6560­
50­
P
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
63
[
OAR­
2004­
0238;
FRL­
]

[
RIN
A2060­
AM16]

National
Emission
Standards
for
Hazardous
Air
Pollutants:
Oil
and
Natural
Gas
Production
Facilities
AGENCY:
Environmental
Protection
Agency
(
EPA).

ACTION:
Supplemental
proposed
rule.

SUMMARY:
This
action
is
a
supplemental
notice
of
proposed
rulemaking
to
our
February
6,
1998
(
63
FR
6288)
proposed
national
emissions
standards
for
hazardous
air
pollutants
(
NESHAP)
to
limit
emissions
of
hazardous
air
pollutants
(
HAP)
from
oil
and
natural
gas
production
facilities
that
are
area
sources.
The
final
NESHAP
for
major
sources
was
promulgated
on
June
17,
1999
(
64
FR
32610),
but
final
action
with
respect
to
area
sources
was
deferred.
This
action
proposes
changes
to
the
1998
proposed
rule
for
area
sources,

proposes
alternative
applicability
criteria
and
reopens
the
public
comment
period
to
solicit
comment
on
the
changes
proposed
today.
The
proposal
also
includes
the
addition
of
ASTM
D6420­
99
as
an
alternative
test
method
to
EPA
Method
18.
Oil
and
natural
gas
production
is
included
as
an
area
source
category
for
regulation
under
the
Urban
Air
Toxics
2
Strategy
(
Strategy)(
64
FR
38706,
July
19,
1999).
As
explained
below,
we
included
oil
and
natural
gas
production
facilities
in
the
Strategy
because
of
benzene
emissions
from
triethylene
glycol
(
TEG)
dehydration
units
located
at
such
facilities.

DATES:
Comments
must
be
received
on
or
before
[
INSERT
DATE
60
DAYS
AFTER
PUBLICATION
OF
THE
PROPOSED
RULE
IN
THE
FEDERAL
REGISTER].

ADDRESSES:
Comments.
Submit
your
comments,
identified
by
Docket
ID
No.
OAR­
2004­
0238,
by
one
of
the
following
methods:

°
Federal
eRulemaking
Portal:

http://
www.
regulations.
gov.
Follow
the
on­
line
instructions
for
submitting
comments.

°
Agency
Website:
http://
www.
epa.
gov/
edocket.
EDOCKET,

EPA's
electronic
public
docket
and
comment
system,
is
EPA's
preferred
method
for
receiving
comments.
Follow
the
on­
line
instructions
for
submitting
comments.

°
E­
mail:
a­
and­
r­
docket@
epa.
gov.

°
Fax:
(
202)
566­
1741.

°
Mail:
Air
and
Radiation
Docket,
U.
S.
Environmental
Protection
Agency,
Mailcode
6102T,
1200
Pennsylvania
Ave.,

N.
W.,
Washington,
DC,
20460.
Please
include
a
total
of
two
copies.
In
addition,
please
mail
a
copy
of
your
comments
on
3
the
information
collection
provisions
to
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget
(
OMB),
Attn:
Desk
Officer
for
EPA,
725
17th
St.

N.
W.,
Washington,
DC,
20503.

°
Hand
Delivery:
U.
S.
Environmental
Protection
Agency,

1301
Constitution
Ave.,
N.
W.,
Room:
B102,
Washington,
DC,

20460.
Such
deliveries
are
only
accepted
during
the
Docket's
normal
hours
of
operation,
and
special
arrangements
should
be
made
for
deliveries
of
boxed
information.

We
request
that
a
separate
copy
also
be
sent
to
the
contact
person
listed
below
(
see
FOR
FURTHER
INFORMATION
CONTACT).

Instructions.
Direct
your
comments
to
Docket
ID
No.
OAR­

2004­
0238.
The
EPA's
policy
is
that
all
comments
received
will
be
included
in
the
public
docket
without
change
and
may
be
made
available
online
at
http://
www.
epa.
gov/
edocket,

including
any
personal
information
provided,
unless
the
comment
includes
information
claimed
to
be
Confidential
Business
Information
(
CBI)
or
other
information
whose
disclosure
is
restricted
by
statute.
Do
not
submit
information
that
you
consider
to
be
CBI
or
otherwise
protected
through
EDOCKET,
regulations.
gov,
or
e­
mail.
The
EPA
EDOCKET
and
the
federal
regulations.
gov
websites
are
"
anonymous
access"
systems,
which
means
EPA
will
not
know
4
your
identity
or
contact
information
unless
you
provide
it
in
the
body
of
your
comment.
If
you
send
an
e­
mail
comment
directly
to
EPA
without
going
through
EDOCKET
or
regulations.
gov,
your
e­
mail
address
will
be
automatically
captured
and
included
as
part
of
the
comment
that
is
placed
in
the
public
docket
and
made
available
on
the
Internet.
If
you
submit
an
electronic
comment,
EPA
recommends
that
you
include
your
name
and
other
contact
information
in
the
body
of
your
comment
and
with
any
disk
or
CD­
ROM
you
submit.
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.
Electronic
files
should
avoid
the
use
of
special
characters,
any
form
of
encryption,

and
be
free
of
any
defects
or
viruses.
For
additional
information
about
EPA's
public
docket,
visit
EDOCKET
on­
line
or
see
the
Federal
Register
of
May
31,
2002
(
67
FR
38102).

Docket.
All
documents
in
the
docket
are
listed
in
the
EDOCKET
index
at
http://
www.
epa.
gov/
edocket.
Although
listed
in
the
index,
some
information
is
not
publicly
available,
i.
e.,
CBI
or
other
information
whose
disclosure
is
restricted
by
statute.
Certain
other
information,
such
as
copyrighted
materials,
is
not
placed
on
the
Internet
and
will
be
publicly
available
only
in
hard
copy
form.
Publicly
available
docket
materials
are
available
either
5
electronically
in
EDOCKET
or
in
hard
copy
form
at
the
Air
and
Radiation
Docket,
EPA/
DC,
EPA
West,
Room
B102,
1301
Constitution
Ave.,
N.
W.,
Washington,
DC.
The
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
Public
Reading
Room
is
(
202)
566­
1744,
and
the
telephone
number
for
the
Air
and
Radiation
Docket
is
(
202)
566­
1742.

FOR
FURTHER
INFORMATION
CONTACT:
Mr.
Greg
Nizich,
Office
of
Air
Quality
Planning
and
Standards,
Emission
Standards
Division
(
C439­
03),
EPA,
Research
Triangle
Park,
NC
27711;

telephone
number:
919­
541­
3078;
fax
number:
919­
541­
3207;

electronic
mail
address:
nizich.
greg@
epa.
gov.

SUPPLEMENTARY
INFORMATION:
Entities
Table.
Entities
potentially
affected
by
this
proposed
action
include,
but
are
not
limited
to,
the
following:

Category
NAICS
Code1
Examples
of
Regulated
Entities
Industry
211111,
211112
Condensate
tank
batteries,
glycol
dehydration
units,
and
natural
gas
processing
plants.
1
North
American
Industry
Classification
System.

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
would
be
regulated
by
this
action,
you
should
6
examine
the
applicability
criteria
in
40
CFR
part
63,

subpart
HH­
National
Emissions
Standards
for
Hazardous
Air
Pollutants:
Oil
and
Natural
Gas
Production
Facilities.
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.

Worldwide
Web.
In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
the
proposed
rule
is
also
available
on
the
Worldwide
Web
(
WWW)
through
the
Technology
Transfer
Network
(
TTN).
Following
the
Administrator's
signature,
a
copy
of
the
proposed
rule
will
be
posted
on
the
TTN's
policy
and
guidance
page
for
newly
proposed
or
promulgated
rules
at
http://
www.
epa.
gov/
ttn/
oarpg.
The
TTN
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.

Public
Hearing.
If
anyone
contacts
EPA
requesting
to
speak
at
a
public
hearing
by
[
INSERT
DATE
20
DAYS
AFTER
PUBLICATION
IN
THE
FEDERAL
REGISTER],
a
public
hearing
will
be
held
on
[
INSERT
DATE
30
DAYS
AFTER
PUBLICATION
IN
THE
FEDERAL
REGISTER].
If
a
public
hearing
is
requested,
it
will
be
held
at
10:
00
a.
m.
at
the
EPA
Facility
Complex
in
Research
Triangle
Park,
North
Carolina
or
at
an
alternate
site
nearby.
Contact
Mr.
Greg
Nizich
at
919­
541­
3078
to
request
a
hearing,
to
request
to
speak
at
a
public
hearing,
7
to
determine
if
a
hearing
will
be
held,
or
to
determine
the
hearing
location.

Outline.
The
information
presented
in
this
preamble
is
organized
as
follows:

I.
Background
II.
Summary
of
Proposed
Rule
for
Area
Sources
III.
Rationale
for
Selecting
the
Proposed
Standards
A.
How
did
we
select
the
source
category?
B.
How
did
we
select
the
affected
sources
and
emission
points?
C.
What
changes
to
the
applicability
requirements
for
area
sources
are
part
of
this
supplemental
notice?
D.
What
changes
are
we
proposing
to
the
startup,
shutdown,
and
malfunction
plan
requirements?
IV.
Summary
of
Environmental,
Energy,
Cost,
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
non­
air
environmental
and
energy
impacts?
V.
Statutory
and
Executive
Order
Reviews
A.
Executive
Order
12866:
Regulatory
Planning
and
Review
B.
Paperwork
Reduction
Act
C.
Regulatory
Flexibility
Act
D.
Unfunded
Mandates
Reform
Act
E.
Executive
Order
13132:
Federalism
F.
Executive
Order
13175:
Consultation
and
Coordination
with
Indian
Tribal
Governments
G.
Executive
Order
13045:
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
H.
Executive
Order
13211:
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
I.
National
Technology
Transfer
and
Advancement
Act
I.
Background
We
proposed
NESHAP
for
the
Oil
and
Natural
Gas
Production
source
category
on
February
6,
1998
(
63
FR
6288)
8
1
The
proposed
finding
evaluated
HAP
from
TEG
units,
but
the
only
HAP
identified
in
the
Strategy
that
is
emitted
from
TEG
units
is
benzene.
that
addressed
both
major
and
area
sources
of
oil
and
natural
gas
production
facilities.
Area
sources
of
HAP
are
those
stationary
sources
that
emit
or
have
the
potential
to
emit,
considering
controls,
less
than
10
tons
per
year
of
any
one
HAP
and
less
than
25
tons
per
year
of
any
combination
of
HAP.
The
1998
proposed
area
source
rule
was
based
on
a
proposed
finding
of
adverse
human
health
effects
from
benzene
emissions
from
triethylene
glycol
(
TEG)

dehydration
units
at
area
source
oil
and
natural
gas
production
facilities1.
Based
on
this
finding,
referred
to
as
an
area
source
finding,
we
proposed
to
amend
the
source
category
list
to
add
oil
and
natural
gas
production
to
the
list
of
area
source
categories
established
under
section
112(
c)(
1)
of
the
Clean
Air
Act
(
CAA).
In
June
1999,
we
took
final
action
on
the
major
source
standards
but
deferred
action
on
the
TEG
dehydration
units
at
oil
and
natural
production
area
source
facilities
and
on
listing
the
area
source
category
pending
issuance
of
the
Strategy.

The
Strategy
was
issued
on
July
19,
1999
(
64
FR
38706)

and
addressed
section
112(
c)(
3)
and
112(
k)(
3)(
B)(
ii)
of
the
CAA
that
instruct
us
to
identify
not
less
than
30
HAP
which,
9
as
the
result
of
emissions
from
area
sources,
present
the
greatest
threat
to
public
health
in
the
largest
number
of
urban
areas,
and
to
list
sufficient
area
source
categories
or
subcategories
to
ensure
that
emissions
representing
90
percent
of
the
30
listed
HAP
are
subject
to
regulation.
The
Strategy
included
a
list
of
33
HAP
judged
to
pose
the
greatest
potential
threat
to
public
health
in
the
largest
number
of
urban
areas
(
the
urban
HAP)
and
a
list
of
area
source
categories
emitting
30
of
the
listed
HAP
(
area
source
HAP).
Once
listed,
these
area
source
categories
shall
be
subject
to
standards
under
section
112(
d)
of
the
CAA.
The
proposed
standards
that
are
the
subject
of
today's
action
are
based
on
generally
available
control
technology
(
GACT)

pursuant
to
section
112(
d)(
5)
of
the
CAA.

Benzene
was
one
of
the
HAP
listed
under
the
Strategy.

Oil
and
natural
gas
production
facilities
were
listed
in
the
Strategy
solely
because
the
TEG
dehydration
units
located
at
these
facilities
contributed
approximately
47
percent
of
the
national
urban
emissions
of
benzene
from
stationary
sources
at
area
sources.
As
the
result
of
the
emission
standards
development
process,
we
recognize
that
our
description
of
the
source
category
in
the
Strategy
is
overbroad.
The
listing
should
read
TEG
dehydration
units
at
oil
and
natural
gas
production
facilities.
This
clarification
to
the
scope
10
of
the
source
category
is
consistent
with
the
Agency's
proposed
1998
finding
and
the
record
supporting
both
the
1998
finding
and
the
1999
listing
in
the
Strategy.

Today,
we
are
proposing
the
addition
of
regulatory
language
to
40
CFR
part
63,
subpart
HH,
to
address
area
sources
and
fulfill
a
portion
of
our
obligation
under
section
112(
c)(
3)
to
regulate
stationary
sources
of
benzene.

Even
though
we
had
previously
included
area
source
requirements
as
part
of
the
1998
subpart
HH
proposal,
at
this
time,
we
are
proposing
some
changes
to
the
previously
proposed
standards
in
response
to
the
comments
we
received
on
the
1998
proposal.
In
addition,
we
are
proposing
another
geographical
applicability
option
as
an
alternative
to
the
previously
proposed
criteria.
We
are
seeking
comment
on
these
proposed
changes.
Most
importantly,
we
are
seeking
comments
on
both
applicability
options
that
are
under
consideration.

An
applicability
option
under
consideration
was
first
described
in
the
1998
proposed
rule.
Specifically,
we
proposed
that
the
area
source
standards
would
apply
only
to
TEG
dehydration
units
at
area
source
oil
and
natural
gas
production
facilities
located
in
an
urban
county
rather
than
11
2
Urban­
1
and
Urban­
2
are
defined
based
on
the
U.
S.
Census
Bureau's
most
current
decennial
census
data.
Urban­
1
counties
consist
of
counties
with
metropolitan
statistical
areas
(
MSA)
with
a
population
greater
than
250,000.
Urban­
2
counties
are
defined
as
all
other
counties
where
more
than
50
percent
of
the
population
is
designated
urban
by
the
U.
S.
Census
Bureau.
For
purposes
of
this
preamble,
we
refer
to
those
counties
that
qualify
as
Urban­
1
and
Urban­
2
as
"
urban"
counties.
Rural
counties
are
those
counties
that
do
not
meet
the
criteria
of
Urban­
1
or
Urban­
2.
A
list
of
the
urban
and
rural
counties
based
on
the
1990
census
classifications
can
be
found
online
at
http://
www.
epa.
gov/
ttnatw01/
urban/
112kfac.
html.
A
list
of
the
urban
and
rural
counties
based
on
the
1990
and
2000
census
classifications
can
be
found
online
at
http://
www.
epa.
gov/
ttn/
atw/
oilgas/
oilgaspg.
html
and
in
the
Docket.
a
rural
county
using
Urban­
1
and
Urban­
22
classifications
that
we
defined
based
on
information
from
the
U.
S.
Census
Bureau
(
64
FR
6293).
(
Note:
Urban­
2
counties
in
the
1998
proposed
rule
were
incorrectly
defined.
In
that
notice,
we
incorrectly
stated
that
Urban­
2
counties
were
defined
by
criteria
used
by
the
U.
S.
Census
Bureau
to
define
urbanized
areas,
which
are
not
county­
based
areas.
The
actual
parameters
for
Urban­
2
that
we
used
for
determining
urban
HAP
under
the
Strategy,
as
well
as
for
the
1998
and
today's
proposed
standards
for
TEG
units
at
area
source
oil
and
natural
gas
production
facilities,
are
provided
in
footnote
2
of
today's
notice.)
Under
this
proposed
geographical
applicability
criterion
described
in
footnote
2,
those
area
source
TEG
dehydration
units
located
in
counties
classified
as
urban
areas
would
be
subject
to
the
rule.
12
In
today's
notice,
we
are
proposing
a
second,

alternative
applicability
approach
for
purposes
of
the
proposed
rule.
Under
that
alternative
option,
the
final
rule
would
apply
to
all
TEG
dehydrators
at
area
source
oil
and
natural
gas
production
facilities.

We
are
seeking
comment
on
both
of
these
proposed
applicability
options.
We
are
not
requesting
comment
on
any
aspect
of
subpart
HH
as
it
applies
to
major
sources.
We
issued
the
final
rule
for
major
sources
in
1999,
and
that
rule
is
not
part
of
today's
proposal.
We
are
today,

however,
proposing
to
add
ASTM
D6420­
99(
2004)
as
an
alternative
to
EPA
Method
18
for
both
major
and
area
sources,
and
we
seek
comment
on
this
particular
proposed
regulatory
change,
as
it
affects
both
major
and
area
sources.

II.
Summary
of
Proposed
Rule
for
Area
Sources
The
1998
proposal
described
the
area
source
requirements
as
largely
identical
to
the
major
source
requirements,
except
for
the
addition
of
geographic
applicability
criteria,
the
fact
that
only
the
TEG
dehydration
unit
would
be
an
affected
source
covered
by
the
emission
reduction
standards
at
area
sources,
and
some
reduced
reporting
requirements.
Except
as
described
below,

we
have
not
changed
these
requirements
with
today's
13
supplemental
notice.

As
in
the
1998
proposed
rule
(
63
FR
6290),
the
standards
proposed
today
are
based
on
GACT
which
would
require
owners
or
operators
of
TEG
dehydration
units
at
area
sources
to
connect,
through
a
closed­
vent
system,
each
process
vent
on
the
TEG
dehydration
unit
to
an
emission
control
system.
The
control
system
must
reduce
emissions
either:
(
1)
by
95.0
percent
or
more
of
HAP
(
generally
a
condenser
with
a
flash
tank),
or
(
2)
to
an
outlet
concentration
of
20
parts
per
million
by
volume
(
ppmv)
or
less
(
for
combustion
devices),
or
(
3)
to
a
benzene
emission
level
of
less
than
0.90
Megagrams
per
year
(
Mg/
yr)
(
1.0
tons
per
year(
tpy)).
Sources
whose
actual
annual
average
flowrate
of
natural
gas
to
the
TEG
dehydration
unit
is
less
than
85
thousand
standard
cubic
meters
per
day
(
thousand
m3/
day)
(
3
million
standard
cubic
feet
per
day
(
MMSCFD)),
or
sources
whose
actual
average
emissions
of
benzene
from
the
TEG
dehydration
unit
process
vent
to
the
atmosphere
are
less
than
0.90
Mg/
yr
(
1
tpy),
as
determined
by
the
procedures
specified
in
40
CFR
63.772(
b)(
1)
and
(
2),
would
not
have
any
control
requirements.

We
believe
these
cutoffs
are
appropriate
due
to
similarities
between
TEG
units
at
area
sources
and
those
at
major
sources.
Based
on
the
available
data
for
TEG
units
at
14
major
sources
in
1998,
we
were
not
able
to
determine
any
level
of
emission
control
below
the
85
thousand
m3/
day
and
0.90
Mg/
yr
cutoff
levels
at
major
sources.
Because
our
assessment
of
the
cutoff
levels
for
TEG
units
at
major
sources
has
not
changed
since
1998,
and
because
we
have
no
information
suggesting
any
difference
between
major
and
area
sources
in
the
basis
for
controlling
TEG
units,
we
do
not
believe
that
we
would
be
able
to
determine
any
level
of
emission
control
for
TEG
units
below
the
cutoff
levels
at
area
sources
either.
In
addition,
we
compared
the
cost
of
control
per
unit
of
HAP
removed
when
controlling
all
units,

against
such
cost
when
controlling
only
units
with
benzene
emissions
of
1
tpy
or
greater.
We
also
evaluated
the
projected
impacts
and
costs
associated
with
four
different
levels
of
natural
gas
throughput
(
see
63
FR
6288
and
6299).

Based
on
these
assessments,
we
believe
that
the
cost
burden
to
the
affected
sources
below
these
cutoff
levels
would
be
too
high
for
the
amount
of
emission
reduction
these
sources
would
achieve
with
the
proposed
controls.

We
note
that
for
the
reasons
described
above,
we
are
proposing
in
this
action
to
subcategorize
those
TEG
dehydration
units
that
are
subject
to
the
final
rule
based
on
whether
the
unit
has
an
annual
average
flowrate
of
natural
gas
less
than
85
thousand
m3/
day
(
3
MMSCFD),
or
15
actual
annual
average
benzene
emissions
from
the
TEG
dehydration
unit
process
vent
to
the
atmosphere
less
than
0.90
MG/
yr
(
1
tpy).
We
are
further
proposing
that
GACT
for
sources
that
meet
the
cutoffs
described
above
is
no
control.

We
specifically
seek
comment
on
our
proposed
subcategorization
approach
(
including
the
specific
values
for
the
cutoffs)
and
whether
to
proceed
with
subcategorization
in
this
rule.
Pursuant
to
section
112(
d),

EPA
also
has
authority
to
"
distinguish
among
classes,
types,

and
sizes
of
sources
within
a
category
or
subcategory
in
establishing
.
.
.
(
emission)
standards."
CAA
section
112(
d)(
1).

As
an
alternative
to
complying
with
the
control
requirements
mentioned
above,
pollution
prevention
measures,

such
as
process
modifications
or
combinations
of
process
modifications
and
one
or
more
control
device
that
reduce
the
amount
of
HAP
emissions
generated,
are
allowed
provided
they
achieve
the
required
emissions
reductions.

Similarly,
area
sources
would
be
subject
to
the
same
initial
and
continuing
compliance
requirements
as
major
sources
except
that
area
sources
would
be
required
to
submit
periodic
reports
annually,
instead
of
semiannually
as
is
required
for
major
sources.
That
is,
affected
sources
must
submit
Notification
of
Compliance
Status
Reports
annually,
16
inspect/
test
the
closed­
vent
system
and
control
device(
s),

and
establish
monitoring
parameter
values.
Continuing
compliance
requirements
include
submitting
Periodic
Reports,

conducting
annual
inspections
of
closed­
vent
systems,

repairing
leaks
and
defects,
conducting
the
required
monitoring,
and
maintaining
required
records.

As
the
result
of
comments
received
on
the
1998
proposal
on
the
level
of
the
standards
and
how
it
is
to
be
demonstrated,
the
final
major
source
rule
addressed
the
need
for
an
averaging
period
to
accommodate
fluctuations
in
condenser
efficiency
due
to
changes
in
ambient
temperature.

We
also
clarified
in
that
final
rule
that
owners
or
operators
could
be
allowed
to
achieve
a
95
percent
emission
reduction
using
process
modifications
or
combinations
of
process
modifications
and
one
or
more
control
device.
These
changes
are
not
dependent
on
the
amount
of
emissions
at
the
facility,
but
rather
address
practical
considerations
in
complying
with
the
control
standards,
which
are
the
same
for
both
major
and
area
sources.
Therefore,
as
indicated
in
today's
proposal,
we
propose
that
these
provisions
also
apply
to
area
sources.

Today's
supplemental
notice
presents
compliance
dates
for
existing
area
sources
and
new
or
reconstructed
area
sources
for
the
two
proposed
applicability
options
noted
17
above
and
described
in
greater
detail
below.
For
purposes
of
establishing
compliance
dates,
it
should
be
noted
that
the
1998
proposal
applied
only
to
TEG
dehydrators
located
in
urban
areas,
which
are
counties
designated
as
Urban­
1
and
Urban­
2
(
see
supra
note
2).
The
tables
that
follow
present
compliance
dates
for
the
two
alternative
geographic
applicability
options
that
we
are
proposing.
Under
Option
1
all
TEG
dehydration
units
at
area
source
oil
and
natural
gas
production
facilities
would
be
subject
to
the
final
rule.

Under
Option
2,
the
option
we
proposed
in
1998,
only
those
TEG
units
located
in
counties
that
satisfy
the
Urban­
1
or
Urban­
2
county
criteria,
as
described
herein,
would
be
subject
to
the
requirements
of
the
final
rule.

Table
1
of
this
preamble
presents
compliance
dates
for
Option
1.

Table
1
­­
Compliance
Dates
for
Existing
and
New
Sources
for
Applicability
Option
1
For
an
affected
area
source
located
in
a
county
we
classified
as...
Where
the
source
was
constructed/
reconstructed
...
then
the
source
is...
And
the
compliance
date
for
that
source
would
be...

(
a)
urban
based
on
2000
census
data
before
February
6,
1998
existing
3
years
after
the
effective
date
of
the
area
source
standards.
18
(
b)
urban
based
on
2000
census
data
on
or
after
February
6,
1998
new
the
effective
date
of
the
area
source
standards
or
startup,
whichever
is
later.

(
c)
rural
based
on
2000
census
data
before
today's
supplemental
proposal
existing
3
years
after
the
effective
date
of
the
area
source
standards.

(
d)
rural
based
on
2000
census
data
on
or
after
today's
supplemental
proposal
new
the
effective
date
of
the
area
source
standards
or
startup,
whichever
is
later.

With
respect
to
item
(
b)
in
Table
1
above,
we
solicit
comment
on
the
proposed
compliance
date
for
those
sources
located
in
counties
that
were
rural
in
1990
and
became
urban
as
a
result
of
the
2000
decennial
census.
Specifically,
we
solicit
comment
on
whether
the
sources
affected
under
item
(
b)
should
be
considered
new
or
existing,
and
what
the
appropriate
trigger
date
should
be
for
defining
new
source
status.
We
further
solicit
comment
on
the
compliance
deadlines
for
these
sources.

The
list
of
urban
(
i.
e.,
Urban­
1
and
Urban­
2)
and
rural
counties
based
on
1990
U.
S.
Census
Bureau
data
can
be
found
at
http://
www.
epa.
gov/
ttnatw01/
urban/
112kfac.
html).
This
list
can
also
be
found
in
the
docket,
along
with
the
list
of
urban
counties
based
on
2000
U.
S.
Census
Bureau
data
(
Docket
No.
OAR­
2004­
0238).
These
two
lists
can
also
be
found
at
19
the
following
url
as
well:

http://
www.
epa.
gov/
ttn/
atw/
oilgas/
oilgaspg.
html.

For
Option
2,
existing
sources
(
i.
e.,
affected
sources
constructed
before
the
1998
proposal)
must
achieve
compliance
within
3
years
after
the
effective
date
of
the
final
rule,
and
new
sources
(
affected
sources
constructed
on
or
after
the
1998
proposal)
must
comply
on
the
effective
date
of
the
final
rule,
or
startup,
whichever
date
is
later.

Sources
that
are
located
in
a
county
that
meets
the
definition
of
rural
are
not
subject
to
the
requirements
of
the
rule
under
Option
2.

We
recognize
that
where
a
source
is
constructed
in
a
county
that
is
initially
classified
as
rural
and
subsequently
reclassified
as
urban,
the
reclassification
may
occur
after
the
source's
startup
date
or
the
effective
date
of
the
final
rule,
such
that
it
is
impossible
for
the
source
to
meet
the
relevant
compliance
deadline
described
above.

To
account
for
changes
in
urban/
rural
status
that
will
likely
occur
with
each
decennial
census,
EPA
intends,
after
the
issuance
of
the
decennial
census
data,
to
publish
in
the
Federal
Register
an
updated
list
of
counties
that
qualify
as
urban
based
on
the
most
recent
decennial
data.

For
any
new
source
(
i.
e.,
affected
sources
constructed
on
or
after
the
1998
proposal)
located
in
a
county
where
the
classification
of
that
county
changes
from
rural
to
urban
20
based
on
2010
or
a
later
decennial
census,
we
are
proposing
that
the
compliance
deadline
for
such
source
be
the
date
EPA
publishes
the
updated
list
of
urban
counties
in
the
Federal
Register.
We
request
comment
on
whether
this
compliance
deadline
is
appropriate.
For
existing
sources
(
i.
e.,

affected
sources
constructed
before
the
1998
proposal)

located
in
a
county
that
is
redesignated
as
urban
based
on
2010
or
later
census
data,
we
propose
that
the
compliance
date
for
such
sources
be
three
years
after
the
publication
of
the
updated
list
of
counties
in
the
Federal
Register.

As
noted
above,
we
also
solicit
comment
on
how
to
treat
new
sources
that
were
rural
in
1990
and
became
urban
based
on
the
2000
decennial
census
data
and
what
the
compliance
date
for
such
sources
should
be.

In
the
1998
proposal,
we
proposed
that
area
sources
would
be
exempt
from
title
V
permitting
requirements
(
63
FR
6307).
We
do
not
believe
that
the
proposed
applicability
approaches
described
in
today's
notice
alter
the
basis
for
the
proposed
title
V
permit
exemption.
Neither
the
scope
of
geographical
applicability
nor
the
number
of
sources
impacted
by
the
options
change
the
degree
to
which
the
standards
are
implementable
outside
of
a
permit,
and
we,

therefore,
maintain
our
belief
that
the
permit
would
provide
minimal
additional
benefit.
Therefore,
we
propose
to
21
maintain
the
exemption.

III.
Rationale
for
Selecting
the
Proposed
Standards
A.
How
did
we
select
the
source
category?

We
listed
area
source
oil
and
natural
gas
production
facilities
in
July
1999
pursuant
to
112(
c)(
3)
and
112(
k)(
3)(
B)
of
the
CAA
to
ensure
that
area
sources
representing
90
percent
of
the
area
source
emissions
of
the
30
HAP
that
present
the
greatest
threat
to
public
health
in
the
largest
number
of
urban
areas
are
subject
to
regulation
under
section
112.
This
listing
was
based
on
information
showing
that
benzene
emissions
from
the
TEG
dehydration
units
at
area
sources
of
oil
and
natural
gas
production
facilities
contribute
at
least
47
percent
of
the
national
urban
emissions
of
benzene,
one
of
the
30
listed
area
source
HAP,
from
stationary
sources
that
are
area
sources.
Based
on
emission
estimates
ranking
the
area
source
categories,

TEG
dehydration
units
at
area
sources
contributed
the
highest
quantity
of
benzene
of
all
the
source
categories
analyzed
(
see
Docket
No.
A­
97­
44).

B.
How
did
we
select
the
affected
sources
and
emission
points?

The
1999
area
source
listing
in
the
Strategy
was
based
on
emissions
information
showing
that
TEG
dehydration
units
emit
benzene
in
levels
that
contribute
significantly
to
22
nationwide
emissions
of
benzene
from
area
sources
in
urban
areas.
Furthermore,
TEG
dehydration
units
account
for
approximately
90
percent
of
the
HAP
emissions
at
an
oil
and
natural
gas
production
facility.
Therefore,
in
listing
this
area
source
category
in
the
Strategy
in
1999,
EPA
focused
on
regulating
benzene
emissions
from
TEG
dehydration
units.

For
the
same
reasons,
our
1998
proposal
(
and
proposed
area
source
finding)
did
not
include
for
regulation
other
types
of
dehydration
units
or
other
emission
points
at
area
source
oil
and
natural
gas
production
facilities.
Consistent
with
the
1998
proposed
area
source
finding
that
benzene
emissions
from
TEG
dehydration
units
are
the
emission
points
of
concern
for
this
area
source
category,
we
are
maintaining
the
1998
proposed
definition
of
the
affected
source
as
each
TEG
dehydration
unit
located
at
a
facility
that
is
an
area
source
and
that
processes,
upgrades,
or
stores
hydrocarbon
liquids
prior
to
the
point
of
custody
transfer
or
that
processes,
upgrades,
or
stores
natural
gas
prior
to
the
point
at
which
natural
gas
enters
the
natural
gas
transmission
and
storage
source
category
or
is
delivered
to
the
final
end
user.

We
are
seeking
comment
on
the
proposed
applicability
approaches
described
above
as
they
relate
directly
to
the
scope
of
TEG
dehydration
units
at
oil
and
natural
gas
23
production
facilities
that
would
be
subject
to
the
final
rule.

C.
What
changes
to
the
applicability
requirements
for
area
sources
are
part
of
this
supplemental
notice?

The
1998
area
source
proposal
contained
geographical
applicability
criteria
for
area
source
TEG
dehydration
units
that
would
have
limited
the
application
of
area
source
standards
to
those
selected
area
source
TEG
dehydration
units
located
in
counties
we
classified
as
Urban­
1
or
Urban­

2,
referred
to
herein
as
"
urban."

As
stated
earlier,
today,
we
are
proposing
an
alternative
to
the
geographical
applicability
criteria
proposed
in
1998.
If
finalized,
the
1998
criteria
would
require
all
TEG
dehydration
units
at
area
source
oil
and
natural
gas
production
facilities
in
areas
that
meet
the
urban
requirements
to
comply
with
the
final
rule.
See
supra
fn.
2.
The
alternative
option
we
are
proposing
for
the
first
time
today,
if
finalized,
would
require
TEG
dehydration
units
at
area
source
oil
and
natural
gas
production
facilities
in
urban
and
rural
counties
to
comply
with
the
requirements
of
the
final
rule.
In
sum,
we
are
proposing
two
options
for
defining
geographically
the
scope
of
the
area
source
standards.
The
standards
would
apply:

(
1)
in
urban
and
rural
counties;
or
(
2)
in
urban
counties
24
only
(
the
1998
proposal).

In
the
1998
proposal,
we
estimated
that
there
were
37,000
area
source
glycol
dehydrators
in
the
U.
S.,
and
that
TEG
dehydrators
comprised
most
of
that
figure.
Based
on
more
recent
information
from
the
Department
of
Energy
(
DOE)

regarding
the
number
of
oil
and
gas
wells
and
the
amount
of
natural
gas
produced
in
the
U.
S.,
we
have
updated
this
figure
to
approximately
38,000
dehydrators.

Although
we
believe
our
estimate
of
TEG
dehydrator
population
is
reasonable,
we
lack
information
indicating
the
locations
of
most
of
these
units.
Therefore,
in
assessing
the
impacts
of
the
different
applicability
options
being
considered,
we
made
several
assumptions.
Using
DOE
data
from
2003,
we
identified
13
States
where
95
percent
of
the
natural
gas
in
the
U.
S.
is
produced
(
Texas,
New
Mexico,

Oklahoma,
Wyoming,
Louisiana,
Colorado,
Alaska,
Kansas,

California,
Utah,
Michigan,
Alabama
and
Mississippi).

First,
although
Outer
Continental
Shelf
(
OCS)
sources
contribute
over
20
percent
of
the
2003
natural
gas
production
total,
we
assumed
that
none
of
the
sources
on
the
OCS
are
uncontrolled
area
sources
that
would
be
impacted
by
the
final
rule.
This
assumption
is
based
on
a
belief
that
these
sources
are
generally
controlled
through
flares
for
safety
purposes.
Next,
we
assumed
a
uniform
distribution
of
25
sources
by
assigning
95
percent
of
the
estimated
number
of
sources
in
the
13
States
in
proportion
to
their
percentage
of
natural
gas
production.
Finally,
we
assumed
a
linear
distribution
within
each
of
the
13
States
that
is
proportional
to
the
amount
of
geographical
area
encompassed
by
a
given
option
(
i.
e.,
for
an
option
encompassing
areas
covering
20
percent
of
the
13­
State
landmass
would
contain
20
percent
of
the
area
source
glycol
dehydrators).
We
realize
this
approach
does
not
yield
precise
results
for
determining
affected
facility
populations
for
individual
options,
and
it
assumes
a
uniform
distribution
of
sources
between
rural
and
urban
areas,
but
we
believe
it
is
useful
for
comparing
different
options
and
estimating
the
number
of
potentially
affected
units.

The
urban/
rural
classification
status
of
some
counties
may
change
every
10
years
as
the
population
is
reassessed
by
the
U.
S.
Census
Bureau.
These
changes
occur
with
increases
in
U.
S.
population
and
also
with
population
relocation.

These
changes
may
cause
land
area
classifications
to
change
from
one
where
the
rule
would
not
apply
to
a
classification
where
it
would
apply.
The
reverse
case
is
also
a
possibility
although
we
would
expect
such
a
scenario
to
be
infrequent.

For
the
urban
county
option,
sources
would
be
required
26
3
We
do
not
believe
that
the
GACT
analysis
and
subcategorization
of
TEG
dehydration
units
described
above
would
change
based
on
the
applicability
option
selected
in
the
final
rule.
to
determine
the
final
rule's
applicability
based
on
data
from
the
latest
decennial
census.
Based
on
the
latest
decennial
data,
sources
in
urban
counties
would
be
required
to
comply
with
the
requirements
of
the
final
rule.
We
would
recommend
that
those
sources
not
subject
to
requirements
of
the
final
rule
document
their
status
and
retain
a
record
of
their
finding.
We
further
recommend
that
all
sources
in
rural
counties
reconfirm
their
status
related
to
geographical
location
within
6
months
after
the
release
of
the
latest
decennial
census
results.

Proposed
Applicability
Options3
Option
1:

Under
option
1,
all
TEG
dehydrators
at
area
source
oil
and
natural
gas
production
facilities
would
be
subject
to
the
final
rule.
This
applicability
option
provides
a
HAP
reduction
of
approximately
14,700
Mg/
yr
(
16,400
tpy)
and
requires
an
estimated
2,200
TEG
dehydrators
to
reduce
emissions.

Option
1
would
ensure
that
units
effecting
every
urban
area
would
be
subject
to
regulation.
It
would
also
ensure
that
benzene
is
reduced
in
non­
densely
populated
areas
which
27
can
provide
additional
benefits
since
benzene
is
a
carcinogen
and
a
national
risk
driver
based
on
our
National
Air
Toxics
Assessment
(
NATA).
(
NATA
is
our
program
for
evaluating
air
toxics
in
the
U.
S.
and
involves:
expanding
air
toxics
monitoring,
improving/
updating
emission
inventories,
improving
small
and
large
scale
modeling,
as
well
as
improving
our
knowledge
of
health
effects
and
assessment
tools
(
see
http://
www.
epa.
gov/
ttn/
atw/
nata/
for
additional
information
about
NATA)).
Moreover,
reduction
in
benzene
emissions
from
affected
sources
in
urban
and
rural
counties
brings
us
closer
to
one
goal
of
the
Strategy
(
i.
e.,

to
achieve
a
75
percent
reduction
in
cancer
incidence).

With
this
option,
there
is
no
issue
of
change
in
geographical
applicability
with
decennial
census
updates
(
i.
e.,
neither
the
regulators
nor
the
sources
need
to
be
concerned
with
keeping
track
of
changes
in
the
applicability
of
this
rule
due
to
future
changes
in
population
density).

We
do,
however,
believe
that
option
1
raises
an
issue
because
it
requires
emission
reductions
for
sources
located
in
remote
areas
many
miles
from
densely
populated
areas.
As
noted
above,
GACT
for
lower
emitting
sources
(
i.
e.,
sources
with
either
a
natural
gas
throughput
below
3
MMSCFD
or
emitting
less
than
1
tpy
of
benzene)
is
no
control.
We
estimate
the
annual
compliance
cost
for
this
option
to
be
28
$
39.2
million.

Option
2:

This
option,
which
was
in
the
1998
proposal,
would
provide
HAP
emission
reductions
of
approximately
6,900
Mg/
yr
(
7,700
tpy)
in
counties
with
MSA
populations
exceeding
250,000
people
and
in
counties
where
the
majority
of
people
are
classified
by
the
U.
S.
Census
Bureau
to
live
in
urban
areas
based
on
2000
census
data.
This
applicability
option
would
require
an
estimated
1,050
facilities
to
control
emissions.
Since
this
applicability
option
is
a
countybased
scope,
and
since
the
Urban­
2
county
classification
is
based
on
percentage
of
people
in
urban
areas
within
a
county,
we
believe
changes
in
county
status
from
rural
to
urban
from
one
decennial
census
to
the
next
could
occur
as
densely
settled
areas
grow.
For
determining
initial
applicability,
sources
would
know
immediately
which
facilities
would
be
subject
to
the
emission
reduction
requirements
simply
based
on
county
designation.
However,

the
urban/
rural
designation
provides
an
imperfect
measure
of
population
density
in
the
immediate
vicinity
of
TEG
dehydrators.
Thus,
under
this
option
emission
reductions
may
be
required
from
sources
in
remote
areas
of
counties
meeting
the
urban
criteria
and,
at
the
same
time,
TEG
dehydrators
may
be
located
in
densely
populated
areas
in
29
unregulated
rural
counties.
Thus,
units
located
in
similarly
populated
areas
would
be
regulated
differently
based
on
county
designation.
We
estimate
the
annual
compliance
cost
for
this
applicability
option
to
be
$
18.5
million.

We
specifically
request
comment
on
both
applicability
options
and
on
possible
alternative
approaches
that
might
better
reflect
population
density
and
exposure.
We
also
request
information
related
to
the
locations
of
TEG
dehydration
units
at
area
source
oil
and
natural
gas
production
facilities.

D.
What
changes
are
we
proposing
to
the
startup,
shutdown,

and
malfunction
plan
requirements?

In
the
1998
proposal,
we
proposed
that
owners
and
operators
of
TEG
dehydration
units
subject
to
the
area
source
standards
would
not
be
subject
to
the
requirements
of
40
CFR
63.6(
e)
of
the
General
Provisions
for
developing
and
maintaining
a
startup,
shutdown,
and
malfunction
(
SSM)
plan,

or
the
requirements
of
40
CFR
63.10(
d)
of
the
General
Provisions
for
reporting
actions
not
consistent
with
the
plan.
Rather
than
developing
a
SSM
plan
and
submitting
reports
in
accordance
with
that
plan,
we
proposed
an
alternative
to
the
General
Provisions
where
owners
and
operators
of
affected
area
sources
should
only
submit
30
reports
of
any
malfunctions
that
are
not
corrected
within
2
calendar
days
of
the
malfunction
within
7
days
of
the
subject
malfunction(
s).
It
was
our
intent
that
the
1998
proposal
would
require
only
the
submittal
of
malfunction
reports,
and
not
the
development
and
implementation
of
a
SSM
plan,
and
that
such
an
approach
would
reduce
burden.

Commenters
on
the
1998
proposal
stated
that
submittal
of
malfunction
reports
would
be
burdensome
and
impractical,

particularly
in
remote
locations
that
do
not
have
full
time
operators
onsite.
They
recommended
that
area
sources
be
allowed
to
develop
a
simplified
contingency
plan,
adopt
and
update
the
plan
using
their
notification
of
compliance
status
reports,
and
allow
for
compilation
of
all
events
in
which
special
action
was
taken
that
is
inconsistent
with
the
plan
to
be
submitted
in
monthly
letter
reports.
Commenters
also
suggested
that
sources
be
allowed
more
time
to
correct
malfunctions
and
report
them,
given
the
nature
of
their
operations
and
staffing.

Based
on
these
comments,
we
have
decided
to
follow
the
requirements
of
the
General
Provisions
regarding
SSM
events.

We
believe
that
the
unique
nature
of
unmanned
or
remote
area
source
oil
and
natural
gas
production
facilities
can
best
be
addressed
by
having
owners
or
operators
prepare
an
SSM
plan
that
would
provide
needed
flexibility
of
dealing
with
SSM
31
events
at
these
sites.
The
SSM
plan
could
be
tailored
to
identify
SSM
events
posing
concerns
for
them
and
establish
appropriate
procedures
for
minimizing
emissions
and
making
necessary
repairs
in
the
manner
suitable
for
each
situation.

The
purposes
of
a
SSM
plan
are
to:
ensure
that
the
owner
or
operator
operates
and
maintains
each
affected
source
in
such
a
way
that
minimizes
emissions
in
a
manner
consistent
with
safety
and
good
air
pollution
control
practices,
ensure
that
owners
or
operators
are
prepared
to
correct
malfunctions
as
soon
as
practicable
after
their
occurrence
to
minimize
excess
emissions,
and
reduce
the
reporting
burden
associated
with
SSM
events.
The
submittal
of
separate
SSM
reports
are
only
required
if
actions
taken
during
these
events
are
not
consistent
with
the
plan.
Events
handled
in
accordance
with
the
SSM
plan
are
documented
and
included
with
the
periodic
reports.
For
the
reasons
stated
above,
we
have
revised
the
SSM
provisions
for
area
sources
in
the
1998
proposal
to
require
the
development
and
implementation
of
SSM
plans,
as
opposed
to
malfunction
reports
as
proposed
in
1998.
We
are
proposing
the
same
SSM
requirements
that
we
have
for
major
sources,
except
the
timing
of
periodic
SSM
reports.
Because
we
are
proposing
that
area
sources
submit
annual
rather
than
semiannual
periodic
reports,
which
may
include
periodic
SSM
reports,
area
sources
may
submit
such
reports
annually.
32
IV.
Summary
of
Environmental,
Energy,
Cost,
and
Economic
Impacts
The
environmental
and
cost
impacts
for
the
proposed
options
are
presented
in
Table
3
of
this
preamble:

Table
3.
Summary
of
National
Impacts
for
the
Geographical
Options
for
the
Oil
and
Natural
Gas
Production
NESHAP
Emissions
Reductions
(
Mg/
yr)

No.
of
Controlled
Sources
VOC
HAP
Benzene
Total
Annual
Compliance
Cost
(
million
$/
yr)

Option
1
2,200
28,600
14,700
4,400
39.2
Option
2
1,050
13,700
6,900
2,070
18.5
A.
What
are
the
air
quality
impacts?

For
existing
area
source
TEG
dehydration
units
in
the
oil
and
natural
gas
production
source
category,
we
estimate
that
nationwide
baseline
area
sources
HAP
emissions
are
45,100
Mg/
yr
(
49,600
tpy).
The
standards
being
proposed
with
today's
supplemental
notice
require
that
TEG
dehydration
units
with
a
natural
gas
throughput
greater
than
85
thousand
standard
cubic
meters
per
day
and
benzene
emissions
greater
than
0.90
Mg/
yr
(
1.0
tpy)
achieve
a
95
percent
emission
reduction
either
through
pollution
prevention
process
changes
or
by
installing
a
control
device
(
e.
g.,
condenser).

We
anticipate
that
no
new
area
source
TEG
dehydration
units
will
be
constructed
over
the
next
5
years
based
on
an
33
assumption
that
any
new
sources
constructed
during
this
period
will
be
major
sources.
We
specifically
request
comment
on
this
assumption.
Emission
reduction
requirements
for
new
sources
are
the
same
as
for
existing
sources.

Secondary
environmental
impacts
are
considered
to
be
any
air,
water,
or
solid
waste
impacts,
positive
or
negative,
associated
with
the
implementation
of
the
final
standards.
These
impacts
are
exclusive
of
the
direct
organic
HAP
air
emissions
reductions
discussed
in
the
previous
section.

The
capture
and
control
of
benzene
that
is
presently
emitted
from
area
source
TEG
dehydration
units
will
result
in
a
decrease
in
volatile
organic
compound
(
VOC)
emissions
as
well.
The
estimated
total
VOC
emissions
reductions
shown
above
are
from
a
nationwide
baseline
of
86,500
Mg/
yr
(
95,200
tpy).

Emissions
of
VOC
have
been
associated
with
a
variety
of
health
and
welfare
impacts.
VOC
emissions,
together
with
nitrogen
oxides,
are
precursors
to
the
formation
of
groundlevel
ozone,
or
smog.
Exposure
to
ambient
ozone
is
responsible
for
a
series
of
public
health
impacts,
such
as
alterations
in
lung
capacity
and
aggravation
of
existing
respiratory
disease.
Ozone
exposure
can
also
damage
forests
and
crops.
34
Other
secondary
environmental
impacts
are
those
associated
with
the
operation
of
certain
air
emission
control
devices
(
i.
e.,
flares).
The
adverse
secondary
air
impacts
would
be
minimal
in
comparison
to
the
primary
HAP
reduction
benefits
from
implementing
the
proposed
control
options
for
area
sources.
We
estimate
that
national
annual
increase
of
secondary
air
pollutant
emissions
that
would
result
from
the
use
of
a
flare
to
comply
with
the
proposed
standards
is
less
than
1
Mg/
yr
(
0.24
tpy)
for
sulfur
oxides,

2.2
Mg/
yr
(
2.4
tpy)
for
carbon
monoxide,
and
11
Mg/
yr
(
12
tpy)
for
nitrogen
oxides
based
on
option
1,
which
affects
the
largest
number
of
sources.

B.
What
are
the
cost
impacts?

Since
several
compliance
options
are
available
to
owners/
operators
of
affected
sources,
we
are
not
sure
what
control
method
will
be
employed.
Sources
can
control
emissions
by
routing
emissions
to
a
condenser,
a
flare,
a
process
heater,
or
back
to
the
process
or
by
implementing
pollution
prevention
process
changes.
Some
of
these
options
have
very
low
capital
costs,
however,
for
the
purpose
of
determining
costs,
we
have
assumed
that
90
percent
of
the
affected
sources
utilize
condensers
and
10
percent
use
flares.
For
the
cost
estimates
developed
for
condenser
systems,
we
looked
at
systems
with
and
without
the
use
of
a
35
gas
condensate
glycol
separator
(
GCG
separator
or
flash
tank)
in
TEG
dehydration
system
design.

The
estimated
annual
costs
shown
in
Table
3
of
this
preamble
include
the
capital
cost;
operating
and
maintenance
costs;
the
cost
of
monitoring,
inspection,
recordkeeping,

and
reporting
(
MIRR);
and
any
associated
product
recovery
credits.

C.
What
are
the
economic
impacts?

For
the
1998
proposal,
we
prepared
an
economic
impact
analysis
evaluating
the
impacts
of
the
rule
on
affected
producers,
consumers,
and
society.
The
economic
analysis
focuses
on
the
regulatory
effects
on
the
U.
S.
natural
gas
market
that
is
modeled
as
a
national,
perfectly
competitive
market
for
a
homogenous
commodity.

The
results
of
the
analysis
show
that
the
imposition
of
regulatory
costs
on
the
natural
gas
market
would
result
in
negligible
changes
in
natural
gas
prices,
output,

employment,
foreign
trade,
and
business
closures.
The
price
and
output
changes
as
a
result
of
the
1998
proposed
regulation
were
estimated
to
be
less
than
0.01
percent,

significantly
less
than
observed
market
trends.
Because
we
believe
that
these
assumptions
are
relevant
for
both
applicability
options
described
in
today's
proposal
and
that
the
result
of
the
1998
economic
impact
analysis
resulted
in
36
a
very
low
percent
increase
in
price
and
output
changes,
we
believe
that
imposition
of
regulatory
costs
associated
with
the
proposed
applicability
options
will
result
in
negligible
changes
in
natural
gas
prices,
output,
employment,
foreign
trade,
and
business
closures.

D.
What
are
the
non­
air
environmental
and
energy
impacts?

The
water
impacts
associated
with
the
installation
of
a
condenser
system
for
the
TEG
dehydration
unit
reboiler
vent
would
be
minimal.
This
is
because
the
condensed
water
collected
with
the
hydrocarbon
condensate
can
be
directed
back
into
the
system
for
reprocessing
with
the
hydrocarbon
condensate
or,
if
separated,
combined
with
produced
water
for
disposal
by
reinjection.

Similarly,
the
water
impacts
associated
with
installation
of
a
vapor
control
system
would
be
minimal.

This
is
because
the
water
vapor
collected
along
with
the
hydrocarbon
vapors
in
the
vapor
collection
and
redirect
system
can
be
directed
back
into
the
system
for
reprocessing
with
the
hydrocarbon
condensate
or,
if
separated,
combined
with
the
produced
water
for
disposal
for
reinjection.

Therefore,
we
expect
the
adverse
water
impacts
from
the
implementation
of
control
options
for
either
option
considered
for
proposed
area
source
standards
to
be
minimal.

We
do
not
anticipate
any
adverse
solid
waste
impacts
37
from
the
implementation
of
the
area
source
standards.

Energy
impacts
are
those
energy
requirements
associated
with
the
operation
of
emission
control
devices.
There
would
be
no
national
energy
demand
increase
from
the
operation
of
any
of
the
control
options
analyzed
under
the
proposed
oil
and
natural
gas
production
standards
for
area
sources.
The
proposed
area
source
standards
encourage
the
use
of
emission
controls
that
recover
hydrocarbon
products,
such
as
methane
and
condensate,
that
can
be
used
on­
site
as
fuel
or
reprocessed,
within
the
production
process,
for
sale.
Thus,

both
options
considered
for
proposed
standards
have
a
positive
impact
associated
with
the
recovery
of
nonrenewable
energy
resources.

V.
Statutory
and
Executive
Order
Reviews
A.
Executive
Order
12866:
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,

1993),
we
must
determine
whether
a
regulatory
action
is
"
significant"
and
therefore
subject
to
Office
of
Management
and
Budget
(
OMB)
review
and
the
requirements
of
the
Executive
Order.
The
Order
defines
a
"
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,
adversely
affecting
in
a
material
way
the
38
economy,
a
sector
of
the
economy,
productivity,
competition,

jobs,
the
environment,
public
health
or
safety
in
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
entitlement,
grants,
user
fees,
or
loan
programs
of
the
rights
and
obligations
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,
OMB
has
notified
EPA
that
it
considers
this
a
"
significant
regulatory
action"
within
the
meaning
of
the
Executive
Order.
The
EPA
submitted
this
action
to
OMB
for
review.

Changes
made
in
response
to
OMB
suggestions
or
recommendations
will
be
documented
in
the
public
record.

B.
Paperwork
Reduction
Act
The
OMB
has
previously
approved
the
information
collection
requirements
in
the
existing
major
source
rule
(
40
CFR
part
63,
subpart
HH).
The
information
collection
requirements
in
the
proposed
rule
have
been
submitted
for
approval
to
OMB
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.

3501
et
seq.
The
Information
Collection
Request
(
ICR)
39
document
prepared
by
EPA
has
been
assigned
EPA
ICR
number
1788.07.

The
information
to
be
collected
for
the
area
source
provisions
of
the
Oil
and
Natural
Gas
Production
NESHAP
are
based
on
notification,
recordkeeping,
and
reporting
requirements
in
the
NESHAP
General
Provisions
in
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
the
EPA
pursuant
to
the
recordkeeping
and
reporting
requirements
for
which
a
claim
of
confidentiality
is
made
is
safeguarded
according
to
EPA
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
in
subpart
A
to
40
CFR
part
63.
The
recordkeeping
requirements
require
only
the
specific
information
needed
to
determine
compliance.

The
oil
and
natural
gas
production
NESHAP
require
that
facility
owners
or
operators
retain
records
for
a
period
of
5
years,
which
exceeds
the
3
year
retention
period
contained
in
the
guidelines
in
5
CFR
1320.6.
The
5­
year
retention
40
period
is
consistent
with
the
General
Provisions
of
40
CFR
part
63,
and
with
the
5­
year
records
retention
requirement
in
the
operating
permit
program
under
title
V
of
the
CAA.

All
subsequent
guidelines
have
been
followed
and
do
not
violate
any
of
the
Paperwork
Reduction
Act
guidelines
contained
in
5
CFR
1320.6.

The
burden
and
associated
costs
discussed
here
are
based
on
option
1
since
it
would
affect
the
greatest
number
of
sources
among
the
two
proposed
applicability
options.

The
annual
projected
burden
for
this
information
collection
to
owners
and
operators
of
affected
sources
subject
to
the
final
rule
(
averaged
over
the
first
3
years
after
the
effective
date
of
the
promulgated
rule)
is
estimated
to
be
209,322
labor­
hours
per
year,
with
a
total
annual
cost
of
$
17.1
million
per
year.
These
estimates
include
a
one­
time
performance
test
and
report
(
with
repeat
tests
where
needed):
preparation
of
a
startup,
shutdown,
and
malfunction
plan;
immediate
reports
for
any
event
when
the
procedures
in
the
plan
were
not
followed;
annual
compliance
reports;
maintenance
inspections;
notifications;
and
recordkeeping.

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
41
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
EPA's
regulations
in
40
CFR
are
listed
in
40
CFR
part
9.

To
comment
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,
EPA
has
established
a
public
docket
for
the
proposed
rule,
which
includes
this
ICR,
under
Docket
ID
number
OAR­
2004­
0238.
Submit
any
comments
related
to
the
ICR
for
the
proposed
rule
to
EPA
and
OMB.
See
ADDRESSES
42
section
at
the
beginning
of
this
notice
for
where
to
submit
comments
to
EPA.
Send
comments
to
OMB
at
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
725
17th
St.,
N.
W.,
Washington,
DC
20503,
Attention:

Desk
Office
for
EPA.
Since
OMB
is
required
to
make
a
decision
concerning
the
ICR
between
30
and
60
days
after
[
INSERT
DATE
OF
PUBLICATION
OF
THE
PROPOSED
RULE
IN
THE
FEDERAL
REGISTER],
a
comment
to
OMB
is
best
assured
of
having
its
full
effect
if
OMB
receives
it
by
[
INSERT
DATE
30
DAYS
AFTER
PUBLICATION
OF
THE
PROPOSED
RULE
IN
THE
FEDERAL
REGISTER].
The
final
rule
will
respond
to
any
OMB
or
public
comments
on
the
information
collection
requirements
contained
in
this
proposal.

C.
Regulatory
Flexibility
Act
The
Regulatory
Flexibility
Act
(
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
the
proposed
43
rule
on
small
entities,
small
entity
is
defined
as:
(
1)
a
small
business
based
on
Small
Business
Administration
size
standards
of
1,500
employees
and
a
mass
throughput
of
75,000
barrels/
day
or
less,
and
4
million
kilowatt­
hours
of
production
or
less,
respectively;
(
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
for­
profit
enterprise
that
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.

After
considering
the
economic
impacts
of
the
proposed
rule
on
small
entities,
I
certify
that
the
proposed
rule
will
not
have
a
significant
impact
on
a
substantial
number
of
small
entities.
While
we
cannot
predict
the
exact
number
of
small
entities
that
will
be
subject
to
the
control
requirements
of
the
final
rule,
the
proposed
rule
provides
that
GACT
for
certain
subcategories
(
85
thousand
m3/
day
(
3
MMSCF/
D))
is
no
control.
That
should
minimize
impacts
on
those
small
businesses
that
operate
area
source
oil
and
natural
gas
production
facilities.
The
proposed
rule
would
require
installation
of
emissions
controls
only
at
facilities
that
operate
a
TEG
dehydration
unit
with
an
average
annual
natural
gas
throughput
of
85
thousand
m3/
day
(
3
MMSCF/
D)
or
higher.
Exempting
potential
sources
under
85
44
thousand
m3/
day
(
3
MMSCF/
D)
will
limit
the
number
of
sources
who
would
have
to
comply
with
the
emission
control
requirements
from
approximately
38,000
potential
sources
to
2,222.

EPA
performed
an
economic
impact
analysis
to
estimate
the
changes
in
product
price
and
production
quantities
for
the
proposed
rule.
However,
sales
and
revenues
data
were
not
readily
available
for
the
affected
industries,
so
EPA
began
its
analysis
by
examining
the
annual
cost
of
control.

The
annual
per
unit
cost
of
compliance
with
the
proposed
rule
would
be
$
17,699.
The
throughput
cost
for
natural
gas
has
experienced
significant
volatility
within
the
past
several
years,
making
a
point
estimate
difficult
to
identify.
Therefore,
EPA
assumed
a
throughput
value
at
the
high
end
of
the
range
of
recent
costs,
at
$
88.29
per
thousand
cubic
meters
($
2.50
per
thousand
cubic
feet),
for
this
analysis.

One
frequently­
used
approach
for
determining
whether
or
not
a
rule
would
have
a
significant
impact
on
a
small
entity
is
to
compare
annualized
control
cost
with
annualized
revenue
from
sales.
Typically,
costs
less
than
1
percent
of
revenues
are
not
considered
as
imposing
a
significant
impact.
In
the
present
case,
the
annual
per­
unit
cost
of
compliance
is
estimated
to
be
$
17,699.
Using
the
45
aforementioned
1
percent
criterion
for
significant
impact,

annual
revenues
would
have
to
be
less
than
$
1,769,900
in
order
for
significant
impact
to
occur.
At
$
88.29
per
thousand
cubic
meters
($
2.50
per
thousand
cubic
feet)
of
throughput,
that
revenue
translates
to
20,046
thousand
cubic
meters
per
year
(
707,960
thousand
cubic
feet
per
year)

throughput,
or
54.9
thousand
m3/
day
(
1.94
MMSCF/
D).
Since
the
cutoff
for
installation
of
emissions
controls
for
the
proposed
rule
is
85
thousand
m3/
day
(
3
MMSCF/
D),
the
Agency
determined
the
annual
cost
of
control
for
those
entities
affected
by
the
proposed
rule
is
not
sufficient
to
generate
a
significant
impact
on
a
substantial
number
of
small
entities.

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
CAA.
In
addition,
as
mentioned
above,
the
natural
gas
throughput
criteria
should
reduce
the
size
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
46
impacts.

D.
Unfunded
Mandates
Reform
Act
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
or
final
rules
with
Federal
mandates
that
may
result
in
expenditures
by
State,
local,
and
tribal
governments,
in
the
aggregate,
or
by
the
private
sector,
of
$
100
million
or
more
in
any
1
year.
Before
promulgating
an
EPA
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
leastburdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
where
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
us
to
adopt
an
alternative
other
than
the
leastcostly
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
47
or
uniquely
affect
small
governments,
including
tribal
governments,
we
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
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
our
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
options
considered
in
today's
proposed
rule
contain
no
Federal
mandate
that
may
result
in
estimated
costs
of
$
100
million
or
more
to
State,

local,
and
tribal
governments,
in
the
aggregate,
or
the
private
sector
in
any
1
year.
The
maximum
total
annual
cost
of
the
proposed
rule
for
any
1
year
has
been
estimated
to
be
less
than
$
40
million.
Thus,
today's
proposed
rule
is
not
subject
to
the
requirements
of
sections
202
and
205
of
the
UMRA.

E.
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
48
implications."
"
Policies
that
have
federalism
implications"

is
defined
in
the
Executive
Order
to
include
regulations
that
have
"
substantial
direct
effects
on
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government."

Today's
proposal
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.
Thus,
Executive
Order
13132
does
not
apply
to
the
proposed
rule.

In
the
spirit
of
Executive
order
13132,
and
consistent
with
our
policy
to
promote
communication
between
us
and
State
and
local
governments,
we
specifically
solicit
comment
on
the
proposed
rule
from
State
and
local
officials.

F.
Executive
Order
13175:
Consultation
and
Coordination
with
Indian
Tribal
Governments
Executive
Order
13175
(
65
FR
67249,
November
6,
2000)

requires
us
to
develop
an
accountable
process
to
ensure
"
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications."
The
proposed
rule
does
not
have
tribal
implications,
as
specified
in
Executive
Order
13175.
49
The
proposed
rule
does
not
significantly
or
uniquely
affect
the
communities
of
Indian
tribal
governments.
We
do
not
know
of
any
area
source
TEG
dehydration
units
owned
or
operated
by
Indian
tribal
governments.
However
if
there
are
any,
the
effect
of
the
proposed
rule
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.
We
specifically
solicit
comment
on
the
proposed
rule
from
tribal
officials.

G.
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
the
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
the
EPA
must
evaluate
the
environmental
health
or
safety
effects
of
the
proposed
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered
by
the
EPA.

The
EPA
interprets
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
50
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.
No
children's
risk
analysis
was
performed
because
no
alternative
technologies
exist
that
would
provide
greater
stringency
at
a
reasonable
cost.
Furthermore,
the
proposed
rule
has
been
determined
not
to
be
"
economically
significant"
as
defined
under
Executive
Order
12866.

H.
Executive
Order
13211:
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
This
rule
is
not
a
"
significant
energy
action"
as
defined
in
Executive
Order
13211,
"
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,

Distribution,
or
Use"
(
66
FR
28355
(
May
22,
2001))
because
it
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy.
Further,
we
have
concluded
that
this
rule
is
not
likely
to
have
any
adverse
energy
effects.

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;
51
15
U.
S.
C.
272
note)
directs
us
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
EPA
to
provide
Congress,
through
annual
reports
to
the
OMB,
with
explanations
when
an
agency
does
not
use
available
and
applicable
voluntary
consensus
standards.

The
proposed
rule
does
not
involve
any
additional
technical
standards.
Therefore,
the
requirements
of
the
NTTAA
do
not
apply
to
this
action.
However,
we
would
like
to
note
that
the
draft
standard
ASTM
Z7420Z,
which
was
cited
in
the
final
Oil
and
Natural
Gas
Production
NESHAP
(
64
FR
32609­
32664,
June
17,
1999)
as
a
potentially
practical
method
to
use
in
lieu
of
EPA
Method
18,
has
now
been
finalized
by
ASTM
and
approved
by
EPA
for
use
in
rules
where
Method
18
is
cited.
This
new
standard
is
ASTM
D6420­

99(
2004),
"
Test
Method
for
Determination
of
Gaseous
Organic
Compounds
by
Direct
Interface
Gas
Chromatography/
Mass
Spectrometry"
and
it
is
appropriate
for
inclusion
in
the
proposed
rule
in
addition
to
EPA
Method
18
codified
at
40
52
CFR
part
60,
Appendix
A,
for
measurement
of
total
organic
carbon,
total
HAP,
total
volatile
HAP,
and
benzene.

Similar
to
EPA's
performance­
based
Method
18,
ASTM
D6420­
99(
2004)
is
also
a
performance­
based
method
for
measurement
of
total
gaseous
organic
compounds.
However,

ASTM
D6420­
99(
2004)
was
written
to
support
the
specific
use
of
highly
portable
and
automated
gas
chromatographs/
mass
spectrometers
(
GC/
MS).
While
offering
advantages
over
the
traditional
Method
18,
the
ASTM
method
does
allow
some
less
stringent
criteria
for
accepting
GC/
MS
results
than
required
by
Method
18.
Therefore,
ASTM
D6420­
99(
2004)
is
a
suitable
alternative
to
Method
18
only
where:
(
1)
the
target
compound(
s)
are
those
listed
in
Section
1.1
of
ASTM
D6420­

99(
2004),
and
(
2)
the
target
concentration
is
between
150
ppbv
and
100
ppmv.
For
target
compound(
s)
not
listed
in
Section
1.1
of
ASTM
D6420­
99(
2004),
but
potentially
detected
by
mass
spectrometry,
the
proposed
rule
specifies
that
the
additional
system
continuing
calibration
check
after
each
run,
as
detailed
in
Section
10.5.3
of
the
ASTM
method,
must
be
followed,
met,
documented,
and
submitted
with
the
data
report
even
if
there
is
no
moisture
condenser
used
or
the
compound
is
not
considered
water
soluble.
For
target
compound(
s)
not
listed
in
Section
1.1
of
ASTM
D6420­

99(
2004),
and
not
amenable
to
detection
by
mass
53
spectrometry,
ASTM
D6420­
99(
2004)
does
not
apply.

As
a
result,
EPA
will
allow
ASTM
D6420­
99
for
use
with
the
proposed
rule.
The
EPA
will
also
allow
Method
18
as
an
option
in
addition
to
ASTM
D6420­
99(
2004).
This
will
allow
the
continued
use
of
GC
configurations
other
than
GC/
MS.

Under
§
§
63.7(
f)
and
63.8(
f)
of
40
CFR
part
63,
subpart
A
of
the
General
Provisions,
a
source
may
apply
to
EPA
for
permission
to
use
alternative
test
methods
or
alternative
monitoring
requirements
in
place
of
any
of
the
EPA
testing
methods,
performance
specifications,
or
procedures.
NESHAP
for
Oil
and
Natural
Gas
Production
­
Supplemental
notice
of
proposed
rulemaking
­
Page
54
of
77
List
of
Subjects
in
40
CFR
Part
63
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Hazardous
substances,

Intergovernmental
relations,
Recordkeeping
and
reporting
requirements.

Dated:

Stephen
L.
Johnson,
Administrator.
55
For
the
reasons
set
forth
in
the
preamble,
title
40,
chapter
I,
part
63
of
the
Code
of
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.

Subpart
A
[
AMENDED]

2.
Revise
§
63.14(
b)(
29)
to
read
as
follows:

§
63.14
Incorporations
by
reference.

*
*
*
*
*

(
b)
*
*
*

(
29)
ASTM
D6420­
99(
2004),
Test
Method
for
Determination
of
Gaseous
Organic
Compounds
by
Direct
Interface
Gas
Chromatography/
Mass
Spectrometry,
IBR
approved
for
§
§
63.772(
a)(
1)(
ii),
63.5799
and
63.5850.

Subpart
HH
[
AMENDED]

3.
Section
63.760
is
amended
to:

a.
Revise
the
first
and
fourth
sentences
of
paragraph
(
a)(
1)
introductory
text;

b.
Revise
paragraph
(
b)
introductory
text;

c.
Add
paragraph
(
b)(
5);

d.
Revise
paragraph
(
f)
introductory
text;

e.
Revise
paragraphs
(
f)(
1)
and
(
f)(
2);
56
f.
Add
paragraphs
(
f)(
3)
through
(
6);

g.
Revise
the
first
sentence
of
paragraph
(
g)

introductory
text;
and
f.
Add
a
sentence
to
paragraph
(
h)
to
read
as
follows:

§
63.760
Applicability
and
designation
of
affected
source.

(
a)
*
*
*

(
1)
Facilities
that
are
major
or
area
sources
of
hazardous
air
pollutants
(
HAP)
as
defined
in
§
63.761.

Emissions
for
major
source
determination
purposes
can
be
estimated
using
the
maximum
natural
gas
or
hydrocarbon
liquid
throughput,
as
appropriate,
calculated
in
paragraphs
(
a)(
1)(
i)
through
(
iii)
of
this
section.
As
an
alternative
to
calculating
the
maximum
natural
gas
or
hydrocarbon
liquid
throughput,
the
owner
or
operator
of
a
new
or
existing
source
may
use
the
facility's
design
maximum
natural
gas
or
hydrocarbon
liquid
throughput
to
estimate
the
maximum
potential
emissions.
Other
means
to
determine
the
facility's
major
source
status
are
allowed,
provided
the
information
is
documented
and
recorded
to
the
Administrator's
satisfaction.
A
facility
that
is
determined
to
be
an
area
source,
but
subsequently
increases
its
emissions
or
its
potential
to
emit
above
the
major
source
levels
(
without
first
obtaining
and
complying
with
other
limitations
that
keep
its
potential
to
emit
HAP
below
major
57
source
levels)
and
becomes
a
major
source,
must
comply
thereafter
with
all
provisions
of
this
subpart
applicable
to
a
major
source
starting
on
the
applicable
compliance
date
specified
in
paragraph
(
f)
of
this
section.
Nothing
in
this
paragraph
is
intended
to
preclude
a
source
from
limiting
its
potential
to
emit
through
other
appropriate
mechanisms
that
may
be
available
through
the
permitting
authority.

*
*
*
*
*

(
b)
The
affected
sources
to
which
the
provisions
of
this
subpart
apply
shall
comprise
each
emission
point
located
at
a
facility
that
meets
the
criteria
specified
in
paragraph
(
a)
of
this
section
and
listed
in
paragraphs
(
b)(
1)
through
(
4)
of
this
section
for
major
sources
and
paragraph
(
b)(
5)
of
this
section
for
area
sources.

*
*
*
*
*

(
5)
For
area
sources,
the
affected
source
includes
each
triethylene
glycol
dehydration
unit
located
at
a
facility
that
meets
the
criteria
specified
in
paragraph
(
a)

of
this
section.

*
*
*
*
*

(
f)
The
owner
or
operator
of
an
affected
major
source
shall
achieve
compliance
with
the
provisions
of
this
subpart
by
the
dates
specified
in
paragraphs
(
f)(
1)
and
(
2)
of
this
section.
The
owner
or
operator
of
an
affected
area
source
58
shall
achieve
compliance
with
the
provisions
of
this
subpart
by
the
dates
specified
in
paragraphs
(
f)(
3)
through
(
6)
of
this
section.

(
1)
The
owner
or
operator
of
an
affected
major
source,

the
construction
or
reconstruction
of
which
commenced
before
February
6,
1998,
shall
achieve
compliance
with
the
applicable
provisions
of
this
subpart
no
later
than
June
17,

2002
except
as
provided
for
in
§
63.6(
i).
*
*
*

(
2)
The
owner
or
operator
of
an
affected
major
source,

the
construction
or
reconstruction
of
which
commences
on
or
after
February
6,
1998,
shall
achieve
compliance
with
the
applicable
provisions
of
this
subpart
immediately
upon
initial
startup
or
June
17,
1999,
whichever
date
is
later.
*

*
*

Option
1
for
paragraphs
(
f)(
3)
through
(
6):

(
3)
The
owner
or
operator
of
an
affected
area
source
located
in
an
urban
area,
as
defined
in
§
63.761,
the
construction
or
reconstruction
of
which
commences
before
February
6,
1998,
shall
achieve
compliance
with
the
provisions
of
this
subpart
no
later
than
3
years
after
the
date
of
publication
of
the
final
rule
in
the
Federal
Register
except
as
provided
for
in
§
63.6(
i).

(
4)
The
owner
or
operator
of
an
affected
area
source
located
in
an
urban
area,
as
defined
in
§
63.761,
the
59
construction
or
reconstruction
of
which
commences
on
or
after
February
6,
1998,
shall
achieve
compliance
with
the
provisions
of
this
subpart
immediately
upon
initial
startup
or
date
of
publication
of
the
final
rule
in
the
Federal
Register,
whichever
date
is
later.

(
5)
The
owner
or
operator
of
an
affected
area
source
located
in
a
rural
area,
as
defined
in
§
63.761,
the
construction
or
reconstruction
of
which
commences
before
[
INSERT
DATE
OF
PUBLICATION
OF
THE
PROPOSED
RULE
IN
THE
FEDERAL
REGISTER]
shall
achieve
compliance
with
the
provisions
of
this
subpart
no
later
than
3
years
after
the
date
of
publication
of
the
final
rule
in
the
Federal
Register
except
as
provided
for
in
§
63.6(
i).

(
6)
The
owner
or
operator
of
an
affected
area
source
located
in
a
rural
area,
as
defined
in
§
63.761,
the
construction
or
reconstruction
of
which
commences
on
or
after
[
INSERT
DATE
OF
PUBLICATION
OF
THE
PROPOSED
RULE
IN
THE
FEDERAL
REGISTER]
shall
achieve
compliance
with
the
provisions
of
this
subpart
immediately
upon
initial
startup
or
date
of
publication
of
the
final
rule
in
the
Federal
Register,
whichever
date
is
later.

*
*
*
*
*

Option
2
for
paragraphs
(
f)(
3)
through
(
6):

(
3)
Except
as
otherwise
provided
in
paragraph
(
f)(
5)
of
60
this
section,
the
owner
or
operator
of
an
affected
area
source,
the
construction
or
reconstruction
of
which
commenced
before
February
6,
1998,
shall
achieve
compliance
with
the
applicable
provisions
of
this
subpart
no
later
than
three
years
after
the
date
of
publication
of
the
final
rule
in
the
Federal
Register
except
as
provided
for
in
§
63.6(
i).

(
4)
Except
as
otherwise
provided
in
paragraph
(
f)(
6)

of
this
section,
the
owner
or
operator
of
an
affected
area
source,
the
construction
or
reconstruction
of
which
commences
on
or
after
February
6,
1998,
shall
achieve
compliance
with
the
applicable
provisions
of
this
subpart
immediately
upon
startup
or
the
date
of
publication
of
the
final
rule
in
the
Federal
Register,
whichever
date
is
later,

except
as
provided
for
in
§
63.6(
i).

(
5)
If
an
area
source,
the
construction
or
reconstruction
of
which
commenced
before
February
6,
1998,

becomes
an
affected
area
source
due
to
subsequent
county
reclassification
(
based
on
the
most
recent
decennial
census
data)
from
rural
to
urban,
as
defined
in
§
63.761,
the
owner
or
operator
of
such
source
must
comply
with
the
applicable
provisions
of
this
subpart
no
later
than
three
years
after
the
date
of
publication
of
the
updated
list
of
urban
counties
in
the
Federal
Register,
except
as
provided
for
in
§
63.6(
i).
61
(
6)
If
an
area
source,
the
construction
or
reconstruction
of
which
commences
on
or
after
February
6,

1998,
becomes
an
affected
area
source
due
to
subsequent
county
reclassification
(
based
on
the
most
recent
decennial
census
data)
from
rural
to
urban,
as
defined
in
§
63.761,
the
owner
or
operator
of
such
source
must
comply
with
the
applicable
provisions
of
this
subpart
on
the
date
of
publication
of
the
updated
list
of
urban
counties
in
the
Federal
Register,
or
initial
startup,
whichever
date
is
later,
except
as
provided
for
in
§
63.6(
i)

*
*
*
*
*

(
g)
The
following
provides
owners
or
operators
of
an
affected
source
at
a
major
source
with
information
on
overlap
of
this
subpart
with
other
regulations
for
equipment
leaks.
*
*
*

*
*
*
*
*

(
h)
*
*
*
Unless
otherwise
required
by
law,
the
owner
or
operator
of
an
area
source
subject
to
the
provisions
of
this
subpart
is
exempt
from
the
permitting
requirements
established
by
40
CFR
part
70
or
40
CFR
part
71.

*
*
*
*
*

4.
Section
63.761
is
amended
by
adding,
in
alphabetical
order,
the
definitions
of
"
rural
area"
and
"
urban
area"
to
read
as
follows:
62
§
63.761
Definitions.

*
*
*
*
*

Rural
area
means
a
county
not
defined
as
an
urban
area.

*
*
*
*
*

Option
1
for
the
definition
of
"
urban
area":

Urban
area
is
defined
by
use
of
the
2000
U.
S.
Census
Bureau
statistical
decennial
census
data
to
classify
designated
counties
in
the
U.
S.
into
one
of
two
classifications:

(
1)
Urban­
1
areas
which
are
counties
that
contain
a
part
of
a
metropolitan
statistical
area
with
a
population
greater
than
250,000;

(
2)
Urban­
2
areas
which
are
counties
where
more
than
50
percent
of
the
population
is
classified
by
the
U.
S.
Census
Bureau
as
urban.

*
*
*
*
*

Option
2
for
the
definition
of
"
urban
area":

Urban
area
is
defined
by
use
of
the
most
current
U.
S.

Census
Bureau
statistical
decennial
census
data
to
classify
designated
counties
in
the
U.
S.
into
one
of
two
classifications:

(
1)
Urban­
1
areas
which
are
counties
that
contain
a
part
of
a
metropolitan
statistical
area
with
a
population
greater
than
250,000;
63
(
2)
Urban­
2
areas
which
are
counties
where
more
than
50
percent
of
the
population
is
classified
by
the
U.
S.
Census
Bureau
as
urban.

*
*
*
*
*

5.
Section
63.764
is
amended
to:

a.
Add
paragraph
(
d);

b.
Revise
paragraph
(
e)(
1),
introductory
text;
and
c.
Add
paragraph
(
g)
to
read
as
follows:

§
63.764
General
standards.

*
*
*
*
*

(
d)
Except
as
specified
in
paragraph
(
e)(
1)
of
this
section,
the
owner
or
operator
of
an
affected
source
located
at
an
existing
or
new
area
source
of
HAP
emissions
shall
comply
with
the
standards
in
this
subpart
as
specified
in
paragraphs
(
d)(
1)
through
(
3)
of
this
section.

(
1)
The
control
requirements
for
glycol
dehydration
unit
process
vents
specified
in
§
63.765;

(
2)
The
monitoring
requirements
specified
in
§
63.773;

and
(
3)
The
recordkeeping
and
reporting
requirements
specified
in
§
§
63.774
and
63.775.

*
*
*
*
*

(
e)
*
*
*

(
1)
The
owner
or
operator
is
exempt
from
the
64
requirements
of
paragraphs
(
c)(
1)
and
(
d)
of
this
section
if
the
criteria
listed
in
paragraphs
(
e)(
1)(
i)
or
(
ii)
of
this
section
are
met,
except
that
the
records
of
the
determination
of
these
criteria
must
be
maintained
as
required
in
§
63.774(
d)(
1).

*
*
*
*
*

(
g)
Unless
otherwise
required
by
law,
the
owner
or
operator
of
an
area
source
subject
to
the
provisions
of
this
subpart
is
exempt
from
the
permitting
requirements
established
by
40
CFR
part
70
or
part
71.

(
h)
[
Reserved]

*
*
*
*
*

6.
Section
63.765
is
amended
by
revising
paragraph
(
a)

to
read
as
follows:

§
63.765
Glycol
dehydration
unit
process
vent
standards.

(
a)
This
section
applies
to
each
glycol
dehydration
unit
subject
to
this
subpart
with
an
actual
annual
average
natural
gas
flowrate
equal
to
or
greater
than
85
thousand
standard
cubic
meters
per
day,
and
with
actual
average
benzene
glycol
dehydration
unit
process
vent
emissions
equal
to
or
greater
than
0.90
megagrams
per
year,
that
must
be
controlled
for
HAP
emissions
as
specified
in
either
paragraph
(
c)(
1)(
i)
or
paragraph
(
d)(
1)
of
§
63.764.

*
*
*
*
*
65
7.
Section
63.772
is
amended
to:

a.
Revise
paragraph
(
a)(
1)
introductory
text;

b.
Add
paragraphs
(
a)(
1)(
i)
and
(
ii);

c.
Revise
the
first
sentence
of
paragraph
(
b)(
2)(
ii);

d.
Revise
paragraph
(
e)(
3)(
iii)
introductory
text,

e.
Revise
paragraph
(
e)(
3)(
iii)(
B)(
2);
and
f.
Revise
the
first
and
second
sentences
of
paragraph
(
e)(
iv)
introductory
text
to
read
as
follows:

§
63.772
Test
methods,
compliance
procedures,
and
compliance
demonstrations.

(
a)
*
*
*

(
1)
For
a
piece
of
ancillary
equipment
and
compressors
to
be
considered
not
in
VHAP
service,
it
must
be
determined
that
the
percent
VHAP
content
can
be
reasonably
expected
never
to
exceed
10.0
percent
by
weight.
For
the
purposes
of
determining
the
percent
VHAP
content
of
the
process
fluid
that
is
contained
in
or
contacts
a
piece
of
ancillary
equipment
or
compressor,
you
shall
use
the
method
in
either
paragraph
(
a)(
1)(
i)
or
(
ii)
of
this
section.

(
i)
Method
18
of
40
CFR
part
60,
appendix
A;
or
(
ii)
ASTM
D6420­
99(
2004),
Standard
Test
Method
for
Determination
of
Gaseous
Organic
Compounds
by
Direct
Interface
Gas
Chromatography­
Mass
Spectrometry
(
incorporated
by
reference
 
see
§
63.14),
provided
that
the
66
provisions
of
paragraphs
(
A)
through
(
D)
of
this
section
are
followed:

(
A)
The
target
compound(
s)
are
those
listed
in
section
1.1
of
ASTM
D6420­
99(
2004);

(
B)
The
target
concentration
is
between
150
parts
per
billion
by
volume
and
100
parts
per
million
by
volume;

(
C)
For
target
compound(
s)
not
listed
in
Table
1.1
of
ASTM
D6420­
99(
2004),
but
potentially
detected
by
mass
spectrometry,
the
additional
system
continuing
calibration
check
after
each
run,
as
detailed
in
section
10.5.3
of
ASTM
D6420­
99(
2004),
is
conducted,
met,
documented,
and
submitted
with
the
data
report,
even
if
there
is
no
moisture
condenser
used
or
the
compound
is
not
considered
water
soluble;
and
(
D)
For
target
compound(
s)
not
listed
in
Table
1.1
of
ASTM
D6420­
99(
2004),
and
not
amenable
to
detection
by
mass
spectrometry,
ASTM
D6420­
99(
2004)
may
not
be
used.

*
*
*
*
*

(
b)
*
*
*

(
2)
*
*
*

(
ii)
The
owner
or
operator
shall
determine
an
average
mass
rate
of
benzene
emissions
in
kilograms
per
hour
through
direct
measurement
using
the
methods
in
§
63.772(
a)(
1)(
i)
or
(
ii),
or
an
alternative
method
according
to
§
63.7(
f).
*
*
*

*
*
*
*
*
67
(
e)
*
*
*

(
3)
*
*
*

(
iii)
To
determine
compliance
with
the
control
device
percent
reduction
performance
requirement
in
§
63.771(
d)(
1)(
i)(
A),
(
d)(
1)(
ii),
and
(
e)(
3)(
ii),
the
owner
or
operator
shall
use
either
Method
18,
40
CFR
part
60,

appendix
A,
or
Method
25A,
40
CFR
part
60,
appendix
A;
or
ASTM
D6420­
99(
2004)
as
specified
in
§
63.772(
a)(
1)(
ii).

Alternatively,
any
other
method
or
data
that
have
been
validated
according
to
the
applicable
procedures
in
Method
301,
40
CFR
part
63,
appendix
A,
as
specified
in
§
63.7(
f)

may
be
used.
The
following
procedures
shall
be
used
to
calculate
percent
reduction
efficiency:

*
*
*
*
*

(
B)
*
*
*

(
2)
When
the
TOC
mass
rate
is
calculated,
all
organic
compounds
(
minus
methane
and
ethane)
measured
by
Method
18,

40
CFR
part
60,
appendix
A,
or
Method
25A,
40
CFR
part
60,

appendix
A,
or
ASTM
D6420­
99(
2004)
as
specified
in
§
63.772(
a)(
1)(
ii),
shall
be
summed
using
the
equations
in
paragraph
(
e)(
3)(
iii)(
B)(
1)
of
this
section.

*
*
*
*
*

(
iv)
To
determine
compliance
with
the
enclosed
combustion
device
total
HAP
concentration
limit
specified
in
68
§
63.771(
d)(
1)(
i)(
B),
the
owner
or
operator
shall
use
either
Method
18,
40
CFR
part
60,
appendix
A,
or
Method
25A,
40
CFR
part
60,
appendix
A,
or
ASTM
D6420­
99(
2004)
as
specified
in
§
63.772(
a)(
1)(
ii),
to
measure
either
TOC
(
minus
methane
and
ethane)
or
total
HAP.
Alternatively,
any
other
method
or
data
that
have
been
validated
according
to
Method
301
of
appendix
A
of
this
part,
as
specified
in
§
63.7(
f),
may
be
used.
*
*
*

*
*
*
*
*

8.
Section
63.774
is
amended
by
revising
paragraph
(
d)(
1)
introductory
text
to
read
as
follows:

(
d)
*
*
*

(
1)
An
owner
or
operator
that
is
exempt
from
control
requirements
under
§
63.764(
e)(
1)
shall
maintain
the
records
specified
in
paragraph
(
d)(
1)(
i)
or
(
d)(
1)(
ii)
of
this
section,
as
appropriate,
for
each
glycol
dehydration
unit
that
is
not
controlled
according
to
the
requirements
of
paragraph
(
c)(
1)(
i)
or
(
d)(
1)
of
§
63.764.

*
*
*
*
*

9.
Section
63.775
is
amended
to:

a.
Add
paragraph
(
c);

b.
Revise
paragraph
(
e)
introductory
text;
and
c.
Add
paragraph
(
e)(
3)
to
read
as
follows:

§
63.775
Reporting
requirements.
69
*
*
*
*
*

(
c)
Each
owner
or
operator
of
an
area
source
subject
to
this
subpart
for
shall
submit
the
information
listed
in
paragraphs
(
c)(
1)
through
(
6)
of
this
section,
except
as
provided
in
paragraph
(
c)(
7).

(
1)
The
initial
notifications
required
under
§
63.9(
b)(
2)
shall
be
submitted
not
later
than
1
year
following
the
date
of
publication
of
the
final
rule
in
the
Federal
Register.

(
2)
If
an
owner
or
operator
is
required
by
the
Administrator
to
conduct
a
performance
evaluation
for
a
continuous
monitoring
system,
the
date
of
the
performance
evaluation
as
specified
in
§
63.8(
e)(
2).

(
3)
The
planned
date
of
a
performance
test
at
least
60
days
before
the
test
in
accordance
with
§
63.7(
b).
Unless
requested
by
the
Administrator
a
site­
specific
test
plan
is
not
required
by
this
subpart.
If
requested
by
the
Administrator,
the
owner
or
operator
must
submit
the
sitespecific
test
plan
required
by
§
63.7(
c)
with
the
notification
of
the
performance
test.
A
separate
notification
of
the
performance
test
is
not
required
if
it
is
included
in
the
initial
notification
submitted
in
accordance
with
paragraph
(
c)(
1)
of
this
section.

(
4)
A
Notification
of
Compliance
Status
as
described
70
in
paragraph
(
d)
of
this
section.

(
5)
Periodic
reports
as
described
in
paragraph
(
e)(
3)

of
this
section.

(
6)
Startup,
shutdown,
and
malfunction
reports
specified
in
§
63.10(
d)(
5)
shall
be
submitted
as
required.

Separate
startup,
shutdown,
and
malfunction
reports
as
described
in
§
63.10(
d)(
5)
are
not
required
if
the
information
is
included
in
the
Periodic
Report
specified
in
paragraph
(
e)
of
this
section.

(
7)
Each
owner
or
operator
of
a
triethylene
glycol
dehydration
unit
subject
to
this
subpart
that
is
exempt
from
the
control
requirements
for
glycol
dehydration
unit
process
vents
in
§
63.765,
is
exempt
from
all
reporting
requirements
for
area
sources
in
this
subpart,
for
that
unit.

*
*
*
*
*

(
e)
Periodic
Reports.
An
owner
or
operator
of
a
major
source
shall
prepare
Periodic
Reports
in
accordance
with
paragraphs
(
e)(
1)
and
(
2)
of
this
section
and
submit
them
to
the
Administrator.
An
owner
or
operator
of
an
area
source
shall
prepare
Periodic
Reports
in
accordance
with
paragraph
(
e)(
3)
of
this
section
and
submit
them
to
the
Administrator.

*
*
*
*
*

(
3)
An
owner
or
operator
of
an
area
source
shall
prepare
and
submit
Periodic
Reports
in
accordance
with
71
paragraphs
(
e)(
3)(
i)
through
(
iii)
of
this
section.

(
i)
Periodic
reports
must
be
submitted
on
an
annual
basis.
The
first
reporting
period
shall
cover
the
period
beginning
on
the
date
the
Notification
of
Compliance
Status
Report
is
due
and
ending
on
December
31.
The
report
shall
be
submitted
within
30
days
after
the
end
of
the
reporting
period.

(
ii)
Subsequent
reporting
periods
begin
every
January
1
and
end
on
December
31.
Subsequent
reports
shall
be
submitted
within
30
days
following
the
end
of
the
reporting
period.

(
iii)
The
periodic
reports
must
contain
the
information
included
in
paragraph
(
e)(
2)
of
this
section.

*
*
*
*
*

10.
Revise
Table
2
to
subpart
HH
of
part
63
to
read
as
follows:

TABLE
2
TO
SUBPART
HH
OF
PART
63­
 
APPLICABILITY
OF
40
CFR
PART
63
GENERAL
PROVISIONS
TO
SUBPART
HH
General
Provisions
Reference
Applicable
to
subpart
HH
Explanation
§
63.1(
a)(
1)........
Yes
§
63.1(
a)(
2)........
Yes
§
63.1(
a)(
3)........
Yes
§
63.1(
a)(
4)........
Yes
§
63.1(
a)(
5)........
No..............
Section
reserved.

§
63.1(
a)(
6)
through
(
a)(
8).............
Yes
72
§
63.1(
a)(
9)........
No..............
Section
reserved.

§
63.1(
a)(
10).......
Yes
§
63.1(
a)(
11).......
Yes
§
63.1(
a)(
12)
through
(
a)(
14)....
Yes
§
63.1(
b)(
1)........
No..............
Subpart
HH
specifies
applicability.

§
63.1(
b)(
2)........
Yes
§
63.1(
b)(
3)........
No
§
63.1(
c)(
1)........
No..............
Subpart
HH
specifies
applicability.

§
63.1(
c)(
2)........
No
§
63.1(
c)(
3)........
No..............
Section
reserved.

§
63.1(
c)(
4)........
Yes
§
63.1(
c)(
5)........
Yes
§
63.1(
d)...........
No..............
Section
reserved.

§
63.1(
e)...........
Yes
§
63.2..............
Yes
Except
definition
of
major
source
is
unique
for
this
source
category
and
there
are
additional
definitions
in
subpart
HH.

§
63.3(
a)
through
(
c)................
Yes
§
63.4(
a)(
1)
through
(
a)(
3).............
Yes
§
63.4(
a)(
4)........
No..............
Section
reserved.

§
63.4(
a)(
5)........
Yes
§
63.4(
b)...........
Yes
§
63.4(
c)...........
Yes
§
63.5(
a)(
1)........
Yes
§
63.5(
a)(
2)........
No..............
Preconstruction
review
required
only
for
major
sources
that
commence
construction
after
promulgation
of
the
standard.

§
63.5(
b)(
1)........
Yes
73
§
63.5(
b)(
2)........
No..............
Section
reserved.

§
63.5(
b)(
3)........
Yes
§
63.5(
b)(
4)........
Yes
§
63.5(
b)(
5)........
Yes
§
63.5(
b)(
6)........
Yes
§
63.5(
c)...........
No..............
Section
reserved.

§
63.5(
d)(
1)........
Yes
§
63.5(
d)(
2)........
Yes
§
63.5(
d)(
3)........
Yes
§
63.5(
d)(
4)........
Yes
§
63.5(
e)...........
Yes
§
63.5(
f)(
1)........
Yes
§
63.5(
f)(
2)........
Yes
§
63.6(
a)...........
Yes
§
63.6(
b)(
1)........
Yes
§
63.6(
b)(
2)........
Yes
§
63.6(
b)(
3)........
Yes
§
63.6(
b)(
4)........
Yes
§
63.6(
b)(
5)........
Yes
§
63.6(
b)(
6)........
No..............
Section
reserved.

§
63.6(
b)(
7)........
Yes
§
63.6(
c)(
1)........
Yes
§
63.6(
c)(
2)........

§
63.6(
c)(
3)
through
(
c)(
4).............
No..............
Section
reserved.

§
63.6(
c)(
5)........
Yes
§
63.6(
d)...........
No..............
Section
reserved.

§
63.6(
e)...........
Yes
§
63.6(
e)(
1)(
i).....
No..............
Except
as
otherwise
specified.
Addressed
in
§
63.762.

§
63.6(
e)(
1)(
ii)....
Yes
74
§
63.6(
e)(
1)(
iii)...
Yes
§
63.6(
e)(
2)........
Yes
§
63.6(
e)(
3)(
i).....
Yes
§
63.6(
e)(
3)(
i)(
A)..
No..............
Except
as
otherwise
specified.
Addressed
in
§
63.762(
c).

§
63.6(
e)(
3)(
i)(
B)..
Yes
§
63.6(
e)(
3)(
i)(
C)..
Yes
§
63.6(
e)(
3)(
ii)
through
(
3)(
vi)....
Yes
§
63.6(
e)(
3)(
vii)...
Yes
§
63.6(
e)(
3)(
vii)(
A)
...................
Yes
§
63.6(
e)(
3)(
vii)(
B)
...................
Yes.............
Except
that
the
plan
must
provide
for
operation
in
compliance
with
§
63.762(
c).

§
63.6(
f)(
1)........
Yes
§
63.6(
f)(
2)........
Yes
§
63.6(
f)(
3)........
Yes
§
63.6(
g)...........
Yes
§
63.6(
h)...........
No
Subpart
HH
does
not
contain
opacity
or
visible
emission
standards.

§
63.6(
i)(
1)
through
(
i)(
14)............
Yes
§
63.6(
i)(
15).......
No
Section
reserved.

§
63.6(
i)(
16).......
Yes
§
63.6(
j)...........
Yes
§
63.7(
a)(
1)........
Yes
§
63.7(
a)(
2)........
Yes.............
But
the
performance
test
results
must
be
submitted
within
180
days
after
the
compliance
date.

§
63.7(
a)(
3)........
Yes
§
63.7(
b)...........
Yes
§
63.7(
c)...........
Yes
75
§
63.7(
d)...........
Yes
§
63.7(
e)(
1)........
Yes
§
63.7(
e)(
2)........
Yes
§
63.7(
e)(
3)........
Yes
§
63.7(
e)(
4)........
Yes
§
63.7(
f)...........
Yes
§
63.7(
g)...........
Yes
§
63.7(
h)...........
Yes
§
63.8(
a)(
1)........
Yes
§
63.8(
a)(
2)........
Yes
§
63.8(
a)(
3)........
No..............
Section
reserved.

§
63.8(
a)(
4)........
Yes
§
63.8(
b)(
1)........
Yes
§
63.8(
b)(
2)........
Yes
§
63.8(
b)(
3)........
Yes
§
63.8(
c)(
1)........
Yes
§
63.8(
c)(
2)........
Yes
§
63.8(
c)(
3)........
Yes
§
63.8(
c)(
4)........
No
§
63.8(
c)(
5)
through
(
c)(
8).............
Yes
§
63.8(
d)...........
Yes
§
63.8(
e)...........
Yes.............
Subpart
HH
does
not
specifically
required
continuous
emissions
monitor
performance
evaluation,
however,
the
Administrator
can
request
that
one
be
conducted.

§
63.8(
f)(
1)
through
(
f)(
5).............
Yes
§
63.8(
f)(
6)........
No..............
Subpart
HH
does
not
require
continuous
emissions
monitoring.

§
63.8(
g)...........
No..............
Subpart
HH
specifies
continuous
monitoring
system
data
reduction
requirements.
76
§
63.9(
a)...........
Yes
§
63.9(
b)(
1)........
Yes
§
63.9(
b)(
2)........
Yes.............
Existing
sources
are
given
1
year
(
rather
than
120
days)
to
submit
this
notification.

§
63.9(
b)(
3)........
Yes
§
63.9(
b)(
4)........
Yes
§
63.9(
b)(
5)........
Yes
§
63.9(
c)...........
Yes
§
63.9(
d)...........
Yes
§
63.9(
e)...........
Yes
§
63.9(
f)...........
Yes
§
63.9(
g)...........
Yes
§
63.9(
h)(
1)
through
(
h)(
3).............
Yes
§
63.9(
h)(
4)........
No..............
Section
reserved.

§
63.9(
h)(
5)
through
(
h)(
6).............
Yes
§
63.9(
i)...........
Yes
§
63.9(
j)...........
Yes
§
63.10(
a)..........
Yes
§
63.10(
b)(
1).......
Yes.............
§
63.774(
b)(
1)
requires
sources
to
maintain
the
most
recent
12
months
of
data
on
site
and
allows
offsite
storage
for
the
remaining
4
years
of
data.

§
63.10(
b)(
2).......
Yes
§
63.10(
b)(
3).......
No..............
Section
reserved.

§
63.10(
c)(
1).......
Yes
§
63.10(
c)(
2)
through
(
c)(
4).....
No..............
Sections
reserved.

§
63.10(
c)(
5)
through
(
c)(
8).....
Yes
§
63.10(
c)(
9).......
No..............
Section
reserved.

§
63.10(
c)(
10)
through
(
c)(
15)....
Yes
77
§
63.10(
d)(
1).......
Yes
§
63.10(
d)(
2).......
Yes
§
63.10(
d)(
3).......
Yes
§
63.10(
d)(
4).......
Yes
§
63.10(
d)(
5).......
Yes.............
Subpart
HH
requires
major
sources
to
submit
a
startup,
shutdown
and
malfunction
report
semi­
annually.

§
63.10(
e)(
1).......
Yes
§
63.10(
e)(
2).......
Yes
§
63.10(
e)(
3)(
i)....
Yes.............
Subpart
HH
requires
major
sources
to
submit
Periodic
Reports
semi­
annually.
Area
sources
are
required
to
submit
Periodic
Reports
annually.

§
63.10(
e)(
3)(
i)(
A)
...................
Yes
§
63.10(
e)(
3)(
i)(
B)
...................
Yes
§
63.10(
e)(
3)(
i)(
C)
...................
No..............
Subpart
HH
does
not
require
quarterly
reporting
for
excess
emissions.

§
63.10(
e)(
3)(
ii)
through
(
viii).....
Yes
§
63.10(
f)..........
Yes
§
63.11(
a)
and
(
b)..
Yes
§
63.12(
a)
through
(
c)................
Yes
§
63.13(
a)
through
(
c)................
Yes
§
63.14(
a)
and
(
b)..
Yes
§
63.15(
a)
and
(
b)..
Yes
