Document ID: EPA-HQ-OAR-2002-0060-0338
Agency: epa
Document Type: Proposed Rule
Title: National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines.
Posted Date: 2003-01-14T05:00Z

Tuesday,

January
14,
2003
Part
II
Environmental
Protection
Agency
40
CFR
Part
63
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Stationary
Combustion
Turbines;
Proposed
Rule
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Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
63
[
OAR
 
2002
 
0060;
FRL
 
7417
 
8]

RIN
2060
 
AG67
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Stationary
Combustion
Turbines
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Proposed
rule.

SUMMARY:
This
action
proposes
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
for
stationary
combustion
turbines.
We
have
identified
stationary
combustion
turbines
as
major
sources
of
hazardous
air
pollutants
(
HAP)
emissions
such
as
formaldehyde,
toluene,
benzene,
and
acetaldehyde.
The
proposed
NESHAP
would
implement
section
112(
d)
of
the
Clean
Air
Act
(
CAA)
by
requiring
all
major
sources
to
meet
HAP
emission
standards
reflecting
the
application
of
the
maximum
achievable
control
technology
(
MACT)
for
combustion
turbines.
We
estimate
that
20
percent
of
the
stationary
combustion
turbines
affected
by
the
proposed
rule
will
be
located
at
major
sources.
As
a
result,
the
environmental,
energy,
and
economic
impacts
presented
in
this
preamble
reflect
these
estimates.
The
proposed
standards
would
protect
public
health
by
reducing
exposure
to
air
pollution,
by
reducing
total
national
HAP
emissions
by
an
estimated
81
tons/
year
in
the
5th
year
after
the
standards
are
promulgated.
This
action
also
proposes
to
add
Method
323
of
40
CFR
part
63,
appendix
A
for
the
measurement
of
formaldehyde
emissions
from
natural
gas­
fired
stationary
sources.
DATES:
Comments.
Submit
comments
on
or
before
February
13,
2003.
Public
Hearing.
If
anyone
contacts
us
requesting
to
speak
at
a
public
hearing
by
January
24,
2003,
we
will
hold
a
public
hearing
on
January
29,
2003.
ADDRESSES:
Comments
may
be
submitted
by
mail
(
in
duplicate,
if
possible)
to
EPA
West
(
Air
Docket),
U.
S.
EPA
(
MD
 
6102T),
Room
B
 
108,
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460,
Attention
Docket
ID
No.
OAR
 
2002
 
0060.
By
hand
delivery/
courier,
comments
may
be
submitted
(
in
duplicate,
if
possible)
to
EPA
Docket
Center
(
Air
Docket),
U.
S.
EPA,
MD
 
6102T),
Room
B
 
108,
1301
Constitution
Avenue,
NW.,
Washington,
DC
20460,
Attention
Docket
ID
No.
OAR
 
2002
 
0060.
Comments
may
be
submitted
electronically
according
to
the
detailed
instructions
as
provided
in
the
SUPPLEMENTARY
INFORMATION
section.
Public
Hearing.
If
a
public
hearing
is
held,
it
will
be
held
at
the
new
EPA
facility
complex
in
Research
Triangle
Park,
North
Carolina.
Docket.
Docket
No.
OAR
 
2002
 
0060
contains
supporting
information
used
in
developing
the
standards.
The
docket
is
located
at
the
U.
S.
EPA,
1301
Constitution
Avenue,
NW.,
Washington,
DC
20460
in
room
B102,
and
may
be
inspected
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.

FOR
FURTHER
INFORMATION
CONTACT:
Mr.
Sims
Roy,
Combustion
Group,
Emission
Standards
Division
(
MD
 
C439
 
01),
U.
S.
EPA,
Research
Triangle
Park,
North
Carolina
27711;
telephone
number
(
919)
541
 
5263;
facsimile
number
(
919)
541
 
5450;
electronic
mail
address
roy.
sims@
epa.
gov.

SUPPLEMENTARY
INFORMATION:
Regulated
Entities.
Categories
and
entities
potentially
regulated
by
this
action
include:

Category
SIC
NAICS
Examples
of
regulated
entities
Any
industry
using
a
stationary
combustion
turbine
as
defined
in
the
regulation.
4911
2211
Electric
power
generation,
transmission,
or
distribution
4922
486210
Natural
gas
transmission.
1311
211111
Crude
petroleum
and
natural
gas
production.
1321
211112
Natural
gas
liquids
producers.
4931
221
Electric
and
other
services
combined.

This
table
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
for
readers
regarding
entities
likely
to
be
regulated
by
this
action.
To
determine
whether
your
facility
is
regulated
by
this
action,
you
should
examine
the
applicability
criteria
in
§
63.6085
of
the
proposed
rule.
If
you
have
any
questions
regarding
the
applicability
of
this
action
to
a
particular
entity,
consult
the
person
listed
in
the
preceding
FOR
FURTHER
INFORMATION
CONTACT
section.
Docket.
The
EPA
has
established
an
official
public
docket
for
this
action
under
Docket
ID
No.
OAR
 
2002
 
0060.
The
official
public
docket
consists
of
the
documents
specifically
referenced
in
this
action,
any
public
comments
received,
and
other
information
related
to
this
action.
Although
a
part
of
the
official
docket,
the
public
docket
does
not
include
Confidential
Business
Information
(
CBI)
or
other
information
whose
disclosure
is
restricted
by
statute.
The
official
public
docket
is
the
collection
of
materials
that
is
available
for
public
viewing
at
the
Air
and
Radiation
Docket
in
the
EPA
Docket
Center,
(
EPA/
DC)
EPA
West,
Room
B108,
1301
Constitution
Ave.,
NW.,
Washington,
DC.
The
EPA
Docket
Center
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Reading
Room
is
(
202)
566
 
1744,
and
the
telephone
number
for
the
Air
and
Radiation
Docket
is
(
202)
566
 
1742.
A
reasonable
fee
may
be
charged
for
copying
docket
materials.
Electronic
Access.
You
may
access
this
Federal
Register
document
electronically
through
the
EPA
Internet
under
the
Federal
Register
listings
at
http://
www.
epa.
gov/
fedrgstr/.
An
electronic
version
of
the
public
docket
is
available
through
EPA's
electronic
public
docket
and
comment
system,
EPA
Dockets.
You
may
use
EPA
Dockets
at
http://
www.
epa.
gov/
edocket/
to
submit
or
view
public
comments,
access
the
index
listing
of
the
contents
of
the
official
public
docket,
and
to
access
those
documents
in
the
public
docket
that
are
available
electronically.
Once
in
the
system,
select
``
search,''
then
key
in
the
appropriate
docket
identification
number.
Certain
types
of
information
will
not
be
placed
in
the
EPA
Dockets.
Information
claimed
as
CBI
and
other
information
whose
disclosure
is
restricted
by
statute,
which
is
not
included
in
the
official
public
docket,
will
not
be
available
for
public
viewing
in
EPA's
electronic
public
docket.
The
EPA's
policy
is
that
copyrighted
material
will
not
be
placed
in
EPA's
electronic
public
docket
but
will
be
available
only
in
printed
paper
form
in
the
official
public
docket.
To
the
extent
feasible,
publicly
available
docket
materials
will
be
made
available
in
EPA's
electronic
public
docket.
When
a
document
is
selected
from
the
index
list
in
EPA
Dockets,
the
system
will
identify
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January
14,
2003
/
Proposed
Rules
whether
the
document
is
available
for
viewing
in
EPA's
electronic
public
docket.
Although
not
all
docket
materials
may
be
available
electronically,
you
may
still
access
any
of
the
publicly
available
docket
materials
through
the
docket
facility
identified
above.
The
EPA
intends
to
work
towards
providing
electronic
access
to
all
of
the
publicly
available
docket
materials
through
EPA's
electronic
public
docket.
For
public
commenters,
it
is
important
to
note
that
EPA's
policy
is
that
public
comments,
whether
submitted
electronically
or
on
paper,
will
be
made
available
for
public
viewing
in
EPA's
electronic
public
docket
as
EPA
receives
them
and
without
change,
unless
the
comment
contains
copyrighted
material,
CBI,
or
other
information
whose
disclosure
is
restricted
by
statute.
When
EPA
identifies
a
comment
containing
copyrighted
material,
EPA
will
provide
a
reference
to
that
material
in
the
version
of
the
comment
that
is
placed
in
EPA's
electronic
public
docket.
The
entire
printed
comment,
including
the
copyrighted
material,
will
be
available
in
the
public
docket.
Public
comments
submitted
on
computer
disks
that
are
mailed
or
delivered
to
the
docket
will
be
transferred
to
EPA's
electronic
public
docket.
Public
comments
that
are
mailed
or
delivered
to
the
Docket
will
be
scanned
and
placed
in
EPA's
electronic
public
docket.
Where
practical,
physical
objects
will
be
photographed,
and
the
photograph
will
be
placed
in
EPA's
electronic
public
docket
along
with
a
brief
description
written
by
the
docket
staff.
For
additional
information
about
EPA's
electronic
public
docket
visit
EPA
Dockets
online
or
see
67
FR
38102,
May
31,
2002.
You
may
submit
comments
electronically,
by
mail,
or
through
hand
delivery/
courier.
To
ensure
proper
receipt
by
EPA,
identify
the
appropriate
docket
identification
number
in
the
subject
line
on
the
first
page
of
your
comment.
Please
ensure
that
your
comments
are
submitted
within
the
specified
comment
period.
Comments
received
after
the
close
of
the
comment
period
will
be
marked
``
late.''
The
EPA
is
not
required
to
consider
these
late
comments.
However,
late
comments
may
be
considered
if
time
permits.
Electronically.
If
you
submit
an
electronic
comment
as
prescribed
below,
EPA
recommends
that
you
include
your
name,
mailing
address,
and
an
e­
mail
address
or
other
contact
information
in
the
body
of
your
comment.
Also
include
this
contact
information
on
the
outside
of
any
disk
or
CD
ROM
you
submit,
and
in
any
cover
letter
accompanying
the
disk
or
CD
ROM.
This
ensures
that
you
can
be
identified
as
the
submitter
of
the
comment
and
allows
EPA
to
contact
you
in
case
EPA
cannot
read
your
comment
due
to
technical
difficulties
or
needs
further
information
on
the
substance
of
your
comment.
The
EPA's
policy
is
that
EPA
will
not
edit
your
comment,
and
any
identifying
or
contact
information
provided
in
the
body
of
a
comment
will
be
included
as
part
of
the
comment
that
is
placed
in
the
official
public
docket
and
made
available
in
EPA's
electronic
public
docket.
If
EPA
cannot
read
your
comment
due
to
technical
difficulties
and
cannot
contact
you
for
clarification,
EPA
may
not
be
able
to
consider
your
comment.
Your
use
of
EPA's
electronic
public
docket
to
submit
comments
to
EPA
electronically
is
EPA's
preferred
method
for
receiving
comments.
Go
directly
to
EPA
Dockets
at
http://
www.
epa.
gov/
edocket,
and
follow
the
online
instructions
for
submitting
comments.
To
access
EPA's
electronic
public
docket
from
the
EPA
Internet
Home
Page,
select
``
Information
Sources,''
``
Dockets,''
and
``
EPA
Dockets.''
Once
in
the
system,
select
``
search,''
and
then
key
in
Docket
ID
No.
OAR
 
2002
 
0060.
The
system
is
an
``
anonymous
access''
system,
which
means
EPA
will
not
know
your
identity,
e­
mail
address,
or
other
contact
information
unless
you
provide
it
in
the
body
of
your
comment.
Comments
may
be
sent
by
electronic
mail
(
e­
mail)
to
a­
and­
r­
docket@
epa.
gov,
Attention
Docket
ID
No.
OAR
 
2002
 
0060.
In
contrast
to
EPA's
electronic
public
docket,
EPA's
e­
mail
system
is
not
an
``
anonymous
access''
system.
If
you
send
an
e­
mail
comment
directly
to
the
Docket
without
going
through
EPA's
electronic
public
docket,
EPA's
e­
mail
system
automatically
captures
your
email
address.
E­
mail
addresses
that
are
automatically
captured
by
EPA's
e­
mail
system
are
included
as
part
of
the
comment
that
is
placed
in
the
official
public
docket
and
made
available
in
EPA's
electronic
public
docket.
You
may
submit
comments
on
a
disk
or
CD
ROM
that
you
mail
to
the
mailing
address
identified
below.
These
electronic
submissions
will
be
accepted
in
WordPerfect
or
ASCII
file
format.
Avoid
the
use
of
special
characters
and
any
form
of
encryption.
By
Mail.
Send
your
comments
(
in
duplicate
if
possible)
to:
Air
and
Radiation
Docket
and
Information
Center,
U.
S.
EPA,
Mailcode:
6102T,
1200
Pennsylvania
Ave.,
NW,
Washington,
DC,
20460,
Attention
Docket
ID
No.
OAR
 
2002
 
0060.
The
EPA
requests
a
separate
copy
also
be
sent
to
the
contact
person
listed
above
(
see
FOR
FURTHER
INFORMATION
CONTACT).
By
Hand
Delivery
or
Courier.
Deliver
your
comments
to:
EPA
Docket
Center,
Room
B108,
1301
Constitution
Ave.,
NW,
Washington,
DC,
20460,
Attention
Docket
ID
No.
OAR
 
2002
 
0060.
Such
deliveries
are
only
accepted
during
the
Docket's
normal
hours
of
operation
as
identified
above.
Do
not
submit
information
that
you
consider
to
be
CBI
electronically
through
EPA's
electronic
public
docket
or
by
e­
mail.
Send
or
deliver
information
identified
as
CBI
only
to
the
following
address:
Mr.
Sims
Roy,
c/
o
OAQPS
Document
Control
Officer
(
Room
C404
 
2),
U.
S.
EPA,
Research
Triangle
Park,
27711,
Attention
Docket
ID
No.
OAR
 
2002
 
0060.
You
may
claim
information
that
you
submit
to
EPA
as
CBI
by
marking
any
part
or
all
of
that
information
as
CBI
(
if
you
submit
CBI
on
disk
or
CD
ROM,
mark
the
outside
of
the
disk
or
CD
ROM
as
CBI
and
then
identify
electronically
within
the
disk
or
CD
ROM
the
specific
information
that
is
CBI).
Information
so
marked
will
not
be
disclosed
except
in
accordance
with
procedures
set
forth
in
40
CFR
part
2.
In
addition
to
one
complete
version
of
the
comment
that
includes
any
information
claimed
as
CBI,
a
copy
of
the
comment
that
does
not
contain
the
information
claimed
as
CBI
must
be
submitted
for
inclusion
in
the
public
docket
and
EPA's
electronic
public
docket.
If
you
submit
the
copy
that
does
not
contain
CBI
on
disk
or
CD
ROM,
mark
the
outside
of
the
disk
or
CDROM
clearly
that
it
does
not
contain
CBI.
Information
not
marked
as
CBI
will
be
included
in
the
public
docket
and
EPA's
electronic
public
docket
without
prior
notice.
If
you
have
any
questions
about
CBI
or
the
procedures
for
claiming
CBI,
please
consult
the
person
identified
in
the
FOR
FURTHER
INFORMATION
CONTACT
section.
You
may
find
the
following
suggestions
helpful
for
preparing
your
comments:
1.
Explain
your
views
as
clearly
as
possible.
2.
Describe
any
assumptions
that
you
used.
3.
Provide
any
technical
information
and/
or
data
you
used
that
support
your
views.
4.
If
you
estimate
potential
burden
or
costs,
explain
how
you
arrived
at
your
estimate.
5.
Provide
specific
examples
to
illustrate
your
concerns.
6.
Offer
alternatives.
7.
Make
sure
to
submit
your
comments
by
the
comment
period
deadline
identified.

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9
/
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January
14,
2003
/
Proposed
Rules
8.
To
ensure
proper
receipt
by
EPA,
identify
the
appropriate
docket
identification
number
in
the
subject
line
on
the
first
page
of
your
response.
It
would
also
be
helpful
if
you
provided
the
name,
date,
and
Federal
Register
citation
related
to
your
comments.
Public
Hearing.
Persons
interested
in
presenting
oral
testimony
or
inquiring
as
to
whether
a
hearing
is
to
be
held
should
contact
Mrs.
Kelly
Hayes,
Combustion
Group,
Emission
Standards
Division
(
MD
 
C439
 
01),
U.
S.
EPA,
Research
Triangle
Park,
North
Carolina
27711,
(
919)
541
 
5578
at
least
2
days
in
advance
of
the
public
hearing.
Persons
interested
in
attending
the
public
hearing
must
also
call
Mrs.
Hayes
to
verify
the
time,
date,
and
location
of
the
hearing.
The
public
hearing
will
provide
interested
parties
the
opportunity
to
present
data,
views,
or
arguments
concerning
the
proposed
rule.
If
a
public
hearing
is
requested
and
held,
EPA
will
ask
clarifying
questions
during
the
oral
presentation
but
will
not
respond
to
the
presentations
or
comments.
Written
statements
and
supporting
information
will
be
considered
with
equivalent
weight
as
any
oral
statement
and
supporting
information
presented
at
a
public
hearing,
if
held.
Outline.
The
information
presented
in
this
preamble
is
organized
as
follows:

I.
Background
A.
What
is
the
regulatory
development
background
of
the
source
category?
B.
What
is
the
source
of
authority
for
development
of
NESHAP?
C.
What
criteria
are
used
in
the
development
of
NESHAP?
D.
What
are
the
health
effects
associated
with
HAP
from
stationary
combustion
turbines?
II.
Summary
of
the
Proposed
Rule
A.
Am
I
subject
to
the
proposed
rule?
B.
What
source
categories
and
subcategories
are
affected
by
the
proposed
rule?
C.
What
are
the
primary
sources
of
HAP
emissions
and
what
are
the
emissions?
D.
What
are
the
emission
limitations
and
operating
limitations?
E.
What
are
the
initial
compliance
requirements?
F.
What
are
the
continuous
compliance
provisions?
G.
What
monitoring
and
testing
methods
are
available
to
measure
these
low
concentrations
of
CO
and
formaldehyde?
H.
What
are
the
notification,
recordkeeping
and
reporting
requirements?
III.
Rationale
for
Selecting
the
Proposed
Standards
A.
How
did
we
select
the
source
category
and
any
subcategories?
B.
What
about
stationary
combustion
turbines
located
at
area
sources?
C.
What
is
the
affected
source?
D.
How
did
we
determine
the
basis
and
level
of
the
proposed
emission
limitations
for
existing
sources?
E.
How
did
we
determine
the
basis
and
level
of
the
proposed
emission
limitations
and
operating
limitations
for
new
sources?
F.
How
did
we
select
the
format
of
the
standard
for
new
diffusion
flame
combustion
turbines?
G.
How
did
we
select
the
initial
compliance
requirements?
H.
How
did
we
select
the
continuous
compliance
requirements?
I.
How
did
we
select
the
monitoring
and
testing
methods
to
measure
these
low
concentrations
of
CO
and
formaldehyde?
J.
How
did
we
select
the
notification,
recordkeeping
and
reporting
requirements?
IV.
Summary
of
Environmental,
Energy
and
Economic
Impacts
A.
What
are
the
air
quality
impacts?
B.
What
are
the
cost
impacts?
C.
What
are
the
economic
impacts?
D.
What
are
the
nonair
health,
environmental
and
energy
impacts?
V.
Solicitation
of
Comments
and
Public
Participation
A.
General
B.
Can
we
achieve
the
goals
of
the
proposed
rule
in
a
less
costly
manner?
C.
Limited
Use
Subcategory
VI.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
B.
Executive
Order
13132,
Federalism
C.
Executive
Order
13175,
Consultation
and
Coordination
with
Indian
Tribal
Governments
D.
Executive
Order
13045,
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
E.
Executive
Order
13211,
Actions
Concerning
Regulations
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
F.
Unfunded
Mandates
Reform
Act
of
1995
G.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.
H.
Paperwork
Reduction
Act
I.
National
Technology
Transfer
and
Advancement
Act
I.
Background
A.
What
Is
the
Regulatory
Development
Background
of
the
Source
Category?
In
September
1996,
we
chartered
the
Industrial
Combustion
Coordinated
Rulemaking
(
ICCR)
advisory
committee
under
the
Federal
Advisory
Committee
Act
(
FACA).
The
committee's
objective
was
to
develop
recommendations
for
regulations
for
several
combustion
source
categories
under
sections
112
and
129
of
the
CAA.
The
ICCR
advisory
committee,
also
known
as
the
Coordinating
Committee,
formed
Source
Work
Groups
for
the
various
combustor
types
covered
under
the
ICCR.
One
work
group,
the
Combustion
Turbine
Work
Group,
was
formed
to
research
issues
related
to
stationary
combustion
turbines.
The
Combustion
Turbine
Work
Group
submitted
recommendations,
information,
and
data
analyses
to
the
Coordinating
Committee,
which
in
turn
considered
them
and
submitted
recommendations
and
information
to
us.
The
Committee's
2­
year
charter
expired
in
September
1998.
We
considered
the
Committee's
recommendations
in
developing
the
proposed
rule
for
stationary
combustion
turbines.

B.
What
Is
the
Source
of
Authority
for
Development
of
NESHAP?
Section
112
of
the
CAA
requires
us
to
list
categories
and
subcategories
of
major
sources
and
area
sources
of
HAP
and
to
establish
NESHAP
for
the
listed
source
categories
and
subcategories.
The
stationary
turbine
source
category
was
listed
on
July
16,
1992
(
57
FR
31576).
Major
sources
of
HAP
are
those
that
have
the
potential
to
emit
greater
than
10
ton/
yr
of
any
one
HAP
or
25
ton/
yr
of
any
combination
of
HAP.

C.
What
Criteria
Are
Used
in
the
Development
of
NESHAP?
Section
112
of
the
CAA
requires
that
we
establish
NESHAP
for
the
control
of
HAP
from
both
new
and
existing
major
sources.
The
CAA
requires
the
NESHAP
to
reflect
the
maximum
degree
of
reduction
in
emissions
of
HAP
that
is
achievable.
This
level
of
control
is
commonly
referred
to
as
the
MACT.
The
MACT
floor
is
the
minimum
control
level
allowed
for
NESHAP
and
is
defined
under
section
112(
d)(
3)
of
the
CAA.
In
essence,
the
MACT
floor
ensures
that
the
standard
is
set
at
a
level
that
assures
that
all
major
sources
achieve
the
level
of
control
at
least
as
stringent
as
that
already
achieved
by
the
better
controlled
and
lower
emitting
sources
in
each
source
category
or
subcategory.
For
new
sources,
the
MACT
standards
cannot
be
less
stringent
than
the
emission
control
that
is
achieved
in
practice
by
the
best
controlled
similar
source.
The
MACT
standards
for
existing
sources
can
be
less
stringent
than
standards
for
new
sources,
but
they
cannot
be
less
stringent
than
the
average
emission
limitation
achieved
by
the
best
performing
12
percent
of
existing
sources
in
the
category
or
subcategory
(
or
the
best
performing
5
sources
for
categories
or
subcategories
with
fewer
than
30
sources).
In
developing
MACT,
we
also
consider
control
options
that
are
more
stringent
than
the
floor.
We
may
establish
standards
more
stringent
than
the
floor
based
on
the
consideration
of
cost
of
achieving
the
emissions
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/
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January
14,
2003
/
Proposed
Rules
reductions,
any
nonair
quality
health
and
environmental
impacts,
and
energy
requirements.

D.
What
Are
the
Health
Effects
Associated
With
HAP
From
Stationary
Combustion
Turbines?

Emission
data
collected
during
development
of
the
proposed
NESHAP
show
that
several
HAP
are
emitted
from
stationary
combustion
turbines.
These
HAP
emissions
are
formed
during
combustion
or
result
from
HAP
compounds
contained
in
the
fuel
burned.
Among
the
HAP
which
have
been
measured
in
emission
tests
that
were
conducted
at
natural
gas
fired
and
distillate
oil
fired
combustion
turbines
are:
1,3
butadiene,
acetaldehyde,
acrolein,
benzene,
ethylbenzene,
formaldehyde,
naphthalene,
poly
aromatic
hydrocarbons
(
PAH)
propylene
oxide,
toluene,
and
xylenes.
Metallic
HAP
from
distillate
oil
fired
stationary
combustion
turbines
that
have
been
measured
are:
arsenic,
beryllium,
cadmium,
chromium,
lead,
manganese,
mercury,
nickel,
and
selenium.
Although
numerous
HAP
may
be
emitted
from
combustion
turbines,
only
a
few
account
for
essentially
all
the
mass
of
HAP
emissions
from
stationary
combustion
turbines.
These
HAP
are:
formaldehyde,
toluene,
benzene,
and
acetaldehyde.
The
HAP
emitted
in
the
largest
quantity
is
formaldehyde.
Formaldehyde
is
a
probable
human
carcinogen
and
can
cause
irritation
of
the
eyes
and
respiratory
tract,
coughing,
dry
throat,
tightening
of
the
chest,
headache,
and
heart
palpitations.
Acute
inhalation
has
caused
bronchitis,
pulmonary
edema,
pneumonitis,
pneumonia,
and
death
due
to
respiratory
failure.
Long­
term
exposure
can
cause
dermatitis
and
sensitization
of
the
skin
and
respiratory
tract.
Other
HAP
emitted
in
significant
quantities
from
stationary
combustion
turbines
include
toluene,
benzene,
and
acetaldehyde.
The
health
effect
of
primary
concern
for
toluene
is
dysfunction
of
the
central
nervous
system
(
CNS).
Toluene
vapor
also
causes
narcosis.
Controlled
exposure
of
human
subjects
produced
mild
fatigue,
weakness,
confusion,
lacrimation,
and
paresthesia;
at
higher
exposure
levels
there
were
also
euphoria,
headache,
dizziness,
dilated
pupils,
and
nausea.
After
effects
included
nervousness,
muscular
fatigue,
and
insomnia
persisting
for
several
days.
Acute
exposure
may
cause
irritation
of
the
eyes,
respiratory
tract,
and
skin.
It
may
also
cause
fatigue,
weakness,
confusion,
headache,
and
drowsiness.
Very
high
concentrations
may
cause
unconsciousness
and
death.
Benzene
is
a
known
human
carcinogen.
The
health
effects
of
benzene
include
nerve
inflammation,
CNS
depression,
and
cardiac
sensitization.
Chronic
exposure
to
benzene
can
cause
fatigue,
nervousness,
irritability,
blurred
vision,
and
labored
breathing
and
has
produced
anorexia
and
irreversible
injury
to
the
bloodforming
organs;
effects
include
aplastic
anemia
and
leukemia.
Acute
exposure
can
cause
dizziness,
euphoria,
giddiness,
headache,
nausea,
staggering
gait,
weakness,
drowsiness,
respiratory
irritation,
pulmonary
edema,
pneumonia,
gastrointestinal
irritation,
convulsions,
and
paralysis.
Benzene
can
also
cause
irritation
to
the
skin,
eyes,
and
mucous
membranes.
Acetaldehyde
is
a
probable
human
carcinogen.
The
health
effects
for
acetaldehyde
are
irritation
of
the
eyes,
mucous
membranes,
skin,
and
upper
respiratory
tract,
and
it
is
a
CNS
depressant
in
humans.
Chronic
exposure
can
cause
conjunctivitis,
coughing,
difficult
breathing,
and
dermatitis.
Chronic
exposure
may
cause
heart
and
kidney
damage,
embryotoxicity,
and
teratogenic
effects.
Acetaldehyde
is
a
potential
carcinogen
in
humans.

II.
Summary
of
the
Proposed
Rule
A.
Am
I
Subject
to
the
Proposed
Rule?

The
proposed
rule
applies
to
you
if
you
own
or
operate
a
stationary
combustion
turbine
which
is
located
at
a
major
source
of
HAP
emissions.
A
major
source
of
HAP
emissions
is
a
plant
site
that
emits
or
has
the
potential
to
emit
any
single
HAP
at
a
rate
of
10
tons
(
9.07
megagrams)
or
more
per
year
or
any
combination
of
HAP
at
a
rate
of
25
tons
(
22.68
megagrams)
or
more
per
year.
Section
112(
n)(
4)
of
the
CAA
requires
that
the
aggregation
of
HAP
for
purposes
of
determining
whether
an
oil
and
gas
production
facility
is
major
or
nonmajor
be
done
only
with
respect
to
particular
sites
within
the
source
and
not
on
a
total
aggregated
site
basis.
We
incorporated
the
requirements
of
section
112(
n)(
4)
of
the
CAA
into
our
NESHAP
for
Oil
and
Natural
Gas
Production
Facilities
in
subpart
HH
of
part
63.
As
in
subpart
HH,
we
plan
to
aggregate
HAP
emissions
for
the
purposes
of
determining
a
major
HAP
source
for
turbines
only
with
respect
to
particular
sites
within
an
oil
and
gas
production
facility.
The
sites
are
called
surface
sites
and
may
include
a
combination
of
any
of
the
following
equipment;
glycol
dehydrators,
tanks
which
have
potential
for
flash
emissions,
reciprocating
internal
combustion
engines
and
combustion
turbines.

Six
subcategories
have
been
defined
within
the
stationary
combustion
turbine
source
category.
While
all
stationary
combustion
turbines
are
subject
to
the
proposed
rule,
each
subcategory
has
distinct
requirements.
For
example,
existing
diffusion
flame
combustion
turbines
and
stationary
combustion
turbines
with
a
rated
peak
power
output
of
less
than
1.0
megawatt
(
MW)
(
at
International
Organization
for
Standardization
(
ISO)
standard
day
conditions)
are
not
required
to
comply
with
emission
limitations,
recordkeeping
or
reporting
requirements
in
the
proposed
rule.
New
or
reconstructed
stationary
combustion
turbines
and
existing
lean
premix
stationary
combustion
turbines
with
a
rated
peak
power
output
of
1.0
MW
or
more
that
either
operate
exclusively
as
an
emergency
stationary
combustion
turbine,
as
a
limited
use
stationary
combustion
turbine,
or
as
a
stationary
combustion
turbine
which
burns
landfill
gas
or
digester
gas
as
its
primary
fuel
must
only
comply
with
the
initial
notification
requirements.
New
or
reconstructed
diffusion
flame
or
lean
premix
combustion
turbines
must
comply
with
emission
limitations,
recordkeeping
and
reporting
requirements
in
the
proposed
rule.
The
emission
limitations
for
each
subcategory
are
summarized
in
Table
2
of
this
preamble.
You
must
determine
your
source's
subcategory
to
determine
which
requirements
apply
to
your
source.

The
proposed
rule
does
not
apply
to
stationary
combustion
turbines
located
at
an
area
source
of
HAP
emissions.
An
area
source
of
HAP
emissions
is
a
plant
site
that
does
not
emit
any
single
HAP
at
a
rate
of
10
tons
(
9.07
megagrams)
or
greater
per
year
or
any
combination
of
HAP
at
a
rate
of
25
tons
(
22.68
megagrams)
or
greater
per
year.
To
determine
whether
a
facility
is
a
major
source,
EPA
will
accept
HAP
emissions
estimated
using
HAP
emission
factors
listed
in
Table
1
of
this
preamble.

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No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
TABLE
1.
 
SUMMARY
OF
HAP
EMISSION
FACTORS
Turbine
Load
Fuel
HAP
emission
factor
(
lb/
MMBtu)

Diffusion
Flame
...........................................................
All
loads
.........................................
Natural
Gas
....................................
0.0188
Diffusion
Flame
...........................................................
>
80%
..............................................
Natural
Gas
....................................
0.00479
Diffusion
Flame
...........................................................
All
loads
.........................................
Diesel
.............................................
0.00241
Diffusion
Flame
...........................................................
>
80%
..............................................
Diesel
.............................................
0.00233
Lean
Premix
...............................................................
All
loads
.........................................
Natural
Gas
....................................
0.000644
Lean
Premix
...............................................................
>
80%
..............................................
Natural
Gas
....................................
0.000212
If
the
turbine
mainly
operates
at
high
load,
the
emission
factor
for
greater
than
80
percent
load
should
be
used.
If
the
turbine
operates
on
varying
loads,
the
emission
factor
for
all
loads
should
be
used.
Emission
factors
were
developed
based
on
data
from
the
combustion
turbines
emissions
database.
A
copy
of
the
emissions
database
may
be
downloaded
off
the
internet
at
http://
www.
epa.
gov/
ttn/
atw/
combust/
turbine/
turbpg.
html.
The
proposed
rule
does
not
cover
duct
burners.
They
are
part
of
the
waste
heat
recovery
unit
in
a
combined
cycle
system.
Waste
heat
recovery
units,
whether
part
of
a
cogeneration
system
or
a
combined
cycle
system,
are
steam
generating
units
and
are
not
covered
by
the
proposed
rule.
Finally,
the
proposed
rule
does
not
apply
to
stationary
combustion
engine
test
cells/
stands
since
these
facilities
will
be
covered
by
another
NESHAP,
40
CFR
part
63,
subpart
PPPPP.

B.
What
Source
Categories
and
Subcategories
Are
Affected
by
the
Proposed
Rule?
The
proposed
rule
covers
stationary
combustion
turbines.
A
stationary
combustion
turbine
is
any
simple
cycle
stationary
combustion
turbine,
any
regenerative/
recuperative
cycle
stationary
combustion
turbine,
the
combustion
turbine
portion
of
any
stationary
cogeneration
cycle
combustion
system,
or
the
combustion
turbine
portion
of
any
stationary
combined
cycle
steam/
electric
generating
system.
Stationary
means
that
the
combustion
turbine
is
not
self
propelled
or
intended
to
be
propelled
while
performing
its
function.
The
combustion
turbine
may,
however,
be
mounted
on
a
vehicle
for
portability
or
transportability.
Stationary
combustion
turbines
have
been
divided
into
the
following
six
subcategories:
(
1)
Emergency
stationary
combustion
turbines,
(
2)
limited
use
stationary
combustion
turbines,
(
3)
stationary
combustion
turbines
which
fire
landfill
gas
or
digester
gas
as
their
primary
fuel,
(
4)
stationary
combustion
turbines
of
less
than
1
MW
rated
peak
power
output,
(
5)
stationary
diffusion
flame
combustion
turbines,
and
(
6)
stationary
lean
premix
combustion
turbines.
An
emergency
stationary
combustion
turbine
means
any
stationary
combustion
turbine
that
operates
as
a
mechanical
or
electrical
power
source
when
the
primary
power
source
for
a
facility
has
been
rendered
inoperable
by
an
emergency
situation.
One
example
is
emergency
power
for
critical
networks
or
equipment
when
electric
power
from
the
normal
source
of
power
is
interrupted.
Another
example
is
to
pump
water
in
the
case
of
fire
or
flood.
Peaking
units
at
electric
utilities
and
other
types
of
stationary
combustion
turbines
that
typically
operate
at
low
capacity
factors,
but
are
not
confined
to
operation
in
an
emergency,
are
not
emergency
stationary
combustion
turbines.
A
limited
use
stationary
combustion
turbine
means
any
stationary
combustion
turbine
that
operates
50
hours
or
less
per
calendar
year.
One
example
is
a
stationary
combustion
turbine
used
to
stabilize
electrical
power
voltage
and
protect
sensitive
electronic
equipment
during
periods
of
brown
outs.
Another
example
is
periodic
operation
of
an
emergency
stationary
combustion
turbine
to
check
readiness
or
perform
maintenance
checks.
Since
electrical
power
has
not
been
interrupted
during
these
readiness
and
maintenance
checks,
the
stationary
combustion
turbine
is
not
operating
as
an
emergency
stationary
combustion
turbine.
We
are
specifically
soliciting
comments
on
creating
a
subcategory
of
limited
use
combustion
turbines
with
a
capacity
utilization
of
10
percent
or
less.
This
is
further
discussed
in
the
``
Solicitation
of
Comments
and
Public
Participation''
section
of
this
preamble.
Stationary
combustion
turbines
which
fire
landfill
gas
or
digester
gas
as
their
primary
fuel
qualify
as
a
separate
subcategory
because
the
types
of
control
available
for
these
turbines
are
limited.
Stationary
combustion
turbines
of
less
than
1
MW
rated
peak
power
output
were
also
identified
as
a
subcategory.
These
small
stationary
combustion
turbines
are
few
in
number
and,
to
our
knowledge,
none
use
emission
control
technology
to
reduce
HAP.
Given
the
very
small
size
of
these
stationary
combustion
turbines
and
the
lack
of
application
of
HAP
emission
control
technologies,
we
have
concerns
about
the
applicability
of
HAP
emission
control
technology
to
them.
The
stationary
diffusion
flame
combustion
turbines
subcategory
includes
only
diffusion
flame
combustion
turbines
that
are
greater
than
1
MW
rated
peak
power
output
and
are
not
emergency
stationary
combustion
turbines,
limited
use
stationary
combustion
turbines,
or
stationary
combustion
turbines
which
fire
landfill
gas
or
digester
gas
as
their
primary
fuel.
In
a
diffusion
flame
combustor,
the
fuel
and
air
are
injected
at
the
combustor
and
are
mixed
only
by
diffusion
prior
to
ignition.
Hazardous
air
pollutants
emissions
from
these
turbines
can
be
significantly
decreased
with
the
addition
of
air
pollution
control
equipment.
The
stationary
lean
premix
combustion
turbines
subcategory
includes
only
lean
premix
combustion
turbines
that
are
greater
than
1
MW
rated
peak
power
output
and
are
not
emergency
stationary
combustion
turbines,
limited
use
stationary
combustion
turbines,
or
stationary
combustion
turbines
which
fire
landfill
gas
or
digester
gas
as
their
primary
fuel.
Lean
premix
technology,
introduced
in
the
1990'
s,
was
developed
to
reduce
NOX
emissions
without
the
use
of
add
on
controls.
In
a
staged
lean
premix
combustor,
the
air
and
fuel
are
thoroughly
mixed
to
form
a
lean
mixture
before
delivery
to
the
combustor.
The
staged
entry
limits
the
flame
temperature
and
the
residence
time
at
the
peak
flame
temperature.
Lean
premix
combustors
emit
lower
levels
of
NOX,
carbon
monoxide
(
CO),
formaldehyde
and
other
HAP
than
diffusion
flame
combustion
turbines.

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/
Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
C.
What
Are
the
Primary
Sources
of
HAP
Emissions
and
What
Are
the
Emissions?
The
sources
of
emissions
are
the
exhaust
gases
from
combustion
of
gaseous
and
liquid
fuels
in
a
stationary
combustion
turbine.
Hazardous
air
pollutants
that
are
present
in
the
exhaust
gases
from
stationary
combustion
turbines
include
formaldehyde,
toluene,
benzene,
and
acetaldehyde.

D.
What
Are
the
Emission
Limitations
and
Operating
Limitations?
As
the
owner
or
operator
of
an
existing
lean
premix
stationary
combustion
turbine
or
a
new
or
reconstructed
stationary
combustion
turbine
located
at
a
major
source
of
HAP
emissions,
you
must
comply
with
one
of
the
following
two
emission
limitations
by
the
effective
date
of
the
standard
(
or
upon
startup
if
you
start
up
your
stationary
combustion
turbine
after
the
effective
date
of
the
standard):
(
1)
Reduce
CO
emissions
in
the
exhaust
from
the
new
or
reconstructed
stationary
combustion
turbine
by
95
percent
or
more,
if
you
use
an
oxidation
catalyst
emission
control
device;
or
(
2)
reduce
the
concentration
of
formaldehyde
in
the
exhaust
from
the
new
or
reconstructed
stationary
combustion
turbine
to
43
parts
per
billion
by
volume
or
less,
dry
basis
(
ppbvd),
at
15
percent
oxygen,
if
you
use
means
other
than
an
oxidation
catalyst
emission
control
device.
There
are
no
operating
limitations
if
you
choose
to
comply
with
the
emission
limitation
for
CO
emission
reduction.
If
you
comply
with
the
emission
limitation
for
formaldehyde
emissions
and
your
stationary
combustion
turbine
is
not
lean
premix
or
diffusion
flame,
you
must
comply
with
any
additional
operating
limitations
approved
by
the
Administrator,
as
discussed
later.
Finally,
as
mentioned
earlier,
stationary
combustion
turbines
with
a
rated
peak
power
output
of
less
than
1.0
MW,
emergency
stationary
combustion
turbines,
limited
use
stationary
combustion
turbines,
and
stationary
combustion
turbines
which
burn
landfill
gas
or
digester
gas
as
their
primary
fuel,
are
not
required
to
comply
with
these
emission
limitations.
In
addition,
existing
diffusion
flame
stationary
combustion
turbines,
are
not
required
to
comply
with
these
emission
limitations.
The
emission
limitations
for
each
subcategory
are
summarized
in
Table
2
of
this
preamble.

TABLE
2.
 
SUMMARY
OF
EMISSION
LIMITATIONS
Subcategory
Emission
limitation
Comment
Existing
Diffusion
Flame
Stationary
Combustion
Turbine
 
1.0
MW.
None
................................................................................
No
requirements.

Existing
Lean
Premix
Stationary
Combustion
Turbine
 
1.0
MW.
(
1)
Reduce
CO
emissions
by
95%
or
more,
if
you
use
an
oxidation
catalyst
emission
control
device.
or
(
2)
Reduce
the
concentration
of
formaldehyde
to
43
ppbvd
@
15%
O2,
if
you
use
means
other
than
an
oxidation
catalyst
emission
control
device.
or
New/
Reconstructed
Stationary
Combustion
Turbine
 
1.0
MW.
Emergency
Stationary
Combustion
Turbine
....................
or
No
emission
limitations
....................................................
Initial
notification
requirements
only.
Limited
Use
Stationary
Combustion
Turbine
or
Landfill/
Digester
Gas
Stationary
Combustion
Turbine.
 
1
MW
Stationary
Combustion
Turbine
..........................
None
................................................................................
No
requirements.

E.
What
Are
the
Initial
Compliance
Requirements?
The
initial
compliance
requirements
for
a
stationary
combustion
turbine
vary
depending
on
the
subcategory
of
your
combustion
turbine
and
your
control
strategy.
If
you
operate
a
new
or
reconstructed
stationary
combustion
turbine
and
comply
with
the
emission
limitation
for
CO
emission
reduction,
you
must
install
a
continuous
emission
monitoring
system
(
CEMS)
to
measure
CO
and
either
carbon
dioxide
or
oxygen
simultaneously
at
the
inlet
and
outlet
of
the
oxidation
catalyst
emission
control
device.
To
demonstrate
initial
compliance,
you
must
conduct
an
initial
performance
evaluation
using
Performance
Specifications
3
and
4A
of
40
CFR
part
60,
appendix
B.
You
must
demonstrate
that
the
reduction
of
CO
emissions
is
at
least
95
percent
using
the
first
4­
hour
average
after
a
successful
performance
evaluation.
Your
inlet
and
outlet
measurements
must
be
on
a
dry
basis
and
corrected
to
15
percent
oxygen
or
equivalent
carbon
dioxide
content.
You
must
also
conduct
an
annual
relative
accuracy
test
audit
(
RATA)
of
the
CEMS
using
Performance
Specifications
3
and
4A
of
40
CFR
part
60,
appendix
B.
If
you
operate
a
new
or
reconstructed
combustion
turbine
or
an
existing
lean
premix
combustion
turbine
and
comply
with
the
emission
limitation
for
formaldehyde
emissions,
you
must
conduct
an
initial
performance
test
using
Test
Method
320
of
40
CFR
part
63,
appendix
A;
ARB
Method
430
of
California
Environmental
Protection
Agency,
Air
Resources
Board,
2020
L
Street,
Sacramento,
CA
95812;
or
EPA
Solid
Waste
(
SW)
 
846
Method
0011
to
demonstrate
that
the
outlet
concentration
of
formaldehyde
is
43
ppbvd
or
less
(
corrected
to
15
percent
oxygen).
Natural
gas­
fired
sources
may
also
use
the
proposed
Test
Method
323
of
40
CFR
part
63,
appendix
A,
to
measure
formaldehyde.
To
correct
to
15
percent
oxygen,
dry
basis,
you
must
measure
oxygen
using
Method
3A
or
3B
of
40
CFR
part
60,
appendix
A,
and
moisture
using
Method
4
of
40
CFR
part
60,
appendix
A.
As
stated
previously,
if
you
choose
to
comply
with
the
emission
limitation
for
formaldehyde
emissions
and
your
stationary
combustion
turbine
is
not
lean
premix
or
diffusion
flame,
you
must
also
petition
the
Administrator
for
approval
of
operating
limitations
or
approval
of
no
operating
limitations.
If
you
petition
the
Administrator
for
approval
of
operating
limitations,
your
petition
must
include
the
following:
(
1)
Identification
of
the
specific
parameters
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Federal
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/
Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
you
propose
to
use
as
operating
limitations;
(
2)
a
discussion
of
the
relationship
between
these
parameters
and
HAP
emissions,
identifying
how
HAP
emissions
change
with
changes
in
these
parameters
and
how
limitations
on
these
parameters
will
serve
to
limit
HAP
emissions;
(
3)
a
discussion
of
how
you
will
establish
the
upper
and/
or
lower
values
for
these
parameters
which
will
establish
the
limits
on
these
parameters
in
the
operating
limitations;
(
4)
a
discussion
identifying
the
methods
you
will
use
to
measure
and
the
instruments
you
will
use
to
monitor
these
parameters,
as
well
as
the
relative
accuracy
and
precision
of
these
methods
and
instruments;
and
(
5)
a
discussion
identifying
the
frequency
and
methods
for
recalibrating
the
instruments
you
will
use
for
monitoring
these
parameters.
If
you
petition
the
Administrator
for
approval
of
no
operating
limitations,
your
petition
must
include
the
following:
(
1)
Identification
of
the
parameters
associated
with
operation
of
the
stationary
combustion
turbine
and
any
emission
control
device
which
could
change
intentionally
(
e.
g.,
operator
adjustment,
automatic
controller
adjustment,
etc.)
or
unintentionally
(
e.
g.,
wear
and
tear,
error,
etc.)
on
a
routine
basis
or
over
time;
(
2)
a
discussion
of
the
relationship,
if
any,
between
changes
in
these
parameters
and
changes
in
HAP
emissions;
(
3)
for
those
parameters
with
a
relationship
to
HAP
emissions,
a
discussion
of
whether
establishing
limitations
on
these
parameters
would
serve
to
limit
HAP
emissions;
(
4)
for
those
parameters
with
a
relationship
to
HAP
emissions,
a
discussion
of
how
you
could
establish
upper
and/
or
lower
values
for
these
parameters
which
would
establish
limits
on
these
parameters
in
operating
limitations;
(
5)
for
those
parameters
with
a
relationship
to
HAP
emissions,
a
discussion
identifying
the
methods
you
could
use
to
measure
these
parameters
and
the
instruments
you
could
use
to
monitor
them,
as
well
as
the
relative
accuracy
and
precision
of
these
methods
and
instruments;
(
6)
for
these
parameters,
a
discussion
identifying
the
frequency
and
methods
for
recalibrating
the
instruments
you
could
use
to
monitor
them;
and
(
7)
a
discussion
of
why,
from
your
point
of
view,
it
is
infeasible
or
unreasonable
to
adopt
these
parameters
as
operating
limitations.

F.
What
Are
the
Continuous
Compliance
Provisions?
Several
general
continuous
compliance
requirements
apply
to
stationary
combustion
turbines
required
to
comply
with
the
emission
limitations.
You
are
required
to
comply
with
the
emission
limitations
and
the
operating
limitations
(
if
applicable)
at
all
times,
except
during
startup,
shutdown,
and
malfunction
of
your
stationary
combustion
turbine.
You
must
also
operate
and
maintain
your
stationary
combustion
turbine,
air
pollution
control
equipment,
and
monitoring
equipment
according
to
good
air
pollution
control
practices
at
all
times,
including
startup,
shutdown,
and
malfunction.
You
must
conduct
all
monitoring
at
all
times
that
the
stationary
combustion
turbine
is
operating,
except
during
periods
of
malfunction
of
the
monitoring
equipment
or
necessary
repairs
and
quality
assurance
or
control
activities,
such
as
calibration
checks.
To
demonstrate
continuous
compliance
with
the
CO
emission
reduction
limitation,
you
must
calibrate
and
operate
your
CEMS
according
to
the
requirements
in
40
CFR
63.8.
You
must
continuously
monitor
and
record
the
CO
concentration
before
and
after
the
oxidation
catalyst
emission
control
device
and
calculate
the
percent
reduction
of
CO
emissions
hourly.
The
reduction
in
CO
emissions
must
be
95
percent
or
more,
based
on
a
rolling
4­
hour
average,
averaged
every
hour.
To
demonstrate
continuous
compliance
with
the
operating
limitations
(
if
applicable),
you
must
continuously
monitor
the
values
of
any
parameters
which
have
been
approved
by
the
Administrator
as
operating
limitations.
The
proposed
rule
does
not
require
your
lean
premix
combustion
turbine
to
demonstrate
continuous
compliance.
It
is
assumed
that
if
you
meet
the
low
NOX
emission
levels
required
by
your
federally
enforceable
permit
(
or
guaranteed
by
the
turbine
manufacturer
if
there
is
no
permit
level),
your
turbine
is
in
compliance
with
the
43
ppbvd
formaldehyde
emission
limit.

G.
What
Monitoring
and
Testing
Methods
Are
Available
to
Measure
These
Low
Concentrations
of
CO
and
Formaldehyde?
Continuous
emissions
monitoring
systems
are
available
which
can
accurately
measure
CO
emission
reduction
at
the
low
concentrations
found
in
the
combustion
turbine
exhaust
following
an
oxidation
catalyst
emission
control
device.
Our
performance
specification
for
CO
CEMS
(
PS
 
4A)
of
40
CFR
part
60,
appendix
A,
however,
has
not
been
updated
recently
and
does
not
reflect
the
performance
capabilities
of
these
systems.
We
are
currently
undertaking
a
review
of
PS
 
4A
of
40
CFR
part
60,
appendix
A,
for
CO
CEMS
and,
in
conjunction
with
this
effort,
we
solicit
comments
on
the
performance
capabilities
of
CO
CEMS
and
their
ability
to
accurately
measure
the
low
concentrations
of
CO
experienced
in
the
exhaust
of
a
combustion
turbine
following
an
oxidation
catalyst
emission
control
device.
Similarly,
our
Fourier
Transform
Infrared
(
FTIR)
test
method,
Method
320
of
40
CFR
part
63,
appendix
A,
as
well
as
EPA
SW
 
846
Method
0011
and
CARB
Method
430,
can
be
used
to
accurately
measure
formaldehyde
concentrations
in
the
exhaust
of
a
combustion
turbine
as
low
as
43
ppbvd.
As
these
test
methods
are
currently
written,
however,
they
do
not
provide
for
this
level
of
accuracy.
These
methods
must
be
used
with
some
revisions
to
achieve
such
accuracy.
As
a
result,
we
are
currently
undertaking
a
review
of
our
FTIR
method,
Method
320
of
40
CFR
part
63,
appendix
A,
to
incorporate
revisions
to
ensure
it
can
be
used
to
accurately
measure
formaldehyde
concentrations
as
low
as
43
ppbvd
in
the
exhaust
from
a
combustion
turbine.
In
conjunction
with
this
effort,
we
solicit
comments
on
revisions
to
Method
320
of
40
CFR
part
63,
appendix
A,
to
ensure
accurate
measurement
of
such
low
concentrations
of
formaldehyde.
We
are
also
proposing
to
add
Method
323
of
40
CFR
part
63,
appendix
A.
Method
323
is
for
the
measurement
of
formaldehyde
emissions
from
natural
gas­
fired
stationary
sources
using
acetyl
acetone
derivitization.
We
solicit
comments
on
the
use
of
this
method
to
measure
low
concentrations
of
formaldehyde.

H.
What
Are
the
Notification,
Recordkeeping
and
Reporting
Requirements?
You
must
submit
all
of
the
applicable
notifications
as
listed
in
the
NESHAP
General
Provisions
(
40
CFR
part
63,
subpart
A),
including
an
initial
notification,
notification
of
performance
test
or
evaluation,
and
a
notification
of
compliance,
for
each
stationary
combustion
turbine
which
must
comply
with
the
emission
limitations.
If
your
new
or
reconstructed
source
is
located
at
a
major
source,
has
greater
than
1
MW
rated
peak
power
output,
and
is
an
emergency
stationary
combustion
turbine,
limited
use
stationary
combustion
turbine
or
a
combustion
turbine
which
fires
landfill
or
digester
gas
as
its
primary
fuel,
you
must
submit
only
an
initial
notification.
For
each
combustion
turbine
subject
to
the
emission
limitations,
you
must
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record
all
of
the
data
necessary
to
determine
if
you
are
in
compliance
with
the
emission
limitations.
Your
records
must
be
in
a
form
suitable
and
readily
available
for
review.
You
must
also
keep
each
record
for
5
years
following
the
date
of
each
occurrence,
measurement,
maintenance,
report,
or
record.
Records
must
remain
on
site
for
at
least
2
years
and
then
can
be
maintained
off
site
for
the
remaining
3
years.
You
must
submit
a
compliance
report
semiannually
for
each
new
or
reconstructed
stationary
combustion
turbine
that
must
comply
with
the
CO
emission
reduction
limitation.
This
report
must
contain
the
company
name
and
address,
a
statement
by
a
responsible
official
that
the
report
is
accurate,
a
statement
of
compliance,
or
documentation
of
any
deviation
from
the
requirements
of
the
proposed
rule
during
the
reporting
period.

III.
Rationale
for
Selecting
the
Proposed
Standards
A.
How
Did
We
Select
the
Source
Category
and
Any
Subcategories?

Stationary
combustion
turbines
can
be
major
sources
of
HAP
emissions
and,
as
a
result,
we
listed
them
as
a
major
source
category
for
regulatory
development
under
section
112
of
the
CAA.
Section
112
of
the
CAA
allows
us
to
establish
subcategories
within
a
source
category
for
the
purpose
of
regulation.
Consequently,
we
evaluated
several
criteria
associated
with
stationary
combustion
turbines
which
might
serve
as
potential
subcategories.
We
identified
six
subcategories
of
stationary
combustion
turbines
located
at
major
sources:
(
1)
Emergency
stationary
combustion
turbines,
(
2)
limited
use
stationary
combustion
turbines,
(
3)
stationary
combustion
turbines
which
fire
landfill
gas
or
digester
gas
as
their
primary
fuel,
(
4)
stationary
combustion
turbines
of
less
than
1
MW
rated
peak
power
output,
(
5)
stationary
diffusion
flame
combustion
turbines,
and
(
6)
stationary
lean
premix
combustion
turbines.
Stationary
combustion
turbines
can
be
classified
as
either
diffusion
flame
or
lean
premix.
We
examined
formaldehyde
test
data
for
both
diffusion
flame
and
lean
premix
stationary
combustion
turbines
and
observed
that
uncontrolled
formaldehyde
emissions
for
stationary
lean
premix
combustion
turbines
are
significantly
lower
than
those
of
stationary
diffusion
flame
combustion
turbines.
An
analysis
of
the
formaldehyde
emissions
data
shows
that
uncontrolled
formaldehyde
emissions
from
stationary
lean
premix
combustion
turbines
are
comparable
to
controlled
formaldehyde
emissions
from
stationary
diffusion
flame
combustion
turbines
controlled
with
oxidation
catalyst
systems.
Due
to
the
difference
in
the
two
technologies,
we
decided
to
establish
subcategories
for
diffusion
flame
and
lean
premix
stationary
combustion
turbines.
We
identified
emergency
stationary
combustion
turbines
as
a
subcategory.
Emergency
stationary
combustion
turbines
operate
only
in
emergencies,
such
as
a
loss
of
power
provided
by
another
source.
These
types
of
stationary
combustion
turbines
operate
infrequently
and,
when
called
upon
to
operate,
must
respond
without
failure
and
without
lengthy
periods
of
startup.
These
conditions
limit
the
applicability
of
HAP
emission
control
technology
to
emergency
stationary
combustion
turbines.
Limited
use
stationary
combustion
turbines
were
also
identified
as
a
subcategory.
These
types
of
stationary
combustion
turbines
are
operated
50
hours
per
calendar
year
or
less.
They
are
used
primarily
to
stabilize
electrical
power
voltage
levels
during
periods
of
brown
outs
to
prevent
damage
to
sensitive
electronic
equipment.
As
with
emergency
stationary
combustion
turbines,
they
are
operated
infrequently
and,
when
called
upon
to
operate,
must
respond
without
failure
and
without
lengthy
periods
of
startup.
These
conditions
limit
the
applicability
of
HAP
emission
control
technology.
Similarly,
stationary
combustion
turbines
which
fire
landfill
gas
or
digester
gas
as
their
primary
fuel
were
identified
as
a
subcategory.
Landfill
and
digester
gases
contain
a
family
of
chemicals
referred
to
as
siloxanes,
which
limit
the
application
of
HAP
emission
control
technology.
Stationary
combustion
turbines
of
less
than
1
MW
rated
peak
power
output
were
also
identified
as
a
subcategory.
We
believe
these
small
stationary
combustion
turbines
are
few
in
number
and,
to
our
knowledge,
none
use
emission
control
technology
to
reduce
HAP.
Given
the
very
small
size
of
these
stationary
combustion
turbines
and
the
lack
of
application
of
HAP
emission
control
technologies,
we
have
concerns
about
the
applicability
of
HAP
emission
control
technology
to
them.

B.
What
About
Stationary
Combustion
Turbines
Located
at
Area
Sources?
The
proposed
rule
does
not
apply
to
stationary
combustion
turbines
located
at
an
area
source
of
HAP
emissions.
In
developing
our
Urban
Air
Toxics
Strategy,
we
identified
area
sources
we
believe
warrant
regulation
to
protect
the
environment
and
the
public
health
and
satisfy
the
statutory
requirements
in
section
112
of
the
CAA
pertaining
to
area
sources.
Stationary
combustion
turbines
located
at
area
sources
were
not
included
on
that
list.
As
a
result,
the
proposed
rule
does
not
apply
to
these
stationary
combustion
turbines.

C.
What
Is
the
Affected
Source?
The
proposed
rule
applies
to
any
stationary
combustion
turbine
located
at
a
major
source.
Consequently,
stationary
combustion
turbines
located
at
major
sources
of
HAP
emissions
are
the
affected
source
under
the
proposed
rule.

D.
How
Did
We
Determine
the
Basis
and
Level
of
the
Proposed
Emission
Limitations
for
Existing
Sources?
As
established
in
section
112
of
the
CAA,
the
MACT
standards
must
be
no
less
stringent
than
the
MACT
floor.
The
MACT
floor
for
existing
sources
is
the
average
emission
limitation
achieved
by
the
best
performing
12
percent
of
existing
sources.

1.
MACT
Floor
for
Existing
Diffusion
Flame
Combustion
Turbines
To
determine
the
MACT
floor
for
existing
stationary
diffusion
flame
combustion
turbines,
we
primarily
consulted
two
databases:
an
inventory
database
and
an
emissions
database.
The
MACT
floors
and
MACT
for
stationary
diffusion
flame
combustion
turbines
located
at
major
sources
were
developed
through
the
analyses
of
these
databases.
The
inventory
database
provides
population
information
on
stationary
combustion
turbines
in
the
United
States
(
U.
S.)
and
was
constructed
in
order
to
support
the
proposed
rulemaking.
Data
in
the
inventory
database
are
based
on
information
from
available
databases,
such
as
the
Aerometric
Information
Retrieval
System
(
AIRS),
the
Ozone
Transport
and
Assessment
Group
(
OTAG),
and
State
and
local
agencies'
databases.
The
first
version
of
the
database
was
released
in
1997.
Subsequent
versions
have
been
released
reflecting
additional
or
updated
data.
The
most
recent
release
of
the
database
is
version
4,
released
in
November
1998.
The
inventory
database
contains
information
on
approximately
4,800
stationary
combustion
turbines.
The
current
stationary
combustion
turbine
population
is
estimated
to
be
about
8,000
turbines.
Therefore,
the
inventory
database
represents
about
60
percent
of
the
stationary
combustion
turbines
in
the
U.
S.
At
least
90
percent
of
those
turbines
are
assumed
to
be
diffusion
flame
combustion
turbines,
based
on
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conversations
with
turbine
manufacturers.
The
information
contained
in
the
inventory
database
is
believed
to
be
representative
of
stationary
combustion
turbines
primarily
because
of
its
comprehensiveness.
The
database
includes
both
small
and
large
stationary
combustion
turbines
in
different
user
segments.
Forty­
eight
percent
are
``
industrial,''
39
percent
are
``
utility,''
and
13
percent
are
``
pipeline.''
Note
that
independent
power
producers
(
IPP)
are
included
in
the
utility
and
industrial
segments.
We
examined
the
inventory
database
for
information
on
HAP
emission
control
technology.
There
were
no
turbines
controlled
with
oxidation
catalyst
systems
in
the
inventory
database
so
we
used
information
supplied
by
catalyst
vendors.
There
are
about
200
oxidation
catalyst
systems
installed
in
the
U.
S.
The
only
control
technology
currently
proven
to
reduce
HAP
emissions
from
stationary
diffusion
flame
combustion
turbines
is
an
oxidation
catalyst
emission
control
device,
such
as
a
CO
oxidation
catalyst.
These
control
devices
are
used
to
reduce
CO
emissions
and
are
currently
installed
on
several
stationary
combustion
turbines.
However,
less
than
3
percent
of
existing
stationary
diffusion
flame
combustion
turbines
in
the
U.
S.,
based
on
information
in
our
inventory
database
and
information
from
catalyst
vendors,
are
equipped
with
oxidation
catalyst
emission
control
devices;
thus,
the
average
of
the
best
performing
12
percent
of
existing
diffusion
flame
combustion
turbines
is
no
HAP
emissions
reductions.
We
also
investigated
the
use
of
good
operating
practices
for
stationary
diffusion
flame
combustion
turbines
to
determine
if
the
use
of
such
practices
might
identify
a
MACT
floor.
There
are
no
references
in
the
inventory
database
to
good
operating
practices
for
any
stationary
combustion
turbines.
Most
stationary
diffusion
flame
combustion
turbines
will
not
operate
unless
preset
conditions
established
by
the
manufacturer
are
met.
Stationary
diffusion
flame
combustion
turbines,
by
manufacturer
design,
permit
little
operator
involvement
and
there
are
no
operating
parameters,
such
as
air/
fuel
ratio,
for
the
operator
to
adjust.
We
concluded,
therefore,
that
there
are
no
specific
good
operating
practices
which
could
reduce
HAP
emissions
or
which
could
serve
to
identify
a
MACT
floor.
We
also
investigated
switching
fuels
in
existing
diffusion
flame
combustion
turbines
using
fuels
which
result
in
higher
HAP
emissions
with
fuels
that
result
in
lower
HAP
emissions.
When
we
compared
the
HAP
emissions
of
the
various
fuels
from
combustion
turbines
using
the
April
2000
revision
of
Chapter
3.1
(
Stationary
Gas
Turbines)
of
``
Compilation
of
Air
Pollutant
Emission
Factors
AP
 
42,
Fifth
Edition,
Volume
1:
Stationary
Point
and
Area
Sources,''
we
could
not
find
a
fuel
that
was
clearly
less
HAP
emitting.
The
summation
of
emission
factors
for
various
HAP
when
using
natural
gas
(
usually
considered
the
cleanest
fuel),
diesel
fuel,
landfill,
or
digester
gas
were
comparable
based
on
the
emission
factor
information
that
is
available.
Therefore,
we
could
not
identify
a
MACT
floor
based
on
use
of
a
particular
fuel.
Another
approach
we
investigated
to
identify
a
MACT
floor
was
to
review
the
requirements
in
existing
State
regulations
and
permits.
No
State
regulations
exist
for
HAP
emission
limits
for
stationary
combustion
turbines.
Only
one
State
permit
limitation
for
a
single
HAP
(
benzene)
was
identified.
Therefore,
we
were
unable
to
use
State
regulations
or
permits
to
identify
a
MACT
floor.
As
a
result,
we
concluded
the
MACT
floor
for
existing
stationary
diffusion
flame
combustion
turbines
is
no
emissions
reductions.

2.
MACT
for
Existing
Diffusion
Flame
Combustion
Turbines
To
determine
MACT
for
existing
stationary
diffusion
flame
combustion
turbines,
we
evaluated
regulatory
alternatives
more
stringent
than
the
MACT
floor.
For
existing
diffusion
flame
sources,
in
terms
of
an
emission
control
technology
which
could
serve
as
the
basis
for
MACT,
we
considered
two
beyond­
the­
floor
options.
The
first
option
considered
was
the
use
of
an
oxidation
catalyst
emission
control
device.
However,
we
concluded
that
the
incremental
cost
per
ton
of
HAP
removed
for
this
option
is
excessive.
The
incremental
cost
per
ton
is
the
difference
in
annual
costs
between
this
regulatory
option
and
the
MACT
floor
divided
by
the
difference
in
annual
emissions.
It
is
often
used
as
a
measure
of
the
economic
feasibility
of
applying
emission
control
technology
to
a
source.
We
also
considered
the
nonair
health,
environmental,
and
energy
impacts
of
an
oxidation
catalyst
system,
as
discussed
previously
in
this
preamble,
and
concluded
that
there
would
be
only
a
small
energy
impact
and
no
nonair
health
or
environmental
impacts.
However,
as
stated
above,
we
did
not
adopt
this
regulatory
option
due
to
cost
considerations.
The
second
option
considered
was
to
switch
fuels
in
existing
turbines
using
fuels
which
result
in
higher
HAP
emissions
with
fuels
that
result
in
lower
HAP
emissions.
As
stated
above,
we
could
not
find
a
fuel
that
was
clearly
less
HAP
emitting.
Therefore,
we
could
find
no
basis
to
further
consider
fuel
switching
as
a
beyond­
the­
floor
HAP
emissions
reductions
option.
We
were
unable
to
identify
any
other
beyond­
thefloor
regulatory
option
to
consider.
As
discussed
above,
we
are
not
aware
of
any
specific
good
operating
practices
for
diffusion
flame
turbines
that
could
reduce
HAP
emissions.
As
a
result,
we
concluded
that
MACT
for
existing
diffusion
flame
combustion
turbines
is
the
MACT
floor
(
i.
e.,
no
emissions
reductions).

3.
MACT
Floor
for
Existing
Lean
Premix
Combustion
Turbines
There
are
an
estimated
800
lean
premix
combustion
turbines
in
the
U.
S.,
of
which
160
are
estimated
to
be
major
sources.
For
existing
lean
premix
combustion
turbines,
we
must
establish
a
MACT
floor
which
represents
the
average
emission
limitation
achieved
by
the
best
performing
12
percent
of
the
existing
sources
for
which
we
have
emissions
information.
We
have
emissions
information
on
five
existing
lean
premix
combustion
turbines.
Therefore,
we
plan
to
establish
the
MACT
floor
based
on
the
performance
of
the
best
performing
lean
premix
combustion
turbine.
(
This
best
performing
turbine
represents
the
top
20
percent
of
the
existing
turbines
for
which
we
have
emissions
information
and
will
also
be
used
to
establish
the
MACT
floor
for
new
lean
premix
combustion
turbines.)
The
best
performing
existing
lean
premix
combustion
turbine
achieved
a
level
of
formaldehyde
concentration
emission
which
averaged
6.1
parts
per
billion
(
ppb)
formaldehyde
at
15
percent
oxygen
(
O2).
This
is
the
best
performer
out
of
five
lean
premix
combustion
turbine
tests
for
which
we
have
data.
The
three­
run
average
formaldehyde
emissions
from
these
five
turbines
ranged
from
6.1
to
41
ppb
formaldehyde.
The
formaldehyde
concentrations
for
the
individual
runs
for
the
best
performing
turbine
were
5.1
ppb,
5.7
ppb,
and
7.7
ppb.
The
test
method
that
was
used
to
measure
the
emissions
from
the
best
performing
turbine
was
California
Air
Resources
Board
(
CARB)
Method
430.
We
do
not
believe
that
the
MACT
emission
limit
should
be
set
lower
than
the
limit
of
detection
of
the
method.
If
it
were,
we
could
not
determine
whether
a
source
with
test
results
at
the
limit
of
detection
was
actually
in
compliance
with
the
MACT
emission
limit.
For
the
test
runs
on
the
best
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Federal
Register
/
Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
1
1998
National
Air
Quality
and
Emission
Trends
Report,
Table
5
 
2
and
Figure
5
 
1a.
performing
turbine,
we
determined
that
the
method
had
a
minimum
detection
level
(
MDL)
of
between
2
and
3
ppb
formaldehyde.
We
expect
the
MDL
to
vary
somewhat
in
actual
practice
and,
thus,
do
not
assume
that
the
MDL
would
be
the
same
if
the
method
were
run
by
another
person
or
at
another
laboratory.
We
have
no
information
regarding
the
distribution
of
the
CARB
Method
430
MDL
actually
achieved
by
other
testers.
We
want
to
ensure
that
the
MACT
floor
reflects
the
variability
in
the
limit
of
detection
determined
by
different,
competent
testers
throughout
the
U.
S.
using
the
same
method,
i.
e.,
CARB
Method
430.
We
only
have
one
test,
the
test
conducted
on
the
best
performing
turbine,
to
try
to
determine
a
limit
of
detection
for
this
method,
and
this
is
not
enough
information
to
determine
the
variability
in
the
limit
of
detection
among
different
testers.
If
we
had
sufficient
information
on
the
limit
of
detection
determined
by
different
competent
testers
using
Method
430,
under
similar
conditions,
we
would
analyze
the
results
to
determine
the
average
limit
of
detection
and
its
standard
deviation.
To
establish
a
limit
of
detection
that
would
be
achievable
by
approximately
99
percent
of
all
the
testers,
we
would
add
three
times
the
standard
deviation
to
the
average
limit
of
detection.
Since
we
do
not
have
this
information,
we
can
attempt
to
estimate
it.
We
believe
that
it
is
reasonable
to
assume
that
the
standard
deviation
of
the
limit
of
detection
is
no
greater
than
the
single
estimate
of
the
limit
that
we
have.
If
we
multiply
the
single
value
of
the
limit
of
detection
by
three
and
add
it
to
itself,
the
result
is
an
estimate
of
the
upper
bound
for
the
limit
of
detection
that
is
four
times
the
single
measured
value
that
we
have.
Based
on
the
considerations
above,
the
lowest
MACT
floor
that
we
believe
would
take
into
account
the
variability
in
the
MDL
is
12
ppb.
This
level
provides
a
safety
factor
of
four
to
account
for
uncertainty
in
whether
testers
could
routinely
achieve
a
limit
of
detection
of
2
to
3
ppb
formaldehyde.
The
combustion
turbine
MACT
would
be
a
national
standard,
and
therefore,
the
MACT
limit
should
reflect
variations
in
the
performance
of
the
best
performing
turbine
that
could
occur.
There
are
two
major
sources
of
variability
that
together
produce
the
total
variability
observed
in
the
emissions
sample
results.
These
sources
of
variability
are:
the
actual
variability
in
the
emissions,
and
the
variability
associated
with
procedures
for
sampling
and
analyzing
the
emissions
samples.
We
believe
there
is
substantial
basis
to
conclude
that
sources
of
variability
unrelated
to
turbine
performance
account
for
the
differences
in
formaldehyde
emissions
concentrations
between
the
five
turbines.
We
discuss
these
sources
of
variability
in
more
detail
below.
When
we
began
investigating
the
possible
sources
of
the
actual
(
nonsampling
non­
analytical)
variability
in
lean
premix
combustion
turbine
emissions,
we
realized
that
turbine
performance
was
only
one
of
several
possible
sources
of
that
variability,
and
that
turbine
emissions
also
could
vary
widely
due
to
environmental
and
operational
factors
that
are
unrelated
to
turbine
performance
and
that
are
beyond
an
operator's
control.
Specifically,
formaldehyde
concentrations
are
expected
to
vary
temporally
(
e.
g.,
seasonally)
and
spatially
(
e.
g.,
geographically)
due
to
environmental
and
operational
factors
such
as
temperature,
humidity,
atmospheric
pressure,
fuel
quality,
and
the
concentrations
of
formaldehyde
present
in
the
ambient
air.
It
is
our
judgement
that
if
the
turbines
were
tested
at
various
times
during
the
year
and
at
various
locations
throughout
the
U.
S.,
the
concentration
of
formaldehyde
emitted
by
a
given
turbine
could
vary
by
a
factor
of
seven
or
more,
solely
due
to
geographic
and
temporal
differences
in
temperature,
humidity,
atmospheric
pressure,
fuel
quality,
and
formaldehyde
concentration
in
the
ambient
air.
This
factor
is
based
not
only
on
the
short
term
variability
of
the
data
for
the
turbine
with
the
lowest
reported
formaldehyde
emissions,
but
also
on
the
test
data
from
all
five
turbines.
Variations
in
temperature,
humidity,
atmospheric
pressure,
and
fuel
quality
are
known
to
have
resulted
in
fluctuations
in
criteria
pollutant
stack
concentrations
(
e.
g.,
NOX,
VOC,
and
CO),
and
we
anticipate
that
they
also
would
cause
variations
in
formaldehyde
concentrations
in
the
combustion
turbine
stack.
An
owner
or
operator
cannot
control
the
variability
of
environmental
parameters
such
as
ambient
temperature,
humidity,
or
atmospheric
pressure.
With
regard
to
fuel
quality,
an
owner
or
operator
cannot
control
the
quality
of
the
natural
gas
delivered
through
a
pipeline,
or
the
nature
and
concentration
of
natural
gas
additives
or
contaminants.
The
five
turbines
for
which
we
have
formaldehyde
emissions
data
operate
at
four
locations
in
the
Western
U.
S.
that
are
at
considerably
different
altitudes.
Moreover,
each
of
the
five
turbines
was
sampled
over
only
a
3­
hour
period,
and
the
five
sampling
events
occurred
in
four
different
months
of
the
year:
April,
May,
June
(
two
turbines),
and
December.
Therefore,
we
believe
that
the
variability
in
formaldehyde
concentration
of
the
turbine
emissions
will
be
greater
than
the
variability
reflected
in
the
3­
hour
sampling
period.
Furthermore,
we
believe
that
the
variability
observed
in
the
available
turbine
emissions
data
may
reflect
the
variability
of
formaldehyde
concentrations
in
ambient
air
 
much
of
which
is
due
to
natural
causes.
The
average
concentration
of
formaldehyde
in
ambient
air
varies
between
2
and
25
ppb
within
the
U.
S.,
with
a
U.
S.
annual
average
urban
concentration
of
5.17
ug/
m3
(
4.2
ppb).
1
The
difference
between
hourly
maximum
and
minimum
formaldehyde
concentrations
across
the
U.
S.
would
be
even
greater
than
the
average
annual
23
ppb
range
in
U.
S.
formaldehyde
concentrations.
We
do
not
have
information
that
specifically
shows
that
the
ambient
concentration
of
formaldehyde
affects
the
stack
outlet
concentration
of
formaldehyde.
We
expect
that
some
formaldehyde,
especially
the
portion
that
goes
through
the
combustors,
would
be
destroyed.
However,
about
two­
thirds
of
the
inlet
combustion
turbine
air
bypasses
the
combustors.
We
are
not
sure
that
all
of
the
ambient
formaldehyde
that
enters
with
the
combustion
air
is
destroyed
and,
therefore,
ambient
formaldehyde
may
affect
the
formaldehyde
concentration
in
the
outlet
stack
of
the
combustion
turbine.
For
example,
if
half
of
the
ambient
formaldehyde
passes
through
to
the
outlet
stack,
the
annual
average
contribution
of
ambient
formaldehyde
to
the
stack
formaldehyde
concentration
may
be
in
the
10
ppb
range
in
some
parts
of
the
U.
S.
This
means
that
hourly
formaldehyde
emissions
from
the
outlet
stack
of
a
given
turbine
could
differ
by
over
10
ppb
based
solely
on
the
region
of
the
country
where
the
turbine
is
located.
Sampling
variability
is
a
result
of
the
fact
that
it
is
impossible
to
collect
two
samples
in
exactly
the
same
way.
Sampling
variability
occurs
both
when
an
individual
intends
to
collect
replicate
samples
of
the
same
emissions
stream,
and
when
sampling
is
conducted
by
different
personnel
using
different
procedures
and
different
equipment
under
different
physical
conditions.
If
the
same
sampling
personnel
collect
a
suite
of
samples
using
the
same
equipment
and
procedures,
the
variability
of
the
sampling
results
will
be
reduced.
However,
a
given
individual
or
a
given
piece
of
equipment
may
impart
bias,
a
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1898
Federal
Register
/
Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
systematic
error,
into
the
sampling
procedure.
In
the
context
of
an
aggregate
of
data
collected
by
different
personnel
using
different
procedures
and
different
equipment
under
different
physical
conditions,
this
bias
could
have
the
effect
of
increasing
the
variability
of
the
data.
The
emissions
sample
results
for
the
five
turbines
evaluated
for
the
proposed
rule
were
provided
by
state
agencies,
and
samples
were
not
collected
by
the
same
sampling
personnel,
or
even
personnel
acting
in
coordination
with
one
another
and
following
the
same
sampling
plan
and
methodologies,
increasing
the
nonsystematic
sampling­
induced
variability
across
the
five
sets
of
turbine
samples
and
also
increasing
the
chance
that
any
bias
imposed
on
each
set
of
turbine
samples
might
also
increase
the
variability
of
the
results.
Moreover,
two
different
sampling
and
analysis
procedures
were
used
to
collect
the
samples,
EPA
Method
0011
and
CARB
Method
430,
likely
introducing
additional
variability
into
the
sampling
procedure.
For
example,
EPA
generally
recognizes
that
the
quality
assurance/
quality
control
(
QA/
QC)
protocols
for
CARB
Method
430
are
more
rigorous
than
those
for
EPA
Method
0011.
Similar
to
sampling
variability,
variability
occurs
when
samples
are
analyzed
at
the
same
time
in
the
same
laboratory
(
e.
g.,
variability
is
seen
in
the
results
of
a
laboratory's
repeated
analysis
of
the
same
sample)
and
occurs
when
samples
are
analyzed
by
different
laboratories.
For
example,
analytic
variability
may
result
from
the
use
of
different
analytical
procedures,
different
equipment,
different
laboratory
environments,
different
reagents,
different
sampling
handling
procedures,
and
different
analysts.
The
emissions
samples
evaluated
for
the
proposed
rule
were
analyzed
in
different
laboratories,
by
different
analysts,
and
using
two
different
analytical
procedures.
The
EPA
suspects
that
sampling
and
analytic
variability
may
be
a
significant
source
of
the
variability
of
formaldehyde
emissions
results
reported
for
the
five
tested
turbines,
and
that
if
stricter
QA/
QC
protocols
were
followed,
the
results
for
the
five
turbines
might
have
been
closer
in
magnitude.
One
measure
of
overall
variability
(
i.
e.,
variability
from
all
sources
 
environmental,
operational,
test
method,
etc.)
is
the
variability
of
formaldehyde
concentration
that
the
best
performing
turbine
demonstrated
during
the
three
test
runs.
The
formaldehyde
concentration
varied
between
5.1
and
7.7
ppb
formaldehyde,
a
factor
of
1.5
during
only
a
3­
hour
period.
Another
measure
of
formaldehyde
concentration
variability
is
the
variability
in
formaldehyde
concentration
from
the
five
lean
premix
combustion
turbines
tested.
As
stated
previously,
the
average
formaldehyde
concentration
varied
between
6.1
and
41
ppb
(
a
factor
of
seven).
We
reviewed
the
emission
test
reports
and
could
not
find
any
specific
reason
to
account
for
the
variability.
These
tests
were
properly
conducted,
and
the
lean
premix
combustion
turbines
were
operating
properly.
Therefore,
we
believe
that
at
least
some
portion,
and
possibly
all,
of
that
variability
is
due
to
factors
other
than
turbine
performance.
As
a
result,
we
believe
that
some
variability
in
formaldehyde
concentration
of
the
best
performing
turbine
will
occur
beyond
the
variability
reflected
by
the
three
test
runs.
It
is
our
judgement
that
if
the
best
performing
turbine
were
tested
at
various
times
during
the
year
and
at
various
locations
throughout
the
U.
S.,
the
overall
formaldehyde
concentration
of
the
best
performing
turbine
could
vary
by
a
factor
of
seven
or
more.
This
factor
is
based
on
the
short
term
variability
of
the
test
data
from
the
best
performing
turbine
and
also
on
the
test
data
from
the
five
turbine
tests
mentioned
previously.
Therefore,
we
believe
that
43
ppbvd
formaldehyde
is
a
reasonable
approximation
of
the
performance
of
the
best
performing
turbine,
taking
into
account
all
of
the
types
of
variability
discussed
above.
As
a
result,
we
are
proposing
an
emission
limit
of
43
ppbvd
formaldehyde
as
the
MACT
floor
for
existing
lean
premix
combustion
turbines.
The
lean
premix
combustor
turbine
technology
varies
to
some
extent
regarding
its
uncontrolled
emissions
of
NOX
and
CO
and
possibly
HAP.
The
data
that
we
have
obtained
for
the
five
source
tests
were
based
primarily
on
lean
premix
combustor
turbines
that
can
achieve
lower
than
15
ppm
NOX
and
less
than
5
ppm
CO
(
at
full
load)
at
15
percent
O2
without
add­
on
controls.
Lean
premix
combustor
turbines
which
have
these
characteristics
are
the
types
of
lean
premix
combustor
turbines
that
we
believe
will
most
likely
achieve
the
43
ppb
formaldehyde
emission
limit.
Other
types
of
lean
premix
combustor
turbines
which
achieve
45
ppm
NOX
and
as
high
as
200
ppm
CO
at
15
percent
O2
may
not
achieve
the
43
ppb
formaldehyde
emission
limit.
Typically,
the
lean
premix
combustor
turbines
in
the
latter
category
are
smaller
aeroderivative
turbines.
Therefore,
we
realize
that
not
all
lean
premix
combustor
turbines
will
be
able
to
achieve
the
43
ppb
formaldehyde
emission
limitation
and
some
will
have
to
install
add­
on
controls.
Most
new
turbines
projected
to
be
installed
at
power
plants
are
expected
to
be
able
to
achieve
the
43
ppb
emission
limitation.
We
request
public
comment
on
the
proposed
MACT
floor
level
for
existing
lean
premix
combustion
turbines.
We
are
particularly
interested
in
obtaining
information
on
the
annual/
seasonal
and
geographic
variability
in
formaldehyde
emissions
that
occur
for
lean
premix
combustion
turbines.
Formaldehyde
emission
test
reports
that
were
conducted
over
time
for
the
same
lean
premix
combustion
turbine
would
be
especially
helpful.
We
are
also
soliciting
information
regarding
the
contribution
of
ambient
formaldehyde
to
the
variability
of
outlet
stack
concentrations
of
formaldehyde.

4.
MACT
for
Existing
Lean
Premix
Combustion
Turbines
To
determine
MACT
for
existing
stationary
lean
premix
combustion
turbines,
we
evaluated
regulatory
alternatives
more
stringent
than
the
MACT
floor.
For
existing
lean
premix
turbines,
in
terms
of
an
emission
control
technology
which
could
serve
as
the
basis
for
MACT,
we
considered
the
use
of
an
oxidation
catalyst
emission
control
device.
According
to
catalyst
vendors,
oxidation
catalyst
emission
control
is
being
used
on
some
existing
lean
premix
combustion
turbines,
however,
we
lack
specific
data
regarding
the
performance
of
turbines
with
such
controls.
The
concentration
of
formaldehyde
in
the
exhaust
stream
from
lean
premix
combustion
turbines
is
already
significantly
lower
than
the
concentration
of
formaldehyde
in
the
exhaust
stream
from
diffusion
flame
combustion
turbines,
and
any
reduction
achieved
by
oxidation
catalyst
control
would
be
difficult
to
measure.
Thus,
we
concluded
that
the
incremental
cost
per
ton
of
HAP
removed
for
that
option
is
excessive.
We
also
considered
the
use
of
good
operating
practices
to
reduce
HAP
emissions,
but
determined
that
we
could
not
identify
specific
good
operating
practices
that
would
reduce
HAP
emissions.
Similarly,
we
also
considered
requiring
the
use
of
a
particular
fuel
to
reduce
HAP
emissions
but
concluded
that
fuel
switching
would
not
result
in
further
HAP
emissions
reductions.
As
a
result,
we
are
proposing
to
set
MACT
for
existing
lean
premix
combustion
turbines
at
the
MACT
floor
(
i.
e.,
43
ppbvd
formaldehyde).

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Federal
Register
/
Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
E.
How
Did
We
Determine
the
Basis
and
Level
of
the
Proposed
Emission
Limitations
and
Operating
Limitations
for
New
Sources?

For
new
sources,
the
MACT
floor
is
defined
as
the
emission
control
that
is
achieved
in
practice
by
the
best
controlled
similar
source.

1.
MACT
Floor
for
New
Diffusion
Flame
Combustion
Turbines
To
identify
the
MACT
floor
for
new
stationary
combustion
turbines
located
at
major
sources,
we
consulted
the
inventory
database
and
oxidation
catalyst
vendor
information.
As
mentioned
earlier,
oxidation
catalyst
emission
control
devices
are
currently
installed
on
about
3
percent
of
stationary
diffusion
flame
combustion
turbines.
This
3
percent
represents
about
200
stationary
combustion
turbines.
We
also
considered
whether
the
best
controlled
diffusion
flame
combustion
turbine
might
be
using
good
operating
practices
or
a
particular
fuel
that
would
reduce
HAP
emissions
further
and
concluded,
as
we
had
previously
in
this
preamble
for
existing
sources,
that
we
could
not
identify
specific
good
operating
practices
that
would
reduce
HAP
emissions,
and
that
fuel
switching
would
not
result
in
further
HAP
emissions
reductions.
We
concluded,
therefore,
that
the
level
of
HAP
emission
control
achieved
by
the
use
of
oxidation
catalyst
emission
control
devices
is
the
MACT
floor
for
new
stationary
combustion
turbines.
After
establishing
this
basis
for
the
MACT
floor,
we
determined
the
level
of
performance
based
on
the
data
available
in
the
emissions
database.
The
emissions
database,
which
is
a
compilation
of
available
HAP
emission
test
reports,
was
created
for
the
purpose
of
supporting
rulemaking
for
the
proposed
rule.
The
majority
of
HAP
emission
test
reports
collected
were
conducted
in
California
as
part
of
the
AB
2588
(
Air
Toxics
``
Hot
Spots''
Information
Assessment
Act
of
1987)
program.
Complete
copies
of
HAP
emission
test
reports
for
stationary
combustion
turbines
were
gathered
from
all
air
districts
in
California
and
from
other
sources,
such
as
the
EPA
Source
Test
Information
Retrieval
System
(
STIRS).
Other
States,
including
Washington,
Texas,
Pennsylvania,
and
New
Jersey,
and
trade
associations
such
as
the
Western
States
Petroleum
Association
(
WSPA)
and
the
Gas
Research
Institute
(
GRI)
were
also
contacted
for
available
HAP
emission
test
reports.
We
then
examined
the
emission
control
efficiency
achieved
by
an
oxidation
catalyst
emission
control
device
on
a
stationary
combustion
turbine.
We
concluded
that
CO
emission
reductions
are
a
good
surrogate
for
HAP
emissions
reductions
for
oxidation
catalyst
emission
control
devices.
This
conclusion
that
CO
emission
reductions
are
a
good
surrogate
for
HAP
emissions
reductions
achieved
through
the
use
of
oxidation
catalyst
emission
control
devices
is
also
supported
by
data
we
have
collected
from
the
use
of
oxidation
catalyst
emission
control
devices
on
stationary
reciprocating
internal
combustion
engines
(
RICE).
These
data
from
stationary
RICE
also
show
a
direct
relationship
between
CO
emission
reductions
and
HAP
emissions
reductions.
When
oxidation
catalyst
emission
control
devices
are
used
to
reduce
CO
emissions,
they
will
reduce
HAP
emissions.
The
emissions
database
contains
several
emission
test
reports
that
measured
HAP
and
CO
emissions
from
stationary
combustion
turbines,
but
no
emission
test
reports
that
measure
the
emission
reduction
efficiency
of
an
oxidation
catalyst
emission
control
device
(
measuring
CO
and
HAP
emissions
both
before
and
after
the
control
device).
However,
we
obtained
information
from
a
catalyst
vendor
for
two
tests
for
one
turbine.
The
results
of
those
tests
show
that
a
CO
reduction
of
95
to
98
percent
was
achieved
using
an
oxidation
catalyst
control
system.
We
reviewed
the
test
report
for
the
data
to
assure
that
the
turbine
was
operated
correctly
and
that
there
was
no
turbine
or
control
device
malfunction;
we
found
no
discrepancy.
In
addition
to
emissions
testing
data,
we
reviewed
design
data
from
oxidation
catalyst
vendors
for
the
systems
installed
in
the
U.
S.
The
typical
emission
reduction
for
turbines
that
have
been
installed
is
90
percent
CO
emission
reduction,
with
a
few
systems
that
are
designed
to
be
95
percent
or
greater.
We
reviewed
other
factors
such
as
operator
training
in
addition
to
the
control
technology
itself
that
could
potentially
result
in
better
emission
reduction,
but
we
found
no
effect
of
those
factors
on
the
control
efficiency.
Based
on
the
conclusions
and
data,
we
believe
that
95
percent
represents
the
level
of
control
that
can
be
achieved
by
the
best
controlled
similar
source.
As
a
result,
we
concluded
that
the
level
of
performance
associated
with
the
MACT
floor
(
i.
e.,
use
of
an
oxidation
catalyst
emission
control
device)
is
an
emission
reduction
efficiency
of
95
percent
or
more
for
CO.
The
MACT
floor
for
new
stationary
diffusion
flame
combustion
turbines
is,
therefore,
a
CO
emission
reduction
efficiency
of
95
percent
or
more,
using
an
oxidation
catalyst
control
system.

2.
MACT
for
New
Diffusion
Flame
Combustion
Turbines
We
were
unable
to
identify
any
beyond­
the­
floor
regulatory
alternatives
for
new
stationary
combustion
turbines.
We
know
of
no
emission
control
technology
currently
available
which
can
reduce
HAP
emissions
to
levels
lower
than
that
achieved
through
the
use
of
oxidation
catalyst
emission
control
devices.
Similarly,
we
know
of
no
work
practice
that
could
further
reduce
HAP
emissions.
In
addition,
fuel
switching
will
not
result
in
further
reductions
of
HAP
emissions.
We
concluded,
therefore,
that
MACT
for
new
diffusion
flame
stationary
combustion
turbines
is
equivalent
to
the
MACT
floor.
It
should
be
noted
that
the
majority
of
new
combustion
turbines
are
expected
to
be
lean
premix
combustion
turbines
based
on
the
significantly
reduced
emissions
of
NOX,
CO,
and
formaldehyde.
We
estimate
that
less
than
5
percent
of
new
combustion
turbines
will
be
diffusion
flame.
Dieselfired
combustion
turbines
cannot
be
operated
in
the
lean
premix
mode,
and
these
turbines
would
have
to
install
an
oxidation
catalyst
system.

3.
MACT
Floor
for
New
Lean
Premix
Combustion
Turbines
To
determine
the
MACT
floor
for
new
stationary
lean
premix
combustion
turbines,
we
based
our
analysis
on
the
same
emissions
data
for
formaldehyde
that
we
used
for
the
existing
MACT
floor.
The
MACT
floor
for
existing
lean
premix
combustion
turbines
is
based
on
the
performance
of
the
best
performing
lean
premix
combustion
turbine;
this
same
level
of
performance
can,
therefore,
be
used
to
determine
the
MACT
floor
for
new
lean
premix
combustion
turbines.
As
discussed
previously
in
the
existing
source
MACT,
we
believe
that
43
ppbvd
formaldehyde
represents
the
best
performing
turbine.
The
MACT
floor
for
new
lean
premix
combustion
turbines
is,
therefore,
an
emission
limit
of
43
ppbvd
formaldehyde.

4.
MACT
for
New
Lean
Premix
Combustion
Turbines
To
determine
MACT
for
new
stationary
lean
premix
combustion
turbines,
we
evaluated
regulatory
alternatives
more
stringent
than
the
MACT
floor.
As
with
existing
lean
premix
combustion
turbines,
we
considered
the
use
of
an
oxidation
catalyst
control
system.
However,
although
catalyst
vendors
have
indicated
that
some
existing
lean
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14JAP2.
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14JAP2
1900
Federal
Register
/
Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
premix
combustion
turbines
are
using
oxidation
catalyst
emission
control,
we
lack
specific
data
regarding
the
performance
of
turbines
with
such
controls.
The
HAP
concentration
in
the
lean
premix
combustion
turbine
exhaust
is
very
low
and,
therefore,
would
be
difficult
to
measure
if
it
were
further
reduced
through
the
installation
of
an
oxidation
catalyst.
Due
to
the
low
HAP
levels,
the
cost
per
ton
of
HAP
removed
would
be
very
high.
We
concluded,
therefore,
that
MACT
for
new
stationary
lean
premix
combustion
turbines
is
equivalent
to
the
MACT
floor.

5.
MACT
for
Other
Subcategories
Although
the
proposed
rule
would
apply
to
all
stationary
combustion
turbines
located
at
major
sources
of
HAP
emissions,
emergency
stationary
combustion
turbines,
limited
use
stationary
combustion
turbines,
stationary
combustion
turbines
which
fire
landfill
gas
or
digester
gas
as
their
primary
fuel,
and
stationary
combustion
turbines
of
less
than
1
MW
rated
peak
power
output
are
not
required
to
meet
the
emission
limitations
or
operating
limitations.
For
each
of
the
subcategories
of
stationary
combustion
turbines,
as
mentioned
earlier,
we
have
concerns
about
the
applicability
of
emission
control
technology.
For
example,
emergency
stationary
combustion
turbines
operate
infrequently.
In
addition,
when
called
upon
to
operate
they
must
respond
immediately
without
failure
and
without
lengthy
startup
periods.
This
infrequent
operation
limits
the
applicability
of
HAP
emission
control
technology.
Limited
use
stationary
combustion
turbines
also
operate
infrequently.
As
with
emergency
stationary
combustion
turbines,
it
is
this
infrequent
operation
that
limits
the
applicability
of
HAP
emission
control
technology.
Landfill
and
digester
gases
contain
a
family
of
silicon
based
gases
called
siloxanes.
Combustion
of
siloxanes
forms
compounds
that
can
foul
postcombustion
catalysts,
rendering
catalysts
inoperable
within
a
very
short
time
period.
Pretreatment
of
exhaust
gases
to
remove
siloxanes
was
investigated.
However,
no
pretreatment
systems
are
in
use
and
their
long
term
effectiveness
is
unknown.
We
also
considered
fuel
switching
for
this
subcategory
of
turbines.
Switching
to
a
different
fuel
such
as
natural
gas
or
diesel
would
potentially
allow
the
turbine
to
apply
an
oxidation
catalyst
emission
control
device.
However,
fuel
switching
would
defeat
the
purpose
of
using
this
type
of
fuel
which
would
then
either
be
allowed
to
escape
uncontrolled
or
would
be
burned
in
a
flare
with
no
energy
recovery.
We
believe
that
switching
landfill
or
digester
gas
to
another
fuel
is
inappropriate
and
is
an
environmentally
inferior
option.
For
stationary
combustion
turbines
of
less
than
1
MW
rated
peak
power
output,
we
have
concerns
about
the
effectiveness
of
scaling
down
the
oxidation
catalyst
emission
control
technology.
Just
as
there
are
often
unforeseen
problems
associated
with
scaling
up
a
technology,
there
can
be
problems
associated
with
scaling
down
a
technology.
As
a
result,
we
identified
subcategories
for
each
of
these
types
of
stationary
combustion
turbines
and
investigated
MACT
floors
and
MACT
for
each
subcategory.
As
expected,
since
we
identified
these
types
of
stationary
combustion
turbines
as
separate
subcategories
based
on
concerns
about
the
applicability
of
emission
control
technology,
we
found
no
stationary
combustion
turbines
in
these
subcategories
using
any
emission
control
technology
to
reduce
HAP
emissions.
As
discussed
above,
we
are
not
aware
of
any
work
practices
that
might
constitute
a
MACT
floor,
nor
did
we
find
that
the
use
of
a
particular
fuel
results
in
HAP
emissions
reductions.
The
MACT
floor,
therefore,
for
each
of
these
subcategories
is
no
emissions
reduction.
Despite
our
concerns
with
the
applicability
of
emission
control
technology,
we
examined
the
cost
per
ton
of
HAP
removed
for
these
subcategories.
Whether
our
concerns
are
warranted
or
not,
we
consider
the
incremental
cost
per
ton
of
HAP
removed
excessive
 
primarily
because
of
the
very
small
reduction
in
HAP
emissions
that
would
result.
We
also
considered
the
nonair
health,
environmental,
and
energy
impacts
of
an
oxidation
catalyst
system,
as
discussed
previously
in
this
preamble,
and
concluded
that
there
would
be
only
a
small
energy
impact
and
no
nonair
health
or
environmental
impacts.
However,
as
stated
above,
we
did
not
adopt
this
regulatory
option
due
to
cost
considerations
and
concerns
about
the
applicability
of
this
technology
to
these
subcategories.
We
were
not
able
to
identify
any
other
means
of
achieving
HAP
emissions
reductions
for
these
subcategories.
As
a
result,
for
all
of
these
reasons,
we
conclude
that
MACT
for
these
subcategories
is
the
MACT
floor
(
i.
e.,
no
emissions
reductions).
F.
How
Did
We
Select
the
Format
of
the
Standard
for
New
Diffusion
Flame
Combustion
Turbines?

We
are
proposing
two
options
for
complying
with
the
standard
for
new
diffusion
flame
combustion
turbines.
You
may
reduce
CO
by
95
percent
if
you
use
an
oxidation
catalyst
emission
control
device,
or
reduce
the
concentration
of
formaldehyde
in
the
exhaust
from
the
turbine
to
43
ppb
by
volume
or
less,
dry
basis,
at
15
percent
oxygen.
We
considered
proposing
an
emission
limitation
for
HAP,
but
are
proposing
a
CO
emission
reduction
limitation
as
a
surrogate
for
a
HAP
emission
limitation.
We
have
decided
to
propose
the
use
of
the
CO
emission
reduction
limitation
as
a
surrogate
for
the
HAP
emission
limitation,
because
CO
monitoring
is
currently
being
used
by
combustion
turbine
owners
and
operators,
it
is
significantly
easier
and
less
expensive
to
measure
and
monitor
CO
than
to
measure
and
monitor
each
HAP,
and
because
we
believe
that
CO
reduction
is
a
good
measure
of
performance
of
the
oxidation
catalyst
emission
control
device.
Monitoring
equipment
for
CO
is
readily
available,
which
is
not
the
case
for
HAP
monitoring
equipment.
We
are
also
proposing
a
percent
reduction
in
CO
emissions
as
the
emission
limitation,
rather
than
a
single
value
for
CO
emissions.
The
data
upon
which
MACT
are
based
show
that
while
the
level
of
CO
emissions
entering
an
oxidation
catalyst
emission
control
device
may
vary,
the
oxidation
catalyst
emission
control
device
is
able
to
maintain
a
CO
emission
reduction
efficiency
of
95
percent
or
more.
We
are
also
proposing
an
alternative
emission
limitation
for
formaldehyde
emissions.
You
may
choose
to
comply
with
the
emission
limitation
for
CO
emission
reduction
(
if
you
use
an
oxidation
catalyst
emission
control
device)
or
you
may
choose
to
comply
with
the
emission
limitation
for
formaldehyde
emission
concentration
(
if
you
use
some
means
other
than
an
oxidation
catalyst
control
device
to
reduce
HAP
emissions).
We
would
like
to
promote
the
development
and
eventual
use
of
alternative
emission
control
technologies
(
including
pollution
prevention
technologies)
to
reduce
HAP
emissions,
and
we
believe
an
alternative
emission
limitation
written
in
terms
of
formaldehyde
emissions
will
serve
to
do
so.
We
are
soliciting
information
on
HAP
and
CO
emissions
data
from
alternative
emission
control
technologies
during
the
comment
period.
We
are
particularly
interested
in
obtaining
test
reports
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/
Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
where
HAP
and
CO
emissions
reductions
were
measured
with
methods
that
we
are
recommending
to
be
used
to
measure
HAP
in
the
proposed
rule.
For
the
emission
limitation,
we
propose
to
use
formaldehyde
as
a
surrogate
for
all
HAP.
Formaldehyde
is
the
HAP
emitted
in
the
highest
concentrations
from
stationary
combustion
turbines.
In
addition,
the
emission
data
show
that
HAP
emission
levels
and
formaldehyde
emission
levels
are
related,
in
the
sense
that
when
emissions
of
one
are
low,
emissions
of
the
other
are
low
and
vice
versa.
This
leads
us
to
conclude
that
emission
control
technologies
which
lead
to
reductions
in
formaldehyde
emissions
will
lead
to
reductions
in
HAP
emissions.
The
emission
limitation
for
formaldehyde
is
in
units
of
parts
per
billion,
and
all
measurements
must
be
corrected
to
15
percent
oxygen,
dry
basis,
to
provide
a
common
basis.
A
volume
concentration
was
chosen
for
the
emission
limitation
because
it
can
be
measured
directly.
We
based
the
alternative
emission
limitation
on
the
ability
of
lean
premix
technology
to
reduce
emissions
to
43
ppbvd
(
at
15
percent
oxygen).
The
reduction
in
formaldehyde
emissions
is
approximately
equivalent
to
that
achieved
when
CO
emissions
are
reduced
by
95
percent
through
the
use
of
an
oxidation
catalyst
emission
control
device.
As
discussed
later,
we
consider
the
cost
of
formaldehyde
CEMS
excessive
for
the
purpose
of
ensuring
continuous
compliance
with
this
emission
limitation
for
formaldehyde
emissions.
As
a
result,
we
selected
stack
emission
testing
to
demonstrate
compliance
with
the
emission
limitation.

G.
How
Did
We
Select
the
Initial
Compliance
Requirements?
The
emissions
tests
which
form
the
basis
of
the
proposed
rule
were
conducted
using
EPA
or
CARB
test
methods.
The
proposed
rule
requires
the
use
of
these
EPA
or
CARB
test
methods
to
determine
compliance.
This
ensures
that
the
same
procedures
that
were
used
to
obtain
the
emission
data
upon
which
the
emission
limitations
are
based
are
used
for
compliance
testing.
By
using
the
same
test
methods,
we
eliminate
the
possibility
of
measurement
bias
and
interference
influencing
determinations
of
compliance.
For
sources
complying
with
the
emission
limitation
to
reduce
CO
emissions,
an
initial
performance
evaluation
is
required.
The
performance
evaluation
will
validate
performance
of
the
CEMS.
The
proposed
rule
also
requires
an
annual
relative
accuracy
test
audit
(
RATA)
to
ensure
that
performance
of
the
CEMS
does
not
deteriorate
over
time.
The
first
4­
hour
period
following
this
performance
evaluation
of
the
CO
CEMS
will
be
used
to
determine
initial
compliance
with
the
CO
emission
reduction
limitation.
New
and
reconstructed
sources
and
existing
lean
premix
combustor
turbines
complying
with
the
emission
limitation
to
reduce
formaldehyde
emissions
are
required
to
conduct
an
initial
performance
test.
The
purpose
of
the
initial
test
is
to
demonstrate
initial
compliance
with
the
formaldehyde
emission
limitation.

H.
How
Did
We
Select
the
Continuous
Compliance
Requirements?
If
you
must
comply
with
the
emission
limitations,
continuous
compliance
with
these
requirements
is
required
at
all
times
except
during
startup,
shutdown,
and
malfunction
of
your
stationary
combustion
turbine.
You
are
not
required
to
develop
a
startup,
shutdown
or
malfunction
plan
since
we
do
not
believe
meaningful
procedures
could
be
developed.
We
consider
the
use
of
CEMS
the
best
means
of
ensuring
continuous
compliance
with
emission
limitations,
and
alternatives
to
CEMS
are
considered
only
if
we
consider
the
use
of
a
CEMS
technically
or
economically
infeasible.
For
sources
complying
with
the
emission
limitation
for
CO
emission
reduction,
we
believe
it
is
feasible
to
require
a
CEMS
because
the
costs
for
a
CO
CEMS
are
reasonable.
Thus,
the
proposed
rule
requires
the
use
of
a
CO
CEMS
to
continuously
monitor
the
reduction
in
CO
emissions.
For
sources
complying
with
the
emission
limitation
for
formaldehyde
emissions,
we
also
considered
requiring
a
CEMS;
however,
we
concluded
that
the
costs
of
a
formaldehyde
CEMS
were
excessive.
We
considered
requiring
those
sources
to
continuously
monitor
operating
load
to
demonstrate
continuous
compliance
because
the
data
establishing
the
formaldehyde
outlet
concentration
level
are
based
on
tests
that
were
done
at
high
loads.
However,
we
believe
that
the
performance
of
a
stationary
lean
premix
combustion
turbine
at
high
load
is
also
indicative
of
its
operation
at
lower
loads.
In
fact,
the
operator
can
make
no
parameter
adjustments
that
would
lead
to
lower
emissions.
We
request
comments
on
the
continued
monitoring
of
stationary
lean
premix
combustion
turbines
that
have
demonstrated
initial
compliance.
The
stationary
lean
premix
combustion
turbines
are
low
NOX
emitting
and
are
permitted
to
continuously
attain
the
permitted
NOX
levels.
The
same
technology
that
results
in
the
maintenance
of
low
NOX
levels
is
also
related
to
the
achievement
of
low
HAP
emissions.
Therefore,
we
would
like
to
solicit
comments
on
the
feasibility
of
requiring
no
additional
testing
or
monitoring
after
the
lean
premix
stationary
combustion
turbine
has
demonstrated
initial
compliance
and
is
relying
on
the
NOX
permit
levels,
or
low
NOX
levels
characteristic
of
lean
premix
combustor
turbines
(
e.
g.
NOX
levels
guaranteed
by
the
manufacturer)
if
there
are
no
permit
levels,
to
assure
continuing
good
performance.
We
are
proposing
this
in
an
attempt
to
streamline
the
continuous
testing,
monitoring,
and
reporting
requirements.
Finally,
since
we
are
unsure
what
new
HAP
emission
control
technologies
might
emerge,
we
do
not
know
whether
it
will
be
necessary
to
establish
additional
operating
limitations
to
ensure
continuous
compliance
with
the
formaldehyde
emission
limitation
for
sources
that
are
not
lean
premix
or
diffusion
flame.
Thus,
as
outlined
earlier,
the
proposed
rule
requires
you
to
petition
the
Administrator
for
approval
of
additional
operating
limitations
or
for
approval
of
no
additional
operating
limitations.

I.
How
Did
We
Select
the
Monitoring
and
Testing
Methods
to
Measure
These
Low
Concentrations
of
CO
and
Formaldehyde?
We
believe
CEMS
are
available
which
can
measure
CO
emissions
at
the
low
concentrations
found
in
the
exhaust
from
a
stationary
combustion
turbine
following
an
oxidation
catalyst
emission
control
device.
Our
performance
specifications
for
CO
CEMS
(
PS4
and
PS4A),
however,
have
not
been
updated
recently
and
do
not
reflect
the
performance
capabilities
of
such
systems
at
these
low
CO
concentration
levels.
As
a
result,
we
solicit
comments
on
the
performance
capabilities
of
state­
ofthe
art
CO
CEMS
and
their
ability
to
accurately
measure
the
low
concentrations
of
CO
experienced
in
the
exhaust
of
a
stationary
combustion
turbine
following
an
oxidation
catalyst
emission
control
device.
We
also
solicit
comments
with
specific
recommendations
on
the
changes
we
should
make
to
our
performance
specifications
for
CO
CEMS
(
PS4
and
PS4A)
to
ensure
the
installation
and
use
of
CEMS
which
can
be
used
to
determine
compliance
with
the
proposed
emission
limitation
for
CO
emission
reduction.
In
addition,
we
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Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
solicit
comments
on
the
availability
of
instruments
capable
of
meeting
the
changes
they
recommend
to
our
performance
specifications
for
CO
CEMS.
Today's
proposal
specifies
the
use
of
Method
10
as
the
reference
method
to
certify
the
performance
of
the
CO
CEMS.
We
also
believe
Method
10
is
capable
of
measuring
CO
concentrations
as
low
as
those
experienced
in
the
exhaust
of
a
stationary
combustion
turbine
following
an
oxidation
catalyst
emission
control
device.
However,
the
performance
criteria
in
addenda
A
of
Method
10
have
not
been
revised
recently
and
are
not
suitable
for
certifying
the
performance
of
a
CO
CEMS
at
these
low
CO
concentrations.
Specifically,
we
believe
the
range
and
minimum
detectable
sensitivity
should
be
changed
to
reflect
target
concentrations
as
low
as
0.1
parts
per
million
(
ppm)
CO
in
some
cases.
We
also
expect
that
dual
range
instruments
will
be
necessary
to
measure
CO
concentrations
at
the
inlet
and
at
the
outlet
of
an
oxidation
catalyst
emission
control
device.
As
a
result,
we
solicit
comments
with
specific
recommendations
on
the
changes
we
should
make
to
Method
10
and
the
performance
criteria
in
addenda
A.
We
also
solicit
comments
on
the
availability
of
instruments
capable
of
meeting
the
changes
they
recommend
to
Method
10
and
the
performance
criteria
in
addenda
A,
while
also
meeting
the
remaining
addenda
A
performance
criteria.
With
regard
to
formaldehyde,
we
believe
systems
meeting
the
requirements
of
Method
320,
a
selfvalidating
FTIR
method,
can
be
used
to
attain
detection
limits
for
formaldehyde
concentrations
below
43
ppbvd.
We
expect
path
lengths
in
the
range
of
100
to
125
meters
and
state­
of­
the­
art
digital
signal
processing
(
to
reduce
signal
to
noise
ratio)
would
be
needed.
Method
320
also
includes
formaldehyde
spike
recovery
criteria,
which
require
spike
recoveries
of
70
to
130
percent.
While
we
believe
FTIR
systems
can
meet
Method
320
and
measure
formaldehyde
concentrations
at
these
low
levels,
we
have
limited
experience
with
their
use.
As
a
result,
we
solicit
comments
on
the
ability
and
use
of
FTIR
systems
to
meet
the
validation
and
quality
assurance
requirements
of
Method
320
for
the
purpose
of
determining
compliance
with
the
emission
limitation
for
formaldehyde
emissions.
As
an
alternative
to
Method
320,
we
are
proposing
Method
323
for
natural
gas­
fired
sources.
Method
323
uses
the
acetyl
acetone
colorimetric
method
to
measure
formaldehyde
emissions
in
the
exhaust
of
natural
gas­
fired,
stationary
combustion
sources.
We
believe
the
proposed
method
can
measure
low
concentrations
of
formaldehyde
at
a
cost
which
is
less
than
or
equal
to
the
cost
of
testing
using
Method
320;
therefore,
we
solicit
comments
on
the
use
of
Method
323
by
natural
gas­
fired
sources
to
demonstrate
compliance
with
the
formaldehyde
emission
limitation.
We
also
believe
CARB
Method
430
and
EPA
SW
 
846
Method
0011
are
capable
of
measuring
formaldehyde
concentrations
at
these
low
levels.
Accordingly,
we
solicit
comments
on
the
use
of
CARB
430
and
EPA
SW
 
846
Method
0011
to
determine
compliance
with
the
emission
limitations
for
formaldehyde.
Based
on
the
comments
we
receive
on
CO
CEMS,
we
anticipate
revising
Method
10
and
our
performance
specifications
(
PS4
and
PS4A)
for
CO
CEMS
to
ensure
the
installation
and
use
of
CEMS
suitable
for
determining
compliance
with
the
emission
limitation
for
CO
emission
reduction.
If
we
should
promulgate
today's
proposed
rule
for
stationary
combustion
turbines
before
completing
these
revisions,
however,
we
may
require
all
new
and
reconstructed
stationary
combustion
turbines
subject
to
the
final
rule
to
demonstrate
compliance
with
the
formaldehyde
emission
limitation,
or
a
formaldehyde
percent
reduction
limitation
similar
to
the
CO
percent
reduction
emission
limitation,
until
we
have
adopted
final
revisions
to
Method
10
and
our
performance
specifications
for
CO
CEMS.
On
the
other
hand,
if
the
comments
we
receive
lead
us
to
conclude
that
CO
CEMS
are
not
capable
of
being
used
to
determine
compliance
with
the
emission
limitation
for
CO
emission
reduction,
there
are
several
alternatives
we
may
consider.
One
alternative
would
be
to
delete
the
proposed
percent
reduction
emission
limitation
for
CO
and
require
compliance
with
a
comparable
formaldehyde
percent
reduction
limitation.
This
alternative
would
require
periodic
stack
emission
testing
before
and
after
the
control
device
and
would
also
require
owners
and
operators
to
petition
the
Administrator
for
additional
operating
limitations,
as
proposed
today
for
those
choosing
to
comply
with
the
emission
limitation
for
formaldehyde.
Another
alternative
would
be
to
delete
the
proposed
emission
limitation
for
CO
emission
reduction
and
require
compliance
with
the
proposed
emission
limitation
for
formaldehyde.
This
alternative
could
require
more
frequent
emission
testing
and
could
also
require
owners
and
operators
to
petition
the
Administrator
for
additional
operating
limitations.
Another
alternative
would
be
to
require
the
use
of
Method
320
(
i.
e.,
FTIR
systems)
to
determine
compliance
with
the
emission
limitation
for
CO
emission
reduction.
This
alternative
could
also
require
more
frequent
emission
testing
and
require
owners
and
operators
to
petition
the
Administrator
for
additional
operating
limitations,
as
proposed
today
for
those
choosing
to
comply
with
the
emission
limitation
for
formaldehyde.
Based
on
the
comments
we
receive
on
FTIR
systems
and
Method
320,
we
may
develop
additional
or
revised
criteria
for
the
use
of
FTIR
systems
and/
or
Method
320
to
determine
compliance
with
the
emission
limitation
for
formaldehyde.
If
we
should
conclude
that
neither
CO
CEMS
or
FTIR
systems
are
capable
of
being
used
to
determine
compliance
with
the
emission
limitations
for
CO
or
formaldehyde
emissions,
then
we
may
delete
the
emission
limitations
for
CO
and
formaldehyde
emissions
and
adopt
an
emission
limitation
consisting
of
an
equipment
and
work
practice
requirement.
This
alternative
would
require
the
use
of
oxidation
catalyst
emission
control
devices
which
meet
specific
and
narrow
design
and
operating
criteria.
We
believe
the
emission
limitations
we
are
proposing
for
CO
emission
reduction
and
formaldehyde
emission
concentration
are
superior
to
these
alternatives
for
a
number
of
reasons.
We
believe
that
the
CO
emission
limitation
is
better
because
it
is
easier
and
cheaper
to
continuously
monitor
CO,
and
it
has
been
shown
to
be
a
good
surrogate
for
HAP.
Also,
we
prefer
to
have
an
emission
limitation
rather
than
an
equipment
or
work
practice
standard.
An
emission
limitation
is
superior
because
it
ensures
that
emissions
are
below
a
certain
level,
as
demonstrated
by
a
CEMS
or
performance
testing.
However,
we
solicit
comments
on
these
alternatives,
should
we
conclude
that
the
proposed
emission
limitations
for
CO
emission
reduction
and
formaldehyde
emission
concentration
are
inappropriate
because
of
difficulties
in
monitoring
or
measuring
CO
emission
reduction
or
formaldehyde
emission
concentration
to
determine
compliance.
We
also
solicit
suggestions
and
recommendations
for
other
alternatives,
should
we
conclude
the
proposed
emission
limitations
are
inappropriate
because
of
monitoring
or
measurement
difficulties.

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Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
J.
How
Did
We
Select
the
Notification,
Recordkeeping
and
Reporting
Requirements?

The
proposed
notification,
recordkeeping,
and
reporting
requirements
are
based
on
the
NESHAP
General
Provisions
of
40
CFR
part
63.

IV.
Summary
of
Environmental,
Energy
and
Economic
Impacts
We
estimate
that
20
percent
of
the
stationary
combustion
turbines
affected
by
the
proposed
rule
will
be
located
at
major
sources.
As
a
result,
the
environmental,
energy,
and
economic
impacts
presented
in
this
preamble
reflect
these
estimates.

A.
What
Are
the
Air
Quality
Impacts?

The
proposed
rule
will
reduce
total
national
HAP
emissions
by
an
estimated
81
tons/
year
in
the
5th
year
after
the
standards
are
promulgated.
The
emissions
reductions
achieved
by
the
proposed
rule
would
be
due
to
the
sources
that
install
an
oxidation
catalyst
control
system.
We
estimate
that
about
10
existing
lean
premix
combustion
turbines
will
install
oxidation
catalyst
control
to
comply
with
the
standard.
In
addition,
we
estimate
that
about
5
percent
of
new
stationary
combustion
turbines
will
install
oxidation
catalyst
control
to
comply
with
the
standards.
The
other
95
percent
of
new
stationary
combustion
turbines
will
be
lean
premix,
a
pollution
prevention
technology
which
in
most
cases
does
not
require
the
use
of
oxidation
catalyst
control.
The
lean
premix
turbines
are
currently
being
installed
to
meet
NOX
emission
standards.
The
reduction
of
HAP
emissions
for
these
stationary
combustion
turbines
is
difficult
to
assess
because
it
is
a
pollution
prevention
technology
and
is
being
installed
to
meet
NOX
limits,
not
as
a
result
of
MACT
for
stationary
combustion
turbines.
Therefore,
as
stated
previously,
the
HAP
emissions
reductions
obtained
by
the
proposed
rule
result
only
from
the
sources
that
install
an
oxidation
catalyst
control
system.
To
estimate
air
impacts,
national
HAP
emissions
in
the
absence
of
the
proposed
rule
(
i.
e.,
HAP
emission
baseline)
were
calculated
using
an
emission
factor
from
the
emissions
database.
We
assumed
new
stationary
combustion
turbines
are
operated
8,760
hours
annually.
We
then
assumed
a
HAP
reduction
of
95
percent,
achieved
by
using
oxidation
catalyst
emission
control
devices
to
comply
with
the
emission
limitation
to
reduce
CO
emissions,
and
applied
this
reduction
to
the
baseline
HAP
emissions
to
estimate
total
national
HAP
emission
reduction.
The
total
national
HAP
emission
reduction
is
the
sum
of
formaldehyde,
acetaldehyde,
benzene,
and
toluene
emission
reductions.
In
addition
to
HAP
emission
reductions,
the
proposed
rule
will
reduce
criteria
air
pollutant
emissions,
primarily
CO
emissions.

B.
What
Are
the
Cost
Impacts?
The
national
total
annualized
cost
of
the
proposed
rule
in
the
5th
year
following
promulgation
is
estimated
to
be
about
$
21.5
million.
Approximately
$
267,500
of
that
amount
is
the
estimated
annualized
cost
for
monitoring,
recordkeeping,
and
reporting.
To
calculate
the
annualized
control
costs,
we
obtained
estimates
of
the
capital
costs
of
oxidation
catalyst
emission
control
devices
from
vendors.
We
then
calculated
the
national
total
annualized
costs
of
control
for
the
new
stationary
combustion
turbines
installing
oxidation
catalyst
emission
control
in
the
next
5
years.
Our
projection
of
new
stationary
combustion
turbine
capacity
that
will
come
online
over
the
next
5
years
is
based
on
review
of
permit
data
gathered
by
EPA
from
1998
to
the
present
time,
confidential
projection
data
from
turbine
manufacturers,
and
published
sales
data.
We
believe
this
projection
is
a
reasonable
estimate
based
on
the
available
information.

C.
What
Are
the
Economic
Impacts?
The
EPA
prepared
an
economic
impact
analysis
to
evaluate
the
impacts
the
proposed
rule
would
have
on
the
combustion
turbines
producers,
consumers
of
goods
and
services
produces
by
combustion
turbines,
and
society.
The
analysis
shows
minimal
changes
in
prices
and
output
for
products
made
by
the
24
industries
affected
by
the
proposed
rule.
The
price
increase
for
affected
output
is
less
than
0.01
percent
and
the
reduction
in
output
is
less
than
0.01
percent
for
each
affected
industry.
Estimates
of
impacts
on
fuel
markets
show
price
increases
of
less
than
0.012
percent
for
petroleum
products
and
natural
gas,
and
price
increases
of
0.13
and
0.17
percent
for
base­
load
and
peak­
load
electricity,
respectively.
The
price
of
coal
is
expected
to
decline
by
about
0.06
percent,
and
this
is
due
to
a
small
reduction
in
demand
for
this
fuel
type.
Reductions
in
output
are
expected
to
be
less
than
0.16
percent
for
each
energy
type,
including
base­
load
and
peak­
load
electricity.
The
social
costs
of
the
proposed
rule
are
estimated
at
$
13.3
million
(
1998
dollars).
Social
costs
include
the
compliance
costs,
but
also
include
those
costs
that
reflect
changes
in
the
national
economy
due
to
changes
in
consumer
and
producer
behavior
resulting
from
the
compliance
costs
associated
with
a
regulation.
In
this
case,
changes
in
energy
use
among
both
consumers
and
producers
to
reduce
the
impact
of
the
regulatory
requirements
of
the
proposed
rule
on
them
lead
to
the
estimated
social
costs
being
somewhat
less
than
the
total
annualized
compliance
cost
estimate
of
$
21.5
million
(
1998$).
The
primary
reason
for
the
much
lower
social
cost
estimate
is
the
increase
in
electricity
supply
generated
by
existing
unaffected
sources,
which
mostly
offsets
the
impact
of
increased
electricity
prices
to
consumers.
For
more
information
on
these
impacts,
please
refer
to
the
economic
impact
analysis
in
the
public
docket.

D.
What
Are
the
Nonair
Health,
Environmental
and
Energy
Impacts?

The
only
energy
requirement
is
a
small
increase
in
fuel
consumption
resulting
from
back
pressure
caused
by
operating
an
oxidation
catalyst
emission
control
device.
This
energy
impact
is
small
in
comparison
to
the
costs
of
other
impacts.
There
are
no
known
nonair
environmental
or
health
impacts
as
a
result
of
the
implementation
of
the
rule
as
proposed.

V.
Solicitation
of
Comments
and
Public
Participation
A.
General
We
are
requesting
comments
on
the
proposed
rule.
We
request
comments
on
all
aspects
of
the
proposed
rule,
such
as
the
proposed
emission
limitations
and
operating
limitations,
recordkeeping
and
monitoring
requirements,
as
well
as
aspects
you
may
feel
have
not
been
addressed.
Specifically,
we
request
comments
on
the
performance
capabilities
of
state­
ofthe
art
CO
CEMS
and
their
ability
to
measure
the
low
concentrations
of
CO
in
the
exhaust
of
a
stationary
combustion
turbine
following
an
oxidation
catalyst
emission
control
device.
We
also
request
comments
with
recommendations
on
changes
commenters
believe
we
should
make
to
our
performance
specifications
for
CO
CEMS
(
PS4
and
PS4A)
of
40
CFR
part
60,
appendix
B,
and
to
Method
10
of
40
CFR
part
60,
appendix
A,
and
the
performance
criteria
in
addenda
A
to
Method
10.
In
addition,
we
request
comments
from
these
commenters
on
the
availability
of
instruments
capable
of
meeting
the
changes
they
recommend
to
our
performance
specifications
for
CO
CEMS
(
PS4
and
PS4A)
of
40
CFR
part
60,
Method
10
of
40
CFR
part
60,

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/
Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
appendix
A,
and
addenda
A
to
method
10.
As
also
mentioned
earlier,
we
request
comments
on
the
ability
and
use
of
FTIR
systems
to
meet
the
validation
and
quality
assurance
requirements
of
Method
320
of
40
CFR
part
63,
appendix
A,
for
the
purpose
of
determining
compliance
with
the
emission
limitation
for
formaldehyde
emissions.
In
addition,
we
request
comments
on
the
use
of
Method
323
of
40
CFR
part
63,
appendix
A,
SW
 
846
Method
0011,
and
CARB
430
to
determine
compliance
with
the
emission
limitations
for
formaldehyde.
We
request
any
HAP
emissions
test
data
available
from
stationary
combustion
turbines;
however,
if
you
submit
HAP
emissions
test
data,
please
submit
the
full
and
complete
emission
test
report
with
this
data.
Without
a
complete
emission
test
report,
which
includes
sections
describing
the
stationary
combustion
turbine
and
its
operation
during
the
test
as
well
as
identifying
the
stationary
combustion
turbine
for
purposes
of
verification,
discussion
of
the
test
methods
employed
and
the
Quality
Assurance/
Quality
Control
(
QA/
QC)
procedures
followed,
the
raw
data
sheets,
all
the
calculations,
etc.,
which
such
reports
contain,
submittal
of
HAP
emission
data
by
itself
is
of
little
use.

B.
Can
We
Achieve
the
Goals
of
the
Proposed
Rule
in
a
Less
Costly
Manner?
We
have
made
every
effort
in
developing
the
proposal
to
minimize
the
cost
to
the
regulated
community
and
allow
maximum
flexibility
in
compliance
options
consistent
with
our
statutory
obligations.
We
recognize,
however,
that
the
proposal
may
still
require
some
facilities
to
take
costly
steps
to
further
control
emissions
even
though
those
emissions
may
not
result
in
exposures
which
could
pose
an
excess
individual
lifetime
cancer
risk
greater
than
one
in
1
million
or
exceed
thresholds
determined
to
provide
an
ample
margin
of
safety
for
protecting
public
health
and
the
environment
from
the
effects
of
HAP.
We
also
recognize
that
in
some
cases
the
proposal
may
require
facilities
to
undertake
emissions
testing
and
monitoring
even
when
the
rule
will
not
require
them
to
reduce
emissions
at
all.
However,
this
is
necessary
to
assure
the
proper
initial
performance
and
continuing
performance
of
the
emission
reductionpollution
prevention
technology.
We
are,
therefore,
specifically
soliciting
comment
on
whether
there
are
further
ways
to
structure
the
proposed
rule
to
focus
on
the
facilities
which
pose
significant
risks
and
avoid
the
imposition
of
high
costs
on
facilities
that
pose
little
risk
to
public
health
and
the
environment.
Representatives
of
the
plywood
and
composite
wood
products
industry
provided
EPA
with
descriptions
of
three
mechanisms
that
they
believed
could
be
used
to
implement
more
cost­
effective
reductions
in
risk.
The
docket
for
today's
proposed
rule
contains
white
papers
prepared
by
the
plywood
and
composite
wood
products
industry
that
outline
their
proposed
approaches
(
see
docket
OAR
 
2002
 
0060).
These
approaches
could
be
effective
in
focusing
regulatory
controls
on
facilities
that
pose
significant
risks
and
avoiding
the
imposition
of
high
costs
on
facilities
that
pose
little
risk
to
public
health
or
the
environment,
and
we
are
seeking
public
comment
on
the
utility
of
each
of
these
approaches
with
respect
to
the
proposed
rule.
One
of
the
approaches,
an
applicability
cutoff
for
threshold
pollutants,
would
be
implemented
under
the
authority
of
CAA
section
112(
d)(
4);
the
second
approach,
subcategorization
and
delisting,
would
be
implemented
under
the
authority
of
CAA
sections
112(
c)(
1)
and
112(
c)(
9);
and
the
third
approach
would
involve
the
use
of
a
concentration­
based
applicability
threshold.
We
are
seeking
comment
on
whether
these
approaches
are
legally
justified
and,
if
so,
we
ask
for
information
that
could
be
used
to
support
such
approaches.
In
addition,
on
August
21,
2002,
the
Agency
received
a
petition
from
the
Gas
Turbine
Association
(
GTA)
requesting
that
natural
gas
fueled
combustion
turbines
be
delisted
and
a
study
that
they
believed
would
justify
delisting.
Section
112(
c)(
9)
of
the
CAA
provides
EPA
with
the
authority
to
delist
categories
or
subcategories
either
in
response
to
the
petition
of
any
person
or
upon
the
Administrator's
own
motion.
The
GTA
states
that
the
study
supports
a
determination
that
HAP
emissions
from
gas
turbines
would
not
result
in
a
lifetime
cancer
risk
greater
than
one
in
a
million
to
the
individual
in
the
population
most
exposed
to
the
emissions
or
non­
carcinogenic
health
risk
exceeding
a
level
which
is
adequate
to
protect
public
health
with
an
ample
margin
of
safety.
We
have
reviewed
the
GTA
study
and
responded
to
the
GTA
on
October
11,
2002
with
questions
and
areas
that
we
believe
need
further
analysis.
The
EPA's
request
for
further
information
and
all
information
provided
by
the
petitioner
to
date
is
located
in
the
docket
for
today's
proposed
rule.
The
MACT
program
outlined
in
CAA
section
112(
d)
is
intended
to
reduce
emissions
of
HAP
through
the
application
of
MACT
to
major
sources
of
toxic
air
pollutants.
Section
112(
c)(
9)
is
intended
to
allow
EPA
to
avoid
setting
MACT
standards
for
sources
or
subcategories
of
sources
that
pose
less
than
a
specified
level
of
risk
to
public
health
and
the
environment.
The
EPA
requests
comment
on
whether
the
proposals
described
here
appropriately
coordinate
these
provisions
of
CAA
section
112.
The
two
health­
based
approaches
focus
on
assessing
inhalation
exposures
or
accounting
for
adverse
environmental
impacts.
EPA
specifically
requests
comment
on
the
appropriateness
and
necessity
of
extending
these
approaches
to
account
for
non­
inhalation
exposures
of
certain
HAP
which
may
deposit
from
the
atmosphere
after
being
emitted
into
the
air
or
to
account
for
adverse
environmental
impacts.
In
addition
to
the
specific
requests
for
comment
noted
in
this
section,
we
are
also
interested
in
any
information
or
comment
concerning
technical
limitations,
environmental
and
cost
impacts,
compliance
assurance,
legal
rationale,
and
implementation
relevant
to
the
identified
approaches.
We
also
request
comment
on
appropriate
practicable
and
verifiable
methods
to
ensure
that
sources'
emissions
remain
below
levels
that
protect
public
health
and
the
environment.
We
will
evaluate
all
comments
before
determining
whether
to
include
an
approach
in
the
final
rule.

1.
Industry
HAP
Emissions
and
Potential
Health
Effects
For
the
stationary
combustion
turbines
source
category,
four
HAP
account
for
essentially
all
of
the
mass
of
HAP
emissions.
Those
four
HAP
are
formaldehyde,
toluene,
benzene,
and
acetaldehyde.
Additional
HAP
which
have
been
measured
in
emission
tests
that
were
conducted
at
natural
gas
fired
and
distillate
oil
fired
combustion
turbines
are:
1,3
butadiene,
acrolein,
ethylbenzene,
naphthalene,
polycyclic
aromatic
hydrocarbons
(
PAH),
propylene
oxide,
and
xylenes.
The
following
metallic
HAP
emissions
have
been
measured
from
distillate
oil
fired
stationary
combustion
turbines:
arsenic,
beryllium,
cadmium,
chromium,
lead,
manganese,
mercury,
nickel,
and
selenium.
Of
the
four
HAP
emitted
in
the
largest
quantities
by
this
source
category,
all
can
cause
toxic
effects
following
sufficient
exposure.
The
potential
toxic
effects
of
these
four
HAP
are
discussed
previously
in
this
preamble.
In
accordance
with
section
112(
k),
EPA
developed
a
list
of
33
HAP
which
present
the
greatest
threat
to
public
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14,
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/
Proposed
Rules
2
See
63
FR
18754,
18765
 
66
(
April
15,
1998)
(
Pulp
and
Paper
Sources
Proposed
NESHAP)
3
``
Methods
for
Derivation
of
Inhalation
Reference
Concentrations
and
Applications
of
Inhalation
Dosimetry.''
EPA
 
600/
8
 
90
 
066F,
Office
of
Research
and
Development,
USEPA,
October
1994.
4
``
Supplementary
Guidance
for
Conducting
Health
Risk
Assessment
of
Chemical
Mixtures.
Risk
Assessment
Forum
Technical
Panel,''
EPA/
630/
R
 
00/
002.
USEPA,
August
2000.
http://
www.
epa.
gov/
nceawww1/
pdfs/
chem_
mix/
chem_
mix
08_
2001.
pdf.
2
health
in
the
largest
number
of
urban
areas.
Of
the
four
predominant
HAP,
three
(
acetaldehyde,
benzene,
and
formaldehyde)
are
included
on
this
list
for
the
EPA's
Urban
Air
Toxics
Program.
Eleven
of
the
other
emitted
HAP
(
acrolein,
arsenic
compounds,
beryllium
compounds,
1,3­
butadiene,
cadmium
compounds,
chromium
compounds,
lead
compounds,
manganese
compounds,
mercury
compounds,
nickel
compounds,
and
PAH
(
as
POM))
also
appear
on
the
list.
In
November
1998,
EPA
published
``
A
Multimedia
Strategy
for
Priority
Persistent,
Bioaccumulative,
and
Toxic
(
PBT)
Pollutants.''
None
of
the
predominant
four
HAP
emitted
by
stationary
combustion
turbine
operations
appears
on
the
published
list
of
compounds
referred
to
in
the
EPA's
PBT
strategy.
Three
of
the
other
HAP
(
mercury
compounds,
cadmium
compounds,
and
PAH)
appear
on
the
list.
Of
the
HAP
emitted
by
stationary
combustion
turbine
operations,
fifteen
(
acetaldehyde,
acrolein,
arsenic
compounds,
benzene,
beryllium
compounds,
1,3­
butadiene,
cadmium
compounds,
chromium
compounds,
formaldehyde,
lead
compounds,
mercury
compounds,
naphthalene,
nickel
compounds,
PAH,
and
propylene
oxide)
are
carcinogens
that,
at
present,
are
not
considered
to
have
thresholds
for
cancer
effects.
Formaldehyde,
however,
is
a
potential
threshold
carcinogen,
and
EPA
is
currently
revising
the
dose­
response
assessment
for
formaldehyde.

2.
Applicability
Cutoffs
for
Threshold
Pollutants
Under
Section
112(
d)(
4)
of
the
CAA
The
first
approach
is
an
applicability
cutoff
for
threshold
pollutants
that
is
based
on
EPA's
authority
under
CAA
section
112(
d)(
4)
to
establish
standards
for
HAP
which
are
threshold
pollutants.
A
threshold
pollutant
is
one
for
which
there
is
a
concentration
or
dose
below
which
adverse
effects
are
not
expected
to
occur
over
a
lifetime
of
exposure.
For
such
pollutants,
CAA
section
112(
d)(
4)
allows
EPA
to
consider
the
threshold
level,
with
an
ample
margin
of
safety,
when
establishing
emissions
standards.
Specifically,
CAA
section
112(
d)(
4)
allows
EPA
to
establish
emission
standards
that
are
not
based
upon
the
MACT
specified
under
CAA
section
112(
d)(
2)
for
pollutants
for
which
a
health
threshold
has
been
established.
Such
standards
may
be
less
stringent
than
MACT.
Historically,
EPA
has
interpreted
CAA
section
112(
d)(
4)
to
allow
categories
of
sources
that
emit
only
threshold
pollutants
to
avoid
further
regulation
if
those
emissions
result
in
ambient
levels
that
do
not
exceed
the
threshold,
with
an
ample
margin
of
safety.
2
A
different
interpretation
would
allow
us
to
exempt
individual
facilities
within
a
source
category
that
meet
the
CAA
section
112(
d)(
4)
requirements.
There
are
three
potential
scenarios
under
this
interpretation
of
the
CAA
section
112(
d)(
4)
provision.
One
scenario
would
allow
an
exemption
for
individual
facilities
that
emit
only
threshold
pollutants
and
can
demonstrate
that
their
emissions
of
threshold
pollutants
would
not
result
in
air
concentrations
above
the
threshold
levels,
with
an
ample
margin
of
safety,
even
if
the
category
is
otherwise
subject
to
MACT.
A
second
scenario
would
allow
the
CAA
section
112(
d)(
4)
provision
to
be
applied
to
both
threshold
and
non­
threshold
pollutants,
using
the
one
in
a
million
cancer
risk
level
for
decisionmaking
for
non­
threshold
pollutants.
A
third
scenario
would
allow
a
CAA
section
112(
d)(
4)
exemption
at
a
facility
that
emits
both
threshold
and
nonthreshold
pollutants.
For
those
emission
points
where
only
threshold
pollutants
are
emitted
and
where
emissions
of
the
threshold
pollutants
would
not
result
in
air
concentrations
above
the
threshold
levels,
with
an
ample
margin
of
safety,
those
emission
points
could
be
exempt
from
the
MACT
standards.
The
MACT
standards
would
still
apply
to
nonthreshold
emissions
from
other
emission
points
at
the
source.
For
this
third
scenario,
emission
points
that
emit
a
combination
of
threshold
and
nonthreshold
pollutants
that
are
cocontrolled
by
MACT
would
still
be
subject
to
the
MACT
level
of
control.
However,
any
threshold
HAP
eligible
for
exemption
under
CAA
section
112(
d)(
4)
that
are
controlled
by
control
devices
different
from
those
controlling
nonthreshold
HAP
would
be
able
to
use
the
exemption,
and
the
facility
would
still
be
subject
to
the
parts
of
the
standards
that
control
non­
threshold
pollutants
or
that
control
both
threshold
and
non­
threshold
pollutants.
a.
Estimation
of
hazard
quotients
and
hazard
indices.
Under
the
CAA
section
112(
d)(
4)
approach,
EPA
would
have
to
determine
that
emissions
of
each
of
the
threshold
pollutants
emitted
by
stationary
combustion
turbines
at
the
facility
do
not
result
in
exposures
which
exceed
the
threshold
levels,
with
an
ample
margin
of
safety.
The
common
approach
for
evaluating
the
potential
hazard
of
a
threshold
air
pollutant
is
to
calculate
a
hazard
quotient
by
dividing
the
pollutant's
inhalation
exposure
concentration
(
often
assumed
to
be
equivalent
to
its
estimated
concentration
in
air
at
a
location
where
people
could
be
exposed)
by
the
pollutant's
inhalation
Reference
Concentration
(
RfC).
An
RfC
is
an
estimate
(
with
uncertainty
spanning
perhaps
an
order
of
magnitude)
of
a
continuous
inhalation
exposure
that,
over
a
lifetime,
likely
would
not
result
in
the
occurrence
of
adverse
health
effects
in
humans,
including
sensitive
individuals.
The
EPA
typically
establishes
an
RfC
by
applying
uncertainty
factors
to
the
critical
toxic
effect
derived
from
the
lowest­
or
no­
observed­
adverse­
effect
level
of
a
pollutant.
3
A
hazard
quotient
less
than
one
means
that
the
exposure
concentration
of
the
pollutant
is
less
than
the
RfC,
and,
therefore,
presumed
to
be
without
appreciable
risk
of
adverse
health
effects.
A
hazard
quotient
greater
than
one
means
that
the
exposure
concentration
of
the
pollutant
is
greater
than
the
RfC.
Further,
EPA
guidance
for
assessing
exposures
to
mixtures
of
threshold
pollutants
recommends
calculating
a
hazard
index
(
HI)
by
summing
the
individual
hazard
quotients
for
those
pollutants
in
the
mixture
that
affect
the
same
target
organ
or
system
by
the
same
mechanism.
4
The
HI
values
would
be
interpreted
similarly
to
hazard
quotients;
values
below
one
would
generally
be
considered
to
be
without
appreciable
risk
of
adverse
health
effects,
and
values
above
one
would
generally
be
cause
for
concern.
For
the
determinations
discussed
herein,
EPA
would
generally
plan
to
use
RfC
values
contained
in
EPA's
toxicology
database,
the
Integrated
Risk
Information
System
(
IRIS).
When
a
pollutant
does
not
have
an
approved
RfC
in
IRIS,
or
when
a
pollutant
is
a
carcinogen,
EPA
would
have
to
determine
whether
a
threshold
exists
based
upon
the
availability
of
specific
data
on
the
pollutant's
mode
or
mechanism
of
action,
potentially
using
a
health
threshold
value
from
an
alternative
source
such
as
the
Agency
for
Toxic
Substances
and
Disease
Registry
(
ATSDR)
or
the
California
Environmental
Protection
Agency
(
CalEPA).
Table
3
provides
RfC,
as
well
as
unit
risk
estimates,
for
the
HAP
emitted
by
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/
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14,
2003
/
Proposed
Rules
5
ibid.
combustion
turbine
operations.
A
unit
risk
estimate
is
defined
as
the
upperbound
excess
lifetime
cancer
risk
estimated
to
result
from
continuous
exposure
to
an
agent
at
a
concentration
of
1
ug/
m3
in
the
air.

TABLE
3.
 
DOSE­
RESPONSE
ASSESSMENT
VALUES
FOR
HAP
REPORTED
EMITTED
BY
THE
COMBUSTION
TURBINE
SOURCE
CATEGORY
Chemical
name
CAS
No.
Reference
concentration
a
(
mg/
m3)
Unit
risk
estimate
b
(
1/(
ug/
m3))

Acetaldehyde
............................................................................................................................
75
 
07
 
0
9.0E
 
03
IRIS
2.2E
 
06
IRIS
Acrolein
....................................................................................................................................
107
 
02
 
8
2.0E
 
05
IRIS
Arsenic
compounds
..................................................................................................................
7440
 
38
 
2
3.0E
 
05
CAL
4.3E
 
03
IRIS
Benzene
...................................................................................................................................
71
 
43
 
2
6.0E
 
02
CAL
7.8E
 
06
IRIS
Beryllium
compounds
...............................................................................................................
7440
 
41
 
7
2.0E
 
05
IRIS
2.4E
 
03
IRIS
1,3­
Butadiene
...........................................................................................................................
106
 
99
 
0
2.0E
 
03
IRIS
3.0E
 
05
EPA
ORD
Cadmium
compounds
..............................................................................................................
7440
 
43
 
9
2.0E
 
05
IRIS
1.8E
 
03
IRIS
Chromium
(
VI)
compounds
......................................................................................................
18540
 
29
 
9
1.0E
 
04
IRIS
1.2E
 
02
IRIS
Ethyl
benzene
..........................................................................................................................
100
 
41
 
4
1.0E+
00
IRIS
Formaldehyde
..........................................................................................................................
50
 
00
 
0
9.8E
 
03
ATSDR
1.3E
 
05
IRIS
Lead
compounds
......................................................................................................................
7439
 
92
 
1
1.2E
 
05
CAL
Manganese
compounds
...........................................................................................................
7439
 
96
 
5
5.0E
 
05
IRIS
Mercury
compounds
.................................................................................................................
HG_
CMPDS
9.0E
 
05
CAL
Naphthalene
.............................................................................................................................
91
 
20
 
3
3.0E
 
03
IRIS
Nickel
compounds
....................................................................................................................
7440
 
02
 
0
2.0E
 
04
ATSDR
9.1E
 
01
CAL
PAH
(
shown
below
as
7
 
PAH)
................................................................................................
Benzo
(
a)
anthracene
..............................................................................................................
56
 
55
 
3
1.1E
 
04
CAL
Benzo
(
b)
fluoranthene
............................................................................................................
205
 
99
 
2
1.1E
 
04
CAL
Benzo
(
k)
fluoranthene
.............................................................................................................
207
 
08
 
9
1.1E
 
04
CAL
Benzo
(
a)
pyrene
.....................................................................................................................
50
 
32
 
8
1.1E
 
03
CAL
Chrysene
..................................................................................................................................
218
 
01
 
9
1.1E
 
05
CAL
Dibenz
(
a,
h)
anthracene
..........................................................................................................
53
 
70
 
3
1.2E
 
03
CAL
Indeno
(
1,2,3­
cd)
pyrene
..........................................................................................................
193
 
39
 
5
.
1.4E
 
04
CAL
Propylene
oxide
.......................................................................................................................
75
 
56
 
9
3.0E
 
02
IRIS
3.7E
 
06
IRIS
Selenium
compounds
...............................................................................................................
7782
 
49
 
2
2.0E
 
02
CAL
Toluene
....................................................................................................................................
108
 
88
 
3
4.0E
 
01
IRIS
Xylenes
(
mixed)
.......................................................................................................................
1330
 
20
 
7
4.3E
 
01
ATSDR
a
Reference
Concentration:
An
estimate
(
with
uncertainty
spanning
perhaps
an
order
of
magnitude)
of
a
continuous
inhalation
exposure
to
the
human
population
(
including
sensitive
subgroups
which
include
children,
asthmatics,
and
the
elderly)
that
is
likely
to
be
without
an
appreciable
risk
of
deleterious
effects
during
a
lifetime.
It
can
be
derived
from
various
types
of
human
or
animal
data,
with
uncertainty
factors
generally
applied
to
reflect
limitations
of
the
data
used.
b
Unit
Risk
Estimate:
The
upper­
bound
excess
lifetime
cancer
risk
estimated
to
result
from
continuous
exposure
to
an
agent
at
a
concentration
of
1
ug/
m3
in
air.
The
interpretation
of
the
Unit
Risk
Estimate
would
be
as
follows:
If
the
Unit
Risk
Estimate
=
1.5
×
10
 
6
per
ug/
m3,
1.5
excess
tumors
are
expected
to
develop
per
1,000,000
people
if
exposed
daily
for
a
lifetime
to
1
ug
of
the
chemical
in
1
cubic
meter
of
air.
Unit
Risk
Estimates
are
considered
upper
bound
estimates,
meaning
they
represent
a
plausible
upper
limit
to
the
true
value.
(
Note
that
this
is
usually
not
a
true
statistical
confidence
limit.)
The
true
risk
is
likely
to
be
less,
but
could
be
greater.
Sources:
IRIS
=
EPA
Integrated
Risk
Information
System
(
http://
www.
epa.
gov/
iris/
subst/
index.
html).
ATSDR
=
U.
S.
Agency
for
Toxic
Substances
and
Disease
Registry
(
http://
www.
atsdr.
cdc.
gov/
mrls.
html).
CAL
=
California
Office
of
Environmental
Health
Hazard
Assessment.
(
http://
www.
oehha.
ca.
gov/
air/
hot_
spots/
index.
html).
HEAST
=
EPA
Health
Effects
Assessment
Summary
Tables
(#
PB(=
97
 
921199,
July
1997).

To
establish
an
applicability
cutoff
under
CAA
section
112(
d)(
4),
EPA
would
need
to
define
ambient
air
exposure
concentration
limits
for
any
threshold
pollutants
involved.
There
are
several
factors
to
consider
when
establishing
such
concentrations.
First
we
would
need
to
ensure
that
the
concentrations
that
would
be
established
would
protect
public
health
with
an
ample
margin
of
safety.
As
discussed
above,
the
approach
EPA
commonly
uses
when
evaluating
the
potential
hazard
of
a
threshold
air
pollutant
is
to
calculate
the
pollutant's
hazard
quotient,
which
is
the
exposure
concentration
divided
by
the
RfC.
The
EPA's
``
Supplementary
Guidance
for
Conducting
Health
Risk
Assessment
of
Chemical
Mixtures''
suggests
that
the
noncancer
health
effects
associated
with
a
mixture
of
pollutants
ideally
are
assessed
by
considering
the
pollutants'
common
mechanisms
of
toxicity
5.
The
guidance
also
suggests
that
when
exposures
to
mixtures
of
pollutants
are
being
evaluated,
the
risk
assessor
may
calculate
a
HI.
The
recommended
method
is
to
calculate
multiple
hazard
indices
for
each
exposure
route
of
interest,
and
for
a
single
specific
toxic
effect
or
toxicity
to
a
single
target
organ.
The
default
approach
recommended
by
the
guidance
is
to
sum
the
hazard
quotients
for
those
pollutants
that
induce
the
same
toxic
effect
or
affect
the
same
target
organ.
A
mixture
is
then
assessed
by
several
HI,
each
representing
one
toxic
effect
or
target
organ.
The
guidance
notes
that
the
pollutants
included
in
the
HI
calculation
are
any
pollutants
that
show
the
effect
being
assessed,
regardless
of
the
critical
effect
upon
which
the
RfC
is
based.
The
guidance
cautions
that
if
the
target
organ
or
toxic
effect
for
which
the
HI
is
calculated
is
different
from
the
RfC's
critical
effect,
then
the
RfC
for
that
chemical
will
be
an
overestimate,
that
is,
the
resultant
HI
potentially
may
be
overprotective.
Conversely,
since
the
calculation
of
a
HI
does
not
account
for
the
fact
that
the
potency
of
a
mixture
of
HAP
can
be
more
potent
than
the
sum
of
the
individual
HAP
potencies,
a
HI
may
potentially
be
underprotective
in
some
situations.

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No.
9
/
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14,
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/
Proposed
Rules
6
Senate
Debate
on
Conference
Report
(
October
27,
1990),
reprinted
in
``
A
Legislative
History
of
the
Clean
Air
Act
Amendments
of
1990,''
Comm.
Print
S.
Prt.
103
 
38
(
1993)
(``
Legis.
Hist.'')
at
868.
7
See
http://
www.
epa.
gov/
ttn/
atw/
nata.
8
See
http://
www.
atsdr.
cdc.
gov/
toxpro2.
html.
9
``
A
Tiered
Modeling
Approach
for
Assessing
the
Risks
due
to
Sources
of
Hazardous
Air
Pollutants.''
EPA
 
450/
4
 
92
 
001.
David
E.
Guinnup,
Office
of
Air
Quality
Planning
and
Standards,
USEPA,
March
1992.
10
``
Draft
Revised
Guidelines
for
Carcinogen
Risk
Assessment.''
NCEA
 
F
 
0644,
USEPA,
Risk
Assessment
Forum,
July
1999.
pp
3
 
9ff.
http://
www.
epa.
gov/
ncea/
raf/
pdfs/
cancer
l
gls.
pdf.
b.
Options
for
establishing
a
HI
limit.
One
consideration
in
establishing
a
HI
limit
is
whether
the
analysis
considers
the
total
ambient
air
concentrations
of
all
the
emitted
HAP
to
which
the
public
is
exposed
6.
There
are
several
options
for
establishing
a
HI
limit
for
the
§
112(
d)(
4)
analysis
that
reflect,
to
varying
degrees,
public
exposure.
One
option
is
to
allow
the
hazard
index
posed
by
all
threshold
HAP
emitted
by
combustion
turbines
at
the
facility
to
be
no
greater
than
one.
This
approach
is
protective
if
no
additional
threshold
HAP
exposures
would
be
anticipated
from
other
sources
at,
or
in
the
vicinity
of,
the
facility
or
through
other
routes
of
exposure
(
i.
e.,
through
ingestion).
A
second
option
is
to
adopt
a
default
percentage
approach,
whereby
the
HI
limit
of
the
HAP
emitted
by
the
facility
is
set
at
some
percentage
or
fraction
of
one
(
e.
g.,
20
percent
or
0.2).
This
approach
recognizes
the
fact
that
the
facility
in
question
is
only
one
of
many
sources
of
threshold
HAP
to
which
people
are
typically
exposed
every
day.
Because
noncancer
risk
assessment
is
predicated
on
total
exposure
or
dose,
and
because
risk
assessments
focus
only
on
an
individual
source,
establishing
a
HI
limit
of
0.2
would
account
for
an
assumption
that
20
percent
of
an
individual's
total
exposure
is
from
that
individual
source.
For
the
purposes
of
this
discussion,
we
will
call
all
sources
of
HAP,
other
than
operations
within
the
source
category
at
the
facility
in
question,
``
background''
sources.
If
the
affected
source
is
allowed
to
emit
HAP
such
that
its
own
impacts
could
result
in
HI
values
of
one,
total
exposures
to
threshold
HAP
in
the
vicinity
of
the
facility
could
be
substantially
greater
than
one
due
to
background
sources,
and
this
would
not
be
protective
of
public
health,
since
only
HI
values
below
one
are
considered
to
be
without
appreciable
risk
of
adverse
health
effects.
Thus,
setting
the
HI
limit
for
the
facility
at
some
default
percentage
of
one
will
provide
a
buffer
which
would
help
to
ensure
that
total
exposures
to
threshold
HAP
near
the
facility
(
i.
e.,
in
combination
with
exposures
due
to
background
sources)
will
generally
not
exceed
one,
and
can
generally
be
considered
to
be
without
appreciable
risk
of
adverse
health
effects.
The
EPA
requests
comment
on
using
the
default
percentage
approach
and
on
setting
the
default
HI
limit
at
0.2.
The
EPA
is
also
requesting
comment
on
whether
an
alternative
HI
limit,
in
some
multiple
of
one,
would
be
a
more
appropriate
applicability
cutoff.
A
third
option
is
to
use
available
data
(
from
scientific
literature
or
EPA
studies,
for
example)
to
determine
background
concentrations
of
HAP,
possibly
on
a
national
or
regional
basis.
These
data
would
be
used
to
estimate
the
exposures
to
HAP
from
noncombustion
turbine
sources
in
the
vicinity
of
an
individual
facility.
For
example,
EPA's
National
Scale
Air
Toxics
Assessment
(
NATA)
7
and
ATSDR's
Toxicological
Profiles
8
contain
information
about
background
concentrations
of
some
HAP
in
the
atmosphere
and
other
media.
The
combined
exposures
from
an
affected
source
and
from
background
emissions
(
as
determined
from
the
literature
or
studies)
would
then
not
be
allowed
to
exceed
a
HI
limit
of
1.
The
EPA
requests
comment
on
the
appropriateness
of
setting
the
hazard
index
limit
at
one
for
such
an
analysis.
A
fourth
option
is
to
allow
facilities
to
estimate
or
measure
their
own
facility­
specific
background
HAP
concentrations
for
use
in
their
analysis.
With
regard
to
the
third
and
fourth
options,
EPA
requests
comment
on
how
these
analyses
could
be
structured.
Specifically,
EPA
requests
comment
on
how
the
analyses
should
take
into
account
background
exposure
levels
from
air,
water,
food
and
soil
encountered
by
the
individuals
exposed
to
emissions
from
this
source
category.
In
addition,
we
request
comment
on
how
such
analyses
should
account
for
potential
increases
in
exposures
due
to
the
use
of
a
new
HAP
or
the
increased
use
of
a
previously
emitted
HAP,
or
the
effect
of
other
nearby
sources
that
release
HAP.
The
EPA
requests
comment
on
the
feasibility
and
scientific
validity
of
each
of
these
or
other
options.
Finally,
EPA
requests
comment
on
how
we
should
implement
the
CAA
section
112(
d)(
4)
applicability
cutoffs,
including
appropriate
mechanisms
for
applying
cutoffs
to
individual
facilities.
For
example,
would
the
title
V
permit
process
provide
an
appropriate
mechanism?
c.
Tiered
analytical
approach
for
predicting
exposure.
Establishing
that
a
facility
meets
the
cutoffs
established
under
CAA
section
112(
d)(
4)
will
necessarily
involve
combining
estimates
of
pollutant
emissions
with
air
dispersion
modeling
to
predict
exposures.
The
EPA
envisions
that
we
would
promote
a
tiered
analytical
approach
for
these
determinations.
A
tiered
analysis
involves
making
successive
refinements
in
modeling
methodologies
and
input
data
to
derive
successively
less
conservative,
more
realistic
estimates
of
pollutant
concentrations
in
air
and
estimates
of
risk.
As
a
first
tier
of
analysis,
EPA
could
develop
a
series
of
simple
look­
up
tables
based
on
the
results
of
air
dispersion
modeling
conducted
using
conservative
input
assumptions.
By
specifying
a
limited
number
of
input
parameters,
such
as
stack
height,
distance
to
property
line,
and
emission
rate,
a
facility
could
use
these
look­
up
tables
to
determine
easily
whether
the
emissions
from
their
sources
might
cause
a
hazard
index
limit
to
be
exceeded.
A
facility
that
does
not
pass
this
initial
conservative
screening
analysis
could
implement
increasingly
more
sitespecific
but
more
resource­
intensive
tiers
of
analysis
using
EPA­
approved
modeling
procedures,
in
an
attempt
to
demonstrate
that
their
facility
does
not
exceed
the
HI
limit.
Existing
EPA
guidance
could
provide
the
basis
for
conducting
such
a
tiered
analysis.
9
The
EPA
requests
comment
on
methods
for
constructing
and
implementing
a
tiered
analysis
for
determining
applicability
of
the
CAA
section
112(
d)(
4)
criterion
to
specific
combustion
turbine
sources.
Ambient
monitoring
data
could
possibly
be
used
to
supplement
or
supplant
the
tiered
modeling
analysis
described
above.
We
envision
that
the
appropriate
monitoring
to
support
such
a
determination
could
be
extensive.
The
EPA
requests
comment
on
the
appropriate
use
of
monitoring
in
the
determinations
described
above.
d.
Accounting
for
dose­
response
relationships.
In
the
past,
EPA
routinely
treated
carcinogens
as
nonthreshold
pollutants.
The
EPA
recognizes
that
advances
in
risk
assessment
science
and
policy
may
affect
the
way
EPA
differentiates
between
threshold
and
nonthreshold
HAP.
The
EPA's
draft
Guidelines
for
Carcinogen
Risk
Assessment
10
suggest
that
carcinogens
be
assigned
non­
linear
dose­
response
relationships
where
data
warrant.
Moreover,
it
is
possible
that
doseresponse
curves
for
some
pollutants
may
reach
zero
risk
at
a
dose
greater
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14,
2003
/
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Rules
than
zero,
creating
a
threshold
for
carcinogenic
effects.
It
is
possible
that
future
evaluations
of
the
carcinogens
emitted
by
this
source
category
would
determine
that
one
or
more
of
the
carcinogens
in
the
category
is
a
threshold
carcinogen
or
is
a
carcinogen
that
exhibits
a
non­
linear
dose­
response
relationship
but
does
not
have
a
threshold.
The
dose­
response
assessment
for
formaldehyde
is
currently
undergoing
revision
by
EPA.
As
part
of
this
revision
effort,
EPA
is
evaluating
formaldehyde
as
a
potential
non­
linear
carcinogen.
The
revised
dose­
response
assessment
will
be
subject
to
review
by
the
EPA
Science
Advisory
Board,
followed
by
full
consensus
review,
before
adoption
into
the
EPA
IRIS.
At
this
time,
EPA
estimates
that
the
consensus
review
will
be
completed
by
the
end
of
2003.
The
revision
of
the
dose­
response
assessment
could
affect
the
potency
factor
of
formaldehyde,
as
well
as
its
status
as
a
threshold
or
nonthreshold
pollutant.
At
this
time,
the
outcome
is
not
known.
In
addition
to
the
current
reassessment
by
EPA,
there
have
been
several
reassessments
of
the
toxicity
and
carcinogenicity
of
formaldehyde
in
recent
years,
including
work
by
the
World
Health
Organization
and
the
Canadian
Ministry
of
Health.
The
EPA
requests
comment
on
how
we
should
consider
the
state
of
the
science
as
it
relates
to
the
treatment
of
threshold
pollutants
when
making
determinations
under
CAA
section
CAA
section
112(
d)(
4).
In
addition,
EPA
requests
comment
on
whether
there
is
a
level
of
emissions
of
a
non­
threshold
carcinogenic
HAP
at
which
it
would
be
appropriate
to
allow
a
facility
to
use
the
scenarios
discussed
under
the
CAA
section
112(
d)(
4)
approach.
If
the
CAA
section
112(
d)(
4)
approach
were
adopted,
the
requirements
of
the
rule
as
proposed
would
not
apply
to
any
source
that
demonstrates,
based
on
a
tiered
analysis
that
includes
EPAapproved
modeling
of
the
affected
source's
emissions,
that
the
anticipated
HAP
exposures
do
not
exceed
the
specified
HI
limit.

3.
Subcategory
Delisting
Under
Section
112(
c)(
9)(
B)
of
the
CAA
The
EPA
is
authorized
to
establish
categories
and
subcategories
of
sources,
as
appropriate,
pursuant
to
CAA
section
112(
c)(
1),
in
order
to
facilitate
the
development
of
MACT
standards
consistent
with
section
112
of
the
CAA.
Further,
section
CAA
section
112(
c)(
9)(
B)
allows
EPA
to
delete
a
category
(
or
subcategory)
from
the
list
of
major
sources
for
which
MACT
standards
are
to
be
developed
when
the
following
can
be
demonstrated:
(
1)
In
the
case
of
carcinogenic
pollutants,
that
``
no
source
in
the
category
*
*
*
emits
[
carcinogenic]
air
pollutants
in
quantities
which
may
cause
a
lifetime
risk
of
cancer
greater
than
one
in
1
million
to
the
individual
in
the
population
who
is
most
exposed
to
emissions
of
such
pollutants
from
the
source'';
(
2)
in
the
case
of
pollutants
that
cause
adverse
noncancer
health
effects,
that
``
emissions
from
no
source
in
the
category
or
subcategory
*
*
*
exceed
a
level
which
is
adequate
to
protect
public
health
with
an
ample
margin
of
safety'';
and
(
3)
in
the
case
of
pollutants
that
cause
adverse
environmental
effects,
that
``
no
adverse
environmental
effect
will
result
from
emissions
from
any
source.''
One
way
in
which
the
Agency
could
use
these
authorities
would
be
to
define
a
subcategory
of
facilities
within
the
source
category
based
upon
technological
differences,
such
as
differences
in
turbine
design
characteristics,
fuel
type,
production
rate,
emission
vent
flow
rates,
overall
facility
size,
emissions
characteristics,
processes,
or
air
pollution
control
device
viability.
The
EPA
requests
comment
on
how
we
might
establish
subcategories
based
on
these,
or
other,
source
characteristics.
If
it
could
then
be
determined
that
each
source
in
this
technologically­
defined
subcategory
presents
a
low
risk
to
the
surrounding
community,
the
subcategory
could
then
be
delisted
in
accordance
with
CAA
section
112(
c)(
9).
The
GTA
letter
discussed
above
provides
two
examples
of
technological
differences
that
may
allow
us
to
create
subcategories
of
stationary
combustion
turbines.
Those
subcategories
could
be
delisted
if
it
were
demonstrated
that
they
met
the
requirements
of
CAA
section
112(
c)(
9).
The
GTA
letter
includes
information
on
the
risks
created
by
emissions
from
lean­
premix
turbines.
We
are
already
proposing
a
subcategory
for
lean­
premix
turbines
and
in
that
discussion
describe
how
these
turbines
are
clearly
technologically
different
from
other
types
of
stationary
combustion
turbines.
While
the
GTA
letter
did
not
provide
sufficient
information
for
us
to
delist
lean­
premix
turbines
at
this
time,
leanpremix
turbines
are
a
subcategory
that
could
be
delisted
if
GTA
or
other
commenters
provide
sufficient
information
for
us
to
determine
that
this
subcategory
satisfies
the
requirements
of
CAA
section
112(
c)(
9).
Natural
gas
fired
turbines
are
another
example
of
a
subcategory
that
might
be
delisted
under
this
approach.
We
have
created
subcategories
based
on
fuel
type
in
other
MACT
rules
and
believe
that
fuel
type
could
be
an
appropriate
way
of
subcategorizing
stationary
combustion
turbines
or
of
creating
further
subdivisions
within
the
subcategories
contained
in
the
proposed
rule.
We
are
not
proposing
a
subcategory
for
natural
gas
fired
turbines
at
this
time,
although
we
could
create
such
a
subcategory
in
the
future,
if
appropriate.
While
the
information
presented
in
GTA's
letter
is
not
sufficient
for
us
to
make
this
determination
at
this
time,
additional
information
on
the
emissions
and
risks
from
natural
gas
fired
turbines
could
lead
us
to
delist
natural
gas
fired
turbines
under
this
approach.
The
EPA
requests
comment
on
the
concept
of
identifying
technologicallybased
subcategories
that
may
include
only
low­
risk
facilities
within
the
combustion
turbine
source
category
and
on
the
specific
examples
presented
above.
Another
approach
to
using
the
authority
granted
in
CAA
section
112(
c)(
9)
is
presented
in
the
white
paper
prepared
by
representatives
of
the
plywood
and
composite
wood
products
industry
(
see
docket
OAR
2002
 
0060).
The
EPA
is
considering
whether
it
would
be
possible
to
establish
a
subcategory
of
facilities
within
the
larger
source
category
that
would
meet
the
risk­
based
criteria
for
delisting.
Such
criteria
would
likely
include
the
same
requirements
as
described
previously
for
the
second
scenario
under
the
CAA
section
112(
d)(
4)
approach,
whereby
a
facility
would
be
in
the
low­
risk
subcategory
if
its
emissions
of
threshold
pollutants
do
not
result
in
exposures
which
exceed
the
HI
limits
and
if
its
emissions
of
nonthreshold
pollutants
do
not
exceed
a
cancer
risk
level
of
10
¥
6.
The
EPA
requests
comment
on
what
an
appropriate
HI
limit
would
be
for
a
determination
that
a
facility
be
included
in
the
low­
risk
subcategory.
Since
each
facility
in
such
a
subcategory
would
be
a
low­
risk
facility
(
i.
e.,
if
each
met
these
criteria),
the
subcategory
could
be
delisted
in
accordance
with
CAA
section
112(
c)(
9),
thereby
limiting
the
costs
and
impacts
of
the
proposed
MACT
rule
to
only
those
facilities
that
do
not
qualify
for
subcategorization
and
delisting.
Facilities
seeking
to
be
included
in
the
delisted
subcategory
would
be
responsible
for
providing
all
data
required
to
determine
whether
they
are
eligible
for
inclusion.
Facilities
that
could
not
demonstrate
that
they
are
eligible
to
be
included
in
the
low­
risk
subcategory
would
be
subject
to
MACT
and
possible
future
residual
risk
standards.
The
EPA
solicits
comment
on
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Proposed
Rules
implementing
a
risk­
based
approach
for
establishing
subcategories
of
stationary
combustion
turbines.
Since
each
facility
in
such
a
subcategory
would
be
a
low­
risk
facility
(
i.
e.,
if
each
met
these
criteria),
the
subcategory
could
be
delisted
in
accordance
with
CAA
section
112(
c)(
9),
thereby
limiting
the
costs
and
impacts
of
the
proposed
MACT
rule
to
only
those
facilities
that
do
not
qualify
for
subcategorization
and
delisting.
Establishing
that
a
facility
qualifies
for
the
low­
risk
subcategory
under
CAA
section
112(
c)(
9)
will
necessarily
involve
combining
estimates
of
pollutant
emissions
with
air
dispersion
modeling
to
predict
exposures.
The
EPA
envisions
that
we
would
employ
the
same
tiered
analysis
described
earlier
in
the
CAA
section
112
(
d)(
4)
discussion
for
these
determinations.
One
concern
that
EPA
has
with
respect
to
the
CAA
section
112(
c)(
9)
approach
is
the
effect
that
it
could
have
on
the
MACT
floors.
If
many
of
the
facilities
in
the
low­
risk
subcategory
are
well­
controlled,
that
could
make
the
MACT
floor
less
stringent
for
the
remaining
facilities.
One
approach
that
has
been
suggested
to
mitigate
this
effect
would
be
to
establish
the
MACT
floor
now
based
on
controls
in
place
for
the
entire
category
and
to
allow
facilities
to
become
part
of
the
low­
risk
subcategory
in
the
future,
after
the
MACT
standards
are
established.
This
would
allow
lowrisk
facilities
to
use
the
CAA
section
112(
c)(
9)
exemption
without
affecting
the
MACT
floor
calculation.
The
EPA
requests
comment
on
this
suggested
approach.
If
a
CAA
section
112(
c)(
9)
approach
were
adopted,
the
requirements
of
the
rule
as
proposed
would
not
apply
to
any
source
that
demonstrates
that
it
belongs
in
a
subcategory
which
has
been
delisted
under
CAA
section
112(
c)(
9).

C.
Limited
Use
Subcategory
We
are
soliciting
comments
on
creating
a
subcategory
of
limited
use
stationary
combustion
turbines
with
capacity
utilization
of
10
percent
or
less
(
876
or
fewer
hours
of
annual
operation).
Units
in
this
subcategory
would
include
combustion
turbines
used
for
electric
power
peak
shaving
that
are
called
upon
to
operate
fewer
than
876
hours
per
year.
These
units
operate
only
during
peak
energy
use
periods,
typically
in
the
summer
months.
We
believe
that
these
infrequently
operated
units
typically
operate
10
percent
of
the
year
or
less.
While
these
are
potential
sources
of
emissions,
and
it
is
appropriate
for
EPA
to
address
them
in
the
proposed
rule,
the
Agency
believes
that
their
use
and
operation
are
different
compared
to
typical
combustion
turbines.
We
believe
that
it
may
be
appropriate
for
such
limited
use
units
to
have
their
own
subcategory.
Therefore,
we
are
soliciting
comment
on
subcategorizing
combustion
turbines
having
a
capacity
utilization
of
less
than
10
percent.
We
are
interested
in
comments
on
creating
a
subcategory
for
limited
use
peak
shaving
(
less
than
10
percent
capacity
utilization)
combustion
turbines.
We
are
interested
in
comments
on
the
validity
and
appropriateness
under
the
CAA
for
a
subcategory
for
limited
use
peak
shaving
combustion
turbines,
data
on
the
levels
of
control
currently
achieved
by
such
combustion
turbines,
and
any
technical
limitations
that
might
make
it
impossible
to
achieve
control
of
emissions
from
limited
use
peak
shaving
combustion
turbines.

VI.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,
1993),
we
must
determine
whether
a
regulatory
action
is
``
significant''
and,
therefore,
subject
to
review
by
the
Office
of
Management
and
Budget
(
OMB)
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,
competition,
jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
tribal
governments
or
communities;
(
2)
create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;
(
3)
materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs,
or
the
rights
and
obligation
of
recipients
thereof;
or
(
4)
raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
Executive
Order
12866,
we
have
determined
that
the
proposed
rule
is
a
``
significant
regulatory
action''
within
the
meaning
of
the
Executive
Order.
As
such,
this
action
was
submitted
to
OMB
for
review.
Changes
made
in
response
to
OMB
suggestions
or
recommendations
are
included
in
the
docket.

B.
Executive
Order
13132,
Federalism
Executive
Order
13132
(
64
FR
43255,
August
10,
1999)
requires
us
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
are
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
The
proposed
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
We
are
required
by
section
112
of
the
CAA,
42
U.
S.
C.
§
7412,
to
establish
the
standards
in
the
proposed
rule.
The
proposed
rule
primarily
affects
private
industry,
and
does
not
impose
significant
economic
costs
on
State
or
local
governments.
The
proposed
rule
does
not
include
an
express
provision
preempting
State
or
local
regulations.
Thus,
the
requirements
of
section
6
of
the
Executive
Order
do
not
apply
to
the
proposed
rule.
Although
section
6
of
Executive
Order
13132
does
not
apply
to
the
proposed
rule,
we
consulted
with
representatives
of
State
and
local
governments
to
enable
them
to
provide
meaningful
and
timely
input
into
the
development
of
the
proposed
rule.
This
consultation
took
place
during
the
ICCR
FACA
committee
meetings
where
members
representing
State
and
local
governments
participated
in
developing
recommendations
for
EPA's
combustion­
related
rulemakings,
including
the
proposed
rule.
The
concerns
raised
by
representatives
of
State
and
local
governments
were
considered
during
the
development
of
the
proposed
rule.
In
the
spirit
of
Executive
Order
13132,
and
consistent
with
EPA
policy
to
promote
communications
between
EPA
and
State
and
local
governments,
EPA
specifically
solicits
comment
on
the
proposed
rule
from
State
and
local
officials.

C.
Executive
Order
13175,
Consultation
and
Coordination
with
Indian
Tribal
Governments
Executive
Order
13175
(
65
FR
67249,
November
6,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
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/
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14,
2003
/
Proposed
Rules
implications.''
``
Policies
that
have
tribal
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
one
or
more
Indian
tribes,
on
the
relationship
between
the
Federal
government
and
the
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes.''
The
proposed
rule
does
not
have
tribal
implications.
It
will
not
have
substantial
direct
effects
on
tribal
governments,
on
the
relationship
between
the
Federal
government
and
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes,
as
specified
in
Executive
Order
13175.
We
do
not
know
of
any
stationary
combustion
turbines
owned
or
operated
by
Indian
tribal
governments.
However,
if
there
are
any,
the
effect
of
these
rules
on
communities
of
tribal
governments
would
not
be
unique
or
disproportionate
to
the
effect
on
other
communities.
Thus,
Executive
Order
13175
does
not
apply
to
the
proposed
rule.

D.
Executive
Order
13045,
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that:
(
1)
Is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
we
have
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
we
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives.
We
interpret
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5
 
501
of
the
Executive
Order
has
the
potential
to
influence
the
regulation.
The
proposed
rule
is
not
subject
to
Executive
Order
13045
because
it
is
based
on
technology
performance
and
not
on
health
or
safety
risks.

E.
Executive
Order
13211,
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
Executive
Order
13211
(
66
FR
28355,
May
22,
2001),
provides
that
agencies
shall
prepare
and
submit
to
the
Administrator
of
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
a
Statement
of
Energy
Effects
for
certain
actions
identified
as
``
significant
energy
actions.''
Section
4(
b)
of
Executive
Order
13211
defines
``
significant
energy
actions''
as
``
any
action
by
an
agency
(
normally
published
in
the
Federal
Register)
that
promulgates
or
is
expected
to
lead
to
the
promulgation
of
a
final
rule
or
regulation,
including
notices
of
inquiry,
advance
notices
of
proposed
rulemaking,
and
notices
of
proposed
rulemaking:
(
1)
(
i)
That
is
a
significant
regulatory
action
under
Executive
Order
12866
or
any
successor
order,
and
(
ii)
is
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy;
or
(
2)
that
is
designated
by
the
Administrator
of
the
Office
of
Information
and
Regulatory
Affairs
as
a
significant
energy
action.''
The
proposed
rule
is
a
significant
regulatory
action
within
the
meaning
of
Executive
Order
12866.
We
have,
therefore,
prepared
a
Statement
of
Energy
Effects
for
this
action
as
follows.
The
increase
in
petroleum
product
output,
which
includes
increases
in
fuel
production,
is
estimated
at
0.003
percent,
or
about
475
barrels
per
day
based
on
2000
U.
S.
fuel
production
nationwide.
The
reduction
in
coal
production
is
estimated
at
0.006
percent,
or
about
700,000
short
tons
per
year
based
on
2000
U.
S.
coal
production
nationwide.
The
reduction
in
electricity
output
is
estimated
at
0.02
percent,
or
about
4.9
billion
kilowatt­
hours
per
year
based
on
2000
U.
S.
electricity
production
nationwide.
Production
of
natural
gas
is
expected
to
increase
by
3.0
million
cubic
feet
(
ft3)
per
day.
The
maximum
of
all
energy
price
increases,
which
include
increases
in
natural
gas
prices
as
well
as
those
for
petroleum
products,
coal,
and
electricity,
is
estimated
to
be
the
0.18
percent
increase
in
peak­
load
electricity
rates
nationwide.
Energy
distribution
costs
may
increase
by
roughly
no
more
than
the
same
amount
as
electricity
rates.
We
expect
that
there
will
be
no
discernable
impact
on
the
import
of
foreign
energy
supplies,
and
no
other
adverse
outcomes
are
expected
to
occur
with
regards
to
energy
supplies.
Also,
the
increase
in
cost
of
energy
production
should
be
minimal
given
the
very
small
increase
in
fuel
consumption
resulting
from
back
pressure
related
to
operation
of
oxidation
catalyst
emission
control
devices.
All
of
the
estimates
presented
above
account
for
some
passthrough
of
costs
to
consumers
as
well
as
the
direct
cost
impact
to
producers.
For
more
information
on
these
estimated
energy
effects,
please
refer
to
the
economic
impact
analysis
for
the
proposed
rule.
This
analysis
is
available
in
the
public
docket.
No
new
combustion
turbines
with
a
capacity
of
less
than
1.0
MW
will
be
affected.
Also,
the
control
level
applied
to
affected
new
combustion
turbines
is
the
minimum
that
can
be
applied
consistent
with
the
provisions
of
the
Clean
Air
Act.
Therefore,
we
conclude
that
the
proposed
rule
when
implemented
will
not
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy.

F.
Unfunded
Mandates
Reform
Act
of
1995
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Public
Law
104
 
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
we
generally
must
prepare
a
written
statement,
including
a
cost­
benefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
to
State,
local,
and
tribal
governments,
in
the
aggregate,
or
to
the
private
sector,
of
$
100
million
or
more
in
any
1
year.
Before
promulgating
a
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
us
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
cost­
effective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
us
to
adopt
an
alternative
other
than
the
least
costly,
most
cost­
effective
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
we
establish
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
we
must
develop
a
small
government
agency
plan
under
section
203
of
the
UMRA.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
We
have
determined
that
the
proposed
rule
contains
a
Federal
mandate
that
will
not
result
in
expenditures
of
$
100
million
or
more
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No.
9
/
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January
14,
2003
/
Proposed
Rules
for
State,
local,
and
tribal
governments,
in
the
aggregate,
or
the
private
sector
in
any
1
year.
Accordingly,
we
have
not
prepared
a
written
statement
under
section
202
of
the
UMRA.

1.
Statutory
Authority
As
discussed
in
previously
in
this
preamble,
the
statutory
authority
for
the
proposed
rulemaking
is
section
112
of
the
CAA.
Title
III
of
the
CAA
was
enacted
to
reduce
nationwide
air
toxic
emissions.
Section
112(
b)
of
the
CAA
lists
the
188
chemicals,
compounds,
or
groups
of
chemicals
deemed
by
Congress
to
be
HAP.
These
toxic
air
pollutants
are
to
be
regulated
by
NESHAP.
Section
112(
d)
of
the
CAA
directs
us
to
develop
NESHAP
which
require
existing
and
new
major
sources
to
control
emissions
of
HAP
using
MACT.
The
NESHAP
apply
to
all
stationary
combustion
turbines
located
at
major
sources
of
HAP
emissions,
however,
only
new
or
reconstructed
stationary
combustion
turbines
have
substantive
regulatory
requirements.
In
compliance
with
section
205(
a)
we
identified
and
considered
a
reasonable
number
of
regulatory
alternatives.
Additional
information
on
the
costs
and
environmental
impacts
of
the
regulatory
alternatives
is
presented
in
the
``
Stationary
Combustion
Turbines
Control
Options
Cost
Information
Summary''
in
the
docket.
The
regulatory
alternative
upon
which
the
proposed
rule
is
based
represents
the
MACT
floor
for
stationary
combustion
turbines
and,
as
a
result,
it
is
the
least
costly
and
least
burdensome
alternative.
In
addition,
we
have
conducted
an
economic
impact
analysis
of
today's
proposed
rule
that
includes
the
impacts
on
State
and
local
government
entities
in
order
to
provide
information
on
the
effects
of
the
proposed
rule
on
such
entities.
The
analysis
is
available
in
the
docket
for
the
proposed
rule.

2.
Consultation
With
Government
Officials
The
Unfunded
Mandates
Act
requires
that
we
describe
the
extent
of
the
Agency's
prior
consultation
with
affected
State,
local,
and
tribal
officials,
summarize
the
officials'
comments
or
concerns,
and
summarize
our
response
to
those
comments
or
concerns.
In
addition,
section
203
of
the
UMRA
requires
that
we
develop
a
plan
for
informing
and
advising
small
governments
that
may
be
significantly
or
uniquely
impacted
by
a
proposal.
Although
the
proposed
rule
does
not
significantly
affect
any
State,
local,
or
tribal
governments,
we
have
consulted
with
State
and
local
air
pollution
control
officials.
We
also
have
held
meetings
on
the
proposed
rule
with
many
of
the
stakeholders
from
numerous
individual
companies,
environmental
groups,
consultants
and
vendors,
labor
unions,
and
other
interested
parties.
We
have
added
materials
to
the
Air
docket
to
document
those
meetings.
In
addition,
we
have
determined
that
the
proposed
rule
contains
no
regulatory
requirements
that
might
significantly
or
uniquely
affect
small
governments.
Therefore,
today's
proposed
rule
is
not
subject
to
the
requirements
of
section
203
of
the
UMRA.

G.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.
The
RFA
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedure
Act
or
any
other
statute
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
purposes
of
assessing
the
impacts
of
today's
proposed
rule
on
small
entities,
small
entity
is
defined
as:
(
1)
A
small
business
whose
parent
company
has
fewer
than
100
or
1,000
employees,
depending
on
size
definition
for
the
affected
North
American
Industry
Classification
System
(
NAICS)
code,
or
fewer
than
4
billion
kW­
hr
per
year
of
electricity
usage;
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not­
forprofit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
It
should
be
noted
that
small
entities
in
6
NAICS
codes
are
affected
by
the
proposed
rule,
and
the
small
business
definition
applied
to
each
industry
by
NAICS
code
is
that
listed
in
the
Small
Business
Administration
(
SBA)
size
standards
(
13
CFR
121).
After
considering
the
economic
impacts
of
today's
proposed
rule
on
small
entities,
I
certify
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
This
certification
is
based
upon
(
1)
examining
the
impacts
to
small
entities
based
on
the
existing
combustion
turbines
inventory,
and
presuming
that
the
existing
mix
of
combustion
turbines
among
industries
is
a
good
approximation
of
the
mix
of
turbines
that
will
be
installed
and
affected
by
the
proposed
rule
up
to
2005,
and
(
2)
considering
influences
on
the
decision
by
small
entities
to
install
new
turbines.
We
have
determined,
based
on
the
existing
combustion
turbines
inventory,
that
29
small
entities
out
of
300
in
the
industries
impacted
by
the
proposed
rule
may
be
affected.
None
of
these
small
entities
will
incur
control
costs
associated
with
the
proposed
rule,
but
will
incur
monitoring,
recordkeeping,
and
reporting
costs
and
the
costs
of
performance
testing.
These
29
small
entities
own
51
affected
turbines
in
the
existing
combustion
turbines
inventory,
which
represents
only
2.5
percent
of
the
existing
turbines
overall.
Of
these
entities,
22
of
these
entities
are
small
communities
and
7
are
affected
small
firms.
None
of
the
29
affected
small
entities
are
estimated
to
have
compliance
costs
that
exceed
onehalf
of
1
percent
of
their
revenues.
The
median
compliance
costs
to
affected
small
entities
is
only
0.07
percent
of
sales.
In
addition,
the
proposed
rule
is
likely
to
also
increase
profits
at
the
many
small
firms
and
increase
revenues
for
the
many
small
communities
using
combustion
turbines
that
are
not
affected
by
the
rule
as
a
result
of
the
very
slight
increase
in
market
prices.
Thus,
we
conclude
that
the
proposed
rule
will
not
have
a
significant
impact
on
a
substantial
number
of
small
entities.
It
should
be
noted
that
it
is
likely
that
the
ongoing
deregulation
of
the
electric
power
industry
across
the
nation
should
minimize
the
proposed
rule's
impacts
on
small
entities.
Increased
competition
in
the
electric
power
industry
is
forecasted
to
decrease
the
market
price
for
wholesale
electric
power.
Open
access
to
the
grid
and
lower
market
prices
for
electricity
will
make
it
less
attractive
for
local
communities
to
purchase
and
operate
new
combustion
turbines.
For
more
information
on
the
results
of
the
analysis
of
small
entity
impacts,
please
refer
to
the
economic
impact
analysis
in
the
docket.
Although
the
proposed
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities,
EPA
nonetheless
has
tried
to
reduce
the
impact
of
the
rule
on
small
entities.
In
the
proposed
rule,
the
Agency
is
applying
the
minimum
level
of
control
and
the
minimum
level
of
monitoring,
recordkeeping,
and
reporting
to
affected
sources
allowed
by
the
Clean
Air
Act.
In
addition,
as
mentioned
earlier
in
the
preamble,
new
turbines
with
capacities
under
1.0
MW
are
not
covered
by
the
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Vol.
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9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
proposed
rule.
This
provision
should
reduce
the
level
of
small
entity
impacts.
We
continue
to
be
interested
in
the
potential
impacts
of
the
proposed
rule
on
small
entities
and
welcome
comments
on
issues
related
to
such
impacts.

H.
Paperwork
Reduction
Act
The
information
collection
requirements
in
the
proposed
rule
will
be
submitted
for
approval
to
the
Office
of
Management
and
Budget
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
An
Information
Collection
Request
(
ICR)
document
has
been
prepared
(
ICR
No.
1967.01)
and
a
copy
may
be
obtained
from
Susan
Auby
by
mail
at
the
Collection
Strategies
Division,
U.
S.
Environmental
Protection
Agency
(
2822),
1200
Pennsylvania
Avenue
NW,
Washington,
DC
20460,
by
e­
mail
at
auby.
susan@
epa.
gov,
or
by
calling
(
202)
566
 
1672.
A
copy
may
also
be
downloaded
off
the
internet
at
http:/
/
www.
epa.
gov/
icr.
The
information
requirements
are
based
on
notification,
recordkeeping,
and
reporting
requirements
in
the
NESHAP
General
Provisions
(
40
CFR
part
63,
subpart
A),
which
are
mandatory
for
all
operators
subject
to
national
emission
standards.
These
recordkeeping
and
reporting
requirements
are
specifically
authorized
by
section
114
of
the
CAA
(
42
U.
S.
C.
7414).
All
information
submitted
to
EPA
pursuant
to
the
recordkeeping
and
reporting
requirements
for
which
a
claim
of
confidentiality
is
made
is
safeguarded
according
to
Agency
policies
set
forth
in
40
CFR
part
2,
subpart
B.
The
proposed
rule
would
require
maintenance
inspections
of
the
control
devices
but
would
not
require
any
notifications
or
reports
beyond
those
required
by
the
General
Provisions.
The
recordkeeping
requirements
require
only
the
specific
information
needed
to
determine
compliance.
The
annual
monitoring,
reporting,
and
recordkeeping
burden
for
this
collection
(
averaged
over
the
first
3
years
after
the
effective
date
of
the
standards)
is
estimated
to
be
8,458
labor
hours
per
year
at
a
total
annual
cost
of
$
2.4
million.
This
estimate
includes
a
onetime
performance
test,
semiannual
excess
emission
reports,
maintenance
inspections,
notifications,
and
recordkeeping.
Total
capital/
startup
costs
associated
with
the
monitoring
requirements
over
the
3­
year
period
of
the
ICR
are
estimated
at
$
515,262,
with
operation
and
maintenance
costs
of
$
21,047
per
year.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
Agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
our
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
Comments
are
requested
on
the
Agency's
need
for
this
information,
the
accuracy
of
the
provided
burden
estimates,
and
any
suggested
methods
for
minimizing
respondent
burden,
including
through
the
use
of
automated
collection
techniques.
Send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division,
U.
S.
Environmental
Protection
Agency
(
2822),
1200
Pennsylvania
Ave.,
NW,
Washington,
DC
20460;
and
to
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
725
17th
St.,
NW,
Washington,
DC
20503,
marked
Attention:
Desk
Officer
for
EPA.
Include
the
ICR
number
in
any
correspondence.
Since
OMB
is
required
to
make
a
decision
concerning
the
ICR
between
30
and
60
days
after
January
14,
2003,
a
comment
to
OMB
is
best
assured
of
having
its
full
effect
if
OMB
receives
it
by
February
13,
2003.
The
final
rule
will
respond
to
any
OMB
or
public
comments
on
the
information
collection
requirements
contained
in
this
proposal.

I.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
(
NTTAA)
of
1995
(
Public
Law
No.
104
 
113;
15
U.
S.
C.
272
note)
directs
EPA
to
use
voluntary
consensus
standards
in
their
regulatory
and
procurement
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(
e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
business
practices)
developed
or
adopted
by
one
or
more
voluntary
consensus
bodies.
The
NTTAA
directs
us
to
provide
Congress,
through
annual
reports
to
the
Office
of
Management
and
Budget
(
OMB),
with
explanations
when
an
agency
does
not
use
available
and
applicable
voluntary
consensus
standards.
The
proposed
rulemaking
involves
technical
standards.
We
propose
in
the
rule
to
use
EPA
Methods
1,
1A,
3A,
3B,
4
of
40
CFR
part
60,
appendix
A;
Method
320
of
40
CFR
part
63,
appendix
A;
Method
323
of
40
CFR
part
63,
appendix
A;
Performance
Specification
(
PS)
3,
PS
4A
of
40
CFR
part
60,
appendix
B;
EPA
SW
 
846
Method
0011;
and
ARB
Method
430,
California
Environmental
Protection
Agency,
Air
Resources
Board,
2020
L
Street,
Sacramento,
CA
95812.
Consistent
with
the
NTTAA,
we
conducted
searches
to
identify
voluntary
consensus
standards
in
addition
to
these
EPA
methods.
No
applicable
voluntary
consensus
standards
were
identified
for
EPA
Methods
1A,
3B
of
40
CFR
part
60,
appendix
A;
PS
3,
PS
4
of
40
CFR
part
60,
appendix
B;
and
ARB
Method
430,
California
Environmental
Protection
Agency,
Air
Resources
Board,
2020
L
Street,
Sacramento,
CA
95812.
The
search
and
review
results
have
been
documented
and
are
placed
in
the
docket
for
the
proposed
rule.
This
search
for
emission
measurement
procedures
identified
nine
voluntary
consensus
standards.
We
determined
that
six
of
these
nine
standards
were
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
the
proposed
rulemaking.
Therefore,
we
do
not
propose
to
adopt
these
standards
today.
The
reasons
for
this
determination
for
the
six
methods
are
discussed
below.
Two
of
the
six
voluntary
consensus
standards
are
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
the
proposed
rulemaking
because
they
are
too
general,
too
broad,
or
not
sufficiently
detailed
to
assure
compliance
with
EPA
regulatory
requirements:
ASTM
E337
 
84
(
Reapproved
1996),
``
Standard
Test
Method
for
Measuring
Humidity
with
a
Psychrometer
(
the
Measurement
of
Wet­
and
Dry­
Bulb
Temperatures),''
for
EPA
Method
4;
and
CAN/
CSA
Z223.2
 
M86(
1986),
``
Method
for
the
Continuous
Measurement
of
Oxygen,
Carbon
Dioxide,
Carbon
Monoxide,
Sulphur
Dioxide,
and
Oxides
of
Nitrogen
in
Enclosed
Combustion
Flue
Gas
Streams,''
for
EPA
Method
3A
of
40
CFR
part
60,
appendix
A.
Four
of
the
six
voluntary
consensus
standards
are
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
the
proposed
rulemaking
because
they
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14,
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/
Proposed
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lacked
sufficient
quality
assurance
and
quality
control
requirements
necessary
for
EPA
compliance
assurance
requirements:
ASTM
D3154
 
91,
``
Standard
Method
for
Average
Velocity
in
a
Duct
(
Pitot
Tube
Method),''
for
EPA
Methods
1,
2,
2C,
3,
3B,
and
4
of
40
CFR
part
60,
appendix
A;
ASTM
D5835
 
95,
``
Standard
Practice
for
Sampling
Stationary
Source
Emissions
for
Automated
Determination
of
Gas
Concentration,''
for
EPA
Method
3A
of
40
part
60,
appendix
A;
ISO
10396:
1993,
``
Stationary
Source
Emissions:
Sampling
for
the
Automated
Determination
of
Gas
Concentrations,''
for
EPA
Method
3A
of
40
CFR
part
60,
appendix
A;
and
ISO
9096:
1992,
``
Determination
of
Concentration
and
Mass
Flow
Rate
of
Particulate
Matter
in
Gas
Carrying
Ducts
 
Manual
Gravimetric
Method,''
for
EPA
Method
5
of
40
CFR
part
60,
appendix
A.
The
following
three
of
the
nine
voluntary
consensus
standards
identified
in
this
search
were
not
available
at
the
time
the
review
was
conducted
for
the
purposes
of
the
proposed
rulemaking
because
they
are
under
development
by
a
voluntary
consensus
body:
ASME/
BSR
MFC
13M,
``
Flow
Measurement
by
Velocity
Traverse,''
for
EPA
Method
1
(
and
possibly
2)
of
40
CFR
part
60,
appendix
A;
ISO/
DIS
12039,
``
Stationary
Source
Emissions
 
Determination
of
Carbon
Monoxide,
Carbon
Dioxide,
and
Oxygen
 
Automated
Methods,''
for
EPA
Method
3A
of
40
CFR
part
60,
appendix
A;
and
ASTM
D6348
 
98,
``
Determination
of
Gaseous
Compounds
by
Extractive
Direct
Interface
Fourier
Transform
(
FTIR)
Spectroscopy,''
for
EPA
Method
320
of
40
CFR
part
63,
appendix
A.
While
we
are
not
proposing
to
include
these
three
voluntary
consensus
standards
in
today's
proposal,
we
will
consider
the
standards
when
final.
For
the
voluntary
consensus
standard,
ASTM
D6348
 
98,
Determination
of
Gaseous
Compounds
by
Extractive
Direct
Interface
Fourier
Transform
(
FTIR)
Spectroscopy,
we
have
submitted
comments
to
ASTM
regarding
EPA's
technical
evaluation
of
ASTM
D6348
 
98.
Currently,
the
ASTM
Subcommittee
D22
 
03
is
undertaking
a
revision
of
the
ASTM
standard
in
part
to
address
EPA's
comments.
Upon
successful
ASTM
balloting
and
demonstration
of
technical
equivalency
with
the
EPA's
FTIR
methods,
the
revised
ASTM
standard
could
be
incorporated
by
reference
into
the
proposed
rule
at
a
later
date.
We
are
taking
comment
on
the
compliance
demonstration
requirements
in
the
proposed
rulemaking
and
specifically
invite
the
public
to
identify
potentially­
applicable
voluntary
consensus
standards.
Commenters
should
also
explain
why
the
proposed
rule
should
adopt
these
voluntary
consensus
standards
in
lieu
of
or
in
addition
to
EPA's
standards.
Emission
test
methods
and
performance
specifications
submitted
for
evaluation
should
be
accompanied
with
a
basis
for
the
recommendation,
including
method
validation
data
and
the
procedure
used
to
validate
the
candidate
method
(
if
a
method
other
than
Method
301,
40
CFR
part
63,
Appendix
A,
was
used).
Tables
3
and
5
of
proposed
subpart
YYYY
list
the
EPA
testing
methods
and
performance
standards
included
in
the
proposed
rule.
Under
§
63.8
of
40
CFR
part
63,
subpart
A,
a
source
may
apply
to
EPA
for
permission
to
use
alternative
monitoring
in
place
of
any
of
the
EPA
testing
methods.

List
of
Subjects
in
40
CFR
Part
63
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Hazardous
substances,
Intergovernmental
relations,
Reporting
and
recordkeeping
requirements.

Dated:
November
26,
2002.
Christine
Todd
Whitman,
Administrator.

For
the
reasons
set
out
in
the
preamble,
title
40,
chapter
I,
part
63
of
the
Code
of
the
Federal
Regulations
is
proposed
to
be
amended
as
follows:

PART
63
 
[
AMENDED]

1.
The
authority
citation
for
part
63
continues
to
read
as
follows:

Authority:
42
U.
S.
C.
7401,
et
seq.

2.
Part
63
is
proposed
to
be
amended
by
adding
subpart
YYYY
to
read
as
follows:

Subpart
YYYY
 
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Stationary
Combustion
Turbines
What
This
Subpart
Covers
Sec.
63.6080
What
is
the
purpose
of
subpart
YYYY?
63.6085
Am
I
subject
to
this
subpart?
63.6090
What
parts
of
my
plant
does
this
subpart
cover?
63.6092
Are
duct
burners
and
waste
heat
recovery
units
covered
by
subpart
YYYY?
63.6095
When
do
I
have
to
comply
with
this
subpart?

Emission
and
Operating
Limitations
63.6100
Sea
What
emission
and
operating
limitations
must
I
meet?

General
Compliance
Requirements
63.6105
What
are
my
general
requirements
for
complying
with
this
subpart?
Testing
and
Initial
Compliance
Requirements
63.6110
By
what
date
must
I
conduct
the
initial
performance
tests
or
other
initial
compliance
demonstrations?
63.6115
When
must
I
conduct
subsequent
performance
tests?
63.6120
What
performance
tests
and
other
procedures
must
I
use?
63.6125
What
are
my
monitor
installation,
operation,
and
maintenance
requirements?
63.6130
How
do
I
demonstrate
initial
compliance
with
the
emission
and
operating
limitations?

Continuous
Compliance
Requirements
63.6135
How
do
I
monitor
and
collect
data
to
demonstrate
continuous
compliance?
63.6140
How
do
I
demonstrate
continuous
compliance
with
the
emission
and
operating
limitations?

Notifications,
Reports,
and
Records
63.6145
What
notifications
must
I
submit
and
when?
63.6150
What
reports
must
I
submit
and
when?
63.6155
What
records
must
I
keep?
63.6160
In
what
form
and
how
long
must
I
keep
my
records?

Other
Requirements
and
Information
63.6165
What
parts
of
the
General
Provisions
apply
to
me?
63.6170
Who
implements
and
enforces
this
subpart?
63.6175
What
definitions
apply
to
this
subpart?

Tables
to
Subpart
YYYY
of
Part
63
Table
1
to
Subpart
YYYY
of
Part
63.
 
Emission
Limitations
Table
2
to
Subpart
YYYY
of
Part
63.
 
Operating
Limitations
Table
3
to
Subpart
YYYY
of
Part
63.
 
Requirements
for
Performance
Tests
and
Initial
Compliance
Demonstrations
Table
4
to
Subpart
YYYY
of
Part
63.
 
Initial
Compliance
with
Emission
Limitations
Table
5
to
Subpart
YYYY
of
Part
63.
 
Continuous
Compliance
with
Emission
Limitations
Table
6
to
Subpart
YYYY
of
Part
63.
 
Continuous
Compliance
with
Operating
Limitations
Table
7
to
Subpart
YYYY
of
Part
63.
 
Requirements
for
Reports
Table
8
to
Subpart
YYYY
of
Part
63.
 
Applicability
of
General
Provisions
to
Subpart
YYYY
What
This
Subpart
Covers
§
63.6080
What
is
the
purpose
of
subpart
YYYY?

Subpart
YYYY
establishes
national
emission
limitations
and
operating
limitations
for
hazardous
air
pollutants
(
HAP)
emissions
from
stationary
combustion
turbines
located
at
major
sources
of
HAP
emissions
and
requirements
to
demonstrate
initial
and
continuous
compliance
with
the
emission
and
operating
limitations.

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Proposed
Rules
§
63.6085
Am
I
Subject
to
This
Subpart?
You
are
subject
to
this
subpart
if
you
own
or
operate
a
stationary
combustion
turbine
located
at
a
major
source
of
HAP
emissions.
(
a)
A
stationary
combustion
turbine
is
one
that
is
not
self
propelled
or
intended
to
be
propelled
while
performing
its
function,
although
it
may
be
mounted
on
a
vehicle
for
portability
or
transportability.
Stationary
combustion
turbines
covered
by
this
subpart
include
simple
cycle
stationary
combustion
turbines,
regenerative/
recuperative
cycle
stationary
combustion
turbines,
cogeneration
cycle
stationary
combustion
turbines,
and
combined
cycle
stationary
combustion
turbines.
(
b)
A
major
source
of
HAP
emissions
is
a
plant
site
that
emits
or
has
the
potential
to
emit
any
single
HAP
at
a
rate
of
10
tons
(
9.07
megagrams)
or
more
per
year
or
any
combination
of
HAP
at
a
rate
of
25
tons
(
22.68
megagrams)
or
more
per
year,
except
that
for
oil
and
gas
production
facilities,
a
major
source
of
HAP
emissions
is
determined
for
each
surface
site.

§
63.6090
What
parts
of
my
plant
does
this
subpart
cover?
This
subpart
applies
to
each
affected
source.
(
a)
Affected
source.
An
affected
source
is
any
existing,
new,
or
reconstructed
stationary
combustion
turbine
located
at
a
major
source
of
HAP
emissions.
(
1)
Existing
stationary
combustion
turbine.
A
stationary
combustion
turbine
is
existing
if
you
commenced
construction
or
reconstruction
of
the
stationary
combustion
turbine
on
or
before
January
14,
2003.
A
change
in
ownership
of
an
existing
stationary
combustion
turbine
does
not
make
that
stationary
combustion
turbine
a
new
or
reconstructed
stationary
combustion
turbine.
(
2)
New
stationary
turbine.
A
stationary
combustion
turbine
is
new
if
you
commenced
construction
of
the
stationary
combustion
turbine
after
January
14,
2003.
(
3)
Reconstructed
stationary
turbine.
A
stationary
combustion
turbine
is
reconstructed
if
you
meet
the
definition
of
reconstruction
in
§
63.2
of
subpart
A
of
this
part
and
reconstruction
is
commenced
after
January
14,
2003.
(
b)
Exceptions.
(
1)
A
new
or
reconstructed
stationary
combustion
turbine
located
at
a
major
source
or
an
existing
lean
premix
stationary
combustion
turbine
located
at
a
major
source
which
meets
any
of
the
following
criteria
does
not
have
to
meet
the
requirements
of
this
subpart
and
of
subpart
A
of
this
part
except
for
the
initial
notification
requirements
of
§
63.6145(
d):
(
i)
The
stationary
combustion
turbine
is
an
emergency
stationary
combustion
turbine;
(
ii)
The
stationary
combustion
turbine
is
a
limited
use
stationary
combustion
turbine;
or
(
iii)
The
stationary
combustion
turbine
burns
landfill
gas
or
digester
gas
as
the
primary
fuel.
(
2)
An
existing,
new,
or
reconstructed
stationary
combustion
turbine
with
a
rated
peak
power
output
of
less
than
1.0
megawatt
(
MW)
at
International
Organization
for
Standardization
(
ISO)
standard
day
conditions,
which
is
located
at
a
major
source,
does
not
have
to
meet
the
requirements
of
this
subpart
and
of
subpart
A
of
this
part.
(
3)
Existing
diffusion
flame
stationary
combustion
turbines
do
not
have
to
meet
the
requirements
of
this
subpart
and
of
subpart
A
of
this
part.
(
4)
Combustion
turbine
engine
test
cells/
stands
do
not
have
to
meet
the
requirements
of
this
subpart
but
may
have
to
meet
the
requirements
of
subpart
A
of
this
part
if
subject
to
another
subpart.

§
63.6092
Are
duct
burners
and
waste
heat
recovery
units
covered
by
subpart
YYYY?

No,
duct
burners
and
waste
heat
recovery
units
are
considered
steam
generating
units
and
are
not
covered
under
this
subpart.

§
63.6095
When
do
I
have
to
comply
with
this
subpart?

(
a)
Affected
sources.
(
1)
If
you
start
up
your
new
or
reconstructed
stationary
combustion
turbine
before
[
DATE
THE
FINAL
RULE
IS
PUBLISHED
IN
THE
FEDERAL
REGISTER],
you
must
comply
with
the
emission
limitations
and
operating
limitations
in
this
subpart
no
later
than
[
DATE
THE
FINAL
RULE
IS
PUBLISHED
IN
THE
FEDERAL
REGISTER].
(
2)
If
you
start
up
your
new
or
reconstructed
stationary
combustion
turbine
after
[
DATE
THE
FINAL
RULE
IS
PUBLISHED
IN
THE
FEDERAL
REGISTER],
you
must
comply
with
the
emission
limitations
and
operating
limitations
in
this
subpart
upon
startup
of
your
affected
source.
(
3)
If
you
have
an
existing
stationary
combustion
turbine,
you
must
comply
with
the
emission
limitations
and
operating
limitations
in
this
subpart
no
later
than
3
years
after
[
DATE
THE
FINAL
RULE
IS
PUBLISHED
IN
THE
FEDERAL
REGISTER].
(
b)
Area
sources
that
become
major
sources.
If
your
new
or
reconstructed
stationary
combustion
turbine
is
an
area
source
that
increases
its
emissions
or
its
potential
to
emit
such
that
it
becomes
a
major
source
of
HAP,
it
must
be
in
compliance
with
this
subpart
when
it
becomes
a
major
source.
(
c)
You
must
meet
the
notification
requirements
in
§
63.6145
according
to
the
schedule
in
§
63.6145
and
in
40
CFR
part
63,
subpart
A.

Emission
and
Operating
Limitations
§
63.6100
What
emission
and
operating
limitations
must
I
meet?

For
each
stationary
combustion
turbine
with
a
rated
peak
power
output
of
1.0
MW
or
greater
at
ISO
standard
day
conditions
located
at
a
major
source,
which
is
not:
(
a)
An
emergency
stationary
combustion
turbine;
(
b)
A
stationary
combustion
turbine
burning
landfill
gas
or
digester
gas
as
its
primary
fuel;
(
c)
A
limited
use
stationary
combustion
turbine;
or
(
d)
An
existing
diffusion
flame
stationary
combustion
turbine;
you
must
comply
with
the
emission
limitations
and
operating
limitations
in
Table
1
and
Table
2
of
this
subpart.

General
Compliance
Requirements
§
63.6105
What
are
my
general
requirements
for
complying
with
this
subpart?

(
a)
You
must
be
in
compliance
with
the
emission
limitations
and
operating
limitations
which
apply
to
you
at
all
times
except
during
startup,
shutdown,
and
malfunctions.
(
b)
If
you
must
comply
with
emission
and
operating
limitations,
you
must
operate
and
maintain
your
stationary
combustion
turbine,
oxidation
catalyst
emission
control
device
or
other
air
pollution
control
equipment,
and
monitoring
equipment
in
a
manner
consistent
with
good
air
pollution
control
practices
for
minimizing
emissions
at
all
times
including
during
startup,
shutdown,
and
malfunction.

Testing
and
Initial
Compliance
Requirements
§
63.6110
By
what
date
must
I
conduct
the
initial
performance
tests
or
other
initial
compliance
demonstrations?

You
must
conduct
the
initial
performance
tests
or
other
initial
compliance
demonstrations
in
Table
4
of
this
subpart
that
apply
to
you
within
180
calendar
days
after
the
compliance
date
that
is
specified
for
your
stationary
combustion
turbine
in
§
63.6095
and
according
to
the
provisions
in
§
63.7(
a)(
2).

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2003
/
Proposed
Rules
§
63.6115
When
must
I
conduct
subsequent
performance
tests?
If
you
are
complying
with
the
formaldehyde
emission
concentration
limitation
and
your
stationary
combustion
turbine
is
lean
premix,
this
section
applies
to
you.
If
you
are
not
attaining
low
NOX
levels,
as
permitted
by
an
enforcement
agency,
or
if
there
are
not
permit
levels
and
you
are
not
attaining
low
NOX
levels
characteristic
of
lean
premix
combustion
(
e.
g.,
NOX
levels
guaranteed
by
the
manufacturer),
additional
performance
testing
may
be
required
by
the
enforcement
agency.

§
63.6120
What
performance
tests
and
other
procedures
must
I
use?
(
a)
You
must
conduct
each
performance
test
in
Table
3
of
this
subpart
that
applies
to
you.
(
b)
For
demonstrations
of
initial
compliance
with
the
emission
limitation
for
carbon
monoxide
(
CO)
reduction,
you
must
complete
the
actions
described
in
paragraphs
b(
1)
and
(
2)
of
this
section.
(
1)
Normalize
the
CO
concentrations
at
the
inlet
and
outlet
of
the
oxidation
catalyst
emission
control
device
to
a
dry
basis
and
to
15
percent
oxygen
or
an
equivalent
percent
carbon
dioxide
(
CO2).
(
2)
Calculate
the
percent
reduction
of
CO
using
the
following
equation
1
of
this
section:

C
C
C
R
Eq
i
o
i
 
×
=
100
.
1
Where:
Ci
=
CO
concentration
at
inlet
of
the
oxidation
catalyst
emission
control
device
Co
=
CO
concentration
at
the
outlet
of
the
oxidation
catalyst
emission
control
device
R
=
percent
reduction
in
CO
emissions.
(
3)
The
initial
demonstration
of
compliance
consists
of
the
first
4­
hour
average
percent
reduction
in
CO
recorded
after
completion
of
the
performance
evaluation
of
the
CEMS.
(
c)
Each
performance
test
must
be
conducted
according
to
the
requirements
of
the
General
Provisions
at
§
63.7(
e)(
1)
and
under
the
specific
conditions
in
Table
2
of
this
subpart.
(
d)
Do
not
conduct
performance
tests
or
compliance
evaluations
during
periods
of
startup,
shutdown,
or
malfunction.
(
e)
If
you
comply
with
the
emission
limit
for
formaldehyde
emission
concentration,
you
must
conduct
three
separate
test
runs
for
each
performance
test,
and
each
test
run
must
last
at
least
1
hour.
(
f)
If
you
comply
with
the
emission
limitation
for
formaldehyde
emission
concentration
and
your
stationary
combustion
turbine
is
not
diffusion
flame
or
lean
premix,
you
must
petition
the
Administrator
for
additional
operating
limitations
to
be
established
during
the
initial
performance
test
and
continuously
monitored
thereafter,
or
for
approval
of
no
additional
operating
limitations.
You
must
not
conduct
the
initial
performance
test
until
after
the
petition
has
been
approved
by
the
Administrator.
(
g)
If
you
comply
with
the
emission
limitation
for
formaldehyde
emission
concentration
and
your
stationary
combustion
turbine
is
not
diffusion
flame
or
lean
premix
and
you
petition
the
Administrator
for
approval
of
additional
operating
limitations,
your
petition
must
include
the
following
information
described
in
paragraphs
(
g)(
1)
through
(
5)
of
this
section.
(
1)
Identification
of
the
specific
parameters
you
propose
to
use
as
additional
operating
limitations;
(
2)
A
discussion
of
the
relationship
between
these
parameters
and
HAP
emissions,
identifying
how
HAP
emissions
change
with
changes
in
these
parameters
and
how
limitations
on
these
parameters
will
serve
to
limit
HAP
emissions;
(
3)
A
discussion
of
how
you
will
establish
the
upper
and/
or
lower
values
for
these
parameters
which
will
establish
the
limits
on
these
parameters
in
the
operating
limitations;
(
4)
A
discussion
identifying
the
methods
you
will
use
to
measure
and
the
instruments
you
will
use
to
monitor
these
parameters,
as
well
as
the
relative
accuracy
and
precision
of
these
methods
and
instruments;
and
(
5)
A
discussion
identifying
the
frequency
and
methods
for
recalibrating
the
instruments
you
will
use
for
monitoring
these
parameters.
(
h)
If
you
comply
with
the
emission
limitation
for
formaldehyde
emission
concentration
and
you
petition
the
Administrator
for
approval
of
no
additional
operating
limitations,
your
petition
must
include
the
information
described
in
paragraphs
(
h)(
1)
through
(
7)
of
this
section.
(
1)
Identification
of
the
parameters
associated
with
operation
of
the
stationary
combustion
turbine
and
any
emission
control
device
which
could
change
intentionally
(
e.
g,
operator
adjustment,
automatic
controller
adjustment,
etc.)
or
unintentionally
(
e.
g.,
wear
and
tear,
error,
etc.)
on
a
routine
basis
or
over
time;
(
2)
A
discussion
of
the
relationship,
if
any,
between
changes
in
the
parameters
and
changes
in
HAP
emissions;
(
3)
For
the
parameters
which
could
change
in
such
a
way
as
to
increase
HAP
emissions,
a
discussion
of
whether
establishing
limitations
on
the
parameters
would
serve
to
limit
HAP
emissions;
(
4)
For
the
parameters
which
could
change
in
such
a
way
as
to
increase
HAP
emissions,
a
discussion
of
how
you
could
establish
upper
and/
or
lower
values
for
the
parameters
which
would
establish
limits
on
the
parameters
in
operating
limitations;
(
5)
For
the
parameters,
a
discussion
identifying
the
methods
you
could
use
to
measure
them
and
the
instruments
you
could
use
to
monitor
them,
as
well
as
the
relative
accuracy
and
precision
of
the
methods
and
instruments;
(
6)
For
the
parameters,
a
discussion
identifying
the
frequency
and
methods
for
recalibrating
the
instruments
you
could
use
to
monitor
them;
and
(
7)
A
discussion
of
why,
from
your
point
of
view,
it
is
infeasible
or
unreasonable
to
adopt
the
parameters
as
operating
limitations.

§
63.6125
What
are
my
monitor
installation,
operation,
and
maintenance
requirements?

(
a)
If
you
comply
with
the
emission
limitation
for
CO
reduction,
you
must
install,
operate,
and
maintain
a
CEMS
to
monitor
CO
and
either
oxygen
or
CO2
at
both
the
inlet
and
outlet
of
the
oxidation
catalyst
emission
control
device
according
to
the
requirements
described
in
paragraphs
(
a)(
1)
through
(
4)
of
this
section.
(
1)
You
must
install,
operate,
and
maintain
each
CEMS
according
to
the
applicable
Performance
Specification
of
40
CFR
part
60,
appendix
B
(
PS
 
4A).
(
2)
You
must
conduct
a
performance
evaluation
of
each
CEMS
according
to
the
requirements
in
40
CFR
63.8
and
according
to
the
applicablePerformance
Specification
of
40
CFR
part
60,
appendix
B.
(
3)
As
specified
in
§
63.8(
c)(
4)(
ii),
each
CEMS
must
complete
a
minimum
of
one
cycle
of
operation
(
sampling,
analyzing,
and
data
recording)
for
each
consecutive
15­
minute
period.
You
must
have
at
least
two
data
points,
each
representing
a
different
15­
minute
period
within
the
same
hour
to
have
a
valid
hour
of
data.
(
4)
Continuous
emission
monitoring
system
data
must
be
reduced
as
specified
in
§
63.8(
g)(
2)
and
recorded
in
parts
per
million
(
ppm)
CO
at
15
percent
oxygen
or
equivalent
CO2
concentration.
(
b)
If
you
have
monitors
that
are
subject
to
paragraph
(
a)
of
this
section,
you
must
properly
maintain
and
operate
the
monitors
continuously
according
to
the
requirements
described
in
paragraphs
(
b)(
1)
and
(
2)
of
this
section.

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1916
Federal
Register
/
Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
(
1)
Proper
maintenance.
You
must
maintain
the
monitoring
equipment
at
all
times
that
the
turbine
is
operating,
including
but
not
limited
to,
maintaining
necessary
parts
for
routine
repairs
of
the
monitoring
equipment.
(
2)
Continued
operation.
You
must
conduct
all
monitoring
in
continuous
operation
at
all
times
that
the
combustion
turbine
is
operating,
except
for,
as
applicable,
monitoring
malfunctions,
associated
repairs,
and
required
quality
assurance
or
control
activities
(
including,
as
applicable,
calibration
checks
and
required
zero
and
span
adjustments).
Data
recorded
during
monitoring
malfunctions,
associated
repairs,
out­
of­
control
periods,
and
required
quality
assurance
or
control
activities
shall
not
be
used
for
purposes
of
calculating
data
averages.
You
must
use
all
of
the
data
collected
from
all
other
periods
in
assessing
compliance.
A
monitoring
malfunction
is
any
sudden,
infrequent,
not
reasonably
preventable
failure
of
the
monitoring
equipment
to
provide
valid
data.
Monitoring
failures
that
are
caused
in
part
by
poor
maintenance
or
careless
operation
are
not
malfunctions.
Any
period
for
which
the
monitoring
system
is
out­
of­
control
and
data
are
not
available
for
required
calculations
constitutes
a
deviation
from
the
monitoring
requirements.

§
63.6130
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations?
(
a)
You
must
demonstrate
initial
compliance
with
each
emission
and
operating
limitation
that
applies
to
you
according
to
Table
4
of
this
subpart.
(
b)
You
must
submit
the
Notification
of
Compliance
Status
containing
results
of
the
initial
compliance
demonstration
according
to
the
requirements
in
§
63.6145(
f).

Continuous
Compliance
Requirements
§
63.6135
How
do
I
monitor
and
collect
data
to
demonstrate
continuous
compliance?
(
a)
Except
for
monitor
malfunctions,
associated
repairs,
and
required
quality
assurance
or
quality
control
activities
(
including,
as
applicable,
calibration
checks
and
required
zero
and
span
adjustments
of
the
monitoring
system),
you
must
conduct
all
monitoring
in
continuous
operation
at
all
times
the
stationary
combustion
turbine
is
operating.
(
b)
Do
not
use
data
recorded
during
monitor
malfunctions,
associated
repairs,
and
required
quality
assurance
or
quality
control
activities
for
meeting
the
requirements
of
this
subpart,
including
data
averages
and
calculations.
You
must
use
all
the
data
collected
during
all
other
periods
in
assessing
the
performance
of
the
control
device
or
in
assessing
emissions
from
the
new
or
reconstructed
stationary
combustion
turbine.

§
63.6140
How
do
I
demonstrate
continuous
compliance
with
the
emission
and
operating
limitations?

(
a)
You
must
demonstrate
continuous
compliance
with
each
emission
limitation
and
operating
limitation
in
Table
1
and
Table
2
of
this
subpart
according
to
methods
specified
in
Table
5
and
Table
6
of
this
subpart.
(
b)
You
must
report
each
instance
in
which
you
did
not
meet
each
emission
limitation
or
operating
limitation.
You
must
also
report
each
instance
in
which
you
did
not
meet
the
requirements
in
Table
8
of
this
subpart
that
apply
to
you.
These
instances
are
deviations
from
the
emission
and
operating
limitations
in
this
subpart.
These
deviations
must
be
reported
according
to
the
requirements
in
§
63.6150.
(
c)
Consistent
with
§
§
63.6(
e)
and
63.7(
e)(
1),
deviations
that
occur
during
a
period
of
startup,
shutdown,
and
malfunction
are
not
violations.

Notifications,
Reports,
and
Records
§
63.6145
What
notifications
must
I
submit
and
when?

(
a)
You
must
submit
all
of
the
notifications
in
§
§
63.7(
b)
and
(
c),
63.8(
e),
63.8(
f)(
4)
and
(
6),
and
63.9(
b)
and
(
h)
that
apply
to
you
by
the
dates
specified.
(
b)
As
specified
in
§
63.9(
b)(
2),
if
you
start
up
your
combustion
turbine
before
[
DATE
THE
FINAL
RULE
IS
PUBLISHED
IN
THE
FEDERAL
REGISTER],
you
must
submit
an
Initial
Notification
not
later
than
120
calendar
days
after
[
DATE
THE
FINAL
RULE
IS
PUBLISHED
IN
THE
FEDERAL
REGISTER].
(
c)
As
specified
in
§
63.9(
b),
if
you
start
up
your
new
or
reconstructed
stationary
combustion
turbine
on
or
after
[
DATE
THE
FINAL
RULE
IS
PUBLISHED
IN
THE
FEDERAL
REGISTER],
you
must
submit
an
Initial
Notification
not
later
than
120
calendar
days
after
you
become
subject
to
this
subpart.
(
d)
If
you
are
required
to
submit
an
Initial
Notification
but
are
otherwise
not
affected
by
the
requirements
of
this
subpart,
in
accordance
with
§
63.6090(
b),
your
notification
should
include
the
information
in
§
63.9(
b)(
2)(
i)
through
(
v)
and
a
statement
that
your
new
or
reconstructed
stationary
combustion
turbine
has
no
additional
requirements
and
explain
the
basis
of
the
exclusion
(
for
example,
that
it
operates
exclusively
as
an
emergency
stationary
combustion
turbine).
(
e)
If
you
are
required
to
conduct
an
initial
performance
test,
you
must
submit
a
notification
of
intent
to
conduct
an
initial
performance
test
at
least
60
calendar
days
before
the
initial
performance
test
is
scheduled
to
begin
as
required
in
§
63.7(
b)(
1).
(
f)
If
you
are
required
to
comply
with
either
the
emission
limitation
for
CO
reduction
or
the
emission
limitation
for
formaldehyde
emission
concentration,
you
must
submit
a
Notification
of
Compliance
Status
according
to
§
63.9(
h)(
2)(
ii).
(
1)
For
each
initial
compliance
demonstration
with
the
emission
limitation
for
CO
reduction,
you
must
submit
the
Notification
of
Compliance
Status
before
the
close
of
business
on
the
30th
calendar
day
following
the
completion
of
the
initial
compliance
demonstration.
(
2)
For
each
performance
test
required
to
demonstrate
compliance
with
the
emission
limitation
for
formaldehyde
emission
concentration,
you
must
submit
the
Notification
of
Compliance
Status,
including
the
performance
test
results,
before
the
close
of
business
on
the
60th
calendar
day
following
the
completion
of
the
performance
test.

§
63.6150
What
reports
must
I
submit
and
when?
(
a)
Any
one
who
owns
or
operates
a
new
or
reconstructed
stationary
combustion
turbine
which
must
meet
the
emission
limitation
for
CO
reduction
must
submit
a
semiannual
compliance
report
according
to
Table
7
of
this
subpart
by
the
date
specified
in
paragraphs
(
a)(
1)
through
(
5)
of
this
section
unless
the
Administrator
has
approved
a
different
schedule,
according
to
the
information
described
in
paragraphs
(
a)(
1)
through
(
5)
of
this
section.
(
1)
The
first
semiannual
compliance
report
must
cover
the
period
beginning
on
the
compliance
date
specified
in
§
63.6095
and
ending
on
June
30
or
December
31,
whichever
date
is
the
first
date
following
the
end
of
the
first
calendar
half
after
the
compliance
date
specified
in
§
63.6095.
(
2)
The
first
semiannual
compliance
report
must
be
postmarked
or
delivered
no
later
than
July
31
or
January
31,
whichever
date
follows
the
end
of
the
first
calendar
half
after
the
compliance
date
that
is
specified
in
§
63.6095.
(
3)
Each
subsequent
semiannual
compliance
report
must
cover
the
semiannual
reporting
period
from
January
1
through
June
30
or
the
semiannual
reporting
period
from
July
1
through
December
31.

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/
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No.
9
/
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January
14,
2003
/
Proposed
Rules
(
4)
Each
subsequent
semiannual
compliance
report
must
be
postmarked
or
delivered
no
later
than
July
31
or
January
31,
whichever
date
is
the
first
date
following
the
end
of
the
semiannual
reporting
period.
(
5)
For
each
new
or
reconstructed
stationary
combustion
turbine
that
is
subject
to
permitting
regulations
pursuant
to
40
CFR
part
70
or
71,
and
if
the
permitting
authority
has
established
the
date
for
submitting
semiannual
reports
pursuant
to
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A),
you
may
submit
the
first
and
subsequent
compliance
reports
according
to
the
dates
the
permitting
authority
has
established
instead
of
according
to
the
dates
in
paragraphs
(
a)(
1)
through
(
4)
of
this
section.
(
b)
The
semiannual
compliance
report
must
contain
the
information
described
in
paragraphs
(
b)(
1)
through
(
4)
of
this
section.
(
1)
Company
name
and
address.
(
2)
Statement
by
a
responsible
official,
with
that
official's
name,
title,
and
signature,
certifying
the
accuracy
of
the
content
of
the
report.
(
3)
Date
of
report
and
beginning
and
ending
dates
of
the
reporting
period.
(
4)
If
there
is
no
deviation
from
any
emission
limitation
that
applies
to
you,
a
statement
that
there
was
no
deviation
from
the
emission
limitations
during
the
reporting
period
and
that
no
CEMS
was
inoperative,
inactive,
malfunctioning,
out
of
control,
repaired,
or
adjusted.
(
c)
For
each
deviation
from
an
emission
limitation
that
occurs
where
you
are
not
using
a
CEMS
to
comply
with
the
emission
limitations
in
this
subpart,
the
compliance
report
must
contain
the
information
in
paragraphs
(
b)(
1)
through
(
3)
of
this
section
and
the
information
contained
in
paragraphs
(
c)(
1)
through
(
3)
of
this
section.
(
1)
The
total
operating
time
of
each
new
or
reconstructed
combustion
turbine
during
the
reporting
period.
(
2)
Information
on
the
number,
duration,
and
cause
of
deviations
(
including
unknown
cause,
if
applicable),
as
applicable,
and
the
corrective
action
taken.
(
3)
Information
on
the
number,
duration,
and
cause
for
monitor
downtime
incidents
(
including
unknown
cause,
if
applicable,
other
than
downtime
associated
with
zero
and
span
and
other
daily
calibration
checks).
(
d)
For
each
deviation
from
an
emission
limitation
occurring
where
you
are
using
a
CEMS
to
comply
with
an
emission
limitation,
you
must
include
the
information
in
paragraphs
(
c)(
1)
through
(
3)
of
this
section
and
the
information
included
in
paragraphs
(
d)(
1)
through
(
11)
of
this
section.
(
1)
The
date
and
time
that
each
deviation
started
and
stopped.
(
2)
The
date
and
time
that
each
CEMS
was
inoperative
except
for
zero
(
lowlevel
and
high­
level
checks.
(
3)
The
date
and
time
that
each
CEMS
was
out­
of­
control
including
the
information
in
§
63.8(
c)(
8).
(
4)
The
date
and
time
that
each
deviation
started
and
stopped,
and
whether
each
deviation
occurred
during
a
period
of
startup,
shutdown
or
malfunction
or
during
another
period.
(
5)
A
summary
of
the
total
duration
of
the
deviation
during
the
reporting
period
(
recorded
in
4­
hour
periods),
and
the
total
duration
as
a
percent
of
the
total
operating
time
during
that
reporting
period.
(
6)
A
breakdown
of
the
total
duration
of
the
deviations
during
the
reporting
period
into
those
that
are
due
to
control
equipment
problems,
process
problems,
other
known
causes,
and
other
unknown
causes.
(
7)
A
summary
of
the
total
duration
of
CEMS
downtime
during
the
reporting
period
(
reported
in
4­
hour
periods),
and
the
total
duration
of
CEMS
downtime
as
a
percent
of
the
total
turbine
operating
time
during
that
reporting
period.
(
8)
A
breakdown
of
the
total
duration
of
CEMS
downtime
during
the
reporting
period
into
periods
that
are
due
to
monitoring
equipment
malfunctions,
non­
monitoring
equipment
malfunctions,
quality
assurance/
quality
control
calibrations,
other
known
causes
and
other
unknown
causes.
(
9)
The
monitoring
equipment
manufacturer(
s)
and
model
number(
s)
of
each
monitor.
(
10)
The
date
of
the
latest
CEMS
certification
or
audit.
(
11)
A
description
of
any
changes
in
CEMS
or
controls
since
the
last
reporting
period.

§
63.6155
What
records
must
I
keep?

(
a)
You
must
keep
the
records
as
described
in
paragraphs
(
a)(
1)
through
(
5)
of
this
section.
(
1)
A
copy
of
each
notification
and
report
that
you
submitted
to
comply
with
this
subpart,
including
all
documentation
supporting
any
Initial
Notification
or
Notification
of
Compliance
Status
that
you
submitted,
according
to
the
requirements
in
§
63.10(
b)(
2)(
xiv).
(
2)
Records
of
performance
tests
and
performance
evaluations
as
required
in
§
63.10(
b)(
2)(
viii).
(
3)
Records
of
the
occurrence
and
duration
of
each
startup,
shutdown,
or
malfunction
as
required
in
§
63.10(
b)(
2)(
i).
(
4)
Records
of
the
occurrence
and
duration
of
each
malfunction
of
the
air
pollution
control
equipment,
if
applicable,
as
required
in
§
63.10(
b)(
2)(
ii).
(
5)
Records
of
all
maintenance
on
the
air
pollution
control
equipment
as
required
in
§
63.10(
b)(
iii).
(
b)
For
each
CEMS,
you
must
keep
the
records
as
described
in
paragraphs
(
b)(
1)
through
(
3)
of
this
section.
(
1)
Records
described
in
§
63.10(
b)(
2)(
vi)
through
(
xi).
(
2)
Previous
(
i.
e.,
superceded)
versions
of
the
performance
evaluation
plan
as
required
in
§
63.8(
d)(
3).
(
3)
Request
for
alternatives
to
the
relative
accuracy
test
for
CEMS
as
required
in
§
63.8(
f)(
6)(
i),
if
applicable.
(
c)
You
must
keep
the
records
required
in
Tables
5
and
6
of
this
subpart
to
show
continuous
compliance
with
each
emission
limitation
and
operating
limitation
that
applies
to
you.

§
63.6160
In
what
form
and
how
long
must
I
keep
my
records?

(
a)
You
must
maintain
all
applicable
records
in
such
a
manner
that
they
can
be
readily
accessed
and
are
suitable
for
inspection
according
to
§
63.10(
b)(
1).
(
b)
As
specified
in
§
63.10(
b)(
1),
you
must
keep
each
record
for
5
years
following
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record.
(
c)
You
must
retain
your
records
of
the
most
recent
2
years
on
site
or
your
records
must
be
accessible
on
site.
Your
records
of
the
remaining
3
years
may
be
retained
off
site.

Other
Requirements
and
Information
§
63.6165
What
parts
of
the
General
Provisions
apply
to
me?

Table
8
of
this
subpart
shows
which
parts
of
the
General
Provisions
in
§
63.1
through
13
apply
to
you.

§
63.6170
Who
implements
and
enforces
this
subpart?

(
a)
This
subpart
is
implemented
and
enforced
by
the
U.
S.
EPA
or
a
delegated
authority
such
as
your
State,
local,
or
tribal
agency.
If
the
EPA
Administrator
has
delegated
authority
to
your
State,
local,
or
tribal
agency,
then
that
agency
(
as
well
as
the
U.
S.
EPA)
has
the
authority
to
implement
and
enforce
this
subpart.
You
should
contact
your
EPA
Regional
Office
to
find
out
whether
this
subpart
is
delegated
to
your
State,
local,
or
tribal
agency.
(
b)
In
delegating
implementation
and
enforcement
authority
of
this
subpart
to
a
State,
local,
or
tribal
agency
under
section
40
CFR
part
63,
subpart
E,
the
authorities
contained
in
paragraph
(
c)
of
this
section
are
retained
by
the
EPA
Administrator
and
are
not
transferred
to
the
State,
local,
or
tribal
agency.

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Federal
Register
/
Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
(
c)
The
authorities
that
will
not
be
delegated
to
State,
local,
or
tribal
agencies
are:
(
1)
Approval
of
alternatives
to
the
emission
limitations
or
operating
limitations
in
§
63.6100
under
§
63.6(
g).
(
2)
Approval
of
major
alternatives
to
test
methods
under
§
63.7(
e)(
2)(
ii)
and
(
f)
and
as
defined
in
§
63.90.
(
3)
Approval
of
major
alternatives
to
monitoring
under
§
63.8(
f)
and
as
defined
in
§
63.90.
(
4)
Approval
of
major
alternatives
to
recordkeeping
and
reporting
under
§
63.10(
f)
and
as
defined
in
§
63.90.

§
63.6175
What
definitions
apply
to
this
subpart?
Terms
used
in
this
subpart
are
defined
in
the
CAA;
in
40
CFR
63.2,
the
General
Provisions
of
this
part;
and
in
this
section:
Area
source
means
any
stationary
source
of
HAP
that
is
not
a
major
source
as
defined
in
this
part.
Associated
equipment
as
used
in
this
subpart
and
as
referred
to
in
section
112(
n)(
4)
of
the
CAA,
means
equipment
associated
with
an
oil
or
natural
gas
exploration
or
production
well,
and
includes
all
equipment
from
the
well
bore
to
the
point
of
custody
transfer,
except
glycol
dehydration
units,
storage
vessels
with
potential
for
flash
emissions,
combustion
turbines,
and
stationary
reciprocating
internal
combustion
engines.
CAA
means
the
Clean
Air
Act
(
42
U.
S.
C.
7401
et
seq.,
as
amended
by
Public
Law
101
 
549,
104
Stat.
2399).
Cogeneration
cycle
stationary
combustion
turbine
means
any
stationary
combustion
turbine
that
recovers
heat
from
the
stationary
combustion
turbine
exhaust
gases
using
an
exhaust
heat
exchanger,
such
as
a
heat
recovery
steam
generator.
Combined
cycle
stationary
combustion
turbine
means
any
stationary
combustion
turbine
that
recovers
heat
from
the
stationary
combustion
turbine
exhaust
gases
using
an
exhaust
heat
exchanger
to
generate
steam
for
use
in
a
steam
turbine.
Combustion
turbine
engine
test
cells/
stands
means
engine
test
cells/
stands,
as
defined
in
subpart
PPPPP
of
this
part,
that
test
stationary
combustion
turbines.
Custody
transfer
means
the
transfer
of
hydrocarbon
liquids
or
natural
gas:
after
processing
and/
or
treatment
in
the
producing
operations,
or
from
storage
vessels
or
automatic
transfer
facilities
or
other
such
equipment,
including
product
loading
racks,
to
pipelines
or
any
other
forms
of
transportation.
For
the
purposes
of
this
subpart,
the
point
at
which
such
liquids
or
natural
gas
enters
a
natural
gas
processing
plant
is
a
point
of
custody
transfer.
Deviation
means
any
instance
in
which
an
affected
source
subject
to
this
subpart,
or
an
owner
or
operator
of
such
a
source:
(
1)
Fails
to
meet
any
requirement
or
obligation
established
by
this
subpart,
including
but
not
limited
to
any
emission
limitation
or
operating
limitation;
(
2)
Fails
to
meet
any
term
or
condition
that
is
adopted
to
implement
an
applicable
requirement
in
this
subpart
and
that
is
included
in
the
operating
permit
for
any
affected
source
required
to
obtain
such
a
permit;
or
(
3)
Fails
to
meet
any
emission
limitation
or
operating
limitation
in
this
subpart
during
malfunction,
regardless
or
whether
or
not
such
failure
is
permitted
by
this
subpart.
Diffusion
flame
stationary
combustion
turbine
means
any
stationary
combustion
turbine
where
fuel
and
air
are
injected
at
the
combustor
and
are
mixed
only
by
diffusion
prior
to
ignition.
Digester
gas
means
any
gaseous
byproduct
of
wastewater
treatment
formed
through
the
anaerobic
decomposition
of
organic
waste
materials
and
composed
principally
of
methane
and
CO2.
Emergency
stationary
combustion
turbine
means
any
stationary
combustion
turbine
that
operates
as
a
mechanical
or
electrical
power
source
when
the
primary
source
of
power
is
interrupted
by
an
emergency
situation.
Examples
include
stationary
combustion
turbines
used
to
produce
power
for
critical
networks
or
equipment
when
electric
power
from
the
local
utility
is
interrupted,
or
stationary
combustion
turbines
used
to
pump
water
in
the
case
of
fire
or
flood,
etc.
Emergency
stationary
combustion
turbines
do
not
include
stationary
combustion
turbines
used
as
peaking
units
at
electric
utilities
or
stationary
combustion
turbines
at
industrial
facilities
that
typically
operate
at
low
capacity
factors.
Hazardous
air
pollutant
(
HAP)
means
any
air
pollutant
listed
in
or
pursuant
to
section
112(
b)
of
the
CAA.
ISO
standard
day
conditions
means
288
degrees
Kelvin
(
15
°
C),
60
percent
relative
humidity
and
101.3
kilopascals
pressure.
Landfill
gas
means
a
gaseous
byproduct
of
the
land
application
of
municipal
refuse
formed
through
the
anaerobic
decomposition
of
waste
materials
and
composed
principally
of
methane
and
CO2.
Lean
premix
stationary
combustion
turbine
means
any
stationary
combustion
turbine
where
the
air
and
fuel
are
thoroughly
mixed
to
form
a
lean
mixture
before
delivery
to
the
combustor.
Limited
use
stationary
combustion
turbine
means
any
stationary
combustion
turbine
which
is
operated
50
hours
or
less
per
calendar
year.
Major
Source,
as
used
in
this
subpart,
shall
have
the
same
meaning
as
in
§
63.2,
except
that:
(
1)
Emissions
from
any
oil
or
gas
exploration
or
production
well
(
with
its
associated
equipment
(
as
defined
in
this
section))
and
emissions
from
any
pipeline
compressor
station
or
pump
station
shall
not
be
aggregated
with
emissions
from
other
similar
units,
to
determine
whether
such
emission
points
or
stations
are
major
sources,
even
when
emission
points
are
in
a
contiguous
area
or
under
common
control
except
when
they
are
on
the
same
surface
site;
(
2)
For
oil
and
gas
production
facilities,
emissions
from
processes,
operations,
or
equipment
that
are
not
part
of
the
same
oil
and
gas
production
facility,
as
defined
in
this
section,
shall
not
be
aggregated;
and
(
3)
For
production
field
facilities,
only
HAP
emissions
from
glycol
dehydration
units,
storage
tanks
with
flash
emissions
potential,
combustion
turbines
and
reciprocating
internal
combustion
engines
shall
be
aggregated
for
a
major
source
determination.
Malfunction
means
any
sudden,
infrequent,
and
not
reasonably
preventable
failure
of
air
pollution
control
equipment,
process
equipment,
or
a
process
to
operate
in
a
normal
or
usual
manner.
Failures
that
are
caused
in
part
by
poor
maintenance
or
careless
operation
are
not
malfunctions.
Oil
and
gas
production
facility
as
used
in
this
subpart
means
any
grouping
of
equipment
where
hydrocarbon
liquids
are
processed,
upgraded
(
i.
e.,
remove
impurities
or
other
constituents
to
meet
contract
specifications),
or
stored
prior
to
the
point
of
custody
transfer;
or
where
natural
gas
is
processed,
upgraded,
or
stored
prior
to
entering
the
natural
gas
transmission
and
storage
source
category.
For
purposes
of
a
major
source
determination,
facility
(
including
a
building,
structure,
or
installation)
means
oil
and
natural
gas
production
and
processing
equipment
that
is
located
within
the
boundaries
of
an
individual
surface
site
as
defined
in
this
section.
Equipment
that
is
part
of
a
facility
will
typically
be
located
within
close
proximity
to
other
equipment
located
at
the
same
facility.
Pieces
of
production
equipment
or
groupings
of
equipment
located
on
different
oil
and
gas
leases,
mineral
fee
tracts,
lease
tracts,
subsurface
or
surface
unit
areas,

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surface
fee
tracts,
surface
lease
tracts,
or
separate
surface
sites,
whether
or
not
connected
by
a
road,
waterway,
power
line
or
pipeline,
shall
not
be
considered
part
of
the
same
facility.
Examples
of
facilities
in
the
oil
and
natural
gas
production
source
category
include,
but
are
not
limited
to,
well
sites,
satellite
tank
batteries,
central
tank
batteries,
a
compressor
station
that
transports
natural
gas
to
a
natural
gas
processing
plant,
and
natural
gas
processing
plants.
Oxidation
catalyst
emission
control
device
means
an
emission
control
device
that
incorporates
catalytic
oxidation
to
reduce
CO
emissions.
Potential
to
emit
means
the
maximum
capacity
of
a
stationary
source
to
emit
a
pollutant
under
its
physical
and
operational
design.
Any
physical
or
operational
limitation
on
the
capacity
of
the
stationary
source
to
emit
a
pollutant,
including
air
pollution
control
equipment
and
restrictions
on
hours
of
operation
or
on
the
type
or
amount
of
material
combusted,
stored,
or
processed,
shall
be
treated
as
part
of
its
design
if
the
limitation
or
the
effect
it
would
have
on
emissions
is
federally
enforceable.
Production
field
facility
means
those
oil
and
gas
production
facilities
located
prior
to
the
point
of
custody
transfer.
Regenerative/
recuperative
cycle
stationary
combustion
turbine
means
any
stationary
combustion
turbine
that
recovers
heat
from
the
stationary
combustion
turbine
exhaust
gases
using
an
exhaust
heat
exchanger
to
preheat
the
combustion
air
entering
the
combustion
chamber
of
the
stationary
combustion
turbine.
Simple
cycle
stationary
combustion
turbine
means
any
stationary
combustion
turbine
that
does
not
recover
heat
from
the
stationary
combustion
turbine
exhaust
gases.
Surface
site
means
any
combination
of
one
or
more
graded
pad
sites,
gravel
pad
sites,
foundations,
platforms,
or
the
immediate
physical
location
upon
which
equipment
is
physically
affixed.

Tables
to
Subpart
YYYY
of
Part
63
As
stated
in
§
§
63.6100
and
63.6140,
you
must
comply
with
the
following
emission
limitations:

TABLE
1
TO
SUBPART
YYYY
OF
PART
63.
 
EMISSION
LIMITATIONS
For
.
.
.
You
must
meet
one
of
the
following
emission
limitations
.
.
.

1.
each
stationary
combustion
turbine
described
in
§
63.6100
a.
achieve
a
reduction
in
CO
of
95
percent
or
greater,
measured
before
and
after
an
oxidation
catalyst
emission
control
device
is
installed
to
treat
all
of
the
stationary
combustion
turbine
exhaust
gases,
if
you
install
an
oxidation
catalyst
emission
control
device
or
b.
limit
the
concentration
of
formaldehyde
to
43
ppbvd
or
less
at
15
percent
O2,
if
you
do
not
install
an
oxidation
catalyst
emission
control
device.

As
stated
in
§
§
63.6100
and
63.6140,
you
must
comply
with
the
following
operating
limitations:

TABLE
2
TO
SUBPART
YYYY
OF
PART
63.
 
OPERATING
LIMITATIONS
For
.
.
.
You
must
.
.
.

1.
Each
stationary
combustion
turbine
complying
with
the
emission
limitation
for
CO
reduction.
Meet
no
operating
limitations.

2.
Each
stationary
combustion
turbine
complying
with
the
emission
limitation
for
formaldehyde
emission
concentration
that
is
diffusion
flame
or
lean
premix.
Meet
no
operating
limitations.

3.
Each
stationary
combustion
turbine
complying
with
the
emission
limitation
for
formaldehyde
emission
concentration
that
is
not
diffusion
flame
or
lean
premix.
You
must
comply
with
any
additional
operating
limitations
approved
by
the
Administrator.

As
stated
in
§
63.6120,
you
must
comply
with
the
following
requirements
for
performance
tests
and
initial
compliance
demonstrations:

TABLE
3
OF
SUBPART
YYYY
OF
PART
63.
 
REQUIREMENTS
FOR
PERFORMANCE
TESTS
AND
INITIAL
COMPLIANCE
DEMONSTRATIONS
For
each
stationary
combustion
turbine
complying
with
.
.
.
You
must
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.

1.
The
emission
limitation
for
CO
reduction
Demonstrate
a
reduction
in
CO
of
95
percent
or
more.
A
CEMS
for
CO
and
either
O2
or
CO2
to
monitor
at
both
the
inlet
and
outlet
of
the
oxidation
catalyst
emission
control
device.
This
demonstration
is
conducted
immediately
following
a
successful
performance
evaluation
of
the
CEMS
as
required
in
§
63.6125(
a).
The
demonstration
consists
of
the
first
4­
hour
average
of
measurements.
The
reduction
in
CO
is
calculated
using
the
equation
in
§
63.6120
and
must
be
normalized
to
15
percent
O2
or
equivalent
percent
CO2.

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14,
2003
/
Proposed
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TABLE
3
OF
SUBPART
YYYY
OF
PART
63.
 
REQUIREMENTS
FOR
PERFORMANCE
TESTS
AND
INITIAL
COMPLIANCE
DEMONSTRATIONS
 
Continued
For
each
stationary
combustion
turbine
complying
with
.
.
.
You
must
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.

2.
The
emission
limitation
for
formaldehyde
emission
concentration.
a.
Demonstrate
formaldehyde
emissions
are
43
ppbvd
or
less
by
a
performance
test
and.
i.
Test
Method
320
of
40
CFR
part
63,
appendix
A;
or
EPA
SW
 
846
Method
0011;
or
California
Environmental
Protection
Agency,
Air
Resources
Board,
Method
430*
formaldehyde
and
acetaldehyde
in
emissions
from
stationary
sources,
adopted
Sept
12,
1989,
amended
December
13,
1991
(
ARB
Method
430)*;
or
if
your
affected
source
fires
natural
gas,
Test
Method
323
of
40
CFR
part
63,
appendix
A;
or
other
methods
approved
by
the
Administrator.
(
1)
Formaldehyde
concentration
must
be
corrected
to
15
percent
O2,
dry
basis.
Results
of
this
test
consist
of
the
average
of
the
three
1
hour
runs.

b.
Select
the
sampling
port
location
and
the
number
of
traverse
points
and.
i.
Method
1
or
1A
of
40
CFR
part
60,
appendix
A
§
63.7(
d)(
1)(
i).
(
1)
If
using
an
air
pollution
control
device
the
sampling
site
must
be
located
at
the
outlet
of
the
air
pollution
control
device.
c.
Determine
the
O2
concentration
at
the
sampling
port
location.
i.
Method
3A
or
3B
of
40
CFR
part
60,
appendix
A.
(
1)
Measurements
to
determine
O2
concentration
must
be
made
at
the
same
time
as
the
performance
test.

*
You
may
obtain
a
copy
of
ARB
Method
430
from
the
California
Environmental
Protection
Agency,
Air
Resources
Board,
2020
L
Street,
Sacramento,
CA
95812,
or
you
may
download
a
copy
of
ARB
Method
430
from
ARB's
web
site
(
http://
www.
arb.
ca.
gov/
testmeth/
vol3/
vol3.
htm).

As
stated
in
§
§
63.6110
and
63.6130,
you
must
comply
with
the
following
requirements
to
demonstrate
initial
compliance
with
emission
limitations:

TABLE
4
TO
SUBPART
YYYY
OF
PART
63.
 
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
For
the
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.

1.
Emission
limitation
for
CO
reduction
....................................................................
The
average
reduction
of
CO
emissions
is
at
least
95
percent
dry
basis.

2.
Emission
limitation
for
formaldehyde
....................................................................
The
average
formaldehyde
concentration
is
43
ppbvd
or
less
at
15
percent
O2.

As
stated
in
§
§
63.6135
and
63.6140,
you
must
comply
with
the
following
requirements
to
demonstrate
continuing
compliance
with
emissions
limitations:

TABLE
5
OF
SUBPART
YYYY
OF
PART
63.
 
CONTINUOUS
COMPLIANCE
WITH
EMISSION
LIMITATIONS
For
the
.
.
.
You
must
demonstrate
continous
compliance
by
.
.
.

1.
Emission
limitation
for
CO
reduction
..............
a.
Collecting
the
CEMS
data
according
to
§
63.6125(
a),
reducing
the
measurements
to
1­
hour
averages,
calculating
the
percent
reduction
in
CO
emissions
according
to
§
63.6120;
and
b.
Demonstrating
a
reduction
in
CO
of
95
percent
or
more
over
each
4­
hour
averaging
period;
and
c.
Applying
40
CFR
part
60
appendix
F,
procedure
1.

As
stated
in
§
§
63.6135
and
63.6140,
you
must
comply
with
the
following
requirements
to
demonstrate
continuing
compliance
with
operating
limitations:

TABLE
6
OF
SUBPART
YYYY
OF
PART
63.
 
CONTINUOUS
COMPLIANCE
WITH
OPERATING
LIMITATIONS
For
the
emission
limitation
.
.
.
For
the
operating
limitation
.
.
.
You
must
demonstrate
continuous
compliance
by
.
.
.

For
formaldehyde
...............................................
To
comply
with
operating
limitations
approved
by
the
Administrator.
Collect
the
data
according
to
§
63.6120(
g)
and
maintain
the
operating
parameters
within
the
operating
limits.

As
stated
in
§
§
63.6145
and
63.6150,
you
must
comply
with
the
following
requirements
for
reports:

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TABLE
7
OF
SUBPART
YYYY
OF
PART
63.
 
REQUIREMENTS
FOR
REPORTS
If
you
own
or
operate
a
stationary
combustion
turbine
which
must
comply
with
the
CO
emission
reduction
limitation,
you
must
submit
a
.
.
.

Semiannual
compliance
report
If
there
is
no
deviation
from
any
emission
limitation
or
operating
limitation,
a
statement
that
you
have
had
no
deviation
from
the
emission
limitation
or
operating
limitation
during
the
reporting
period
and
that
no
CEMS
or
CPMS
was
inoperative,
inactive,
out­
of­
control,
repaired,
or
adjusted.
If
you
had
a
deviation
from
any
emission
limitation
or
operating
limitation
during
the
reporting
period,
the
report
must
contain
the
information
in
§
63.6150(
d)
or
(
e),
as
applicable.
Semiannually,
according
to
the
requirements
in
$
63,6150.

You
must
comply
with
the
applicable
General
Provisions
requirements:

TABLE
8
OF
SUBPART
YYYY
OF
PART
63.
 
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
YYYY
Citation
Subject
Applies
to
subpart
YYYY
Explanation
§
63.1(
a)(
1)
..................
General
applicability
of
the
General
Provisions
Yes
.............................
Additional
terms
defined
in
§
63.6175.

§
63.1(
a)(
2)
 
(
4)
............
Yes..

§
63.1(
a)(
5)
..................
[
Reserved].

§
63.1(
a)(
6)
 
(
7)
............
Contact
for
source
category
information;
extension
of
compliance
through
early
reduction
Yes.

§
63.1(
a)(
8)
..................
.........................................................................
No
...............................
Refers
to
State
programs.

§
63.1(
a)(
9)
..................
[
Reserved].

§
63.1(
a)(
10)
 
(
14)
........
.........................................................................
Yes..

§
63.1(
b)(
1)
..................
Initial
applicability
............................................
Yes
.............................
Subpart
YYYY
clarifies
applicability
at
§
63.6085.

§
63.1(
b)(
2)
..................
Title
V
operating
permit­
reference
to
part
70
Yes
.............................
All
major
affected
sources
are
required
to
obtain
a
title
V
permit.

§
63.1(
b)(
3)
..................
Record
of
applicability
determination
..............
Yes.

§
63.1(
c)(
1)
..................
Applicability
after
standards
are
set
...............
Yes
.............................
Subpart
YYYY
clarifies
the
applicability
of
each
paragraph
of
subpart
A
to
sources
subject
to
subpart
YYYY.

§
63.1(
c)(
2)
..................
Title
V
permit
requirement
for
sources
...........
No
...............................
Area
sources
are
not
subject
to
area
subpart
YYYY.

§
63.1(
c)(
3)
..................
[
Reserved].

§
63.1(
c)(
4)
..................
Extension
of
compliance
for
existing
sources
Yes.

§
63.1(
c)(
5)
..................
Notification
requirements
for
an
area
source
becoming
a
major
source.
Yes
§
63.1(
d)
.......................
[
Reserved].

§
63.1(
e)
.......................
Applicability
of
permit
program
before
a
relevant
standard
has
been
set.
Yes.

§
63.2
...........................
Definitions
.......................................................
Yes
.............................
Additional
terms
defined
in
§
63.6175.

§
63.3
...........................
Units
and
abbreviations
..................................
Yes.

§
63.4
...........................
Prohibited
activities
.........................................
Yes.

§
63.5(
a)
.......................
Construction
and
reconstruction
applicability
Yes.

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/
Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
TABLE
8
OF
SUBPART
YYYY
OF
PART
63.
 
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
YYYY
 
Continued
Citation
Subject
Applies
to
subpart
YYYY
Explanation
§
63.5(
b)(
1)
..................
Requirements
upon
construction
or
reconstruction
Yes.

§
63.5(
b)(
2)
..................
[
Reserved].

§
63.5(
b)(
3)
..................
Approval
of
construction
.................................
Yes.

§
63.5(
b)(
4)
..................
Notification
of
construction
..............................
Yes.

§
63.5(
b)(
5)
..................
Compliance
.....................................................
Yes.

§
63.5(
b)(
6)
..................
Addition
of
equipment
.....................................
Yes.

§
63.5(
c)
.......................
[
Reserved].

§
63.5(
d)
.......................
Application
for
construction
reconstruction
.....
Yes.

§
63.5(
e)
.......................
Approval
of
construction
or
reconstruction
.....
Yes.

§
63.5(
f)
........................
Approval
of
construction
or
reconstruction
based
on
prior
State
review.
Yes.

§
63.6(
a)
.......................
Applicability
.....................................................
Yes.

§
63.6(
b)(
1)
 
(
2)
............
Compliance
dates
for
new
and
reconstructed
sources.
Yes.

§
63.6(
b)(
3)
..................
Compliance
dates
for
sources
constructed
or
reconstructed
before
effective
date.
No
...............................
Compliance
is
required
by
startup
or
effective
date.

§
63.6(
b)(
4)
..................
Compliance
dates
for
sources
also
subject
to
§
112(
f)
standards.
Yes.

§
63.6(
b)(
5)
..................
Notification
......................................................
Yes.

§
63.6(
b)(
6)
..................
[
Reserved].

§
63.6(
b)(
7)
..................
Compliance
dates
for
new
and
reconstructed
area
sources
that
become
major.
Yes.

§
63.6(
c)(
1)
 
(
2)
............
Compliance
dates
for
existing
sources
...........
Yes.

§
63.6(
c)(
3)
 
(
4)
............
[
Reserved].

§
63.6(
c)(
5)
..................
Compliance
dates
for
existing
area
sources
that
become
major.
Yes.

§
63.6(
d)
.......................
[
Reserved].

§
63.6(
e)(
1)
 
(
2)
............
Operation
and
maintenance
...........................
Yes
.............................
Except
that
you
are
not
required
to
have
a
startup,
shutdown,
and
malfunction
plan
(
SSMP).

§
63.6(
e)(
3)
..................
SSMP
..............................................................
No.

§
63.6(
f)(
1)
...................
Applicability
of
standards
except
during
startup
shutdown,
or
malfunction
(
SSM).
Yes.

§
63.6(
f)(
2)
...................
Methods
for
determining
compliance
..............
Yes.

§
63.6(
f)(
3)
...................
Finding
of
compliance
.....................................
Yes.

§
63.6(
g)(
1)
 
(
3)
............
Use
of
alternative
standard
.............................
Yes.

§
63.6(
h)
.......................
Opacity
and
visible
emission
standards
.........
No
...............................
Subpart
YYYY
does
not
contain
opacity
or
visible
emission
standards.

§
63.6(
i)
........................
Compliance
extension
procedures
and
criteria
Yes.

§
63.6(
j)
........................
Presidential
compliance
exemption
................
Yes.

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No.
9
/
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January
14,
2003
/
Proposed
Rules
TABLE
8
OF
SUBPART
YYYY
OF
PART
63.
 
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
YYYY
 
Continued
Citation
Subject
Applies
to
subpart
YYYY
Explanation
§
63.7(
a)(
1)
 
(
2)
............
Performance
test
dates
...................................
Yes
.............................
Subpart
YYYY
contains
performance
test
dates
at
§
63.6110.

§
63.7(
a)(
3)
..................
Section
114
authority
......................................
Yes.

§
63.7(
b)(
1)
..................
Notification
of
performance
test
......................
Yes.

§
63.7(
b)(
2)
..................
Notification
of
rescheduling
.............................
Yes.

§
63.7(
c)
.......................
Quality
assurance/
test
plan
............................
Yes.

§
63.7(
d)
.......................
Testing
facilities
..............................................
Yes.

§
63.7(
e)(
1)
..................
Conditions
for
conducting
performance
tests
Yes.

§
63.7(
e)(
2)
..................
Conduct
of
performance
tests
and
reduction
of
data.
Yes
.............................
Subpart
YYYY
specifies
test
methods
at
§
63.6120.

§
63.7(
e)(
3)
..................
Test
run
duration
.............................................
Yes.

§
63.7(
e)(
4)
..................
Administrator
may
require
other
testing
under
section
114
of
the
CAA.
Yes.

§
63.7(
f)
........................
Alternative
test
method
provisions
..................
Yes.

§
63.7(
g)
.......................
Performance
test
data
analysis,
recordkeeping
and
reporting.
Yes.

§
63.7(
h)
.......................
Waiver
of
tests
................................................
Yes.

§
63.8(
a)(
1)
..................
Applicability
of
monitoring
requirements
.........
Yes
.............................
Subpart
YYYY
contains
specific
requirements
for
monitoring
at
§
63.6125.

§
63.8(
a)(
2)
..................
Performance
specifications
.............................
Yes.

§
63.8(
a)(
3)
..................
[
Reserved].

§
63.8(
a)(
4)
..................
Monitoring
with
flares
......................................
No.

§
63.8(
b)(
1)
..................
Monitoring
.......................................................
Yes.

§
63.8(
b)(
2)
 
(
3)
............
Multiple
effluents
and
multiple
monitoring
systems
Yes.

§
63.8(
c)(
1)
..................
Monitoring
system
operation
and
maintenance

§
63.8(
c)(
1)(
i)
...............
Routine
and
predictable
SSM
.........................
No
...............................
Subpart
YYYY
does
not
require
SSMP.

§
63.8(
c)(
1)(
ii)
..............
SSM
not
in
SSMP
...........................................
No
...............................
Subpart
YYYY
does
not
require
SSMP.

§
63.8(
c)(
1)(
iii)
..............
Compliance
with
operation
and
maintenance
requirements.
Yes.

§
63.8(
c)(
2)
 
(
3)
............
Monitoring
system
installation
.........................
Yes.

§
63.8(
c)(
4)
..................
Continuous
monitoring
system
(
CMS)
requirements
Yes
.............................
Except
that
subpart
YYYY
does
not
require
continuous
opacity
monitoring
systems
(
COMS).

§
63.8(
c)(
5)
..................
COMS
minimum
procedures
..........................
No.

§
63.8(
c)(
6)
 
(
8)
............
CMS
requirements
..........................................
Yes
.............................
Except
that
subpart
YYYY
does
not
require
COMS.

§
63.8(
d)
.......................
CMS
quality
control
.........................................
Yes.

§
63.8(
e)
.......................
CMS
performance
evaluation
.........................
Yes
.............................
Except
for
§
63.8(
e)(
5)(
ii),
which
applies
to
COMS.

§
63.8(
f)(
1)
 
(
5)
.............
Alternative
monitoring
method
........................
Yes.

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/
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68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
TABLE
8
OF
SUBPART
YYYY
OF
PART
63.
 
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
YYYY
 
Continued
Citation
Subject
Applies
to
subpart
YYYY
Explanation
§
63.8(
f)(
6)
...................
Alternative
to
relative
accuracy
test
................
Yes.

§
63.8(
g)
.......................
Data
reduction
.................................................
Yes
.............................
Except
that
provisions
for
COMS
are
not
applicable
Averaging
periods
for
demonstrating
compliance
are
specified
at
§
§
63.6135
and
63.6140.

§
63.9(
a)
.......................
Applicability
and
State
delegation
of
notification
requirements.
Yes.

§
63.9(
b)(
1)
 
(
5)
............
Initial
notifications
............................................
Yes.

§
63.9(
c)
.......................
Request
for
compliance
extension
.................
No
...............................
Compliance
extensions
do
not
apply
to
new
or
reconstructed
sources.

§
63.9(
d)
.......................
Notification
of
special
compliance
requirements
for
new
sources.
Yes.

§
63.9(
e)
.......................
Notification
of
performance
test
......................
Yes.

§
63.9(
f)
........................
Notification
of
visible
emissions/
opacity
test
..
No.

§
63.9(
g)(
1)
..................
Notification
of
performance
evaluation
...........
Yes.

§
63.9(
g)(
2)
..................
Notification
of
use
of
COMS
data
...................
No
...............................
Subpart
YYYY
does
not
contain
opacity
or
VE
standards.

§
63.9(
g)(
3)
..................
Notification
that
criterion
for
alternative
to
relative
accuracy
test
audit
(
RATA)
is
exceeded
Yes
.............................
If
alternative
is
in
use.

§
63.9(
h)(
1)
 
(
6)
............
Notification
of
compliance
status
....................
Yes
.............................
Except
that
notifications
for
sources
not
conducting
performance
tests
are
due
30
days
after
completion
of
performance
evaluations

§
63.9(
i)
........................
Adjustment
of
submittal
deadlines
..................
Yes.

§
63.9(
j)
........................
Change
in
previous
information
......................
Yes.

§
63.10(
a)
.....................
Administrative
provisions
for
recordkeeping
and
reporting.
Yes.

§
63.10(
b)(
1)
................
Record
retention
.............................................
Yes.

§
63.10(
b)(
2)(
i)
 
(
iii)
......
Records
related
to
SSM
.................................
Yes.

§
63.10(
b)(
2)(
iv)
 
(
v)
.....
Records
related
to
actions
during
SSM
..........
No
...............................
Subpart
YYYY
does
not
require
SSMP
so
requirements
to
demonstrate
conformance
or
nonconformance
with
SSMP
are
not
applicable

§
63.10(
b)(
2)(
vi)
 
(
xi)
....
CMS
records
...................................................
Yes.

§
63.10(
b)(
2)(
xii)
..........
Record
when
under
waiver
.............................
Yes.

§
63.10(
b)(
2)(
xiii)
..........
Records
when
using
alternative
to
RATA
......
Yes
.............................
For
CO
standard
if
using
RATA
alternative.

§
63.10(
b)(
2)(
xiv)
.........
Records
of
supporting
documentation
............
Yes.

§
63.10(
b)(
3)
................
Records
of
applicability
determination
............
Yes.

§
63.10(
c)(
1)
................
Additional
records
for
sources
using
CEMS
...
Yes.

§
63.10(
d)(
1)
................
General
reporting
requirements
......................
Yes.

§
63.10(
d)(
2)
................
Report
of
performance
test
results
.................
Yes.

§
63.10(
d)(
3)
................
Reporting
opacity
or
VE
observations
............
No
...............................
Subpart
YYYY
does
not
contain
opacity
or
VE
standards.

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Federal
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/
Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
TABLE
8
OF
SUBPART
YYYY
OF
PART
63.
 
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
YYYY
 
Continued
Citation
Subject
Applies
to
subpart
YYYY
Explanation
§
63.10(
d)(
4)
................
Progress
reports
.............................................
No
...............................
Compliance
extensions
do
not
apply
to
new
or
reconstructed
sources.

§
63.10(
d)(
5)
................
Startup,
shutdown,
and
malfunction
reports
...
No
...............................
Subpart
YYYY
does
not
require
reporting
of
startup,
shutdowns,
or
malfunctions.

§
63.10(
e)(
1)
and
(
2)(
i)
Additional
CMS
reports
...................................
Yes.

§
63.10(
e)(
2)(
ii)
............
COMS­
related
report
.......................................
No
...............................
Subpart
YYYY
does
not
require
COMS.

§
63.10(
e)(
3)
................
Excess
emissions
and
parameter
exceedances
reports.
Yes.

§
63.10(
e)(
4)
................
Reporting
COMS
data
....................................
No
...............................
Subpart
YYYY
does
not
require
COMS.

§
63.10(
f)
......................
Waiver
for
recordkeeping
and
reporting
.........
Yes.

§
63.11
.........................
Flares
..............................................................
No.

§
63.12
.........................
State
authority
and
delegations
......................
Yes.

§
63.13
.........................
Addresses
.......................................................
Yes.

§
63.14
.........................
Incorporation
by
reference
..............................
Yes.

§
63.15
.........................
Availability
of
information
................................
Yes.

3.
Appendix
A
to
Part
63
is
proposed
to
be
amended
by
adding,
in
numerical
order,
Method
323
to
read
as
follows:

Appendix
A
to
Part
63
 
Test
Methods
*
*
*
*
*

Method
323
 
Measurement
of
Formaldehyde
Emissions
from
Natural
Gas­
Fired
Stationary
Sources
 
Acetyl
Acetone
Derivitization
Method
1.0
Introduction
This
method
describes
the
sampling
and
analysis
procedures
of
the
acetyl
acetone
colorimetric
method
for
measuring
formaldehyde
emissions
in
the
exhaust
of
natural
gas­
fired,
stationary
combustion
sources.
This
method,
which
was
prepared
by
the
Gas
Research
Institute
(
GRI),
is
based
on
the
Chilled
Impinger
Train
Method
for
Methanol,
Acetone,
Acetaldehyde,
Methyl
Ethyl
Ketone,
and
Formaldehyde
(
Technical
Bulletin
No.
684)
developed
and
published
by
the
National
Council
of
the
Paper
Industry
for
Air
and
Stream
Improvement,
Inc.
(
NCASI).
1
However,
this
method
has
been
prepared
specifically
for
formaldehyde
and
does
not
include
specifications
(
e.
g.,
equipment
and
supplies)
and
procedures
(
e.
g.,
sampling
and
analytical)
for
methanol,
acetone,
acetaldehyde,
and
methyl
ethyl
ketone.
To
obtain
reliable
results,
persons
using
this
method
should
have
a
thorough
knowledge
of
at
least
Methods
1,
2,
3,
and
4
of
40
CFR
part
60,
appendix
A.

1.1
Scope
and
Application
1.1.1
Analytes.
The
only
analyte
measured
by
this
method
is
formaldehyde
(
CAS
Number
50
 
00
 
0).
1.1.2
Applicability.
This
method
is
for
analyzing
formaldehyde
emissions
from
uncontrolled
and
controlled
natural
gas­
fired,
stationary
combustion
sources.
1.1.3
Data
Quality
Objectives.
If
you
adhere
to
the
quality
control
and
quality
assurance
requirements
of
this
method,
then
you
and
future
users
of
your
data
will
be
able
to
assess
the
quality
of
the
data
you
obtain
and
estimate
the
uncertainty
in
the
measurements.

2.0
Summary
of
Method
An
emission
sample
from
the
combustion
exhaust
is
drawn
through
a
midget
impinger
train
containing
chilled
reagent
water
to
absorb
formaldehyde.
The
formaldehyde
concentration
in
the
impinger
is
determined
by
reaction
with
acetyl
acetone
to
form
a
colored
derivative
which
is
measured
colorimetrically.

3.0
Definitions
[
Reserved]

4.0
Interferences
The
presence
of
acetaldehyde,
amines,
polymers
of
formaldehyde,
periodate,
and
sulfites
can
cause
interferences
with
the
acetyl
acetone
procedure
which
is
used
to
determine
the
formaldehyde
concentration.
However,
based
on
experience
gained
from
extensive
testing
of
natural
gas­
fired
combustion
sources
using
FTIR
to
measure
a
variety
of
compounds,
GRI
expects
only
acetaldehyde
to
be
potentially
present
when
combusting
natural
gas.
Acetaldehyde
has
been
reported
to
be
a
significant
interferent
only
when
present
at
concentrations
above
50
ppm.
4
However,
GRI
reports
that
the
concentration
of
acetaldehyde
from
gas­
fired
sources
is
very
low
(
typically
below
the
FTIR
detection
limit
of
around
0.5
ppmv);
therefore,
the
potential
positive
bias
due
to
acetaldehyde
interference
is
expected
to
be
negligible.
5.0
Safety
5.1
Prior
to
applying
the
method
in
the
field,
a
site­
specific
Health
and
Safety
Plan
should
be
prepared.
General
safety
precautions
include
the
use
of
steel­
toed
boots,
safety
glasses,
hard
hats,
and
work
gloves.
In
certain
cases,
facility
policy
may
require
the
use
of
fire­
resistant
clothing
while
on­
site.
Since
the
method
involves
testing
at
high­
temperature
sampling
locations,
precautions
must
be
taken
to
limit
the
potential
for
exposure
to
high­
temperature
gases
and
surfaces
while
inserting
or
removing
the
sample
probe.
In
warm
locations,
precautions
must
also
be
taken
to
avoid
dehydration.
5.2
Potential
chemical
hazards
associated
with
sampling
include
formaldehyde,
nitrogen
oxides
(
NOX),
and
carbon
monoxide
(
CO).
Formalin
solution,
used
for
field
spiking,
is
an
aqueous
solution
containing
formaldehyde
and
methanol.
Formaldehyde
is
a
skin,
eye,
and
respiratory
irritant
and
a
carcinogen,
and
should
be
handled
accordingly.
Eye
and
skin
contact
and
inhalation
of
formaldehyde
vapors
should
be
avoided.
Natural
gas­
fired
combustion
sources
can
potentially
emit
CO
at
toxic
concentrations.
Care
should
be
taken
to
minimize
exposure
to
the
sample
gas
while
inserting
or
removing
the
sample
probe.
If
the
work
area
is
enclosed,
personal
CO
monitors
should
be
used
to
insure
that
the
concentration
of
CO
in
the
work
area
is
maintained
at
safe
levels.
5.3
Potential
chemical
hazards
associated
with
the
analytical
procedures
include
acetyl
acetone
and
glacial
acetic
acid.
Acetyl
acetone
is
an
irritant
to
the
skin
and
respiratory
system,
as
well
as
being
moderately
toxic.
Glacial
acetic
acid
is
highly
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FR\
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14JAP2.
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14JAP2
1926
Federal
Register
/
Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
corrosive
and
is
an
irritant
to
the
skin,
eyes,
and
respiratory
system.
Eye
and
skin
contact
and
inhalation
of
vapors
should
be
avoided.
Acetyl
acetone
and
glacial
acetic
acid
have
flash
points
of
41
°
C
(
105.8
°
F)
and
43
°
C
(
109.4
°
F),
respectively.
Exposure
to
heat
or
flame
should
be
avoided.

6.0
Equipment
and
Supplies
6.1
Sampling
Probe.
Quartz
glass
probe
with
stainless
steel
sheath
or
stainless
steel
probe.
6.2
Teflon
Tubing.
Teflon
tubing
to
connect
the
sample
probe
to
the
impinger
train.
A
heated
sample
line
is
not
needed
since
the
sample
transfer
system
is
rinsed
to
recover
condensed
formaldehyde
and
the
rinsate
combined
with
the
impinger
contents
prior
to
sample
analysis.
6.3
Midget
Impingers.
Three
midget
impingers
are
required
for
sample
collection.
The
first
impinger
serves
as
a
moisture
knockout,
the
second
impinger
contains
20
mL
of
reagent
water,
and
the
third
impinger
contains
silica
gel
to
remove
residual
moisture
from
the
sample
prior
to
the
dry
gas
meter.
6.4
Vacuum
Pump.
Vacuum
pump
capable
of
delivering
a
controlled
extraction
flow
rate
between
0.2
and
0.4
L/
min.
6.5
Flow
Measurement
Device.
A
rotameter
or
other
flow
measurement
device
to
indicate
consistent
sample
flow.
6.6
Dry
Gas
Meter.
A
dry
gas
meter
is
used
to
measure
the
total
sample
volume
collected.
The
dry
gas
meter
must
be
sufficiently
accurate
to
measure
the
sample
volume
to
within
2
percent,
calibrated
at
the
selected
flow
rate
and
conditions
actually
encountered
during
sampling,
and
equipped
with
a
temperature
sensor
(
dial
thermometer,
or
equivalent)
capable
of
measuring
temperature
accurately
to
within
3
°
C
(
5.4
°
F).
6.7
Spectrophotometer.
A
spectrophotometer
is
required
for
formaldehyde
analysis,
and
must
be
capable
of
measuring
absorbance
at
412
nm.

7.0
Reagents
and
Standards
7.1
Sampling
Reagents
7.1.1
Reagent
water.
Deionized,
distilled,
organic­
free
water.
This
water
is
used
as
the
capture
solution,
for
rinsing
the
sample
probe,
sample
line,
and
impingers
at
the
completion
of
the
sampling
run,
in
reagent
dilutions,
and
in
blanks.
7.1.2
Ice.
Ice
is
necessary
to
pack
around
the
impingers
during
sampling
in
order
to
keep
the
impingers
cold.
Ice
is
also
needed
for
sample
transport
and
storage.

7.2
Analysis
7.2.1
Acetyl
acetone
Reagent.
Prepare
the
acetyl
acetone
reagent
by
dissolving
15.4
g
of
ammonium
acetate
in
50
mL
of
reagent
water
in
a
100­
mL
volumetric
flask.
To
this
solution,
add
0.20
mL
of
acetyl
acetone
and
0.30
mL
of
glacial
acetic
acid.
Mix
the
solution
thoroughly,
then
dilute
to
100
mL
with
reagent
water.
The
solution
can
be
stored
in
a
brown
glass
bottle
in
the
refrigerator,
and
is
stable
for
at
least
two
weeks.
7.2.2
Formaldehyde.
Reagent
grade.
7.2.3
Ammonium
Acetate.
7.2.4
Glacial
Acetic
Acid.

8.0
Sample
Collection,
Preservation,
Storage,
and
Transport
8.1
Pre­
test
8.1.1
Collect
information
about
the
site
characteristics
such
as
exhaust
pipe
diameter,
gas
flow
rates,
port
location,
access
to
ports,
and
safety
requirements
during
a
pre­
test
site
survey.
You
should
then
decide
the
sample
collection
period
per
run
and
the
target
sample
flow
rate
based
on
your
best
estimate
of
the
formaldehyde
concentration
likely
to
be
present.
You
want
to
assure
that
sufficient
formaldehyde
is
captured
in
the
impinger
solution
so
that
it
can
be
measured
precisely
by
the
spectrophotometer.
You
may
use
Equation
323
 
1
to
design
your
test
program.
As
a
guideline
for
optimum
performance,
if
you
can,
design
your
test
so
that
the
liquid
concentration
(
Cl)
is
approximately
10
times
the
assumed
spectrophotometer
detection
limit
of
0.2
ppmw.
However,
since
actual
detection
limits
are
instrument
specific,
we
also
suggest
that
you
confirm
that
the
laboratory
equipment
can
meet
or
exceed
this
detection
limit.
8.1.2
Prepare
and
then
weigh
the
midget
impingers
prior
to
configuring
the
sampling
train.
The
first
impinger
is
initially
dry.
The
second
impinger
contains
20
mL
of
reagent
water,
and
the
third
impinger
contains
silica
gel
that
is
added
before
weighing
the
impinger.
Each
prepared
impinger
is
weighed
and
the
pre­
sampling
weight
is
recorded
to
the
nearest
0.5
gm.
8.1.3
Assemble
the
sampling
train
(
see
Figure
1).
Ice
is
packed
around
the
impingers
in
order
to
keep
them
cold
during
sample
collection.
A
small
amount
of
water
may
be
added
to
the
ice
to
improve
thermal
transfer.
8.1.4
Perform
a
sampling
system
leakcheck
(
from
the
probe
tip
to
the
pump
outlet)
as
follows:
Connect
a
rotameter
to
the
outlet
of
the
pump.
Close
off
the
inlet
to
the
probe
and
observe
the
leak
rate.
The
leak
rate
must
be
less
than
2
percent
of
the
planned
sampling
rate
of
0.2
or
0.4
L/
min.
8.1.5
Source
gas
temperature
and
static
pressure
should
also
be
considered
prior
to
field
sampling
to
ensure
adequate
safety
precautions
during
sampling.

8.2
Sample
Collection
8.2.1
Set
the
sample
flow
rate
between
0.2
 
0.4
L/
min,
depending
upon
the
anticipated
concentration
of
formaldehyde
in
the
engine
exhaust.
(
You
may
have
to
refer
to
published
data
5
6
for
anticipated
concentration
levels.)
If
no
information
is
available
for
the
anticipated
levels
of
formaldehyde,
use
the
higher
sampling
rate
of
0.4
L/
min.
8.2.2
Record
the
sampling
flow
rate
every
5
 
10
minutes
during
the
sample
collection
period.
8.2.3
Monitor
the
amount
of
ice
surrounding
the
impingers
and
add
ice
as
necessary
to
maintain
the
proper
impinger
temperature.
Remove
excess
water
as
needed
to
maintain
an
adequate
amount
of
ice.
8.2.4
Record
measured
leak
rate,
beginning
and
ending
times
and
dry
gas
meter
readings
for
each
sampling
run,
impinger
weights
before
and
after
sampling,
and
sampling
flow
rates
and
dry
gas
meter
exhaust
temperature
every
5
 
10
minutes
during
the
run,
in
a
signed
and
dated
notebook.
8.2.5
If
possible,
monitor
and
record
the
fuel
flow
rate
to
the
engine
and
the
exhaust
oxygen
concentration
during
the
sampling
period.
This
data
can
be
used
to
estimate
the
engine
exhaust
flow
rate
based
on
the
Method
19
approach.
This
approach,
if
accurate
fuel
flow
rates
can
be
determined,
is
preferred
for
reciprocating
IC
engine
exhaust
flow
rate
estimation
due
to
the
pulsating
nature
of
the
engine
exhaust.
The
F­
Factor
procedures
described
in
Method
19
may
be
used
based
on
measurement
of
fuel
flow
rate
and
exhaust
oxygen
concentration.
One
example
equation
is
Equation
323
 
2.
8.3
Post­
test.
Perform
a
sampling
system
leak­
check
(
from
the
probe
tip
to
pump
outlet).
Connect
a
rotameter
to
the
outlet
of
the
pump.
Close
off
the
inlet
to
the
probe
and
observe
the
leak
rate.
The
leak
rate
must
be
less
than
2
percent
of
the
sampling
rate.
Weigh
and
record
each
impinger
immediately
after
sampling
to
determine
the
moisture
weight
gain.
The
impinger
weights
are
measured
before
transferring
the
impinger
contents,
and
before
rinsing
the
sample
probe
and
sample
line.
The
moisture
content
of
the
exhaust
gas
is
determined
by
measuring
the
weight
gain
of
the
impinger
solutions
and
volume
of
gas
sampled
as
described
in
Method
4.
Rinse
the
sample
probe
and
sample
line
with
reagent
water.
Transfer
the
impinger
catch
to
an
amber
40­
mL
VOA
bottle
with
a
Teflon­
lined
cap.
If
there
is
a
small
amount
of
liquid
in
the
dropout
impinger
(<
10
mL),
the
impinger
catches
can
be
combined
in
one
40
mL
VOA
bottle.
If
there
is
a
larger
amount
of
liquid
in
the
dropout
impinger,
use
a
larger
VOA
bottle
to
combine
the
impinger
catches.
Rinse
the
impingers
and
combine
the
rinsate
from
the
sample
probe,
sample
line,
and
impingers
with
the
impinger
catch.
In
general,
combined
rinse
volumes
should
not
exceed
10
mL.
The
volume
of
the
rinses
during
sample
recovery
should
not
be
excessive
as
this
may
result
in
your
having
to
use
a
larger
VOA
bottle.
This
in
turn
would
raise
the
detection
limit
of
the
method
since
after
combining
the
rinses
with
the
impinger
catches
in
the
VOA
bottle,
the
bottle
should
be
filled
with
reagent
water
to
eliminate
the
headspace
in
the
sample
vial.
Keep
the
sample
bottles
over
ice
until
analyzed
on­
site
or
received
at
the
laboratory.
Samples
should
be
analyzed
as
soon
as
possible
to
minimize
possible
sample
degradation.
Based
on
a
limited
number
of
previous
analyses,
samples
held
in
refrigerated
conditions
showed
some
sample
degradation
over
time.

8.4
Quality
Control
Samples
8.4.1
Field
Duplicates.
During
at
least
one
run,
a
pair
of
samples
should
be
collected
concurrently
and
analyzed
as
separate
samples.
Results
of
the
field
duplicate
samples
should
be
identified
and
reported
with
the
sample
results.
The
percent
difference
in
exhaust
(
stack)
concentration
indicated
by
field
duplicates
should
be
within
20
percent
of
their
mean
concentration.
Data
are
to
be
flagged
as
suspect
if
the
duplicates
do
not
meet
the
acceptance
criteria.

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E:\
FR\
FM\
14JAP2.
SGM
14JAP2
1927
Federal
Register
/
Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
8.4.2
Spiked
Samples.
An
aliquot
of
one
sample
from
each
source
sample
set
should
be
spiked
at
2
to
3
times
the
formaldehyde
level
found
in
the
unspiked
sample.
It
is
also
recommended
that
a
second
aliquot
of
the
same
sample
be
spiked
at
around
half
the
level
of
the
first
spike;
however,
the
second
spike
is
not
mandatory.
The
results
are
acceptable
if
the
measured
spike
recovery
is
80
to
120
percent.
Use
Equation
323
 
4.
Data
are
to
be
flagged
as
suspect
if
the
spike
recovery
do
not
meet
the
acceptance
criteria.
8.4.3
Field
Blank.
A
field
blank
consisting
of
reagent
water
placed
in
a
clean
impinger
train,
taken
to
the
test
site
but
not
sampled,
then
recovered
and
analyzed
in
the
same
manner
as
the
other
samples,
should
be
collected
with
each
set
of
source
samples.
The
field
blank
results
should
be
less
than
50
percent
of
the
lowest
calibration
standard
used
in
the
sample
analysis.
If
this
criteria
is
not
met,
the
data
should
be
flagged
as
suspect.

9.0
Quality
Control
QA/
QC
Specification
Acceptance
criteria
Frequency
Corrective
action
Leak­
check
 
Sections
8.1.4,
8.3
...
<
2%
of
Sampling
rate
...................
Pre­
and
Post­
sampling
................
Pre­
sampling:
Repair
leak
and
recheck
Post­
sampling:
Flag
data
and
repeat
run
if
for
regulatory
compliance.
Sample
flow
rate
............................
Between
0.2
and
0.4
L/
min
..........
Throughout
sampling
....................
Adjust.
VOA
vial
headspace
......................
No
headspace
..............................
After
sample
recovery
..................
Flag
data.
Sample
preservation
......................
Maintain
on
ice
.............................
After
sample
recovery
..................
Flag
data.
Sample
hold
time
...........................
14
day
maximum
..........................
After
sample
recovery
..................
Flag
data.
Field
Duplicates
 
Section
8.4.1
.....
Within
20%
of
mean
of
original
and
duplicate
sample.
One
duplicate
per
source
sample
set.
Flag
data.

Spiked
Sample
 
Section
8.4.2
......
Recovery
between
80
and
120%
One
spike
per
source
sample
set
Flag
data.
Field
Blank
 
Section
8.4.3
............
<
50%
of
the
lowest
calibration
standard.
One
blank
per
source
sample
set
Flag
data.

Calibration
Linearity
 
Section
10.1
Correlation
coefficient
of
0.99
or
higher.
Per
source
sample
set
.................
Repeat
calibration
procedures.

Calibration
Check
Standard
 
Section
10.3.
Within
10%
of
theoretical
value
....
One
calibration
check
per
source
sample
set.
Repeat
check,
remake
standard
and
repeat,
repeat
calibration.
Lab
Duplicates
 
Section
11.2.1
....
Within
10%
of
mean
of
original
and
duplicate
sample
analysis.
One
duplicate
per
10
samples
.....
Flag
data.

Analytical
Blanks
 
Section
11.2.2
<
50%
of
the
lowest
calibration
standard.
One
blank
per
source
sample
set
Clean
glassware/
analytical
equipment
and
repeat.

10.0
Calibration
and
Standardization
10.1
Spectrophotometer
Calibration.
Prepare
a
stock
solution
of
10
ppm
formaldehyde.
Prepare
a
series
of
calibration
standards
from
the
stock
solution
by
adding
0,
0.1,
0.3,
0.7,
1.0,
and
1.5
mL
of
stock
solution
(
corresponding
to
0,
1.0,
3.0,
7.0,
10.0,
and
15.0
µ
g
formaldehyde,
respectively)
to
screw­
capped
vials.
Adjust
each
vial's
volume
to
2.0
mL
with
reagent
water.
Add
2.0
mL
of
acetyl
acetone
reagent,
thoroughly
mix
the
solution,
and
place
the
vials
in
a
water
bath
(
or
heating
block)
at
60
°
C
for
10
minutes.
Remove
the
vials
and
allow
to
cool
to
room
temperature.
Transfer
each
solution
to
a
cuvette
and
measure
the
absorbance
at
412
nm
using
the
spectrophotometer.
Develop
a
calibration
curve
from
the
analytical
results
of
these
standards.
The
acceptance
criteria
for
the
spectrophotometer
calibration
is
a
correlation
coefficient
of
0.99
or
higher.
If
this
criteria
is
not
met,
the
calibration
procedures
should
be
repeated.
10.2
Spectrophotometer
Zero.
The
spectrophotometer
should
be
zeroed
with
reagent
water
when
analyzing
each
set
of
samples.
10.3
 
Calibration
Checks.
Calibration
checks
consisting
of
analyzing
a
standard
separate
from
the
calibration
standards
must
be
performed
with
each
set
of
samples.
The
calibration
check
standard
should
not
be
prepared
from
the
calibration
stock
solution.
The
result
of
the
check
standard
must
be
within
10
percent
of
the
theoretical
value
to
be
acceptable.
If
the
acceptance
criteria
are
not
met,
the
standard
must
be
reanalyzed.
If
still
unacceptable,
a
new
calibration
curve
must
be
prepared
using
freshly
prepared
standards.
11.0
Analytical
Procedure
11.1
Sample
Analysis.
A
2.0­
mL
aliquot
of
the
impinger
catch/
rinsate
is
transferred
to
a
screw­
capped
vial.
Two
mL
of
the
acetyl
acetone
reagent
are
added
and
the
solution
is
thoroughly
mixed.
Once
mixed,
the
vial
is
placed
in
a
water
bath
(
or
heating
block)
at
60
°
C
for
10
minutes.
Remove
the
vial
and
allow
to
cool
to
room
temperature.
Transfer
the
solution
to
a
cuvette
and
measure
the
absorbance
using
the
spectrophotometer
at
412
nm.
The
quantity
of
formaldehyde
present
is
determined
by
comparing
the
sample
response
to
the
calibration
curve.
Use
Equation
323
 
5.
If
the
sample
response
is
out
of
the
calibration
range,
the
sample
must
be
diluted
and
reanalyzed.
Such
dilutions
must
be
performed
on
another
aliquot
of
the
original
sample
before
the
addition
of
the
acetyl
acetone
reagent.
The
full
procedure
is
repeated
with
the
diluted
sample.

11.2
Analytical
Quality
Control
11.2.1
Laboratory
Duplicates.
Two
aliquots
of
one
sample
from
each
source
sample
set
should
be
prepared
and
analyzed
(
with
a
minimum
of
one
pair
of
aliquots
for
every
10
samples).
The
percent
difference
between
aliquot
analysis
should
be
within
10
percent
of
their
mean.
Use
Equation
323
 
3.
Data
are
flagged
if
the
laboratory
duplicates
do
not
meet
this
criteria.
11.2.2
Analytical
blanks.
Blank
samples
(
reagent
water)
should
be
incorporated
into
each
sample
set
to
evaluate
the
possible
presence
of
any
cross­
contamination.
The
acceptance
criteria
for
the
analytical
blank
is
less
than
50
percent
of
the
lowest
calibration
standard.
If
the
analytical
blank
does
not
meet
this
criteria,
the
glassware/
analytical
equipment
should
be
cleaned
and
the
analytical
blank
repeated.

12.0
Calculations
and
Data
Analysis
12.1
Nomenclature
A
=
measured
absorbance
of
2
mL
aliquot
B
=
estimated
sampling
rate,
lpm
Cl
=
target
concentration
in
liquid,
ppmw
D
=
estimated
stack
formaldehyde
concentration
(
ppmv)
E
=
estimated
liquid
volume,
normally
40,
mL
(
the
size
of
the
VOA
used)
cform
=
formaldehyde
concentration
in
gas
stream,
ppmvd
cform
@
15%
02
=
formaldehyde
concentration
in
gas
stream
corrected
to
15%
oxygen,
ppmvd
Csm
=
measured
concentration
of
formaldehyde
in
the
spiked
aliquot
Cu
=
measured
concentration
of
formaldehyde
in
the
unspiked
aliquot
of
the
same
sample
Cs
=
calculated
concentration
of
formaldehyde
spiking
solution
added
to
the
spiked
aliquot
df
=
dilution
factor,
1
unless
dilution
of
the
sample
was
needed
to
reduce
the
absorbance
into
the
calibration
range
Fd
=
dry
basis
F­
factor
from
Method
19,
dscf
per
million
btu
GCVg
=
Gross
calorific
value
(
or
higher
heating
value),
btu
per
scf
Kc
=
spectrophotometer
calibration
factor,
slope
of
the
least
square
regression
line
(
Note:
Most
spreadsheets
are
capable
of
calculating
a
least
squares
line.)
K1
=
0.3855
°
K/
mm
Hg
for
metric
units,
(
17.65
°
R/
in.
Hg
for
English
units.)
MW
=
molecular
weight,
30
g/
g­
mole,
for
formaldehyde
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1928
Federal
Register
/
Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
24.05
=
mole
specific
volume
constant,
liters
per
g­
mole
m
=
mass
of
formaldehyde
in
liquid
sample,
mg
Pstd
=
Standard
pressure,
760
mm
Hg
(
29.92
in.
Hg)
Pbar
=
Barometric
pressure,
mm
Hg
(
in.
Hg)
PD
=
Percent
Difference
Qe
=
exhaust
flow
rate,
dscf
per
minute
Qg
=
natural
gas
fuel
flow
rate,
scf
per
minute
Tm
=
Average
DGM
absolute
temperature,
°
K
(
°
R).
Tstd
=
Standard
absolute
temperature,
293
°
K
(
528
°
R).
t
=
sample
time
(
minutes)
Vm
=
Dry
gas
volume
as
measured
by
the
DGM,
dcm
(
dcf).
Vm(
std)
=
Dry
gas
volume
measured
by
the
DGM,
corrected
to
standard
conditions,
dscm
(
dscf).
Vt
=
actual
total
volume
of
impinger
catch/
rinsate,
mL
Va
=
volume
(
2.0)
of
aliquot
analyzed,
mL
X1
=
first
value
X2
=
second
value
O2d
=
oxygen
concentration
measured,
percent
by
volume,
dry
basis
%
R
=
percent
recovery
of
spike
Zu
=
volume
fraction
of
unspiked
(
native)
sample
contained
in
the
final
spiked
aliquot
[
e.
g.,
Vu/(
Vu
+
Vs),
where
Vu
+
Vs
should
=
2.0
mL
]
Zs
=
volume
fraction
of
spike
solution
contained
in
the
final
spiked
aliquot
[
e.
g.,
Vs/(
Vu
+
Vs)]
R
=
0.02405
dscm
per
g­
mole,
for
metric
units
Y
=
Dry
Gas
Meter
calibration
factor
12.2
Pretest
Design
C
B
t
D
E
l
=
 
 
 
 
30
24
05
1
.
Eq.
323­

12.3
Exhaust
Flow
Rate
Q
F
Q
GCV
O
Eq
d
g
g
d
=
 
 
 
 
 
 
 
10
20
9
20
9
2
6
2
.

.
.
323­

12.4
Percent
Difference.
 
(
Applicable
to
Field
and
Lab
Duplicates)

PD
X
X
X
X
Eq
=
 
(
)
+

 
 
 
 
 
1
2
1
2
2
100
3
323­
.
12.5
Percent
Recovery
of
Spike
%
.
R
C
ZC
Z
C
Eq
sm
u
u
s
s
=
 
(
) 
323­
100
4
12.6
Mass
of
Formaldehyde
in
Liquid
Sample
m
KAF
V
V
Eq
c
t
a
=
 
 
 
 
 
 
.
323­
5
12.7
Dry
Sample
Gas
Volume,
Corrected
to
Standard
Conditions
V
V
YT
P
T
P
Eq
YV
P
T
m
std
m
std
bar
m
std
m
bar
m
(
)
.
=(
)
(
)
323­
6
=
Ki
12.8
Formaldehyde
Concentration
in
Gas
Stream
c
R
MW
m
V
Eq
form
m
std
=
 
 
 
 
 
 
 
 
 
 
 
 
×
(
)
(
)
.
1
1
106
g
1000
mg
ppm
323­
7
12.9
Formaldehyde
Concentration,
Corrected
to
15%
Oxygen
c
c
O
Eq
form
O
form
d
@
(
.
)

.
.
15%
2
2
20
9
15
20
9
=
 
 
 
(
)
323­
8
13.0
Method
Performance
13.1
Precision.
Based
on
a
Method
301
validation
using
quad
train
arrangement
with
post
sampling
spiking
study
of
the
method
at
a
natural
gas­
fired
IC
engine,
the
relative
standard
deviation
of
six
pairs
of
unspiked
samples
was
11.2
percent
at
a
mean
stack
gas
concentration
of
16.7
ppmvd.
13.2
Bias.
No
bias
correction
is
allowed.
The
single
Method
301
validation
study
of
the
method
at
a
natural
gas­
fired
IC
engine,
indicated
a
bias
correction
factor
of
0.91
for
that
set
of
data.
An
earlier
spiking
study
got
similar
average
percent
spike
recovery
when
spiking
into
a
blank
sample.
This
data
set
is
too
limited
to
justify
using
a
bias
correction
factor
for
future
tests
at
other
sources.
13.3
Range.
The
range
of
this
method
for
formaldehyde
is
0.2
to
7.5
ppmw
in
the
liquid
phase.
(
This
corresponds
to
a
range
of
0.27
to
10
ppmv
in
the
engine
exhaust
if
sampling
at
a
rate
of
0.4
Lpm
for
60
minutes
and
using
a
40
mL
VOA
bottle.)
If
the
liquid
sample
concentration
is
above
this
range,
perform
the
appropriate
dilution
for
accurate
measurement.
Any
dilutions
must
be
taken
from
new
aliquots
of
the
original
sample
before
reanalysis.
13.4
Sample
Stability.
Based
on
a
sample
stability
study
conducted
in
conjunction
with
the
method
validation,
sample
degradation
for
7
and
14­
day
hold
times
does
not
exceed
2.3
and
4.6
percent,
respectively,
based
on
a
95
percent
level
of
confidence.
Therefore,
the
recommended
maximum
sample
holding
time
for
the
underivatized
impinger
catch/
rinsate
is
14
days,
where
projected
sample
degradation
is
below
5
percent.

14.0
Pollution
Prevention
Sample
gas
from
the
combustion
source
exhaust
is
vented
to
the
atmosphere
after
passing
through
the
chilled
impinger
sampling
train.
Reagent
solutions
and
samples
should
be
collected
for
disposal
as
aqueous
waste.

15.0
Waste
Management
Standards
of
formaldehyde
and
the
analytical
reagents
should
be
handled
according
to
the
Material
Safety
Data
Sheets.

16.0
References
1
National
Council
of
the
Paper
Industry
for
Air
and
Stream
Improvement,
Inc.,
``
Volatile
Organic
Emissions
from
Pulp
and
Paper
Mill
Sources,
Part
X
 
Test
Methods,
Quality
Assurance/
Quality
Control
Procedures,
and
Data
Analysis
Protocols,''
Technical
Bulletin
No.
684,
December
1994.
2
National
Council
of
the
Paper
Industry
for
Air
and
Stream
Improvement,
Inc.,
``
Field
Validation
of
a
Source
Sampling
Method
for
Formaldehyde,
Methanol,
and
Phenol
at
Wood
Products
Mills,''
1997
TAPPI
International
Environmental
Conference.
3
Roy
F.
Weston,
Inc.,
``
Formaldehyde
Sampling
Method
Field
Evaluation
and
Emission
Test
Report
for
Georgia­
Pacific
Resins,
Inc.,
Russellville,
South
Carolina,''
August
1996.
4
Hoechst
Celanese
Method
CL
8
 
4,
``
Standard
Test
Method
for
Free
Formaldehyde
in
Air
Using
Acetyl
acetone,''
Revision
0,
September
1986.
5
Shareef,
G.
S.,
et
al.
``
Measurement
of
Air
Toxic
Emissions
from
Natural
Gas­
Fired
Internal
Combustion
Engines
at
Natural
Gas
Transmission
and
Storage
Facilities.''
Report
No.
GRI
 
96/
0009.1,
Gas
Research
Institute,
Chicago,
Illinois,
February
1996.
6
Gundappa,
M.,
et
al.
``
Characteristics
of
Formaldehyde
Emissions
from
Natural
Gas­
Fired
Reciprocating
Internal
Combustion
Engines
in
Gas
Transmission.
Volume
I:
Phase
I
Predictive
Model
for
Estimating
Formaldehyde
Emissions
from
2
 
Stroke
Engines.''
Report
No.
GRI
 
97/
0376.1,
Gas
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1929
Federal
Register
/
Vol.
68,
No.
9
/
Tuesday,
January
14,
2003
/
Proposed
Rules
Research
Institute,
Chicago,
Illinois,
September
1997.
17.0
Tables,
Diagrams,
Flowcharts,
and
Validation
Data
BILLING
CODE
6560
 
50
 
P
[
FR
Doc.
03
 
86
Filed
1
 
13
 
03;
8:
45
am]

BILLING
CODE
6560
 
50
 
C
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