Document ID: EPA-HQ-OAR-2004-0055-0002
Agency: epa
Document Type: Notice
Title: 1995 Federal Register Notice: National Emission Standards for Hazardous Air Pollutants:  Petroleum Refineries; Preamble, Part 1 of 1995
Posted Date: 2004-05-10T04:00Z

U.
S.
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Parts
60
and
63
[
AD­
FRL
]

RIN
2060­
AD94
National
Emission
Standards
for
Hazardous
Air
Pollutants:
Petroleum
Refineries
AGENCY:
U.
S.
Environmental
Protection
Agency
(
EPA).

ACTION:
Final
rule.

SUMMARY:
This
final
rule
promulgates
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
for
petroleum
refineries.
This
rule
implements
section
112
of
the
Clean
Air
Act
(
Act)
and
are
based
on
the
Administrator's
determination
that
petroleum
refineries
emit
organic
hazardous
air
pollutants
(
HAP's)
identified
on
the
EPA's
list
of
189
HAP's.
The
petroleum
refinery
NESHAP
requires
petroleum
refineries
located
at
major
sources
to
meet
emission
standards
reflecting
the
application
of
the
maximum
achievable
control
technology
(
MACT),
consistent
with
sections
112(
d)
and
(
h)
of
the
Act.
The
petroleum
refinery
affected
source
is
defined
to
include
petroleum
refinery
process
units,
marine
tank
vessel
loading
operations,
and
gasoline
loading
rack
operations
classified
under
Standard
Industrial
Classification
(
SIC)
code
2911
emission
points
located
at
petroleum
refineries.
The
petroleum
refinery
affected
source
and
source
category
description
are
revised
to
reflect
the
inclusion
of
these
emission
points.
2
This
action
also
amends
two
standards
of
performance
for
two
stationary
sources:
standards
of
performance
for
equipment
leaks
of
volatile
organic
compounds
(
VOC)
in
the
synthetic
organic
chemicals
manufacturing
industry
(
SOCMI);

and
standards
of
performance
for
VOC
emissions
from
petroleum
refinery
wastewater
systems.
The
amended
standards
were
previously
promulgated
under
section
111
of
the
Act.

EFFECTIVE
DATE:
[
Insert
date
of
publication
in
the
Federal
Register
here.]
See
the
Supplementary
Information
section
concerning
judicial
review.

ADDRESSES:
Docket.
Docket
No.
A­
93­
48,
containing
information
considered
by
the
EPA
in
development
of
the
promulgated
standards,
is
available
for
public
inspection
between
8:
00
a.
m.
and
4:
00
p.
m.,
Monday
through
Friday
except
for
Federal
holidays,
at
the
following
address:

U.
S.
Environmental
Protection
Agency,
Air
and
Radiation
Docket
and
Information
Center
(
MC­
6102),
401
M
Street
SW,

Washington
DC
20460;
telephone:
(
202)
260­
7548.
The
docket
is
located
at
the
above
address
in
Room
M­
1500,
Waterside
Mall
(
ground
floor).
A
reasonable
fee
may
be
charged
for
copying.

Response
to
Comment
Document.
The
response
to
comment
document
for
the
promulgated
standards
may
be
obtained
from
the
U.
S.
EPA
Library
(
MD­
35),
Research
Triangle
Park,
North
Carolina
27711,
telephone
(
919)
541­
2777;
or
from
the
3
National
Technical
Information
Services,
5285
Port
Royal
Road,
Springfield,
Virginia
22151,
telephone
(
703)
487­
4650.

Please
refer
to
"
National
Emission
Standards
for
Hazardous
Air
Pollutants,
Petroleum
Refineries­
Background
Information
for
Final
Standards,
Summary
of
Public
Comments
and
Responses"
(
EPA
No­
453/
R­
95­
015b).
The
document
contains:

(
1)
A
summary
of
all
the
public
comments
made
on
the
proposed
standards
and
the
Administrator's
response
to
the
comments;
and
(
2)
a
summary
of
the
changes
made
to
the
standards
since
proposal.
This
document
is
also
available
for
downloading
from
the
Technology
Transfer
Network
(
see
below)
under
the
Clean
Air
Act,
Recently
Signed
Rules.

Technology
Transfer
Network.
The
Technology
Transfer
Network
is
one
of
the
EPA's
electronic
bulletin
boards.
The
Technology
Transfer
Network
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.
The
service
is
free
except
for
the
cost
of
a
phone
call.
Dial
(
919)
541­
5472
for
up
to
a
14,400
bps
modem.
If
more
information
on
the
Technology
Transfer
Network
is
needed
call
the
HELP
line
at
(
919)
541­
5384.

FOR
FURTHER
INFORMATION
CONTACT:
For
information
concerning
the
final
standards,
contact
Mr.
James
Durham,
Waste
and
Chemical
Processes
Group,
Emission
Standards
Division
(
MD­
13),
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
North
Carolina,
27711,
telephone
number
(
919)
541­
5672.
4
SUPPLEMENTARY
INFORMATION:
Judicial
Review.
National
emission
standards
for
HAP's
for
petroleum
refineries
were
proposed
in
the
Federal
Register
(
FR)
on
July
15,
1994
(
59
FR
36130).
This
Federal
Register
action
announces
the
EPA's
final
decisions
on
the
rule.
Under
section
307(
b)(
1)

of
the
Act,
judicial
review
of
the
NESHAP
is
available
only
by
the
petition
for
review
in
the
U.
S.
Court
of
Appeals
for
the
District
of
Columbia
Circuit
within
60
days
of
today's
publication
of
this
final
rule.
Under
section
307(
b)(
2)
of
the
Act,
the
requirements
that
are
the
subject
of
today's
notice
may
not
be
challenged
later
in
civil
or
criminal
proceedings
brought
by
the
EPA
to
enforce
these
requirements.

The
following
outline
is
provided
to
aid
in
reading
the
preamble
to
the
final
regulation.

I.
Background
II.
Summary
of
Considerations
in
Developing
the
Rule
A.
Purpose
of
Regulation
B.
Technical
Basis
of
Regulation
C.
Stakeholder
and
Public
Participation
III.
Summary
of
Promulgated
Standards
A.
Miscellaneous
Process
Vent
Provisions
B.
Storage
Vessel
Provisions
C.
Wastewater
Provisions
D.
Equipment
Leak
Provisions
5
E.
Marine
Vessel
Loading
and
Unloading,
Bulk
Gasoline
Terminal
or
Pipeline
Breakout
Station
Storage
Vessels,
and
Bulk
Gasoline
Terminal
Loading
Rack
Provisions
F.
Recordkeeping
and
Reporting
Provisions
G.
Emissions
Averaging
IV.
Summary
of
Impacts
V.
Significant
Comments
and
Changes
to
the
Proposed
Standards
A.
Process
Vents
Group
Determination
B.
Process
Vent
Impacts
C.
Equipment
Leaks
Compliance
Requirements
D.
Storage
Vessels
E.
Overlapping
Regulations
F.
Source
Category
Definition
G.
Emissions
Averaging
H.
Monitoring,
Recordkeeping,
and
Reporting
I.
Subcategorization
J.
Economic
Analysis
K.
Benefits
Analysis
L.
Emissions
Data
VI.
Changes
to
NSPS
VII.
Administrative
Requirements
A.
Docket
B.
Paperwork
Reduction
Act
C.
Executive
Order
12866
D.
Regulatory
Flexibility
Act
6
E.
Unfunded
Mandates
I.
Background
Section
112(
b)
of
the
Act
lists
189
HAP's
and
directs
the
EPA
to
develop
rules
to
control
all
major
and
some
area
sources
emitting
HAP's.
On
July
16,
1992
(
57
FR
31576),
the
EPA
published
a
list
of
major
and
area
sources
for
which
NESHAP
are
to
be
promulgated.
Petroleum
refineries
were
listed
as
a
category
of
major
sources.
On
December
3,
1993
(
58
FR
83941),
the
EPA
published
a
schedule
for
promulgating
standards
for
the
listed
major
and
area
sources.
Standards
for
the
petroleum
refinery
source
category
for
sources
not
distinctly
listed
were
scheduled
for
promulgation
on
November
15,
1994.
The
EPA
is
promulgating
these
standards
under
a
July
28,
1995
court­
ordered
deadline.

II.
Summary
of
Considerations
in
Developing
the
Rule
A.
Purpose
of
Regulation
The
Act
was
developed,
in
part,

to
protect
and
enhance
the
quality
of
the
Nations
air
resources
so
as
to
promote
the
public
health
and
welfare
and
the
productive
capacity
of
its
population
[
the
Act,
section
101(
b)(
1)].

Petroleum
refineries
are
major
sources
of
HAP
emissions.

Individual
refineries
emit
over
23
megagrams
per
year
(
Mg/
yr)
(
25
tons
per
year
(
tpy))
of
organic
HAP's
including
benzene,
toluene,
ethyl
benzene,
and
other
HAP's.
The
HAP's
controlled
by
this
rule
are
associated
with
a
variety
of
adverse
health
effects.
The
range
of
adverse
health
effects
include
cancer
and
a
number
of
other
chronic
health
7
disorders
(
e.
g.,
aplastic
anemia,
pancytopenia,
pernicious
anemia,
pulmonary
(
lung)
structural
changes)
and
a
number
of
acute
health
disorders
(
e.
g.,
dyspnea
(
difficulty
in
breathing),
upper
respiratory
tract
irritation
with
cough,

conjunctivitis,
neurotoxic
effects
(
e.
g.,
visual
blurring,

tremors,
delirium,
unconsciousness,
coma,
convulsions).

Table
1
presents
the
11
most
significant
organic
HAP's
emitted
from
the
petroleum
refineries.
Petroleum
refineries
also
emit
inorganic
HAP's
(
e.
g.,
hydrogen
fluoride,
hydrogen
chloride).
Inorganic
HAP
emissions
from
the
emission
points
covered
under
this
rule
are
low
relative
to
organic
HAP
emissions.
Emission
points
emitting
inorganic
HAP's
are
included
in
a
separate
source
category
under
a
separate
schedule.
8
TABLE
1.
SIGNIFICANT
HAZARDOUS
AIR
POLLUTANTS
FROM
PETROLEUM
REFINERIES
Hazardous
Air
Pollutant
2,2,4­
Trimethylpentane
Methyl
tert
butyl
ether
Benzene
Naphthalene
Cresols/
cresylic
acid
Phenol
Ethylbenzene
Toluene
Hexane
Xylenes
Methyl
ethyl
ketone
9
The
catalytic
cracking
unit
catalyst
regeneration
vent
emits
primarily
metal
HAP's,
which
would
be
controlled
using
particulate
controls.
Catalytic
reformer
catalyst
regeneration
vents
emit
hydrogen
chloride,
and
sulfur
plant
vents
emit
carbonyl
sulfide
and
carbon
disulfide.
Because
of
these
compounds'
unique
characteristics,
the
EPA
concluded
that
these
emission
points
warranted
separate
consideration
for
control
of
inorganic
HAP's.
Because
limited
data
are
currently
available,
these
emission
points
are
included
in
a
separate
source
category
under
a
separate
schedule.

The
Regulatory
Impacts
Analysis
(
RIA)
presents
the
results
of
an
examination
of
the
potential
health
and
welfare
benefits
associated
with
air
emission
reductions
projected
as
a
result
of
implementation
of
the
petroleum
refinery
NESHAP.
Of
the
pollutants
emitted
by
petroleum
refineries,
some
are
classified
as
VOC,
which
are
ozone
precursors.
Benefits
from
HAP
emission
reductions
are
presented
separately
from
the
benefits
associated
specifically
with
VOC
emission
reductions.

The
predicted
emissions
of
a
few
HAP's
associated
with
this
regulation
have
been
classified
as
possible,
probable,

or
known
human
carcinogens.
Benzene
and
cresols
are
the
two
HAP's
identified
as
carcinogens.

Benzene
is
classified
as
a
class
A
or
a
known
human
carcinogen.
Benzene
is
a
concern
to
the
EPA
because
long
10
term
exposure
to
this
chemical
causes
an
increased
risk
of
cancer
in
humans,
and
is
also
associated
with
aplastic
anemia,
pancytopenia,
chromosomal
breakages,
and
weakening
of
the
bone
marrow.

Cresols
are
classified
as
class
C
or
possible
human
carcinogens.
For
this
HAP,
there
is
either
inadequate
data
or
no
data
on
human
carcinogenicity.
Therefore,
while
cancer
risk
is
a
possibility,
there
is
not
sufficient
evidence
to
quantify
the
increased
cancer
risk
to
humans
caused
by
these
chemicals.

There
are
serious
health
effects
reported
from
exposure
to
some
of
the
noncarcinogenic
HAP's.
These
serious
health
effects
typically
occur
at
higher
levels
of
exposure
than
estimated
for
the
regulatory
baseline.
Exposure
to
phenol
is
very
toxic
to
animals
and
increases
mortality,
but
there
is
little
human
data.
Exposure
to
n­
hexane
can
cause
polyneuropathy
(
muscle
weakness
and
numbness)
in
humans,
and
exposure
to
naphthalene
is
linked
to
cataracts
and
anemia
in
human
infants.
It
is
also
possible
that
there
are
less
serious
health
effects
in
the
regulatory
baseline
from
exposure
to
these
HAP's.

Emissions
of
VOC
have
been
associated
with
a
variety
of
health
and
welfare
impacts.
Volatile
organic
compound
emissions,
together
with
nitrogen
oxides
(
NOx),
are
precursors
to
the
formation
of
tropospheric
ozone.
Exposure
to
ambient
ozone
is
responsible
for
a
series
of
health
11
impacts,
such
as
alterations
in
lung
capacity;
eye,
nose,

and
throat
irritation;
malaise
and
nausea;
and
aggravation
of
existing
respiratory
disease.
Among
the
welfare
impacts
from
exposure
to
ambient
ozone
include
damage
to
selected
commercial
timber
species
and
economic
losses
for
commercially
valuable
crops
such
as
soybeans
and
cotton.

Based
on
existing
data,
the
benefits
associated
with
reduced
HAP
and
VOC
emissions
were
quantified.
The
quantification
of
dollar
benefits
for
all
benefit
categories
is
not
possible
at
this
time
because
of
limitations
in
both
data
and
available
methodologies.
Although
an
estimate
of
the
total
reduction
in
HAP
emissions
for
various
regulatory
alternatives
has
been
developed
for
the
RIA,
it
has
not
been
possible
to
identify
the
speciation
of
the
HAP
emission
reductions
for
each
type
of
emission
point.
However,
an
estimate
of
HAP
speciation
for
equipment
leaks
has
been
made.
Using
emissions
data
for
equipment
leaks
and
the
Human
Exposure
Model
(
version
1),
the
annual
cancer
risk
caused
by
HAP
emissions
from
petroleum
refineries
was
estimated.
Generally,
this
benefit
category
is
calculated
as
the
difference
in
estimated
annual
cancer
incidence
before
and
after
implementation
of
each
regulatory
alternative.
Since
the
annual
cancer
incidence
associated
with
baseline
conditions
was
less
than
one
life
per
year,

the
cancer
benefits
associated
with
HAP
reductions
for
the
petroleum
refinery
NESHAP
were
determined
to
be
low.
12
Therefore,
these
quantified
benefits
are
not
part
of
the
overall
quantified
benefits
estimate
for
the
analysis.

The
benefits
of
reduced
emissions
of
VOC
from
a
MACT
regulation
of
petroleum
refineries
were
quantified
using
the
technique
of
"
benefits
transfer."
Because
analysis
by
the
Office
of
Technology
Assessment
from
which
benefits
transfer
values
were
obtained
only
estimated
acute
health
benefits
in
ozone
nonattainment
areas,
the
transfer
values
can
be
applied
to
VOC
reductions
occurring
only
in
ozone
nonattainment
areas.
The
range
of
benefit
transfer
values
used
in
this
analysis
is
from
$
25
to
$
1,574
per
megagram
(
Mg)
($
23
to
$
1,431
per
ton)
of
VOC
with
an
average
of
$
800/
Mg
($
727/
ton)
of
VOC.

In
order
to
quantify
benefits
from
VOC
emission
reductions,
the
average
value
is
multiplied
by
VOC
emission
reductions
from
petroleum
refineries
in
ozone
nonattainment
areas.
Estimated
annual
benefits
for
VOC
reductions
are
$
108.8
million
for
selected
regulatory
alternatives.
The
quantified
annual
benefits
exceed
annual
compliance
costs
by
$
29.8
million
(
1992
dollars).

The
promulgated
NESHAP
will
reduce
HAP
emissions
from
petroleum
refineries
by
59
percent.
Table
2
presents
the
national
baseline
emissions
and
emission
reductions
for
petroleum
refinery
process
vents,
storage
vessels,

wastewater,
and
equipment
leaks.
The
emissions
13
reductions
for
controlling
gasoline
loading
racks
and
the
marine
vessel
loading
emission
points
are
discussed
in
supporting
material
for
the
Gasoline
Distribution
(
Stage
I)

and
the
Marine
Vessel
Loading
Operations
rules.
TABLE
2.
NATIONAL
PRIMARY
AIR
POLLUTION
IMPACT
IN
THE
FIFTH
YEAR
Source
Baseline
emissions
(
Mg/
yr)
Emission
reductions
(
Mg/
yr)
(
Percent)

HAP
VOC
HAP
VOC
HAP
VOC
Miscellaneous
process
vents
10,000
109,000
6,700
85,000
67
78
Equipment
leaks
52,000
189,000
40,000
146,000
77
77
Storage
vessels
9,300
111,000
1,300
21,000
14
19
Wastewater
collection
and
treatment
10,000
10,000
a
a
a
a
Total
81,300
419,000
48,000
252,000
59
60
a
The
MACT
level
of
control
is
no
additional
control.
15
B.
Technical
Basis
of
Regulation
National
emission
standards
for
major
sources
of
HAP's
established
under
section
112
of
the
Act
reflect
MACT
or:

...
the
maximum
degree
of
reduction
in
emissions
of
the
HAP...
that
the
Administrator,
taking
into
consideration
the
cost
of
achieving
such
emission
reduction,
and
any
nonair
quality
health
and
environmental
impacts
and
energy
requirements,
determine
is
achievable
for
new
or
existing
sources
in
the
category
or
subcategory
to
which
such
emission
standard
applies...[
the
Act
section
112(
d)(
2)].

Prior
to
proposal,
section
114
questionnaires,

information
collection
requests
(
ICR's),
and
telephone
surveys
were
used
to
obtain
information
on
emissions,

emissions
control,
and
emissions
control
costs
for
petroleum
refinery
emission
points.
Section
114
questionnaires
were
sent
out
to
nine
large
refineries,
of
approximately
130
existing
petroleum
refineries
nationally,
to
obtain
emissions
and
emissions
control
information
for
equipment
leaks,
wastewater,
process
vents,
and
storage
vessel
emission
points
located
in
a
petroleum
refinery.
The
ICR's
were
sent
out
to
the
refineries
that
were
not
sent
section
114
questionnaires
to
obtain
information
on
emissions
control
equipment
and
emissions
for
process
vents,

storage
vessels,
and
equipment
leaks
emission
points.
A
telephone
survey
of
equipment
vendors
was
conducted
to
obtain
leak
detection
and
repair
(
LDAR)
cost
information.

Data
and
information
were
received
for
approximately
130
petroleum
refineries.
This
information
was
used,
in
part,
as
the
technical
basis
in
determining
the
MACT
level
16
of
control
for
the
process
units
covered
under
this
rule.

In
addition
to
information
collected
from
industry,
the
EPA
used
information
on
refinery
locations
and
processes
available
in
the
general
literature.
The
EPA
also
used
control
technology
performance
and
cost
information
developed
under
previous
rulemakings
for
the
petroleum
and
chemical
industries,
such
as
the
petroleum
refinery
new
source
performance
standard
(
NSPS),
benzene
NESHAP,
and
synthetic
organic
chemical
manufacturing
industry
(
SOCMI)

standards.
The
EPA
also
considered
existing
State
regulations
and
additional
information
received
during
the
public
comment
period
for
the
proposed
rule
in
developing
the
final
rule.

C.
Stakeholder
and
Public
Participation
In
the
development
of
this
rule,
numerous
representatives
of
the
petroleum
refinery
industry
were
consulted
prior
to
proposal.
Industry
representatives
have
included
trade
associations,
and
refiners
responding
to
section
114
questionnaires,
ICR's,
and
telephone
surveys.

Representatives
from
State
agencies
and
the
EPA
regions
were
also
consulted
and
participated
in
the
development
of
the
rule.

The
standards
were
proposed
and
published
in
the
Federal
Register
on
July
15,
1994
(
59
FR
36130).
The
preamble
to
the
proposed
standard
describes
the
rationale
for
the
17
proposed
rule.
Public
comments
were
solicited
at
the
time
of
proposal.

To
provide
interested
persons
the
opportunity
for
oral
presentation
of
data,
views,
or
arguments
concerning
the
proposed
standards,
a
public
hearing
was
offered
at
proposal.
A
public
hearing
was
held
in
Research
Triangle
Park,
North
Carolina,
on
August
5,
1994.
The
hearing
was
open
to
the
public
and
four
persons
presented
oral
testimony.
The
public
comment
period
was
from
July
15,
1994
to
September
13,
1994.
Sixty­
two
comment
letters
were
received.
Commenters
included
industry
representatives,

States,
environmental
organizations,
and
others.
The
comments
have
been
carefully
considered,
and
changes
have
been
made
in
the
proposed
standards
when
determined
by
the
Administrator
to
be
appropriate.
A
detailed
discussion
of
these
comments
and
responses
can
be
found
in
the
Response
of
Comment
Document,
which
is
referenced
in
the
ADDRESSES
section
of
this
preamble.
The
summary
of
comments
and
responses
in
the
document
serve
as
the
basis
for
the
revisions
that
have
been
made
to
the
standards
between
proposal
and
promulgation.
Section
V
of
this
preamble
discusses
the
major
comments
that
resulted
in
changes
to
the
standards.

III.
Summary
of
Promulgated
Standards
The
promulgated
standard
applies
to
petroleum
refining
process
units
as
well
as
other
colocated
emission
points
18
that
are
part
of
a
plant
site
that
is
a
major
source
as
defined
in
section
112
of
the
Act.
The
determination
of
potential
to
emit,
and
therefore
major
source
status,
is
based
on
the
total
of
all
HAP
emissions
from
all
activities
at
the
plant
site.
The
applicability
section
of
the
regulation
specifies
what
is
included
in
the
petroleum
refining
source
category
and
defines
the
sources
regulated
by
the
NESHAP.

The
general
standards
consist
of
compliance
dates
for
new
and
existing
sources,
require
sources
to
be
properly
operated
and
maintained
at
all
times,
and
clarify
the
applicability
of
the
NESHAP
General
Provisions
(
40
Code
of
Federal
Regulations
(
CFR)
part
63,
subpart
A)
to
sources
subject
to
subpart
CC.

The
affected
source
comprises
the
miscellaneous
process
vents,
storage
vessels,
wastewater
streams,
and
equipment
leaks
associated
with
petroleum
refining
process
units,
and
marine
tank
vessel
loading
operations
and
gasoline
loading
racks
classified
under
SIC
code
2911
located
at
a
refinery.

The
inclusion
of
marine
tank
vessel
loading
operations
and
gasoline
loading
racks
in
the
definition
of
the
petroleum
refinery
affected
source
and
source
category
is
a
revision
from
the
proposal.
These
emission
points
have
been
included
as
part
of
the
petroleum
refinery
affected
source
and
source
category
to
permit
an
owner
or
operator
of
a
petroleum
refinery
to
average
emissions
among
emission
points
19
collocated
at
the
refinery
to
comply
with
the
standards.

These
standards
do
not
apply
to
distillation
units
located
at
pipeline
pumping
stations
whose
primary
purpose
is
to
produce
fuel
to
operate
turbines
and
internal
combustion
engines
at
the
pipeline
pumping
stations.
A
summary
of
the
specific
provisions
that
apply
to
each
of
the
emission
points
contained
within
a
petroleum
refinery
affected
source
follows.
All
of
the
specified
provisions
for
each
of
the
covered
emission
points
allow
for,
or
are
based
on
and
encourage,
pollution
prevention.

These
standards
do
not
address
three
vents
that
will
be
subject
to
future
NESHAP
standards.
These
are
the
catalyst
regeneration
vents
on
catalytic
cracking
units
and
catalytic
reforming
units
(
CRU's)
and
vents
from
sulfur
recovery
units
(
SRU's).
Industry
is
concerned
that
standards
for
these
three
vents
will
require
the
use
of
control
technologies
designed
to
reduce
non­
HAP
emissions
and
will
preclude
the
use
of
alternatives
that
can
achieve
comparable
HAP
control
at
a
lower
cost.
The
EPA
recognizes
that
standards
should
be
structured
on
a
performance
basis
wherever
possible
to
ensure
that
industry
is
provided
the
flexibility
to
seek
out
and
implement
cost­
effective
controls.
The
EPA's
existing
standards
for
sulfur
dioxide
and
particular
matter
emissions
from
new
FCCU
catalyst
regenerator
vents
demonstrate
such
recognition.
The
allowable
emissions
were
expressed
in
terms
of
the
amount
of
coke
burned
off
the
catalyst
in
order
20
to
provide
industry
with
the
flexibility
to
comply
through
operational
changes
or
through
traditional
end­
of­
pipe
controls
or
a
combination
of
the
two.
The
EPA
has
every
intention
to
ensure
that
future
rules
also
provide
similar
flexibility.

A.
Miscellaneous
Process
Vent
Provisions
Miscellaneous
process
vents
include
vents
from
petroleum
refining
process
units
that
emit
organic
HAP's.
Vents
that
are
routed
to
the
refinery
fuel
gas
system
are
considered
to
be
part
of
the
process
and
are
not
subject
to
the
standard.

The
miscellaneous
process
vent
provisions
define
two
groups
of
vents.
Group
1
process
vents
are
those
with
VOC
emissions
greater
than
or
equal
to
33
kilograms
per
day
(
kg/
day)
(
72
pounds
per
day
(
lb/
day))
for
existing
sources
and
6.8
kg/
day
(
15
lb/
day)
for
new
sources.
Group
2
vents
are
vents
with
emissions
below
these
levels.

The
miscellaneous
process
vent
provisions
for
new
and
existing
sources
require
the
owner
or
operator
of
a
Group
1
miscellaneous
process
vent
to
reduce
organic
HAP
emissions
by
98
percent
or
to
less
than
20
parts
per
million
by
volume
(
ppmv),
or
to
reduce
emissions
using
a
flare
meeting
the
requirements
of
§
63.11(
b)
of
the
NESHAP
General
Provisions
(
40
CFR
part
63,
subpart
A).

Monitoring
requirements
for
Group
1
vents
include
an
initial
performance
demonstration
and
monitoring
of
control
device
operating
parameters.
The
owner
could
also
comply
by
21
reducing
emissions
from
a
Group
1
process
vent
to
less
than
33
kg/
day
(
72
lb/
day)
for
existing
sources
and
6.8
kg/
day
(
15
day)
for
new
sources,
thereby
converting
it
to
a
Group
2
process
vent.
No
controls
or
monitoring
are
required
for
Group
2
process
vents.

B.
Storage
Vessel
Provisions
The
storage
vessel
provisions
define
two
groups
of
vessels:
Group
1
vessels
are
vessels
with
a
design
storage
capacity
and
a
maximum
true
vapor
pressure
above
the
values
specified
in
the
regulation.
Group
2
vessels
are
all
storage
vessels
that
are
not
Group
1
vessels.
The
storage
vessel
provisions
require
that
one
of
the
following
control
systems
be
applied
to
Group
1
storage
vessels:
(
1)
An
internal
floating
roof
(
IFR)
with
proper
seals;
(
2)
an
external
floating
roof
(
EFR)
with
proper
seals;
(
3)
an
EFR
converted
to
an
IFR
with
proper
seals;
or
(
4)
a
closed
vent
system
to
a
control
device
that
reduces
HAP
emissions
by
95
percent
or
to
20
ppmv.
The
storage
provisions
give
details
on
the
type
of
seals
required.
Monitoring
and
compliance
provisions
for
Group
1
vessels
include
periodic
external
visual
inspections
of
vessels
and
roof
seals,
as
well
as
less
frequent
internal
inspections.
If
a
closed
vent
system
and
control
device
is
used
for
venting
emissions
from
Group
1
storage
vessels,
the
owner
or
operator
must
establish
appropriate
monitoring
procedures.
No
controls
or
inspections
are
required
for
Group
2
storage
vessels.
22
For
existing
sources,
the
final
rule
requires
that
fixed
roof
tanks
with
capacities
greater
than
or
equal
to
177
cubic
meters
(
m3)
(
47,000
gallons
(
gal))
that
store
liquids
containing
more
than
4
percent
organic
HAP
with
vapor
pressures
greater
than
10.4
kilopascals
(
kPa)

(
1.5
pounds
per
square
inch
absolute
(
psia))
comply
fully
with
the
rule
within
3
years.
If
an
owner
or
operator
must
replace
an
existing
fixed
roof
tank
in
order
to
comply
with
the
rule,
it
would
be
reasonable
for
the
State
to
grant
an
additional
year
to
comply
as
authorized
under
section
112(
i)(
3)(
B)
of
the
Act
(
a
total
of
four
years).

This
additional
time
would
allow
time
to
design
and
construct
tanks
without
disrupting
refinery
operations
that
could
create
additional
emissions.
Owners
or
operators
of
IFR
or
EFR
tanks
are
allowed
to
defer
upgrading
of
their
seals
to
meet
the
NESHAP
requirements
until
the
next
scheduled
inspection
and
maintenance
activity
or
within
10
years,
whichever
comes
first.

For
new
sources,
the
final
rule
requires
that
vessels
with
capacities
greater
than
or
equal
to
151
m3
(
40,000
gal),
that
store
liquids
containing
more
than
2
percent
organic
HAP
with
vapor
pressures
equal
to
or
greater
than
3.4
kPa
(
0.5
psia),
and
vessels
with
capacities
equal
to
or
greater
than
76
m3
(
20,000
gal)
storing
liquids
containing
more
than
2
percent
organic
HAP
with
vapor
pressures
equal
to
or
greater
than
77
kPa
(
11.1
psia)
comply
23
with
the
level
of
control
required
by
40
CFR
part
63,

subpart
G
(
including
the
controlled
fitting
requirements).

C.
Wastewater
Provisions
The
wastewater
provisions
define
two
groups
of
wastewater
streams.
Group
1
streams
are
those
that
are
located
at
a
refinery
with
a
total
annual
benzene
loading
of
at
least
10
megagrams
per
year
(
Mg/
yr)
(
11
tpy)
and
are
not
exempt
from
control
requirements
under
40
CFR
part
61,

subpart
FF
(
the
benzene
waste
operations
NESHAP
or
BWON).

In
general,
streams
are
not
exempt
from
40
CFR
part
61
subpart
FF
if
they
contain
a
concentration
of
at
least
10
parts
per
million
by
weight
(
ppmw)
benzene,
and
have
a
flow
rate
of
at
least
0.02
liters
per
minute
(
L/
min)

(
0.005
gallons
per
minute
(
gal/
min)).
Group
2
streams
are
wastewater
streams
that
are
not
Group
1.

The
wastewater
provisions
of
the
final
rule
refer
to
the
BWON
for
both
new
and
existing
sources,
which
requires
owners
or
operators
of
a
Group
1
wastewater
stream
to
reduce
benzene
mass
emissions
by
99
percent
using
suppression
followed
by
steam
stripping,
biotreatment,
or
other
treatment
processes.
Vents
from
steam
strippers
and
other
waste
management
or
treatment
units
are
required
to
be
controlled
by
a
control
device
achieving
95
percent
emissions
reduction
or
20
ppmv
at
the
outlet
of
the
control
device.
The
performance
tests,
monitoring,
reporting,
and
recordkeeping
provisions
required
to
demonstrate
compliance
24
are
included
in
the
BWON.
No
controls
or
monitoring
are
required
for
Group
2
wastewater
streams.

D.
Equipment
Leak
Provisions
The
equipment
leak
standards
for
the
petroleum
refinery
NESHAP
allow
owners
or
operators
of
existing
sources
to
choose
between
complying
with
equipment
leaks
provisions
in
40
CFR
part
60,
subpart
VV
(
NSPS
for
Equipment
Leaks)
or
complying
with
a
modified
negotiated
regulation
for
equipment
leaks
presented
in
40
CFR
part
63,
subpart
H
(
Hazardous
Organic
NESHAP
or
HON
equipment
leaks).
The
differences
in
the
NSPS
equipment
leak
requirements
and
the
HON
equipment
leak
requirements
are
in
the
leak
definitions
and
connector
monitoring
provisions.

Under
either
of
the
two
options,
existing
refineries
subject
to
the
rule
will
be
required
to
implement
a
LDAR
program
with
the
same
leak
definitions
(
10,000
parts
per
million
(
ppm))
and
frequencies
as
specified
in
40
CFR
part
60,
subpart
VV
within
3
years
after
promulgation
of
the
petroleum
refineries
NESHAP.
Refineries
that
choose
to
comply
with
the
modified
negotiated
regulation
would
implement
the
Phase
II
leak
definitions
and
frequencies
at
the
end
of
the
fourth
year,
and
comply
with
Phase
III
requirements
5
½
years
after
promulgation.
Phase
III
defines
a
leak
at
a
lower
level,
but
allows
less
frequent
monitoring
for
good
performers.
Although
the
modified
negotiated
regulation
is
not
required
in
the
final
rule,
the
25
EPA
believes
that
it
would
provide
greater
emission
reductions
and,
in
many
cases,
would
be
more
cost
effective
than
40
CFR
part
60,
subpart
VV
and
could
even
provide
cost
savings.
Cost
savings
would
occur
because
it
would
reduce
equipment
leak
product
loss,
and
facilities
with
a
low
percentage
of
leaking
valves
would
be
able
to
monitor
less
frequently,
thereby
reducing
monitoring
costs.

New
sources
must
comply
at
startup
with
the
modified
negotiated
regulation;
pumps
and
valves
at
new
sources
must
be
in
compliance
with
the
Phase
II
requirements
at
startup
rather
than
Phase
I.
This
is
consistent
with
the
negotiated
rule
(
40
CFR
part
63,
subpart
H).

E.
Marine
Tank
Vessel
Loading
and
Gasoline
Loading
Rack
Provisions
The
final
refineries
NESHAP
requires
marine
tank
vessel
loading
operations
at
refineries
to
comply
with
the
marine
loading
NESHAP
(
40
CFR
part
63,
subpart
Y)
unless
they
are
included
in
an
emissions
average.
Gasoline
loading
racks
classified
under
SIC
code
2911
at
refineries
are
required
to
comply
with
the
40
CFR
part
63,
subpart
R
loading
rack
provisions
unless
they
are
included
in
an
emissions
average.

F.
Recordkeeping
and
Reporting
Provisions
The
final
rule
requires
that
petroleum
refineries
subject
to
40
CFR
part
63,
subpart
CC
maintain
required
records
for
a
period
of
at
least
5
years.
The
final
rule
requires
that
the
following
reports
be
submitted:
(
1)
A
26
Notification
of
compliance
status
report,
(
2)
periodic
reports,
and
(
3)
other
reports
(
e.
g.,
notifications
of
storage
vessel
internal
inspections;
startup,
shutdown,
and
malfunction
reports).

G.
Emissions
Averaging
The
EPA
is
allowing
emissions
averaging
among
existing
miscellaneous
process
vents,
storage
vessels,
wastewater
streams,
marine
tank
vessel
loading
operations,
and
gasoline
loading
racks
classified
under
SIC
code
2911
located
at
a
refinery.
New
sources
are
not
allowed
to
use
emissions
averaging.
Under
emissions
averaging,
a
system
of
emission
"
credits"
and
"
debits"
is
allowed
to
determine
whether
a
source
is
achieving
the
required
emission
reductions.

IV.
Summary
of
Impacts
The
impacts
presented
in
this
section
include
process
vents,
storage
vessels,
equipment
leaks,
and
wastewater
streams
from
petroleum
refinery
process
units.
Impacts
for
control
of
marine
tank
vessel
loading
operations
and
gasoline
loading
rack
operations
classified
under
SIC
code
2911
located
at
refineries
are
presented
in
the
background
documentation
for
40
CFR
part
63,
subparts
Y
and
R.

These
standards
will
reduce
nationwide
emissions
of
HAP
from
petroleum
refineries
by
48,000
Mg/
yr
(
53,000
tpy),
or
59
percent
by
1998
compared
to
the
emissions
that
would
result
in
the
absence
of
standards.
No
adverse
secondary
27
air
impacts,
water
or
solid
waste
impacts
are
anticipated
from
the
promulgation
of
these
standards.

The
national
electric
usage
required
to
comply
with
the
rule
is
expected
to
increase
by
48
million
kilowatt­
hours
per
year,
which
is
equivalent
to
approximately
77,500
barrels
of
oil.

The
implementation
of
this
regulation
is
expected
to
result
in
an
overall
annual
national
cost
of
$
79
million.

This
includes
a
cost
of
$
59
million
from
operation
of
control
devices,
and
a
monitoring,
recordkeeping,
and
reporting
cost
of
$
20
million.
The
monitoring,
reporting,

and
recordkeeping
cost
has
been
reduced
by
25
percent
from
proposal.
Table
3
presents
the
national
control
cost
impacts
for
petroleum
refinery
process
vents,
storage
vessels,
wastewater,
and
equipment
leaks.
The
control
costs
for
gasoline
loading
racks
and
marine
tank
vessel
loading
operations
are
discussed
in
supporting
material
for
the
Gasoline
Distribution
(
Stage
I)
and
the
Marine
Vessel
Loading
Operations
rules.
TABLE
3.
NATIONAL
CONTROL
COST
IMPACTS
IN
THE
FIFTH
YEAR
Source
Totala
capital
costsb
($
106)
Totala
annual
costs
($
106/
yr)
Average
HAP
cost
effectiveness
($/
Mg
HAP)
Average
VOC
cost
effectiveness
($/
Mg
VOC)

Miscellaneous
process
vents
21
(
2)
12
(
1)
1,800
140
Equipment
leaks
142
(
16)
58
(
17)
1,500
400
Storage
vessels
48
(
1)
8
(
1)
6,100
380
Wastewater
collection
and
treatment
c
c
c
c
Other
recordkeeping
and
reporting
2
1
d
d
Total
213
(
21)
79
(
20)
1,600
310
a
Numbers
in
parentheses
are
recordkeeping
and
reporting
costs
included
in
total
annual
cost
and
total
capital
cost
estimates.
For
equipment
leaks,
activities
associated
with
setting
up
and
operating
a
LDAR
program
(
e.
g.,
tagging
and
identifying,
monitoring,
data
entry,
setting
up
a
data
management
system,
etc.)

are
not
reflected
in
the
equipment
leak
recordkeeping
and
reporting
costs,
but
are
included
in
the
equipment
leak
total
annual
cost
and
total
capital
cost
estimate.

b
Total
capital
costs
incurred
in
the
5­
year
period.

c
The
MACT
level
of
control
is
no
additional
control.

d
Not
applicable.
29
The
EPA
estimates
that
changes
in
the
compliance
times
for
storage
vessels
with
floating
roofs
and
changes
to
the
process
vents
Group
1
applicability
cutoff
will
provide
substantial
cost
savings
and
emissions
reductions
for
refineries.
Estimates
of
degassing
and
cleaning
storage
tank
costs
provided
by
the
refining
industry
indicate
that
premature
(
within
3
years
of
promulgation)
degassing
and
cleaning
activities
would
cost
between
$
34,000
and
$
213,000
per
floating
roof
tank
depending
on
the
type
of
material
stored.
If
extrapolated
to
the
entire
refining
industry
for
floating
roof
tanks,
the
cost
savings
from
allowing
floating
roofs
to
comply
at
the
next
scheduled
maintenance
would
be
$
6.6
million
per
year.

The
EPA
determined
that
substantial
HAP
emissions
occur
when
storage
vessels
are
degassed
and
cleaned.
Typically,

storage
vessels
are
inspected
and
maintained
on
a
10­
year
schedule,
at
which
time
tanks
are
degassed
and
cleaned.
If
a
3­
year
compliance
schedule
were
required,
storage
vessels
would
be
degassed
and
cleaned
prematurely,
resulting
in
substantial
HAP
emissions
caused
by
the
rule.
These
HAP
emissions
could
not
be
balanced
in
less
than
5
years
for
floating
roof
tanks
by
the
emission
reduction
achieved
from
complying
with
the
rule.
By
changing
the
proposed
rule
to
allow
floating
roof
tanks
to
comply
with
the
storage
vessel
requirements
10
years
after
promulgation
of
the
rule
or
at
the
next
scheduled
inspection,
the
EPA
estimates
that
30
3,000
Mg/
yr
(
2,700
tpy)
of
HAP,
or
8,000
Mg
(
7,200
tpy)
of
HAP
over
3
years,
would
be
prevented
from
being
emitted.

The
existing
source
process
vent
applicability
cutoff
(
33
kg
of
VOC/
day
(
72
lb
of
VOC/
day)
per
vent)
will
exclude
3,000
vents
from
requiring
control
at
a
total
annual
cost
savings
of
$
4.5
million.
The
new
source
process
vent
applicability
cutoff
(
7
kg
of
VOC/
day
(
15
lb
of
VOC/
day)
per
vent)
will
exclude
35
vents
from
requiring
control
at
a
total
annual
cost
savings
of
$
25,000.
The
total
annual
cost
reduction
of
these
changes
in
the
rule
is
a
reduction
of
approximately
$
11
million.

The
economic
impact
analysis
for
the
selected
regulatory
alternatives
shows
that
the
estimated
price
increases
for
affected
products
range
from
0.24
percent
for
residual
fuel
oil
to
0.53
percent
for
jet
fuel.
Estimated
decreases
in
product
output
range
from
0.13
percent
for
jet
fuel
to
0.50
percent
for
residual
fuel
oil.
Annual
net
exports
(
exports
minus
imports)
are
predicted
to
decrease
by
2.3
million
barrels,
with
the
range
of
reductions
varying
from
0.21
million
barrels
for
liquid
petroleum
gas
to
0.91
million
barrels
for
residual
fuel
oil.

Between
zero
and
seven
refineries,
all
of
which
are
classified
as
small,
may
close
due
to
the
regulation.
For
more
information,
consult
the
"
Economic
Impact
Analysis
for
the
Petroleum
Refinery
NESHAP"
in
the
docket
(
see
ADDRESSES
section
of
this
preamble).
31
V.
Significant
Comments
and
Changes
to
the
Proposed
Standards
In
response
to
comments
received
on
the
proposed
standards,
several
changes
have
been
made
to
the
final
rule.

While
several
of
these
changes
are
clarifications
designed
to
make
the
Agency's
intent
clearer,
a
number
of
them
are
significant
changes
to
the
proposed
standard
requirements.

A
summary
of
the
substantive
comments
and/
or
changes
made
since
the
proposal
are
described
in
the
following
sections.

Detailed
Agency
responses
to
public
comments
and
the
revised
analysis
for
the
final
rule
are
contained
in
the
BID
and
docket
(
see
ADDRESSES
section
of
this
preamble).

A.
Process
Vents
Group
Determination
The
proposed
NESHAP
would
have
required
control
of
all
miscellaneous
process
vents
with
HAP
concentrations
over
20
ppmv.
This
level
was
based
on
the
fact
that
combustion
control
technologies
can
reduce
organic
emissions
by
98
percent
or
to
20
ppmv,
but
cannot
necessarily
achieve
lower
concentrations.
Several
commenters
suggested
that
other
applicability
criteria
were
needed
to
determine
which
process
vents
are
required
to
apply
control.
They
pointed
out
that
the
HON
and
State
regulations
use
a
total
resource
effectiveness
(
TRE)
or
emission
rate
cutoff
to
exclude
small
vents
that
have
low
emission
potential
and
high
costs
from
control
requirements.
The
commenters
contended
that
the
MACT
floor
does
not
include
control
of
such
vents.
32
In
response
to
these
comments,
the
EPA
examined
potential
control
applicability
criteria.
The
EPA
reevaluated
the
miscellaneous
process
vents
data
base.
The
EPA's
information
on
miscellaneous
process
vent
streams
was
insufficient
to
establish
an
emission
rate
cutoff.
This
was
because
industry
did
not
have
sufficient
information
on
the
HAP
and
VOC
content
of
vent
streams
requested
by
the
section
114
questionnaires
and
ICR's
and
it
would
have
been
impractical
to
obtain
this
information.
Therefore,
as
suggested
by
a
number
of
commenters,
and
after
consultations
with
industry
and
others,
the
EPA
decided
to
use
State
regulations.

The
EPA
evaluated
the
current
level
of
control
for
miscellaneous
process
vents
in
eight
States
and
two
air
districts
that
contain
the
majority
of
refineries
and
were
expected
to
have
the
most
stringent
regulations.
Of
the
refineries
in
the
United
States,
the
12
percent
that
are
subject
to
the
most
stringent
regulations
are
located
in
three
States.
In
these
three
States,
miscellaneous
process
vents
emitting
greater
than
6.8
to
45
kg/
day
(
15
to
100
lb/
day)
of
VOC
are
required
to
be
controlled.
The
median
applicability
cutoff
level
for
the
12
percent
of
U.
S.
refineries
subject
to
the
most
stringent
regulations
is
33
kg/
day
(
72
lb/
day
VOC).
Thus,
control
of
vents
with
VOC
emissions
greater
than
33
kg/
day
(
72
lb/
day)
is
the
MACT
floor
for
existing
sources
and
6.8
kg/
day
(
15
lb/
day)
is
the
33
MACT
floor
level
of
control
for
new
sources.
The
primary
organic
HAP's
at
refineries
are
also
VOC.
Additionally,
a
VOC­
based
applicability
criteria
is
most
reflective
of
the
current
level
of
control
required
for
miscellaneous
process
vents
as
the
majority
of
State
regulations
are
expressed
in
terms
of
VOC.
Therefore,
the
EPA
has
adopted
these
emission
levels
in
the
final
rule
to
distinguish
Group
1
from
Group
2
vents.
Group
1
vents
are
those
that
emit
over
33
kg/
day
(
72
lb/
day)
for
existing
sources
and
over
6.8
kg/
day
(
15
lb/
day)
for
new
sources.
Group
1
vents
must
be
controlled,
whereas
Group
2
vents
(
which
emit
less
than
33
kg/
day
(
72
lb/
day)
for
existing
sources
and
less
than
6.8
kg/
day
(
15
lb/
day)
for
new
sources)
are
not
required
to
apply
controls
under
the
final
rule.
The
33
kg/
day
(
72
lb/
day)
and
6.8
kg/
day
(
15
lb/
day)
applicability
limits
are
to
be
determined
as
the
gases
exit
from
process
unit
equipment
(
including
any
recovery
devices)
and
prior
to
any
non­
recovery
emission
control
device.

B.
Process
Vent
Impacts
At
proposal,
the
EPA
estimated
that
the
baseline
HAP
and
VOC
emissions
from
process
vents
were
9,800
Mg/
yr
(
10,780
tpy)
and
190,000
Mg/
yr
(
209,000
tpy),
respectively.

Several
commenters
contended
that
the
impacts
analysis
for
process
vents
should
be
redone
because:
(
1)
The
data
base
used
in
the
analysis
contained
several
errors,
and
(
2)
the
emission
estimation
methodology
was
incorrect.
The
34
commenters
asserted
that
these
inaccuracies
resulted
in
overestimates
of
emissions.
Some
of
the
commenters
asserted
that
the
data
base
flaws
included:
(
1)
A
lack
of
data
concerning
the
number,
flowrates,
and
HAP
concentrations
of
miscellaneous
process
vents,
and
(
2)
an
erroneously
high
percentage
of
controlled
vents
because
many
uncontrolled
vents
were
not
reported.
Some
of
the
commenters
contended
that
the
emission
estimation
methodology
was
flawed
because
(
1)
It
included
wastewater
and
maintenance
emissions,

(
2)
emission
factors
were
calculated
from
a
HAP­
to­
VOC
ratio
that
included
reformer
emissions,
and
(
3)
alkylation
emissions
and
crude
unit
emissions
were
based
on
one
refinery
where
vents
were
uncontrolled
at
the
time
of
the
questionnaire
and
are
now
controlled.

The
EPA
agrees
with
the
commenters
that
the
process
vents
emission
impacts
estimate
has
several
assumptions
that
needed
to
be
reanalyzed.
The
EPA
also
agrees
that
the
data
base
used
at
proposal
should
be
reevaluated
to
consider
the
commenters'
concerns.
Therefore,
the
EPA
has
reestimated
the
emissions
and
cost
impacts
of
the
process
vents
provisions
using
the
commenters'
recommendations.

The
emissions
at
proposal
were
estimated
using
responses
from
only
the
section
114
questionnaires
extrapolated
to
the
entire
refining
industry.
Because
the
section
114
questionnaires
were
sent
to
the
largest
companies,
the
data
obtained
from
them
skewed
the
results
based
on
what
the
35
largest
refineries
did.
The
revised
emissions
were
estimated
using
data
from
both
the
section
114
and
ICR
responses.
The
ICR
questionnaires
were
sent
to
refineries
not
receiving
the
section
114
questionnaires.
This
additional
data
increased
the
number
of
vents
in
the
data
base
by
1,300.
The
increase
in
vents
resulted
in
a
decrease
in
controlled
vents
from
40
percent
to
24
percent.
However,

information
on
the
HAP
and
VOC
content
of
vent
streams
remained
limited
as
no
new
data
was
provided
by
the
ICR
respondents.
Additionally,
no
new
HAP
information
was
provided
by
industry
after
proposal
of
the
rule.

Additionally,
errors
in
the
data
base
were
corrected
and
non­
miscellaneous
process
vents
were
removed
from
the
data
base
(
e.
g.,
vents
from
wastewater,
maintenance,
catalytic
reformer
regeneration
vents,
etc).
In
the
revised
emission
estimates,
emissions
from
alkylation
and
crude
units
were
estimated
from
a
number
of
different
data
points
(
not
just
one,
as
the
commenters
have
stated).
Additionally,
the
one
data
point
the
commenters
have
referred
to
has
been
changed
to
reflect
the
change
in
control
status.
The
revised
baseline
miscellaneous
process
vents
HAP
and
VOC
emissions
are
10,000
Mg/
yr
(
11,000
tpy)
and
109,000
Mg/
yr
(
119,900
tpy),
respectively.

The
EPA
agrees
that
the
data
on
HAP
concentrations
is
limited.
However,
no
new
data
was
supplied
by
the
commenters.
The
EPA's
revised
emission
estimates
are
based
36
on
technically
sound
methods
and
the
best
available
information.

C.
Equipment
Leaks
Compliance
Requirements
The
proposed
rule
for
equipment
leaks
at
existing
sources
was
an
above­
the­
floor
option
modeled
after
the
HON
negotiated
rule
for
equipment
leaks.
The
floor
level
of
control
for
equipment
leaks
from
existing
sources
was
determined
to
be
control
equal
to
the
petroleum
refinery
NSPS.
The
modified
negotiated
rule
was
chosen
as
an
abovethe
floor
option
because
it
was
estimated
to
be
cost
effective.
The
option
chosen
in
the
proposed
rule
differed
from
the
HON
in
that:
(
1)
Existing
sources
were
not
required
to
monitor
connectors,
and
(
2)
the
leak
definitions
were
higher
to
reflect
the
different
volatility
of
materials
found
in
refinery
process
lines
as
opposed
to
SOCMI
process
lines.
The
proposed
rule
required
one­
third
of
the
refinery
to
be
in
compliance
6
months
after
promulgation
of
the
rule,

two­
thirds
of
the
refinery
to
be
in
compliance
1
year
after
promulgation
of
the
rule,
and
the
entire
refinery
to
be
in
compliance
18
months
after
promulgation
of
the
rule.

Several
commenters
contended
that
the
emissions
and
cost
information
used
to
determine
the
cost
effectiveness
of
going
from
the
floor
level
of
control
to
the
modified
negotiated
rule
were
inaccurate
and
did
not
consider
recent
changes
to
the
equipment
leak
correlation
equations
for
petroleum
refineries.
The
commenters
concluded
that
using
37
the
most
recent
information
for
refineries
would
show
that
it
is
not
cost
effective
to
go
beyond
the
floor
level
of
control.

The
cost
information
used
in
the
analysis
was
the
best
data
available,
and
is
based
on
surveys
of
vendors
and
established
costs
presented
in
previous
projects.
No
new
cost
information
was
submitted
by
the
industry.
The
equipment
leak
emission
factors
that
are
being
used
to
estimate
the
emissions
and
emission
reductions
of
the
rule
were
developed
in
1980.
These
are
the
only
complete
and
accurate
emission
factors
available
for
this
purpose.
To
accurately
estimate
emissions
from
equipment
leaks,
two
sets
of
information
are
needed.
These
include
the
amount
of
emissions
generated
per
piece
of
equipment
leaking
at
a
given
concentration
and
the
percent
of
equipment
that
are
actually
leaking
at
these
concentrations.
The
1980
study
that
was
used
to
estimate
the
impacts
of
the
refinery
MACT
rule
used
a
consistent
sampling
methodology
to
address
both
of
these
factors
based
on
sampling
at
uncontrolled
refineries.
The
1993
API
study
developed
new
information
only
on
emissions
per
piece
of
leaking
equipment
using
a
different
methodology.
As
stated
in
API's
report,
this
information
was
developed
from
refineries
in
California
for
use
with
other
information
to
estimate
facility­
specific
equipment
leak
emissions.
Thus,
this
study
was
not
designed
to
provide
information
on
industry
average
percent
leaking
38
equipment.
Therefore,
it
was
not
possible
to
redefine
average
emission
factors.
To
actually
use
this
information,

however,
the
EPA
would
need
corresponding
new
information
on
the
percent
of
equipment
leaking.
The
EPA
does
not
believe
that
it
would
be
appropriate
to
combine
1993
information
with
the
1980
data
to
develop
new
emission
factors
because
sampling
methodologies
were
different
and
because
the
1993
study
collected
information
from
information
from
wellcontrolled
facilities
while
the
1980
study
collected
information
from
uncontrolled
facilities.
However,
the
EPA
agrees
that
new
correlation
equations
developed
for
the
refining
industry
indicate
that
the
refinery
factors
may
overestimate
emissions
by
as
much
as
a
factor
of
two,
which
may
make
the
modified
negotiated
rule
option
less
cost
effective.
This
cannot
be
accurately
determined
because
the
appropriate
information
to
update
average
emission
factors
is
not
available.
The
EPA
recognizes
that
enough
uncertainty
exists
in
the
emission
and
cost
estimates
to
question
the
results
of
the
cost­
effectiveness
analysis.

In
recognition
of
this
uncertainty
and
to
provide
compliance
flexibility,
the
EPA
has
changed
the
final
rule
to
provide
each
existing
refinery
with
a
choice
of
complying
with
either:
(
1)
The
equipment
leaks
NSPS
requirements
(
40
CFR
part
60,
subpart
VV)
or
(
2)
a
modified
version
of
the
negotiated
rule
(
40
CFR
part
63,
subpart
H).
The
NSPS
represents
the
MACT
floor
for
existing
sources.
The
39
modified
negotiated
regulation
is
the
same
as
what
was
contained
in
the
proposed
petroleum
refinery
NESHAP
except
that
the
compliance
dates
have
been
extended
for
reasons
described
below.
Although
not
required
in
the
final
rule,

the
EPA
promotes
use
of
the
modified
negotiated
rule
option
because
it
is
believed
to
provide
considerable
product,

emissions,
and
cost
savings
to
a
refinery.

Under
either
option,
existing
refineries
will
be
required
to
implement
an
LDAR
program
with
the
same
leak
definitions
(
10,000
ppm)
and
the
same
leak
frequencies
as
contained
in
the
NSPS
by
3
years
after
promulgation.
A
refinery
may
opt
to
remain
at
this
level
of
control
and
do
the
monitoring,
recordkeeping,
and
reporting
specified
in
the
NSPS.
This
option
allows
refineries
that
are
familiar
with
the
NSPS
to
continue
to
implement
that
standard
without
needing
to
change
their
procedures.

Alternatively,
a
refinery
may
choose
to
comply
with
Phase
I
of
the
negotiated
rule
(
10,000
ppm
leak
definition)

3
years
after
promulgation,
comply
with
Phase
II
4
years
after
promulgation,
and
comply
with
Phase
III
5
½
years
after
promulgation.
Each
phase
has
lower
leak
definitions
for
pumps
and
valves.
In
Phase
III,
monitoring
frequencies
for
valves
are
dependent
on
performance
(
percent
leakers),

providing
an
incentive
(
less
frequent
monitoring
and
reduced
monitoring
costs)
for
good
performance.
Refineries
choosing
to
comply
with
the
modified
negotiated
rule
are
subject
to
40
monitoring,
recordkeeping,
and
reporting
requirements
of
subpart
H.
The
EPA
has
included
this
compliance
alternative
to
add
flexibility
and
opportunities
for
adjustment
for
differences
among
facilities.

The
compliance
dates
for
equipment
leaks
were
revised
to
address
commenter
concerns
that
contended
that
small
refineries
and
refineries
in
ozone
attainment
areas
would
be
at
a
disadvantage
if
they
were
required
to
comply
with
the
proposed
equipment
leak
regulations
because
they
would
not
have
the
experience
to
implement
an
equipment
leaks
control
program
within
6
to
18
months.

The
EPA
agrees
that
small
refineries
may
not
have
the
experience
to
implement
an
LDAR
program
for
equipment
leaks
in
a
short
timeframe
without
significant
expense.
The
EPA
also
contends
that
other
refineries
that
do
not
currently
have
LDAR
programs
may
also
have
trouble
implementing
the
rule
in
6
to
18
months.
In
response
to
these
comments,
the
EPA
has
changed
the
final
rule
to
require
that
existing
refineries,
regardless
of
size,
comply
with
an
LDAR
program
with
the
same
leak
definitions
(
10,000
ppm)
and
monitoring
frequencies
as
the
petroleum
refinery
NSPS
within
3
years
of
promulgation
of
the
rule.
At
the
end
of
the
third
year,
the
entire
refinery
must
be
in
compliance
with
the
petroleum
refinery
NSPS
level
of
control;
there
will
not
be
interim
deadlines
during
the
3­
year
period
by
which
portions
of
the
refinery
are
required
to
comply
during
this
time.
A
41
refinery
owner
or
operator
who
chooses
to
comply
with
the
modified
negotiated
rule
must
then
implement
Phase
II
within
4
years
and
Phase
III
within
5
½
years
of
promulgation.
The
total
annual
cost
estimates
for
the
rule
have
been
revised
in
accordance
with
the
changes
made
to
the
equipment
leak
requirements.

D.
Storage
Vessels
The
proposed
rule
required
existing
storage
vessels
containing
liquids
with
vapor
pressures
greater
than
or
equal
to
8
kPa
(
1.2
psia)
to
comply
with
storage
vessel
requirements
within
3
years.
For
tanks
that
were
already
controlled
with
internal
or
external
floating
roofs,
the
proposed
rule
allowed
operators
to
defer
upgrading
of
seals
until
the
next
scheduled
maintenance
with
the
following
exceptions:
(
1)
Fixed
roof
tanks,
(
2)
EFR
tanks
with
only
a
vapor­
mounted
primary
seal,
and
(
3)
all
tanks
storing
a
liquid
with
a
true
vapor
pressure
greater
than
34
kPa
(
5.0
psia).

Commenters
to
the
proposed
rule
maintained
that
before
additional
emission
controls
(
e.
g.,
secondary
seals)
can
be
installed,
tanks
must
be
removed
from
service,
degassed,
and
cleaned.
Storage
tanks
are
currently
emptied
and
cleaned
roughly
every
10
years
for
inspection
and
maintenance.
The
commenters
contended
that
removing
storage
tanks
that
already
have
floating
roofs
from
service
before
scheduled
maintenance
would
have
adverse
environmental
impacts
that
42
could
not
be
overcome
by
the
emissions
reductions
from
upgrading
the
seals
on
the
tank.
The
commenters
further
stated
that
tank
owners
or
operators
would
incur
substantial
costs
as
a
result
of
degassing
and
cleaning
a
tank
before
scheduled
maintenance.
The
commenters
contended
that
a
3­
year
compliance
schedule
could
not
be
met
because
there
would
not
be
enough
trained
and
capable
fabricators
and
contractors
to
support
the
tank
modification
work.

Commenters
stated
that
the
reason
was
that
the
refinery
rule
compliance
period
overlaps
with
the
implementation
of
other
EPA
rules
and
that
a
10­
year
compliance
schedule
would
be
consistent
with
other
EPA
rulemakings
such
as
the
HON
and
the
benzene
storage
NESHAP.

The
EPA
agrees
with
the
commenters
that
the
HON
and
the
benzene
storage
NESHAP
allow
floating
roof
tanks
to
achieve
compliance
in
10
years
or
at
the
time
of
the
next
scheduled
degassing.
Most
existing
floating
roof
storage
vessels
at
refineries
also
fall
under
the
10­
year
compliance
schedule.

Therefore,
these
storage
vessels
will
be
inspected
within
5
to
10
years
after
promulgation
of
the
rule.
This
is
consistent
with
industry
practice.

In
response
to
these
comments,
the
EPA
analyzed
the
emissions
resulting
from
degassing
and
cleaning
storage
vessels
using
empirical
mass­
transfer
models.
The
analysis
indicated
that
degassing
and
cleaning
of
floating
roof
vessels
generally
results
in
substantial
volatilization
of
43
HAP's
to
the
air.
These
emissions
could
not
be
balanced
in
less
than
5
years
by
the
emission
reductions
achieved
by
controlling
the
tank
to
the
requirements
in
the
rule.

Additionally,
the
degassing
and
cleaning
information
submitted
by
the
refining
industry
indicated
substantial
costs
for
each
degassing
and
cleaning
activity
if
required
within
3
years
after
promulgation
of
the
rule.
Based
on
information
provided
by
industry
and
the
EPA's
empirical
analysis,
the
EPA
determined
that
the
proposed
storage
vessel
provisions
would,
in
many
cases,
result
in
increased
overall
emissions
because
of
the
extra
degassing
emissions.

The
final
rule
allows
owners
or
operators
of
storage
vessels
subject
to
the
rule
to
defer
installation
of
better
seals
on
floating
roof
tanks
storing
any
liquid
until
the
next
scheduled
maintenance
or
within
10
years,
whichever
comes
first.
This
change
addresses
the
commenters'
concerns
about
emissions
and
costs
as
well
as
their
concern
about
the
availability
of
trained
fabricators
and
contractors
to
modify
the
tanks
within
a
3­
year
period.
The
final
rule
maintains
the
requirement
to
retrofit
IFR
tanks
at
existing
sources
with
secondary
seals
that
meet
40
CFR
part
60
subpart
Kb
requirements
because
it
is
the
MACT
floor
for
IFR
vessels.

Based
on
the
EPA's
analysis,
the
emissions
from
degassing
and
cleaning
fixed
roof
tanks
can
be
balanced
within
1
year
(
justifying
a
3­
year
compliance
date)
by
the
44
emission
reductions
achieved
by
controlling
the
tank
to
the
requirements
in
the
rule.
Therefore,
the
final
rule
maintains
the
proposed
compliance
times
(
within
3
years)
for
fixed
roof
tanks.
The
EPA
believes
that
in
certain
situations,
such
as
when
replacement
of
a
tank
is
required,

it
would
be
reasonable
for
States
to
grant
an
additional
year
to
comply
as
authorized
under
section
112(
i)(
3)(
B)
of
the
Act.
The
additional
year
would
provide
time
to
design
and
construct
the
tanks
without
disrupting
refinery
operations
which
could
cause
additional
emissions.
The
EPA
will
work
with
the
industry
and
States
to
find
ways
to
use
the
emissions
averaging
program
to
deal
with
cases
where
tanks
have
to
replaced
or
where
it
is
extremely
difficult
or
costly
to
install
the
required
controls.

Several
commenters
contended
that
the
Group
1
definition
of
8
kPa
(
1.2
psia)
in
the
proposed
NESHAP
was
based
on
data
requests
in
section
114
and
ICR
questionnaires
that
were
misinterpreted
by
respondents.
The
commenters
stated
that
the
questionnaires
did
not
specify
whether
respondents
were
to
provide
maximum
true
vapor
pressures
or
average
annual
true
vapor
pressures.
The
commenters
elaborated
that
because
other
data
were
provided
to
estimate
emissions
on
an
annual
basis,
it
was
reasonable
to
assume
that
respondents
provided
average
annual
true
vapor
pressures
instead
of
maximum
true
vapor
pressures.
The
commenters
concluded
that
vapor
pressures
based
on
the
maximum
monthly
temperatures
45
may
be
0.3
psia
higher
than
the
average
annual
true
vapor
pressure.
The
commenters
recommended
that
the
EPA
either
change
the
applicability
cutoff
to
10
kPa
(
1.5
psia)
maximum
true
vapor
pressure
to
account
for
this
difference
or
specify
that
the
8
kPa
(
1.2
psia)
cutoff
is
the
average
annual
true
vapor
pressure
instead
of
the
maximum
true
vapor
pressure.

The
EPA
agrees
with
the
commenters
that
because
the
questionnaires
did
not
specify
the
type
of
vapor
pressure,

the
respondents
may
have
provided
annual
average
true
vapor
pressures
instead
of
maximum
true
vapor
pressures.
In
order
to
reflect
the
uncertainty
of
the
type
of
vapor
pressure
provided
in
the
questionnaires,
the
EPA
has
decided
to
change
the
storage
vessel
applicability
cutoff
in
the
final
rule
from
a
maximum
true
vapor
pressure
of
8
kPa
(
1.2
psia)

to
10
kPa
(
1.5
psia).
An
analysis
of
the
storage
vessel
data
base
indicated
that
a
change
from
8.3
kPa
(
1.2
psia)
to
10
kPa
(
1.5
psia)
will
not
affect
the
impacts
analysis.

Several
commenters
requested
that
a
minimum
HAP
content
be
considered
as
well
as
a
vapor
pressure
cut­
off
for
storage
vessels
because
some
liquids
may
have
very
low
HAP
concentrations
and
high
vapor
pressures
due
to
the
volatility
of
non­
HAP
compounds
in
the
material.
The
EPA
agrees
that
several
products,
such
as
asphalt,
have
minimal
HAP's
that
may
have
vapor
pressures
greater
than
10
kPa
(
1.5
psia)
if
stored
at
elevated
temperatures.
To
determine
46
HAP
weight
percent
applicability
criteria,
the
EPA
reviewed
the
MACT
floor
analysis
for
storage
vessels
to
determine
the
HAP
weight
percents
in
controlled
storage
vessels
at
the
best­
controlled
sources.
The
MACT
floor
for
new
sources
is
based
on
the
best­
controlled
source,
while
the
floor
for
existing
sources
is
the
average
of
the
best­
controlled
12
percent
of
sources
(
or
16
refineries).
The
HAP
weight
percent
applicability
criterion
was
determined
using
the
same
population
of
storage
tanks
used
to
determine
the
vapor
pressure
applicability
cut­
off
(
i.
e.,
the
best­
controlled
16
refineries).
The
minimum
HAP
concentrations
for
materials
stored
in
the
tanks
meeting
subpart
Kb
at
the
16
best­
controlled
sources
ranged
from
2
weight
percent
to
22
weight
percent.
The
average
HAP
weight
percent
in
the
liquids
stored
in
these
tanks
is
4
percent.
The
bestcontrolled
tanks
contain
liquids
with
a
HAP
weight
percent
in
the
liquid
of
2
percent.
Therefore,
the
HAP
weight
percent
criterion
for
existing
sources
is
4
percent
HAP
in
the
liquid;
the
HAP
weight
percent
for
new
sources
is
2
percent
HAP
in
the
liquid.

E.
Overlapping
Regulations
Several
commenters
contended
that
the
petroleum
refinery
NESHAP
will
lead
to
overlap
with
other
existing
and
future
regulations
such
as
the
40
CFR
part
60
NSPS,
40
CFR
parts
61
and
63
NESHAP,
and
State
and
local
regulations.
Commenters
stated
that
the
overlap
between
regulations
will
lead
to
47
confusion,
uncertainty,
and
frustration
for
sources
and
regulators.

The
EPA
has
clarified
the
applicability
of
subpart
CC
as
it
relates
to
other
NSPS
and
parts
61
and
63
NESHAP
that
apply
to
the
same
source
in
§
63.640
of
the
final
rule.

The
final
rule
clarifies
the
applicability
of
40
CFR
part
63,
subpart
CC
storage
vessel
provisions
to
storage
vessels
at
existing
and
new
petroleum
refinery
sources
subject
to
40
CFR
part
60,
subparts
K,
Ka,
or
Kb.
The
specific
provisions
are
structured
such
that
each
vessel
is
subject
to
only
the
more
stringent
rule.
For
example,
a
Group
1
storage
vessel
at
an
existing
refinery
that
is
also
subject
to
subpart
K
or
Ka
is
required
only
to
comply
with
the
petroleum
refinery
NESHAP
storage
vessel
provisions.

The
final
rule
clarifies
the
applicability
of
40
CFR
part
63,
subpart
CC
wastewater
provisions
by
stating
that
a
Group
1
wastewater
stream
managed
in
a
piece
of
equipment
that
is
also
subject
to
the
provisions
of
40
CFR
part
60,

subpart
QQQ
is
required
only
to
comply
with
40
CFR
part
63,

subpart
CC.
The
final
rule
also
clarifies
that
a
Group
2
wastewater
stream
managed
in
equipment
that
is
also
subject
to
the
provisions
of
40
CFR
part
60,
subpart
QQQ
is
required
only
to
comply
with
subpart
QQQ.
Clarification
of
the
applicable
provisions
for
a
wastewater
stream
that
is
conveyed,
stored,
or
treated
in
a
wastewater
stream
management
unit
that
also
receives
streams
subject
to
the
48
provisions
of
40
CFR
part
63,
subpart
F
has
been
included
in
the
final
rule.

There
should
not
be
any
process
vent
applicability
overlap
between
subpart
CC
and
any
other
Federal
rule.

Process
vents
regulated
under
the
HON
are
not
subject
to
the
petroleum
refinery
NESHAP.

The
EPA
clarifies
the
applicability
of
subpart
CC
equipment
leak
provisions
in
the
final
rule
by
stating
that
petroleum
refinery
sources
subject
to
subpart
CC
and
40
CFR
parts
60
or
61
equipment
leaks
regulations
are
required
to
comply
only
with
the
petroleum
refinery
NESHAP
(
40
CFR
part
63,
subpart
CC)
equipment
leak
provisions.

The
EPA
has
also
included
a
Standard
Industrial
Classification
(
SIC)
code
definition
for
petroleum
refining
(
2911)
to
the
petroleum
refinery
process
units
definition
in
the
final
rule
in
order
to
clarify
which
provisions
of
the
rule
apply
to
storage
vessels
and
equipment
leaks.
The
EPA
believes
that
the
inclusion
of
the
SIC
code
reference
in
the
definition
of
refinery
process
unit
will
alleviate
confusion
about
applicability
of
this
rule
(
reducing
potential
confusion
regarding
process
unit
regulatory
overlap)
and
other
source
categories
scheduled
for
the
development
of
NESHAP
under
the
Act.
The
EPA
has
also
added
a
list
of
pollutants
covered
under
the
rule
to
assist
facilities
in
the
determination
of
whether
emission
points
are
covered
under
the
rule.
49
Another
issue
raised
by
several
commenters
was
the
potential
for
overlap
between
the
petroleum
refinery
MACT
and
other
MACT
standards
such
as
the
HON.
These
commenters
requested
that
the
EPA
clarify
the
distinction
between
process
units
subject
to
the
HON
or
other
MACT
standards
and
process
units
subject
to
the
petroleum
refinery
MACT
standard.
These
commenters
thought
that
the
description
of
refinery
process
units
was
too
general
and
could
include
chemical
processes
subject
to
the
HON
or
other
MACT
standards.

The
final
rule
provides
that
40
CFR
part
63,
subpart
CC
does
not
apply
to
units
that
are
also
subject
to
the
provisions
of
the
HON.
The
applicability
of
subpart
CC
versus
the
HON
or
other
MACT
standard
to
an
emission
point
is
determined
by
the
primary
product
produced
in
the
unit.

The
primary
product
is
the
product
that
is
produced
in
the
greatest
mass
or
volume
that
the
unit
produces.
For
example,
if
a
refinery
operates
a
unit
that
produces
upgraded
feedstock
for
the
alkylation
unit
and
this
unit
also
produces
a
small
quantity
(
less
than
20
percent)
of
the
chemical
methyl
tert
butyl
ether
(
MTBE),
that
unit
is
considered
to
be
subject
to
the
petroleum
refinery
MACT
standard
and
not
to
the
HON.
In
contrast,
if
a
facility
operated
a
process
unit
that
produced
MTBE
as
the
primary
product
and
also
produced
small
quantities
of
a
mixed
hydrocarbon
stream,
the
unit
would
be
subject
to
the
HON
50
because
the
unit
produces
MTBE
as
the
primary
product
and
the
HON
applies
to
chemical
manufacturing
units
that
produce
MTBE.
The
distinction
between
the
units
is
the
difference
in
the
primary
product
produced
in
the
different
units.
In
the
first
case,
the
unit
is
integral
to
the
petroleum
refinery's
operations
and
the
MTBE
is
a
by­
product
of
the
unit.
In
the
second
case,
the
unit's
operation
could
be
replaced
by
purchased
MTBE
and
the
operation
is
not
integral
to
the
petroleum
refinery's
operations.

The
EPA
believes
that
including
the
concept
of
primary
use
in
the
petroleum
refining
process
unit
definition
clarifies
the
applicability
of
the
petroleum
refinery
MACT
standard,
and
that
including
the
primary
product
concept
in
HON
and
other
MACT
standards
will
avoid
the
same
emission
point
from
the
same
process
unit
being
subject
to
multiple
MACT
standards.
The
EPA
also
believes
that
by
directly
stating
in
the
rule
that
process
units
subject
to
the
HON
are
not
subject
to
this
rule,
the
commenter's
concerns
over
applicability
issues
have
been
addressed.

F.
Source
Category
Definition
In
the
July
1994
notice
of
proposed
rulemaking,
the
proposed
rule
preamble
provided
notice
of
and
sought
comment
on
the
issues
of
a
broad
affected
source
definition
and
source
category;
source­
wide
averaging;
and
the
relationship
between
the
gasoline
distribution
affected
source
definition
and
source
category
and
refineries.
In
the
preamble
of
the
51
proposed
refinery
rule,
the
EPA
noted
that
it
did
not
intend
to
include
emission
points
that
are
subject
to
the
gasoline
distribution
standard
in
the
refinery
source
category,
that
all
emission
points
within
the
refinery
source
category
would
be
treated
as
one
stationary
source
for
purposes
of
the
refinery
standard,
and
that
the
EPA
intended
to
permit
averaging
among
all
emission
points
within
the
source
category
except
for
equipment
leaks.

Comments
on
both
the
gasoline
distribution
rule
and
the
refinery
proposal
indicated
that
the
Agency
needed
to
clarify
which
rule
applied
to
which
emissions
points
and
whether
averaging
would
apply
to
collocated
emission
points.

Both
proposed
rules
addressed
similar
emission
points;
for
example,
both
proposed
rules
addressed
storage
tanks
and
equipment
leaks
where
refineries
were
collocated
with
gasoline
distribution
operations.
In
the
preamble
accompanying
the
final
gasoline
distribution
rule,
the
EPA
indicated
the
intent
to
rely
on
SIC
codes
to
distinguish
between
emission
points
at
refineries
covered
by
the
gasoline
distribution
standard
and
those
covered
by
the
refinery
standard.
The
Agency
noted
that
the
SIC
code
for
particular
equipment
would
indicate
the
department
with
managerial
oversight
responsibility
for
each
emission
point.

However,
the
EPA
specifically
provided
that
this
rule,
if
appropriate,
would
modify
the
gasoline
distribution
standard
to
incorporate
SIC
code
limits.
52
Today's
rule
identifies
petroleum
refinery
process
units
and
the
gasoline
loading
rack
emission
points
by
SIC
code
for
purposes
of
identifying
the
appropriate
control
requirements.
A
broad
source
category
and
affected
source
definition
increases
the
opportunity
to
use
flexible
compliance
options
such
as
emissions
averaging.
Because
the
control
technology
under
today's
rule
for
gasoline
loading
racks
is
the
same
as
the
requirements
under
the
gasoline
distribution
NESHAP,
the
required
emissions
reductions
from
gasoline
loading
racks
would
be
at
least
as
great
as
would
have
been
required
had
gasoline
loading
racks
been
excluded
from
the
petroleum
refinery
source
category
and
affected
source;
due
to
the
credit
discount
factors,
overall
emissions
may
be
less
than
otherwise
would
be
required
if
gasoline
loading
racks
are
included
in
an
emissions
averaging
plan.

G.
Emissions
Averaging
The
preamble
to
the
proposed
petroleum
refinery
rule
requested
comments
on
whether
marine
loading
operations
at
refineries
should
be
included
in
emissions
averaging.
The
EPA
also
reopened
the
comment
period
for
the
proposed
NESHAP
for
marine
tank
vessel
loading
operations
(
59
FR
44955)
to
request
comment
on
whether
marine
terminals
collocated
at
refineries
should
be
moved
to
the
petroleum
refinery
source
category.
In
addition,
as
noted
above,
issues
related
to
53
including
gasoline
distribution
emissions
in
averaging
at
refineries
were
also
raised
in
the
proposed
rule
preamble.

During
the
comment
period
for
the
gasoline
distribution
NESHAP,
commenters
requested
that
gasoline
bulk
terminals
contiguous
to
a
refinery
be
regulated
by
the
petroleum
refinery
NESHAP.
Several
commenters
on
the
proposed
petroleum
refinery
NESHAP
and
proposed
marine
tank
vessel
loading
operations
NESHAP
supported
averaging
of
refinery
process
unit
emissions
with
emissions
from
marine
terminals
and
gasoline
distribution
operations
that
are
located
at
refineries.
The
commenters
cited
more
cost­
effective
emission
reduction
as
the
advantage
of
including
these
emission
points
in
emissions
averaging,
and
specifically
commented
that
the
costs
per
megagram
emission
reduction
of
the
marine
loading
controls
are
high.
These
commenters
also
claimed
that
emission
calculation
procedures
for
loading
are
well
established
and
that
adding
marine
loading
to
the
averaging
provisions
will
not
appreciably
increase
the
complexity
of
enforcement.
Other
commenters
opposed
including
marine
loading
and
gasoline
distribution
emission
points
in
emissions
averaging.
Some
commenters
claimed
that
these
are
separate
source
categories
and
that
the
Act
does
not
permit
averaging
across
source
categories.
Other
commenters
were
of
the
opinion
that
the
EPA
has
the
flexibility
to
allow
trading
within
a
facility
that
includes
units
in
different
source
categories.
These
commenters
54
argued
that
it
is
unnecessary
to
redefine
the
source
category
to
include
marine
loading
operations
and
gasoline
distribution
operations
colocated
at
refineries.

In
the
final
rule,
the
definitions
of
the
petroleum
refinery
source
category
and
affected
source
have
been
changed
to
include
gasoline
loading
racks
classified
under
SIC
code
2911
(
Petroleum
Refineries)
and
marine
tank
vessel
loading
operations
that
are
located
at
refinery
plant
sites.

Because
marine
loading
operations
and
bulk
gasoline
transfer
operations
located
at
refineries
are
supplying
raw
materials
to,
or
transferring
products
from,
petroleum
refinery
process
units,
they
are
logically
considered
to
be
part
of
the
same
source
as
the
petroleum
refinery
process
units.

The
EPA
considers
this
definition
to
be
the
most
appropriate
definition
and,
as
noted
by
several
commenters,
to
present
fewer
implementation
problems.

A
gasoline
loading
rack
classified
under
SIC
code
2911
or
a
marine
tank
vessel
loading
operation
that
is
located
at
a
petroleum
refinery
may
be
included
in
an
emissions
average
with
other
refinery
process
unit
emission
points.
Because
these
operations
are
included
as
part
of
a
single
source
within
one
source
category
intersource
averaging
is
not
an
issue.

In
keeping
with
the
EPA's
stated
goal
of
increasing
flexibility
in
rulemakings,
this
decision
has
been
made
to
provide
more
opportunities
to
average.
This
increases
the
55
opportunities
for
refiners
to
find
cost­
effective
emission
reductions
from
overall
facility
operations
onsite.
Costs
and
cost
effectiveness
of
controlling
a
particular
kind
of
emission
point,
such
as
marine
loading,
will
vary
depending
on
many
site­
specific
factors.
Emissions
averaging
allows
the
owner
and
operator
to
find
the
optimal
control
strategy
for
their
particular
situation.

The
EPA
is
presently
reviewing
the
emission
averaging
policy
and
considering
whether
any
more
flexibility
can
be
provided
while
maintaining
environmental
protection.
The
issue
of
intersource
averaging
will
be
considered
along
with
other
aspects
of
the
emissions
averaging
policy.
The
EPA
believes
that
any
decision
to
provide
additional
flexibility
must
be
based
on
careful
consideration
of
enforcement
issues
as
well
as
equity
in
environmental
protection.
Given
the
complexity
of
these
issues,
the
EPA
does
not
believe
that
the
Refinery
MACT
standard
is
the
appropriate
place
to
address
these
issues.
The
EPA
plans
to
examine
the
issue
independently
of
any
specific
rulemaking.
In
this,
the
EPA
plans
to
work
closely
with
both
the
refining
and
chemical
industries
and
other
interested
parties
to
determine
if
there
are
opportunities
for
increasing
flexibility
and
reducing
the
burden
associated
with
demonstrating
compliance
with
the
MACT
rules
while
remaining
within
the
law.

The
EPA
would
like
to
clarify
that
the
emissions
averaging
program
was
designed
to
result
in
equal
or
greater
56
environmental
protection
while
providing
sources
flexibility
to
reduce
emissions
in
the
most
cost­
effective
manner.

Specifically,
allowing
marine
loading
operations,
and
gasoline
loading
racks
classified
under
SIC
code
2911,

located
at
a
refinery
to
be
included
in
emissions
averages
will
result
in
equivalent
or
greater
overall
HAP
emission
reduction
at
each
refinery.
The
averaging
provisions
are
structured
such
that
"
debits"
generated
by
not
controlling
an
emission
point
that
otherwise
would
require
control
must
be
balanced
by
achieving
extra
control
at
other
refinery
emission
points
covered
by
the
NESHAP.
The
averaging
provisions
also
require
that
a
source
demonstrate
that
compliance
through
averaging
will
not
result
in
greater
risk
or
hazard
than
compliance
without
averaging.

Some
commenters
were
concerned
that
including
marine
loading
in
averages
could
result
in
uncontrolled
peak
emissions.
With
regard
to
the
commenters'
concerns
about
peak
emissions,
the
quarterly
cap
on
the
ratio
of
debits
to
credits
is
intended
to
limit
the
possibility
of
exposure
peaks.
Furthermore,
because
loading
occurs
fairly
frequently,
and
emissions
from
an
individual
vessel
filling
or
loading
event
are
relatively
small,
such
emissions
are
not
expected
to
cause
significant
exposure
peaks.
Moreover,

no
evidence
has
been
presented
that
emissions
averaging
would
permit
a
very
different
mix
of
emissions
to
occur
than
would
point­
by­
point
compliance.
That
is,
peaks
of
57
exposures
from
batch
streams,
storage,
and
loading
operations
should
be
equally
likely
under
point­
by­
point
compliance
as
under
emissions
averaging,
so
emissions
averaging
does
not
represent
a
less
effective
control
strategy.
Furthermore,
in
order
to
receive
approval
for
an
emissions
average,
the
owner
or
operator
is
required
to
demonstrate
that
the
emissions
average
does
not
increase
the
risk
or
hazard
relative
to
compliance
without
averaging.

H.
Monitoring,
Recordkeeping,
and
Reporting
Several
commenters
alleged
that
the
recordkeeping
and
reporting
requirements
of
the
proposed
rule
were
extremely
burdensome.
The
commenters
requested
that
the
EPA
reduce
the
monitoring,
recordkeeping,
and
reporting
burden
associated
with
the
proposed
rule.
Commenters
also
requested
that
provisions
be
added
to
the
final
rule
to
avoid
duplicative
reporting
for
equipment
subject
to
multiple
NESHAP
and
NSPS.
Other
commenters
requested
that
flexibility
to
allow
alternative
monitoring,
recordkeeping,

and
reporting
be
incorporated
into
the
final
rule.

The
EPA
recognizes
that
unnecessary
monitoring,

recordkeeping,
and
reporting
requirements
would
burden
both
the
source
and
enforcement
agencies.
Prior
to
proposal,
the
EPA
attempted
to
reduce
the
amount
of
monitoring,

recordkeeping,
and
reporting
to
only
that
which
is
necessary
to
demonstrate
compliance.
For
example,
at
proposal
almost
all
reports
were
consolidated
into
the
Notification
of
58
Compliance
Status
and
the
Periodic
Reports.
This
was
done
to
simplify
and
reduce
the
frequency
of
reporting.
Sources
also
have
the
option
of
retaining
records
either
in
paper
copy
or
in
computer­
readable
formats,
whichever
is
less
burdensome.
If
multiple
performance
tests
are
conducted
for
the
same
kind
of
emission
point
using
the
same
test
method,

only
one
complete
test
report
is
submitted
along
with
summaries
of
the
results
of
other
tests.
This
reduces
the
number
of
lengthy
test
reports
to
be
copied,
reviewed,
and
submitted.

Site­
specific
test
plans
describing
quality
assurance
in
§
63.7(
c)
of
40
CFR
part
63,
subpart
A
are
not
required
because
the
test
methods
cited
in
subpart
CC
already
contain
applicable
quality
assurance
protocols.
The
quality
assurance
provisions
in
the
individual
test
methods
remain
applicable
and
are
not
superseded
by
the
nonapplicability
of
§
63.7(
c)
of
subpart
A.
For
continuously
monitored
parameters,
periodic
reporting
is
limited
to
excursions
outside
the
established
ranges
and
the
in­
range
values
are
not
required
to
be
reported.

In
response
to
the
commenters,
the
EPA
reevaluated
whether
monitoring,
recordkeeping,
and
reporting
requirements
could
be
further
reduced
while
maintaining
the
enforceability
of
the
rule.
The
EPA
has
made
the
following
changes
in
the
promulgated
rule
to
further
reduce
the
monitoring,
recordkeeping,
and
reporting
burden:
59
(
1)
The
requirement
to
submit
an
Initial
Notification
has
been
eliminated;

(
2)
periodic
reports
are
required
to
be
submitted
semiannually
for
all
facilities
that
do
not
use
emissions
averaging
(
the
proposal
required
quarterly
reports
if
monitored
parameters
were
out
of
range
more
than
a
specified
percentage
of
the
time);

(
3)
a
reduction
in
the
frequency
for
parameter
monitoring
and
recording.
The
proposal
required
values
of
monitored
parameters
to
be
recorded
every
15
minutes
and
all
15­
minute
records
had
to
be
retained
for
those
days
when
excess
emissions
occurred.
The
final
rule
allows
hourly
monitoring
and
recording;

(
4)
recordkeeping
and
reporting
provisions
that
eliminate
duplicate
reporting
for
equipment
subject
to
multiple
NESHAP
and
NSPS
were
added
to
the
applicability
section
(
§
63.640)
of
the
final
rule.
The
additions
specify
which
rule
applies
and
overrides
the
less
stringent
NSPS
or
NESHAP.
For
State
and
local
regulation
applicability
determination,
the
final
rule
has
been
amended
to
state
that
the
local
regulatory
authority
(
e.
g.,
State
or
permitting
authority)
can
decide
how
monitoring,
recordkeeping,
and
reporting
requirements
can
be
consolidated,
and
can
approve
alternative
monitoring,
recordkeeping,
and
reporting
requirements.
60
These
reductions
reduce
the
proposal
monitoring,

recordkeeping,
and
reporting
burden
by
25
percent.
The
EPA
plans
to
continue
to
work
with
the
industry
as
well
as
with
other
interested
parties
to
identify
further
opportunities
for
reduction
of
the
monitoring,
recordkeeping,
and
reporting
burden
of
the
rule.
The
EPA
will
consider
ways
to
eliminate
overlapping
requirements
and
to
address
any
inconsistencies
among
the
rules.
The
EPA
will
investigate
the
possibility
of
consolidating
and
simplifying
the
various
rules
while
maintaining
the
same
level
of
environmental
protection.
Assuming
that
the
pilot
project
with
the
chemical
industry
is
successful,
the
EPA
expects
to
be
able
to
complete
the
review
of
the
Refinery
rule
monitoring,

recordkeeping,
and
reporting
requirements
before
the
compliance
date.

I.
Subcategorization
Several
commenters
to
the
proposed
petroleum
refinery
NESHAP
requested
that
the
EPA
subcategorize
refineries
by
size
and/
or
location
in
an
ozone
attainment
area.
Other
commenters
stated
that
subcategorizing
small
refineries
because
of
an
arbitrary
size
exemption
can
result
in
an
unfair
competitive
advantage.
These
commenters
further
elaborated
that
large
refineries
should
not
be
penalized
for
an
economy
of
scale
achieved
through
its
own
effective
competitiveness.
61
In
response
to
these
comments,
the
refinery
data
bases
were
subcategorized
based
on
crude
charge
capacity.
The
refineries
were
also
subcategorized
by
ozone
attainment
status
and
by
refineries
containing
processes
that
are
used
to
produce
gasoline
(
such
as
catalytic
cracking,
coking,
and
catalytic
reforming).
Within
each
subcategory,
the
process
vents,
storage
vessels,
and
equipment
leaks
data
bases
were
sorted
from
most
stringent
control
to
least
stringent.
The
MACT
floor
(
average
of
the
top
12
percent
of
sources)
for
each
subcategory
was
identified.

The
MACT
floors
for
small
refineries
are
not
significantly
different
from
the
industry
as
a
whole.
The
floor
for
process
vents
is
the
same
for
small
refiners
as
for
the
entire
industry.
The
floor
for
storage
tanks
would
increase
the
materials
vapor
pressure
cutoff
from
10
kPa
(
1.5
psia)
to
11
kPa
(
1.7
psia),
which
would
result
in
a
minimal
cost
savings
since
there
are
few
petroleum
liquids
in
this
volatility
range.
The
floor
for
equipment
leaks
would
reduce
the
monitoring
frequency;
however,
small
refiners
would
still
incur
the
cost
of
setting
up
and
implementing
an
LDAR
program.

Based
on
the
EPA's
analysis
and
the
comments
received
during
the
public
comment
period,
a
separate
subcategory
for
small
refineries
has
not
been
included
in
the
final
rule.

This
decision
was
based
on
there
being
no
clear
relationship
62
between
refinery
size
or
design
and
emission
potential.

J.
Economic
Analysis
Comments
were
received
on
both
the
methodology
of
the
economic
analysis
and
the
potential
impacts
of
the
analysis
results.
The
EPA's
economic
model
focused
on
estimating
changes
in
product
price
and
quantity
of
production
for
several
petroleum
products.
Once
the
effects
on
price
and
quantity
were
evaluated,
other
impacts
were
estimated.
The
model
the
EPA
used
is
predicated
on
neoclassical
microeconomic
theory.

The
model
assumed
that
those
refineries
with
the
highest
per­
unit
control
are
marginal
(
i.
e.,
near
the
margin
between
shutdown
and
continuing
operation)
in
the
post­
control
markets,
and
that
they
also
have
the
highest
underlying
perunit
cost
of
production.
This
assumption
may
result
in
an
overstatement
of
the
adverse
impacts,
such
as
closure,
since
the
assumed
relationship
between
per­
unit
control
cost
and
per­
unit
production
cost
may
not
hold
for
all
refineries.

For
more
information,
consult
the
"
Economic
Impact
Analysis
for
the
Petroleum
Refinery
NESHAP"
in
the
docket.

Most
of
the
comments
about
the
economic
analyses
methodology
were
focused
on
possible
impacts
on
other
parts
of
the
petroleum
industry
other
than
refineries.
The
economic
analysis
for
this
rule,
like
most
of
the
EPA's
economic
analyses,
focuses
on
the
impacts
on
the
industry
63
being
regulated
and
does
not
calculate
impacts
to
other
industries
indirectly
affected
unless
those
impacts
are
significant.
In
this
case,
the
impacts
to
indirectly
affected
industries
were
not
calculated
since
the
impacts
estimated
for
the
petroleum
refinery
industry
were
not
significant,
impacts
to
indirectly
affected
industries
would
likely
be
insignificant
also.

K.
Benefits
Analysis
Comments
noted
that
naphthalene
is
classified
as
a
possible
carcinogen,
not
a
known
carcinogen,
and
therefore
should
not
be
included
in
the
risk
analysis.
Commenters
also
argued
that
the
estimates
for
monetized
VOC
benefits
were
too
high,
since
the
VOC
reductions
claimed
in
the
regulation
would
occur
as
a
result
of
State
Implementation
Plans
(
SIP's)
required
by
the
Act.
Other
commenters
wrote
that
the
level
of
benefits
from
HAP
emissions
reduction
was
not
of
sufficient
justification
for
pursuing
the
regulation.

When
the
rule
was
proposed,
naphthalene
was
classified
as
a
possible
human
carcinogen.
Naphthalene
is
no
longer
classified
as
a
possible
human
carcinogen
and
is
not
included
in
the
risk
analysis
for
the
final
rule.

To
estimate
the
benefits
of
reducing
VOC,
the
EPA
used
a
1989
study
conducted
by
the
Office
of
Technology
Assessment
(
OTA).
The
study
examined
a
variety
of
acute
health
impacts
related
to
ozone
exposure
as
well
as
the
benefits
of
reduced
ozone
concentrations
for
selected
agricultural
crops.
64
However,
two
factors
not
considered
in
the
analysis
suggest
that
higher
benefits
may
be
realized
than
were
estimated.

First,
chronic
health
effects,
including
leukemia,

craniofacial
and
limb
abnormalities
in
newborns,
nausea,

dizziness,
headaches,
and
irritation
of
upper
respiratory
track
and
eyes,
are
difficult
to
quantify
and
consequently
were
not
monetized.
Second,
health
impacts
in
the
OTA
study
were
estimated
for
nonattainment
areas
only.
The
potential
impacts
of
this
second
factor
are
likely
to
be
underestimated
due
to
recent
evidence
suggesting
acute
health
effects
may
also
be
experienced
at
ozone
concentrations
below
the
current
national
ambient
air
quality
standards.

As
to
the
comment
about
some
of
the
benefits
being
attributable
to
VOC
emission
reductions
brought
about
by
implementing
SIP's,
the
EPA
attempted
to
include
in
the
baseline
all
possible
impacts
from
SIP
implementation.

Control
of
VOC
in
this
rule
will
be
incorporated
into
future
SIP's
by
affecting
their
baselines,
thus
making
the
emission
reductions
needed
to
meet
them
less,
and
leading
to
lower
costs
for
petroleum
refineries
to
meet
those
SIP's.

Therefore,
control
of
VOC
emissions
in
this
rule
will
lead
to
lower
costs
to
future
SIP
implementation.
Also,
the
emission
streams
from
petroleum
refineries
are
primarily
VOC,
with
a
small
fraction
of
VOC
being
HAP.
Control
of
any
petroleum
refinery
emission
stream
involves
control
of
VOC
65
as
well
as
HAP.
Thus,
any
benefits
estimated
to
occur
from
a
rule
that
controls
VOC,
though
their
control
is
of
secondary
importance,
should
be
included
as
benefits
of
the
rule.

L.
Emissions
Data
Commenters
raised
concerns
about
the
amount
and
quality
of
the
data
on
HAP
emissions,
and
the
uncertainties
in
the
emission
estimates.
Throughout
the
rulemaking,
the
EPA
has
been
aware
of
these
concerns.
During
the
course
of
this
rulemaking,
the
EPA
requested
information
from
the
petroleum
refining
industry
on
emissions
and
emission
control
technologies.
The
industry
provided
sufficient
information
on
the
emission
control
technologies
to
determine
the
best
controlled
facilities,
as
required
by
section
112
of
the
Act.
However,
the
information
received
on
existing
emission
control
levels
was
limited
because
it
was
not
available.

Thus,
there
is
uncertainty
in
the
refinery
baseline
emission
estimates,
and
emission
reductions
and
other
benefits
achieved
from
the
emission
controls
required
to
comply
with
the
rule.
The
EPA
and
the
petroleum
refinery
industry
are
unable
to
reduce
this
uncertainty
at
this
time.
The
Agency
has
characterized
the
costs
and
emission
reductions
of
the
requirements
of
this
rule
as
accurately
as
possible.
While
there
is
a
great
deal
of
qualitative
information
on
the
benefits
of
this
rule,
the
uncertainty
in
the
emission
estimates
and
the
monetary
value
that
can
be
placed
on
the
66
emission
reductions
limits
the
Agency's
ability
to
directly
quantify
all
the
benefits
of
the
refinery
MACT
rule.
The
EPA
does
know,
however,
that
the
controls
required
in
this
rulemaking
are
in
widespread
use
in
the
refining
industry
and
that
they
provide
substantial
emission
reductions.

Under
section
112(
f)
of
the
Act,
the
EPA
must
determine
whether
further
control
of
refinery
emissions
is
necessary
to
protect
the
health
of
the
general
public.
This
determination
will
require
more
accurate
emission
estimates
than
currently
exist.
The
EPA
has
made
a
commitment
to
work
cooperatively
with
industry
to
identify
the
data
needed
to
improve
the
emission
estimates
and
any
other
information
that
is
required
to
determine
the
health
risks
that
may
remain
after
implementation
of
the
refinery
MACT
rule.

VI.
Changes
to
NSPS
The
proposed
changes
to
40
CFR
part
60,
subparts
VV
and
QQQ
are
promulgated
with
minor
edits
for
clarity
and
consistency.

VII.
Administrative
Requirements
A.
Docket
The
docket
is
an
organized
and
complete
file
of
all
the
information
considered
by
the
EPA
in
the
development
of
this
rulemaking.
The
docket
is
a
dynamic
file,
since
material
is
added
throughout
the
rulemaking
development.
The
docketing
system
is
intended
to
allow
members
of
the
public
and
industries
involved
to
readily
identify
and
locate
documents
67
so
that
they
can
effectively
participate
in
the
rulemaking
process.
Along
with
the
proposed
and
promulgated
standards
and
their
preambles,
and
the
BID
containing
the
EPA's
responses
to
significant
comments,
the
contents
of
the
docket
will
serve
as
the
record
in
case
of
judicial
review
(
section
307(
d)(
7)(
A)).

B.
Paperwork
Reduction
Act
The
information
collection
requirements
in
this
rule
have
been
submitted
for
approval
to
the
Office
of
Management
and
Budget
(
OMB)
under
the
provisions
of
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
An
Information
Collection
Request
(
ICR)
document
has
been
prepared
by
the
EPA
(
ICR
No.
1692.02)
and
a
copy
may
be
obtained
from
Sandy
Farmer,
Information
Policy
Branch;
EPA;
401
M
Street,
S.
W.

(
Mail
Code
2136);
Washington,
DC
20460
or
by
calling
(
202)
260­
2740.
These
requirements
are
not
effective
until
OMB
approves
them
and
a
technical
amendment
to
that
effect
is
published
in
the
Federal
Register.

This
collection
of
information
has
an
estimated
annual
reporting
burden
averaging
320
hours
per
respondent
and
an
estimated
annual
recordkeeping
burden
averaging
2,880
hours
per
respondent.
These
estimates
include
time
for
reviewing
instructions,
searching
existing
data
sources,
gathering
and
maintaining
the
data
needed,
and
completing
and
reviewing
the
collection
of
information.
68
Send
comments
regarding
the
burden
estimate
or
any
other
aspect
of
this
collection
of
information,
including
suggestions
for
reducing
this
burden
to
Chief,
Information
Policy
Branch;
EPA;
401
M
St.,
S.
W.
(
Mail
Code
2136);

Washington,
DC
20460;
and
to
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,

Washington,
DC
20503,
marked
"
Attention:
Desk
Officer
for
EPA."

C.
Executive
Order
12866
Under
Executive
Order
12866
(
58
FR
5173
(
October
4,
1993)),
the
Agency
must
determine
whether
the
regulatory
action
is
"
significant"
and
therefore
subject
to
OMB
review
and
the
requirements
of
the
Executive
Order.
The
Order
defines
"
significant
regulatory
action"
as
one
that
is
likely
to
result
in
a
rule
that
may:

(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,

competition,
jobs,
the
environment,
public
health
or
safety,

or
State,
local,
or
tribal
governments
or
communities;

(
2)
create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;

(
3)
materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs
or
the
rights
and
obligations
of
recipients
thereof;
or
69
(
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.

This
action
is
a
"
significant
regulatory
action"
within
the
meaning
of
Executive
Order
12866.
The
EPA
has
submitted
this
action
to
OMB
for
review.
Changes
made
in
response
to
OMB
suggestions
or
recommendations
will
be
documented
in
the
public
record.

D.
Regulatory
Flexibility
Act
Pursuant
to
the
Regulatory
Flexibility
Act
of
1980,

5
U.
S.
C.
601
et
seq.,
when
an
agency
publishes
a
notice
of
rulemaking,
for
a
rule
that
will
have
a
significant
effect
on
a
substantial
number
of
small
entities,
the
agency
must
prepare
and
make
available
for
public
comment
a
regulatory
flexibility
analysis
(
RFA)
that
considers
the
effect
of
the
rule
on
small
entities
(
i.
e.,
small
businesses,
small
organizations,
and
small
governmental
jurisdictions).
In
assessing
the
regulatory
approach
for
dealing
with
small
entities
in
today's
final
rule,
the
EPA
guidelines
indicate
that
an
economic
impact
should
be
considered
significant
if
it
meets
one
of
the
following
criteria:

(
1)
Compliance
increases
annual
production
costs
by
more
than
5
percent,
assuming
costs
are
passed
on
to
consumers;
70
(
2)
compliance
costs
as
a
percentage
of
sales
for
small
entities
are
at
least
10
percent
more
than
compliance
costs
as
a
percentage
of
sales
for
large
entities;

(
3)
capital
costs
of
compliance
represent
a
"
significant"
portion
of
capital
available
to
small
entities,
considering
internal
cash
flow
plus
external
financial
capabilities,
or
(
4)
regulatory
requirements
are
likely
to
result
in
closure
of
small
entities.

Data
were
not
readily
available
to
determine
if
criteria
(
1)
and
(
3)
were
met
or
not,
so
the
analysis
focused
on
the
other
two.
Results
from
the
economic
impact
analysis
indicate
that
between
zero
and
seven
refiners,
all
of
which
are
classified
as
small,
are
at
risk
of
closure
(
refer
to
the
"
Economic
Impact
Analysis
of
the
Regulatory
Alternatives
for
the
Petroleum
Refineries
NESHAP"
in
the
Background
Information
Documents
section).
While
this
percentage
of
net
closures
is
less
than
20
percent
of
the
total
number
of
small
refineries
(
88),
it
was
deemed
high
enough
for
carrying
out
an
RFA
on
that
basis
alone.

Criterion
(
2),
however,
was
satisfied.
The
compliance
costs­
to­
sales
ratio
for
the
small
refiners
was
more
than
10
percent
greater
than
the
same
ratio
calculated
for
all
other
refiners.

There
are
four
reasons
why
small
entities
are
disproportionately
affected
by
the
regulation.
The
first
is
71
the
fact
that
they
tend
to
own
smaller
facilities,
and
therefore
have
smaller
economics
of
scale.
Because
of
the
smaller
economies
of
scale,
per­
unit
costs
of
production
and
compliance
are
higher
for
the
small
refiners
compared
to
others.
Related
to
this
is
the
fact
that
small
refiners
have
less
ability
to
produce
differentiated
products.
This
ability,
called
complexity,
increases
with
increasing
refinery
capacity.
A
large
refinery
can
respond
to
a
relative
increase
in
production
costs
for
one
product
by
increasing
production
of
a
product
now
relatively
cheaper
to
produce,
an
ability
most
small
refiners
rarely
enjoy.

A
second
reason
is
they
have
fewer
capital
resources.

Small
refineries
have
less
ability
to
finance
the
capital
expenditures
needed
to
purchase
the
equipment
required
to
comply
with
the
regulation.
A
third
reason
is
the
difference
in
internal
structure.
None
of
the
small
refiners
are
vertically
or
horizontally
integrated,
and
in
all
but
a
few
cases
are
not
the
subsidiary
of
a
large
parent
company.
The
small
refiners
are
typically
independent
owners
and
operators
of
their
facilities,
and
most
are
owners
of
a
single
refinery.
They
do
not
possess
the
ability
to
shift
production
between
different
refineries
and
have
less
market
power
than
their
large
competitors.

A
fourth
reason
why
smaller
refiners
experience
greater
economic
impacts
than
other
refiners
is
due
to
the
small
industry­
level
price
increases
(
less
than
1
percent
in
all
72
cases).
It
is
unlikely
that
small
refiners
will
be
able
to
recover
annualized
control
costs
by
increasing
product
prices,
since
the
large
refiners
will
not
be
significantly
impacted.
As
seen
in
the
examination
of
criterion
(
2),
the
large
refiners
will
not
be
significantly
affected
from
compliance
with
the
regulation.

In
calculating
the
number
of
closures,
the
assumption
was
made
that
those
refineries
with
the
highest
per­
unit
control
costs
were
marginal
after
compliance
with
the
regulation.
While
this
assumption
is
often
useful
in
closure
analysis,
it
is
not
always
true.
The
assumption
is
consistent
with
perfect
competition
theory
that
presumes
all
firms
are
price­
takers.
If
a
refiner
does
have
some
monopoly
power
in
a
particular
market,
then
it
is
possible
a
refiner
experiencing
some
economic
distress
could
continue
to
operate
for
some
period
while
complying
with
the
regulation.
It
is
a
conservative
assumption
that
likely
biases
the
results
to
overstate
the
number
of
refinery
closures
and
other
impacts
of
the
proposed
regulation.

To
mitigate
the
economic
impacts
on
small
refiners,
the
Agency
has
considered
whether
to
subcategorize
the
MACT
floors
for
the
various
emission
sources
or
to
allow
refiners
more
time
to
comply
with
the
regulation.
The
Agency
has
decided
not
to
include
a
separate
subcategory
for
small
refiners,
but
has
decided
to
allow
refiners
more
time
to
comply
with
various
requirements
for
control
of
equipment
73
leak
and
storage
vessel
emissions
(
refer
to
section
V,

"
Significant
Comments
and
Changes
to
the
Proposed
Standards").

The
definition
of
small
refinery
used
in
the
analysis
is
50,000
bbl
per
stream
day
production
capacity.
This
differs
from
the
definition
of
75,000
barrels
per
stream
current
as
of
May
1,
1992,
a
definition
announced
by
the
Small
Business
Administration
that
day
in
the
Federal
Register
(
57
FR
18808).

E.
Unfunded
Mandates
Under
section
202
of
the
Unfunded
Mandates
Reform
Act
of
1995
("
Unfunded
Mandates
Act"),
signed
into
law
on
March
22,
1995,
the
EPA
must
prepare
a
budgetary
impact
statement
to
accompany
any
proposed
or
final
rule
that
includes
a
Federal
mandate
that
may
result
in
estimated
costs
to
State,
local,
or
tribal
governments
in
the
aggregate,
or
to
the
private
sector,
of
$
100
million
or
more.
Under
section
205,
the
EPA
must
select
the
most
cost
effective
and
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule
and
is
consistent
with
statutory
requirements.
Section
203
requires
the
EPA
to
establish
a
plan
for
informing
and
advising
any
small
governments
that
may
be
significantly
or
uniquely
impacted
by
the
rule.

The
EPA
has
determined
that
the
action
promulgated
today
does
not
include
a
Federal
mandate
that
may
result
in
74
estimated
costs
of
$
100
million
or
more
to
either
State,

local,
or
tribal
governments
in
the
aggregate,
or
to
the
private
sector.
Therefore,
the
requirements
of
the
Unfunded
Mandates
Act
do
not
apply
to
this
action.

List
of
Subjects
40
CFR
Part
60
Administrative
practice
and
procedure,
Air
pollution
control,
Environmental
protection,
Gasoline,

Intergovernmental
relations,
Natural
gas,
Volatile
organic
compounds.

40
CFR
Part
63
Air
pollution
control,
Hazardous
air
pollutants,

Petroleum
refineries,
Reporting
and
recordkeeping
requirements.

Date
[___.___]
Carol
M.
Browner
Administrator