Document ID: EPA-HQ-OAR-2003-0179-0231
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2005-02-23T05:00Z

Enclosure
U.
S.
EPA
Region
4
Objection
Proposed
Part
70
Operating
Permit
Florida
Power
Corporation
Crystal
River
Plant
Permit
No.
0170004­
004­
AV
November
1,
1999
I.
EPA
Objection
Issues
1.
Applicable
Requirements
­
Based
on
our
review
of
the
proposed
permit,
the
title
V
permit
application,
and
supplemental
materials,
EPA
has
determined
that
the
proposed
permit
for
the
FPC
Crystal
River
facility
does
not
assure
compliance
with
all
applicable
requirements
under
the
Clean
Air
Act
(
CAA
or
the
Act),
the
Florida
State
Implementation
Plan
(
SIP),
and
state
and
federal
title
V
regulations.
Specifically,
the
permit
does
not
contain
terms
and
conditions
assuring
compliance
with
applicable
Prevention
of
Significant
Deterioration
(
PSD)
requirements
of
the
Act,
the
Florida
SIP,
and
40
C.
F.
R.
part
70
for
a
proposed
major
modification
to
allow
the
facility
to
burn
petroleum
coke
("
petcoke").
Pursuant
to
CAA
§
504(
a),
title
V
permits
are
to
include,
among
other
conditions,
"
enforceable
emission
limitations
and
standards,
.
.
.
and
such
other
conditions
as
are
necessary
to
assure
compliance
with
applicable
requirements
of
[
the
Act],
including
the
requirements
of
the
applicable
implementation
plan."
"
Applicable
requirements"
are
defined
in
40
C.
F.
R.
§
70.2
to
include:
"(
1)
any
standard
or
other
requirement
provided
for
in
the
applicable
implementation
plan
approved
or
promulgated
by
EPA
through
rulemaking
under
title
I
of
the
Act..."
As
you
know,
FDEP
defines
"
applicable
requirement"
in
a
similar
fashion
to
include,
among
other
requirements,
"
any
standard
or
other
requirement
provided
for
in
the
state
implementation
plan"
62­
210.200(
31)(
a)(
1)
Florida
Administrative
Code
(
F.
A.
C.).
Applicable
requirements
include
the
requirement
to
obtain
preconstruction
permits
that
comply
with
applicable
preconstruction
review
requirements
under
the
Clean
Air
Act,
EPA
regulations,
and
SIPs.
See
generally
CAA
§
§
110(
a)(
2)(
C),
160­
69,
&
173;
40
C.
F.
R.
§
§
51.160­
66
&
52.21;
see
also
Order
In
re
Roosevelt
Regional
Landfill,
at
2,
8
(
May
4,
1999);
Order
In
re
Monroe
Electric
Generating
Plant
Entergy
Louisiana,
Inc.,
at
2
(
June
11,
1999).
Such
applicable
requirements
include
the
requirement
to
obtain
a
PSD
permit
that
in
turn
complies
with
applicable
PSD
requirements.
See
CAA
§
165;
40
C.
F.
R.
§
§
51.160,
51.166
&
52.21;
48
FR
52,713
(
November
22,
1983);
Rule
62­
212.400
F.
A.
C.
Those
requirements
include,
but
are
not
limited
to:
the
use
of
best
available
control
technology
(
BACT)
for
each
regulated
pollutant
that
would
be
emitted
in
significant
amounts,
at
each
emissions
unit
at
which
the
increase
would
occur;
associated
emission
limitations;
and
any
additional
requirements
resulting
from
the
PSD
review,
such
as
those
that
are
necessary
to
afford
protection
to
any
Class
I
area
air
quality
related
values.
The
FPC
Crystal
River
Facility
Title
V
Air
Operating
Permit
Application,
signed
June
12,
1996,
indicates
that
on
December
26,
1995,
FPC
submitted
to
FDEP
a
request
to
allow
the
Crystal
River
facility
to
burn
a
blend
of
petroleum
coke
and
coal
in
Units
1
&
2.
This
proposed
modification
would
result
in
an
actual
emissions
increase
of
approximately
9,400
tons
per
year
of
sulfur
dioxide
and
a
corresponding
increase
in
the
potential
emissions
of
sulfur
dioxide
of
approximately
18,700
tons
per
year.
There
are
no
scrubbers
present
or
planned
for
Units
1
&
2
to
abate
this
emissions
increase.
As
you
are
aware,
a
major
source
is
subject
to
PSD
requirements
if
the
proposed
modification
will
result
in
a
significant
net
emissions
increase
of
40
tons
or
more
per
year
of
sulfur
dioxide.
See
40
C.
F.
R.
§
§
51.166(
b)(
2),
51.166(
b)(
23)
&
51.166(
i);
see
also
62­
212.400(
2)(
e)
2
F.
A.
C.
Hence,
it
is
our
determination
that
the
proposed
modification
is
a
major
modification
subject
to
PSD
review.
FPC's
application,
however,
did
not
address
PSD
requirements,
because
FPC
contended
that
it
qualified
for
an
exemption
from
PSD
permitting
requirements
under
Rule
62­
212.400(
2)(
c)
4
F.
A.
C.
This
FDEP
rule,
as
well
as
federal
PSD
requirements
at
40
C.
F.
R.
§
51.166(
b)(
2)(
iii)(
e)(
1),
exclude
from
the
definition
of
major
modification
the
use
of
an
alternative
fuel
or
raw
material
which:
the
source
was
capable
of
accommodating
before
January
6,
1975,
unless
such
change
would
be
prohibited
under
any
federally
enforceable
permit
condition
which
was
established
after
January
6,
1975.
.
.
.
We
are
aware
that
after
reviewing
FPC's
application
to
burn
petcoke,
FDEP
originally
issued
an
Intent
to
Deny
the
permit
on
June
25,
1996.
Following
an
administrative
hearing
and
a
series
of
procedural
events,
FDEP
issued
a
Final
Order
denying
the
permit
on
March
2,
1998.
FPC
appealed
this
decision
to
the
Fifth
District
Court
of
Appeal
of
Florida
(
5th
DCA).
However,
following
negotiations
with
FPC,
FDEP
agreed
to
vacate
the
Final
Order
and
joined
with
FPC
in
filing
a
Joint
Motion
for
Relinquishment
of
Jurisdiction
with
the
5th
DCA.
On
January
11,
1999,
FDEP
granted
FPC
a
final
state
construction
permit
to
authorize
the
burning
of
a
petcoke­
coal
blend
in
Units
1
and
2.
This
permit
was
not
issued
pursuant
to
the
State
PSD
regulations,
and
hence,
does
not
meet
the
requirements
of
the
CAA,
Federal
PSD
Regulations
or
the
Florida
SIP.
In
addition,
this
permit
was
issued
without
an
opportunity
for
public
or
EPA
review.
The
proposed
title
V
permit
is,
thus,
the
first
opportunity
for
EPA
to
comment
on
the
permit
conditions
related
to
the
proposed
modification.
It
is
our
understanding
that
the
facility
has
not
commenced
burning
of
petcoke.
EPA
has
reviewed
the
supporting
information
related
to
the
above
proceedings,
including,
but
not
limited
to:
supplemental
information
submitted
by
FPC
to
EPA
on
January
6,
1997,
February
11,
1997,
February
18,
1997,
February
21,
1997,
February
28,
1997,
and
May
21,
1997;
information
submitted
by
FDEP
to
EPA
on
December
24,
1996
and
May
13,
1997;
the
Recommended
Order
of
the
administrative
law
judge
(
ALJ)
following
the
FDEP's
administrative
hearing
(
September
23,
1977);
the
FDEP's
Final
Order
to
Deny
the
permit
(
March
2,
1998)
;
and
the
subsequent
vacature
of
that
order
(
January
4,
1999).
As
communicated
in
our
letters
to
Howard
L.
Rhodes,
dated
June
2,
1997
and
July
30,
1997,
and
for
the
reasons
outlined
below,
EPA
continues
to
maintain
that
the
exemption
for
alternative
fuels
given
in
40
C.
F.
R.
§
51.166(
b)(
2)(
iii)(
e)(
1)
and
as
incorporated
into
the
SIP
at
62­
212.400(
2)(
c)
4
F.
A.
C.,
is
not
applicable
for
the
purpose
of
the
proposed
petroleum
coke
modification,
and
thus,
the
proposed
modification
is
major
modification
subject
to
PSD
review.

A.
The
facility
was
not
capable
of
accommodating
petroleum
coke
as
of
January
6,
1975.
The
administrative
hearing
record
and
other
supporting
information
submitted
by
FPC
and
FDEP,
including
discussion
of
a
facility
inspection
by
FDEP
on
December
16,
1996,
indicate
that
Unit
2
was
physically
unable
to
burn
solid
fuel
as
of
January
6,
1975.
Only
through
substantial
modifications
made
during
the
late
1970'
s
to
reconvert
Units
1
and
2
to
coal­
fired
facilities,
did
Unit
2
regain
the
ability
to
burn
coal.
The
record
is
unclear
as
to
whether
the
Unit
1
boiler
remained
capable
of
burning
coal
during
the
time
that
it
burned
fuel
oil.
However,
during
the
"
reconversion"
process,
modifications
to
Unit
1
included
replacement
of
most
of
the
waterwall,
addition
of
induced
draft
fans,
replacement
of
pollution
control
equipment,
and
addition
of
railroad
tracks
to
the
area.
According
to
the
hearing
witness
for
FDEP,
the
physical
alterations
were
required
to
make
the
units
capable
of
accommodating
coal.
Further,
it
is
not
clear
that
the
blending
capability
to
co­
fire
coal
and
petcoke
was
present
prior
to
1975.
Some
of
the
physical
modifications,
as
documented
by
FPC,
necessary
to
convert
the
units
back
to
coal
include
changes
or
additions
of
coal
burners;
piping
for
sootblowers,
service
air,
flame
scanners,
drip
drain
vents,
precipitators,
ash
water,
pyrites,
and
fluidizing
air;
coal
transport
piping,
pulverizers
and
motors;
coal
feeders;
ignitor
horns,
soot
blowers,
and
flame
scanner
systems;
bottom
ash
hopper
and
clinker
grinders;
ash
pond,
ash
sluice
system,
and
flyash
removal
system,
etc.
These
modifications
were
documented
to
cost
over
17
million
dollars
(
past
value),
and
it
appears
that
many
of
these
modifications
were
necessary
to
convert
the
facilities
to
coal­
fired
units,
rather
than
to
simply
bring
the
units
into
compliance
while
burning
coal,
as
characterized
by
FPC
(
Letter
to
Mr.
Brian
Beals,
EPA,
December
24,
1996).
As
discussed
in
FDEP's
Final
Order
of
March
2,
1997,
the
ALJ's
determination
in
this
matter
was
flawed
and
in
fact
contradictory.
Based
upon
EPA's
review
of
the
record,
we
concur
with
FDEP's
finding
in
this
Order
that
there
was
no
substantiated
evidence
to
support
the
assertion
that
the
facility
remained
capable
of
co­
firing
petcoke
during
the
1970'
s
when
the
facility
fired
fuel
oil.
In
fact,
the
evidence,
as
well
as
the
ALJ's
findings
themselves,
support
the
contrary
determination
that
the
facility
was
"
converted"
from
firing
liquid
fuel
to
firing
solid
fuel
during
the
late
1970'
s,
well
after
the
1975
date
in
the
exemption
invoked
by
FPC.

B.
The
use
of
petroleum
coke
was
not
designed
and
built
into
Units
1
and
2.
The
alternative
fuels
exemption
is
not
contained
in
the
Act,
but
was
added
to
the
PSD
regulations
in
1974
(
the
current
version
being
codified
in
1978)
such
that
the
definition
of
modification
would
be
consistent
with
that
used
under
the
New
Source
Performance
Standards
(
NSPS),
as
intended
by
Section
169(
2)(
C)
of
the
Act.
The
stated
intent
of
the
NSPS
exemption
was
to
"
eliminate
inequities
where
equipment
had
been
put
into
partial
operation
prior
to
the
proposal
of
the
standards,"
36
FR
15,704
(
August
3,
1971).
The
current
NSPS
regulations,
at
40
C.
F.
R.
§
60.14(
e)(
4),
contain
an
analogue
to
the
PSD
alternatives
fuel
exemption
at
40
C.
F.
R.
§
52.21(
b)(
2)(
ii)(
e),
which
provides
that
the
use
of
an
alternative
fuel
or
raw
material
shall
not
be
considered
a
modification
if:
.
.
.
the
existing
facility
was
designed
to
accommodate
the
alternative
use.
A
facility
shall
be
considered
to
accommodate
an
alternative
fuel
or
raw
material
if
that
use
could
be
accomplished
under
the
facility's
construction
specifications
as
amended
prior
to
the
change.
.
.
While
the
original
NSPS
exemption
was
changed
slightly
to
allow
for
changes
to
the
"
original"
design
specification
(
40
FR
58,416
(
December
16,1975)),
the
alterations
did
not
change
the
intent
of
the
exemption
­­­
to
grandfather
voluntary
fuel
switches
that
a
facility
had
designed
for
and
built
into
its
system
prior
to
January
6,
1975.
The
only
fuels
contemplated
in
the
design
and
construction
of
Units
1
And
2
were
coal
and
oil.
Nothing
in
the
design
or
construction
documents
for
Units
1
and
2
suggests
that
FPC
considered
petcoke
as
a
fuel
for
these
units,
nor
does
anything
in
those
documents
suggest
that
the
design
or
construction
was
intended
to
accommodate
the
potential
use
of
petcoke
as
a
fuel.
For
example,
the
facility's
1971
operating
permit
application
for
Unit
2
required
the
source
to
identify
"
fuels"
by
type,
and
required
that
such
identification
"
be
specific."
FPC
identified
only
coal
as
the
fuel
type
in
this
document
and
all
other
pre­
1975
documents
made
available
to
EPA.
As
discussed
above,
the
purpose
of
the
alternative
fuels
exemption
was
to
eliminate
any
inequity
faced
by
utilities
which
designed
and
constructed
units
to
burn
more
than
one
fuel,
but
which
were
not
burning
all
of
those
fuels
as
of
January
6,
1975.
For
example,
absent
the
exemption,
a
facility
equipped
to
burn
coal
and
oil,
but
which
was
only
burning
oil
at
the
time
the
NSPS
were
adopted,
would
be
subject
to
the
NSPS
and
subsequently
PSD
review
merely
by
switching
back
to
coal.
Therefore,
EPA
believes
it
is
reasonable
to
interpret
the
alternative
fuels
exemption
to
apply
only
to
fuels
which
were
contemplated
in
the
design
and
construction
of
a
unit
prior
to
January
6,
1975
and
which
the
unit
remained
continuously
able
to
burn.
Units
1
and
2
do
not
meet
these
criteria,
as
they
were
never
designed
for
petcoke
and,
through
conversion
to
oil,
lost
the
ability
to
burn
solid
fuel
prior
to
January
6,
1975.
Furthermore,
in
the
burning
of
petcoke,
FPC
does
not
face
the
inequity
remedied
by
the
alternative
fuels
exemption.
To
interpret
this
provision
as
allowing
a
facility
to
use
"
any"
fuel
that
it
could
possibly
burn
prior
to
January
6,
1997,
regardless
of
whether
such
fuels
were
originally
contemplated
or
included
in
the
original
design,
improperly
expands
the
availability
of
the
intended
PSD
exemption.
To
do
so
would
also
establish
an
obvious
inequity,
neither
intended
nor
likely
to
be
overlooked
by
EPA
in
crafting
the
exemption,
whereby
facilities
constructed
prior
to
1975
would
be
able
to
burn
any
number
of
fuels
without
complying
with
PSD
or
NSPS
requirements
and
those
constructed
after
this
date
would
be
subject
to
review
and
substantive
requirements.

C.
The
proposed
petroleum
coke­
coal
fuel
blend
is
not
an
"
alternative
fuel"
within
the
meaning
of
the
exemption.
As
discussed
in
Alabama
Power
Co.
v.
Costle,
the
PSD
exemption
at
40
C.
F.
R.
§
52.21(
b)(
2)(
iii)(
e)
and
the
corresponding
Florida
provision
at
62­
212.400(
2)(
c)
4
F.
A.
C.
were
intended
to
grandfather
"
voluntary
fuel
switches
by
emission
sources
which
were
designed
to
accommodate
the
alternative
fuels
prior
to
January
6,
1975."
The
provision
was
not
intended
to
provide
a
loop­
hole
by
which
facilities
may
add
various
substances,
such
as
waste
products
or
waste
fuels,
to
their
primary
fuels
without
being
subject
to
PSD
review.
The
Federal
Register
notices
and
background
information
documents
that
speak
to
this
particular
exemption
only
reference
primary
fuels,
such
as
coal,
oil
and
gas.
At
the
time
the
alternative
fuel
exemption
was
promulgated,
EPA
contemplated
"
switches"
between
primary
fuels.
Therefore,
it
is
a
reasonable
interpretation
of
the
regulations
to
limit
this
exemption
to
primary
fuels
and
not
to
apply
the
exemption
to
fuel
additives
that
the
facility
was
neither
designed
nor
built
to
use
as
a
primary
fuel.
FPC
is
currently
burning
coal
as
their
primary
fuel.
It
is
EPA's
determination
that
burning
a
95%
coal,
5%
petcoke
blend
does
not
constitute
a
"
switch"
to
an
"
alternative"
fuel
as
intended
by
the
exemption.
Rather,
the
blending
in
of
5%
petcoke
is
a
change
in
the
current
method
of
operation
that
is
subject
to
PSD
review.
The
above
interpretations
are
consistent
with
FDEP's
and
EPA's
longstanding
interpretations
of
the
"
capable
of
accommodating"
exemption.
As
you
are
aware,
there
are
several
EPA
guidance
memoranda,
including
a
June
7,
1983
document
from
this
office
to
Mr.
Steve
Smallwood
of
FDEP,
that
interpret
the
exemption
to
require
that
the
facility
be
"
designed"
and
continuously
able
to
accommodate
the
use
of
a
specified
alternative
fuel.
This
guidance
clearly
states:
In
order
for
a
plant
to
be
capable
of
accommodating
coal,
the
company
must
show
not
only
that
the
design
(
i.
e.,
construction
specifications)
for
the
source
contemplated
the
equipment,
but
also
that
the
equipment
actually
was
installed
and
still
remains
in
existence.
Otherwise,
it
cannot
reasonably
be
concluded
that
the
use
of
coal
was
"
designed
into
the
source."
FDEP's
past
implementation
of
its
new
source
review
regulations
has
also
been
consistent
with
this
interpretation.
According
to
FDEP's
December
24,
1996
letter
from
C.
H.
Fancy,
Bureau
of
Air
Regulation,
to
Mr.
Brian
Beals,
EPA,
requesting
assistance
with
the
FPC
PSD
applicability
determination,
FDEP
had
treated
as
major
modifications,
the
use
of
a
petroleum
coke­
coal
blend
in
five
coal­
fired
units
in
Florida
for
the
purposes
of
PSD
permitting
as
of
that
date.
As
documented
in
FDEP's
letter:
"
in
each
case,
the
proposals
have
been
treated
as
changes
in
method
of
operation
to
which
PSD
is
applicable
unless
they
are
able
to
'
net
out'
by
demonstrating
that
there
will
be
no
significant
increases
in
PSD
pollutants."
To
remedy
the
above
identified
deficiency,
the
title
V
permit
must
include
a
compliance
schedule,
consistent
with
40
C.
F.
R.
§
70.5(
c)(
8)(
iii),
that
requires
FPC
to
obtain
a
PSD
permit
fulfilling
State
and
federal
PSD
requirements
and
40
C.
F.
R.
§
70.6(
c)(
3).
Progress
reports
referenced
under
40
C.
F.
R.
§
70.6(
c)(
4)
must
be
required
by
the
permit.
Any
additional
requirements
resulting
from
the
PSD
review,
including
requirements
for
control
equipment
and
emission
limitations,
will
have
to
be
incorporated
into
the
title
V
permit
through
permit
modification.
Alternatively,
the
State
may
concurrently
issue
proposed
PSD
and
title
V
permits.
As
a
third
option,
the
State
could
issue
a
valid
synthetic
minor
permit,
limiting
the
emissions
increase
from
the
proposed
change
to
less
than
the
applicable
PSD
significance
levels.
As
above,
such
conditions
would
need
to
be
incorporated
into
the
title
V
permit.

2.
Periodic
Monitoring
­
Conditions
A.
14.
and
B.
13.,
in
conjunction
with
Condition
I.
6.,
require
that
the
source
conduct
annual
testing
for
particulate
matter
whenever
fuel
oil
is
burned
for
more
than
400
hours
in
the
preceding
year.
The
Statement
of
Basis
states
that
this
testing
frequency
"
is
justified
by
the
low
emission
rate
documented
in
previous
emission
tests
while
firing
fuel
oil"
and
that
the
"
Department
has
determined
that
sources
with
emissions
less
than
half
of
the
effective
standard
shall
test
annually."

While
EPA
has
in
the
past
accepted
this
approach
as
adequate
periodic
monitoring
for
particulate
matter,
it
has
done
so
only
for
uncontrolled
natural
gas
and
fuel
oil­
fired
units.
The
units
addressed
in
Conditions
A.
14.
and
B.
13.,
primarily
burn
coal
and
use
add­
on
control
equipment
(
i.
e.,
electrostatic
precipitators)
to
comply
with
the
applicable
particulate
matter
standards.
In
order
to
provide
reasonable
assurance
of
compliance,
the
results
of
annual
stack
testing
will
have
to
be
supplemented
with
additional
monitoring.
Furthermore,
the
results
of
an
annual
test
alone
would
not
constitute
an
adequate
basis
for
the
annual
compliance
certification
that
the
facility
is
required
to
submit
for
these
units
in
order
to
certify
continuous
compliance
with
the
pound/
hour
particular
matter
limit.

The
most
common
approach
to
addressing
periodic
monitoring
for
particulate
emission
limits
on
units
with
add­
on
controls
is
to
establish
either
an
opacity
or
a
control
device
parameter
indicator
range
that
would
provide
evidence
of
proper
control
device
operation.
The
primary
goal
of
such
monitoring
is
to
provide
reasonable
assurance
of
compliance,
and
one
way
of
achieving
this
goal
is
to
use
opacity
data
or
control
device
operating
parameter
data
from
previous
successful
compliance
tests
to
identify
a
range
of
values
that
has
corresponded
to
compliance
in
the
past.
Operating
within
the
range
of
values
identified
in
this
manner
would
provide
assurance
that
the
control
device
is
operating
properly
and
would
serve
as
the
basis
for
an
annual
compliance
certification.
Depending
upon
the
margin
of
compliance
during
the
tests
used
to
establish
the
opacity
or
control
device
parameter
indicator
range,
going
outside
the
range
could
represent
either
a
period
of
time
when
an
exceedance
of
the
applicable
standard
is
likely
or
it
could
represent
a
trigger
for
initiating
corrective
action
to
prevent
an
exceedance
of
the
standard.
In
order
to
avoid
any
confusion
regarding
the
consequences
of
going
outside
the
indicator
range,
the
permit
should
clearly
state
if
doing
so
is
evidence
that
a
standard
has
been
exceeded
and
should
specify
whether
corrective
action
must
be
taken
when
a
source
operates
outside
the
established
indicator
range.

3.
Periodic
Monitoring
­
Conditions
C.
5.
and
D.
4.
require
that
the
source
conduct
Method
9
tests
once
annually
for
the
fly
ash
handling
system
(
Emission
Units
#
006,
#
008,
#
009,
and
#
010)
and
the
bottom
ash
storage
silo
(
Emission
Unit
#
014),
respectively.
For
units
with
control
equipment
(
i.
e.,
baghouses),
this
typically
does
not
constitute
adequate
periodic
monitoring
to
ensure
continuous
compliance
with
the
visible
emissions
standards.
It
is
also
particularly
important
in
this
case
to
include
adequate
periodic
monitoring
with
regard
to
the
fly
ash
handling
system
since
it
has
been
limited
to
only
5
percent
opacity
in
lieu
of
stack
testing
for
particulate
matter.
Therefore,
the
permit
needs
to
include
provisions
requiring
that
the
source
conduct
qualitative
observations
of
visible
emissions
on
a
daily
basis
(
i.
e.,
Method
22)
and
that
Method
9
tests
be
conducted
within
24
hours
of
any
abnormal
qualitative
survey.
As
an
alternative,
since
these
units
are
controlled
by
baghouses,
the
source
may
opt
to
establish
a
parametric
monitoring
program.
For
instance,
the
permit
could
specify
ranges
for
parameters,
such
as
pressure
drop,
that
would
provide
reasonable
assurance
that
the
source
is
in
compliance
with
the
applicable
standards.

4.
Periodic
Monitoring
­
The
material
handling
activities
supporting
the
steam
generating
units
(
Emission
Unit
#
016)
are
subject
to
a
visible
emissions
limit
of
20
percent
opacity;
however,
the
permit
does
not
specify
the
frequency
for
testing.
To
certify
compliance
with
the
applicable
opacity
limit,
the
source
should
be
required
to
conduct
a
Method
9
test
at
least
once
annually.
To
provide
reasonable
assurance
of
continuous
compliance,
the
source
needs
to
conduct
(
and
record
the
results
of)
qualitative
observations
(
i.
e.,
Method
22)
at
least
once
daily
with
follow­
up
Method
9
tests
within
24
hours
of
any
abnormal
visible
emissions
unless
the
statement
of
basis
provides
justification
for
reduced
frequency.

5.
Appropriate
Averaging
Times
­
Conditions
A.
6.,
B.
4.(
a)(
1),
F.
3.,
and
G.
2.
do
not
specify
averaging
times
for
the
respective
particulate
matter
emission
limits.
Because
the
stringency
of
emission
limits
is
a
function
of
both
magnitude
and
averaging
time,
appropriate
averaging
times
must
be
added
to
the
permit
in
order
for
the
limits
to
be
practicably
enforceable.
An
approach
that
may
be
used
to
address
this
deficiency
is
to
include
a
general
condition
in
the
permit
stating
that
the
averaging
times
for
all
specified
emission
standards
are
tied
to
or
based
on
the
run
time
of
the
test
method(
s)
used
for
determining
compliance.

6.
Periodic
Monitoring
(
Practical
Enforceability)
­
Conditions
C.
1.
and
D.
1.
limit
the
mass
flow
rates
of
fly
ash
through
the
fly
ash
handling
system
and
bottom
ash
through
the
bottom
ash
storage
silo,
respectively;
however,
the
permit
does
not
contain
any
provisions
to
practicably
enforce
such
limits.
The
permit
needs
to
include
monitoring
and/
or
recordkeeping
requirements
such
as
the
maintenance
of
daily
records
of
the
mass
throughputs
for
the
affected
units
to
provide
reasonable
assurance
of
compliance
with
the
applicable
limits.

7.
Periodic
Monitoring
(
Practical
Enforceability)
­
Conditions
F.
1.
and
G.
1.
limit
the
volume
flow
rates
of
seawater
through
the
cooling
towers,
Emission
Units
#
013
and
#
015,
respectively;
however,
the
permit
does
not
contain
any
provisions
to
practicably
enforce
such
limits.
The
permit
needs
to
include
provisions
requiring
the
source
to
monitor
and
record
the
flow
of
seawater
through
the
cooling
towers.
­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­

II.
General
Comments
1.
Compliance
Certification
­
Facility­
wide
Condition
11
of
the
permit
should
specifically
reference
the
required
components
of
Appendix
TV­
3,
which
lists
the
compliance
certification
requirements
of
40
C.
F.
R.
§
70.6(
c)(
5)(
iii),
to
ensure
that
complete
certification
information
is
submitted
to
EPA.

2.
Acid
Rain
­
The
Phase
II
Acid
Rain
Application
and
Compliance
Plan
received
on
December
22,
1995,
which
are
referenced
as
attachments
made
part
of
the
permit
(
see
page
1
of
proposed
permit),
should
also
be
referenced
under
Section
IV,
Subsection
A.
1.

3.
Acid
Rain
­
The
NOx
Early
Election
requirements
and
limits
located
in
Subsection
B
(
addressing
Phase
I
Acid
Rain)
for
Units
2,
4,
and
5
of
the
Acid
Rain
part
of
the
proposed
title
V
permit
should
be
moved
to
Subsection
A
(
addressing
Acid
Rain,
Phase
II).
Moving
these
requirements
should
clarify
that
FDEP
is
approving
and
incorporating
the
NOx
Early
Election
requirements
into
the
Phase
II
permit
portion.