
information
gathered in
accordance
with
Sections
225
.240
through
225
.290
and
all
periodic
emissions
testing
information
gathered
in
accordance
with
Section
225.239.
2)
Copies
of
all
reports,
compliance
certifications,
and
other
submissions
and
all
records
made
or
required
or
documents
necessary
to demonstrate
compliance
with
the
requirements
of
this
Subpart
B.
3)
Copies
of
all
documents
used
to
complete a permit
application
and
any
other
submission
under
this
Subpart B.
e)
Liability.
1)
The
owner
or
operator
of
each
source
with
one
or
more
EGUs
must
meet
the
requirements
of
this
Subpart
B.
2)
Any
provision
of
this
Subpart
B
that
applies
to
a source
must
also
apply
to
the
owner
and
operator
of such
source
and
to
the
owner
or operator
of
each
EGU
at the
source.
3)
Any
provision
of
this
Subpart
B that
applies
to an
EGU
must
also
apply
to
the
owner
or
operator
of such
EGU.
f)
Effect
on
Other Authorities.
No
provision of
this
Subpart
B
maybe
construed
as
exempting
or
excluding
the
owner
or
operator
of
a source
or
EGU
from
compliance
with
any
other
provision
of
an
approved
State
Implementation
Plan,
a
permit,
the
Act,
or
the
CAA.
(Source: Amended
at
effective
)
Section 225
.220
Clean
Air
Act
Permit
Program
(CAAPP)
Permit
Requirements
a)
Application
Requirements.
1)
Each
source
with
one
or
more
EGUs
subject
to
the
requirements
of
this
Subpart
B
is
required
to
submit
a
CAAPP
permit
application
that
addresses
all
applicable
requirements
of
this
Subpart
B,
applicable
to
each
EGU
at
the
source.
2)
For
any
EGU
that
commenced
commercial
operation:
A)
on
or
before
December
31,
2008,
the
owner
or operator
of
such
EGUs must
submit
an
initial
permit
application
or
application
for
CAAPP permit
modification
that
meets
the
requirements
of
this
Section
on
or
before
December
31,
2008.
19
B)
after
December
31,
2008,
the
owner
or
operator
of
any
such
EGU
must
submit
an
initial
CAAPP
permit
application
or
application
for
CAAPP
modification
that
meets
the
requirements
of
this
Section
not
later
than
180
days
before
initial
startup
of
the
EGU,
unless
the
construction
permit
issued
for the
EGU addresses
the
requirements
of
this Subpart
B.
b)
Contents
of
Permit
Applications.
In
addition
to
other
information
required
for
a
complete
application
for
CAAPP
permit
or
CAAPP
permit
modification,
the
application
must
include
the
following
information:
1)
The
ORIS (Office
of
Regulatory
Information
Systems)
or
facility
code
assigned
to
the
source
by
the
U.S. Department
of
Energy,
Energy
Information
Administration,
if
applicable.
2)
Identification
of
each
EGU
at
the
source.
3)
The intended
approach
to
the
monitoring
requirements
of
Sections
225.240
through
225.290
of
this
Subpart
B,
or,
in
the
alternative,
the
applicant
may
include
its
intended
approach
to
the
testing
requirement
of
Section
225
.239
of
this
Subpart
B.
4)
The
intended
approach
to
the
mercury
emission
reduction
requirements
of
Section
225
.230
or
225.237
of
this
Subpart
B,
as
applicable.
c)
Permit
Contents.
1)
Each
CAAPP
permit issued
by
the
Agency
for
a
source
with
one
or
more
EGUs subject
to
the
requirements
of
this
Subpart
B
must contain
federally
enforceable
conditions
addressing
all
applicable
requirements
of
this
Subpart
B,
which
conditions
must
be
a
complete and
segregable
portion
of
the
source’s
entire
CAAPP
permit.
2)
In
addition
to
conditions
related
to
the
applicable
requirements
of
this
Subpart
B,
each such
CAAPP
permit
must
also
contain
the
information
specified
under
subsection
(b)
of
this
Section.
(Source:
Amended
at
effective
Section
225.230
Emission
Standards
for
EGUs
at
Existing
Sources
a)
Emission
Standards.
20
1)
Except
as
provided
in
Sections
225.230(b)
and
(d).
225.232
through
225.234,
225.239,
and
225.291
through
225.299 of
this
Subpart
B,
beginning
Beginning
July
1,
2009,
the
owner
or
operator
of
a
source
with
one
or
more
EGUs
subject
to
this
Subpart
B
that
commenced
commercial
operation
on
or
before
December
31,
2008, must
comply
with
one
of
the
following
standards
for
each
EGU
on
a
rolling
12-month
basis:
A)
An
emission
standard
of
0.0080
lb
mercury/GWh
gross
electrical
output;
or
B)
A
minimum
90-percent
reduction
of
input
mercury.
2)
For
an
EGU complying
with subsection
(a)(1)(A)
of
this
Section,
the
actual
mercury
emission
rate
of
the
EGU for
each 12-month
rolling
period,
as
monitored
in
accordance
with
this
Subpart
B
and
calculated
as
follows,
must
not
exceed
the
applicable
emission
standard:
ERE
1
÷O
Where:
ER
=
Actual
mercury
emissions
rate
of
the
EGU for
the
particular
12-
month rolling
period,
expressed
in
lb/GWh.
E
=
Actual
mercury
emissions
of
the
EGU,
in
ibs,
in
an
individual
month
in
the
12-month
rolling
period,
as
determined
in
accordance
with
the
emissions
monitoring
provisions
of
this
Subpart
B.
=
Gross electrical output
of
the
EGU,
in
GWh,
in
an
individual
month
in
the
12-month
rolling
period,
as
determined
in
accordance
with Section
225
.263
of
this
Subpart
B.
3)
For
an
EGU complying
with
subsection
(a)(1)(B)
of
this
Section,
the
actual
control
efficiency
for
mercury
emissions
achieved
by
the
EGU
for
each
12-month
rolling
period,
as
monitored
in
accordance
with
this
Subpart
B
and
calculated
as
follows,
must
meet
or
exceed
the
applicable
efficiency
requirement:
CE=100x{1—(E
1
÷J)}
Where:
CE
Actual
control
efficiency
for
mercury
emissions
of the
EGU
for
the
particular
12-month
rolling
period,
expressed
as
a percent.
21
E
1
=
Actual
mercury
emissions
of
the
EGU,
in
lbs,
in
an
individual
month
in
the
12-month
rolling
period,
as
determined
in
accordance
with
the
emissions
monitoring
provisions
of
this
Subpart
B.
=
Amount
of
mercury
in
the
fuel
fired in
the
EGU, in
lbs,
in
an
individual
month
in
the
12-month
rolling
period,
as
determined
in
accordance
with
Section
225.265
of
this Subpart
B.
b)
Alternative
Emission
Standards
for
Single
EGUs.
1)
As
an
alternative
to
compliance
with
the
emission
standards
in
subsection
(a)
of
this
Section,
the
owner
or
operator
of
the
EGU may
comply
with
the
emission
standards
of
this
Subpart
B
by
demonstrating
that
the
actual
emissions
of
mercury
from
the
EGU are
less
than
the
allowable
emissions
of
mercury
from
the
EGU
on
a
rolling
12-month
basis.
2)
For
the purpose
of
demonstrating
compliance
with
the
alternative
emission
standards
of
this
subsection
(b), for
each
rolling
12-month
period,
the
actual
emissions
of
mercury
from
the
EGU,
as
monitored
in
accordance
with
this
Subpart
B,
must
not
exceed
the
allowable
emissions
of
mercury
from
the
EGU,
as
further
provided
by
the
following
formulas:
E
12
A
12
E
12
=E
1
A
12
=A
1
Where:
=
Actual
mercury
emissions
of
the
EGU
for
the
particular
12-month
rolling
period.
A
12
=
Allowable
mercury
emissions
of
the
EGU
for
the
particular
12-
month
rolling
period.
E
1
=
Actual
mercury
emissions
of
the
EGU
in
an
individual
month
in
the
12-month
rolling
period.
A
=
Allowable
mercury
emissions
of
the
EGU in
an
individual
month
in
the 12-month
rolling
period,
based
on
either
the
input
mercury
to
the
unit
(Aj’)
or
the electrical
output
from the
EGU
),
as
selected
by
the
owner
or
operator
of
the
EGU for
that
given
month.
=
Allowable
mercury
emissions
of
the
EGU
in
an
individual
month
based
on
the
input
mercury
to
the
EGU, calculated
as
10.0
percent
(or
0.100)
of
the
input
mercury
to
the
EGU.
=
Allowable
mercury
emissions
of
the
EGU
in
a
particular
month
based on
the
electrical
output
from
the
EGU, calculated
as
the
product
of
22
the
output
based
mercury
limit,
i.e.,
0.0080
lb/GWh,
and
the
electrical
output
from
the
EGU,
in
GWh.
3)
If
the
owner
or
operator
of
an
EGU
does
not
conduct
the
necessary
sampling,
analysis,
and
recordkeeping,
in
accordance
with
Section
225.265
of
this
Subpart
B,
to
determine
the
mercury
input
to
the
EGU,
the
allowable
emissions
of
the
EGU
must
be
calculated
based
on
the
electrical
output
of
the
EGU.
c)
If
two
or
more
EGUs are
served
by
common
stack(s) and
the
owner
or
operator
conducts
monitoring
for
mercury
emissions
in
the
common
stack(s),
as
provided
for
by
Sections
1.14
through
1.18
of
Appendix
B
to
this
Part,
40
CFR
75,
Subpart
Isuch
that
the
mercury
emissions
of
each
EGU are
not
determined
separately,
compliance
of
the
EGUs with
the
applicable
emission
standards
of
this
Subpart
B
must be
determined
as
if
the
EGUs
were
a
single
EGU.
d)
Alternative
Emission
Standards
for
Multiple
EGUs.
1)
As
an
alternative
to
compliance
with
the
emission
standards
of
subsection
(a)
of
this
Section,
the
owner
or
operator
of
a
source
with
multiple
EGUs
may
comply
with
the
emission
standards
of
this
Subpart
B
by
demonstrating
that
the
actual
emissions
of
mercury
from
all
EGUs
at the
source
are
less
than
the
allowable
emissions
of
mercury
from
all
EGUs
at
the
source
on
a
rolling
12-month
basis.
2)
For
the
purposes
of
the
alternative
emission
standard
of
subsection
(d)(
1)
of
this
Section,
for
each
rolling
12-month
period,
the
actual
emissions
of
mercury
from
all
the
EGUs
at
the
source,
as
monitored
in
accordance
with
this
Subpart
B,
must
not
exceed
the
sum
of
the
allowable
emissions
of
mercury
from
all
the
EGUs
at
the
source,
as
further
provided
by
the
following
formulas:
E
A
A=A
1
Where:
E
5
=
Sum
of
the
actual
mercury
emissions
of
the
EGUs
at
the
source.
A
=
Sum of
the
allowable
mercury
emissions
of
the
EGUs
at
the
source.
23
=
Actual
mercury
emissions
of
an
individual
EGU
at
the
source,
as
determined
in
accordance
with
subsection
(b)(2)
of
this
Section.
A
Allowable
mercury
emissions
of
an
individual
EGU
at
the
source,
as
determined
in accordance
with
subsection
(b)(2)
of
this
Section.
n
Number
of
EGUs
covered
by
the
demonstration.
3)
If
an
owner
or
operator
of
a
source
with
two
or
more
EGUs
that
is relying
on
this
subsection
(d)
to
demonstrate
compliance
fails
to meet
the
requirements
of
this
subsection
(d)
in
a
given
12-month
rolling
period,
all
EGUs at
such
source
covered
by
the
compliance
demonstration
are
considered
out
of
compliance
with
the
applicable
emission standards
of
this
Subpart
B
for
the
entire
last
month
of
that
period.
(Source:
Amended
at
effective
Section
225
.232
Averaging
Demonstrations
for
Existing
Sources
a)
Through
December
31,
2013,
as
an
alternative
to
compliance
with
the
emission
standards
of
Section
225.230(a)
of
this
Subpart
B,
the
owner
or
operator
of
an
EGU
may
comply
with the
emission
standards
of this
Subpart
B
by
means
of
an
Averaging
Demonstration
(Demonstration)
that
demonstrates
that
the
actual
emissions
of mercury
from
the
EGU
and
other
EGUs
at
the
source
and
other
EGUs
at other
sources
covered
by
the
Demonstration
are
less
than
the
allowable
emissions
of
mercury
from
all
EGUs
covered
by
the
Demonstration
on
a
rolling
12-month
basis.
b)
The
EGUs
at
each
source
covered
by
a
Demonstration
must
also
comply
with
one
of
the
following
emission
standards
on
a source-wide
basis
for
the
period
covered
by
the
Demonstration:
1)
An
emission
standard
of
0.020
lb
mercury/GWh
gross
electrical
output;
or
2)
A
minimum
75
percent
reduction
of
input
mercury.
c)
For
the
purpose
of
this
Section,
compliance
must
be
demonstrated
using
the
equations
in
Section 225
.230(a)(2),
(a)(3),
or
(d)(2),
as
applicable,
addressing
all
EGUs at
the
sources
covered
by
the
Demonstration,
rather
than
by
using
only
the
EGUs
at
one
source.
d)
Limitations
on
Demonstrations.
1)
The
owners
or
operators
of
more
than
one
existing
source
with
EGUs
can
only
participate
in
Demonstrations
that
include
other
existing
sources
that
they
own
or
operate.
2)
Single
Existing
Source
Demonstrations
24
A)
The
owner
or
operator
of
only
a
single
existing source
with
EGUs
(i.e.,
City,
Water,
Light
&
Power,
City
of Springfield,
ID
167
12OAAO;
Kincaid
Generating
Station,
1D
0218
14AAB;
and
Southern
Illinois
Power
Cooperative/Marion
Generating
Station,
ID
1
99856AAC)
can
only
participate
in
Demonstrations
with
other
such
owners
or
operators
of
a single existing
source
of
EGUs.
B)
Participation
in
Demonstrations
under
this
Section
by
the
owner
or
operator
of
only a
single
existing
source with
EGUs
must
be
authorized
through
federally
enforceable
permit
conditions
for
each
such
source
participating
in
the
Demonstration.
e)
A
source
may
be
included
in only
one
Demonstration
during
each
rolling
12-
month
period.
1)
The
owner
or
operator
of
EGUs
using
Demonstrations
to
show
compliance
with
this
Subpart
B
must
complete
the
detennination
of
compliance
for
each
12-month
rolling
period
no
later
than
60
days
following
the
end
of
the
period.
g)
If
averaging
is
used
to
demonstrate
compliance
with
this
Subpart
B,
the
effect
of
a
failure
to
demonstrate
compliance
will
be
that
the
compliance
status
of
each
source
must
be
determined
under
Section
225.230 of
this
Subpart
B as
if
the
sources
were
not
covered
by
a
Demonstration.
h)
For
purposes
of this
Section,
if the
owner
or
operator
of
any
source that
participates
in
a
Demonstration
with
an
owner
or
operator
of a
source
that
does
not
maintain
the
required
records,
data,
and
reports
for
the
EGUs
at
the
source,
or
that
does
not
submit
copies
of
such
records,
data,
or
reports to
the
Agency
upon
request,
then
the
effect
of
this
failure
will
be
deemed
to
be
a failure
to
demonstrate
compliance
and
the
compliance
status
of
each
source
must
be
determined
under
Section
225.230
of
this
Subpart
B
as
if
the
sources
were
not
covered
by
a
Demonstration.
Section
225.233
Multi-Pollutant
Standards
(MPS)
a)
General.
1)
As
an
alternative
to
compliance
with
the
emissions
standards
of
Section
225.230(a),
the
owner
of
eligible
EGUs
may
elect
for
those
EGUs
to
demonstrate
compliance
pursuant
to
this
Section,
which
establishes
control
requirements
and
standards
for
emissions
of
NO
and
SO
2
,
as
well
as
for
emissions
of
mercury.
2)
For
the
purpose
of
this
Section,
the
following
requirements
apply:
25
A)
An
eligible
EGU
is an
EGU
that
is
located
in
Illinois
and
which
commenced
commercial
operation
on
or
before
December
31,
2004;
and
B)
Ownership
of
an
eligible
EGU
is
determined
based
on
direct
ownership,
by
the
holding
of
a
majority
interest
in
a
company
that
owns
the
EGU
or
EGUs,
or
by
the
common
ownership
of
the
company
that
owns
the
EGU, whether
through
a
parent-subsidiary
relationship,
as
a sister
corporation,
or
as
an
affiliated
corporation
with
the
same
parent
corporation,
provided
that
the
owner
has
the
right
or
authority
to submit
a
CAAPP
application
on
behalf
of
the
EGU.
3)
The
owner
of
one
or more
EGUs
electing
to
demonstrate
compliance
with
this
Subpart
B
pursuant
to
this
Section
must
submit
an
application
for
a
CAAPP
permit
modification
to
the
Agency,
as
provided
in
Section
225.220,
that
includes
the
information
specified
in
subsection
(b)
of
this
Section
and
which
clearly
states
the
owner’s
election
to
demonstrate
compliance
pursuant
to
this
Section
225.233.
A)
If
the
owner
of
one
or
more
EGUs
elects
to demonstrate
compliance
with
this
Subpart
pursuant
to
this
Section,
then
all
EGUs
it
owns in
Illinois
as
of July
1,
2006,
as
defined
in
sub
section
(a)(2)(B)
of
this
Section,
must
be
thereafter
subject
to
the
standards
and
control
requirements
of
this
Section,
except
as
provided
in
subsection
(a)(3)(B).
Such
EGUs
must be
referred
to
as
a
Multi-Pollutant
Standard (MPS)
Group.
B)
Notwithstanding
the
foregoing,
the
owner
may
exclude
from
an
MPS
Group
any
EGU
scheduled
for
permanent
shutdown
that
the
owner so
designates
in
its
CAAPP
application
required
to
be
submitted
pursuant
to
subsection
(a)(3)
of
this
Section,
with
compliance
for
such
units
to
be
achieved
by
means
of
Section
225.235.
4)
When
an
EGU
is
subject
to the
requirements
of this
Section,
the
requirements
apply
to
all
owners
or
operators
of
the
EGU,
and
to
the
designated
representative
for
the
EGU.
b)
Notice of
Intent.
The
owner
of
one
or
more
EGUs
that
intends
to
comply
with
this
Subpart
B
by
means
of
this
Section must
notify
the
Agency
of
its
intention
by
December
31,
2007.
The
following
information
must
accompany
the
notification:
26
1)
The
identification
of
each
EGU
that
will
be
complying
with
this
Subpart
B
by
means
of
the
multi-pollutant
standards
contained
in
this
Section,
with
evidence
that
the
owner
has
identified
all
EGUs that
it
owned
in
Illinois
as
of
July
1,
2006
and
which
commenced
commercial
operation
on
or
before
December
31,
2004;
2)
If
an
EGU
identified
in subsection
(b)(l)
of
this
Section
is
also
owned
or
operated
by
a
person
different
than the
owner
submitting
the
notice
of
intent,
a
demonstration
that
the
submitter
has
the
right
to
commit
the
EGU
or
authorization
from
the
responsible
official
for
the
EGU
accepting
the
application;
3)
The
Base
Emission
Rates
for
the
EGUs,
with
copies
of
supporting
data
and
calculations;
4)
A
summary
of
the
current
control
devices
installed
and
operating
on
each
EGU
and
identification
of
the
additional
control
devices
that
will
likely
b
needed
for
the
each
EGU
to
càmply
with
emission
control
requirements
of
this
Section,
including
identification
of
each
EGU
in the
MPS
group
that
will
be
addressed
by
subsection
(c)(1)(B)
of
this
Section,
with
information
showing
that
the
eligibility
criteria
for
this
subsection
(b)
are
satisfied;
and
5)
Identification
of
each
EGU
that
is
scheduled
for
permanent
shut
down,
as
provided
by
Section
225.23
5,
which
will
not
be
part
of
the
MPS
Group
and
which will
not
be
demonstrating
compliance
with
this
Subpart
B
pursuant
to
this
Section.
c)
Control
Technology
Requirements
for
Emissions
of
Mercury.
1)
Requirements
for
EGUs in
an
MPS
Group.
A)
For
each
EGU
in
an
MPS
Group
other
than
an
EGU
that
is
addressed
by
subsection
(c)(1)(B)
of
this
Section
for
the
period
beginning
July
1,
2009
(or
December
31,
2009
for
an
EGU
for
which
an
SO
2
scrubber
or
fabric
filter
is
being
installed
to
be
in
operation
by
December
31,
2009),
and
ending
on
December
31,
2014
(or
such
earlier
date
that
the
EGU
is
subject
to
the
mercury
emission
standard
in
subsection
(d)(1)
of
this
Section),
the
owner
or
operator
of
the
EGU
must
install,
to
the
extent
not
already
installed,
and
properly
operate
and
maintain
one
of
the
following
emission
control
devices:
i)
A
Halogenated
Activated
Carbon
Injection
System,
complying
with
the
sorbent
injection
requirements
of
subsection
(c)(2)
of
this
Section,
except
as
may
be
otherwise
provided
by
subsection
(c)(4)
of
this
Section,
and
27
followed
by
a Cold-Side
Electrostatic
Precipitator
or
Fabric
Filter;
or
ii)
If the
boiler
fires
bituminous
coal,
a
Selective
Catalytic
Reduction
(SCR)
System
and
an
SO
2
Scrubber.
B)
An
owner
of
an
EGU
in
an
MPS Group
has
two
options
under
this
subsection
(c).
For
an
MPS
Group that
contains
EGUs
smaller
than
90
gross
MW
in
capacity,
the
owner
may
designate
any
such
EGUs
to be
not
subject
to
subsection
(c)(l)(A)
of
this
Section.
Or,
for
an
MPS
Group
that
contains
EGUs
with
gross
MW
capacity
of
less
than
115
MW, the
owner
may
designate
any
such
EGUs
to
be
not
subject
to
subsection
(c)(1
)(A)
of
this
Section,
provided
that
the
aggregate
gross
MW
capacity
of
the
designated
EGUs
does
not
exceed
4%
of
the
total
gross
MW capacity
of the
MPS
Group.
For
any
EGU
subject
to one
of
these
two
options,
unless the
EGU
is
subject
to
the
emission
standards
in
subsection
(d)(2)
of
this
Section,
beginning
on
January
1,
2013,
and
continuing
until
such
date
that
the
owner
or
operator
of
the
EGU
commits
to
comply
with
the
mercury
emission
standard
in
subsection
(d)(2)
of this
Section,
the
owner
or
operator
of
the
EGU
must
install
and
properly
operate
and
maintain
a Halogenated
Activated
Carbon
Injection
System
that
complies
with
the
sorbent
injection
requirements
of
subsection
(c)(2)
of
this
Section,
except
as
may
be
otherwise
provided
by
subsection
(c)(4)of
this
Section,
and
followed
by
either,
a
Cold-Side
Electrostatic
Precipitator
or Fabric
Filter.
The
use
of
a properly
installed,
operated,
and
maintained
Halogenated
Activated
Carbon
Injection
System
that
meets
the
sorbent
injection
requirements
of
subsection
(c)(2)
of
this
Section
is
defined
as
the
“principal
control
technique.”
2)
For
each
EGU
for
which
injection
of
halogenated
activated
carbon
is
required by
subsection
(c)(1)
of
this
Section,
the
owner
or
operator
of
the
EGU
must
inject
halogenated
activated
carbon
in
an
optimum
manner,
which, except
as
provided
in
subsection
(c)(4)
of this
Section,
is
defined
as
all
of
the
following:
A)
The
use
of
an
injection
system
designed
for
effective
absorption
of
mercury,
considering
the
configuration
of
the
EGU
and
its
ductwork;
B)
The
injection
of
halogenated
activated
carbon
manufactured
by
Aistom,
Norit,
or
Sorbent
Technologies,
or
Calgon
Carbon’s
FLUEPAC
MC
Plus,
or
the
injection
of
any
other
halogenated
activated
carbon
or
sorbent that
the
owner
or
operator
of the
EGU
28
has
demonstrated
to
have
similar
or
better effectiveness
for
control
of
mercury
emissions;
and
C)
The
injection
of
sorbent
at
the
following
minimum
rates,
as
applicable:
i)
For
an
EGU
firing
subbituminous
coal,
5.0
lbs
per
million
actual
cubic
feet
or,
for
any
cyclone-fired
EGU
that
will
install
a scrubber
and
baghouse
by
December
31,
2012,
and
which
already
meets
an
emission
rate
of
0.020
lb
mercury/GWh
gross
electrical
output
or
at
least
75
percent
reduction
of input
mercury,
2.5
lbs
per
million
actual
cubic
feet;
ii)
For
an
EGU
firing
bituminous
coal,
10.0
lbs
per
million
actual
cubic
feet
or
for
any
cyclone-fired
EGU
that
will
install
a scrubber
and
baghouse
by
December
31,
2012,
and
which
already
meets
an
emission
rate
of
0.020
lb
mercury/GWh
gross
electrical
output
or
at
least
75
percent
reduction
of
input
mercury,
5.0
lbs
per
million
actual
cubic
feet;
iii)
For
an
EGU
firing
a
blend
of
subbituminous
and
bituminous
coal,
a
rate
that
is
the
weighted
average
of
the
above
rates,
based
on
the
blend
of coal
being
fired;
or
iv)
A rate
or
rates
set
lower
by
the
Agency,
in
writing,
than
the
rate
specified
in
any
of
subsections
(c)(2)(C)(i),
(c)(2)(C)(ii),
or
(c)(2)(C)(iii)
of
this
Section
on
a unit-
specific
basis,
provided
that
the
owner
or
operator
of
the
EGU
has
demonstrated
that
such
rate
or
rates
are
needed
so
that
carbon
injection
will
not
increase
particulate
matter
emissions
or
opacity
so as
to
threaten
noncompliance
with
applicable
requirements
for
particulate
matter
or
opacity.
D)
For
the
purposes
of
subsection
(c)(2)(C)
of
this
Section,
the
flue
gas
flow
rate
must
be
determined
for
the
point
of
sorbent
injection;
provided
that
this
flow
rate
may
be
assumed
to
be
identical
to
the
stack
flow
rate
if
the
gas
temperatures
at
the
point
of
injection
and
the
stack
are
normally
within
1000
F,
or
the
flue
gas
flow
rate
may
otherwise
be
calculated
from
the
stack
flow
rate,
corrected
for
the
difference
in
gas
temperatures.
3)
The
owner
or
operator
of
an
EGU
that
seeks
to operate
an
EGU
with
an
activated
carbon
injection rate
or
rates
that
are
set
on
a
unit-specific
basis
pursuant
to
subsection
(c)(2)(C)(iv)
of
this
Section
must
submit
an
29
application
to
the
Agency
proposing
such
rate
or
rates,
and
must
meet
the
requirements
of
subsections
(c)(3)(A)
and
(c)(3)(B)
of
this
Section,
subject
to
the
limitations
of
subsections
(c)(3)(C)
and
(c)(3)(D)
of this
Section:
A)
The
application
must
be
submitted
as
an
application
for
a new
or
revised
federally
enforceable
operating
permit
for
the
EGU,
and
it
must
include
a
summary
of
relevant
mercury
emission
data
for
the
EGU,
the
unit-specific
injection
rate
or
rates
that
are
proposed,
and
detailed
infonnation
to
support
the
proposed
injection
rate
or
rates;
and
B)
This
application
must
be
submitted
no
later
than
the
date
that
activated
carbon
must
first
be
injected.
For
example,
the
owner
or
operator
of
an
EGU
that
must
inject activated
carbon
pursuant
to
subsection
(c)(l)(A)
of
this
subsection
must
apply
for
unit-specific
injection
rate
or
rates
by
July
1,
2009. Thereafter,
the
owner
or
operator
of
the
EGU
may
supplement
its
application;
and
C)
Any
decision
of
the
Agency
denying
a
permit
or
granting
a
permit
with
conditions
that
set
a
lower
injection
rate
or
rates
may
be
appealed
to
the
Board
pursuant
to
Section
39
of
the
Act;
and
D)
The
owner
or
operator
of
an
EGU
may
operate
at the
injection
rate
or
rates
proposed
in its
application
until
a
final
decision
is
made
on
the
application,
including
a final decision
on
any
appeal
to
the
Board.
4)
During
any
evaluation
of the
effectiveness
of
a
listed
sorbent,
an
alternative
sorbent,
or
other
technique
to
control
mercury
emissions,
the
owner or
operator
of
an
EGU need
not
comply
with
the
requirements
of
subsection
(c)(2)
of
this
Section
for
any
system
needed
to
carry
out
the
evaluation,
as
further
provided
as
follows:
A)
The
owner
or
operator
of
the
EGU
must
conduct
the
evaluation
in
accordance
with
a formal
evaluation
program
submitted
to the
Agency
at
least
30
days
prior
to
commencement
of
the
evaluation;
B)
The
duration
and
scope
of
the
evaluation
may
not
exceed
the
duration
and
scope
reasonably
needed
to
complete
the
desired
evaluation
of
the
alternative
control
technique,
as
initially
addressed
by
the
owner
or
operator
in
a
support
document
submitted
with
the
evaluation
program;
C)
The
owner
or
operator
of
the
EGU
must
submit
a
report
to
the
Agency
no
later
than
30
days
after
the
conclusion
of
the
evaluation
that
describes
the
evaluation
conducted
and
which
provides
the
results
of
the
evaluation;
and
30
D)
If
the
evaluation
of
the
alternative
control technique
shows
less
effective
control
of
mercury
emissions
from
the
EGU
than
was
achieved
with
the
principal
control technique,
the
owner
or
operator
of
the
EGU
must
resume use
of
the
principal
control
technique.
If
the
evaluation
of
the
alternative
control
technique
shows
comparable
effectiveness
to
the
principal
control
technique,
the
owner
or
operator
of
the
EGU
may either
continue
to
use
the
alternative
control
technique
in
a
manner
that
is
at
least
as
effective
as
the
principal
control
technique,
or
it
may
resume
use
of
the
principal
control
technique.
If the
evaluation
of
the
alternative
control
technique
shows
more effective
control
of
mercury
emissions
than
the
control
technique,
the
owner
or
operator
of
the
EGU
must
continue
to
use
the
alternative
control
technique
in
a
manner
that
is more
effective
than
the
principal
control
technique,
so
long
as
it
continues
to
be
subject to
this
subsection
(c).
5)
In
addition
to
complying
with
the
applicable
recordkeeping
and
monitoring
requirements
in
Sections
225
.240
through
225.290jhe
owner
or
operator
of
an
EGU
that
elects
to
comply
with
this
Subpart
B
by
means
of
this Section
must
also
comply
with
the
following
additional
requirements:
A)
For
the
first
36
months
that
injection
of
sorbent
is
required,
it must
maintain
records
of
the
usage
of
sorb
ent,
the
exhaust
gas
flow
rate
from
the
EGU,
and
the
sorbent
feed
rate,
in
pounds
per
million
actual
cubic
feet
of
exhaust
gas
at
the
injection
point,
on
a weekly
average;
B)
After
the
first
36
months
that
injection
of
sorbent
is
required,
it
must
monitor
activated
sorbent
feed rate
to
the
EGU,
flue
gas
temperature
at
the
point
of
sorbent
injection,
and
exhaust
gas
flow
rate
from
the
EGU, automatically
recording
this
data
and
the
sorbent
carbon
feed
rate,
in
pounds
per
million
actual
cubic
feet
of
exhaust
gas
at
the
injection
point,
on
an
hourly
average;
and
C)
If
a
blend
of
bituminous
and
subbituminous
coal
is
fired
in
the
EGU, it
must
keep
records
of
the
amount
of
each
type
of
coal
burned
and
the
required
injection
rate
for
injection
of
activated
carbon,
on
a
weekly
basis.
6)
As
an
alternative
to
the
CEMS
monitoring,
recordkeeping,
and
reporting
requirements
in
Sections
225.240
through
225
.290,
the
owner
or
operator
of
an
EGU
may
elect
to
comply
with the
emissions
testing,
monitoring,
recordkeeping,
and
reporting
requirements
in
Section
225.239(c),
(d),
(e),
(f)(1)
and
(2),
(h)(2),
(i)(3)
and
(4),
and
(fl(l).
31
76)
In addition
to
complying
with
the
applicable
reporting
requirements
in
Sections
225.240
through
225.290,
the
owner
or
operator
of
an EGU
that
elects
to
comply
with
this
Subpart
B by
means
of
this
Section
must
also
submit
quarterly
reports
for
the
recordkeeping
and
monitoring
conducted
pursuant
to
subsection
(c)(5)
of
this
Section.
d)
Emission
Standards
for
Mercury.
1)
For
each
EGU
in
an MPS
Group
that
is
not
addressed
by
subsection
(c)(1)(B)
of
this
Section,
beginning
January
1,
2015
(or
such
earlier
date
when
the
owner
or operator
of
the
EGU
notifies
the
Agency
that
it will
comply
with
these
standards)
and
continuing
thereafter,
the
owner
or
operator
of
the
EGU
must
comply
with
one
of
the
following
standards
on
a
rolling
1
2-month
basis:
A)
An
emission
standard
of
0.0080
lb
mercury/GWh
gross
electrical
output;
or
B)
A
minimum
90-percent
reduction
of
input
mercury.
2)
For
each
EGU
in an
MPS
Group
that
has
been
addressed
under
subsection
(c)(1)(B)
of
this
Section, beginning
on
the
date
when
the
owner
or
operator
of
the
EGU
notifies
the
Agency
that
it will
comply
with
these
standards
and
continuing
thereafter,
the
owner
or
operator
of
the
EGU
must
comply
with
one
of
the
following
standards
on
a
rolling
12-month
basis:
A)
An
emission
standard
of
0.0080
lb
mercury/GWh
gross
electrical
output;
or
B)
A
minimum
90-percent
reduction
of
input
mercury.
3)
Compliance
with
the
mercury
emission
standard
or
reduction
requirement
of
this
subsection
(d)
must
be
calculated
in
accordance
with
Section
225
.230(a) or
(d).
4)
Until
June
30,
2012, as
an
alternative
to
demonstrating
compliance
with
the
emissions
standards
in this
subsection
(d),
the
owner
or
operator
of
an
EGU
may
elect
to
comply
with
the
emissions
testing
requirements
in
Section
225.239(c),
(d),
(e),
(fl(1)
and
(2),
(h)(2),
(i)(3)
and
(4).
and
j)(1)
of
this
Subpart.
e)
Emission Standards
for
NO
and
SO
2
.
1)
NO
Emission
Standards.
32
A)
Beginning
in
calendar
year
2012
and
continuing
in
each
calendar
thereafter,
for
the
EGUs
in
each
MPS Group, the
owner
and
operator
of
the
EGUs
must
comply with
an
overall
NOx
annual
emission
rate
of
no
more
than
0.11
lb/million
Btu
or
an
emission
rate
equivalent
to
52
percent
of
the
Base
Annual
Rate
of
NO
emissions,
whichever
is
more
stringent.
B)
Beginning
in
the
2012
ozone
season
and
continuing
in
each
ozone
season
thereafter,
for
the
EGUs
in
each
MPS
Group,
the
owner
and
operator
of
the
EGUs
must
comply
with
an
overall
NO
seasonal
emission
rate
of
no
more
than
0.11 lb/million
Btu
or
an
emission
rate
equivalent
to
80
percent
of
the
Base
Seasonal
Rate
of
NO
emissions,
whichever
is
more
stringent.
2)
SO
2
Emission
Standards.
A)
Beginning
in
calendar
year
2013
and
continuing
in
calendar
year
2014,
for
the
EGUs
in
each
MPS
Group,
the
owner
and
operator
of
the
EGUs
must
comply
with
an
overall
SO
2
annual
emission
rate
of
0.33
lbs/million
Btu
or
a rate
equivalent
to
44
percent
of
the
Base
Rate
of
SO
2
emissions,
whichever
is
more
stringent.
B)
Beginning
in
calendar
year
2015
and
continuing
in
each
calendar
year thereafter,
for
the
EGUs
in
each
MPS
Grouping,
the
owner
and
operator
of
the
EGUs
must
comply
with
an
overall
annual
emission
rate
for
SO
2
of
0.25
lbs/million
Btu
or
a rate
equivalent
to
35
percent
of
the
Base
Rate
of
SO
2
emissions,
whichever
is
more
stringent.
3)
Compliance
with
the
NO
and
SO
2
emission
standards
must
be
demonstrated
in
accordance
with
Sections
225.310,
225.410,
and
225.510.
The
owner
or
operator
of
EGUs must
complete
the
demonstration
of
compliance
before
March
1
of
the
following
year
for
annual
standards
and
before
November
1
for
seasonal
standards,
by
which
date
a compliance
report
must
be
submitted
to
the
Agency.
0
Requirements
for
NO
and
SO
2
Allowances.
1)
The
owner
or
operator
of
EGUs
in
an
MPS
Group
must
not
sell
or
trade
to
any
person
or
otherwise
exchange
with
or
give
to,
any
person
NO
allowances
allocated
to
the
EGUs
in
the
MPS
Group
for
vintage
years
2012
and
beyond
that
would
otherwise
be
available
for
sale,
trade,
or
exchange
as
a
result
of
actions
taken
to
comply
with
the
standards
in
subsection
(e)
of
this
Section.
Such
allowances
that
are
not
retired
for
compliance
must
be
surrendered
to
the
Agency
on
an
annual
basis,
33
beginning
in
calendar
year
2013.
This
provision
does
not
apply
to
the
use,
sale,
exchange,
gift,
or
trade
of
allowances among
the
EGUs
in
an
MPS
Group.
2)
The
owners
or
operators
of
EGUs
in
an MPS
Group
must
not
sell
or
trade
to
any
person
or
otherwise
exchange
with
or
give
to
any
person
SO
2
allowances
allocated
to
the
EGUs
in
the
MPS
Group
for
vintage
years
2013
and
beyond
that
would
otherwise
be
available
for
sale
or
trade
as a
result
of actions
taken
to
comply
with
the
standards
in
subsection
(e)
of
this
Section.
Such
allowances
that
are
not
retired
for
compliance,
or
otherwise
surrendered
pursuant
to
a consent
decree
to
which
the
State
of
Illinois
is
a
party,
must
be
surrendered
to
the
Agency
on
an
annual
basis,
beginning
in
calendar
year
2014.
This
provision
does
not
apply
to
the
use,
sale,
exchange,
gift,
or
trade
of allowances
among
the
EGUs
in
an
MPS
Group.
3)
The
provisions
of
this
subsection
(f) do
not
restrict
or
inhibit
the
sale
or
trading
of allowances
that
become
available
from
one
or
more
EGUs
in
a
MPS
Group
as a
result
of
holding
allowances
that
represent
over-
compliance
with
the
NO
or
SO
2
standard
in subsection
(e)
of
this
Section,
once
such
a
standard
becomes
effective,
whether
such
over-compliance
results
from
control
equipment,
fuel
changes,
changes
in the
method
of
operation,
unit
shut
downs,
or other
reasons.
4)
For
purposes
of this
subsection
(f),
NO
and
SO
2
allowances
mean
allowances
necessary
for compliance
with
Subpart
W
of
Section
217
(NO
Trading
Program
for Electrical
Generating
Units)Section
225.310,
225.410,
or
225.510,40
CFR
72,
or
subparts
Subparts
A
through
IA-and
AAAA
of 40
CFR
96,
or
any
future
federal
NQ
or
SO
2
emissions
trading
programs
that
include
Illinois
sources.
This
Section
does
not prohibit
the
owner
or
operator
of
EGUs
in
an
MPS
Group
from
purchasing
or
otherwise
obtaining
allowances
fromother
sources
as
allowed
by
law
for
purposes
of
complying
with
federal
or
state
requirements,
except
as
specifically
set
forth
in
this
Section.
5)
Before
March
1,
2010,
and
continuing
each
year
thereafter,
the
owner
or
operator
of
EGUs
in
an MPS
Group
must
submit
a
report
to the
Agency
that
demonstrates
compliance
with
the
requirements
of
this
subsection
(f)
for
the
previous calendar
year,
and
which
includes
identification
of
any
allowances
that
have
been
surrendered
to
the
USEPA
or
to
the Agency
and
any
allowances
that
were
sold,
gifted,
used,
exchanged,
or
traded
because
they
became
available
due
to
over-compliance.
All
allowances
that
are
required
to
be
surrendered
must
be
surrendered
by August
31,
unless
USEPA
has
not
yet
deducted
the
allowances
from
the previous
year.
A
final
report
must
be
submitted
to
the
Agency
by
August
31
of
each
year,
verifying
that
the
actions
described
in
the
initial
report
have
taken
place
34
or,
if
such
actions
have
not
taken
place, an
explanation
of
all
changes
that
have
occurred
and
the
reasons
for
such changes.
If
USEPA
has
not
deducted
the
allowances
from
the
previous
year by
August
31,
the
final
report
must
be
due,
and
all
allowances
required
to
be
surrendered
must
be
surrendered,
within
30
days
after
such deduction
occurs.
g)
Notwithstanding
35
Ill.
Adm.
Code
201.146(hhh),
until
an
EGU
has
complied with
the
applicable
emission
standards
of
subsections
(d)
and
(e)
of
this
Section
for
12
months,
the
owner
or
operator
of
the
EGU
must
obtain
a
construction
permit
for
any
new
or
modified
air
pollution
control
equipment
that
it
proposes
to
construct
for
control
of
emissions
of
mercury,
NON,
or
502.
(Source:
Amended
at
effective
Section
225.234
Temporary
Technology-Based
Standard
for
EGUs
at
Existing
Sources
a)
General.
1)
At
a
source
with
EGUs
that
commenced
commercial
operation
on
or
before
December
31,
2008, for
an
EGU that
meets
the
eligibility
criteria
in
subsection
(b)
of
this
Section,
the
owner
or
operator
of
the
EGU
may
temporarily
comply
with
the
requirements
of
this
Section
through
June
30,
2015,
as
an
alternative
to
compliance
with
the
mercury
emission
standards
in
Section
225.230,
as
provided
in
subsections
(c),
(d),
and
(e)
of
this
Section.
2)
An
EGU
that
is
complying
with
the
emission
control
requirements
of
this
Subpart
B
by
operating
pursuant
to
this
Section
may
not
be
included
in
a
compliance
demonstration
involving
other
EGUs
during
the
period
that
is
operating
pursuant
to
this
Section.
3)
The
owner
or
operator
of
an
EGU
that
is
complying
with
this
Subpart
B
by
means
of
the
temporary
alternative
emission
standards
of
this
Section
is
not
excused
from
any
of
the applicable
monitoring,
recordkeeping,
and
reporting
requirements
set
forth
in
Sections
225.240
through
225.290
4)
Until
June
30,
2012,
as
an
alternative
to
the
CEMS
monitoring,
recordkeeping,
and
reporting
requirements
in
Sections
225.240
through
225.290,
the
owner
or
operator
of
an
EGU
may
elect
to
comply
with
the
emissions
testing,
monitoring,
recordkeeping,
and
reporting
requirements
in
Section
225.239(c),
(d),
(e),
(f)(l)
and
(2),
(h)(2),
(i)(3)
and
(4),
and
(j)(1).
b)
Eligibility.
35
To
be
eligible
to
operate
an
EGU
pursuant
to
this
Section,
the
following
criteria
must
be met
for
the EGU:
1)
The
EGU
is
equipped
and
operated
with
the
air
pollution
control
equipment
or systems
that
include
injection of
halogenated
activated
carbon
and
either
a
cold-side
electrostatic
precipitator
or
a fabric
filter.
2)
The
owner
or
operator
of
the
EGU
is
injecting
halogenated
activated
carbon
in
an
optimum
manner
for
control
of
mercury
emissions,
which
must
include
injection
of Alstfom,
Norit,
Sorbent
Technologies,
Calg
Carbon’s
FLTJEPAC
MC
Plus,
or other
halogenated
activated
carbon
that
the
owner
or
operator
of the
EGU
has
demonstrated
to
have
similar
or
better
effectiveness
for
control
of
mercury emissions,
at
least
at
the
following
rates
set
forth
in
subsections
(b)(2)(A)
through
(b)(2)(D)
of this
Section,
unless
other
provisions
for
injection of halogenated
activated
carbon
are
established
in a
federally
enforceable
operating
permit
issued
for
the
EGU,
using
an
injection
system
designed
for
effective
absorption
of mercury,
considering
the
configuration
of
the
EGU
and
its
ductwork.
For
the purposes
of this
subsection
(b)(2),
the
flue
gas
flow
rate
must
be
determined
for
the
point
of sorbent
injection
(provided,
however,
that
this
flow
rate
may
be
assumed
to
be identical
to
the
stack
flow
rate
if the
gas
temperatures
at
the point
of
injection
and
the
stack
are
normally
within
1000
F)
or
may
otherwise
be
calculated
from
the
stack
flow
rate,
corrected
for
the
difference
in
gas
temperatures.
A)
For
an
EGU
firing
subbituminous
coal,
5.0
lbs
per
million
actual
cubic
feet.
B)
For
an
EGU
firing
bituminous
coal,
10.0
lbs
per
million
actual
cubic
feet.
C)
For
an
EGU
firing
a blend
of
subbituminous
and
bituminous
coal,
a
rate
that
is the
weighted
average
of
the
above
rates,
based
on
the
blend
of coal
being
fired.
D)
A
rate
or
rates
set
on
a
unit-specific
basis
that
are
lower
than
the
rate
specified
above
to
the extent
that
the
owner
or
operator
of
the
EGU
demonstrates
that
such
rate
or
rates
are
needed
so
that
carbon
injection
would
not
increase
particulate
matter
emissions
or
opacity
so
as to
threaten
compliance
with
applicable
regulatory
requirements
for
particulate
matter
or
opacity.
3)
The
total
capacity
of
the
EGUs
that
operate
pursuant
to
this
Section
does
not
exceed
the
applicable
of
the
following
values:
36
A)
For
the
owner
or
operator
of
more
than one
existing
source
with
EGUs,
25
percent
of
the
total
rated
capacity,
in MW,
of
all
the
EGUs
at
the
existing
sources
that
it
owns
or
operates,
other
than
any
EGUs
operating
pursuant
to
Section
225.23
5 of
this
Subpart
B.
B)
For
the
owner
or
operator
of
only
a
single
existing
source
with
EGUs
(i.e.,
City, Water,
Light
&
Power,
City
of
Springfield,
ID
167120AA0;
Kincaid
Generating
Station,
ID
0218
14AAB;
and
Southern
Illinois
Power
Cooperative/Marion
Generating
Station,
ID
199856AAC),
25
percent
of
the
total
rated
capacity,
in
MW,
of
the
all
the
EGUs
at
the
existing
sources,
other
than
any
EGUs
operating
pursuant
to
Section
225.23
5.
c)
Compliance
Requirements.
1)
Emission
Control
Requirements.
The
owner
or
operator
of
an
EGU
that
is
operating
pursuant
to
this
Section
must
continue
to
maintain
and
operate
the
EGU to
comply
with
the
criteria
for
eligibility
for
operation
pursuant
to
this
Section,
except
during
an
evaluation
of
the
current
sorbent,
alternative
sorbents
or
other
techniques
to
control
mercury
emissions,
as
provided
by subsection
(e)
of
this
Section.
2)
Monitoring
and
Recordkeeping
Requirements.
In
addition
to
complying
with
all
applicable
reporting
monitoring
and
recordkeeping
requirements
in
Sections
225
.240
through
225.290
or
Section
225.239(c),
(d),
(e),
(f)(1)
and
(2),
(h)(2),
and
i(3)
and
(4), the
owner
or
operator
of
an
EGU
operating
pursuant
to
this
Section
must
also:
A)
Through
December
31,
202,
it
must
maintain
records
of
the
usage
of
activated
carbon,
the
exhaust
gas
flow
rate
from the
EGU,
and
the
activated
carbon
feed
rate,
in
pounds
per
million
actual
cubic
feet
of
exhaust
gas
at
the
injection
point,
on
a
weekly
average.
B)
Beginning
January
1,
2013,
it
must
monitor
activated
carbon
feed
rate
to
the
EGU,
flue
gas temperature
at
the
point
of
sorbent
injection,
and
exhaust
gas
flow
rate
from
the
EGU,
automatically
recording
this
data
and
the
activated
carbon feed
rate,
in
pounds
per
million
actual
cubic feet
of
exhaust
gas
at
the
injection
point,
on
an
hourly
average.
C)
If
a
blend
of
bituminous
and
subbituminous
coal
is
fired
in
the
EGU,
it
must
maintain
records
of
the
amount
of
each
type
of
coal
37
burned
and
the
required
injection
rate
for
injection
of
halogenated
activated
carbon,
on
a weekly
basis.
3)
Notification
and
Reporting
Requirements.
In
addition
to
complying
with
all
applicable
reporting
requirements
in
Sections
225.240
through
225.290
or
Section
225.239(0(1),
(0(2),
and
(j)(1),
the
owner
or
operator
of
an
EGU operating
pursuant
to
this
Section
must
also
submit
the
following
notifications
and
reports
to
the
Agency:
A)
Written
notification
prior
to
the
month
in
which
any
of
the
following
events
will
occur:
i)
The
EGU
will
no
longer
be
eligible
to
operate
under
this
Section
due
to
a
change
in
operation;
ii)
The
type
of
coal
fired
in the EGU will
change;
the
mercury
emission
standard
with
which
the
owner
or
operator
is
attempting
to
comply
for
the
EGU
will
change;
or
iii)
Operation
under this
Section
will
be
terminated.
B)
Quarterly
reports.for
the
recordkeeping
and
monitoring
or
emissions
testing
conducted
pursuant
to
subsection
(c)(2)
of
this
Section.
C)
Annual
reports
detailing
activities
conducted
for
the
EGU
to
further improve
control
of
mercury
emissions,
including
the
measures
taken
during
the
past
year
and
activities
planned
for
the
current
year.
d)
Applications
to
Operate
under
the
Technology-Based
Standard
1)
Application
Deadlines.
A)
The
owner
or
operator
of
an
EGU that
is
seeking
to
operate
the
EGU
pursuant
to
this
Section
must
submit
an
application
to
the
Agency
no
later
than
three
months
prior
to
the
date
on
which
compliance
with
Section
225.230
of
this
Subpart
B
would
otherwise
have
to
be
demonstrated.
For
example,
the
owner
or
operator
of
an
EGU that
is
applying
to
operate
the
EGU
pursuant
to
this
Section
on
June
30,
2010,
when
compliance
with
applicable
mercury
emission
standards
must
be
first
demonstrated,
must
apply
by
March
31,
2010
to
operate
under
this
Section.
38
B)
Unless
the
Agency
finds
that
the
EGU
is
not
eligible
to operate
pursuant
to
this
Section
or
that
the
application
for
operation
pursuant
to
this
Section
does
not
meet
the
requirements
of
subsection
(d)(2)
of
this
Section,
the
owner or
operator
of
the
EGU
is
authorized
to
operate
the
EGU
pursuant
to
this
Section
beginning
60
days
after
receipt
of
the
application
by
the
Agency.
C)
The
owner
or
operator
of
an
EGU
operating pursuant
to this
Section
must
reapply
to
operate pursuant
to
this
Section:
i)
If
it
operated
the
EGU pursuant
to
this
Section
225.234
during
the
period
of
June
2010
through
December
2012
and
it
seeks
to
operate
the
EGU
pursuant
to
this
Section
225
.234
during
the
period from
January
2013
through
June
2015.
ii)
If
it
is
planning
a physical
change
to
or
a
change
in
the
method of
operation
of the
EGU,
control
equipment
or
practices
for
injection
of
activated
carbon
that
is
expected
to
reduce
the
level
of
control
of
mercury
emissions.
2)
Contents
of
Application.
An
application
to
operate
an
EGU
pursuant
to
this
Section
225.234
must
be
submitted
as an
application
for
a
new
or
revised
federally
enforceable
operating
permit
for
the
EGU,
and
it
must
include
the
following
documents
and
information:
A)
A
formal
request
to
operate
pursuant
to
this
Section
showing
that
the
EGU
is
eligible
to
operate
pursuant
to
this
Section
and
describing
the
reason
for
the
request,
the
measures
that
have
been
taken
for
control
of
mercury
emissions,
and
factors
preventing
more
effective
control
of
mercury
emissions
from
the
EGU.
B)
The
applicable
mercury emission
standard
in
Section
225.230(a)
with
which
the
owner
or
operator
of
the
EGU
is attempting
to
comply
and
a summary
of
relevant
mercury
emission
data
for
the
EGU.
C)
If
a
unit-specific
rate
or
rates
for
carbon
injection
are
proposed
pursuant
to
subsection
(b)(2) of
this
Section,
detailed
information
to
support
the
proposed
injection
rates.
D)
An
action
plan
describing
the
measures
that
will
be
taken
while
operating
under
this
Section to
improve
control
of
mercury
emissions.
This
plan
must
address
measures
such
as
evaluation
of
alternative
forms
or
sources
of
activated
carbon,
changes
to
the
injection
system,
changes
to
operation
of
the
unit
that
affect
the
39
effectiveness
of
mercury
absorption
and
collection,
changes
to
the
particulate
matter
control
device
to
improve
perfonnance,
and
changes
to
other
emission
control
devices.
For
each
measure
contained
in
the
plan,
the
plan must provide
a
detailed
description
of
the
specific
actions
that
are
planned,
the
reason
that
the
measure
is
being
pursued
and
the range
of
improvement
in
control
of
mercury
that
is
expected,
and
the
factors
that
affect
the
timing
for
carrying
out
the
measure,
together
with
the
current
schedule
for
the
measure.
e)
Evaluation
of
Alternative
Control
Techniques
for
Mercury
Emissions.
1)
During
an
evaluation
of
the effectiveness
of
the
current
sorbent,
alternative
sorb
ent,
or
other
technique
to
control
mercury
emissions,
the
owner
or
operator
of
an
EGU
operating
pursuant
to
this
Section
need
not
comply
with
the
eligibility
criteria
for
operation
pursuant
to
this
Section
as
needed
to
carry out
an
evaluation
of
the
practicality
and
effectiveness
of
such technique,
subject
to
the
following
limitations:
A)
The
owner
or
operator
of
the
EGU
must
conduct
the
evaluation
in
accordance
with
a
formal
evaluation
program
that
it
has
submitted
to
the
Agency
at
least
30
days
prior to
beginning
the
evaluation.
B)
The
duration
and scope
of
the
formal
evaluation
program
must
not
exceed
the
duration
and
scope
reasonably
needed
to
complete
the
desired
evaluation
of
the
alternative
control
technique,
as
initially
addressed
by
the
owner
or
owner
in
a
support
document
that
it
has
submitted
with
the
formal
evaluation
program
pursuant
to
subsection
(e)(
1
)(A) of
this
Section.
C)
Notwithstanding
35
Ill.
Adm.
Code
201.146(hlih),
the
owner
or
operator
of
th
EGU must obtain
a
construction
permit
for
any
new
or
modified
air
pollution
control
equipment
to
be
constructed
as
part
of
the
evaluation
of
the
alternative
control
technique.
D)
The
owner
or
operator
of
the
EGU
must
submit
a
report
to
the
Agency,
no
later
than
90
days afier
the
conclusion
of
the
formal
evaluation
program
describing
the
evaluation
that
was
conducted,
and
providing
the
results
of
the
formal
evaluation
program.
2)
If
the
evaluation
of
the
alternative
control
technique
shows
less
effective
control
of
mercury
emissions
from
the
EGU
than achieved
with
the
prior
control
technique,
the
owner
or
operator
of
the
EGU
must
resume
use
of
the
prior
control
technique.
If
the
evaluation
of
the
alternative
control
technique
shows comparable
control
effectiveness,
the
owner
or
operator
of
the
EGU
may
either continue
to
use
the
alternative
control
technique
in
40
an
optimum
manner
or
resume
use
of
the
prior
control
technique.
If
the
evaluation
of the
alternative
control
technique
shows more
effective
control of
mercury
emissions,
the
owner or
operator of
the
EGU
must
continue
to
use
the
alternative
control
technique
in
an
optimum
manner,
if
it
continues
to
operate
pursuant
to
this
Section.
(Source:
Amended
at
effective
Section
225
.235
Units
Scheduled
for
Pennanent
Shut
Down
a)
The
emission
standards
of
Section
225.230(a)
are
not
applicable
to
an
EGU
that
will
be
permanently
shut
down
as
described
in
this
Section:
1)
The
owner
or
operator
of
an
EGU
that
relies
on
this
Section
must
complete
the
following
actions
before
June
30,
2009:
A)
Have
notified
the
Agency
that
it is
planning
to permanently
shut
down
the
EGU
by
the
applicable
date
specified
in
subsection
(a)(3)
or
(4)
of
this
Section.
This
notification
must include
a
description
of
the
actions
that
have
already
been
taken
to
allow
the
shut
down
of
the
EGU
and
a
description
of
the
future
actions
that
must
be
accomplished
to
complete
the
shut
down
of
the
EGU,
with
the
anticipated
schedule
for
those
actions
and
the
anticipated
date
of
permanent
shut
down
of
the
unit.
B)
Have applied
for
a
construätion
permit
or
be
actively
pursuing
a
federally
enforceable
agreement
that
requires
the
EGU
to
be
permanently
shut
down
in
accordance
with
this
Section.
C)
Have
applied
for
revisions
to
the
operating
permits
for
the
EGU
to
include
provisions
that
terminate
the
authorization
to
operate
the
unit
in
accordance
with
this
Section.
2)
The
owner
or
operator
of
an
EGU
that
relies
on
this
Section
must,
before
June
30,
2010,
complete
the
following
actions:
A)
Have obtained
a
construction
permit
or
entered
into
a
federally
enforceable
agreement
as
described
in
subsection
(a)(l)(B)
of
this
Section;
or
B)
Have
obtained
revised
operating
permits
in
accordance
with
subsection
(a)(1)(C)
of
this
Section.
3)
The
plan
for
permanent
shut
down
of
the
EGU
must
provide
for
the
EGU
to be
permanently
shut
down
by
no
later
than
the
applicable
date
specified
below:
41
A)
If
the
owner
or
operator
of
the
EGU is
not
constructing
a
new
EGU
or
other
generating
unit
to
specifically
replace
the
existing
EGU,
by
December31,
2010.
B)
If
the
owner
or
operator
of
the
EGU
is
constructing
a
new
EGU
or
other
generating
unit
to
specifically
replace
the existing
EGU,
by
December
31,
2011.
4)
The
owner
or
operator
of
the
EGU must
permanently
shut
down
the
EGU
by
the
date
specified
in
subsection
(a)(3) of
this
Section,
unless
the
owner
or
operator
submits
a
demonstration
to
the
Agency
before
the
specified
date
showing
that
circumstances
beyond
its
reasonable
control
(such
as
protracted
delays
in construction
activity,
unanticipated
outage
of
another
EGU,
or
protracted
shakedown
of
a
replacement
unit)
have
occurred
that
interfere
with the
plan
for
permanent
shut down
of
the
EGU,
in
which
case
the
Agency
may
accept
the
demonstration
as
substantiated
and
extend
the
date
for
shut
down
of
the
EGU
as
follows:
A)
If
the
owner
or
operator
of
the
EGU
is
not
constructing
a new
EGU
or
other
generating
unit
to
specifically
replace
the
existing
EGU,
for
up
to
one
year,
i.e.,
permanent
shut
down
of
the
EGU
to
occur
by
no
later
than
December
31,
2011;
or
B)
If
the
owner
or
operator
of
the
EGU
is
constructing
a new
EGU
or
other
generating
unit
to
specifically
replace
the
existing
EGU,
for
up
to
18
months,
i.e.,
permanent
shutdown
of
the
EGU
to
occur
by
no
later than
June
30,
2013;
provided,
however,
that
after
December
31,
2012,
the
existing
EGU
must only
operate
as
a
back
up
unit
to
address
periods
when
the
new
generating
units
are
not
in
service.
b)
Notwithstanding
Sections
225
.230
and 225.232,
any
EGU
that
is
not
required
to
comply
with
Section
225.230
pursuant
to
this Section
must
not
be
included
when
determining
whether
any
other
EGUs
at
the
source
or
other
sources
are
in
compliance
with
Section
225.230.
c)
If
an
EGU,
for
which
the
owner
or
operator
of
the
source
has
relied
upon
this
Section
in
lieu
of
complying
with
Section
225
.230(a)
is
not
permanently
shut
down
as
required
by
this
Section,
the
EGU
must
be
considered
to
be
a
new
EGU
subject
to
the
emission
standards
in
Section
225.237(a)
beginning
in
the
month
after
the
EGU was required
to
be
permanently
shut
down,
in
addition
to
any
other
penalties
that may
be
imposed
for
failure
to
permanently
shut
down
the
EGU
in
accordance
with
this
Section.
42
d)
An
EGU
that
has
completed
the
requirements
of
subsection
(a)
of
this
Section
is
exempt
from
the
monitoring
and
testing
requirements
in
Sections
225
.239
and
225.240.
e)
An
EGU
that
is
scheduled
for
permanent
shut down
pursuant
to
Section
225.294(b)
is
exempt
from
the
monitoring
and
testing
requirements
in
Sections
225.239
and
225
.240.
(Source:
Amended
at
effective
Section
225.237
Emission
Standards
for
New
Sources
with
EGUs
a)
Standards.
1)
Except
as provided
in
Sections
225.238
and
225.239,
the
The
owner
or
operator
of
a
source
with
one
or
more EGUs,
but
that
previously
had
not
had
any
EGUs
that
commenced
commercial
operation
before
January
1,
2009,
must
comply
with
one
of
the
following
emission
standards
for
each
EGU
on
a
rolling
12-month
basis:
A)
An
emission
standard
of
0.0080
lb
mercury/GWh
gross
electrical
output;
or
B)
A
minimum
90
percent
reduction
of
input
mercury.
2)
For
this
purpose,
compliance
may
be
demonstrated
using
the
equations
in
Section 225.230(a)(2),
(a)(3),
or
(b)(2).
b)
The
initial 12-month
rolling
period
for
which
compliance
with
the
emission
standards
of
subsection
(a)(1)
of
this
Section
must
be
demonstrated
for
a
new
EGU
will commence
on
the
date
that
the
initial
performance
testing
commences
under
40
CFR
60.8.
for
the
mercury
emission
standard
under
40
CFR
60.45a
also
commences.
The
CEMS
required
by
this
Subpart
B for
mercury
emissions
from
the
EGU
must
be
certified
prior
to this
date.
Thereafter,
compliance
must
be
demonstrated
on
a
rolling
12-month
basis
based
on
calendar
months.
(Source:
Amended
at
effective
Section 225
.238 Temporary
Technology-Based
Standard
for
New
Sources
with
EGUs
a)
General.
1)
At
a source
with
EGUs
that
previously
had
not
had
any
EGUs
that
commenced
commercial
operation
before
January
1,
2009,
for
an
EGU
that
meets
the
eligibility
criteria
in
subsection
(b)
of
this
Section,
as
an
alternative
to
compliance
with
the
mercury
emission
standards
in
Section
43
225.237,
the
owner
or
operator
of
the
EGU
may temporarily
comply
with
the
requirements
of
this
Section,
through
December
31,
2018,
as
further
provided
in
subsections
(c),
(d),
and
(e)
of
this Section.
2)
An
EGU
that
is
complying
with
the
emission
control
requirements
of
this
Subpart
B
by
operating
pursuant
to
this
Section
may
not
be
included
in
a
compliance
demonstration
involving
other
EGUs
at
the
source
during
the
period
that
the
temporary
technology-based
standard
is
in
effect.
3)
The
owner
or
operator
of
an
EGU
that
is
complying
with
this
Subpart
B
pursuant
to
this
Section
is
not
excused
from
applicable
monitoring,
recordkeeping,
and
reporting
requirements
of
Sections
225
.240
through
225.290.
4)
Until
June
30,
2012,
as
an
alternative
to
the
CEMS
monitoring,
recordkeeping,
and
reporting
requirements
in
Sections
225.240
through
225.290,
the
owner
or
operator
of
an
EGU may
elect
to
comply
with
the
emissions
testing,
monitoring,
recordkeeping,
and
reporting
requirements
in
Section
225.239(c),
(d),
(e),
(f)(1)
and (2),
(h)(2),
(i)(3)
and
(4), and
(j)(1).
b)
Eligibility.
To
be
eligible
to
operate
an
EGU
pursuant
to
this
Section,
the
following
criteria
must
be
met
for
the
EGU:
1)
The
EGU
is
subject
to
Best
Available
Control
Technology
(BACT)
for
emissions
of
sulfur
dioxide,
nitrogen
oxides,
and
particulate
matter,
and
the
EGU
is
equipped
and
operated
with
the
air
pollution
control
equipment
or
systems
specified
below,
as
applicable
to
the
category
of
EGU:
A)
For coal-fired
boilers,
injection
of sorbent
or
other
mercury
control
technique
(e.g.,
reagent)
approved
by
the
Agency.
B)
For
an
EGU
firing
fuel
gas
produced
by
coal
gasification,
processing
of
the
raw
fuel
gas
prior
to
combustion
for
removal
of
mercury
with
a
system
using
a
sorbent
or
other
mercury
control
technique
approved
by
the
Agency.
2)
For
an
EGU
for
which
injection
of
a
sorbent
or
other
mercury
control
technique
is
required
pursuant
to
subsection
(b)(l)
of
this
Section,
the
owner
or
operator
of
the
EGU
is
injecting
sorbent
or
other
mercury
control
technique
in
an
optimum
manner
for
control
of
mercury
emissions,
which
must
include
injection
of
Alstrom,
Norit,
Sorbent
Technologies,
Calgon
Carbon’s
FLUEPAC
MC
Plus,
or
other
sorbent
or
other
mercury
control
technique
that the
owner
or
operator
of
the
EGU
demonstrates
to
have
similar
or
better
effectiveness
for
control
of
mercury
emissions,
at
least
at
the
rate
set
forth
in
the appropriate
of
subsections
(b)(2)(A)
through
44
(b)(2)(C)
of
this
Section,
unless
other provisions
for
injection
of
sorbent
or
other
mercury
control
technique
are
established
in
a
federally
enforceable
operating
permit
issued
for
the
EGU,
with
an
injection
system
designed
for
effective
absorption
of
mercury.
For the
purposes
of
this
subsection
(b)(2),
the
flue
gas
flow
rate
must
be
determined
for
the
point
of
sorbent
injection
or
other
mercury
control
technique
(provided,
however,
that
this
flow
rate
may
be
assumed
to
be
identical
to
the
stack flow
rate
if the
gas
temperatures
at
the
point of
injection
and
the
stack
are
normally
within
1000
F)
,
or
the
flow
rate
may
otherwise
be
calculated
from
the
stack
flow
rate,
corrected
for
the
difference
in
gas
temperatures.
A)
For
an
EGU
firing
subbituminous
coal,
5.0
pounds
per
million
actual
cubic
feet.
B)
For
an
EGU
firing
bituminous
coal,
10.0
pounds.
per
million
actual
cubic
feet.
C)
For
an
EGU
firing
a
blend
of
subbituminous
and
bituminous
coal,
a
rate
that
is
the
weighted
average
of
the
above
rates,
based
on
the
blend
of
coal
being
fired.
D)
A
rate
or
rates
set
on
a
unit-specific
basis that
are
lower
than
the
rate
specified
in
subsections
(b)(2)(A),
(B),
and
(C)
of
this
Section,
to
the
extent
that
the
owner
or
operator
of
the
EGU
demonstrates
that
such
rate
or
rates
are
needed
so
that
sorbent
injection
or
other
mercury
control
technique
would
not
increase
particulate
matter
emissions
or
opacity
so
as
to
threaten
compliance
with
applicable
regulatory
requirements
for
particulate
matter
or
opacity
or
cause
a
safety issue.
c)
Compliance
Requirements-.
1)
Emission
Control Requirements.
The
owner
or
operator
of
an
EGU
that
is
operating
pursuant
to
this
Section
must
continue
to
maintain
and
operate
the
EGU
to
comply
with
the
criteria
for
eligibility
for
operation under
this
Section,
except
during
an
evaluation
of
the
current
sorbent,
alternative
sorbents,
or
other
techniques
to
control
mercury
emissions,
as
provided
by
subsection
(e)
of
this
Section.
2)
Monitoring
and
Recordkeeping
Requirements.
In
addition
to
complying
with all
applicable
reporting
monitoring
and
recordkeeping
requirements
in
Sections
225.240
through
225.290
or
Section
225.239(c),
(d),
(e),
(0(1)
and
(2),
(h)(2),
and
i(3)
and
(4),
the
owner
or
operator
of
a
new
EGU
operating
pursuant
to
this
Section
must
also:
45
A)
Monitor
sorbent
feed
rate
to
the
EGU, flue
gas
temperature
at
the
point
of
sorb
ent
injection
or
other
mercury control
technique,
and
exhaust
gas
flow
rate
from
the
EGU,
automatically
recording
this
data
and
the
sorbent
feed
rate,
in
pounds
per
million
actual
cubic
feet
of
exhaust
gas
at
the
injection
point,
on
an
hourly
average.
B)
If a
blend
of
bituminous
and
subbituminous
coal
is
fired
in
the
EGU,
maintain
records
of
the
amount
of
each
type
of coal
burned
and
the
required
injection
rate
for
injection
of sorbent,
on
a
weekly
basis.
C)
If
a
mercury
control
technique
other
than
sorbent
injection
is
approved
by
the
Agency,
monitor
appropriate
parameter
for
that
control
technique
as
specified
by
the
Agency.
3)
Notification
and
Reporting
Requirements.
In
addition
to
complying
with
all
applicable
reporting
requirements
of
Sections
225.240
through
225.290
or
Section
225.239(f)(l)
and
(2)
and
(fl(l),
the
owner
or
operator
of
an
EGU
operating
pursuant
to
this
Section
must
also
submit
the
following
notifications
and
reports
to
the
Agency:
A)
Written
notification
prior
to
the
month
in
which
any
of
the
following
events
will
occur:
the
EGU
will
no
longer
be
eligible
to
operate
under
this
Section
due
to
a change
in operation;
the
type
of
coal
fired
in
the
EGU
will
change;
the
mercury
emission
standard
with
which
the
owner
or
operator
is
attempting
to
comply
for
the
EGU
will
change;
oroperation
under
this
Section
will
be
terminated.
B)
Quarterly
reports
for
the
recordkeeping
and
monitoring
or
emissions
testing
conducted
pursuant
to
subsection
(c)(2)
of this
Section.
C)
Annual
reports
detailing
activities
conducted
for
the
EGU
to
further
improve
control
of
mercury
emissions,
including
the
measures
taken
during
the
past
year
and
activities
planned
for
the
current
year.
d)
Applications
to Operate
under
the
Technology-Based
Standard.
1)
Application
Deadlines.
A)
The
owner or
operator
of
an
EGU
that
is
seeking
to operate
the
EGU pursuant
to-
this
Section
must
submit
an
application
to the
Agency
no
later
than
three
months
prior
to
the
date
that
46
compliance
with
Section
225.237
would otherwise
have
to
be
demonstrated.
B)
Unless
the
Agency
finds
that
the
EGU
is
not
eligible
to
operate
pursuant
to
this
Section
or
that
the
application
for
operation
under
this
Section
does
not
meet
the
requirements
of
subsection
(d)(2)
of
this
Section,
the
owner
or
operator
of
the
EGU
is
authorized
to
operate
the
EGU
pursuant
to
this
Section
beginning
60
days
after
receipt
of
the
application
by
the
Agency.
C)
The
owner
or
operator
of
an
EGU
operating
pursuant
to
this
Section
must
reapply
to
operate pursuant
to
this
Section
if
it
is
planning
a physical
change
to
or
a change
in the
method
of
operation
of
the
EGU,
control
equipment,
or
practices
for
injection
of
sorbent
or
other
mercury
control
technique
that
is
expected
to
reduce
the
level
of
control
of
mercury
emissions.
2)
Contents
of
Application.
An
application
to
operate
pursuant
to
this
Section
must
be
submitted
as
an
application
for
a
new
or
revised
federally
enforceable
operating permit
for
the
new
EGU, and
it must
include
the
following
information:
A)
A formal
request
to
operate
pursuant
to
this
Section
showing
that
the
EGU
is
eligible
to
operate
pursuant
to
this
Section
and
describing
the
reason
for
the
request,
the
measures
that
have
been
taken
for
control
of
mercury
emissions,
and
factors
preventing
more
effective
control
of
mercury
emissions
from
the
EGU.
B)
The
applicable
mercury
emission
standard
in
Section
225
.237
with
which
the
owner
or
operator
of
the
EGU
is
attempting
to
comply
and
a
summary
of
relevant
mercury
emission
data
for
the
EGU.
C)
If
a unit-specific
rate
or
rates
for
sorbent
or
other
mercury
control
technique
injection
are
proposed
pursuant
to
subsection
(b)(2)
of
this
Section,
detailed
information
to
support
the
proposed
injection
rates.
D)
An
action
plan
describing
the
measures
that
will
be
taken
while
operating
pursuant
to
this
Section
to
improve
control
of
mercury
emissions.
This
plan must
address
measures
such
as
evaluation
of
alternative
forms
or
sources
of
sorb
ent
or
other
mercury
control
technique,
changes
to
the
injection
system,
changes
to
operation
of
the
unit
that
affect
the
effectiveness
of
mercury
absorption
and
collection,
and
changes
to
other
emission
control
devices.
For
each measure
contained
in
the
plan,
the
plan
must
provide
a
detailed
description
of
the
specific
actions
that
are
planned,
the
47
reason
that
the
measure
is
being
pursued
and
the
range
of
improvement
in
control
of
mercury
that
is
expected,
and
the
factors
that
affect
the
timing
for
carrying
out
the
measure,
with
the
current
schedule
for
the
measure.
e)
Evaluation
of
Alternative
Control
Techniques
for
Mercury
Emissions.
1)
During
an
evaluation
of
the
effectiveness
of
the
current
sorb
ent,
alternative
sorbent,
or
other
technique
to
control
mercury
emissions,
the
owner
or
operator
of
an
EGU
operating
pursuant
to
this
Section
does
not
need
to
comply
with
the
eligibility
criteria
for
operation
pursuant
to
this
Section
as
needed
to
carry
out
an
evaluation
of
the
practicality
and
effectiveness
of
such
technique,
further subject
to
the
following
limitations:
A)
The
owner
or
operator
of
the
EGU
must
conduct
the
evaluation
in
accordance
with
a formal
evaluation
program
that
it
has
submitted
to
the
Agency
at
least
30
days
prior to
beginning
the
evaluation.
B)
The
duration
and
scope
of
the
formal evaluation
program
must
not
exceed
the
duration
and
scope reasonably
needed
to
complete
the
desired
evaluation
of
the
alternative
control
technique,
as
initially
addressed
by
the
owner
or
operator
in
a
support
document
that
it
has submitted
with
the
formal
evaluation
program
pursuant
to
subsection
(e)(l)(A)
of
this
Section.
C)
Notwithstanding
35
Iii.
Adm.
Code
201.146(hhh),
the
owner
or
operator
of
the
EGU
must
obtain
a
construction
permit
for
any
new
or
modified
air
pollution
control
equipment
to
be
constructed
as
part
of
the
evaluation
of
the
alternative
control
technique.
D)
The
owner
or
operator
of
the
EGU
must
submit
a
report
to
the
Agency
no
later than
90
days
after
the
conclusion
of
the
formal
evaluation
program
describing
the
evaluation
that
was
conducted
and
providing
the
results
of
the
formal
evaluation
program.
2)
If
the
evaluation
of
the
alternative
control technique
shows
less
effective
control
of
mercury
emissions
from the
EGU
than
was
achieved
with
the
prior
control
technique,
the
owner
or
operator
of
the
EGU
must
resume
use
of
the
prior
control
technique.
If
the
evaluation
of
the
alternative
control
technique
shows
comparable
effectiveness,
the
owner
or
operator
of
the
EGU
may
either
continue
to
use
the
alternative
control
technique
in
an
optimum
manner
or
resume
use
of
the
prior
control
technique.
If
the
evaluation
of
the
alternative
control
technique
shows
more
effective
control
of
mercury
emissions,
the
owner
or
operator
of
the
EGU
must
48
continue
to
use
the
alternative
control
technique
in
an
optimum
manner,
if
it
continues
to
operate
pursuant
to this
Section.
(Source: Amended
at
effective
Section
225.239
Periodic
Emissions
Testing
Alternative
Requirements
a)
General.
1)
As
an
alternative
to
demonstrating
compliance
with
the
emissions
standards
of
Sections
225.230(a)
or 225.237(a),
the
owner
or
operator
of
an EGU
may
elect
to
demonstrate
compliance
pursuant
to
the
emission
standards
in
subsection
(b)
of
this
Section
and
the
use of
quarterly
emissions
testing
as
an alternative
to
the
use
of CEMS;
2)
The
owner
or
operator
of
an
EGU
that
elects
to demonstrate
compliance
.
pursuant
to
this
Section
must
comply
with
the
testing,
recordkeeping,
and
reporting
requirements
of this
Section
in
addition
to
other
applicable
recordkeeping
and reporting
requirements
in
this
Subpart;
3)
The
alternative
method
of
compliance
provided
under
this
subsection
y
only
be
used
until
June
30,
2012,
after
which
a
CEMS
certified
in
•.
accordance
with
Section
225.250
of this
Subpart
B
must
be
used.
4)
If an
owner
or
operator
of an
EGU
demonstrating
compliance
pursuant
to
Section
225
.230
or
225.237
discontinues
use
of
CEMS
before
collecting
a
full
12
months
of
CEMSdata
and
elects
to
demonstrate
compliance
pursuant
to this
Section,
the
data
collected
prior
to that
point
must
be
averaged
to determine
compliance
for
such
period.
In
such
case,
for
purposes
of
calculating
an
emission
standard
or
mercury
control
efficiency
using
the
equations
in
Section
225.230(a)
or
(b).
the
“12”
in
the
equations
cvill
be replaced
by
a variable
equal
to
the
number
of
full
and
partial
months
for
which
the
owner
or
operator
collected
CEMS
data.
b)
Emission
Limits.
1)
Existing
Units:
Beginning
July
1,
2009,
the
owner
or
operator
of
a
source
with
one
or
more
EGUs
subject to
this
Subpart
B
that
commenced
commercial
operation
on
or
before
June
30,
2009,
must
comply
with
one
of
the
following
standards
for
each
EGU,
as
determined
through
quarterly
emissions
testing
according
to
subsections
(c).
(d),
(e),
and
(1)
of
this
Section:
A)
An
emission
standard
of
0.0080
lb
mercury/GWh
gross
electrical
output;
or
49
B)
A
minimum
90-percent
reduction
of
input mercury.
2)
New
Units:
Beginning
within
the
first
2,160
hours
after
the
commencement
of
commercial
operations,
the
owner
or
operator
of a
source
with
one
or
more
EGUs
subject to
this
Subpart B
that
commenced
commercial
operation
after
June
30,
2009, must
comply
with
one
of
the
following
standards
for
each
EGU,
as
determined
through
quarterly
emissions
testing
in
accordance
with
subsections
(c),
(d).
(e),
and
(f)
of
this
Section:
A)
An
emission
standard
of
0.008
0
lb
mercury/GWh
gross
electrical
output;
or
B)
A
minimum
90-percent
reduction
of
input
mercury.
c)
Initial
Emissions
Testing
Requirements
for
New
Units.
The
owner
or
operator
of
an
EGU
that
commenced
commercial
operation
after
June
30,
2009,
and
that
is
complying
by
means
of
this
Section
must
conduct
an
initial
performance
test
in
accordance
with
the
requirements
of
subsections
(d)
and
(e)
of
this
Section
within
the
first
2,160
hours
after
the
conunencement
of
commercial
operations.
d
Emissions
Testing
Requirements
1)
Subsequent
to
the
initial
performance
test,
emissions
tests
must
be
performed
on
a
quarterly
calendar
basis
in accordance
with
the
requirements
of
subsections
(d),
(e),
and
(f)
of
this
Section;
2)
Notwithstanding
the
provisions
in
subparagraph
(1)
of
this
subsection,
owners
or
operators
of
EGUs
demonstrating
compliance
under
Section
225.233
or
Sections
225.291
through
225.299
must
perform
emissions
testing
on
a
semi-annual
calendar
basis,
where
the
periods
consist
of
the
months
of
January
through
Juneand
July
through
December,
in
accordance
with
the
requirements
of
subsections
(d),
(e).
and
(f)(1)
and
(2)
of this
Section;
3)
Emissions
tests
which
demonstrate
compliance
with
this
Subpart
must
be
performed
at
least
45
days
apart.
However,
if
an
emissions
test
fails
to
demonstrate
compliance
with
this
Subpart or
the
emissions
test
is
being
performed
subsequent
to
a
significant
change
in
the
operations
of
an
EGU
under
subsection
(h)(2)
of
this
Section,
the
owner
or
operator
of
an
EGU
may
perform
additional
emissions
test(s) using
the
same
test
protocol
previously
submitted
in
the
same
period,
with
less
than
45
days
in
between
emissions
tests;
50
4)
A
minimum
of
three
and
a
maximum
of
nine
emissions
test
runs,
lasting
at
least
one
hour
each,
shall
be
conducted
and
averaged
to
determine
compliance.
All
test runs
performed
will
be
reported.
5)
If
the
EGU
shares
a
common
stack
with
one
or
more
other
EGUs,
the
owner
or
operator
of
the
EGU
will
conduct
emissions
testing
in the
duct
to
the
common
stack
from
each
unit,
unless
the owner
or
operator
.of
the
EGU
considers
the
combined
emissions
measured
at
the
common
stack
as
the
mass
emissions
of
mercury
for
the
EGUs
for
recordkeeping
and
compliance
purposes.
6)
If
an
owner
or
operator
of
an
EGU
demonstrating
compliance
pursuant
to
this
Section
later
elects
to
demonstrate
compliance
pursuant
to
the
CEMS
monitoring
provisions
in
Section
225.240
of
this
Subpart,
the
owner
or
operator
must comply
with
the
emissions
monitoring
deadlines
in
Section
225.240(b)(4)
of
this
Subpart.
e)
Emissions
Testing
Procedures
1)
The
owner
or
operator
must
conduct
a
compliance
test
in
accordance
with
Method
29,
30A,
or
30B
of
40
CFR
60,
Appendix
A,
as
incorporated
by
reference
in
Section
225.140;
2)
Mercury
emissions
or
control
efficiency
must
be
measured
while
the
affected
unit
is
operating
at
or
above
90%
of
peak
load;
3)
For
units
complying
with
the
control
efficiency
standard
of
subsection
(b)(1’)(B)
or
(b’)(2’)(B)
of
this
Section,
the
owner
or
operator
must
perform
coal
sampling
as
follows:
A)
in
accordance
with
Section
225.265
of
this
Subpart
at
least
once
during
each
day
of
testing;
and
B)
in
accordance
with
Section
225
.265
of
this
Subpart,
once
each
month
in
those
months
when
emissions
testing
is
not
performed;
4)
For units complying
with
the
output-based
emission
standard
of
subsection
(b)(1)(A)
or
(b)(2)(A)
of
this
Section,
the
owner
or
operator
must monitor
gross
electrical
output
for
the
duration
of
the
testing.
5)
The owner
or
operator
of
an
EGU
may use
an
alternative
emissions
testing
method
if
such
alternative
is
submitted
to
the
Agency
in
writing
and
approved
in
writing
by
the
Manager
of
the
Bureau
of
Air’s
Compliance
Section.
Notification
Reauirements
51
1)
The
owner
or
operator
of
an
EGU
must
submit
a
testing
protocol
as
described
in
USEPA’s
Emission
Measurement
Center’s
Guideline
Document
#42
to
the
Agency
at
least
45
days
prior
to
a
scheduled
emissions
test,
except
as
provided
in
Section
225.239(h)(2)
and
(h)(3).
Upon
written
request
directed
to.
the
Manager
of
the
Bureau
of
Air’s
Compliance
Section,
the
Agency
may,
in
its
sole
discretion,
waive
the
45-
day
requirement.
Such
waiver
shall
only
be
effective
if it
is
provided
in
writing and
signed
by
the
Manager
of
the
Bureau
of
Air’s
Compliance
Section,
or
his
or
her
designee;
2)
Notification
of
a
scheduled
emissions
test
must
be
submitted
to
the
Agency
in writing,
directed
to
the
Manager
of
the
Bureau
of
Air’s
Compliance
Section,
at least
30
days
prior
to
the
expected
date
of
the
emissions
test.
Upon
written
request
directed
to the
Manager
of
the
Bureau
of Air’s
Compliance
Section,
the
Agency
may,
in
its
sole
discretion,
waive
the
30-day
notification
requirement.
Such waiver
shall
only
be
effective
if it
is
provided
in
writing
and
signed
by
the
Manager
of
the
Bureau of
Air’s Compliance
Section,
or
his
or
her
designee.
Notification
of
the
actual
date
and
expected
time
of
testing
must
be
submitted
in
writing,
directed
to
the
Manager
of
the
Bureau
of
Air’s
Compliance
Section,
at
least
five
working
days
prior
to
the
actual
date
of
the
test;
3)
For
an
EGU
that
has
elected
to
demonstrate
compliance
by
use
of
the
emission standards
of
subsection
(b)
of
this
Section,
if an
emissions
test
performed
under
the
requirements
of
this
Section
fails
to demonstrate
compliance
with the
limits
of subsection
(b)
of
this
Section,
the
owner
or
operator
of
an
EGU
may
perform
a
new
emissions
test
using
the
same
test
protocol
previously
submitted
in the
same
period,
by
notifying
the
Manager
of
the
Bureau
of
Air’s
Compliance
Section
or
his
or
her
designee
of the
actual
date
and
expected
time
of testing
at
least
five
working
days
prior
to
the
actual
date
of
the
test.
The
Agency
may,
in
its
sole
discretion,
waive
this
five-day
notification
requirement.
Such
waiver
shall
only
be
effective
if
it is
provided
in
writing
and
signed
by
the
Manager
of
the
Bureau
of
Air’s
Compliance
Section,
or
his
or
her
designee;
4)
In
addition
to
the
testing
protocol
required
by
subsection
(f)(1) of
this
Section,
the
owner
or
operator
of
an
EGU
that
has
elected
to
demonstrate
compliance
by
use
of
the
emission
standards
of
subsection
(b)
of
this
Section must
submit
a
Continuous
Parameter
Monitoring
Plan
to
the
Agency at
least
45
days
prior
to
a
scheduled
emissions
test.
Upon
written
request directed
to
the
Manager
of
the
Bureau
of
Air’s
Compliance
Section,
the
Agency
may,
in
its
sole
discretion,
waive
the
45-day
requirement.
Such
waiver
shall
only
be
effective
if
it
is provided
in
writipg
and
signed
by
the
Manager
of
the
Bureau
of
Air’s
Compliance
Section,p
his
or
her
designee.
The
Continuous
Parameter
Monitoring
Plan
must
52
detail
how the
EGU
will
continue
to
operate
within the
parameters
enumerated
in
the
testing
protocol
and
how those
parameters
will
ensure
compliance
with
the
applicable
mercury
limit.
For
example,
the
Continuous
Parameter
Monitoring
Plan
must include
coal
sampling
as
described
in
Section
225.239(e)(3)
of
this
Subpart
and
must
ensure
that
an
EGU that
performs
an
emissions
test
using
a
blend
of
coals
continues
to
operate
using
that
same blend
of
coal.
If the
Agency
disapproves
the
Continuous
Parameter
Monitoring
Plan,
the
owner
or
operator
of
the
EGU
has
30
days
from
the
date
of
receipt
of
the
disapproval
to
submit
more
detailed
information
in
accordance
with
the
Agency’s
request.
g)
Compliance
Determination
1)
Each
quarterly
emissions
test
shall
determine
compliance
with
this
Subpart
for
that
quarter,
where
the
quarterly
periods
consist
of
the
months
of
January
through
March,
April
through
June,
July
through
September,
and
October
through
December;
2)
If
emissions
testing
conducted
pursuant
to
this
Section
fails
to
demonstrate
compliance,
the
owner
or
operator
of
the
EGU
will
be
deemed
to
have
been out
of
compliance
with
this
Subpart
beginning
on
the
day
after
the
most recent
emissions
test
that
demonstrated
compliance
or
the
last
dypf
certified
CEMS data
demonstrating
compliance
on
a
rolling
12-month
basis,
and
the
EGU
will
remain
out
of
compliance
until
a subsequent
emissions
test
successfully demonstrates
compliance
with
the
limits
of
this
Section.
h)
Operation
Requirements
1’)
The
owner
or
operator
of
an
EGU
that
has
elected
to
demonstrate
compliance
by
use
of
the
emission
standards
of
subsection
(1,)
of
this
Section
must
continue
to
operate
the
EGU
commensurate
with
the
Continuous
Parameter
Monitoring
Plan
until
another
Continuous
Parameter
Monitoring
Plan
is developed
and
submitted
to
the
Agency
in
conjunction
with
the
next
compliance
demonstration,
in
accordance
with
subsection
(fl(4)
of
this
Section.
2)
If
the
owner
or
operator
makes
a
significant
change
to
the
operations
of
an
EGU
subject
to
this
Section,
such
as
changing
from
bituminous
to
subbituminous
coal,
the
owner
or
operator
must
submit
a
testing
protocol
to
the
Agency
and
perform
an
emissions
test
within
seven
operating
days
of
the
significant
change.
In
addition,
the
owner
or
operator
of
an
EGU
that
has
elected
to
demonstrate
compliance
by
use
of
the
emission
standards
of
subsection
(b)
of
this
Section
must
submit
a
Continuous
Parameter
Monitoring
Plan
within
seven
operating
days
of
the
significant
change.
53
3)
If
a
blend
of
bituminous
and
subbituminous
coal is
fired
in
the
EGU,
the
owner
or
operator
of
the
EGU must
ensure
that
the
EGU
continues
to
operate
using
the
same
blend
that
was used
during
the
most
recent
successful
emissions
test.
If
the
blend
of
coal changes,
the
owner
or
operator
of
the
EGU must
re-test
in
accordance
with
subsections
(d), (e),
(f),
and
(g)
of
this
Section
within
30
days
of
the
change
in
coal
blend,
notwithstanding
the
requirement
of
subsection
(d)(3)
of
this
Section
that
there
must
be
45
days between
emissions
tests.
i)
Recordkeeping
1)
The
owner
or
operator
of
an
EGU
and
its
designated
representative
must
comply
with
all
applicable
recordkeeping
and
reporting
requirements
in
this
Section.
2)
Continuous
Parameter
Monitoring.
The
owner
or
operator
of
an
EGU
must
maintain
records
to
substantiate
that
the
EGU
is
operating
in
compliance
with
the
parameters
listed
in
the
Continuous
Parameter
Monitoring
Plan,
detailing
the
parameters
that
impact
mercury
reduction
and including
the
following
records
related
to
the
emissions
of
mercury:
A)
For
an
EGU
for
which
the
owner
or
operatoris
complying
with
this
Subpart
B
pursuant
to
Section
225.239(b)(l)(B)
or
225.239(b)(2)(B),
records
of
the
daily
mercury
content
of
coal
used
(lbs/trillion
Btu)
and
the
daily and
quarterly
input
mercury
(lbs).
B)
For
an
EGU for
which
the
owner
or
operator
of
an
EGU
complying
with
this
Subpart
B
pursuant
to
Section
225.239(b)(1’)(A)
or
225
.239(b)(2)(A),
records
of
the
daily
and
quarterly
oss
electrical
output
(MWh)
on
an
hourly
basis.:
-
3)
The
owner
or
operator
of
an
EGU
using
activated
carbon
injection
must
also comply
with
the
following
requirements:
A)
Maintain
records
of
the
usage
of
sorbent,
the
exhaust
gas
flow
rate
from the
EGU,
and
the
sorbent
feed
rate,
in
pounds
per
million
actual
cubic
feet
of
exhaust
gas
at
the
injection
point,
on
a
weekly
average
B)
If
a
blend of
bituminous
and
subbituminous
coal
is
fired
in
the
EGU,
keep
records
of
the
amount
of
each
type
of
coal
burned
and
the
required
injection
rate
for injection
of
activated
carbon,
on
a
weekly
basis.
54
4)
The owner
or
operator
of
an
EGU
must retain
all
records
required
by
this
Section
at
the
source
unless
otherwise
provided
in
the
CAAPP
permit
issued
for
the
source
and
must
make
a
copy
of
any
record
available
to
the
Agency
promptly
upon
request.
5)
The
owner
or
operator
of
an
EGU
demonstrating
compliance
pursuant
to
this
Section
must
monitor
and
report
the
heat
input rate
at
the
unit
level.
The
owner
or
operator
of
an
EGU
*-----
mnntrtiiw
compliance
pursuant
to
this
Section
must
perform
and
report
coal
sampling
in
accordance
with
subsection
225.239(e)(3).
Renortina
Reauirements
1)
An
owner
or
operator
of
an
EGU
shall submit
to
the
Agency
a
Final
Source
Test
Report
for
each
periodic
emissions
test
within
45
days
after
the
test
is
completed.
The
Final
Source
Test
Report
will
be
directed
to
the
•
Manager
of
the
Bureau
of
Air’s
Compliance
Section,
or
his
or
her
designee,
and
include
at
a
minimum:
A)
A
summary
of
results;
B)
A
description
of
test
method(s),
including
a description
of
sampling
points,
sampling
train, analysis
equipment,
and
test
schedule,
and
a
detailed
description
of
test
conditions,
including:
i)
Process
information,
including
but
not
limited
to
mode(s)
of
operation,
process
rate,
and
fuel
or
raw
material
consumption;
ii)
Control
equipment
information
(i.e.,
equipment
condition
and
operating
parameters
during
testing);
iii)
A
discussion
of
any
preparatory
actions
taken
(i.e.,
inspections,
maintenance,
and
repair);
and
Data
and
calculations,
----‘
jpnliidina
cnnii’cz
of
all
raw
data
sheets
and
recordsof
laboratory analyses, sample
calculations,
and
data
on
equipment
calibration.
2)
The
owner
or
operator
of
a
source
with
one
or
more
EGUs
demonstratipE
compliance
with
Subpart
B
in
accordance
with
this
Section
must
submit
to
the
Agency
a
Quarterly
Certification
of
Compliance
within
45
days
following
the
end
of
each
calendar
quarter.
Quarterly
certifications
of
compliance
must certify
whether
compliance
existed
for
each
EGU
for
the
calendar
quarter
covered
by
the
certification.
If
the
EGU
failed
to
comply
6)
iv)
55
during
the
quarter
covered
by
the
certification,
the
owner or
operator
must
provide
the
reasons
the
EGU
or
EGUs
failed
to
comply and
a
full
description
of
the
noncompliance
(i.e..
tested
emissions
rate,
coal
sample
data,
etc.).
In
addition,
for
each
EGU, the
owner
or
operator
must
provide
the
following
appropriate
data
to
the
Agency as
set
forth
in
this
Section.
A)
A
list
of
all
emissions
tests
performed
within
the
calendar
quarter
covered
by
the
Certification
and
submitted
to
the
Agency
for
each
EGU,
including
the
dates
on
which
such
tests
were
performed.
B)
Any
deviations
or
exceptions
each
month and
discussion
of
the
reasons
for
such
deviations
or
exceptions.
C)
All
Quarterly
Certifications
of
Compliance
required
to
be
submitted
must
include
the
following
certification
by
a
responsible
official:
I
certify
under
penalty
of
law
that
this
document
and
all
attachments
were
prepared
under
my
direction
or
supervision
in
accordance
with
a
system
designed
to
assure
that
qualified
personnel
properly
gather
and
evaluate
the
information
submitted.
Based
on
my
inquiry
of
the
person
or
persons
directly
responsible
for
gathering the
information,
the
information
submitted
is,
to
the
best
of
my
knowledge
and
belief,
true,
accurate,
and
complete.
I
am
aware
that
there
are
significant
penalties
for
submitting
false
information,
including
the
possibility
of
fine
and
imprisonment
for
knowing
violations.
3)
Deviation
Reports.
For
each
EGU,
the
owner
or
operator
must
promptjy
notify
the
Agency
of
deviations
from
any
of
the
requirements
of
this
Subpart
B.
At
a
minimum,
these
notifications
must
include
a
description
of
such
deviations
within
30
days
after
discovery
of
the
deviations,
and
a
discussion
of
the
possible
cause
of
such
deviations,
any
corrective
actions,
and
any
preventative
measures
taken.
(Source:
Added
at
effective
Section
225
.240
General
Monitoring
and
Reporting
Requirements
The
owner
or
operator
of
an
EGU must
comply
with
the
monitoring,
recordkeeping,
and
reporting
requirements
as
provided
in
this
Section,
Sections
225.250
through
225.290
of
this
Subpart
B,
and
Sections
1.14
through
1.18
of
Appendix
B
to
this
Part.
Subpart
I
of
40
CFR
75
(sectiona
75.80
through
75.84), incorporated
by
reference
in
Section
225.140.
If
the
EGU
utilizes
a
common
stack
with
units that
are
not
EGUs
and
the
owner
or
operator
of
the
EGU
does
not
conduct
emissions
monitoring
in
the
duct
to
the
common
stack
from
each
EGU,
the
owner
or
operator
of
the
EGU
must conduct
emissions
monitoring
in
accordance
with
Section
l.16(b)(2)
56
of
Appendix
B
to
this
Part
40
CFR
75.82(b)(2)
and
this
Section,
including
monitoring
in
the
duct
to
the
common
stack
from
each
unit
that
is
not
an
EGU,
unless
the
owner
or
operator
of
the
EGU
counts
the combined
emissions
measured
at
the
common
stack
as
the
mass
emissions
of
mercury
for the
EGUs
for
recordkeeping
and
compliance
purposes.
a)
Requirements
for
installation,
certification,
and
data
accounting.
The
owner
or
operator
of
each
EGU
must:
1)
Install
all
monitoring
systems
required
pursuant
to
this
Section
and
Sections
225.250
through
225
.290
for
monitoring
mercury
mass
emissions
(including
all
systems
required
to
monitor
mercury
concentration,
stack
gas
moisture
content,
stack
gas flow
rate,
and
CO
2
or
02
concentration,
as
applicable,
in
accordance
with
Sections
1.15
and 1.16
of
Appendix
B to
this
Part.
40
CFR
75.81
and
75.82).
2)
Successfully
complete
all
certification
tests required
pursuant
to
Section
225
.250
and
meet
all
other
requirements
of
this
Section,
Sections
225.250
through
225.290,
and
Sections
1.14 through
1.18
of
Appendix
B
to
this
j
subpart
I
of
40
CFR
Part
75
applicable
to
the
monitoring
systems
required
under
subsection
(a)(1) of
this
Section.
3)
Record,
report,
and
assure
the
quality
of
the
data from
the
monitoring
systems
required
under
subsection
(a)(1)
of
this
Section.
4)
If
the
owner
or
operator
elects
to
use
the
low
mass
emissions
excepted
monitoring
methodology
for
an
EGU
that
emits
no
more
than
464
ounces
(29 pounds)
of
mercury
per
year
pursuant
to
Section
1.15(b)
of
Appendix
B
to
this
Part
40
CFR
75.8 1(b),
it
must
perform
emissions
testing
in
accordance
with
Section
1.15(c)
of
Appendix
B
to
this
Part
40
CFR
75.81(c)
to
demonstrate
that
the
EGU is
eligible
to
use
this
excepted
emissions
monitoring
methodology,
as
well
as
comply
with
all
other
applicable
requirements
of
Section
1.15(b)
through
(f
of
Appendix
B
to
this Part.
40
CFR 75.8
1(b) through
(f). Also,
the
owner
or
operator
must
submit
a
copy
of
any
information
required
to
be
submitted
to
the
USEPA
pursuant
to
these
provisions
to
the
Agency.
The
initial
emissions
testing
to
demonstrate
eligibility
of
an
EGU
for
the
low
mass
emissions
excepted
methodology
must
be
conducted
by
the
applicable
of
the
following
dates:
A)
If
the
EGU
has commenced
commercial
operation
before
July
1,
2008,
at
least
by
yJanuary
1,
2009,
or
45
days
prior
to
relying
on
the
low
mass emissions
excepted
methodology,
whichever
date
is
later.
B)
If
the
EGU
has
commenced
commercial
operation
on
or
after
July
1,
2008,
at
least
45
days prior
to
the
applicable
date
specified
pursuant
to
subsection
(b)(2)
of
this
Section
or
45
days
prior
to
57
relying
on
the
low
mass
emissions
excepted
methodology,
whichever
date
is
later.
b)
Emissions
Monitoring
Deadlines.
The
owner
or
operator
must
meet
the
emissions
monitoring
system certification
and
other
emissions
monitoring
requirements
of
subsections
(a)(1) and
(a)(2)
of
this
Section
on
or
before
the
applicable
of
the
following
dates.
The
owner
or
operator
must
record,
report,
and
quality-assure
the
data
from
the
emissions
monitoring
systems
required
under subsection
(a)(l)
of
this
Section
on
and
after
the
applicable
of
the
following
dates:
1)
For
the
owner
or
operator
of
an
EGU
that
commences
commercial
operation before
July
1,
2008,
by
jjjyJanuary
1,
2009.
2)
For
the
owner
or
operator
of
an
EGU
that
commences
commercial
operation
on
or
after
July
1,
2008,
by
90
unit
operating
days
or
180
calendar
days,
whichever
occurs
first, after
the
date on
which
the
EGU
commences
commercial
operation.
3)
For
the
owner
or
operator
of
an
EGU
for
which
construction
of
a
new
stack
or
flue
or
installation
of
add-on mercury
emission
controls,
a
flue
gas
desulfurization
system,
a
selectivecatalytic
reduction
system,
a
fabric
filter,
or
a
compact
hybrid
particulate
collector
system
is
completed
after
the
applicable
deadline
pursuant
to
subsection
(b)(1)
or
(b)(2)
of
this
Section,
by
90
unit
operating
days
or
180
calendar
days,
whichever
occurs
first,
after
the
date
on
which emissions
first
exit
to
the
atmosphere
through
the
new
stack
or
flue,
add-on mercury
emission
controls,
flue
gas
desulfurization
system,
selective
catalytic
reduction
system,
fabric
filter,
or
compact
hybrid
particulate
collector
system.
4)
For
an
owner
or
operator
of
an
EGU that
originally
elected
to
demonstrate
compliance
pursuant
to
the
emissions
testing
requirements
in
Section
225
.239,
by
the
first
day
of
the
calendar
quarter
following
the
last
emissions
test
demonstrating
compliance
with
Section
225.239.
c)
Reporting
Data.
1)
Except
as
provided
in
subsection
(c)(2)
of
this
Section,
the
owner
or
operator
of
an
EGU
that
does
not
meet
the
applicable
emissions
monitoring
date set
forth
in
subsection
(b)
of
this
Section
for
any
emissions
monitoring
system
required
pursuant
to
subsection
(a)(1)
of
this
Section
must
begin
periodic
emissions
testing
in
accordance
with
Section
225.239.,
for
each
such
monitoring
system,
detemine,
record,
and
report
the
maximum
potential
(or,
as
appropriate,
the
minimum
potential)
values
for
mercury
concentration,
the
stack
gas
flow
rate,
the
stack
gas
moisture
content,
and
any
other
parameters
required
to
determine
mercury
mass
emissions
in
accordance
with
40
CFR
75.80(g).
58
The
owner
or
operator
of
an
EGU
that
does
not
meet
the
applicable
emissions
monitoring
date
set
forth
in
subsection
(b)(3) of
this
Section
for
any
emissions
monitoring
system
required
pursuant
to
subsection
(a)(1)
of
this
Section
must
begin
periodic
emissions
testing
in
accordance
with
Section
225.239.,
for
each
such
monitoring
system,
determine,
record,
and
report
substitute
data
using
the
applicable
missing
data
procedures
as
set
forth
in4O
CFR
75.80(f),
in
lieu
of
the
maximum
potential
(or,
as
appropriate,
minimum
potential)
values
for
a
parameter,
if
the
owner
or
operator
demonstrates
that
there
is
continuity
between
the
data streams
for
that
parameter
before
and
after
the
construction
or
installation
pursuant
to
subsection
(b)(3)
of
this
Section.
d)
Prohibitions.
1)
No
owner
or
operator
of
an
EGU
may use
any
alternative
emissions
monitoring
system,
alternative
reference
method
for
measuring
emissions,
or
other
alternative
to
the
emissions
monitoring
and
measurement
requirements
of
this
Section
and
Sections
225.250
through
225.290,
unless
such
alternative
is
submitted
to
the
Agency
in
writing
and approved
in
writing
by
the
Manager
of
the
Bureau
of
Air’s
Compliance
Section.
or
his
or
her
designee.
promulgated
by
the
USEPA
and
approved
in
writing
by
the
Agency,
or
the
use
of
such
alternative
is
approved
in
ting
by
the
Agency
and
USEPA.
2)
No
owner
or
operator
of
an
EGU
may
operate
its
EGU
so
as
to
discharge,
or
allow
to
be
discharged,
mercuryemissions
to
the
atmosphere
without
accounting
for
all
such
emissions
in
accordance
with the
applicable
provisions
of
this
Section,
Sections
225.250
through
225.290,
and
Sections
1.14
through
1.18
of
Appendix
B
to
this
Part,
unless
demonstrating
compliance
pursuant
to
Section
225.239,
as
applicable.
subpart
I
of
40
CFR
75.
3)
No
owner
or
operator
of
an
EGU
may
disrupt
the
CEMS,
any
portion
thereof,
or
any other
approved
emission
monitoring
method,
and
thereby
avoid monitoring
and
recording
mercury
mass
emissions
discharged
into
the
atmosphere,
except
for
periods
of
recertification
or
periods
when
calibration,
quality
assurance
testing,
or
maintenance
is
performed
in
accordance
with
the
applicable
provisions
of
this
Section,
Sections
225.250
through
225
.290,
and
Sections
1.14
through
1.18
of
Appendix
B
to
this
Part. subpart
I
of
40
CFR
75.
4)
No
owner
or
operator
of
an
EGU
may
retire
or
permanently
discontinue
use
of
the
CEMS
or
any
component
thereof,
or
any
other
approved
monitoring
system
pursuant
to
this
Subpart
B,
except
under
any
one
of the
following
circumstances:
2)
59
A)
The
owner
or
operator
is
monitoring
emissions
from
the
EGU
with
another
certified
monitoring
system
that
has
been
approved,
in
accordance
with
the
applicable
provisions
of
this
Section,
Sections
225.250
through
225.290
of
this
Subpart
B,
and
Sections
1.14
through
1.18
of
Appendix
B
to
this
Part, subpart
I
of
40
CFR
75,
by
the
Agency
for
use
at
that
EGU
and
that
provides
emission
data
for
the
same
pollutant
or
parameter
as
the
retired
or
discontinued
monitoring
system;
or
B)
The
owner
or
operator
or
designated
representative
submits
notification
of
the
date
of
certification
testing
of
a
replacement
monitoring
system
for
the
retired
or
discontinued
monitoring
system
in
accordance
with
Section
225
.250(a)(3)(A).
C)
The
owner
or
operator
is
demonstrating
compliance
pursuant
to
the
applicable
subsections
of
Section
225.239.
e)
Long-term
Cold
Storage.
The
owner
or
operator
of
an
EGU
that
is
in
long-term
cold storage
is
subject
to
the
provisions
of
40
CFR 75.4
and
40
CFR
75.64,
incorporated
by
reference
in
Section
225.140,
relating
to
monitoring,
rccordkeeping,
and
reporting
for
units
in
long-term
cold
storage.
(Source:
Amended
at
effective
Section
225.250
Initial
Certification
and
Recertification
Procedures
for
Emissions
Monitoring
a)
The owner
or
operator
of
an
EGU
must
comply
with
the
following
initial
certification
and
recertification
procedures
for
a
CEMS
(i.e.,
a
CEMS
or
an
excepted
monitoring
system
(sorbent
trap monitoring
system)
pursuant
to
Section
1.3
of
Appendix
B
to
this
Part
40-CFR
75.15,
incorporated
by
reference
in
Section
225.140)
required
by
Section
225.240(a)(1).
The
owner
or
operator
of
an
EGU
that
qualifies
for,
and
for
which
the
owner
or
operator
elects
to
use,
the
low-mass-
emissions
excepted
methodology
pursuant
to
Section
1.15(b)
of
Appendix
B to
this
Part 40
CFR 75.81(b),
incorporated
by
reference
in
Section
225.140,
must
comply
with
the procedures
set
forth
in
subsection
(c)
of
this
Section.
1)
Requirements
for
Initial
Certification.
The
owner
or
operator
of
an
EGU
must ensure
that,
for
each
CEMS
required
by
Section
225.240(a)(1)
(including
the
automated
data acquisition
and
handling
system),
the
owner
or
operator
successfully
completes
all
of
the
initial
certification
testing
required
pursuant
to
Section
1.4
of
Appendix
B to
this
Part
40
CFR
75.80(d),
incorporated
by
reference
in
Section
225.140,
by
the
applicable
60
deadline
in
Section
225.240(b).
In
addition,
whenever
the
owner
or
operator
of
an
EGU installs
a
monitoring
system
to
meet
the
requirements
of
this
Subpart
B
in
a
location
where
no
such
monitoring
system
was
previously
installed,
the
owner
or
operator
must
successfully
complete
the
initial
certification
requirements
of
Section
1.4
of
Appendix
B
to
this
40
CFR
75.80(d).
2)
Requirements
for Recertification.
Whenever
the
owner
or
operator
of
an
EGU makes
a
replacement,
modification,
or
change
in
any
certified
CEMS,
or
an
excepted
monitoring
system
(sorbent
trap
monitoring
system)
pursuant
to
Section
1.3
of
Appendix
B
to
this
Part
40
CFR
75.15,
and
required
by
Section
225
.240(a)(1),
that
may significantly
affect
the
ability
of
the
system
to
accurately
measure
or
record
mercury
mass
emissions
or
heat
input
rate
or
to
meet
the quality-assurance
and
quality-
control
requirements
of
Section
1.5
ofAppendixB
to
this
Part
40
CFR
75.21
or
Exhibit
B
to
Appendix
B
to
this
PartAppendix
B
to
40
CFR
75,
each incorporated
by
reference
in
Section
225.140,
the
owner
or
operator
of
an
EGU
must
recertify
the
monitoring
system
in
accordance
with
Section
1.4(b)
of
Appendix
B
to
this
Part. 40
CFR
75.20(b),
incorporated
by
reference
in
Section
225.140.
Furthermore,
whenever
the
owner
or
V
operator
of
an
EGU makes
a
replacement,
modification,
or
change
to
the
flue
gas
handling
system
or
the
EGU’s
operation
that
may
significantly
change
the
stack
flow
or
concentration
profile,
the
owner
or
operator
must
recertify
each
CEMS,
and
each
excepted
monitoring
system
(sorbent
trap
monitoring
system)
pursuant
to
Section
1.3
to
Appendix
B
to
this
Part,
40
CFR
75.15,
whose
accuracy
is
potentially
affected
by
the
change,
all
in
accordance
with Section
1.4(b)
to
Appendix
B
to
this
Part.
40
CFR
75.20(b).
Examples
of
changes
to
a
CEMS
that
require
recertification
include,
but are
not
limited
to,
replacement
of
the
analyzer,
complete
replacement
of
an
existing
CEMS,
or
change
in
location
or
orientation
of
the
sampling
probe
or
site.
3)
Approval
Process
for
Initial
Certification
and
Recertification.
Subsections
(a)(3)(A)
through
(a)(3)(D)
of
this
Section
apply
to
both initial
certification
and recertification
of
a
CEMS
required
by
Section
225.240(a)(1).
For
recertifications,
the
words
“certification”
and
“initial
certification”
are
to
be
read
as
the
word
“recertification”,
the
word
“certified”
is
to
be
read
as
the
word
“recertified”,
and
the
procedures
set
forth
in
Section
1.4(b)(5)
of
Appendix
B
to
this
Part 40
CFR
75.20(bXS)
are
to
be
followed
in
lieu
of
the
procedures
set
forth
in
subsection
(a)(3)(E)
of
this
Section.
A)
Notification
of
Certification.
The
owner
or
operator
must
submit
written
notice
of
the
dates
of
certification
testing
to
the
Agency,
directed
to
the
Manager
of
the
Bureau
of
Air’s
Compliance
SectionUSEPA
RegionS,
and
the
Administrator
of
the
USEPA
61
written
notice
of
the
dates
of
certification
testing,
in
accordance
with
Section
225
.270.
B)
Certification
Application.
The
owner
or
operator
must
submit
to
the
Agency
a certification
application for
each
monitoring
system.
A complete
certification
application
must
include
the
information
specified
in
40
CFR
75.63,
incorporated
by
reference
in
Section
225.140.
C)
Provisional
Certification
Date.
The
provisional
certification
date
for
a
monitoring
system
must
be
determined
in
accordance
with
Section
1.4(a)(3) of
Appendix
B
to
this
Part.
40
CFR
75.20(a)(3-)
incorporated
by
reference
in
Section
225.140.
A provisionally
certified
monitoring
system
may
be
used
pursuant
to this
Subpart
B
for
a period
not
to exceed
120
days
after
receipt
by
the
Agency
of
the
complete
certification
application
for
the
monitoring
system
pursuant
to
subsection
(a)(3)(B)
of
this
Section. Data
measured
and
recorded
by
the
provisionally
certified
monitoring
system,
in
accordance
with
the
requirements
of
Appendix B
to this
Part
40
CFR
75,
will
be
considered
valid
quality-assured
data
(retroactive
to
the
date
and
time
of
provisional
certification),
provided
that
the
Agency
does
not
invalidate
the
provisional
certification
by issuing
a
notice
of
disapproval
within
120
days
after
the
date
of
receipt
by
the
Agency
of
the
complete
certification
application.
D)
Certification
Application
Approval
Process.
The
Agency
must
issue
a written
notice
of
approval
or
disapproval
of
the
certification
application
to the
owner
or operator
within
120
days
after
receipt
of
the
complete
certification
application
required
by subsection
(a)(3)(B)
of
this
Section.
In the
event
the
Agency
does
not
issue
a
written
notice
of
approval
or
disapproval
within
the
120-day
period,
each
monitoring
system
that
meets
the
applicable
performance
requirements
of
Appendix
B
to this
Part
40 CFR
75
and
which
is
included
in
the certification
application
will
be
deemed
certified
for
use
pursuant
to this
Subpart
B.
i)
Approval
Notice.
If
the certification
application
is
complete
and
shows
that
each
monitoring
system
meets
the
applicable
performance
requirements
of
Appendix
B
to
this
40
CFR
75,
then
the Agency
must
issue
a
written
notice
of
approval of
the certification
application
within
120
days
after
receipt.
ii)
Incomplete
Application
Notice.
If
the certification
application
is
not
complete,
then
the
Agency
must
issue
a
written
notice
of
incompleteness
that
sets
a reasonable
date
62
by
which
the
owner
or
operator
must
submit
the
additional
information
required
to
complete
the
certification
application.
If
the
owner
or
operator
does
not
comply
with
the
notice
of
incompleteness
by
the
specified
date,
the
Agency
may
issue
a
notice
of
disapproval
pursuant
to
subsection
(a)(3)(D)(iii)
of
this
Section.
The
120-day
review period
will
not
begin
before
receipt
of
a
complete
certification
application.
iii)
Disapproval
Notice.
If
the certification
application
shows
that
any
monitoring
system
does
not
meet the
performance
requirements
of
Appendix
B
to
this
Part,
40
CFR
75,
or
if
the
certification
application
is
incomplete
and
the
requirement
for
disapproval
pursuant
to
subsection
(a)(3)(D)(ii)
of
this
Section
is
met,
the
Agency
must
issue
a
written
notice
of
disapproval
of
the certification
application..
Upon
issuance
of
such notice
of
disapproval,
the
provisional
certification
is
invalidated,
and
the
data
measured
and
recorded
by
each
uncertified
monitoring
system
will
not
be
considered
valid
quality-assured
data
beginning
with
the
date and
hour
of
provisional
certification
(as
defmed
pursuant
to
Section
1
.4(a(3)
of
Appendix
B to
this Part).
40
CFR 75.20(a)(3)).
The
owner
or
operator
must
follow
the
procedures
for
loss
of
certification
set
forth
in
subsection
(a)(3)(E)
of
this
Section
for
each
monitoring
system
that
is
disapproved
for
initial
certification.
iv)
Audit
Decertification.
The
Agency
may
issue
a
notice
of
disapproval
of
the
certification
status of
a
monitor
in
accordance
with
Section
225.260(b).
E)
Procedures
for
Loss
of
Certification.
If
the Agency
issues
a
notice
of
disapproval
of
a
certification
application
pursuant
to
subsection
(a)(3)(D)(iii)
of
this
Section
or
a
notice
of
disapproval
of
certification
status pursuant
to
subsection
(a)(3)(D)(iv)
of
this
Section,
the owner
or
operator
must
fulfill
the
following
requirements:
i)
The owner
or
operator
must
substitute
the
following
vaiu
for
each
disapproved
monitoring
system
and
for
each
hour
of
EGU
operation
during
the
period
of
invalid
data
specified
pursuant
to
40
CFR
75.20(a)(4)(iii)
or
75.21(e),
continuing
until
the
applicable
date
and
hour
specified
pursuant
to
40
CFR 75.20(a)(5)(i),
each
incorporated
by
reference
in
Section
225.140.
For
a
disapproved
mercury
63
pollutant
concentration
monitor
and
disapproved
flow
monitor,
respectively,
the
maximum potential
concentration
of
mercury
and
the
maximum
potential
flow
rate,
as
defined
in sections
2.1.7.1
and
2.1.4.1 of
Appendix
A
to
40
CFR
75,
incorporated
by
reference
in
Section
225.140.
For
a disapproved
moisture
monitoring
system
and
disapproved
diluent
gas
monitoring
system,
respectively,
the
minimum
potential
moisture
percentage
and
either
the
maximum
potential
CO
concentration
or the
minimum
potential
O
concentration
(as
applicable),
as
defined
in
2.1.5,
2.1.3.1,
and
2.1.3.2
of
Appendix
A
to
40
CFR
75,
incorporated
by
reference
in Section
225.140.
For
a disapproved
excepted
monitoring
system
(sorbent trap
monitoring
system)
pursuant
to
40
CFR
75.15
and
disapproved
flow
monitor,
rnctiv1v
the
maximum
potential
concentration
of
mercury
and
maximum
potential
flow
rate,
as
defined
in
sections
2.1.7.1
and
2.1.4.1
of
Appendix
A to,40
CFR
75,
incorporated
by reference
in
section
225.140.
in)
The
owner
or
operator
must
submit
a
notification
of
certification
retest
dates
and
a
new
certification
application
in
accordance
with
subsections
(a)(3)(A)
and
(B)
of
this
Section.
iiiii)
The
owner
or
operator
must
repeat
all
certification
tests
or
other
requirements
that
were
failed
by
the
monitoring
system,
as
indicated
in
the
Agency’s
notice
of
disapproval,
no later
than
30
unit
operating
days
after
the
date
of
issuance
of
the
notice
of
disapproval.
b)
Exemption.
1)
If
an
emissions
monitoring
system has
been
previously
certified
in
accordance
with
Appendix
B
to this
Part
40
CFR
75
and
the
applicable
quality
assurance and
quality
control
requirements
of
Section
1.5
and
Exhibit
B
to
Appendix
B
to
this
Part
40
CFR
75.21
and
Appendix
B to
40
CFR
75
are
fully
met,
the
monitoring
system
will
be
exempt
from
the
initial
certification
requirements
of
this
Section.
2)
The
recertification
provisions
of this
Section
apply
to
an
emissions
monitoring
system
required
by
Section
225.240(a)(1)
exempt
from
initial
certification
requirements
pursuant
to subsection
(a)(1)
of
this
Section.
c)
Initial
certification
and
recertification
procedures
for
EGUs
using
the
mercury
low
mass
emissions
excepted
methodology
pursuant
to
Section
1.15(b) of
Appendix
B
to
this
Part.
40
CFR
75.81(b).
The
owner
or
operator
that
has
elected
to use
the
64
mercury-low-mass-emissions-excepted
methodology
for a qualified
EGU
pursuant
to
Section
1.15(b)
to
Appendix
B
to
this
Part
40
CFR 75.81(b)
must
meet
the
applicable
certification
and
recertification
requirements
in
Section
1.15(c) through
(f)
to
Appendix
B
to
this
Part.
40
CFR
75.81(c)
through
(f),
incorporated
by
reference
in
Section
225.140.
d)
Certification
Applications.
The
owner
or
operator
of
an
EGU must
submit
an
application
to
the
Agency
within
45
days after
completing
all
initial
certification
or
recertification
tests
required
pursuant
to
this
Section,
including
the
information
required
pursuant
to
40
CFR
75.63,
incorporated
by
reference
in
Section
225.140.
(Source:
Amended
at
effective
Section
225.260
Out
of
Control
Periods
and
Data
Availability
for
Emission
Monitors
a)
Out of
control
periods
must
be
determined
in
accordance
with
Section
1.7
of
Appendix
B.
ba)
Monitor
data
availability
must
be
determined
on
a
calendar
quarter
basis
in
accordance
with
Section
1.8
of
Appendix
B
Whenever
any
emissions
monitoring
system
fails
to
meet
the
quality
assurance
and
quality
control
requirements
or
data validation
requirements
of
40
CFR
75,
incorporated
by
reference in
Sectim
225.140,
data must
be
substituted
using
the
applicable
missing
data
procedures-in
Subparts
D
and
I
of
40
CFR 75,
each
incorporated
by
reference
in
Section
225.140.
following
initial
certification
of
the
required
CO
2
Q
2
,
flow
monitor,
or
mercury
concentration
or
moisture
monitoring
system(s)
at
a
particular
unit
or
stack
location.
Compliance
with
the
percent
reduction
standard
in
Section
225
.230(a)(1)(B)
or
225.237(a)(1)(B)
or
the
emissions
concentration
standard
in
Section
225.230(a)(1)(A)
or
225.237(a)(l)(A)
can
only be
demonstrated
if
the
monitor
data availability
is
equal
to
or
greater than
75
percent
that
is,
quality
assured
data
must
be
recorded
by
a
certified
primary
monitor,
a
certified
r6dundant
or
non-redundant
backup
monitor,
or
reference
method
for
that
unit
at
least
75
percent
of
the
time
the
unit
is
in
operation.
cb)
Audit
Decertification.
Whenever
both
an
audit
of
an
emissions
monitoring
system
and
a
review
of
the
initial
certification
or
recertification
application
reveal
that
any emissions
monitoring
system
should
not
have
been
certified
or
recertified
because
it
did
not
meet
a
particular
performance
specification
or
other
requirement
pursuant
to
Section
225.250
or
the
applicable
provisions
of
Appendix
B
to
this
Part,
40
CFR
75,
both
at
the
time
of
the
initial
certification
or
recertification
application
submission
and
at
the
time
of
the
audit,
the
Agency
must
issue
a
notice
of
disapproval
of
the
certification
status
of
such
monitoring
system.
For
the
purposes
of
this
subsection
(çh),
an
audit
must be
either
a
field
audit or
an
audit
of
any
information
submitted
to
the
Agency.
By
issuing
the
notice
of
disapproval,
the
Agency
revokes
prospectively
the
certification
status
of
the
emissions
monitoring
system.
The
data
measured
and recorded
by
the
65
monitoring
system
must
not
be
considered
valid
quality-assured
data
from
the
date
of issuance
of the
notification
of
the
revoked certification
status
until
the
date
and
time
that
the
owner
or
operator
completes
subsequently approved
initial
certification
or
recertification
tests
for
the
monitoring system.
The
owner
or
operator
must
follow
the
applicable
initial
certification
or recertification
procedures
in
Section
225.250
for
each
disapproved monitoring
system.
(Source:
Amended
at
effective
Section
225.26
1
Additional
Requirements
to Provide
Heat
Input
Data
The
owner
or
operator
of
an
EGU
that
monitors
and
reports
mercury
mass
emissions
using
a
mercury
concentration
monitoring
system
and
a
flow
monitoring
system
must
also
monitor
and
report
the heat
input
rate
at
the
EGU
level
using
the
procedures
set
forth
in
Appendix
B
to
this
40
CFR
75,
incorporated
by
reference
in Section
225.140.
(Source: Amended
at
effective
Section
225.263
Monitoring
of Gross
Electrical
Output
The
owner
or
operator
of
an
EGU
complying
with
this
Subpart
B by
means
of
Section
225.230(a)(1)
or
using
electrical
output
(Of)
and
complying
by
means
of
Section
225.230(b)
or
(d)
or
Section
225.232
must
monitor
gross
electrical
output
of
the
associated
generator(s)
in
MWh
on an
hourly
basis.
(Source:
Amended
at
effective
Section
225.265
Coal
Analysis
for
Input
Mercury
Levels
a)
The
owner
or operator
of
an
EGU
complying
with
this
Subpart
B
by
means
of
Section 225.230(a)(j))
ef-using
input
mercury
levels
(Ii)
and
complying
by
means
of
Section
225.230(b)
or(d)
or
Section
225.232,
electing
to
comply
with
the
emissions
testing,
monitoring,
and
recordkeeping
requirements
under
Section
225.239,
or
demonstrating
compliance
under
Section
225.233
or Sections
225.291
through 225.299
must
fulfill
the
following
requirements:
1)
Perform
daily
sampling
of the
coal
combusted
in
the EGU
for
mercury
content.
The
owner
or
operator
of
such
EGU
must
collect
a minimum
of
one
21b:
grab
sample
per
day
of
operation
from
the
belt
feeders
anywhere
between
the
crusher
house
or
breaker
building
and
the
boiler.
The
sample
must
be
taken
in
a
manner
that
provides
a
representative
mercury
content
for
the
coal
burned
on
that
day.
EGUs
complying
by
means
of
Section
225.233
or
Sections
225.29
1 through
225.299
of
this
Subpart
must
perform
such
coal
sampling
at
least
once
per
month;
EGUs
complying
by
means
of
the
emissions
testing,
monitoring,
and
recordkeeping
requirements
under
Section
225.239
must
perform
such
coal
sampling
66
according
to
the
schedule
provided
in
Section
225.239(e)(3) of
this
Subpart;
all
other
EGUs
subject to
this
requirement
must
perform
such
coal
sampling
on
a daily
basis.
2)
Analyze
the
grab
coal sample
for
the
following:
A)
Determine
the
heat
content
using
ASTM
D5865-04
or
an
equivalent
method
approved
in
writing
by
the
Agency.
B)
Determine
the
moisture
content
using
ASTM
D3173-03
or
an
equivalent
method
approved
in
writing
by
the
Agency.
C)
Measure
the
mercury
content
using
ASTM
D6414-0l,
ASTM
D3684-01,
or
an
equivalent
method approved
in
writing
by
the
Agency.
3)
The
owner
or operator
of
multiple
EGUs
at
the
same
source
using
the
same
crusher
house
or
breaker
building may take
one
sample
per
crusher
house
or
breaker
building,
rather
than
one
per
EGU.
4)
The
owner
or
operator
of
an
EGU
must
use
the
data
analyzed
pursuant
to
subsection
(b)
of
this
Section
to
determine
the
mercury
content
in
terms
of
lbs/trillion
Btu.
b)
The
owner
or
operator
of
an
EGU that
must
conduct
sampling
and
analysis
of
coal
pursuant
to
subsection
(a)
of
this
Section
must
begin
such
activity
by
the
following
date:
1)
If
the
EGU
is
in
daily
service,
at
least
30
days
before
the
start
of
the
month
for
which
such
activity
will
be
required.
2)
If the
EGU
is
not
in
daily
service,
on
the
day
that
the
EGU
resuines
operation.
(Source:
Amended
at
effective
Section 225
.270
Notifications
The
owner
or
operator
of
a
source with
one
or
more EGUs
must
submit
written
notice
to
the
Agency
according
to
the
provisions
in
40
CFR
75.61,
incorporated
by
reference
in
Section
225.140
(a
a
segment
of
40
CFR
75),
for
each
EGU
or
group
of
EGUs
monitored
at a
common
stack
and
each
non-EGU
monitored
pursuant
to
Section
1.16(b)(2)(B
of
Appendix
B
to
this
Part.
40
CFR
75.82(b)(2)(ii),
incorporated
by
reference
in
Section
225.140.
(Source:
Amended
at
effective
67
Section
225.290
Recordkeeping
and
Reporting
a)
General Provisions.
1)
The
owner
or operator
of
an
EGU
and
its
designated
representative
must
comply
with
all
applicable
recordkeeping
and
reporting
requirements
in
this
Section
and
with
all
applicable
recordkeeping
and
reporting
requirements
of
Section
1.18
to Appendix
B
to
this
Part.
40
CFR
75.84,
incorporated
by
reference
in
Section
225.140.
2)
The
owner
or
operator
of
an
EGU
must
maintain
records
for
each
month
identifying
the
emission
standard
in
Section
225.230(a)
or
225.237(a)
of
this
Section
with
which
it is
complying
or
that
is applicable
for
the
EGU
and
the
following
records
related
to
the
emissions
of
mercury
that
the
EGU
is
allowed
to
emit:
A)
For
an
EGU
for
which
the
owner
or
operator
is
complying
with
this
Subpart
B
by
means
of
Section
225.230(a)(12
or
225.237(a)(1)(B)
or
using
input
mercury
levels
to
determine
the
allowable
emissions
of
the
EGU,
records
of
the
daily
mercury
content
of
coal
used
(lbs/trillion
Btu)
and
the
daily
and
monthly
input
mercury
(lbs),
which
must
be kept
in the
file
pursuant
to
Section
1.18(a)
of
Appendix
B to
this
Part.
40
CFR
75.84(a).
B)
For
an
EGU
for
which
the
owner
or
operator
of an
EGU
complying
with
this
Subpart
B
by
means
of
Section
225.230(a)(l)(
or
225
.237(a)(
1
)(A)
or
using
electrical
output
to
determine
the
allowable
emissions
of
the
EGU,
records
of
the
daily
and
monthly
gross
electrical
output
(GWh),
which
must
be
kept
in the
file
required
pursuant
to
Section
1.18(a)
of
Appendix
B
to
this
Part-40
CFR
75.84(a).
3)
The
owner
or
operator
of
an
EGU
must
maintain
records
of
the
following
data
for
each
EGU:
A)
Monthly
emissions
of
mercury
from
the
EGU.
B)
For
an
EGU
for
which
the
owner
or operator
is
complying
by
means
of
Section
225.230(b)
or
(d)
of
this
Subpart
B,
records
of
the
monthly
allowable
emissions
of
mercury
from
the
EGU.
4)
The
owner or
operator
of
an
EGU
that
is
participating
in
an Averaging
Demonstration
pursuant
to
Section
225.232
of
this
Subpart
B must
maintain
records
identifying
all
sources
and
EGUs
covered
by
the
Demonstration
for
each
month
and,
within
60 days
after
the
end
of
each
calendar
month,
calculate
and
record the
actual
and
allowable
mercury
68
emissions
of
the
EGU
for
the
month
and
the
applicable
12-month
rolling
period.
5)
The
owner
or
operator
of
an
EGU
must
maintain
the
following
records
related
to
quality
assurance
activities
conducted
for
emissions
monitoring
systems:
A)
The
results
of
quarterly
assessments
conducted
pursuant
to
Section
section
2.2
of
Exhibit
B
to
Appendix
B to
this
Part
Appendix
B
of
40
CFR
75,
incorporated
by
reference
in
Section
225.140;
and
B)
Daily/weekly
system
integrity
checks
pursuant
to
Section
section
2.6
of
Exhibit
B
to
Appendix
B
to
this
Part
Appendix
B
of
40
CFR
75,
incorporated
by
reference
in
Section
225.140.
6)
The
owner
or
operator
of
an
EGU
must
maintain
an
electronic
copy
of
all
electronic
submittals
to
the
USEPA
pursuant
to
Section
1.18(f) to
Appendix
B
to
this
Part.
40
CFR
75.84(f),
incorporated
by
reference
in
Section
225.140.
7)
The
owner
or
operator
of
an
EGU
must retain
all
records
required
by
this
Section
at
the
source
unless
otherwise
provided
in
the
CAAPP
permit
issued
for
the
source
and
must
make
a
copy
of
any
record
available
to
the
Agency
upon
request.
b)
Quarterly Reports.
The
owner
or
operator
of
a
source
with
one
or
more
EGUs
must
submit quarterly
reports
to
the
Agency as
follows:
1)
These
reports
must
include
the
following
infonnation
for
operation
of
the
EGUs
during
the
quarter:
A)
The
total
operating
hours of
each
EGU
and
the
mercury
CEMS,
as
also
reported
in
accordance
with
Appendix
B
to
this
Part.
40-CFR
75,
incorporated
by
reference
in
Section
225.140.
B)
A
discussion
of
any
significant
changes
in
the
measures
used
to
control
emissions
of
mercury
from
the
EGUs
or
the
coal
supply
to
the
EGUs, including
changes
in
the
source
of
coal.
C)
Summary
information
on
the
performance
of
the
mercury
CEMS.
When
the
mercury
CEMS was
not
inoperative,
repaired,
or
adjusted,
except
for
routine zero
and
span
checks,
this
must
be
stated
in
the
report.
D)
If the
CEMS
downtime
was
more
than
5.0
percent
of
the
total
operating
time
for
the
EGU:
the
date
and
time
identifying
each
69
period
during
which
the
CEMS
was
inoperative,
except
for
routine
zero
and
span
checks;
the
nature
of
CEMS
repairs
or
adjustments
and
a
summary
of
quality
assurance
data
consistent
with
Appendix
B
to
this
Part
40
CFR
75,
i.e.,
the
dates
and
results
of
the
Linearity
Tests
and
any
RATAs
during
the
quarter;
a
listing
of
any
days
when
a
required
daily
calibration
was not
performed;
and
the
date
and
duration
of
any
periods
when
the
CEMS
was
out-of-control
as
addressed
by
Section
225.260.
B)
Recertification
testing
that
has
been
performed
for
any
CEMS
and
the
status
of
the
results.
2)
The
owner
or
operator
must
submit
each quarterly
report
to
the
Agency
within
45
days following
the
end
of
the
calendar
quarter
covered
by
the
report.
c)
Compliance
Certification.
The
owner
or
operator
of
a
source
with
one
or
more
EGUs
must
submit
to
the
Agency
a
compliance
certification
in
support
of
each
quarterly
report
based
on
reasonable
inquiry of
those
persons
with primary
responsibility
for
ensuring
that
all
of
the
EGUs’
emissions
are
correctly
and
fully
monitored.
The
certification
must
state:
1)
That
the
monitoring
data
submitted
were
recorded
in
accordance
with
the
applicable
requirements
of
this
Section,
Sections
225.240
through
225
.270
and
Section
225.290
of
this
Subpart
B,
and
Appendix
B
to
this
Part
40
CFR 75,
including
the
quality
assurance
procedures
and
specifications;
and
2)
For an
EGU
with
add-on
mercury
emission
controls,
a
flue
gas
desulfurization
system,
a
selective
catalytic
reduction
system,
or
a
compact
hybrid
particulate
collector
system
-and-for
all
hours
where
mercury
data
is missing
that:
are
substituted
in
accoidance
with
40
CFR
75.34(a)(l):
A)
That:
Ai)
The mercury
add-on
emission
controls,
flue
gas
desulfurization
system,
selective
catalytic
reduction
system,
or
compact
hybrid
particulate
collector
system was
operating
within
the
range
of
parameters
listed
in
the
quality
assurance/quality
control
program
pursuant
to
Exhibit
B
to
Appendix
B to
this
Part
Appendix
B
to
40
CFR75;or
i4)
With
regard
to
a flue
gas
desulfurization
system
or
a
selective
catalytic
reduction
system,
quality-assured
SO
2
emission
data
recorded
in
accordance
with Appendix
B
to
this
Part
40
CFR
75
document
that
the
flue
gas
desulfurization
system
was
operating
properly,
or
quality-assured
NOx
emission
data recorded
in
70
accordance
with
Appendix
B
to
this
Part
40 CFR
75
document
that
the
selective
catalytic
reduction
system
was
operating
properly,
as
applicable;
and
B)
The
substitute
data
values
do
not
systematically
underestimate
mercury
emissions.
d)
Annual
Certification
of Compliance.
1)
The
owner
or operator
of
a
source
with
one
or
more
EGUs
subject
to this
Subpart
B
must
submit
to
the
Agency
an
Annual
Certification
of
Compliance
with
this
Subpart
B
no
later
than
May
1
of
each
year
and
must
address
compliance
for
the previous
calendar
year.
Such
certification
must
be
submitted
to
the
Agency,
Air
Compliance
and
Enforcement
Section,
and
the
Air
Regional
Field
Office.
2)
Annual
Certifications
of
Compliance
must
indicate
whether
compliance
existed
for
each
EGU
for
each
month
in the
year
covered
by
the
Certification
and
it must
certify
to
that
effect.
In
addition,
for
each
EGU,
the
owner
or
operator
must
provide
the
following
appropriate
data
as
set
forth
in
subsections
(d)(2)(A)
through
(d)(2)(E) of
this
Section,
together
with the
data
set
forth
in
subsection
(d)(2)(F)
of
this
Section:
A)
If
complying
with
this
Subpart
B
by
means
of Section
225.230(a)(1)(A)
or
225.237(a)(l)(A):
i)
Actual
emissions
rate,
in
lbIGWh,
for
each
1 2-month
rolling
period
ending
in
the
year
covered
by
the
Certification;
ii)
Actual
emissions,
in
lbs, and
gross
electrical
output,
in
GWh,
for each
12-month
rolling
period
ending
in
the
year
covered
by
the
Certification;
and
iii)
Actual
emissions,
in
lbs. and
gross
electrical
output,
in
GWh,
for
each
month
in the
year
covered
by
the
Certification
and
in the
previous
year.
B)
If complying
with
this
Subpart
B
by
means
of
Section
225.230(a)(1)(B)
or
225.237(a)(1)(B):
i)
Actual
control
efficiency
for emissions
for each
12-month
rolling
period
ending
in
the
year
covered
by
the
Certification,
expressed
as a
percent;
71
ii)
Actual
emissions,
in
ibs,
and
mercury
content
in
the
fuel
fired
in
such
EGU,
in
ibs,
for
each
12-month
rolling
period
ending
in
the
year
covered
by
the
Certification;
and
iii)
Actual emissions,
in ibs,
and
mercury
content
in
the
fuel
fired
in
such
EGU,
in
ibs,
for
each
month
in
the
year
covered
by
the
Certification
and
in the
previous
year.
C)
If
complying
with
this
Subpart
B
by
means of
Section
225.230(b):
i)
Actual
emissions
and
allowable
emissions
for
each
12-
month
rolling
period
ending
in
the
year
covered
by
the
Certification;
and
ii)
Actual
emissions
and
allowable
emissions,
and
which
standard
of
compliance
the
owner
or
operator
was
utilizing
for
each
month
in
the
year
covered
by
the
Certification
and
in
the
previous
year.
D)
If
complying
with
this
Subpart
B
by
means
of
Section
225.230(d):
i)
Actual
emissions
and
allowable
emissions
for
all
EGUs
at
the
source
for
each
12-month
rolling
period ending
in the
year
covered
by
the
Certification;
and
ii)
Actual
emissions
and
allowable
emissions,
and
which
standard
of compliance
the
owner
or
operator
was
utilizing
for
each
month
in
the
year
covered
by
the
Certification
and
in
the
previous
year.
E)
If
complying
with
this
Subpart
B
by
means
of
Section
225.232:
i)
Actual
emissions
and
allowable
emissions
for
all
EGUs
at
the
source
in
an
Averaging
Demonstration
for
each
12-
month
rolling
period
ending
in
the
year
covered
by
the
Certification;
and
ii)
Actual
emissions
and
allowable
emissions,
with
the
standard
of
compliance
the
owner
or
operator
was
utilizing
for
each
EGU
at
the
source
in
an
Averaging
Demonstration
for
each
month
for
all
EGUs
at
the
source
in
an
Averaging
Demonstration
in
the
year
covered
by
the
Certification
and
in
the
previous
year.
72
F)
Any
deviations,
data
substitutions,
or
exceptions
each
month
and
discussion
of
the
reasons
for
such
deviations,
data
substitutions,
or
exceptions.
3)
All
Annual
Certifications
of
Compliance
required
to
be
submitted
must
include
the
following
certification
by
a
responsible
official:
I
certify under
penalty
of
law
that
this
document
and
all
attachments
were
prepared
under
my
direction
or
supervision
in
accordance
with
a
system
designed
to
assure
that
qualified
personnel
properly
gather
and
evaluate
the
information
submitted.
Based
on
my
inquiry
of
the
person
or
persons
directly
responsible
for
gathering
the
information,
the
information
submitted
is,
to
the
best
of
my
knowledge
and
belief,
true,
accurate,
and
complete.
I am
aware
that
there
are
significant
penalties
for
submitting
false
information,
including
the
possibility
of
fine
and
imprisonment
for
knowing
violations.
4)
The
owner
or
operator
of
an
EGU
must
submit
its
first
Annual
Certification
of Compliance
to
address
calendar
year
2009
or the
calendar
year
in
which
the
EGU
commences
commercial
operation,
whichever
is
later.
Notwithstanding
subsection
(d)(2)
of
this
Section,
in
the
Annual
Certifications
of
Compliance
that
are
required
to
be
submitted
by
May
1,
2010,
and
May 1,
2011, to
address
calen4ar
years
2009
and
2010,
respectively,
the
owner or
operator
is
not
required
to
provide
12-month
rolling
data
for
any
period
that
ends
before
June
30,
2010.
e)
Deviation
Reports.
For
each
EGU,
the
owner
or
operator
must
promptly
notify
the
Agency
of
deviations
from
requirements
of
this
Subpart
B.
At
a
minimum,
these
notifications
must
include
a description
of
such deviations
within
30
days
after
discovery
of
the
deviations,
and
a
discussion
of
the
possible
cause
of
such
deviations,
any
corrective
actions,
and
any
preventative
measures
taken.
f)
Quality
Assurance
RATA
Reports.
The
owner
or operator
of
an
EGU
must
submit
to
the
Agency,
Air
Compliance
and
Enforcement
Section,
the
quality
assurance
RATA
report for
each
EGU
or
group
of
EGUs
monitored
at
a
common
stack
and
each
non-EGU
pursuant
to Section
1.16(b)(2)(B) of
Appendix
B to
this
40
CFR 75.82(b)(2)(ii),
incorporated
by
reference
in
Section 225.140,
within
45
days
after
completing
a
quality
assurance
RATA.
(Source:
Amended
at
effective
ireatmuiit
4ercurv
Allowances
Any
mercury
allowances
allocated
to
the
Agency
by
the
USEPA
must
be
treated
as
follows:
73
a)
No
such
allowances
may
be
allocated
to
any
owner
or
operator
of an
EGU
or
other
sources
of
mercury
emissions
into
the
atmosphere
or
discharges
into
the
wnterg
of
the
State.
by
the
USEPA
to
the
State.
At
,l.
instruct
the
USEPA
to
retire
(Source:
Repealed
at
effective
Section
225.291
Combined
Pollutant
Standard:
Purpose
The
purpose
of
Sections
225.291
through
225.299
(hereinafter
referred
to as
the
Combined
Pollutant
Standard
(“CPS”))
is
to
allow
an alternate
means
of
compliance
with
the
emissions
standards
for
mercury
in
Section
225.230(a)
for
specified
EGUs
through
permanent
shut-down,
installation
of ACT,
and
the
application
of
pollution
control
technology
for
and
SO
2
emissions
that
also
reduce
mercury
emissions
as a
co-benefit
and
to
establish
permanent
emissions
standards
for
those
specified
EGUs.
Unless
otherwise
provided
for
in the
CPS,
owners and
operators
of those
specified
EGUs
are
not
excused
from
compliance
with
other
applicable
requirements
of
Subparts
B,
C,
D,
and
E.
(Source:
Added
at
effective
Section
225.292
Applicability
of
the
Combined
Pollutant
Standard
a)
As
an
alternative
to
compliance
with
the
emissions
standards
of
Section
225.230(a),
the
owner
or
operator
of
specified EGUs in
the
CPS
located
at Fisk,
Crawford,
Joliet,
Powerton,
Waukegan,
and
Will
County
power
plants
may
elect
for
all
of
those
EGUs
as
a
group
to
demonstrate
compliance
pursuant
to
the
CPS,
which
establishes
control
requirements
and
emissions
standards
for
NO,
1
,
PI’j,
$,
and
mercury.
For
this
purpose,
ownership
of
a
specified
EGU
is
determined
based
on
direct
ownership,
by
holding
a
majority
interest
in
a
company
that
owns
the
EGU
or
EGUs, or
by
the
common
ownership
of
the
company
that
owns
the
EGU,
whether
through
a
parent-subsidiary
relationship,
as
a
sister
corporation,
or
as
an
affiliated
corporation
with
the
same
parent
corporation,
provided
that
the
owner
or
operator
has
the
right
or
authority
to
submit
a CAAPP
application
on
behalf
of
the
EGU.
b)
A
specified
EGU
is
a coal-fired
EGU
listed
in
Appendix
A,
irrespective
of
any
subsequent
changes
in
ownership
of the
EGU
or
power
plant,
the
operator,
unit
designation,
or
name
of
unit.
c)
The
owner
or
operator
of
each
of
the
specified EGUs
electing
to
demonstrate
compliance
with
Section
225.230(a)
pursuant
to
the
CPS
must
submit
an
application
for
a CAAPP permit
modification
to
the
Agency,
as
provided
for
in
Section
225.220,
that
includes
the
information
specified
in Section
225.293
that
b)
,•
/
f-,pnfl,
r
tn,,
fly
hold
all
• the
end
of each
calendar
year,
the
Agency
permanently
all
such
allowances.
iiowances
allocatea
74
clearly
states
the
owner’s
or
operator’s
election
to
demonstrate
compliance
with
Section
225.230(a)
pursuant
to
the
CPS.
d)
If an
owner
or
operator
of
one
or
more
specified
EGUs
elects
to
demonstrate
compliance
with
Section
225.230(a)
pursuant
to
the
CPS,
then
all
specified
EGUs
owned
or
operated
in
Illinois
by
the
owner
or
operator
as
of
December
31,
2006,
as defined
in
subsection
(a)
of
this
Section,
are
thereafter
subject
to the
standards
and
control
requirements
of the
CPS.
Such
EGUs
are
referred
to
as
a
Combined
Pollutant
Standard
(CPS)
group.
e)
If an
EGU
is
subject
to the
requirements
of this
Section,
then
the
requirements
apply
to
all
owners
and
operators
of
the
EGU,
and
to
the
CAIR
designated
representative
for
the EGU.
(Source:
Added
at
effective
Section
225.293
Combined
Pollutant
Standard:
Notice
of
Intent
The
owner
or operator
of
one
or
more
specified
EGUs
that
intends
to comply
with
Section
225
.230(a)
by
means
of
the
CPS
must
notify
the
Agency
of its
intention
on or
before
December
31,
2007.
The
following
information
must
accompany
the
notification:
a)
The
identification
of
each
EGU
that
will
be
complying
with
Section
225.230(a)
pursuant
to the
CPS,
with
evidence
that
the
owner
or
operator
has
identified
all
specified
EGUs
that
it
owned
or operated
in
Illinois
as
of December
31,
2006,
and
which
commenced
commercial
operation
on
or
before
December
31,
2004;
b)
If an
EGU
identified
in subsection
(a)
of
this
Section
is also
owned
or
operated
by
a person
different
than
the
owner
or operator
submitting
the
notice
of
intent,
a
demonstration
that
the
submitter
has
the
right
to commit
the EGU
or
authorization
from
the
responsible
official
for
the
EGU
submitting
the
application:
and
c)
A
summary
of the
current
control
devices
installed
and
operating
on
each
EGU
and
identification
of
the
additional
control
devices
that
will
likely
be
needed
for
each
EGU
to
comply
with
emission
control
requirements
of
the CPS.
(Source:
Added
at
effective
Section
225.294
Combined Pollutant
Standard:
Control
Technology
Requirements
and
Emissions Standards
for
Mercury
a
Control
Technology
Requirements
for Mercury.
1)
For
each
EGU
in
a CPS
group
other
than
an
EGU
that
is
addressed
by
subsection
(b)
of
this
Section,
the
owner
or
operator
of
the
EGU
must
install,
if
not
already
installed,
and
properly
operate
and
maintain,
by
the
75
dates
set
forth
in
subsection
(a)(2)
of
this
Section,
ACT
equipment
complying
with
subsections (g),
(h),
(i),
(j),
and
(k)
of
this
Section,
as
applicable.
2)
By
the
following
dates,
for
the
EGUs listed
in
subsections
(a)(2)(A)
and
(B),
which
include
hot
and
cold
side
ESPs,
the
owner
or
operator
must
install,
if
not
already
installed,
and
begin
operating
ACI
equipment
or
the
Agency
must
be
given
written
notice that
the
EGU
will
be
shut
down
on
or
before
the
following
dates:
A)
Fisk
19,
Crawford
7,
Crawford
8,
Waukegan
7,
and
Waukegan
8
on
or
before
July
1,
2008;
and
Powerton
5,
Powerton
6,
Will
County
3,
Will
County
4.
Joliet
&
Joliet
7,
and
Joliet
8
on
or
before
July
1,
2009.
b)
Notwithstanding
subsection
(a)
of
this
Section, the
following
EGUs are
not
required
to
install
ACT
equipment
because
they
will
be
permanently
shut
down,
as
addressed
by
Section
225
.297,
by
the
date
specified:
1)
EGUs
that
are
required
to
permanently
shut
down:
A)
On
or
before
December
31,
2007, Waukegan
6;
and
B)
On
or
before
December
31,
2010,
Will
County
1
and
Will
Counjy
2.
Any
other
soecified
EGU
that
is
nermanentlv
shut
down
by
December
31
2010.
c)
Beginning
on
January
1,
2015,
and
continuing
thereafter,
and
measured
on
a
rolling 12-month
basis
(the
initial
period
is
January
1,
2015,
through
December
31,
2015,
and,
then,
for
every 12-month
period
thereafter),
each
specified
EGU,
except Will
County
3,
shall
achieve
one
of
the
following
emissions
standards:
1)
An
emissions
standard
of 0.00
lbs
rnercury/GWh
gross
electrical
outnut:
or
2
A
minimum
90
nercent
reduction
of
innut
mercury.
d)
Beginning
on
January
1,
2016,
and
continuing
thereafter,
Will
County
3
shall
achieve the
mercury
emissions
standards
of
subsection
(c)
of
this
Section
measured
on
a
rolling
12-month
basis
(the
initial
period
is January
1,
2016,
through
December
31,
2016,
and,
then,
for
every
12-month
period
thereafter).
Comoliance
with
Emission
Standards
B)
2)
76
1)
At
any
time
prior
to
the
dates
required
for
compliance
in subsections
(c)
and
(d)
of
this
Section,
the
owner
or
operator
of
a
specified
EGU,
upon
notice
to
the
Agency,
may
elect
to
comply
with
the
emissions
standards
of
subsection
(c)
of
this
Section
measured
on
either:
A)
a
rolling
12-month
basis,
or;
B)
semi-annual
calendar
basis
pursuant
to
the
emissions
testing
requirements
in
Section
225.239(c),
(d),
(e),
(f)(l)
and
(2),
(h)(
and
(i)(3)
and
(4)
of
this
Subpart
until
June
30,
2012.
2)
Once
an
EGU
is
subject
to
the
mercury
emissions
standards
of
subsection
(c)
of
this
Section,
it
shall
not
be
subject
to
the
requirements
of
subsections
(g),
(h),
(i),(j)
and
(k)
of
thisSection.
f)
Compliance
with
the
mercury
emissions
standards
or reduction
requirement
of
this
Section
must
be
calculated
in
accordance
with
Section
225.230(a)
or
(b).
g)
For
each
EGU
for
which
injection
of
halogenated
activated
carbon
is
required
hi
subsection
(a)(
1)
of
this
Section,
the
owner
or operator
of
the
EGU
must
iiieç
halogenated
activated
carbon in
an
optimum
manner,
which,
except
as
provided
in
subsection
(h)
of
this
Section,
is
defined
as
all
of
the
following:
1)
The
use
of
an
injection
system
for
effective
absorption
of mercury,
considering
the
configuration
of
the
EGU
and
its
ductwork;
The
injection
of
halogenated
activated
carbon
manufactured
by
Aistom,
Norit,
or
Sorbent
Technologies,
or
Calgon Carbon’s
FLUEPAC
MC
Plus,
or
the
injection
of
any
other
halo
genated
activated
carbon
or
sorbent
that
the
owner
or
operator
of
the
EGU
has
demonstrated
to
have
similar
or
better
effectiveness
for
control
of
mercury
emissions;
and
--
----
--
-
A)
For
an
EGU
firing
subbituminous
coal,
5.0
lbs
per
million
actual
cubic
feet
or,
for
any
cyclone-fired
EGU
that
will
install
a
scrubber
and
baghouse
by
December
31,
2012,
and
which
already
meets
an
emission
rate
of
0.020
lb
mercuryfGWh
gross
electrical
output
or
at
least
75
percent
reduction
of
input
mercury,
2.5
lbs
per
million
actual
cubic
feet;
B)
For
an
EGU
firing
bituminous
coal,
10.0
lbs
per
million
actual
cubic
feet
or,
for
any
cyclone-fired
EGU
that
will
install
a
scrubber
and
baghouse
by
December
31,
2012,
and
which
already
meets
an
emission
rate
of
0.020 lb
mercury/GWh
gross
electrical
output
or
2)
3
The
iniection
of
sorbent
at
the
following
minimum
rates
as
annlicah1e
77
at
least
75
percent
reduction
of
input
mercury,
5.0
lbs
per
million
actual
cubic
feet;
C)
For
an
EGU firing
a
blend
of
subbituminous
and
bituminous
coal,
a
rate
that is
the
weighted average
of
the
rates
specified
in
subsections
(g)(3)(A) and
(B),
based
on
the
blend
of
coal
being
fired;
or
D)
A
rate
or
rates
set
lower
by
the
Agency,
in
writing,
than
the
rate
specified in
any
of
subsection
(g)(3)(A’,
(B),
or
(C)
of
this
Section
on
a
unit-specific
basis, provided
that
the
owner
or
operator
of
the
EGU
has
demonstrated
that
such
rate
or
rates
are
needed
so
that
carbon
injection
will
not
increase
particulate
matter
emissions
or
opacity
so
as
to
threaten
noncompliance
with
applicable
requirements
for
particulate
matter
or
opacity.
4)
For
purposes
of
subsection
(g)(3)
of
this Section,
the
flue
gas
flow
rate
must
be
determined
for
the
point
sorbent
injection;
provided
that
this
flow
rate
may
be
assumed
to
be
identical
to
the
stack
flow
rate
if
the
gas
temperatures
at
the
point
of
injection
and
the
stack
are
normally
within
1000
F,
or
the
flue
gas
flow
rate
may otherwise
be
calculated
from
the
stack
flow
rate,
corrected
for
the
difference
in
gas
temperatures.
h)
The
owner
or
operator
of
an
EGU
that
seeks
to
operate
an
EGU
with
an
activated
carbon
injection
rate
or
rates
that
are
set
on
a
unit-specific
basis
pursuant
to
subsection
(g)(3)(D)
of
this
Section
must
submit
an
application
to
the
Agency
proposing
such
rate
or
rates,
and
must
meet
the
requirements
of
subsections
h)(1)
and
(h)(2)
of
this
Section,
subject
to
the
limitations
of
subsections
(h)(3)
and
(h)(4)
of
this
Section:
1)
The application
must
be
submitted
as
an
application
for
a
new
or
revised
federally
enforceable
operation
permit
for
the
EGU,
and
it
must
include
a
summary
of
relevant
mercury
emissions
data
for
the
EGU,
the
unit-
specific
injection rate
or
rates
that
are
proposed,
and
detailed
information
to
support
the
proposed
injection
rate
or
rates;
and
2)
This application
must
be
submitted
no later
than
the
date
that
activated
carbon
must first
be
injected.
For
example, the
owner
or
operator
of
an
EGU that
must
inject
activated
carbon
pursuant
to
subsection
(a)(1)
of
this
Section
must apply
for
unit-specific
injection
rate
or
rates
by
July
1,
2008.
Thereafter,
the
owner
or
operator
may
supplement
its
application;
and
3)
Any decision
of
the
Agency
denying
a
permit
or
granting
a
permit
with
conditions
that
set
a
lower
injection
rate
or
rates
may
be
appealed
to
the
Board
pursuant
to
Section
39
of
the
Act;
and
78
4)
The
owner
or
operator
of
an
EGU
may
operate
at
the
injection
rate
or
rates
proposed
in
its
application
until
a
final
decision
is
made
on
the
application
including
a
final
decision
on
any
appeal
to
the
Board.
i)
During
any
evaluation
of
the
effectiveness
of
a
listed
sorb
ent,
alternative
sorbent,
or
other
technique
to
control
mercury
emissions,
the
owner
or
operator
of
an
EGU
need
not
comply
with
the
requirements
of
subsection
(g)
of
this
Section
for
any
system
needed
to
carry
out
the
evaluation,
as
further
provided
as
follows:
I)
The
owner
or
operator
of
the
EGU
must
conduct
the
evaluation
in
accordance
with
a formal
evaluation
program
submitted
to
the
Agency
at
least
30
days
prior
to
commencement
of
the
evaluation:
2)
The
duration
and
scope
of
the
evaluation
may
not
exceed
the
duration
and
. scope
reasonably
needed
to
complete
the
desired
evaluation
of
the
alternative
control
techniques,
as
initially
addressed
by
the
owner
or
operator
in
a
support
document
submitted
with
the
evaluation
program;
and
3)
The
owner
or
operator
of
the
EGU must
submit
a report
to
the
Agency
no
later
than
30
days
after
the
conclusion
of
the
evaluation
that
describes
the
evaluation
conducted
and
which
provides
the
results
of
the
evaluation;
and
4)
If the
evaluation
of
alternative
control
techniques
shows
less
effective
control
of
mercury
emissions
from
the
EGU than
was
achieved
with
the
principal
control techniques,
the
owner
or
operator
of
the
EGU
must
resume
use
of
the
principal
control
techniques.
If
the
evaluation
of
the
alternative
control
technique
shows
comparable
effectiveness
to
the
principal
control technique,
the
owner
or
operator
of
the
EGU
may
either
continue
to
use
the
alternative
control
technique
in
a
manner
that
is
at
least
as
effective
as
the
principal
control
technique
or
it
may resume
use
of
the
principal
control
technique.
If
the
evaluation
of
the
alternative
control
technique
shows
more effective
control
of
mercury
emissions
than
the
control
technique,
the
owner
or
operator
of
the
EGU
must
continue
to
use
the
alternative
control technique
in
a
manner
that
is
more
effective
than
the
principal
control
technique,
so
long
as
it
continues
to
be
subject
to this
Section.
j)
In
addition
to
complying
with
the
applicable recordkeeping
and
monitoring
requirements
in
Sections
225.240
through
225.290,
the
owner
or
operator
of
an
EGU that
elects
to
comply
with
Section
225.23
0(a)
by
means
of
the
CPS
must
also comply
with
the
following
additional
requirements:
1)
For the
first
36
months
that
injection
of
sorbent
is
required,
it
must
maintain
records
of
the
usage of
sorbent,
the
exhaust
gas
flow
rate
from
79
the
EGU,
and
the
sorbent
feed
rate,
in
pounds
per
million
actual
cubic
feet
of
exhaust
gas
at
the
injection
point,
on
a
weekly
average:
2)
After
the
first
36
months
that
injection
of
sorbent
is
required,
it
must
monitor
activated
sorbent
feed
rate
to
the
EGU,
flue
gas
temperature
at
the
point
of
sorbent
injection,
and
exhaust
gas
flow rate
from
the
EGU,
automatically
recording
this
data
and
the
sorbent
carbon
feed
rate,
in
pounds
per
million
actual
cubic
feet
of
exhaust
gas
at
the
injection
point,
on
an
hourly
average:
and
3)
If
a
blend
of
bituminous
and
subbituminous
coal
is
fired
in
the
EGU,
it
must
keep
records
of
the
amount
of
each type
of
coal burned
and
the
required
injection
rate
for
injection
of
activated
carbon
on
a
weekly
basis.
k)
In
addition
to
complying
with
the
applicable
reporting
requirements
in
Sections
225.240
through
225.290,
the
owner
or
operator
of
an
EGU
that
elects
to
comply
with
Section
225.230(a)
by
means
of
the
CPS
must
also
submit
quarterly
reports
for
the
recordkeeping
and
monitoring
conducted
pursuant
to
subsection
(j)
of
this
Section.
1)
As
an
alternative
to
the
CEMS
monitoring,
recordkeeping,
and
reporting
requirements
in
Sections
225.240
through
225.290,
the
owner
or
operator
of
an
EGU may
elect
to
comply
with
the
emissions
testing,
monitoring,
recordkeeping,
and reporting
requirements
in
Section
225
.23
9(c),
(ci),
(e),
(f)(1)
and
(2),
(h)(2),
(i)(3)
and
(4),
and
(fl(1).
(Source:
Added
at
effective
Section
225.295
Combined
Pollutant
Standard:
Emissions
Standards
for
NO
and
SO
2
a)
Emissions
Standards
for
NOand
Reporting
Requirements.
1)
Beginning
with
calendar
year
2012
and
continuing
in
each
calendar
year
thereafter,
the
CPS group,
which
includes
all
specified
EGUs
that
have
not
been
permanently
shut
down
by
December
31
before
the
applicable
calendar
year,
must
comply
with
a
CPS
group
average
annual
NO
emissions
rate
of
no
more
than 0.11
lbs/mmBtu.
2)
Beginning
with
ozone
season
control
period
2012
and
continuing
in
each
ozone
season control
period (May
1
through
September
30)
thereafter,
the
CPS
group,
which
includes
all
specified
EGUs that
have
not
been
permanently
shut
down
by
December
31
before
the
applicable
ozone
season,
must
comply
with
a CPS
group
average
ozone
season
NO
emissions
rate
of
no
more
than
0.11
lbslnnnBtu.
80
3)
The
owner
or
operator
of
the
specified
EGUs
in the
CPS
group
must
file,
not
later
than
one
year
after
startup
of any
selective
SNCR
on such
EGU,
a
report
with
the
Agency
describing
the
NO
emissions
reductions
that
the
SNCR
has
been
able
to
achieve.
b)
Emissions
Standards
for
SO
2
.
Beginning
in
calendar
year
2013
and
continuing
in
each
calendar
year
thereafter,
the
CPS
group
must
comply
with
the
applicable
CPS
group
average
annual
SO
2
emissions
rate
listed
as
follows:
year
2013
2014
2015
2016
2017
2018
2019
1h/mm1tu
c)
Compliance
with
the
NO
and
SO
2
emissions
standards
must
be
demonstrated
in
accordance
with
Sections
225.3
10,
225.410,
and
225.5
10.
The
owner
or
operator
of
the specified
EGUs
must
complete
the
demonstration
of
compliance
pursuant
to
Section
225.298(c)
before
March
1 of
the
following
year
for
annual
standards
and
before
November
30
of the
particular
year
for ozone
season
control
periods
(May
1 through
September
30)
standards,
by which
date
a compliance
report
must
be
submitted
to the
Agency.
d)
The
CPS
group
average
annual
SO
2
emission
rate,
annual
NO
emission
rate
and
ozone
season
NO
emission
rates
shall
be
determined
as follows:
n
n
ERJSO
or
NO
tons/
(H
i=1
i=1
Where:
SO
=
NO
1
=
crzr
ft44
0.41
0.28
0.195
•
0.15
0.
13
0.11
ER
=
average
annual
or
ozone
season
emission
rate
in
lbs/mmBbtu
of
all
EGUs
in
the
CPS
group.
HI
1
=
heat
input
for
the
annual
or
ozone
control
period
of each
EGU,
in
mmBtu.
—
actual
annual
SO
tons
of each
EGTJ
in the
CPS
group.
actual
annual
or
ozone
season
NO
tons
of
each
EGU
in the
CPS
grouD.
n
=
number
of
EGUs
that
are
in
the CPS
-rnun
i
=
each
EGU
in the
CPS
group.
81
(Source:
Added
at
effective
Section
225.296
Combined
Pollutant
Standard:
Control
Technology
Requirements
for
SOand
PM
Emissions
a)
Control
Technology
Requirements
for
NO
and
SO
2
.
1)
On
or
before
December
31,
2013,
the
owner
or
operator
must
either
permanently
shut
down
or
install
and
have
operational
FGD
equipment
on
Waukegan
7;
2)
On
or
before
December
31,
2014,
the
owner
or
operator
must
either
permanently
shut
down
or
install
and
have
operational
FGD
equipment
on
Waukegan8;
3)
On
or
before
December
31,
2015,
the
owner
or
operator
must
either
permanently
shut
down
or install
and
have
operational
FGD
equipment
on
Fisk
19;
4)
If
Crawford
7
will
be
operated
after
December
31,
2018,
and
not
permanently
shut
down
by
this
date,
the
owner
or
operator
must:
A)
On
or
before
December
31,
2015,
install
and
have
operational
SNCR
or
equipment
capable
of
delivering
essentially
equivalent
NQ
reductions
on
Crawford
7;
and
B)
On
or
before
December
31,
2018,
install
and
have
oerational
FGD
equipment
on
Crawford
7;
V
5)
If
Crawford
8
will
be
operated
after
December
31,
2017
and
not
permanently
shut
down
by
this
date,
the
owner
or
operator
must:
A)
On
or
before
December
31,
2015,
install
and
have
operational
SNCR
or
equipment
capable
of
delivering
essentially
equivalent
NQ,eimissions
reductions
on
Crawford
8;
and
B)
On
or
before
December
31,
2017,
install
and
have
operational
FGD
equipment
on
Crawford
8.
V
b)
Other
Control
Technology
Requirements
for
SO,.
Owners
or
operators
of
specified
EGUs
must
either
permanently
shut
down
or
install
FGD
equipment
on
each
specified
EGU
(except
Joliet
5),
on
or
before
December
31,
2018,
unless
an
earlier
date
is
specified
in
subsection
(a)
of
this
Section.
82
c)
Control
Technology
Requirements
for
PM.
The
owner
or
operator
of
the
two
specified
EGUs
listed
in
this
subsection
that
are
equipped
with
a
hot-side
ESP
must
replace
the
hot-side
ESP
with
a
cold-side
ESP,
install
an
appropriately
designed
fabric
filter,
or
permanently
shut
down
the
EGU by
the
dates
specified.
Hot-side
ESP
means
an
ESP
on
a coal-fired
boiler
that
is
installed
before
the
boiler’s
air-preheater
where
the
operating
temperature
is
typically
at
least
5500
F,
as
distinguished
from
a
cold-side
ESP
that
is
installed
after
the
air
pre-heater
where
the
operating
temperature
is
typically
no
more
than
350°
F.
1)
Waukegan
7
on
or
before
December
31,
2013;
and
2)
Will
County
3
on
or
before
December
31,
2015.
d)
Beginning
on
December
31,
2008,
and
annually
thereafterup
to
and
including
December
31,
2015,
the
owner
or
operator
of
the
Fisk power
plant
must
submit
in
•
writing
to
the
Agency
a
report
on
any
technology
or
equipment
designed
to
affect
air
quality that
has
been considered
or
explored
for
the
Fisk
power
plant in
the
•
preceding
12
months.
This
report
will
not
obligate
the
owner
or
operator
to
install
any
equipment
described
in
the
report.
e)
Notwithstanding
35
Iii.
Adm.
Code
201.146(hhh),
until
an
EGU
has
complied
with
the
applicable
requirements
of
subsections
225.296(a), (b),
and
(c),
the
owner
or
operator
of
the
EGU must
obtain
a
construction
permit
for
any
new
or
modified
air
pollution
control
equipment
that
it
proposes
to
construct
for
control
of
emissions
of
mercury,
NO,
PM,
or
SO
2
.
(Source:
Added
at
effective
)
Section
225.297
Combined
Pollutant
Standard:
Permanent
Shut
Downs
a)
The
owner
or
operator
of
the
following
EGUs must
permanently
shut
down
the
EGU
by
the
dates
specified:
1)
Waukegan
6
on
or
before
December
31,
2007;
and
2)
Will
County
1
and
Will
County
2
on
or
before
December
31,
2010.
b)
No
later
than
8
months
before
the
date
that
a
specified
EGU
will
be
permanently
shut
down,
the
owner
or
operator
must
submit
a
report
to
the
Agency
that
includes
a
description
of
the
actions
that
have
already
been
taken
to allow
the
shutdown
of
the
EGU
and a
description
of
the
future
actions
that
must
be
accomplished
to
complete
the
shutdown
of
the
EGU,
with
the
anticipated
schedule
for
those
actions
and
the
anticipated
date
of
permanent
shutdown
of
the
unit.
c)
No
later
than
six
months
before
a
specified
EGU
will
be
permanently
shut
down,
the
owner
or
operator
shall
apply
for
revisions
to
the
operating
permits
for
the
83
EGU
to
include
provisions
that
terminate
the
authorization
to
operate
the
unit
on
that
date.
d)
If
after
applying
for
or
obtaining
a
construction
permit
to
install
required
control
equipment,
the
owner
or
operator
decides
to
permanently
shut-down
a Specified
EGU
rather
than
install
the
required
control
technology,
the
owner
or
operator
must
immediately
notify
the
Agency
in
writing
and
thereafter
submit
the
information
required
by
subsections
(b)
and
(c)
of
this
Section.
e)
Failure
to
permanently
shut
down
a
specified
EGU
by
the
required date
shall
be
considered
separate
violations
of
the
applicable
emissions
standards
and
control
technology
requirements
of
the
CPS
for
NON.
PM.
SQ2.
and
mercury.
(Source:
Added
at
effective
Section
225.298
Combined
Pollutant
Standard:
Requirements
for
NO
and
SO
2
Allowances
a)
The
following
requirements
apply
to
the
owner,
the
operator,
and
the
designated
representative
with
respect
toSQ
2
and
NO
allowances:
1)
The
owner,
operator,
and
designated
representative
of
specified
EGUs
in
a
CPS
group
is
permitted
to
sell,
trade,
or
transfer
SO
2
and
NQ
emissions
allowances
of
any
vintage
owned,
allocated
to,
or
earned
by
the
specified
EGUs
(the
“CPS allowances”)
to
its
affiliated
Homer
City,
Pennsylvania,
generating
station
for as
long
as
the
Homer
City Station
needs
the
CPS
allowances
for
compliance.
2)
When
and
if
the
Homer
City
Station
no
longer
requires
all
of
the
CPS
allowances,
the
owner,
operator,
or
designated
representative
of
specified
EGUs
in
a
CPS
group
may
sell
any
and
all
remaining
CPS allowances,
without
restriction,
to
any person
or
entity
located
anywhere,
except
that
the
owner
or
operator
may not
directly
sell,
trade,
or
transfer
CPS
allowances
to
a
unit
located
in
Ohio,
Indiana,
Illinois,
Wisconsin,
Michigan,
Kentucky,
Missouri,
Iowa,
Minnesota.
or
Texas.
3)
In
no
event
shall
this
subsection
(a)
require
or
be
interpreted
to
require
any
restriction
whatsoever
on
the
sale,
trade,
or
exchange
of
the
CPS
allowances
by
persons
or
entities
who have
acquired
the
CPS
allowances
from
the
owner,
operator,
or
designated
representative
of
specified
EGUs
in
a
CPS group.
b)
The owner,
operator,
and
designated
representative
of
EGUs
in
a
specified
CPS
group
is
prohibited
from
purchasing
or
using
SO
2
and
NO
allowances
for
the
purposes
of
meeting
the
SO
2
and
NO
emissions
standards
set
forth
in
Section
225.295.
84
c)
Before
March
1, 2010,
and
continuing
each
year
thereafter,
the
designated
representative
of the
EGUs
in
a
CPS
group
must
submit
a
report
to
the Agepy
that
demonstrates
compliance
with
the
requirements
of this
Section
for
the
previous
calendar
year
and
ozone
season
control
period
(May
1
through
September
30),
and
includes
identification
of any
NO
or
SO
2
allowances
that
have
been
used
for
compliance
with
any
NO
or
SO,
trading
programs,
and
any
NQoiSO_SO
allowances
that
were
sold,
gifted,
used,
exchanged,
or traded.
A
final
report
must
be
submitted
to the
Agency
by
August
31
of
each
year,
providing
either
verification
that
the
actions
described
in
the
initial
report
have
taken
place,
or,
if such
actions
have
not
taken
place,
an
explanation
of
the
changes
that
have
occurred
and
the
reasons
for
such
changes.
(Source:
Added
at
Section
225.299
effective
Combined
Pollutant
Standard:
Clean
Air
Act
Reouirernents
onerators
-
-‘hose
specified
EGUs
are
not
applicable
requirements
of Subparts B,
C,
D,
and
E.
The
SO,
emissions
rates
set
forth
in
the
CPS
shall
be
deemed
to
be
best
available
retrofit
technology
(“BART”)
under
the
Visibility
Protection
provisions
of the
CAA
(42
USC
742Th
reasonably
available
control
technology
(“RACT”) and
reasonably
available
control
measures
(“RACM”)
for
achieving
fine
particulate
matter
(“PM”)
requirements
under
NAAQS in
effect
on
August
31,
2007,
as
required
by
the
CAA
(42
USC
7502). The
Agency
may
use
the
SO,
and
NQ
emissions
reductions
required
under
the
CPS
in
developing
attainment
demonstrations
and
demonstrating
reasonable
further
progress
for
PM,
5
and
8
hour
ozone
standards,
as
required
under
the
CAA.
Furthermore,
in
developing
rules,
regulations,
or
State
Implementation
Plans
designed
to comply
with
PM,
5
and
8 hour
ozone
NAAQS.
the
Agency,
taking
into
account
all
emission
reduction
efforts
and
other
appropriate
factors,
willuse
best
efforts
to seek
SO,
and
emissions
rates
from
other
EGUs
that
are
equal
to
or less
than
the
rates
applicable
to the
CPS
group
and
will
seek
SO
and
NO
reductions
from
other
sources
before
seeking
additional
emissions
reductions
from
any
EGU
in
the
CPS
group.
(Source:
Added
at
effective
-
SUBPART
F:
COMBiNED
POLLUTANT
STANDARDS
Section
225.600
Purpose
The
purpose
of
this
Subpart
F
is
to
allow
an
alternate
means
of compliance
with
the
emissions
standards
for
mercury
in Section
225.230(a)
for
specified
EGUs
through
permanent
shut
down,
installation
of
ACI,
and
the
application
of
pollution
control
technology
for
NOR,
PM,
and
SO
emissions
that
also
reduce
mercury
emissions
as
a co
benefit
and
to establish
permanent
emissions
standards
for
those
specified
EGUs.
Unless
othevise
provided
for
in
this
Subpart
F,
excused
from
compliance
with
other
85
(Source:
Repealed
at
effective
Section
225.605
A
a)
As
an
alternative
to
compliance
with
the
emissions
standards
of
Section
225.230(a),
the
owner
or
operator
of
specified
EGUs
in
this
Subpart
F
located
at
Fisk, Crawford,
Joliet,
Powerton,
Waulcegan,
and
Will
County power
plants
may
elect for
all
of
those
EGUs
as
a
group
to
demonstrate
compliance
pursuant
to
this
Subpart
F,
which
establishes
control
requirements
and
emissions
standards
for
NOR,
PM,
SO;,
and
mercury.
For
this
purpose,
ownership
of
a
specified
EGU
is
determined
based
on
direct
ownership,
by
holding
a
majority
interest
in
a
company
that
owns
the
EGU
or
EGUs,
or
by
the
common
ownership
of
the
company
that
owns
the
EGU,
whether
through
a
parent
subsidiary
relationship,
as
a
sister
corporation,
or
as
an
affiliated
corporation
with
the
same
parent
corporation,
provided
that
the
owner
or
operator
has
the
right
or
authority
to
submit
a
CAAPP
application
on
behalf
of
the
EGU.
b)
A
specified
EGU
is
a coal
fired
EGU
listed
in
Appendix
A,
irrespective
of
any
subsequent
changes
in
ownership
of
the
EGU
or
power
plant,
the
operator,
unit
designation,
or
name
of
unit.
c)
The
owner
or
operator
of
each
of
the
specified
EGUs
electing
to
demonstrate
compliance
with
Section
225.230(a)
pursuant
to
this
Subpart
must
submit
an
application
for
a
CAAPP
permit
modification
to
the
Agency,
as
provided
for-in
Section
225.220,
that
includes
the
information
specified
in
Section
225.6
10
that
clearly
states
the
owner’s
or
operator’s
election
to
demonstrate
compliance
with
Section
225.230(a)
pursuant
to
this
Subpart
F.
d)
If
an
owner
or
operator
of
one
or
more
specified
EGUs
elects
to
demonstrate
compliance
with
Section
225.230(a)
pursuant
to
this
Subpart
F,
then all
specified
EGUs
owned
or
operated
in
illinois
by
the
owner
or
operator
as
of
December
31,
2006, as
defined
in
subsection
(a)
of
this Section,
ar
thereafter
subject
to
the
standards
and
control
requirements
of
this
Subpart
F.
Such
EGUs
are
referred
to
as
a
Combined
Pollutant
Standard
(CPS)
group.
e)
If
an
EGU
is
subject
to
the
requil
apply to
all
ov’ners
and
operator
renresentative
for
the
EGU.
ements
of
this
Section,
then
the
requirements
of
the
EGU,
and
to
the
CAIR
designated
(Source:
Repealed
at
)
Section
225.6 10
86
The
owner
or
operator
of
one
or
more
specified
EGUs
that
intends
to
comply
with
Section
225
.230(a)
by
means
of
this
Subpart
F
must
notify
the
Agency
of
its
intention
on
or
before
December
31,
2007.
The
following
information
must
accomoanv
the
notification:
a)
The identification
of
each
EGU
that
will
be
complying
with
Section
225
.230(a)
pursuant
to
this
Subpart
F,
with
evidence
that
the owner
or
operator
has
identified
all
specified
EGUs
that
it
owned
or
operated
in
Illinois
as
of
December
31,
2006,
and
which
commenced
commercial
operation
on
or
before
December
31,
2004;
and identification
of
the
additional
each
EGU
to
comply
with
emissioi
(Source:
Repealed
at
effective
wices
installed
and
operating
on
each
EGU
ontrol
devices
that
will
likely
be
needed
for
control
requirements
of
this Subpart
F.
Section
225.6
15
Control
Teclmology
Requirements
and
Emissions
Standards
for
Mercury
a)
1_1
rT’__1_
1
ents
for
Mercury.
1)
For
each
EGU
in
a
CPS
group
other
than
an
EGU
that
is
addressed
by
subsection
(b)
of
this
Section,
the
owner
or
operator
of
the
EGU
must
install,
if
not
already
installed,
and
properly
operate
and maintain,
by
the
dates
set
forth
in
subsection
(a)(2)
of
this
Section,
ACT
equipment
complying
with
subsections
(g),
(h),
(i),
‘
and
(k)
of
this
Section,
as
applicable.
Poverton
5,
Powerton
6,
Will
County
3,
Will
County
4,
-6
Joliet
7,
and
Joliet
S
on
or
before
July
1,
2009.
b)
If
an
EGU identified
in
subsection
(a)
of
this Section
is
also
owned or
operated
by
a
person
different
than
the
owner
or
operator
submiffing
the
notice
of
intent,
a
demonstration
that
the
submitter
has
the
right
to
commit
the
EGU or
authorization
from
the
responsible
official
for
the
EGU submitting
the
application;
and
2)
,w1
fl
subsections
By
the
foTh
dates,
for
the
EGUs
listed
in
(a)(2)(A)
.f
an
(
B),
which
include
hot
and
cold
side
ESPs,
the
owner
or
operator
must
install,
if
not
afready
installed,
and begin
operating
ACT equipment
or
the
Agency
must
be
given
wriffen
notice
that
the
EGU
will
be
shut
down
on
or
before
the
following
dates:
A)
Fisk
19,
Crawford
7,
Crawford
8,
Waukegan
7,
and
Waukegan
S
on
or
before
July
1,
2008;
and
B)
87
b)
Notwithstanding
subsection
(a)
of
this
Section,
the
following
EGUs
are
not
1
iired
to
install
AC
“‘
1___
‘‘i
acllressecl
1__1_
uy
Lioii
oy
inc
uaw
specified:
1)
EGUs
that
are
required
to permanently
shut
down:
A)
On
or
before
December
31,
2007, Waukegan
6;
and
B)
On
or
before
December
31,
2010,
Will
County
1
and
Will
County
2
wguipuieia
because
they
will
be
permanently
shut
down,
as
Any
e’’-
specified
EGU
2010.
c)
Beginning
on
January
1,
2015
and
continuing
thereafter,
and
measured
on
a
rolling 12
month
basis (the
initial
period
is
January 1,
2015,
through
December
31,
2015,
and,
then,
for
every
12
month
period
thereafter),
each
specified
EGU,
except
Will
County
3,
shall
achieve
one
of
the
following
emissions
standards:
1)
An
emissions
standard
of
0.0080
lbs
mercury/GWh
gross
electrical
output;
2)
Aminimum90p
duction
of
input
mercury.
d)
Beginning
on
January
1, 2016,
and
continuing
thereafter,
Will
County
3
shall
achieve
the
mercury
emissions
standards
of
subsection
(c)
of this
Section
measured
on
a
rolling
12
month
basis
(the
initial
period
is
January
1,
2016
through
December
31,
2016,
and,
then,
for
every
12
month
period
thereafter).
e)
At
any
time
prior
to
the
dates
required
for
compliance
in
subsections
(c)
and
(d)
of this
Section, the
owner
or
operator
of
a
specified
EGU,
upon
notice
to
the
Agency,
may elect
to
comply
with
the
emissions
standards
of
subsection
(c)
of
this
Section measured
on
a rolling
12
month basis
for
one
or
more
EGUs.
Onee
an
EGU
is
subject
to the
mercury
emissions
standards
of
subsection
(c)
of this
Section,
it
shall
not
be
subject
to
the
requirements
of
subsections
(g),
(h),
(i),
j)
and
(k)
of
this
Section.
subsection
(a(1)
of
this
Section,
the
or
operator
of
the
EGU
must
inject
88
-)
..
permanently
shut
down
by
December
3 l-
f)
Compliance
with
the
mercury emissions
standards
or reduction
requirement
of
this
Section
must
be
calculated
in
accordance
with
Section
225.230(a)
or
(b).
g)
For
each
EGU
for
which injection
of
halogenated
activated
carbon
is required
by
subsection
(h)
of
this
Section,
is
defined
as
all
of
the
following:
1)
The
use
of
an
injection
system
for
effective
absorption
of
mercury,
considering
the
configuration
of
the
EGU and
its
ductwork;
2)
The
injection
of
halogenated
activated
carbon
manufactured
by
Aistom,
Norit,
or
Sorbent
Technologies,
or
the
injection
of
any
other
halogenated
activated
carbon
or
sorbent
that
the
owner or
operator
of
the
EGU
has
demonstrated
to
have
similar
or
better
effectiveness
for
control
of
mercury
emissions;
and
3)
The
injection
of
sorbent
at
the
following
minimum
rates,
as
applicable:
A)
For
an
EGU
flung
subbituminous
coal,
5.0
lbs
per
million
actual
cubic
feet
or,
for
any
cyclone
fired
EGU that
will
install
a scrubber
and
baghouse
by
December
31,
2012,
and
which
already
meets
an
emission
rate
of
0.020
lb
mercuGVi
gross
electrical output
or
at
least
75
percent
reduction
of
input
mercury,
2.5
lbs
per
million
actual
cubic
feet;
B)
For
an
EGU
firing
bituminous
coal,
10.0
lbs
per million
actual
cubic
feet
or,
for
any cyclone
fired
EGU
that
will
install
a
scrubber
and
baghouse
by
December
31, 2012,
and
which
already
meets
an
emission
rate
of
0.020
lb
mercury/GA
gross
electrical
output
or
at
least
75
percent
reduction
of
input
mercury,
5.0
lbs
per
million
actual
cubic feet;
C)
For
an
EGU
firing
a
blend
of
subbituininous
and
bituminous
coal,
a
rate
that is
the
weighted
average
of
the rates
specified
in
subsections
(g)(3)(A)
and
(B), based
on
the
blend
of
coal
being
fired;
or
D)
A
rate
or
rates set
lower
by
the
Agency,
in
writing,
than
the
rate
specified
in
any
of
subsection
(g)(3)(A),
(B),
or
(C)
of
this
Section
on
a
unit
specific
basis,
provided
that
the
owner
or
operator
of
the
EGU has
demonstrated
that such
rate
or
rates
are
needed
so
that
carbon
injection
will
not
increase
particulate
matter
emissions
or
opacity
so
as
to
threaten
noncompliance
with
applicable
reauirements
for
particulate
matter
or
opacity.
4)
For
purposes
of
subsection
(g)(3)
of
this
Section,
the
flue
gas
flow
rate
must
be
determined
for
the
point
sorbent
injection;
provided
that
this
flow
rate
may
be
assumed
to
be
identical
to
the
stack
flow
rate
if
the
gas
temperatures
at
the
point
of
irj
ection
and
the
stack
are
normally
within
1000
F,
or
the
flue
gas
flow rate
may
otherwise
be
calculated
from
the
stack
flow
rate,
corrected
for
the
difference
in
gas
temperatures.
89
h)
The
owner
or
operator
of
an
EGU
that
seeks
to
operate
an
EGU
with
an
activated
carbon
injection
rate
or
rates
that
are
set
on
a
unit
specific
basis
pursuant
to
subsection
(g)(3)(D)
of
this
Section
must
submit
an
application
to
the
Agency
proposing
such
rate
or
rates,
and
must
meet
the
requirements
of
subsections
h(1)
and
(h)(2)
of
this
Section,
subject
to
the
limitations
of
subsections
(h)(3)
and
(h(4)
of
this
Section:
1)
The
application
must
be
submitted
as
an
application
for
a new
or
revised
federally
enforceable
operation
permit
for
the
EGU,
and
it
must
include
a
sua’
of
relevant
mercury
emissions
data
for
the
EGU,
the
unit
specific
injection
rate
or
rates
that
are
proposed,
and
detailed
information
to
support
the
proposed
injection
rate
or rates;
and
2)
This
application
must
be
submitted
no
later
than
the
date
that
activated
carbon
must
first
be
injected.
For
example,
the
owner
or
operator
of
an
EGU
that
must
inject
activated
carbon
pursuant
to
subsection
(a)(l)
of
this
Section
must
apply
for
unit
specific injection
rate
or
rates
by
July
1,
2008.
Thereafter,
the
owner
or
operator
may
supplement
its
application;
and
3)
Any decision
of
the
Agency
denying
a
permit
or
granting
a
permit
with
conditions
that
set
a lower
injection
rate
or
rates
may
be
appealed
to
the
Board
pursuant
to
Section
39
of
the
Act;
and
4)
The
owner
or
operator
of
an
EGU
may
operate
at
the
injection
rate
or
rates
proposed
in
its
application
until
a
final
decision
is
made
on
the
application
including
a
fmal
decision
on
any
appeal
to
the
Board.
i)
During
any
evaluation
of
the
effectiveness
of a
listed
sorbent,
alternative
sorbent,
or
other
technique
to
control
mercury
emissions,
the
owner
or
operator
of
an
EGU
need
not
comply
with
the
requirements
of
subsection
(g)
of this
Section
for—any
system
needed
to
cay
out
the
evaluation,
as
thrther
provided
as
follows:
1)
The
owner
or
operator
of
the
EGU
must
conduct
the
evaluation
in
accordance
with
a
formal
evaluation
program
submitted
to
the
Agency
at
least
30
days
prior
to
commencement
of
the
evaluation;
2)
The
duration
and
scope
of
the
evaluation
may
not
exceed
the
duration
and
scope reasonably
needed
to
complete
the
desired
evaluation
of
the
alternative
control
techniques,
as
mitially
addressed
by
the
owner
or
operator
in
a
support
document
submitted
with
the
evaluation
program;
ffld
.
:ftheEGUmust
iihmitnrnnfl
the-A
gency
no
later
than
30
days
after
the
conclusion
of
the
evaluation
that
describes
the
evaluation
conducted
and
which
provides
the
results
of
the
evaluation;
and
3)
The
owner
or
nnemtnr
,i
90
4)
If
the
evaluation
of
alternative
control
techniques
shows
less
effective
control
of
mercury
emissions
from
the
EGU
than
was
achieved
with
the
principal
control
techniques,
the
owner
or
operator
of
the
EGU
must
resume
use
of
the
principal
control
techniques.
If
the
evaluation
of
the
alternative
control
technique
shows
comparable
effectiveness
to
the
principal
control
technique,
the
owner
or
operator
of
the
EGU may
either
continue
to
use
the
alternative
control
technique
in
a
manner
that
is
at
least
as
effective
as
the
principal
control
technique
or
it
may
resume
use
of
the
principal
control
technique.
If
the
evaluation
of
the
alternative
control
technique
shows
more
effective
control
of
mercury
emissions
than
the
control
technique,
the
owner
or
operator
of
the
EGU must
continue
to
use
the
alternative
control
technique
in
a
manner
that
is
more
effective
than
the
principal
control
technique,
so
long
as
it
continues
to
be
subject
to
this
Section.
j)
In
addition
to
complying
with
the
applicable
recoidkeeping
and
monitoring
requirements
in
Sections
225.240
through
225.290,
the
owner
or
operator
of
an
EGU
that elects
to
comply
with
Section
225
.230(a
by
means
of
this
Subpart
F
must
also comply
with
the
following
additional
requirements:
1)
For
the
first
36
months
that
injection
of
sorbent
is
required,
it
must
maintain
records
of
the
usage
of
sorb
ent,
the
exhaust
gas
flow
rate
from
the
EGU,
and
the
sorb
ent
feed
rate,
in
pounds
per
million
actual
cubic
feet
of
exhaust
gas
at
the
injection
point,
on
a
weekly
average;
2)
After
the
first
36
months
that
injection
of
sorbent
is
required,
it
must
monitor
activated
sorbent
feed
rate
to
the
EGU,
flue
gas
temperature
at
the
point
of
sorbent
injection,
and
exhaust
gas
flow
rate
from
the
EGU,
automatically
recording
this
data
and the
sorbent
carbon
feed
rate-in
pounds
per
million
actual
cubic
feet
of
exhaust
gas
at
the
injection
point,
on
an
hourly
average;
and
3)
If
a
blend
of
bituminous
and subbituminous
coal is
fired
in
the
EGU,
it
must
keep records
of
the
amount
of
each
type
of
coal
burned
and
the
requircd injection
rate
for
injection
of
activated
carbon
on
a
weekly
basis.
k)
In
addition
to
complying
with
the
applicable
reporting
requirements
in
Sections
225.240
through
225
.290,
the owner
or
operator
of
an
EGU that
elects
to
comply
with
Section
225
.230(a)
by
means
of
this
Subpart
F
must
also
submit quarterly
reports
of
this
Section.
for
the
recordkeeping
and
monitoring
conducted
pursuant
to
subsection
(I)
(Source:
Repealed
at
effective
Section
225
.620
Emissions
Standards for
NO
and
SO
91
a)
Emissions
Standards
for
NO
and
Reporting
Requirements.
1)
Beginning
with
calendar
year
2012
and
continuing
in
each
calendar
year
thereafter,
the
CPS
group,
which
includes
all
specified
EGUs
that
have
not
been
permanently
shut
down
by
December 31
before
the
applicable
calendar
year,
must
comply
with
a CPS
group
average
annual
NO
emissions
rate
of
no
more
than
0.11
lbshBtu.
2)
Beginning
with
ozone
season
control
period 2012
and
continuing
in
each
ozone
season
control
period
(May
1
through September
30)
thereafter,
the
CPS
group,
which
includes
all
specified EGUs
that
have
not
been
permanently
shut
down
by
December31
before
the
applicable
ozone
season,
must
complywith
a
CPS
group average
ozone
season
NO
.
emissions
rate
of
no
more
than
0.11
lbs/mmBth.
3)
The
owner
or
opr
tor
of
the
specified
EGUs
in the
CPS
group
must
file,
not
later
than
one
year
after
startup
of
any
selective
SNCR
on
such
EGU,
a
report
with
the
Agency
describing
the
NO
emissions
reductions
that
the
SNCR
has
been
able
to
achieve.
b)
Emissions
Standards
for
SO
3
.
Beginning
in
calendar
year
2013
and
continuing
in
each
calendar
year
thereafter,,
the
CPS
group
must
comply
with
the
applicable
CPS
group average
annual
SO
3
emissions
rate
listed
as
follows:
y
2013
0.44
2014
0.41
2015
0.28
2016
0.195
2017
-
0.15
2018
0.13
2019
0.11
c)
Compliance
with
the
NO
and
SO
2
emissions
standards
must
be
demonstrated
in
accordance
with
Sections
225.3
10,
225.410,
and
225.5
10.
The
owner
or
operator
of
the
specified
EGUs
must
complete
the
demonstration
of
compliance
pursuant
to
Section 225.635(c)
before
March
1 of
the
following
year
for
annual
standards
and
before November
30
of
the
particular
year
for
ozone
season
control
periods
(May
1
through
September
30)
standards,
by
which
date
a
compliance
report
must
be submitted
to
the
Agency.
d)
The
CPS
group
average
annual
SO
3
emission
rate,
annual
NO
emission
rate-and
ozone
season
NO
emission
rates
shall
be
determined
as
follows:
92
ERagSO
4
or
NO4s--(HIj
Where:
EP
rate
in
lbs/mmBbtu
of
all
EGUs
in
the
CPS
group.
—
heat
input
for the
annual
or
ozbn
period
of
each
EGU,
in
mmBtu.
of
EGUs
that
are
in
the
CPS
group
each
EGU
in
the
CPS
group.
Control
Technology
for
NO
3
-SO
3
,
and
PM
Emissions
a)
Control
Technology
Requii
for
NO
and
SO
4+
I-__
m
.1
31,
2013,
the
owner
or
operator
must
either
and
have
operational
FGD
equipment
2)
On
or
before
December
31,
2014,
the owner
or
operator
must
either
permanently
shut
down
or
install
and
have
operational
FGD
equipment
on
Waukegan
8;
eee
owner
or
onerator
must
ILAOI,Ltfli
4)
If
Crawford
7
will
be
operated
after
December
31,
2018,
and
not
permanently
shut
down
by
this
date,
the
owner
or
operator
must:
A)
efore
December
31
2015-
install
and have
nnerntimii
SNCR
or
equipment
capable
of
delivering
essentially
equivalent
NO
reductions
on
Crawford
7;
and
B)
31,
2018,
install
and
have
-.1
t’iim
HI
SO
—
actual
annual
SO
2
tons
of
each
EGU
in
the
CPS group.
NOj
—
acmal
annual
or
ozone
season
NO
tons
of
each
EGU
in
the
CPS group.
(Source:
Repealed
at
effective
3)
On
or
before
D
iber
31,
2015,
the
permanently
shut
down
Fisk
19;
2..11
and
have
operational
FGD-equipment
on
_1
93
5)
If
Crawford
8
will
be
operated
after
December
31,
2017
and
not
permanently
shut
down
by
this
date,
the
owner
or
operator
must:
A)
On
or
before
December
31,
2015,
install
and
have
operational
SNCR
or
equipment
capable
of
delivering
essentially
equivalent
NO
emissions
reductions
on
Crawford
8;
and
or before
December
1
-
2017,
install
and
have
operatiuiiai
equipment
on
Crawford
8.
b)
Other
Control Technology
Requirements
for
SO. Owners or
operators
of
specified
EGUs
must
either
permanently
shut
down or
install
FGD
equipment
on
each
specified
EGU
(except
Joliet
5),
on
or
before December
31,
2018,
unless
an
earlier
date
is
specified
in
subsection
(a)
of
this
Section.
c)
Control
Technology
Requirements
for
PM.
The
owner
or
operator
of
the
two
specified
EGUs
listed
in
this
subsection
that
are
equipped
with
a
hot
side
ESP
must
replace
the
hot
side
ESP
with
a
cold
side
ESP,
install
an
appropriately
designed
fabric
filter,
or
permanently
shut
down the
EGU
by
the
dates
speciflcd
Hot
side
ESP
means
an
ESP
on
a
coal
fired boiler
that
is
installed
before
the
boiler’s air
preheater
where
the
operating
temperature
is
tically
at
least
550°
F,
as
distinguished
from
a
cold
side
ESP
that
is installed
after
the
air
pre
heater
where
the
operating
temperature
is tically
no
more
than
350°
F.
1)
Waukegan
7
on
or
before
December
31,
2013;
and
2)
Will
County
3 on
or
before December
31,
2015.
d)
Beginning
on
December
31,
2008, and
annually
thereafter
up
to
and
including
December
31,
2015, the
owner
or
operator
of
the
Fisk
power
plant
must
submit
in
writing
to
the
Agency
a
report
on
any
technology
or
equipment
designed
to
affect
air
quality that
has
been
considered
or
explored
for
the
Fisk
power
plant
in
the
preceding
12 months.
This
report will
not
obligate
the
ovmer
or
operator
to
install
any
equipment
described
in the
report.
Notwithstanding
35
Ill.
Adm. Code
201.146(hhh),
until
an EGU
has
complied
with
the
applicable
requirements
of
subsections
225.625(a,
(b),
and
(c),
the
owner
or
operator
of
the
EGU
must
obtain
a
construction
permit
for
any
new
or
modified
air
pollution
control
equipment
that
it
proposes
to construct
for
control
of
emissions
of
mercury,
NOR,
PM,
or
SO
(Source:
Repealed
at
effective
Section 225.630
rermanent
Shut Downs
94
a)
The
owner
or
operator
of
the
following
EGUs must permanently
shut
down
the
EGU
by
the
dates
specified:
1)
Waukegan
6
on
or
before
December
31, 2007;
and
2)
Will
County
1
and
Will
County
2
on
or
before
December
31,
2010.
b)
No
later
than
8
months
before
the
date
that
a
specified
EGU
will
be
permanently
shut down,
the
owner
or
operator
must
submit
a
report
to
the Agency
that
includes
a
description
of
the
actions
that
have
already
been
taken
to
allow
the
shutdown
of
the
EGU and
a
description
of
the
future
actions
that
must
be
accomplished
to
complete
the
shutdown
of
the
EGU, with
the
anticipated
schedule
for
those
actions
and
the
anticipated
date
of
permanent
shutdown
of
the
unit.
c)
No
later
than six
months
before
a
specified
EGU
will
be
permanently
shut
down,
the
owner
or
operator
shall
apply for
revisions
to
the operating
permits
for
the
EGU
to
include
provisions
that
terminate
the
authorization
to
operate
the
unit
on
that date.
d)
If
after
applying
for
or
obtaining
a
construction
permit
to
install
required
control
equipment,
the
owner
or
operator
decides
to
permanently
shut
down
a
Specified
EGU
rather
than
install
the
required
control
technology,
the
owner
or
operator
must immediately
notify
the
Agency
in
writing
and
thereafter
submit
the
information
required
by
subsections
(b)
and (c)
of
this
Section.
e)
Failure
to
permanently
shut down
a
specified
EGU
by
the
required
date
shall
be
considered
separate
violations
of
the applicable
emissions
standards
and
control
tecnnology
requirements
of
this
Subpart
F
for
NOR,
PM,
SO
2,
,
and
mercury.
(Source:
Repealed
at
effective
Section
225.635
Kequirements
for
CAR
SO
2,,
CAR
NOR,
and
CAR
NO
Ozone
Season
Allowances
a)
The following
requirements
apply to
the
owner,
the
operator
and
the
designated
representative
with respect
to
CAR
SO
2,
,
CAR
NON,
and
CAR
NO
Ozone
Season
allowances:
1)
“
I
The
owner,
operator,
ue,iiiaieu
id
CA
::presentative
of
specified
EGUs in
a CPS group
is
permitted
to
sell,
trade,
or
transfer
SO
2,
and
NO,
emissions
allowances
of
any
vintage
owned,
allocated
to,
or
earned
by-the
specified
EGUs
(the
“CPS
allowances”)
to
its
affiliated
Homer
City,
Pennsylvania
generating
station
for
as
long
as
the
Homer
City
Station
needs
the
CPS
allowances
for
compliance.
95
2)
When
and
if
the Homer
City
Station
no
longer
requires
all
of
the
CPS
allowances,
the
owner,
operator,
or
CA1R
designated
representative
of
specified
EGUs
in
CPS
group
may
sell
any
and
all remaining
CPS
allowances,
without
restriction,
to
any
person
or entity
located
anyvhere,
except
that the
owner
or operator
may
not directly
sell,
trade,
or
transfer
CPS
allowances
to
a
CAIR
NO
or
CAW
SO
2
unit
located
in
Ohio,
thdiana,
Illinois,
Wisconsin,
Michigan,
Kentucky,
Missouri,
Iowa,
Miunesota,
or Texas.
3)
In
no
event
shall
this
subsection
(a) require
or be
intereted
to
require
any
restriction
whatsoever
on
the
sale,
trade,
or
exchange
of the
CPS
allowances
by
persons
or entities
who
have
acquired
the CPS
allowances
from
the
owner,
operator,
or CAIR
designated representative
of
specified
EGUs
in
a
CPS
group.
b)
The
over,
operator,
and
CAR
designated
representative
of
EGUs
in a
specified
CPS
group
is
prohibited
from
purchasing
or
using
CAIR
SO
2
,
CAIR
NOR-and
CAIR
NO
Ozone
Season
allowances
for
the
puoses
of meeting
the
SO;-and
NO
emissions
standards
set
forth
in Section
225.620.
c)
(Source:
Repealed
at
effective
Section
225.640
-
A
A
_- -I-i
The SO;
emissions
rates
set forth
in
this
Subpart
F
shall
be
deemed
to
be
best
available
retrofit
technology
(“BT”
under
the Visibility Protection
provisions
of
the
(42
USC
7491),
reasonably available
control
technology
(“RACT”) and
reasonably
available
control
measures
(“RACM”)
for
achieving
fine
particulate
matter
(“PM”)
requirements
under
NAAQS
in effect
on
August
31,
2007,
as
required
by
the
CP
(42
USC
7502).
The
Agency
may
use
the
SO;-ed
NO
emissions reductions
required
under
this
Subpart
F in
developing
attainment
demonstrations
and
demonstrating
reasonable
further
progress
for
PM
and
8
hour
ozone
standards,
as
required
under
the
CAA.
Furthermore,
in
developing
rules,
regulations,
or State
Implementation
Plans
96
Before
March
1,
2,
ill 11
IEI(,
continuIng
-;I[:iI
year
thereafter,
the
CAR
de
nated
representative
of
the
EGUs
in a
CPS
group
must
submit
a
report
to
the
Agency
that
demonstrates
compliance
with
the
requirements
of
this
Section
for
the
previous
calendar
year
and
ozone
season
control
period
(May
1 through
September
30),
and
includes
identification
of
any CAIR
allowances
that
have
been
used
for
compliance
with
the
CAR
Trading
Programs
as set
forth
in
Subparts
C,
D,
and
E, and
any
CAR
allowances
that
were
sold,
gifted,
used,
exchanged,
or traded.
A
final
report
must
be
submitted
to
the
Agency
by
August
31
of each
year,
providing
either
verification
that
the actions
described
in
the
initial
report
have
taken
place,
or,
if
such
actions
have
not
taken
place,
an
explanation
of the
changes
that
have
occued
and
the
reasons
for
such
chanaes.
designed
to
comply
with
PM
and
8
hour
ozone
N&QS,
the
Agency,
taking
into
account
all
emission
reduction
efforts
and
other
appropate
factors,
will
use
best
efforts
to
seek
SO-ad
NO
emissions
rates
from
other
EGUs
that
are
equal
to
or
less than
the
rates applicable
to
the
CPS
group
and
will
seek
SO
and
NO
reductions
from
other
sources
before
seeking
additional
emissions
reductions
from
any
EGU
in the
CPS
group.
(Source:
Repealed
at
225.APPENDIX
A
effective
Specified
EGUs
for
Purposes
of
the
CPS
Subpart
F
(Midwest
Generation’s
Coal-Fired
Boilers
as
of
July
1,
2006)
Boiler
Permit
designation
Unit
19
Boiler
BLR19
Unit
7
Boiler
BLR71
Unit
7
Boiler
BLR72
Unit
8 Boiler
BLR8
1
Unit
8 Boiler
BLR82
Unit
6
Boiler
BLR5
CPS
Subpart
F
Designation
Crawford
7
Crawford
8
Fisk
19
Joliet
7
Joliet
7
Joliet
8
Joliet
8
Joliet
6
Powerton
179801AAA
51
52
61
62
Unit
5
Boiler
BLR
51
Unit
5
Boiler
BLR
52
Unit
6
Boiler
BLR
61
Unit
6
Boiler
BLR
62
Powerton
5
Powerton
5
Powerton
6
Powerton
6
Waukegan
097190AAC
17
7
8
Unit
6
Boiler
BLR17
Unit
7
Boiler
BLR7
Unit
8
Boiler
BLR8
Waukegan
6
Waukegan
7
Waukegan
8
Will
County
1978
1OAAK
1
2
3
4
Unit
1
Boiler
BLR1
Unit
2
Boiler
BLR2
Unit
3
Boiler
BLR3
Unit
4
Boiler
BLR4
Will
County
1
Will
County
2
Will
County
3
Will
County
4
(Source:
Amended
at
Plant
Permit
Number
Crawford
031600A1N
Fisk
031600AM1
19
Joliet
197809AA0
71
72
81
82
5
7
Unit
7
Boiler BLR1
8
Unit
8
Boiler
BLR2
97